FORM 10-K

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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the registrant’s Class A common units held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2011, was $4,958,091,529.

As of March 13, 2012 the registrant has 238,043,964 Class A common units outstanding.

In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.”

This Annual Report on Form 10-K contains forward-looking statements, which are typically identified by words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “project,” “strategy,” “target,” “could,” “should” or “will” and similar words or statements, express or implied, suggesting future outcomes or statements regarding an outlook or the negative of those terms. Although we believe that these forward-looking statements are reasonable based on the information available on the dates these statements are made and processes used to prepare the information, these statements are not guarantees of future performance, and we caution you not to place undue reliance on these statements. By their nature, these statements involve a variety of assumptions, unknown risks, uncertainties and other factors, which may cause actual results, levels of activity and performance to differ materially from those expressed or implied by these statements. Material assumptions may include, among others, the expected supply of and demand for crude oil, natural gas and natural gas liquids, or NGLs; prices of crude oil, natural gas and NGLs; inflation and interest rates; operational reliability; and weather.

Our forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions, interest rates and commodity prices including but not limited to those risks and uncertainties discussed in this Annual Report on Form 10-K and our other reports that we have filed or will file with the Securities and Exchange Commission, or SEC. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and our future course of action depends on the assessment of all information available at the relevant time by those responsible for the management of our operations. Except to the extent required by law, we assume no obligation to publicly update or revise any forward-looking statements made herein whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements, as such may be updated in our future filings with the SEC. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K.

The following abbreviations, acronyms and terms used in this Form 10-K are defined below:

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We are a publicly traded Delaware limited partnership that 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 of America. Our Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “EEP.”

The following chart shows our organization and ownership structure as of December 31, 2011. The ownership percentages referred to below illustrate the relationships between us, Enbridge Management, our General Partner and Enbridge and its affiliates:

We were formed in 1991 by our General Partner, to own and operate the Lakehead system, which is the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada, referred to as the Mainline system. A subsidiary of Enbridge Inc., or Enbridge, owns the Canadian portion of the Mainline system. Enbridge, which is based in Calgary, Alberta, Canada is a leading provider of energy transportation, distribution and related services in North America and internationally. Enbridge is the ultimate parent of our General Partner.

We are a geographically and operationally diversified partnership consisting of interests and assets that provide midstream energy services. As of December 31, 2011, our portfolio of assets included the following:

Enbridge Energy Management L.L.C., or Enbridge Management, is a Delaware limited liability company that was formed in May 2002 to manage our business and affairs. Under a delegation of control agreement, our General Partner delegated substantially all of its power and authority to manage our business and affairs to Enbridge Management. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management is the sole owner of a special class of our limited partner interests, which we refer to as “i-units.”

Our primary objective is to provide stable and sustainable cash distributions to our unitholders, while maintaining a relatively low-risk investment profile. Our business strategies focus on creating value for our customers, which we believe is the key to creating value for our investors. To accomplish our objective, we focus on the following key strategies:

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses while remaining focused on the safe, reliable, effective and efficient operation of our current assets. We are well positioned to pursue opportunities for accretive acquisitions in or near the areas in which we have a competitive advantage. We intend to execute our growth strategy by maintaining a capital structure that balances our outstanding debt and equity in a manner that sustains our investment grade credit rating.

The map below presents the locations of our current Liquids systems assets and projects being constructed. This map depicts some assets owned by Enbridge and projects being constructed to provide an understanding of how they interconnect with our Liquids systems.

Our business strategy provides an overview of North American production that is transported on our pipelines and the projects that we are pursuing to connect the growing supplies of this production to key refinery markets in the United States.

In 2011, we transported production from the Western Canadian Sedimentary Basin, or WCSB, and the North Dakota Bakken. Western Canadian crude oil is an important source of supply for the United States. According to the latest available data for 2011 from the United States Department of Energy’s Energy Information Administration, or EIA, Canada supplied approximately 2.2 million Bpd of crude oil to the United States, the largest source of United States imports. Approximately 57.8 percent of the Canadian crude oil moving into the United States was transported on the Mainline system. The Canadian Association of Petroleum Producers, which we refer to as CAPP, in their June 2011 forecast of future production from the Alberta Oil Sands, continued to expect steady growth in supply during the next 14 years with an additional 2.7 million Bpd

of incremental supply available by 2025, based on a subset of currently approved applications and announced expansions. We are well positioned to deliver growing volumes of crude oil that are expected from the Alberta Oil Sands to our existing and new markets.

North Dakota, Montana and Saskatchewan, Canada have continued to experience tremendous growth in the development of crude oil, natural gas, and NGLs from the Bakken and Three Forks formations. The latest data released in December 2010 by the EIA shows that proved reserves of crude oil in North Dakota were approximately 1.0 billion barrels, an 83 percent increase from the EIA 2009 Summary. Significant advancements in exploration techniques and an increased understanding of the Williston Basin now suggest the proved reserve base to be substantially higher than what the EIA published. In 2008, the United States Geological Society, or USGS, announced that technically recoverable reserves in North Dakota were approximately 3.0 billion barrels. Although the USGS has not updated their 2008 estimate, varying independent industry estimates anticipate a significant increase in recoverable reserves ranging between 9.0 billion and 11.8 billion barrels.

In North Dakota, oil production levels rose to approximately 535,000 Bpd by December 2011 an approximate 55 percent increase since December 2010. Capitalizing on this growth, we continue to develop options to access key refinery markets in the Bakken region. The following are Bakken projects that will allow Bakken crude oil access to our markets:

In October 2011, we and Enbridge announced our Eastern Market Expansion, which will initially consist of two projects that will provide increased access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States. One of the projects involves the expansion of our Line 5 light crude line between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd, while

the second project involves reversing a portion of Enbridge’s Line 9 in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario. Subject to regulatory approvals, the Line 5 expansion is targeted to be in service during the first quarter of 2013 and the Line 9 reversal is targeted to be in service in late 2013.

Along with Enbridge, we are actively working with our customers to develop options that will alleviate capacity constraints in addition to providing access to new markets in the United States. Our market strategy is to provide timely, economic, competitive, integrated transportation solutions to connect growing supplies of production to key refinery markets in the United States. Our strategy also includes further development of our transportation infrastructure to address growing production of crude oil from the Bakken and Three Forks formations. Together, our existing and future plans advance our vision of being North America’s first choice for liquids deliveries.

The map below presents the locations of our current Natural Gas systems assets and projects being constructed, including joint ventures. This map depicts some assets owned or under development by Enbridge to provide an understanding of how they relate to our Natural Gas systems.

Our natural gas assets are primarily located in Texas, which continues to maintain its status as one of the most active natural gas producing areas in the United States. Our three systems in Texas are located in basins that have experienced active drilling over the last several years. These core basins are known as the East Texas basin, the Fort Worth basin and the Anadarko basin. Our focus has primarily been on developing and expanding the service capability of our existing pipeline systems and acquiring assets with strong growth prospects located in or near the areas we serve or have competitive advantage. We expect to also target future growth in areas where we can deploy our successful operating strategy to expand our portfolio into other natural gas production regions.

One of our key goals is to become the premier midstream energy company in the United States Gulf Coast region. To achieve this end, the operations and commercial activities of our gathering and processing assets and intrastate pipelines are integrated to provide better service to our customers. From an operations perspective, our key strategies are to provide safe and reliable service at reasonable costs to our customers, enhance our reputation and capitalize on opportunities for attracting new customers. From a commercial perspective, our focus is to provide our customers with a greater value for their commodity. We intend to achieve this latter objective by increasing customer access to preferred natural gas markets and natural gas liquids, or NGLs. The aim is to be able to move significant quantities of natural gas and NGLs from our Anadarko, North Texas and East Texas systems to the major market hubs in Texas and Louisiana. From these market hubs, natural gas can be used in the local Texas markets or transported to consumers in the Midwest, Northeast and Southeast United States.

The growth prospects in our core areas remain favorable primarily as a result of technological advancements that permit the economical production of natural gas and NGLs from tight sand and shale formations. During 2011, overall natural gas commodity prices stabilized at rates that were below those experienced in recent years due to excess supplies of natural gas in the United States, while the prices of NGLs and condensate have remained above historical averages. As a result of the existing commodity price environment, producers have focused their development activities in areas that have high levels of NGL content within the natural gas stream, such as the Granite Wash formation, which is served by our Anadarko system. Additionally, supply in these areas has benefited from enhanced horizontal drilling and fracturing techniques, enabling higher flow rates from the wells of the producers.

Due to the significant increase in drilling activity in the Anadarko region and the resulting increase in natural gas production, we expanded the gathering and processing capabilities of our Anadarko system with the September 2010 acquisition of the Elk City natural gas gathering and processing system, referred to as the Elk City system. The Elk City system consists of approximately 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 NGL production capability of 20,000 Bpd. The Elk City system complements our existing Anadarko system by providing additional processing capacity and expansion capability by allowing us to further capitalize on growing volumes of natural gas with a high content of NGLs from the Granite Wash formation.

In November 2011, we placed into service a cryogenic processing plant and related facilities on our Anadarko system which will address capacity constraints in the Anadarko region, which we refer to as the Allison Plant. The Allison Plant is intended to accommodate the resurgence of horizontal drilling activity that exists in the Granite Wash formation in the Texas Panhandle, where our Anadarko system is located. We are awaiting the completion of additional third party NGL takeaway capacity to the Allison Plant, which will allow us to fully utilize its capacity. This additional third party takeaway capacity is expected to be in place during the first quarter of 2012. In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system, which we refer to as our Ajax Plant. The Ajax Plant is anticipated to be in service in early 2013. The Allison and Ajax plants, when both operational, are expected to increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d.

In September 2011, we announced a joint venture among us, Enterprise Products Partners L.P., or Enterprise Products, and Anadarko Petroleum Corporation, or Anadarko, to design and construct a new NGL pipeline referred to as the Texas Express Pipeline, or TEP. The pipeline will extend approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas and have an initial capacity of approximately 280,000 Bpd. Additionally, the joint venture will include two new NGL gathering systems. Enterprise will construct and serve as the operator of the pipeline, while we will build and operate the new gathering systems. The pipeline and portions of the gathering systems are expected to begin service in mid-2013, subject to regulatory approvals and finalization of commercial agreements. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide a new source of strong and stable cash flow.

Our Natural Gas business also includes trucking, rail and liquids marketing operations that we use to enhance the value of the NGLs produced at our processing plants. Our Natural Gas marketing business provides us with the ability to maximize the value received for the natural gas we transport and purchase by identifying customers with consistent demand for natural gas. In October 2010, we acquired the assets of a common carrier trucking company for $10.3 million to meet the growing supply of NGLs, condensate and crude oil from our processing facilities, as well as to capitalize on the opportunity to better serve our customers in south Texas.

These segments have unique business activities that require different operating strategies. For information relating to revenues from external customers, operating income and total assets for each segment, refer to Note 19. Segment Information of our consolidated financial statements beginning on page 178 of this report.

Our Lakehead system consists primarily of crude oil and liquid petroleum common carrier pipelines and terminal assets in the Great Lakes and Midwest regions of the United States. The Lakehead system, together with the Enbridge system in Canada, form the Mainline system, which has been in operation for over 60 years and forms the longest liquid petroleum pipeline system in the world. The Mainline system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the Province of Ontario, Canada.

Over the past four years, we have completed the largest pipeline expansion program in our history that we initiated in 2005. During the 2008 through 2010 time periods, we completed the Southern Access expansion program, referred to as the Southern Access Pipeline, which increased the capacity of our Mainline system into the Chicago area by 400,000 Bpd and the Alberta Clipper expansion program, referred to as the Alberta Clipper Pipeline, which added 450,000 Bpd of additional capacity into Superior. The Southern Access Pipeline can be expanded further to a total capacity of 1,200,000 Bpd with additional pumping station capital. The United States portion of the Alberta Clipper Pipeline can also be further expanded to 800,000 Bpd. With supply from the Bakken-Three Forks plays in Montana and North Dakota expected to grow by 300,000 Bpd by 2020 and from Western Canada oil sands developments are expected to grow by as much as 2.7 million Bpd by 2025, the industry requires more capacity to transport crude oil out of North Dakota, Montana and the oil sands regions into the United States Midwest markets. The need for further capacity on our Lakehead system was driven by producers and refiners that have long development timelines and need assurance that adequate pipeline infrastructure will be in place in time to transport the additional production resulting from completion of their projects. Both the Alberta Clipper and Southern Access Pipelines were a direct response to this need.

Our Lakehead system is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission, or FERC. Our Lakehead system spans a distance of approximately 1,900 miles, and consists of approximately 5,100 miles of pipe with diameters ranging from 12 inches to 48 inches, and is the primary transporter of crude oil and liquid petroleum from Western Canada to the United States. Additionally, the system has 61 pump station locations with a total of approximately 900,000 installed horsepower and 72 crude oil storage tanks with an aggregate capacity of approximately 13.9 million barrels. The Mainline system operates in a segregation, or batch mode, allowing the transport in excess of 50 crude oil commodities including light, medium and heavy crude oil (including bitumen, which is a naturally occurring tar-like mixture of hydrocarbons), condensate and NGLs.

Customers. Our Lakehead system operates under month-to-month transportation arrangements with our shippers. During 2011, approximately 42 shippers tendered crude oil and liquid petroleum for delivery through our Lakehead system. We consider multiple companies that are controlled by a common entity to be a single

shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Lakehead system. Our customers include integrated oil companies, major independent oil producers, refiners and marketers.

Supply and Demand. Our Lakehead system is well positioned as the primary transporter of Western Canadian crude oil and continues to benefit from the growing production of crude oil from the Alberta Oil Sands. Similar to United States domestic conventional crude oil production, Western Canada’s conventional crude oil production is declining. Over the last several years, development of the Alberta Oil Sands has more than offset declining conventional production. The National Energy Board, or NEB, estimated that total production from the WCSB averaged approximately 2.8 billion Bpd in 2011 and 2.5 billion in 2010. Volumes of WCSB crude oil production are comparable with production volumes from Iraq and Venezuela, key members of the Organization of Petroleum Exporting Countries, or OPEC.

Remaining established reserves from the Alberta Oil Sands as of the end of 2010 were approximately 170 billion barrels according to the Energy Resources Conservation Board, or ERCB. Additionally, remaining established conventional oil reserves in Western Canada were estimated to be approximately 3.6 billion barrels at the end of 2010. Canada’s combined conventional and oil sands estimated proved reserves of approximately 174 billion barrels compares with Saudi Arabia’s estimated proved reserves of approximately 265 billion barrels.

According to CAPP, an estimated $123 billion CAD, has been spent on oil sands development from 1997 through 2010. Development of the Alberta Oil Sands moderated in previous years due to declining demand and commodity prices; however, rising oil prices and demand has led to a rebound in production growth and the announcement of new oil sands projects, as noted in the discussion below. As mentioned above, CAPP’s June 2011 Growth Forecast estimates that the future production from the Alberta Oil Sands is expected to grow steadily during the next 14 years, with an additional 2.7 million Bpd of incremental production available by 2025.

The near-term growth in crude oil supply comes from the completion and ramp up of major expansion projects at existing synthetic crude oil upgraders and growth of bitumen production from both existing and new Steam Assisted Gravity Drainage, or SAGD, and mining facilities. The 2011 delivered production of four major Alberta Oil Sands producers is detailed as follows:

Over the next two years, twenty individual projects are expected to come on-line that should start or increase the production of unblended bitumen. Notable projects include Suncor’s North Steepbank Extension and Firebag Stage 4, Imperial’s Kearl Lake, Cenovus Energy’s Christina Lake, and Canadian Natural Resources’ Kirby South. Based on the CAPP Production forecast, unblended bitumen production is expected to increase by roughly 216,000 Bpd by the end of 2012 and then increase by an additional 120,000 Bpd by the end of 2013.

Although the crude oil and liquid petroleum delivered through our Lakehead system originate primarily in oilfields in Western Canada, our Lakehead system also receives approximately seven percent of its receipts from domestic sources including:

Based on forecasted growth in Western Canadian crude oil production and completion of upgrader expansions and increased bitumen production, as well as a 435,000 Bpd competitor pipeline that came on-line in 2010 and was expanded to 590,000 Bpd in 2011, our Lakehead system deliveries are expected to average 1.7 million Bpd in 2012 comparable with 1.7 million Bpd of actual deliveries in 2011. The ability to increase deliveries and to expand our Lakehead system in the future will ultimately depend upon numerous factors. The investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil and natural gas prices, future operating costs, United States demand and availability of markets for produced crude oil. Higher crude oil production from the WCSB should result in higher deliveries on our Lakehead system. Deliveries on our Lakehead system are also affected by periodic maintenance, turnarounds and other shutdowns at producing plants that supply crude oil to, or refineries that take delivery from, our Lakehead system.

Refinery configurations and crude oil requirements in PADD II continue to be an attractive market for Western Canadian supply. According to the EIA, 2011 demand for crude oil in PADD II averaged 3.4 million Bpd an increase of 70,000 Bpd from 2010. At the same time, production of crude oil within PADD II increased by 105,000 Bpd to 795,000 Bpd.

Competition. Our Lakehead system, along with the Enbridge system, is the main crude oil export route from the WCSB. WCSB production in excess of Western Canadian demand moves on existing pipelines into PADD II, the Rocky Mountain states (PADD IV), the Anacortes area of Washington State (PADD V) and the United States Gulf Coast (PADD III). In each of these regions, WCSB crude oil competes with local and imported crude oil. As local crude oil production declines and refineries demand more imported crude oil, imports from the WCSB should increase.

For 2011, the latest data available shows that PADD II total demand was 3.4 million Bpd while it produced only 795,000 Bpd and thus imported 2.6 million Bpd. The 2011 data indicates PADD II imported approximately 1.4 million Bpd of crude oil from Canada, a majority of which was transported on our Lakehead system. The remaining barrels were imported via competitor pipelines from Alberta, and from PADDs III and IV as well as from offshore sources from the United States Gulf Coast. Lakehead system deliveries of Canadian crude oil to PADD II were approximately 13,800 Bpd lower than delivery volumes for 2010. Total deliveries from our Lakehead system averaged 1.7 million Bpd in 2011, meeting approximately 70 to 80 percent of the refinery capacity in the greater Chicago area; the Minnesota refinery capacity; and the Ontario refinery demand.

Considering all of the pipeline systems that transport Western Canadian crude oil out of Canada, the Mainline system transported approximately 58 percent of the total Western Canadian crude oil exports in 2011 to the United States. The remaining production was transported by systems serving the British Columbia, PADD II, PADD IV and PADD V markets. There are a number of smaller competing pipelines located in PADD IV that transport Canadian crude oil into production facilities within the United States. However, the production facilities located within the Rocky Mountain states have significantly less refining capacities in relation to the facilities we serve that are located within the Midwest region of the United States.

Given the expected increase in crude oil production from the Alberta Oil Sands over the next 10 years, alternative transportation proposals have been presented to crude oil producers. These proposals and projects range from expansions of existing pipelines that currently transport Western Canadian crude oil, to new pipelines and extensions of existing pipelines. These proposals and projects are in various stages of development, with some at the concept stage and others that are operational. Some of these proposals are in direct competition with our Lakehead system.

Enbridge has filed an application with the NEB for construction of the Northern Gateway Pipeline which includes both a condensate import pipeline and a petroleum export pipeline. The Northern Gateway Pipeline has an expected in-service date in the 2016 to 2017 timeframe, depending on the length of the regulatory review process. The condensate line would transport imported diluent from Kitimat, British Columbia to the Edmonton, Alberta area. The petroleum export line would transport crude oil from the Edmonton area to Kitimat and would compete with our Lakehead system for production from the Alberta Oil Sands. Given the substantial growth in Western Canadian crude oil supply, this pipeline will provide another market option for Canadian crude oil, an important consideration for Canadian crude oil producers.

We and Enbridge believe that the Southern Access Pipeline, Alberta Clipper Pipeline, the Line 5 expansion, Flanagan West proposed pipeline, the Seaway reversal and other initiatives to provide access to new markets in the Midwest, Mid-Continent, Eastern Canada and Gulf Coast, offer flexible solutions to future transportation requirements of Western Canadian crude oil producers.

The following provides an overview of other proposals and projects put forth by competing pipeline companies that are not affiliated with Enbridge:

These competing alternatives for delivering Western Canadian crude oil into the United States and other markets could erode shipper support for further expansion of our Lakehead system. They could also affect throughput on and utilization of the Mainline system. However, together the Lakehead and Enbridge systems offer significant cost savings and flexibility advantages, which are expected to continue to favor the Mainline system as the preferred alternative for meeting shipper transportation requirements to the Midwest United States and beyond.

The following table sets forth average deliveries per day and barrel miles of our Lakehead system for each of the periods presented.

Our Mid-Continent system, which we have owned since 2004, is located within PADD II and is comprised of our Ozark pipeline and storage terminals at Cushing and El Dorado, Kansas. Our Mid-Continent system includes over 430 miles of crude oil pipelines and 17.3 million barrels of crude oil storage capacity. Our Ozark pipeline transports crude oil from Cushing to Wood River where it delivers to ConocoPhillips’ Wood River refinery and interconnects with the Woodpat Pipeline and the Wood River Pipeline, each owned by unrelated parties.

The storage terminals consist of 91 individual storage tanks ranging in size from 58,000 to 575,000 barrels with eight new tanks under various stages of construction that will add 2.2 million barrels of total shell capacity for service during 2012. Of the 17.3 million barrels of storage capacity on our Mid-Continent system, the Cushing terminal accounts for 16.1 million barrels. A portion of the storage facilities are used for operational purposes, while we contract the remainder of the facilities with various crude oil market participants for their term storage requirements. Contract fees include fixed monthly capacity fees as well as utilization fees, which we charge for injecting crude oil into and withdrawing crude oil from the storage facilities.

Customers. Our Mid-Continent system operates under month-to-month transportation arrangements and both long-term and short-term storage arrangements with its shippers. During 2011, approximately 38 shippers tendered crude oil for service on our Mid-Continent system. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Mid-Continent system. These customers include integrated oil companies, independent oil producers, refiners and marketers. Average deliveries on the Ozark pipeline system were 226,000 Bpd for 2011 and 212,000 Bpd for 2010.

Supply and Demand. Our Mid-Continent system is positioned to capitalize on increasing near-term demand for crude oil from west Texas and imported crude oil delivered to the United States Gulf Coast, as well as third-party storage demand. In 2011, PADD II imported 2.6 million Bpd from outside of the PADD II region. The 2011 data indicates PADD II imported approximately 1.4 million Bpd of crude oil from Canada, a majority of which was transported on our Lakehead system. The remaining barrels of crude oil were imported from PADDs III and IV as well as offshore sources. We expect the gap between local supply and demand for crude oil in PADD II to continue to widen, encouraging imports of crude oil from Canada, PADD III and foreign sources.

Competition. Our Ozark pipeline system currently serves an exclusive corridor between Cushing and Wood River. However, refineries connected to Wood River have crude oil supply options available from Canada via our Lakehead system and a third party pipeline. These same refineries also have access to the United States Gulf Coast and foreign crude oil supply through a third-party pipeline system, which is an undivided joint interest pipeline that is owned by unrelated parties. In addition, refineries located east of Patoka with access to crude oil through our Ozark system, also have access to west Texas supply through the West Texas Gulf / Mid-Valley pipeline systems owned by unrelated parties. Our Ozark pipeline system faces a significant increase in competition after the completion of a competitor’s new pipeline from Hardisty to Patoka that came into service in June 2010. Our Ozark pipeline system provides crude oil types and grades that are generally lighter and with lower sulfur relative to that expected to be transported on the new pipeline. To date, our Ozark system has remained full. If a negative impact does occur to the volumes on our Ozark system, we will consider alternative uses for our Ozark system.

In addition to movements into Wood River, crude oil in Cushing is transported to Chicago and El Dorado on third-party pipeline systems. With the reversal of the Spearhead pipeline, western Canadian crude oil moving on Spearhead is increasing the importance of Cushing as a terminal and pipeline origination area.

The storage terminals rely on demand for storage service from numerous oil market participants. Producers, refiners, marketers and traders rely on storage capacity for a number of different reasons: batch scheduling, stream quality control, inventory management, and speculative trading opportunities. Competitors to our storage facilities at Cushing include large integrated oil companies and other midstream energy partnerships. Demand for storage capacity at Cushing has remained steady as customers continue to value the flexibility and optionality available with this service. Competition comes from other storage providers with available land and operational facilities in the area. Competition is driven by reliability, quality of service and price.

Our North Dakota system is a crude oil gathering and interstate transportation system servicing the Williston basin in North Dakota and Montana, which includes the Bakken and Three Forks formations. The crude oil gathering pipelines of our North Dakota system collect crude oil from points near producing wells in approximately 22 oil fields in North Dakota and Montana. Most deliveries from our North Dakota system are made at Clearbrook to our Lakehead system and to a third-party pipeline system. Our North Dakota system includes approximately 240 miles of crude oil gathering lines connected to a transportation line that is approximately 730 miles long, with a capacity of approximately 210,000 Bpd at the end of 2011. Our North Dakota system also has 21 pump stations, one delivery station and 11 storage facilities with an aggregate working storage capacity of approximately 870,000 barrels.

We added 25,000 Bpd of capacity from Berthold, North Dakota to the international border near Lignite, North Dakota with the completion of PREP during 2011. Capacity will again increase in the first quarter of 2013 when our Bakken Project is scheduled to be complete. This expansion was necessary to meet increased crude oil production from the Montana and North Dakota region. This expansion, when added to the 25,000 Bpd of expanded capacity discussed above will total 145,000 Bpd, with further expansion available to increase the takeaway capacity to 325,000 Bpd. Of the 145,000 Bpd, 100,000 Bpd is in the form of firm commitments with multiple shippers who committed to the project during an open season in February 2011. The entire capacity will be subject to the approved cost of service based surcharges added to the existing transportation rates.

In October 2011, we announced the Bakken Access Program, a series of projects which represents an upstream expansion that will further complement our Bakken expansion, as discussed above. This expansion program will substantially enhance our gathering capabilities on the western side of our North Dakota system by 100,000 Bpd. This program is expected to be in service by early 2013, and it involves increasing pipeline capacities, construction of additional storage tanks and the addition of truck access facilities at multiple locations in western North Dakota.

Additionally, in December 2011, we announced that we will be proceeding with the Berthold Rail Project, an investment that will provide an interim solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold, North Dakota Terminal by 80,000 barrels per day and includes the construction of a three unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing facilities. Conditional approval was received in early December 2011 subject to securing remaining shipper commitments. A regulatory filing is in progress and detailed design is proceeding to enable construction to commence in April 2012 with a scheduled in-service date by early-2013.

Customers. Customers of our North Dakota system include refiners of crude oil, producers of crude oil and purchasers of crude oil at the wellhead, such as marketers, that require crude oil gathering and transportation services. Producers range in size from small independent owner/operators to the integrated oil companies.

Supply and Demand. Similar to our Lakehead system, our North Dakota system depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States and the ability of crude oil producers to maintain their crude oil production and exploration activities. Due to increased exploration of the Bakken and Three Forks formations within the Williston Basin, the state of North Dakota has seen increased production levels up to 535,000 Bpd as of December 2011, an approximate 55 percent increase in production levels since December 2010. The latest data released in December 2009 by the EIA shows that proved reserves of crude oil in North Dakota were approximately 1.0 billion barrels, an 83 percent increase from the EIA 2008 Summary. Significant advancements in exploration techniques and an increased understanding of the Williston Basin now suggest the proved reserve base to be substantially higher than what the EIA published. In 2008, the United States Geological Society, or USGS, announced that technically recoverable reserves in North Dakota were approximately 3.0 billion barrels. Although the USGS has not updated their 2008 estimate, varying independent industry estimates anticipate a significant increase in recoverable reserves ranging between 9.0 billion and 11.8 billion barrels.

Competition. Competitors of our North Dakota system include integrated oil companies, interstate and intrastate pipelines or their affiliates and other crude oil gatherers. Many crude oil producers in the oil fields served by our North Dakota system have alternative gathering facilities available to them or have the ability to build their own assets, including some existing rail loading facilities.

There are a number of third party pipelines with proposed expansions to increase their capacities to take advantage of the Bakken and Three Forks volume growth.

We own and operate natural gas gathering, treating, processing and transportation systems as well as trucking, rail and liquids marketing operations. We purchase and gather natural gas from the wellhead and deliver it to plants for treating and/or processing and to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies.

Natural gas treating involves the removal of hydrogen sulfide, carbon dioxide, water and other substances from raw natural gas so that it will meet the standards for pipeline transportation. Natural gas processing involves the separation of raw natural gas into residue gas and NGLs. Residue gas is the processed natural gas that ultimately is consumed by end users. NGLs separated from the raw natural gas are either sold and transported as NGL raw mix or further separated through a process known as fractionation and sold as their individual components, including ethane, propane, butanes and natural gasoline. At December 31, 2011, we had 9 active treating plants and 25 active processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants. We may idle some of these plants from time to time based on current volumes. Our treating facilities have a combined capacity that approximates 1,240 MMcf/d while the combined capacity of our processing facilities approximates 2,015 MMcf/d, including 350 MMcf/d provided by the HCDP plants.

Customers. Our natural gas pipeline systems serve customers predominantly in the United States Gulf Coast region and include both purchasers and producers of natural gas. Purchasers are comprised of large users of natural gas, such as power plants, industrial facilities, local distribution companies, large consumers seeking an alternative to their local distribution company, and shippers of natural gas, such as natural gas producers and marketers, including our Marketing business. Producers served by our systems consist of small, medium and large independent operators and large integrated energy companies. We sell NGLs resulting from our processing activities to a variety of customers ranging from large petrochemical and refining companies to small regional retail propane distributors.

Supply and Demand. Demand for our gathering, treating and processing services primarily depends upon the supply of natural gas reserves and the drilling rate for new wells. The level of impurities in the natural gas gathered also affects treating services. Demand for these services also depends upon overall economic conditions and the prices of natural gas and NGLs. During 2011, overall natural gas prices were at rates below the rates experienced in recent years due to excess supplies of natural gas in the United States. At the same time prices for NGLs and condensate, which are more closely correlated with movements in crude oil prices, have remained above historical averages. As a result of the combination of these pricing dynamics, drilling activity has increased in areas known to have natural gas with high levels of NGL content, such as the Granite Wash formation, and areas where the cost of drilling for natural gas allows for a reasonable return for the natural gas produced as is the case in the Haynesville and Barnett shales. Additionally, supply in both of these areas has benefited from enhanced horizontal drilling and fracturing techniques, enabling higher flow rates from the wells

of the producers. As drilling rates continue to improve and the number of drilling rigs increase, we expect the demand for our services to increase. Our existing natural gas assets are in basins that have the opportunity to grow in an improved pricing environment. All three of our natural gas systems exist in regions that have shale or tight sands formations where horizontal fracturing technology can be utilized to increase production from the natural gas wells.

Our East Texas system is primarily located in the East Texas basin. The Bossier trend, which is located on the western side of our East Texas system within the East Texas basin, has been the driver of growth on our East Texas system for the past several years. Production in the Bossier trend grew from 650 MMcf/d in 1997 to a peak of 2,400 MMcf/d in March of 2009. However with the decline in natural gas prices, the Bossier trend has seen a decrease in development with production falling to 1,800 MMcf/d as of October 2011. This decreased drilling activity in the Bossier trend is expected to be offset by the increased activity focused in and around the Haynesville shale. The Haynesville shale is a formation that runs from western Louisiana into eastern Texas, and is one of the largest natural gas discoveries in the United States.

In an effort to address the continuing growth in natural gas production occurring in east Texas, and take advantage of the resource potential of the Haynesville shale, we announced plans to expand our East Texas system by constructing three lateral pipelines into the east Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage, which will further expand our recently completed Shelby County Loop. The expansion into the Haynesville shale area is expected to increase the capacity of our East Texas system by 900 MMcf/d. A portion of the pipeline for the project was completed during the second quarter of 2010 and the main trunkline to Carthage in December 2010, with the remainder of the facilities to be completed in the first quarter of 2012.

A substantial portion of natural gas on our North Texas system is produced in the Barnett shale area within the Fort Worth basin conglomerate. The Fort Worth basin conglomerate is a mature zone that is experiencing slow production decline. In contrast, the Barnett shale area became one of the more active natural gas plays in North America. While abundant natural gas reserves have been known to exist in the Barnett shale area since the early 1980s, technological advances in fracturing the shale formation allows commercial production of these natural gas reserves. Based on the latest information available for 2011, Barnett shale production has risen from approximately from 110 MMcf/d in 1999 to approximately 5,800 MMcf/d by October 2011. We anticipate that throughput on the North Texas system will be steady in each of the next several years as a result of modest Barnett shale development due to low natural gas prices. This is a result of producers deploying their resources to other natural gas shale plays with higher liquids content.

Our Anadarko system is located within the Anadarko basin and has experienced considerable growth as a result of the rapid development of the Granite Wash play in Hemphill and Wheeler counties in Texas. Favorable pricing for NGLs relative to the lower prices for natural gas has encouraged producers to increase production in the Granite Wash formation due to the high content of NGLs and condensate present in the natural gas stream. Rig counts have increased steadily since late 2009 with an increased emphasis by producers to use horizontal drilling and multistage hydraulic fracturing technologies. We continue to experience an increase in the supply of natural gas for processing and transportation on our Anadarko system resulting from the increase in production of the Granite Wash formation due to the successful application of these new technologies by our customers.

In response to the increased supply of natural gas and NGLs and the increased demand for our services in the Anadarko region, we acquired the Elk City system in September 2010. The Elk City system includes one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 MMcf/d, and a combined current NGL production capability of 20,000 Bpd, enabling us to process greater volumes of natural gas resulting from the increased production in the Granite Wash formation. This acquisition enhanced the processing capacity and expansion capability of our Anadarko system. In an effort to further alleviate the capacity constraints resulting from the increasing supplies of natural gas in the areas served by our Anadarko system, we constructed a cryogenic processing plant, which we refer to as the Allison Plant. The Allison Plant

was placed into service in November 2011 and is intended to accommodate the resurgence of horizontal drilling activity that exists in the Granite Wash formation. We are awaiting the completion of additional third party NGL takeaway capacity to the Allison Plant, which will allow us to fully utilize its capacity. This additional third party takeaway capacity is expected to be in place during the first quarter of 2012. In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system, which we refer to as our Ajax Plant. The Allison and Ajax plants, when operational, will increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d.

Other potential expansions may arise as more producers begin further developing the Granite Wash, Barnett shale, Haynesville shale and other areas in the basins served by our systems and commit for additional capacity. We will opportunistically evaluate strategic prospects to further expand the service capabilities of our existing systems.

Results of our Natural Gas business depend upon the drilling activities of natural gas producers in the areas we serve. We expect that natural gas production will continue to rise in areas with high liquids content gas and to decline in our dry gas basins due to low natural gas prices. We expect the volumes on our Anadarko system to rise due to the high prices for NGLs and the increased use of horizontal drilling in the Mid-continent region of the United States. Our East Texas and North Texas systems are located in two areas where we believe producers will develop dry gas to hold their acreage position. Growth will be modest or flat until forward natural gas prices improve.

In September 2011, we announced a joint venture among us, Enterprise Products, and Anadarko, to design and construct a new NGL pipeline referred to as the Texas Express Pipeline, or TEP. The pipeline will extend approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas and have an initial capacity of approximately 280,000 Bpd. Additionally, the joint venture will include two new NGL gathering systems. Enterprise will construct and serve as the operator of the pipeline, while we will build and operate the new gathering systems. The pipeline and portions of the gathering systems are expected to begin service in mid-2013, subject to regulatory approvals and finalization of commercial agreements. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide a new source of strong and stable cash flow.

Competition. Competition from other pipeline companies is significant in all the markets we serve. Competitors of our gathering, treating and processing systems include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. Some of these competitors are substantially larger than we are. Competition for the services we provide varies based upon the location of gathering, treating and processing facilities. Most natural gas producers and owners have alternate gathering, treating and processing facilities available to them. In addition, they have alternatives such as building their own gathering facilities or, in some cases, selling their natural gas supplies without treating and processing. In addition to location, competition also varies based upon pricing arrangements and reputation. On the sour natural gas systems, such as our East Texas system, competition is more limited in certain locations due to the infrastructure required to treat sour natural gas.

Competition for customers in the marketing of residue natural gas is based primarily upon the price of the delivered natural gas, the services offered by the seller and the reliability of the seller in making deliveries. Residue natural gas also competes on a price basis with alternative fuels such as crude oil and coal, especially for customers that have the capability of using these alternative fuels, and on the basis of local environmental considerations. Competition in the marketing of NGLs comes from other NGL marketing companies, producers, traders, chemical companies and other asset owners.

Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability. Many of the large wholesale customers we serve have

multiple pipelines connected or adjacent to their facilities. Accordingly, many of these customers have the ability to purchase natural gas directly from a number of pipelines or third parties that may hold capacity on the various pipelines. In addition, several new interstate natural gas pipelines have been and are being constructed in areas currently served by our natural gas pipeline systems. Some of these new pipelines may compete for customers with our existing pipelines.

We also include our trucking and NGL marketing operations in our Natural Gas segment. These operations include the transportation of NGLs, crude oil and other products by truck and railcar from wellheads and treating, processing and fractionation facilities to wholesale customers, such as distributors, refiners and chemical facilities. In addition, our trucking and NGL marketing operations resell these products. A key component of our business is ensuring market access for the liquids extracted at our processing facilities. On average, this accounts for approximately 40 percent of the volumes marketed or transported by our trucking and NGL marketing business and is a major source of its growth in this area.

Our services are provided using trucks, trailers and rail cars, pipeline capacity, fractionation agreements, product treating and handling equipment. Our trucking operations transport NGLs, condensate and crude oil from our processing facilities and from third party producers to our United States Gulf Coast customers. In October 2010, we acquired the assets of a common carrier trucking company for $10.3 million to meet the growing supply of NGLs, condensate and crude oil, as well as to capitalize on the opportunity to better serve our United States Gulf Coast customers. As a result of the acquisition, our fleet expanded and as of December 31, 2011 consists of approximately 220 trucks and 375 trailers.

NGL Marketers. Most of the customers of our trucking and NGL marketing operations are wholesale customers, such as refineries and propane distributors. Our trucking and NGL marketing operations also market products to wholesale customers such as petrochemical plants.

Supply and Demand. Supply is sourced from a variety of areas in the United States Gulf Coast, with a significant amount of the NGL volume coming from our own gathering and processing facilities. Crude oil and natural gas prices and production levels affect the supply of these products. The demand for our services is affected by the demand for NGLs and crude oil by large industrial refineries and similar customers in the regions served by this business.

Competition. Our trucking and NGL marketing operations have a number of competitors, including other trucking and railcar operations, pipelines, and, to a lesser extent, marine transportation and alternative fuels. In addition, the marketing activities of our trucking and NGL marketing operations have numerous competitors, including marketers of all types and sizes, affiliates of pipelines and independent aggregators.

Our Marketing segment’s primary objectives are to maximize the value of the natural gas purchased by our gathering systems and the throughput on our gathering and intrastate wholesale customer pipelines and to mitigate financial risk. To achieve this objective, our Marketing segment transacts with various counterparties to provide natural gas supply, transportation, balancing, storage and sales services.

Since our gathering and intrastate wholesale customer pipeline assets are geographically located within Texas and Oklahoma, the majority of activities conducted by our Marketing segment are focused within these areas, or points downstream of these locations.

Customers. Natural gas purchased by our Marketing business is sold to industrial, utility and power plant end use customers. In addition, gas is sold to marketing companies at various market hubs. These sales are typically priced based upon a published daily or monthly price index. Sales to end-use customers incorporate a pass-through charge for costs of transportation and additional margin to compensate us for associated services.

Supply and Demand. Supply for our Marketing business depends to a large extent on the natural gas reserves and rate of drilling within the areas served by our Natural Gas business. Demand is typically driven by weather-related factors with respect to power plant and utility customers and industrial demand.

Our Marketing business uses third-party storage capacity to balance supply and demand factors within its portfolio. Our Marketing business pays third-party storage facilities and pipelines for the right to store gas for various periods of time. These contracts may be denoted as firm storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with sales and purchase contracts and to take advantage of price differential opportunities. Our Marketing business leases third-party pipeline capacity downstream from our Natural Gas assets under firm transportation contracts, which capacity is dependent on the volumes of natural gas from our natural gas assets. This capacity is leased for various lengths of time and at rates that allow our Marketing business to diversify its customer base by expanding its service territory. Additionally, this transportation capacity provides assurance that our natural gas will not be shut in, which can result from capacity constraints on downstream pipelines.

Competition. Our Marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

Our Lakehead, North Dakota and Ozark systems are our primary interstate common carrier liquids pipelines subject to regulation by the FERC under the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, or EP Act, and rules and orders promulgated thereunder. As common carriers in interstate commerce, these pipelines provide service to any shipper who requests transportation services, provided that the shipper satisfies the conditions and specifications contained in the applicable tariff. The ICA requires us to maintain tariffs on file with the FERC that set forth the rates we charge for providing transportation services on our interstate common carrier pipelines, as well as the rules and regulations governing these services.

The ICA gives the FERC the authority to regulate the rates we can charge for service on interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and that they not be unduly discriminatory or unduly preferential to certain shippers. The ICA permits interested parties to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate the rates to determine if they are just and reasonable. If the FERC finds the new or changed rate unlawful, it is authorized to require the carrier to refund, with interest, the amount of any revenues in excess of the amount that would have been collected during the term of the investigation at the rate properly determined to be lawful. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

In October 1992, Congress passed the EP Act, which deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment, or that were in effect on the 365^th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period, to be just and reasonable under the ICA (i.e., “grandfathered”). The EP Act also limited the circumstances under which a

complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party must show: (1) that it was contractually barred from challenging the rates during the relevant 365-day period; (2) that there has been a substantial change after the date of enactment of the EP Act in the economic circumstances of the pipeline or in the nature of the services that were the basis for the rate, or (3) that the rate is unduly discriminatory or unduly preferential.

The FERC determined our Lakehead system rates are not covered by the grandfathering provisions of the EP Act because they were subject to challenge prior to the effective date of the statute. We believe that the rates for our North Dakota and Ozark systems should be found to be subject to the grandfathering provisions of the EP Act because those rates were not suspended or subject to protest or complaint during the 365-day period established by the EP Act.

The EP Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561 which adopted an indexing rate methodology for petroleum pipelines. Under these regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels may be protested, but such protests generally must show that the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling, although a pipeline is not required to reduce its rate below the level grandfathered under the EP Act. Under Order No. 561, a pipeline must as a general rule utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

The tariff rates for our Ozark system are primarily set under the FERC indexing rules. The tariff rates for our Lakehead and North Dakota systems are set using a combination of the FERC indexing rules (which apply to the base rates on those systems) and FERC-approved surcharges for particular projects that were approved under the FERC’s settlement rules.

Under Order No. 561, the original inflation index adopted by the FERC (for the period January 1995 through June 2001) was equal to the annual change in the Producer Price Index for Finished Goods, or PPI-FG, minus one percentage point. The index is subject to review every five years. For the period from July 2001 through June 2006, the FERC set the index at the PPI-FG without an upward or downward adjustment. For the period from July 2006 through June 2011, the FERC set the index at the PPI-FG plus 1.3 percentage points. The index as of July 1, 2010 was negative, resulting in a general downward adjustment of petroleum pipeline rates as of that date.

On December 16, 2010, the FERC set the index for the period from July 2011 through June 2016 at PPI-FG plus 2.65 percentage points. The FERC’s December 16, 2010 order was challenged and an appeal was filed by a shipper with the D.C Circuit Court. However, on December 6, 2011, the shipper filed a motion requesting that the appeal be dismissed. Therefore no further judicial or commission review of the decision will occur.

FERC Allowance for Income Taxes in Interstate Common Carrier Pipeline Rates

In May 2005, the FERC adopted a policy statement providing that pipelines regulated by FERC that are owned by entities organized as master limited partnerships, or MLPs, could include an income tax allowance in their cost-of-service rates to the extent the income generated from regulated activities was subject to an actual or potential income tax liability. Pursuant to this policy statement, a FERC-regulated pipeline that is a tax pass-through entity seeking such an income tax allowance must establish that its owners, partners or members have an actual or potential income tax obligation on the company’s income from regulated activities. This tax allowance

policy was upheld on appeal by the U. S. Court of Appeals for the D.C. Circuit, also referred to as the D.C. Circuit Court, in May 2007. Whether a particular pipeline’s owners have an actual or potential income tax liability is reviewed by the FERC on a case-by-case basis. To the extent any of our FERC-regulated oil pipeline systems were to file cost-of-service rates, their entitlement to an income tax allowance would be assessed under the FERC policy statement and the facts existing at the relevant time.

On April 17, 2008, the FERC issued a Policy Statement regarding the inclusion of MLPs in the proxy groups used to determine the return on equity, or ROE, for oil pipelines. Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, 123 FERC ¶ 61,048 (2008), rehearing denied, 123 FERC ¶ 61,259 (2008). No petitions for review of the Policy Statement were filed with the D.C. Circuit Court. The Policy Statement largely upheld the prior method by which ROEs were calculated for oil pipelines, explaining that MLPs should continue to be included in the ROE proxy group for oil pipelines, and that there should be no ceiling on the level of distributions included in the FERC’s current discounted cash flow, or DCF, methodology. The Policy Statement further indicated that the Institutional Brokers’ Estimate System, or IBES, forecasts should remain the basis for the short-term growth forecast used in the DCF calculation and there should be no modification to the current respective two-thirds and one-third weightings of the short- and long-term growth factors. The primary change to the prior ROE methodology was the Policy Statement’s holding that the gross domestic product, or GDP, forecast used for the long-term growth rate should be reduced by 50 percent for all MLPs included in the proxy group. Everything else being equal, that change will result in somewhat lower ROEs for oil pipelines than would have been calculated under the prior ROE methodology. The actual ROEs to be calculated under the new Policy Statement, however, are dependent on the companies included in the proxy group and the specific conditions existing at the time the ROE is calculated in each case.

In June 2005, the FERC issued an order in Docket AI05-1 describing how FERC-regulated companies should account for costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation, or DOT, and the Pipeline and Hazardous Materials Safety Administration, or PHMSA. The order took effect on January 1, 2006. Under the order, FERC-regulated companies are generally required to recognize costs incurred for performing pipeline assessments that are part of a pipeline integrity management program as a maintenance expense in the period in which the costs are incurred. Costs for items such as rehabilitation projects designed to extend the useful life of the system can continue to be capitalized to the extent permitted under the existing rules. The FERC denied rehearing of its accounting guidance order on September 19, 2005.

Prior to 2006, we capitalized first time in-line inspection programs, based on previous rulings by the FERC. In January 2006, we began expensing all first-time internal inspection costs for all our pipeline systems, whether or not they are subject to the FERC’s regulation, on a prospective basis. We continue to expense secondary internal inspection tests consistent with the previous practice. Refer to Note 2. Summary of Significant Accounting Policies included in our consolidated financial statements beginning at page 90 of this annual report on Form 10-K for additional discussion.

Our operations are subject to regulation under the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the Texas Railroad Commission, or TRRC. Generally, the TRRC is vested with authority to ensure that rates charged for natural gas sales and transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law, unless challenged in a complaint. We cannot predict whether such a complaint may be filed against us or whether the TRRC will

change its method of regulating rates. The Texas Natural Resources Code provides that an Informal Complaint Process that is conducted by the Texas Railroad Commission shall apply to any rate issues associated with gathering or transmission systems, thus subjecting the intrastate pipeline activities of Enbridge to the jurisdiction of the Texas Railroad Commission via its Informal Complaint Process.

Our Texas intrastate pipelines are generally not subject to regulation by the FERC. However, to the extent our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. In addition, under FERC regulations we are subject to market manipulation and transparency rules. This includes the public posting of certain capacity information pursuant to FERC Order No. 720 et al and FERC Order No. 720-A. As discussed below in Natural Gas Gathering Pipeline Regulation, this posting requirement for intrastate pipelines was invalidated by the Fifth Circuit in late 2011; however the rules remain in place for interstate pipelines.

Section 1(b) of the Natural Gas Act, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas facilities that we believe meet the traditional tests the FERC has used to establish a facility’s status as a gatherer not subject to FERC jurisdiction. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to FERC Order 704-A. Additionally, several of our gathering systems fall under the definition of “major non-interstate pipeline.” These systems were previously subject to FERC Order No. 720 et al., however on October 24, 2011 the U.S. Court of Appeals for the Fifth Circuit issued an Opinion vacating the FERC rule (RM08-2) promulgated by Order Nos. 720 and 720-A, which required major intrastate pipelines to post their system’s flow information. The Fifth Circuit entered its final mandate on December 30, 2011. In keeping with that mandate, Enbridge ceased posting of capacity and flow information for its major intrastate pipelines on January 3, 2012.

State regulations of gathering facilities typically address the safety and environmental concerns involved in the design, construction, installation, testing and operation of gathering facilities. In addition, in some circumstances, nondiscriminatory requirements are also addressed; however, historically rates have not fallen under the purview of state regulations for gathering facilities. Also, some states have, or are considering providing, greater regulatory scrutiny over the commercial regulation of the natural gas gathering business. Many of the producing states have previously adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access or perceived rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to significant and unduly burdensome state or federal regulation of rates and services.

The price at which we sell natural gas currently is not subject to federal or state regulation except for certain systems in Texas. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to facilitate price transparency in markets for the wholesale sale of physical natural gas.

Our sales of crude oil, condensate and NGLs currently are not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s jurisdiction under the ICA. Certain regulations implemented by the FERC in recent years could increase the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other marketers of these products.

The governments of the United States and Canada have, by treaty, agreed to ensure nondiscriminatory treatment for the passage of oil and natural gas through the pipelines of one country across the territory of the other. Individual border crossing points require United States government permits that may be terminated or amended at the discretion of the United States Government. These permits provide that pipelines may be inspected by or subject to orders issued by federal or state government agencies.

Under published tariffs as of December 31, 2011 (including the transportation rate surcharges related to Lakehead system expansions) for transportation on the Lakehead system, the rates for transportation of light, medium and heavy crude oil from the International Border near Neche, North Dakota, where the Lakehead system enters the United States (unless otherwise stated), to principal delivery points are set forth below:

The transportation rates as of December 31, 2011 for medium and heavy crude oil are higher than the transportation rates for light crude oil set forth in this table to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons. The Lakehead system periodically adjusts transportation rates as allowed under the FERC’s index methodology and the tariff agreements described below.

The base portion of the transportation rates for our Lakehead system are subject to an annual adjustment, which cannot exceed established ceiling rates as approved by the FERC and are determined in compliance with the FERC approved index methodology.

On December 21, 1998, the FERC issued an order in Docket No. OR99-2-000 approving an uncontested Settlement Agreement, referred to as the 1998 Settlement Agreement, between us and CAPP with respect to three agreed-upon changes to our Lakehead system’s rates: (1) a surcharge to recover costs of an expansion project

known as the System Expansion Program Phase II, or SEP II; (2) a surcharge to recover costs of the Terrace expansion program; and (3) an increase in the surcharge for heavy petroleum to reflect a change in Lakehead’s operating capability to transport heavier grades of petroleum.

Under the Settlement Agreement with CAPP that the FERC approved in 1996 and reconfirmed in 1998, Lakehead implemented a transportation rate surcharge related to SEP II. This surcharge, which is added to the base transportation rates, is a cost-of-service based calculation that is trued-up annually (usually in April) for actual costs and throughput from the previous calendar year and is not subject to indexing. The initial term of the SEP II portion of the Settlement Agreement was for 15 years, beginning in 1999 and expiring December 31, 2013.

Under the 1998 Settlement Agreement, the Lakehead system implemented a transportation rate surcharge for the Terrace expansion program which is referred to as the Terrace Surcharge, of approximately $0.013 per barrel for light crude oil from the Canadian border to Chicago and will remain at this level through 2013, when the Terrace Surcharge ends. In addition to the Terrace Surcharge, included in the tariff agreement are the Terrace Schedule B and C adjustments. The Schedule B adjustment to the Terrace Surcharge is required if the change in current multi-pipeline cost of equity plus or minus 200 basis points exceeds the 1998 multi-pipeline rate of return. In 2011, since the current multi-pipeline rate of return plus or minus 200 basis points exceeded the 1998 multi-pipeline rate of return, an immaterial adjustment to the Terrace Surcharge was made. The Schedule C adjustment to the Terrace Surcharge is required when Terrace Phase III facilities are in service and the annual actual average pumping exiting Clearbrook is less than 225,000 cubic meters, or m³, per day. However, in the 2011 Filing, the actual annual average pumping for 2010 was above the volume threshold and as a result, no adjustment to the Terrace Surcharge was made. As a result there was no change to the rate in the 2011 Terrace Surcharge relative to the 2010 surcharge from the International Boundary, near Neche, to Griffith, Indiana.

In June 2004, the FERC approved an Offer of Settlement in Docket No. OR04-2-000 between the Lakehead system and CAPP, for a facilities surcharge to be implemented separately from and incrementally to the then-existing surcharges in its tariff rates, which we refer to as the Facilities Surcharge. Enbridge Energy, Limited Partnership, 107 FERC ¶ 61,336 (2004). The Facilities Surcharge was intended to be utilized to include additional projects negotiated and agreed upon between the Lakehead system and CAPP as a transparent, cost-of-service based tariff mechanism. This allows the Lakehead system to recover the costs associated with particular shipper-requested projects through an incremental surcharge layered on top of the existing base rates and other FERC approved surcharges already in effect. The Facilities Surcharge Mechanism, or FSM, Settlement requires the Lakehead system to adjust the Facilities Surcharge annually to reflect the latest estimates for the upcoming year and to true-up the difference between estimates and actual cost and throughput data in the prior year.

The FERC permitted the Facilities Surcharge to take effect as of July 1, 2004, and the FSM was expressly designed to be open-ended. In its approval of the FSM Settlement, the Commission accepted the Lakehead system’s proposal “to submit for Commission review and approval future agreements resulting from negotiations with CAPP where the parties have agreed that recovery of costs through the Facilities Surcharge is desirable and appropriate.” At the time the FSM was initially established, four projects were included in the Facilities Surcharge:

On August 14, 2008, the FERC approved an Amendment to the FSM Settlement to allow the Lakehead system to include in the Facilities Surcharge particular shipper-requested projects that are not yet in service as of April 1^st of each year, provided there is an annual true-up of throughput and cost estimates. Enbridge Energy, Limited Partnership, 124 FERC ¶ 61,159 (2008). The FERC also approved the addition of four new projects to the Facilities Surcharge (Docket No. OR08-10-000):

On August 28, 2009, the FERC accepted the supplement to the Settlement (Docket No. OR09-5-000) to allow the following three new projects:

On March 30, 2010, the FERC approved the Acceptance of Settlement (Docket No. OR10-7-000) to permit the recovery of the costs associated with two new projects:

On March 31, 2011, the FERC approved the Acceptance of Supplement to Facilities Surcharge Settlement (Docket No. OR11-5-000) to permit the recovery of the costs associated with one new project:

Project 14 is designed to recover an estimated $175 million USD in capital cost and an estimated US$5 million in operating cost related to the 2010/2011 Line 6B Integrity Program, including costs associated with the Pipeline and Hazardous Materials Safety Administration (PHMSA) Corrective Action Order. Enbridge Energy and CAPP have agreed that the costs associated with Line 6B Integrity Program should be recovered through the Facilities Surcharge Mechanism. Since the filing was uncontested, the Commission accepted the Supplement to Settlement on the grounds that it is fair, reasonable, and in the public interest.

In 2011, the Facilities Surcharge was $0.7522 per barrel for light crude oil movements from the International Border near Neche, North Dakota to Chicago, Illinois.

FERC Tariff No. 45.0.0, issued May 2, 2011, established the International Joint Tariff (IJT) effective July 1, 2011, to provide rates applicable to the transportation of petroleum from all receipt points in western Canada on the Enbridge Pipeline Inc. Canadian Mainline system to all delivery points on the Lakehead pipeline system

owned by Enbridge Energy and to delivery points on the Canadian Mainline located downstream of the Lakehead system. The IJT provides a simplified tolling structure to cover transportation services that cross the international border and provides a rate that is equal to or less than the sum of the combined Canadian Mainline and Lakehead system rates on file and in effect.

Our Mid-Continent system is comprised of pipeline, terminalling and storage infrastructure located in the Mid-Continent region of the United States. Specifically, the system originates in Cushing and offers transportation service to Wood River, and other Mid-Continent system facilities, local area refineries and to other interconnected non-affiliated pipelines. The transportation rate for light crude oil from Cushing to principle delivery points are set forth below:

The transportation rate as of December 31, 2011, outlined above, applies to light crude only. Medium and heavy crude oil transportation rates on these systems are higher to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons.

Where applicable, transportation rates are periodically adjusted as allowed under the FERC’s index methodology. This methodology allows for an adjustment of transportation rates effective July 1 of each year.

The North Dakota system consists of both gathering and trunkline assets. Effective January 1, 2008, two new surcharges were implemented as a part of the North Dakota Phase V expansion program, referred to as North Dakota Phase V. In August 2006, the North Dakota system submitted the Phase V Offer of Settlement to the FERC for an expansion of the system, which was approved by the Commission on October 31, 2006 (Docket No. OR06-9-000). The Phase V Offer of Settlement outlined the mainline expansion and looping surcharges as cost-of-service based surcharges that are trued-up each year to actual costs and volumes and are not subject to the FERC index methodology. These surcharges were initially applicable for five years immediately following the in-service date of North Dakota Phase V, which was January 2008. The mainline expansion surcharge is applied to all routes with a destination of Clearbrook and the looping surcharge is applied to volumes originating at either Trenton or Alexander, North Dakota. Gathering rates in effect as of December 31, 2011 are $0.76 per barrel. Effective April 1, 2010, we extended the term of the looping surcharge on our North Dakota system by four years. The impact of the term extension reduced the looping surcharge from $0.70 per barrel to $0.38 per barrel for all volumes originating from Trenton or Alexander delivered to Tioga thru 2014.

On August 26, 2010, the North Dakota system and Enbridge Bakken US filed a Petition for Declaratory Order approving the proposed priority service for the North Dakota portion of the Bakken Project, as well as the overall tariff and rate structure for the United States portions of the program. This was approved by the FERC on November 22, 2010 (FERC Docket No. OR10-19-000).

On August 30, 2010, the North Dakota system amended its Rules and Regulations tariff by implementing a temporary freeze on the creation of additional Regular Shippers effective October 1, 2010. This change intends to eliminate further proliferation of New Shippers and mitigate the erosion of Regular Shipper capacity on the system which was creating substantial administrative burden. During the 24-month period commencing on

October 1, 2010, shippers that have not yet attained Regular Shipper status as of that date will no longer be permitted to become Regular Shippers until the later of: (i) the date on which that shipper has transported crude oil during nine of the previous 12 months or (ii) a month in which the system as a whole is not in apportionment. No later than the end of the 24 month-period, the North Dakota system will re-evaluate the effects of this change and either extend, revise or permit the termination of the freeze on creation of Regular Shippers. New Shippers will continue to have access to the pipeline, but will be limited to the 10 percent of pipeline capacity reserved for their use. The North Dakota system’s Rules and Regulations tariff was approved by the FERC Order 132 FERC ¶ 61,274, issued on September 30, 2010 (Docket No. IS10-614-000).

On December 30, 2010, our North Dakota system filed to modify the existing tariffs to include rates for delivery to the International Border near Portal, North Dakota effective February 1, 2011. Due to a delay in available downstream capacity, these rates were cancelled and subsequently re-filed to be effective on March 18, 2011. This project is a result of reactivation and reversal work completed on the Portal Link, which provides export capacity into Canada providing immediate relief to the constrained pipeline infrastructure in North Dakota. This service is completely optional; therefore, the rates will only be charged to shippers using these facilities and there will be no rate impact to existing shippers not utilizing this segment. However, existing shippers may benefit from this service as volumes on PREP will reduce the expansion surcharges on the North Dakota system. Rates to the International Boundary near Portal are set equal to the rates to Clearbrook.

In addition to the temporary freeze on the creation of additional Regular Shippers, on May 16, 2011, the North Dakota system implemented a lottery process in order that New Shippers could still be able to receive a minimum batch size on the system (Docket No. IS11-299-000). This change was put into practice as the result of the continued growth in the number of New Shippers seeking access to the system.

On May 12, 2011 and July 29, 2011 in two separate filings, to be effective on June 1, 2011 and September 1, 2011 respectively, the North Dakota system cancelled several gathering and trunk line transportation rates that were under-utilized.

On October 28, 2011, notice was provided by the North Dakota system of a temporary, partial embargo for deliveries to Clearbrook, Minnesota from the Berthold, North Dakota receipt point due to vibration issues that had occurred at Berthold. This is the only receipt and delivery point impacted and was expected to only last two months. However, on December 28, 2011, the temporary, partial embargo was extended for another two months, until February 29, 2012.

On October 31, 2011, the North Dakota system filed to establish new rates to accommodate a connection to the Hawthorn Oil Transportation (North Dakota), Inc. pipeline near Stanley Station, which feeds the EOG Resources Railyard (North Dakota), Inc. Stanley Rail Facility. This service is optional and only used by those shippers wishing to use the Stanley Rail Facility. The new rates will therefore not impact existing shippers who choose not to use the service. However, existing shippers from the Alexander and Trenton receipt points could see a reduction in the Phase V surcharge rates because of the additional volumes this connection could accommodate. These rates went into effect December 1, 2011.

On November 25, 2011, the joint tariff between the North Dakota system and Plains Pipeline, L.P. was cancelled, effective December 31, 2011. While the service is no longer being provided on a joint tariff basis, local tariff rates for both the North Dakota system and Plains Pipeline, L.P. provide rates for the transportation service.

On December 30, 2011, the North Dakota system filed to establish an initial gathering service at Trenton (Williams Country), North Dakota effective February 1, 2012. For gathering into Trenton from an unaffiliated shipper a charge of $0.10 per barrel will be assessed. Rates at Trenton resulted from requests for a pipeline connection from a shipper to facilitate receipts into the Enbridge North Dakota system. Only shippers utilizing this new interconnect service will be subject to the applicable charges.

The rates, surcharges, and embargos for transportation of light crude oil to principal delivery points via trucklines on our North Dakota system are set forth below:

Our transmission and gathering pipelines and storage and processing facilities are subject to extensive federal and state environmental, operational and safety regulation. The added costs imposed by regulations are generally no different than those imposed on our competitors. The failure to comply with such rules and regulations can result in substantial penalties and/or enforcement actions and added operational costs.

Our transmission and non-rural gathering pipelines are subject to regulation by the DOT and PHMSA, under Title 49 of the United States Code of Federal Regulations Parts 190-199 (Pipeline Safety Act, or PSA) relating to the design, installation, testing, construction, operation, replacement and management of transmission and non-rural gathering pipeline facilities. PHMSA is the agency charged with regulating the safe transportation of hazardous materials under all modes of transportation, including interstate and intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations and imposing direct mandates on operators of pipelines.

In 1999, PHMSA published a final rule regarding the qualification of pipeline operations personnel. The “Operator Qualification” regulations require pipeline operators to utilize qualified individuals to perform pipeline operations and maintenance activities or tasks. The rule required pipeline operators to have a written plan in

place by April 27, 2001 and to complete qualification of personnel by October 28, 2002. We have prepared an Operator Qualification Plan, which is in compliance with PHMSA’s final rule. The implementation of this plan does not have a material effect on the operations of our pipelines.

On December 17, 2002, the Pipeline Safety Improvement Act of 2002, referred to as the PSI Act of 2002, was enacted reauthorizing and amending the PSA. The most significant amendment required natural gas pipelines to develop integrity management programs and conduct integrity assessment tests at a minimum of seven year intervals. Such tests can include internal inspection, hydrostatic pressure tests or direct assessments on pipelines in certain high consequence areas. PHMSA has since promulgated rules for this and other mandates included in the PSI Act of 2002.

On December 29, 2006, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, referred to as PIPES of 2006, was enacted, which further amended the PSA. Many of the provisions were welcome, including strengthening excavation damage prevention and enforcement. The most significant provisions of PIPES of 2006 that will affect us include a mandate to PHMSA to remove most exemptions from federal regulations for liquid pipelines operating at low stress and mandates PHMSA to undertake rulemaking requiring pipeline operators to have a human factors management plan for pipeline control room personnel, including consideration for controlling hours of service. On December 3, 2009, the final rule for the Control Room Management/Human Factors was published. The final rule applying safety regulations to all rural onshore hazardous liquid low-stress pipelines was published May 5, 2011 and became effective October 1, 2011.

We have incorporated the new requirements of the 2002 and 2006 PSA amendments into procedures and budgets, and while we expect to incur higher regulatory compliance costs, the increase is not expected to be material.

When hydrocarbons are released into the environment, PHMSA may issue a corrective action order, which can require internal inspections, pipeline pressure reductions and other methods to manage or verify the integrity of a pipeline in the affected area. Any corrective action order, such as that associated with the Line 6B crude oil release, could have a material impact on system throughput or compliance costs.

Our trucking and railcar operations are also subject to safety and permitting regulation by the DOT and state agencies with regard to the safe transportation of hazardous and other materials.

We believe that our pipeline, trucking and railcar operations are in substantial compliance with applicable operational and safety requirements. In instances of non-compliance, we have taken actions to remediate the situations. Nevertheless, significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the capabilities of our current pipeline control system or other safety equipment.

General. Our operations are subject to complex federal, state and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling, storage and release of crude oil and other liquid hydrocarbon materials or emissions from natural gas compression facilities. As with the pipeline and processing industry in general, complying with current and anticipated environmental laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position since the operations of our competitors are generally similarly affected.

In addition to compliance costs, violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. We believe that our operations are in substantial compliance with applicable environmental laws and regulations.

There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of crude oil, liquids, natural gas or other substances from our pipelines or storage facilities. Such accidental releases could, to the extent not insured, subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines, penalties or damages for related violations of environmental laws or regulations.

Although we are entitled, in certain circumstances, to indemnification from third parties for environmental liabilities relating to assets we acquired from those parties, these contractual indemnification rights are limited, and accordingly, we may be required to bear substantial environmental expenses. However, we believe that through our due diligence process, we identify and manage substantial issues.

Air and Water Emissions. Our operations are subject to the federal Clean Air Act, or CAA, and the federal Clean Water Act, or CWA, and comparable state and local statutes. We anticipate, therefore, that we will incur costs in the next several years for air pollution control equipment and spill prevention measures in connection with maintaining existing facilities and obtaining permits and approvals for any new or acquired facilities. In January 2010, the Environmental Protection Agency, or EPA, published that the effective date of the Spill Prevention, Control, and Countermeasures Rule Amendments would be November 10, 2010. However, on October 7, 2010, the EPA issued an extension to the compliance date to November 10, 2011. While the operations of our pipeline facilities are subject to the rule, we have prepared the necessary plans for compliance prior to the November 2011 effective date. In 2009, the EPA published the Greenhouse Gas Recordkeeping and Reporting Rule, which requires applicable facilities to record and report greenhouse gas emissions from combustion sources beginning January 1, 2010. As a part of the reporting rule, in November 2010, the EPA published the requirements for reporting emissions from Petroleum and Natural Gas Systems beginning January 1, 2011. While the operations of our pipelines are subject to the rule, we do not believe that the rule requirements will have a material effect on our operations. Annual emissions from combustion activities in 2010 were reported prior to the September 30, 2011 deadline. Facilities subject to existing Greenhouse Gas Reporting rules will report emissions prior to the March 31, 2012 deadline for 2011 emissions. Additionally, facilities subject to new reporting rules in 2011 will report prior to the September 28, 2012 deadline.

The Oil Pollution Act, or OPA, was enacted in 1990 and amends parts of the CWA and other statutes as they pertain to the prevention of and response to oil spills. Under the OPA, we could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from our facilities into navigable waters, along shorelines or in an exclusive economic zone of the United States. The OPA also imposes certain spill prevention, control and countermeasure requirements for many of our non-pipeline facilities, such as the preparation of detailed oil spill emergency response plans and the construction of dikes or other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or release. For our liquid pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. For our non-transportation facilities, such as storage tanks that are not integral to pipeline transportation system, the OPA regulations are promulgated by the EPA. We believe that we are in material compliance with these laws and regulations.

Hazardous Substances and Waste Management. The federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA (also known as the “Superfund” law) and similar state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owners or operators of waste disposal sites and companies that disposed or arranged for disposal of hazardous substances found at such sites. We may generate some wastes that fall within the definition of a “hazardous substance.” We may, therefore, be jointly and severally liable under CERCLA for all or part of any costs required to clean up and restore sites at which such wastes have been disposed. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous

state laws may apply to a broader range of substances than CERCLA and, in some instances, may offer fewer exemptions from liability. We have not received any notification that we may be potentially responsible for material cleanup costs under CERCLA or similar state laws.

Site Remediation. We own and operate a number of pipelines, gathering systems, storage facilities and processing facilities that have been used to transport, distribute, store and process crude oil, natural gas and other petroleum products. Many of our facilities were previously owned and operated by third parties whose handling, disposal and release of petroleum and waste materials were not under our control. The age of the facilities, combined with the past operating and waste disposal practices, which were standard for the industry and regulatory regime at the time, have resulted in soil and groundwater contamination at some facilities due to historical spills and releases. Such contamination is not unusual within the natural gas and petroleum industry. Historical contamination found on, under or originating from our properties may be subject to CERCLA, the Resource Conservation & Recovery Act and analogous state laws as described above.

Under these laws, we could incur substantial expense to remediate such contamination, including contamination caused by prior owners and operators. In addition, Enbridge Management, as the entity with managerial responsibility for us, could also be liable for such costs to the extent that we are unable to fulfill our obligations. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate.

Neither we nor Enbridge Management have any employees. Our General Partner has delegated to Enbridge Management, pursuant to a delegation of control agreement, substantially all of the responsibility for our day-to-day management and operation. Our General Partner, however, retains certain functions and approval rights over our operations. To fulfill its management obligations, Enbridge Management has entered into agreements with Enbridge and several of its affiliates to provide Enbridge Management with the necessary services and support personnel who act on Enbridge Management’s behalf as its agents. We are ultimately responsible for reimbursing these service providers based on the costs that they incur in performing these services.

Our operations are subject to many hazards inherent in the liquid petroleum and natural gas gathering, treating, processing and transportation industry. We maintain commercial liability insurance coverage that is consistent with coverage considered customary for our industry. We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates through the policy renewal date of May 1, 2012. We do not maintain insurance coverage for interruption of our operations except for water crossings.

The general pollution liability insurance policies are in United States Dollar, or USD, denominated policies, while our property and business interruption policy is a CAD denominated policy. The coverage limits are deductible amounts at December 31, 2011 for our insurance policies denominated in CAD and USD were as follows:

We can make no assurance that the insurance coverage we maintain will be available or adequate for any particular risk or loss or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows.

We are not a taxable entity for United States federal income tax purposes. Generally, federal and state income taxes on our taxable income are borne by our individual partners through the allocation of our taxable income. In a limited number of states, an income tax is imposed upon us and generally, not our individual partners. The income tax that we bear is reflected in our consolidated financial statements. The allocation of taxable income to our individual partners may vary substantially from net income reported in our consolidated statements of income.

We file annual, quarterly and other reports, and any amendments to those reports and information with the SEC, under the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We also make available free of charge on or through our Internet website http://www.enbridgepartners.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not part of this report.

We encourage you to read the risk factors below in connection with the other sections of this Annual Report on Form 10-K.

Our actual construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate, which may limit our ability to maintain or increase cash distributions.

Our strategy contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets. The construction of new assets involves numerous regulatory, environmental, legal, political, materials and labor cost and operational risks that are difficult to predict and beyond our control. As a result, we may not be able to complete our projects at the costs currently estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

Any or all of these methods may not be available when needed or may adversely affect our future results of operations and cash flows.

Our revenues and cash flows may not increase immediately on our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. If our revenues and cash flow do not increase at projected levels because of substantial unanticipated delays or other factors, we may not meet our obligations as they become due, and we may need to reduce or reprioritize our capital budget, sell non-strategic assets, access the capital markets or reassess our level of distributions to unitholders to meet our capital requirements.

Our ability to access capital markets and credit on attractive terms to obtain funding for our capital projects and acquisitions may be limited.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as those prevalent during the recessionary period of 2008 and through much of 2010, periodically result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, our ability to raise capital through equity or debt offerings. Additionally, the availability and cost of obtaining credit commitments from lenders can change as economic conditions and banking regulations reduce the credit that lenders have available or are willing to lend. These conditions, along with significant write-offs in the financial services sector and the re-pricing of market risks, can make it difficult to obtain funding for our capital needs from the capital markets on acceptable economic terms. As a result, we may revise the timing and scope of these projects as necessary to adapt to prevailing market and economic conditions.

Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or capital markets on acceptable terms, if needed and to the extent required. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our

development plan, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

A downgrade in our credit rating could require us to provide collateral for our hedging liabilities and negatively impact our interest costs and borrowing capacity under our New Credit Facility.

Standard & Poor’s, or S&P, Dominion Bond Rating Service, or DBRS, and Moody’s Investors Service, referred to as Moody’s, rate our non-credit enhanced, senior unsecured debt. Although we are not aware of any current plans by the ratings agencies to lower their respective ratings on such debt, we cannot be assured that such credit ratings will not be downgraded.

Currently, we are parties to certain International Swaps and Derivatives Association, Inc., or ISDA^®, agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA^® agreements require us to provide assurances of performance if our counterparties’ exposure to us exceeds certain levels or thresholds. We generally provide letters of credit to satisfy such requirements. At December 31, 2011, we have provided $173.2 million in the form of letters of credit as assurances of performance for our then outstanding derivative financial instruments. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by S&P and Moody’s, we would be required to provide letters of credit in substantially greater amounts to satisfy the requirements of our ISDA^® agreements. For example if our credit ratings had been at the lowest level of investment grade at December 31, 2011, we would have been required to provide additional letters of credit in the aggregate amount of $63.9 million. The amounts of any letters of credit we would have to establish under the terms of our ISDA^® agreements would reduce the amount that we are able to borrow under our senior unsecured revolving credit facility, referred to as our New Credit Facility.

We may not have sufficient cash flows to enable us to continue to pay distributions at the current level.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at the current level. The amount of cash we are able to distribute depends on the amount of cash we generate from our operations, which can fluctuate quarterly based upon a number of factors, including:

In addition, the amount of cash we distribute depends primarily on our cash flow rather than net income or net loss. Therefore, we may make cash distributions during periods when we record net losses or may make no distributions during periods when we record net income.

Our acquisition strategy may be unsuccessful if we incorrectly predict operating results, are unable to identify and complete future acquisitions and integrate acquired assets or businesses.

The acquisition of complementary energy delivery assets is a component of our strategy. Acquisitions present various risks and challenges, including:

In addition, we may be unable to identify acquisition targets and consummate acquisitions in the future.

Our financial performance could be adversely affected if our pipeline systems are used less.

Our financial performance depends to a large extent on the volumes transported on our liquids or natural gas pipeline systems. Decreases in the volumes transported by our systems can directly and adversely affect our revenues and results of operations. The volume transported on our pipelines can be influenced by factors beyond our control including:

As an example, the volume of shipments on our Lakehead system depends heavily on the supplies of western Canadian crude oil. Insufficient supplies of western Canadian crude oil will adversely affect our business by limiting shipments on our Lakehead system. Decreases in conventional crude oil exploration and production activities in western Canada and other factors, including supply disruption, higher development costs and competition, can slow the rate of growth of our Lakehead system. The volume of crude oil that we transport on our Lakehead system also depends on the demand for crude oil in the Great Lakes and Midwest regions of the United States and the volumes of crude oil and refined products delivered by others into these regions and the province of Ontario. Pipeline capacity for the delivery of crude oil to the Great Lakes and Midwest regions of the United States currently exceeds refining capacity.

In addition, our ability to increase deliveries to expand our Lakehead system in the future depends on increased supplies of western Canadian crude oil. We expect that growth in future supplies of western Canadian crude oil will come from oil sands projects in Alberta. Full utilization of additional capacity as a result of our Alberta Clipper and Southern Access pipelines and future expansions of our Lakehead system, will largely depend on these anticipated increases in crude oil production from oil sands projects. A reduction in demand for crude oil or a decline in crude oil prices may make certain oil sands projects uneconomical since development costs for production of crude oil from oil sands is greater than development costs for production of conventional crude oil. Oil sands producers may cancel or delay plans to expand their facilities, as some oil sands producers have done in recent years, if crude oil prices are at levels that do not support expansion. Additionally, measures adopted by the government of the province of Alberta to increase its share of revenues from oil sands development coupled with a decline in crude oil prices could reduce the volume growth we have anticipated in expanding the capacity of our crude oil pipelines.

The volume of shipments on natural gas and NGL systems depends on the supply of natural gas and NGLs available for shipment from the producing regions that supply these systems. Supply available for shipment can be affected by many factors, including commodity prices, weather and drilling activity among other factors listed above. Volumes shipped on these systems are also affected by the demand for natural gas and NGLs in the markets these systems serve. Existing customers may not extend their contracts for a variety of reasons, including a decline in the availability of natural gas from our Mid-Continent, United States Gulf Coast and East Texas producing regions, or if the cost of transporting natural gas from other producing regions through other pipelines into the markets served by the natural gas systems were to render the delivered cost of natural gas on our systems uneconomical. We may be unable to find additional customers to replace the lost demand or transportation fees.

Our Lakehead system faces current and potentially further competition for transporting western Canadian crude oil from other pipelines, which may reduce our volumes and the associated revenues. For our cost-of-service arrangements, these lower volumes will increase our transportation rates. The increase in transportation rates could result in rates that are higher than competitive conditions will otherwise permit. Our Lakehead system competes with other crude oil and refined product pipelines and other methods of delivering crude oil and refined products to the refining centers of Minneapolis-St. Paul, Minnesota, Chicago, Detroit, Michigan, Toledo, Buffalo, New York, and Sarnia and the refinery market and pipeline hub located in the Patoka/Wood River area of southern Illinois. Refineries in the markets served by our Lakehead system compete with refineries in western Canada, the province of Ontario and the Rocky Mountain region of the United States for supplies of western Canadian crude oil.

Our Ozark pipeline system faces a significant increase in competition from a competitor’s new pipeline from Hardisty to Patoka, which commenced deliveries to the Patoka and Wood River areas of southern Illinois in the third quarter of 2010.

We also encounter competition in our natural gas gathering, treating, and processing and transmission businesses. A number of new interstate natural gas transmission pipelines being constructed could reduce the revenue we derive from the intrastate transmission of natural gas. Many of the large wholesale customers served

by our natural gas systems have multiple pipelines connected or adjacent to their facilities. Thus, many of these wholesale customers have the ability to purchase natural gas directly from a number of pipelines or from third parties that may hold capacity on other pipelines. Most natural gas producers and owners have alternate gathering and processing facilities available to them. In addition, they have other alternatives, such as building their own gathering facilities or, in some cases, selling their natural gas supplies without processing. Some of our natural gas marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

As part of our natural gas marketing activities, we purchase natural gas at prices determined by prevailing market conditions. Following our purchase of natural gas, we generally resell natural gas at a higher price under a sales contract that is generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our natural gas operations may be affected by the following factors:

Our results may be adversely affected by commodity price volatility and risks associated with our hedging activities.

The prices of natural gas, NGLs and crude oil are inherently volatile, and we expect this volatility will continue. We buy and sell natural gas and NGLs in connection with our marketing activities. Our exposure to commodity price volatility is inherent to our natural gas and NGL purchase and resale activities, in addition to our natural gas processing activities. To the extent that we engage in hedging activities to reduce our commodity price exposure, we may be prevented from realizing the full benefits of price increases above the level of the hedges. However, because we are not fully hedged, we will continue to have commodity price exposure on the unhedged portion of the fees we derive from the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As of December 31, 2011, we are exposed to fluctuations in commodity prices on 30 to 40 percent of the natural gas, NGLs and condensate we expect to receive in the near term. As a result of this unhedged exposure, a substantial decline in the prices of these commodities could adversely affect our financial performance.

Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective and our hedging policies and procedures are not followed properly or do not work as intended. Further, hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to perform its obligations under the contracts, particularly during periods of weak and volatile economic conditions.

In addition, certain of the financial instruments we use to hedge our commodity risk exposures must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to fluctuations in commodity prices.

Changes in, or challenges to, our rates could have a material adverse effect on our financial condition and results of operations.

The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies or both. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates, the profitability of our pipeline businesses would suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which delay could further reduce our cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services.

We believe that the rates we charge for transportation services on our interstate common carrier oil and open access natural gas pipelines are just and reasonable under the ICA and NGA, respectively. However, because the rates that we charge are subject to review upon an appropriately supported protest or complaint, or a regulator’s own initiative, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier oil and open access natural gas pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations.

Our interstate pipelines and certain activities of our intrastate natural gas pipelines are subject to FERC regulation of terms and conditions of service. In the case of interstate natural gas pipelines, FERC also establishes requirements respecting the construction and abandonment of pipeline facilities. FERC has pending proposals to increase posting and other compliance requirements applicable to natural gas markets. Such changes could prompt an increase in FERC regulatory oversight of our pipelines and additional legislation that could increase our FERC regulatory compliance costs and decrease the net income generated by our pipeline systems.

Compliance with environmental and operational safety regulations may expose us to significant costs and liabilities.

Our pipeline, gathering, processing and trucking operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, oftentimes requiring difficult and costly actions. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our operation of liquid petroleum and natural gas gathering, processing, treating and transportation facilities exposes us to the risk of incurring significant environmental costs and liabilities. Additionally, operational modifications necessary to comply with regulatory requirements and resulting from our handling of liquid petroleum and natural gas, historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or safety and health incidents can also result in significant cost. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of liquid petroleum and natural gas and wastes on, under or from our properties and facilities, many of which have been used for gathering or processing activities for a number of years, oftentimes by third parties not under our

control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our liquid petroleum and natural gas or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may also incur costs in the future due to changes in environmental and safety laws and regulations, or re-interpretations of enforcement policies or claims for personal, property or environmental damage. We may not be able to recover these costs from insurance or through higher rates.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

In June of 2009, the United States House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which was then placed on the United States Senate legislative calendar for consideration. However, the Senate never acted on the legislation during the 111th Congress, which ended at the end of 2010. The 112th Congress, which began in January, 2011, and extends through the end of 2012 is not expected to act on comprehensive climate change legislation. The U.S Environmental Protection Agency (EPA) is working on regulations to limit greenhouse gas emissions within its existing statutory authority under the Clean Air Act. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, on April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal CAA. In July 2008, the EPA released an Advanced Notice of Proposed Rulemaking regarding possible future regulation of greenhouse gas emissions under the CAA and other potential methods of regulating greenhouse gases. On December 7, 2009, the EPA finalized its response to the Massachusetts, et al. v. EPA decision by issuing its “endangerment finding” that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. Moreover, on September 22, 2009, the EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA finalized a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems. Finally, the May 2010 promulgation of regulations to control the greenhouse gas emissions from light-duty motor vehicles automatically triggered CAA provisions that, in general, require stationary source facilities that emit more than 25,000 tons per year of greenhouse gas equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA finalized the “tailoring rule,” which served to increase the greenhouse gas emissions threshold that triggers the permitting requirements for stationary sources. Under a phased-in approach, for most purposes, new permitting provisions are required for facilities that emit 100,000 tons per year or more of carbon dioxide equivalent. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted and upheld by the judicial system as initially written, if at all, or how legislation or new regulation that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions.

The United States’ Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs as discussed above. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for our services.

Pipeline operations involve numerous risks that may adversely affect our business and financial condition.

Operation of complex pipeline systems, gathering, treating, processing and trucking operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Costs of pipeline seepage over time may be mitigated through insurance, however, if not discovered within the specified insurance time period we would incur full costs for the incident. In addition, we could be subject to significant fines and penalties from regulators in connection with such events. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these catastrophic events could be greater.

United States based oil sands development opponents as well as others concerned with environmental impacts of pipeline routes advocated by our competitors have utilized political pressure to influence the timing and whether such permits are granted which could impact future pipeline development.

Measurement adjustments on our pipeline system can be materially impacted by changes in estimation, commodity prices and other factors.

Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum pipelines. The three types of oil measurement adjustments that routinely occur on our systems include:

Quantifying oil measurement adjustments is inherently difficult because physical measurements of volumes are not practical as products continuously move through our pipelines and virtually all of our pipeline systems are located underground. In our case, measuring and quantifying oil measurement losses is especially difficult because of the length of our pipeline systems and the number of different grades of crude oil and types of crude oil products we transport. Accordingly, we utilize engineering-based models and operational assumptions to estimate product volumes in our system and associated oil measurement losses.

Natural gas measurement adjustments occur as part of the normal operating conditions associated with our natural gas pipelines. The quantification and resolution of measurement adjustments is complicated by several factors including: (1) the significant quantities (i.e., thousands) of measurement meters that we use throughout our natural gas systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas in the streams gathered and processed through our systems; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our natural gas systems.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE AND RELATIONSHIPS WITH OUR GENERAL PARTNER AND ENBRIDGE MANAGEMENT

The interests of Enbridge may differ from our interests and the interests of our security holders, and the board of directors of Enbridge Management may consider the interests of all parties to a conflict, not just the interests of our security holders, in making important business decisions.

Enbridge indirectly owns all of the shares of our General Partner and all of the voting shares of Enbridge Management, and elects all of the directors of both companies. Furthermore, some of the directors and officers of our General Partner and Enbridge Management are also directors and officers of Enbridge. Consequently, conflicts of interest could arise between our unitholders and Enbridge.

Our partnership agreement limits the fiduciary duties of our General Partner to our unitholders. These restrictions allow our General Partner to resolve conflicts of interest by considering the interests of all of the parties to the conflict, including Enbridge Management’s interests, our interests and those of our General Partner. In addition, these limitations reduce the rights of our unitholders under our partnership agreement to sue our General Partner or Enbridge Management, its delegate, should its directors or officers act in a way that, were it not for these limitations of liability, would constitute breaches of their fiduciary duties.

We do not have any employees. In managing our business and affairs, we rely on employees of Enbridge, and its affiliates, who act on behalf of and as agents for us. A decrease in the availability of employees from Enbridge could adversely affect us.

Our partnership agreement and the delegation of control agreement limit the fiduciary duties that Enbridge Management and our General Partner owe to our unitholders and restrict the remedies available to our unitholders for actions taken by Enbridge Management and our General Partner that might otherwise constitute a breach of a fiduciary duty.

Our partnership agreement contains provisions that modify the fiduciary duties that our General Partner would otherwise owe to our unitholders under state fiduciary duty law. Through the delegation of control agreement, these modified fiduciary duties also apply to Enbridge Management as the delegate of our General Partner. For example, our partnership agreement:

These and similar provisions in our partnership agreement may restrict the remedies available to our unitholders for actions taken by Enbridge Management or our General Partner that might otherwise constitute a breach of a fiduciary duty.

Potential conflicts of interest may arise among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Because the fiduciary duties of the directors of our General Partner and Enbridge Management have been modified, the directors may be permitted to make decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders.

Conflicts of interest may arise from time to time among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Conflicts of interest may also arise from time to time between us and our unitholders, on the one hand, and Enbridge Management and its shareholders, on the other hand. In managing and controlling us as the delegate of our General Partner, Enbridge Management may consider the interests of all parties to a conflict and may resolve those conflicts by making decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders. The following decisions, among others, could involve conflicts of interest:

In these and similar situations, any decision by Enbridge Management may benefit one group more than another, and in making such decisions, Enbridge Management may consider the interests of all groups, as well as other factors, in deciding whether to take a particular course of action.

In other situations, Enbridge may take certain actions, including engaging in businesses that compete with us, that are adverse to us and our unitholders. For example, although Enbridge and its subsidiaries are generally restricted from engaging in any business that is in direct material competition with our businesses, that restriction is subject to the following significant exceptions:

Since we were not engaged in any aspect of the natural gas business at the time of our initial public offering, Enbridge and its subsidiaries are not restricted from competing with us in any aspect of the natural gas business. In addition, Enbridge and its subsidiaries would be permitted to transport crude oil and liquid petroleum over routes that are not the same as our Lakehead system, even if such transportation is in direct material competition with our business.

These exceptions also expressly permitted the reversal by Enbridge in 1999 of one of its pipelines that extends from Sarnia to Montreal, Quebec. As a result of this reversal, Enbridge competes with us to supply crude oil to the Ontario market.

We can issue additional common or other classes of units, including additional i-units to Enbridge Management when it issues additional shares, which would dilute your ownership interest.

The issuance of additional common or other classes of units by us, including the issuance of additional i-units to Enbridge Management when it issues additional shares may have the following effects:

Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units that it currently owns could reduce the market price of the Class A common units. Our partnership agreement allows the General Partner to cause us to register for public sale any units held by the General Partner or its affiliates. A public or private sale of the Class A or Class B common units currently held by our General Partner could absorb some of the trading market demand for the outstanding Class A common units.

Our unitholders have limited voting rights on matters affecting our business, which may have a negative effect on the price at which our common units trade. In particular, the unitholders did not elect our General Partner or the directors of our General Partner or Enbridge Management and have no rights to elect our General

Partner or the directors of our General Partner or Enbridge Management on an annual or other continuing basis. Furthermore, if unitholders are not satisfied with the performance of our General Partner, they may find it difficult to remove our General Partner. Under the provisions of our partnership agreement, our General Partner may be removed upon the vote of at least 66 ²/₃ percent of the outstanding common units (excluding the units held by the General Partner and its affiliates) and a majority of the outstanding i-units voting together as a separate class (excluding the number of i-units corresponding to the number of shares of Enbridge Management held by our General Partner and its affiliates). Such removal must, however, provide for the election and succession of a new general partner, who may be required to purchase the departing general partner interest in us in order to become the successor general partner. Such restrictions may limit the flexibility of the limited partners in removing our general partner, and removal may also result in the general partner interest in us held by the departing general partner being converted into Class A common units.

We are a holding company and depend entirely on our operating subsidiaries’ distributions to service our debt obligations.

We are a holding company with no material operations. If we cannot receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations. Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions, which could further limit each operating subsidiaries’ ability to make distributions to us.

The debt securities we issue and any guarantees issued by any of our subsidiaries that are guarantors will be structurally subordinated to the claims of the creditors of any of our operating subsidiaries who are not guarantors of the debt securities. Holders of the debt securities will not be creditors of our operating subsidiaries who have not guaranteed the debt securities. The claims to the assets of these non-guarantor operating subsidiaries derive from our own ownership interest in those operating subsidiaries. Claims of our non-guarantor operating subsidiaries’ creditors will generally have priority as to the assets of such operating subsidiaries over our own ownership interest claims and will therefore have priority over the holders of our debt, including the debt securities. Our non-guarantor operating subsidiaries’ creditors may include:

Enbridge Management’s discretion in establishing our cash reserves gives it the ability to reduce the amount of cash available for distribution to our unitholders.

Enbridge Management may establish cash reserves for us that in its reasonable discretion are necessary to fund our future operating and capital expenditures, provide for the proper conduct of business, and comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves affect the amount of cash available for distribution to holders of our common units.

Agreements relating to our debt restrict our ability to make distributions, which could adversely affect the value of our Class A common units, and our ability to incur additional debt and otherwise maintain financial and operating flexibility.

We are prohibited from making distributions to our unitholders during (1) the existence of certain defaults under our New Credit Facility or (2) during a period in which we have elected to defer interest payments on the Junior Notes, subject to limited exceptions as set forth in the related indenture. Further, the agreements governing our New Credit Facility may prevent us from engaging in transactions or capitalizing on business opportunities that we believe could be beneficial to us by requiring us to comply with various covenants, including the maintenance of certain financial ratios and restrictions on:

Although the indentures governing our senior notes do not limit our ability to incur additional debt, they impose restrictions on our ability to enter into mergers or consolidations and sales of all or substantially all of our assets, to incur liens to secure debt and to enter into sale and leaseback transactions. A breach of any restriction under our New Credit Facility or our indentures could permit the holders of the related debt to declare all amounts outstanding under those agreements immediately due and payable and, in the case of our New Credit Facility, terminate all commitments to extend further credit. Any subsequent refinancing of our current debt or any new indebtedness incurred by us or our subsidiaries could have similar or greater restrictions.

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders could be substantially reduced.

As long as we qualify to be treated as a partnership for federal income tax purposes, we are not subject to federal income tax. Although a publicly-traded limited partnership is generally treated as a corporation for federal income tax purposes, a publicly-traded partnership such as us can qualify to be treated as a partnership for federal income tax purposes under current law so long as for each taxable year at least 90% of our gross income is derived from specified investments and activities. We believe that we qualify to be treated as a partnership for federal income tax purposes because we believe that at least 90% of our gross income for each taxable year has been and is derived from such specified investments and activities. Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this gross income requirement for any taxable year and the Internal Revenue Service, or IRS, does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or certain other matters affecting us.

Additionally, current law may change so as to cause us to be treated as a corporation for federal income tax purposes without regard to our sources of income or otherwise subject us to entity-level taxation. Legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner

that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may be applied retroactively.

If we were to be treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Under current law, distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss or deduction would flow through to our unitholders. If we were treated as a corporation at the state level, we may also be subject to the income tax provisions of certain states. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax at a minimum effective rate of 0.7% of our gross income apportioned to Texas in the prior year.

If we become subject to federal income tax and additional state taxes, the additional taxes we pay will reduce the amount of cash we can distribute each quarter to the holders of our Class A and B common units and the number of i-units that we will distribute quarterly. Therefore, our treatment as a corporation for federal income tax purposes or becoming subject to a material amount of additional state taxes could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. Moreover, our payment of additional federal and state taxes could materially and adversely affect our ability to make payments on our debt securities.

If the IRS contests our curative tax allocations or other federal income tax positions we take, the market for our Class A common units may be impacted and the cost of any IRS contest will reduce our cash available for distribution or payments on our debt securities.

Our partnership agreement allows curative allocations of income, deduction, gain and loss by us to account for differences between the tax basis and fair market value of property at the time the property is contributed or deemed contributed to us and to account for differences between the fair market value and book basis of our assets existing at the time of issuance of any Class A common units. If the IRS does not respect our curative allocations, ratios of taxable income to cash distributions received by the holders of Class A common units will be materially higher than previously estimated.

The IRS may adopt positions that differ from the positions we have taken or may take on certain tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we have taken or may take. A court may not agree with some or all of the positions we have taken or may take. Any contest with the IRS may materially and adversely impact the market for our Class A common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution or payments on our debt securities.

The tax liability of our unitholders could exceed their distributions or proceeds from sales of Class A common units.

Because our unitholders will generally be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income tax and, in some cases, state and local income taxes on their allocable share of our income, even if they do not receive cash distributions from us. Unitholders will not necessarily receive cash distributions equal to the tax on their allocable share of our taxable income.

Tax gain or loss on the disposition of our Class A common units could be more or less than expected.

If a unitholder disposes of Class A common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Class A common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their Class A common units, the amount, if any, of such prior excess distributions with respect to their Class A common units sold will, in effect, become taxable income to the unitholder if the Class A common units are sold at a price greater than the unitholder’s tax basis in those Class A common units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells Class A common units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

As a result of investing in our Class A common units, a unitholder may become subject to state and local taxes and return filing requirements in the states where we or our subsidiaries own property and conduct business.

In addition to federal income taxes, a unitholder will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if such unitholder does not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We or our subsidiaries own property and conduct business in the states of Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, New York, South Carolina, North Carolina, North Dakota, Oklahoma, Tennessee, Texas and Wisconsin. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may acquire property or conduct business in additional states or in foreign jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all required United States federal, foreign, state and local tax returns.

Ownership of Class A common units raises issues for tax-exempt entities and other investors.

An investment in our Class A common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts, known as IRAs, Keogh plans and other retirement plans, regulated investment companies and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from United States federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-United States persons should consult their tax adviser before investing in our Class A common units.

We adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the General Partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Class A common units.

When we issue additional Class A common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital

accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of Class A common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of Class A common units and could have a negative impact on the value of the Class A common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in our termination as a partnership for United States federal income tax purposes.

We will be considered to have been terminated for United States federal tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions available in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal tax purposes. If treated as a new partnership for federal tax purposes, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

We treat each purchaser of Class A common units as having the same tax benefits without regard to the actual Class A common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing more tax and may adversely affect the value of the Class A common units.

Because we cannot match transferors and transferees of our Class A common units and to maintain the uniformity of the economic and tax characteristics of our Class A common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding Class A common units. A subsequent holder of those Class A common units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). However, because we cannot identify these Class A common units once they are traded by the initial holder, we do not give any subsequent holder of a Class A common unit any such amortization deduction. This approach understates deductions available to those unitholders who own those Class A common units and results in a reduction in the tax basis of those Class A common units by the amount of the deductions that were allowable but were not taken.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Internal Revenue Code Section 743(b). If so, because neither we nor a unitholder can identify the Class A common units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling Class A common units within the period under audit as if all unitholders owned Class A common units with respect to which allowable deductions were not taken. Any position we take that is

inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of Class A common units and could have a negative impact on the value of the Class A common units or result in audit adjustments to our unitholders’ tax returns.

A unitholder whose Class A common units are loaned to a “short seller” to cover a short sale of Class A common units may be considered as having disposed of those Class A common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those Class A common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose Class A common units are loaned to a “short seller” to cover a short sale of Class A common units may be considered as having disposed of those Class A common units, such unitholder may no longer be treated as a partner with respect to those Class A common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Class A common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Class A common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their Class A common units.

A description of our properties and maps depicting the locations of our liquids and natural gas systems are included in Item 1. Business, which is incorporated herein by reference.

In general, our systems are located on land owned by others and are operated under perpetual easements and rights-of-way, licenses or permits that have been granted by private land owners, public authorities, railways or public utilities. Our liquids systems have pumping stations, tanks, terminals and certain other facilities that are located on land that is owned by us and used by us under easements or permits. Additionally, our natural gas systems have natural gas compressor stations, processing plants and treating plants, the vast majority of which are located on land that is owned by us and used by us under easements or permits.

Titles to our properties acquired in our natural gas systems are subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part II, Item 8. Financial Statements and Supplementary Data, under Note 13. Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference.

Item 5. Market for Registrant’s Common Equity and Related Unitholder Matters

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol “EEP.” The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2011 and 2010 are summarized as follows:

On March 12, 2012 the last reported sales price of our Class A common units on the NYSE was $31.77. At January 31, 2012, there were approximately 68,000 Class A common unitholders, of which there were approximately 1,200 registered Class A common unitholders of record. There is no established public trading market for our Class B common units, all of which are held by the General Partner, or our i-units, all of which are held by Enbridge Management.

The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto beginning at page 81. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


Date of Acquisition / Disposition		Acquisition / Disposition
September 2010		Acquisition of the Elk City system in Oklahoma and Texas.
November 2009		Disposition of natural gas pipelines located predominately outside of Texas.
May 2009		Acquisition of a portion of a crude oil pipeline system running from Flanagan, Illinois to Griffith, Indiana.
January 2009		Disposition of offshore natural gas pipelines.


Date of Debt Issuance	Debt Type	Amount of Debt Issuance
September 2011	4.200% Senior Notes	$	600
September 2011	5.500% Senior Notes	$	150
September 2010	5.500% Senior Notes	$	400
March 2010	5.200% Senior Notes	$	500
December 2008	9.875% Senior Notes	$	500
April 2008	6.500% Senior Notes	$	400
April 2008	7.500% Senior Notes	$	400
December 2007	Affiliate Note Payable	$	130
September 2007	Junior Subordinated Notes	$	400
August 2007	Zero coupon notes	$	200


Date of Unit Issuance	Class of Limited Partnership Interest		Number of Units Issued		Net Proceeds Including General Partner Contribution
2011 Equity Distribution Agreement issuances		Class A		3,084,208	$	95.5
December 2011		Class A		9,775,000	$	298.1
September 2011		Class A		8,000,000	$	222.9
July 2011		Class A		8,050,000	$	238.6
2010 Equity Distribution Agreement issuances		Class A		2,237,402	$	59.9
November 2010		Class A		11,960,000	$	354.8
October 2009		Class A		42,490	$	1.0
December 2008		Class A		32,500,000	$	509.8
March 2008		Class A		9,200,000	$	221.8
May 2007		Class A		10,600,000	$	308.0
April 2007		Class C		11,861,584	$	320.8


Fiscal Year	Amount of Distribution of i-units to i-unit Holders		Amount of Distribution of Class C Units to Class C Unitholders		Retained from General Partner		Distribution of Cash
2011	$	75.7	$	—	$	1.5	$	565.7
2010	$	68.3	$	—	$	1.4	$	481.6
2009	$	61.1	$	60.3	$	2.4	$	395.0
2008	$	54.2	$	72.2	$	2.6	$	286.7
2007	$	48.4	$	59.1	$	2.3	$	245.4

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes beginning in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

In July 2011, the board of directors of Enbridge Management, as delegate of our General Partner, approved a quarterly distribution that reflected a $0.01875 per unit increase over the prior quarterly distribution rate, which increased our distribution rate to $2.13 on an annualized basis.

We provide services to our customers and returns for our unitholders primarily through the following activities:

We conduct our business through three business segments: Liquids, Natural Gas and Marketing. These segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

The following table reflects our operating income by business segment and corporate charges for each of the years ended December 31, 2011, 2010 and 2009. We have removed from “Income (loss) from continuing operations” for each period, the amounts comprising the operating results of non-core natural gas pipeline assets that we sold in November 2009 and presented the amounts in “Loss from discontinued operations.”

Contractual arrangements in our Liquids, Natural Gas and Marketing segments expose us to market risks associated with changes in commodity prices where we receive crude oil, natural gas or NGLs in return for the

services we provide or where we purchase natural gas or NGLs. Our unhedged commodity position is fully exposed to fluctuations in commodity prices. These fluctuations can be significant if commodity prices experience significant volatility. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in crude oil, natural gas and NGL prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of authoritative accounting guidance, which can create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. These systems largely consist of FERC-regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.

The operating income of our Liquids business for the year ended December 31, 2011 increased $840.9 million from the same period in 2010, primarily due to the following:

Our Natural Gas segment consists of natural gas gathering and transmission pipelines as well as natural gas treating and processing plants and related facilities. The revenues of our Natural Gas segment are associated with services we provide to gather and process natural gas and to transport natural gas on our pipelines. Generally, our revenues are in the form of fee for service arrangements and sales of natural gas and NGLs.

The operating income of our Natural Gas business for the year ended December 31, 2011 increased $31.2 million, as compared with the same period of 2010, primarily due to the following:

Our Marketing segment provides supply, transmission, storage and sales services to producers and wholesale customers on our gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Our Marketing activities are primarily undertaken to realize incremental revenue on gas purchased at the wellhead, increase pipeline utilization and provide other services that are valued by our customers.

The operating income of our Marketing business for the year ended December 31, 2011 decreased $4.5 million, as compared with the same period of 2010. Included in the operating results of our Marketing business for the year ended December 31, 2011 were unrealized, non-cash, mark-to-market, net gains of $0.7 million associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with $6.7 million of unrealized, non-cash, mark-to-market, net losses for the year ended December 31, 2010. Offsetting our unrealized, non-cash, mark-to-market net gains for the current period and contributing to the operating loss of our Marketing business were relatively stable natural gas prices during the year ended December 31, 2011, which limited opportunities to benefit from significant price differentials between market centers.

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices and interest rates and to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as follows:

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. We provide a detailed description of each of these systems in Item 1. Business. The following tables set forth the operating results and statistics of our Liquids segment for the periods presented:

The operating results of our Liquids business were significantly affected by the crude oil releases from Lines 6A and 6B of our Lakehead system. Our discussion of the environmental costs associated with these crude oil releases is presented below in the section titled “Operating Impact of Lines 6A and 6B Crude Oil Releases.” The immediately following discussion focuses on the operating results of our Liquids business.

The operating revenue of our Liquids business increased for the year ended December 31, 2011 when compared with the same period in 2010 partially due to higher average daily delivery volumes on all three of our systems, when compared to the same period in 2010. The overall increase in average delivery volumes on our systems increased operating revenues by approximately $40.7 million for our Liquids segment. The total average daily deliveries from our liquid systems increased approximately four percent, to 2.123 million barrels per day, or Bpd, for the year ended December 31, 2011 from 2.032 million Bpd for the same period in 2010. The increase in average deliveries on our liquid systems was partly attributable to the operation of Lines 6A and 6B, which were shut down for part of 2010 due to the Line 6A and Line 6B crude oil releases.

Average daily delivery volumes on our North Dakota system increased 19 percent during the year ended December 31, 2011 to 197,000 Bpd from 165,000 Bpd during the same period in 2010. The additional volumes were the result of an increase in capacity on our North Dakota system resulting from the elimination of segregated sour service on the system. The positive increase also reflects volume from the recently completed PREP project.

Further contributing to the increase in operating revenue was the completion of our Alberta Clipper Pipeline in April 2010. The Alberta Clipper Pipeline contributed approximately $34.8 million of additional operating revenue for the year ended December 31, 2011, when compared with the same period in 2010.

Another contributing factor to the increase in operating revenue is a $17.2 million increase in unrealized, non-cash, mark-to-market net gains related to derivative financial instruments as compared with the same period in 2010. In March 2010, we began to use forward contracts to hedge a portion of the crude oil we expect to receive from our customers as a pipeline loss allowance as part of the transportation of their crude oil. We subsequently sell this crude oil at market rates. We executed derivative financial instruments which fix the sales price we will receive in the future for the sale of this crude oil. We elected not to designate these derivative financial instruments as cash flow hedges.

Our transportation tariffs allow our pipelines to deduct an allowance from our customers for the transportation of their crude oil. We recognize revenue for this allowance at the prevailing market price for crude oil. The average prices of crude oil during the year ended December 31, 2011 were higher than the average prices for the same period of 2010. For example, the average allowance oil prices for North Dakota increased approximately 30 percent for the year ended December 31, 2011, as compared with the same period in 2010. Coupled with the increased liquids volumes, we have experienced an approximate $15.5 million increase in allowance oil revenues.

For the year ended December 31, 2011, we settled a dispute with a shipper on our Lakehead crude oil pipeline system, which we recognized in June 2011, for oil measurement adjustments we had previously experienced in prior years. We recorded $52.2 million to “Oil measurement adjustments”, which is a reduction to operating expenses, for the year ended December 31, 2011.

The “Operating and administrative” expenses of our Liquids business increased $43.7 million from the year ended December 31, 2011, when compared with the same period in 2010 primarily due to the following:

Power costs increased $3.7 million for the year ended December 31, 2011, compared with the same period in 2010. The increase in power costs is primarily associated with the higher volumes of crude oil transported on all three of our liquids systems coupled with utility rate increases for power used by our Lakehead system.

The increase in depreciation expense of $18.3 million is directly attributable to the additional assets we have placed in service since the same period in 2010.

In September 2010, our West Tulsa crude oil pipeline was abandoned due to a significant decrease in throughput on the pipeline and, as a result, we recognized a $10.3 million impairment charge during the third quarter of 2010 to reduce the carrying amount of the asset to zero, as compared to no such impairments in the same period in 2011.

As of December 31, 2011, we have revised our total estimate for this crude oil release to $765.0 million, an increase of $215.0 million from December 31, 2010. The changes in estimate are primarily based on a review of costs and commitments incurred and additional information concerning the reassessment of the overall monitoring area, related cleanup, including submerged oil recovery operations, and remediation activities including the estimated costs related to the additional scope of work set forth in our response to the EPA directive we submitted to the EPA on October 20, 2011. During the fourth quarter of 2011, we submitted a revised work plan which was approved by the EPA on December 19, 2011. To date, we have made payments totaling $570.2 million for costs associated with the Line 6B crude oil release, $276.6 million of which relates to the year ended December 31, 2011.

For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at December 31, 2011. Our estimates do not include amounts we have capitalized or any fines, penalties or claims associated with the release that may later become evident and is before insurance recoveries. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above including modified or revised requirements from regulatory agencies in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

We are continuing to monitor the areas affected by the crude oil release from Line 6A of our Lakehead system for any additional requirements. We have substantially completed the cleanup, remediation and restoration of the areas affected by the release.

In connection with this crude oil release, we have not revised our June 30, 2011 estimate of aggregate costs of approximately $48.0 million, before insurance recoveries and excluding fines and penalties. We continue to monitor this estimate based upon actual invoices received and paid for the personnel, equipment and services provided by our vendors and currently available facts specific to these circumstances, existing technology and presently enacted laws and regulations to determine if our estimate should be updated. To date, we have made payments totaling $45.4 million for costs associated with the Line 6A crude oil release, $11.0 million of which relates to the year ended December 31, 2011.

The claims for the crude oil releases from Lines 6A and 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650 million for pollution liability. Based on our increased estimate of costs in 2011 associated with these crude oil releases, Enbridge Inc., or Enbridge, and its affiliates, including us, will exceed the limits of its coverage under this insurance policy. We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

During the second quarter of 2011, Enbridge renewed its comprehensive insurance program and the current coverage year has an aggregate limit of $575.0 million for pollution liability for the period May 1, 2011 through April 30, 2012.

For the year ended December 31, 2011 we recognized a receivable of $50.0 million for insurance recoveries as reductions to “Environmental costs, net of recoveries” for the year ended December 31, 2011. We expect to record a receivable for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable.

The decrease of $713.7 million in environmental expenses, net of recoveries for the year period ended December 31, 2011 when compared to the same period in 2010, is primarily due to incurring $595.0 million of costs for the Line 6A and Line 6B incidents for the year of 2010 compared to $218.0 million of cost for these incidents offset by our recognized insurance recoveries of $335.0 million for the year ended December 31, 2011.

Operating revenue of our Liquids segment increased for the year ended December 31, 2010 when compared to the same period in 2009 primarily due to the increased average rates for transportation on all of our major systems, most notably those associated with our Alberta Clipper Pipeline. Increases in average transportation rates on all three Liquids systems contributed approximately $186.3 million of additional operating revenue for the year ended December 31, 2010 when compared to the same period in 2009. The changes to our transportation rates included the following:

The operating revenue of our Liquids segment was also improved due to an increase in average delivery volumes on our North Dakota system that contributed an approximate $30.1 million of additional operating revenue for the year ended December 31, 2010 when compared to the same period in 2009. The average trunkline delivery volumes of our North Dakota system increased nearly 53 percent, to 159,000 Bpd for the year ended December 31, 2010 from 104,000 Bpd during the same period in 2009, while gathering volumes during these periods remained constant at 6,000 Bpd. The increase in average trunkline delivery volumes is attributable to our completion in late 2009 of North Dakota Phase VI, which increased the system’s trunkline capacity to approximately 161,000 Bpd from the 110,000 Bpd that was previously available.

Our transportation tariffs allow our pipelines to deduct an allowance from our customers for the transportation of their crude oil. We recognize revenue for this allowance at the prevailing market price for crude oil. The average prices of crude oil during the year ended December 31, 2010 were higher than the average prices for the same period of 2009. For example, the average price of West Texas Intermediate crude oil has increased approximately 28 percent for the year ended December 31, 2010, as compared with the same period in 2009. As a result of the increase in crude oil prices, we have experienced an approximate $14.7 million increase in allowance oil revenues.

Offsetting the improved operating revenues for our Liquids segment for the year ended December 31, 2010 is approximately $16 million of lost operating revenue associated with the temporary shutdowns of Lines 6A and 6B of our Lakehead system resulting from the crude oil releases from these pipelines. Despite the temporary shutdowns of Lines 6A and 6B, the average delivery volumes on our Lakehead system increased to 1.655 million Bpd for the year ended December 31, 2010 from 1.650 million Bpd during the same period in 2009. Prior to the occurrence of the releases, Lines 6A and 6B were operating at approximately 450,000 Bpd and 190,000 Bpd, respectively. Lines 6A and 6B were out of service for eight and 63 days, respectively, before they were returned to service. The lower volumes and related revenue associated with the releases on Lines 6A and 6B were partially offset by greater use of other pipelines on the Lakehead system to facilitate the transportation and delivery of crude oil from the oil sands.

Further offsetting the increases in operating revenue was $22.5 million of revenue we recognized in the year ended December 31, 2009 resulting from an expired joint tolling arrangement with Mustang Pipe Line, LLC, or Mustang, that we did not recognize for the same period in 2010.

Operating and administrative expenses for the Liquids segment increased $18.4 million from the year ended December 31, 2010 when compared to the same period in 2009 due to increases in property taxes associated with assets we placed in service coupled with modest increases on existing assets. Affiliates of our General Partner charge us the costs associated with employees and related benefits for personnel who are assigned to us or otherwise provide us with managerial and administrative services. We experienced an increase in workforce related costs as a result of the growth and expansion of our Liquids system operations. The above increases to operating and administrative expenses were partially offset by lower rent costs associated with the termination of our lease of Line 13 from an affiliate of our General Partner.

Power costs increased $13.0 million for the year ended December 31, 2010, compared with the same period in 2009. The increase in power costs is primarily associated with the higher volumes of crude oil transported on our North Dakota system coupled with utility rate increases for power used by our Lakehead system. Partially, offsetting the increases in power costs was a decline in usage by our Lakehead system during the periods Lines 6A and 6B were not in service.

The increase in depreciation expense of $45.5 million is directly attributable to the additional assets we placed in service during 2010, the most significant of which are North Dakota Phase VI and the Alberta Clipper Pipeline that we placed in service during the first and second quarters of 2010, respectively.

In September 2010, we removed from service the West Tulsa crude oil pipeline on our Mid-Continent system due to a significant decrease in throughput on the pipeline. As a result, we recognized a $10.3 million impairment charge during year ended December 31, 2010 to reduce the carrying amount of the asset to zero.

We experienced two releases of crude oil from our Lakehead system during the year ended December 31, 2010 that significantly affected the operating results of our Liquids business. The first release occurred on July 26, 2010, near Marshall, Michigan on Line 6B of our Lakehead system, and the second occurred on September 9, 2010 in an industrial area of Romeoville, Illinois on Line 6A of our Lakehead system. During 2010, we recognized approximately $595 million of actual and estimated costs in our Liquids business for the emergency response, environmental remediation and cleanup activities associated with the crude oil releases from Lines 6A and 6B, and potential claims by third parties. Our estimates represent gross costs before insurance recoveries and do not include fines and penalties, or the previously disclosed lost revenue of approximately $16 million.

Our Lakehead system is well positioned as the primary transporter of western Canadian crude oil and continues to benefit from the growing production of crude oil from the Alberta Oil Sands. Historically, western Canada has been a key source of oil supply serving the United States energy needs. Canada’s oil sands, one of the largest oil reserves in the world, are an increasingly prominent source of supply. Over the last several years, as conventional crude oil production has declined, development of the Alberta Oil Sands has more than offset this reduction. The NEB estimates that total WCSB production averaged approximately 2.76 million Bpd in 2011 and 2.54 million Bpd in 2010. Volumes of WCSB crude oil production are comparable with production volumes from Kuwait and Venezuela, key members of OPEC. The CAPP in June 2011 estimated future production from the Alberta Oil Sands to continue to grow steadily during the next 14 years, with an additional 2.7 million Bpd of incremental supply available by 2025, based on a subset of currently approved applications and announced expansions. We and Enbridge are actively working with our customers to develop transportation options that will allow Canadian crude oil greater access to markets in the United States.

Based on forecasted growth in western Canadian crude oil production and completion of upgrader expansions and increased bitumen production, as well as a 435,000 Bpd competitor pipeline that came on-line in 2010 and was expanded to 590,000 Bpd in 2011, our Lakehead system deliveries are expected to average approximately 1.7 million Bpd in 2012. The ability to increase deliveries and to expand the Lakehead system in the future will ultimately depend upon a number of factors including crude oil prices, related development activities by crude oil producers in the region and competing pipelines.

As such, commercial support as has been announced to construct Keystone XL, a 36-inch oil pipeline extension to the pipeline described above that will begin at Hardisty and extend down to Cushing and then to Nederland, Texas. The construction of the extension will add an additional 500,000 Bpd of capacity when completed. However, in early 2012 the United States government rejected the necessary permits for the project as it is currently proposed, thereby making the future of this project uncertain. Proponents for the project have stated their intent to reapply for the necessary permits in the future.

Additionally, another competitor announced in early 2012, sufficient commercial support for the expansion of the existing crude oil pipeline transportation services between Alberta and British Columbia. The expansion is expected to be comprised of pipeline facilities that may complete the looping of the pipeline in Alberta and British Columbia, pumping stations, tanks in Edmonton and Burnaby and expansion of the Westridge Marine Terminal, with a planned in service date in early 2017. The pipeline has a current capacity of 300,000 Bpd with expansion alternatives up to 600,000 Bpd. A final decision on this expansion is expected by the end of March 2012.

North Dakota and Montana in the United States and the province of Saskatchewan in Canada have experienced tremendous growth in the development of crude oil and natural gas reserves from the Bakken formation. The latest data released in December 2010 by the EIA shows that proved reserves of crude oil in North Dakota have increased to 1.0 billion barrels at December 31, 2009, an 83 percent increase from December 31, 2008. Further, the Three Forks formations, located underneath the Bakken, is thought to be the next natural step in the development of this region. We continue to solidify our position in the Bakken formation, with the completion of PREP in 2011, and the announcement of several expansion projects that should increase our available capacity within this region.

A key strength of the Partnership is our relationship with Enbridge. Enbridge has announced two major United States Gulf Coast market access pipeline projects, which when completed will pull more volume through the Partnership’s pipeline, and may lead to further expansions on our Alberta Clipper and Southern Access mainline pipelines. Enbridge’s Flanagan South Pipeline project will transport more volumes into Cushing, Oklahoma and twin their existing Spearhead pipeline, which starts at the hub in Flanagan, Illinois and delivers volumes into the Cushing hub. The Partnership’s Southern Access pipeline feeds the Spearhead system at Flanagan. Subject to regulatory and other approvals, the pipeline is expected to be in service by the middle of 2014. In December 2011, Enbridge completed the acquisition of a 50 percent interest in the Seaway Crude Pipeline System, or Seaway, from ConocoPhillips. Seaway is a 670 mile pipeline that includes a 500 mile, 30 inch pipeline from Freeport, Texas to Cushing, Oklahoma long-haul system, as well as a Texas City Terminal and Distribution System which serves refineries in Houston and Texas City areas. The remaining 50 percent interest in Seaway is owned by Enterprise Products Partners L.P., or Enterprise Products. Enbridge and Enterprise Products have announced plans to reverse the direction of the 500 mile Seaway pipeline to enable it to transport oil from Cushing, Oklahoma to the United States Gulf Coast. The initial 150,000 bpd of capacity on the reversed system is expected to be available by the second quarter of 2012. In addition, a proposed 85 mile pipeline is expected to be built from Enterprise Product’s ECHO crude oil terminal southeast of Houston to the Port Arthur/Beaumont, Texas refining center and could offer incremental capacity in excess of 400,000 bpd and is expected to be available in early 2014.

Enbridge Pipelines Inc., or EPI, filed a settlement agreement in May 2011 that is referred to as the Competitive Toll Settlement, or CTS, which was effective on July 1, 2011. On June 24, 2011, the National Energy Board, or NEB, announced its approval of the CTS. The CTS includes a provision for a joint tariff for volumes originating in western Canada that are transported on our Lakehead system. We have entered into an International Joint Tariff Agreement, or IJTA, with EPI that ensures the joint tariff revenues are allocated based on the existing Lakehead rate structures. United States tolls for service on our portion of the Lakehead system will not be affected by the CTS and will continue to be established by our existing toll agreements. We do not expect the terms of the CTS or the IJTA to affect our operating results, cash flows or financial position. The CTS provides a solid platform for the liquids pipeline business to develop new market access points on the mainline by providing shippers with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the EPI and Lakehead systems.

In October 2011, we and Enbridge announced two projects that will provide increased access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States. One of the projects involves the expansion of our Line 5 light crude line between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd, at a total cost of approximately $100 million of which we are obligated for $95 million while Enbridge is obligated for the remaining $5 million. Complementing the Line 5

expansion, Enbridge plans on reversing a portion of its Line 9 in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario. Subject to regulatory approvals, the Line 5 expansion is targeted to be in service during the first quarter of 2013 and the Line 9 reversal is targeted to be in service in late 2013. The project will enable growing light crude production from the Bakken shale and from Alberta to meet refinery needs in Michigan, Ohio and Ontario. The project provides another much needed transportation outlet for light crude, mitigating the current discounting of supplies in this basin while also providing more favorable supply costs to refiners currently dependent on crudes priced off of the Atlantic basin.

In December 2011, we announced that we will be proceeding with the Berthold Rail Project, a $145 million investment that will provide an interim solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold, North Dakota Terminal by 80,000 barrels per day and includes the construction of a three unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing facilities. Conditional approval was received in early December 2011 subject to securing remaining shipper commitments. A regulatory filing is in progress and detailed design is proceeding to enable construction to commence in April 2012 with a scheduled in-service date by early-2013.

In August 2010, we announced the Bakken Project, a joint crude oil pipeline expansion project with an affiliate of Enbridge in the Bakken and Three Forks formations located in the states of Montana and North Dakota and the Canadian provinces of Saskatchewan and Manitoba. The Bakken Project will follow our existing rights-of-way in the United States and those of Enbridge Income Fund Holdings in Canada to terminate and deliver to the Enbridge Mainline system’s terminal at Cromer, Manitoba, Canada. The United States portion of the Bakken Project will expand the United States portion of Line 26 by constructing two new pumping stations in Kenaston and Lignite, North Dakota, and replacing an 11-mile segment of the existing 12-inch diameter pipeline that runs from these two locations. The project also calls for an expansion at our existing terminal and station in Berthold, North Dakota. When completed, the Bakken Project will increase the takeaway capacity from this region by 145,000 Bpd, with further expansion available to increase the takeaway capacity to 325,000 Bpd. The United States portion of the Bakken Project will have an estimated cost of approximately $340 million. We completed a successful binding open season in February 2011 with commitments received for an aggregate of 100,000 Bpd of capacity of the 145,000 Bpd expansion. We commenced construction in July of 2011 with an expected in-service date in the first quarter of 2013.

In October 2011, we announced the Bakken Access Program, a series of projects totaling approximately $100 million, which represents an upstream expansion that will further complement our Bakken expansion, as discussed above. This expansion program will substantially enhance our gathering capabilities on the North Dakota system by 100,000 Bpd. This program is expected to be in service by early 2013, and it involves increasing pipeline capacities, construction of additional storage tanks and the addition of truck access facilities at multiple locations in western North Dakota.

In April 2011, the board of directors of Enbridge Management approved plans to begin construction on four new tanks at our Cushing terminal with an approximate shell capacity of 1.0 million barrels. The new tanks will have an estimated cost of $33 million and are targeted to be in service by December 2012.

During late 2010, we began construction on nine new storage tanks at our Cushing terminal with an approximate shell capacity of 3.2 million barrels. The additional storage tanks will have an estimated cost of $78 million. As of December 31, 2011, five of the tanks, representing approximately 2 million barrels of additional shell capacity, were completed and placed in service. The remaining four tanks are expected to be in service by early 2012.

On May 12, 2011, we announced plans to replace 75-miles of non-contiguous sections of Line 6B of our Lakehead system at an estimated cost of $286.0 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. Subject to regulatory approvals, the new segments of pipeline will be constructed mostly in 2012 and are targeted to be placed in service by the first quarter of 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through our Facilities Surcharge Mechanism, or FSM, that is part of the system-wide rates of the Lakehead system. We have subsequently revised the scope of this project to increase the cost by approximately $30.0 million, which will bring the total capital for this replacement program to an estimated cost of $316.0 million. The $30.0 million of additional costs do not currently have recovery under the FSM.

We completed on schedule all the work required by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, that we agreed to perform as part of our restart of Line 6B. Additionally, a new line was installed beneath the St. Clair River in March 2011 and was tied into the existing pipeline during June 2011, and we announced plans for a pipeline replacement plan as discussed above. Additional integrity expenditures, which could be significant, may be required after this initial remediation program. The total cost of these integrity measures is separate from the environmental liabilities discussed above. The pipeline integrity and replacement costs will be capitalized or expensed in accordance with our capitalization policies as these costs are incurred, the majority of which are expected to be capital in nature. We expect to incur ongoing operating costs for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems.

In February 2011, we filed a supplement to our FSM, which became effective on April 1, 2011, for recovery of $175.0 million of capital costs and $5.0 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, which include an equity return component, interest expense and an allowance for income taxes will be recovered over a 30-year period, while operating costs will be recovered through our annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

Our Natural Gas segment consists of natural gas gathering and transmission pipelines, as well as treating and processing plants and related facilities. Collectively, these systems include:

The following tables set forth the operating results of our Natural Gas segment assets and approximate average daily volumes of our major systems in millions of British Thermal Units per day, or MMBtu/d, for the periods presented. We have revised the amounts for 2009 to exclude the results of our discontinued operations, which are discussed below in the section labeled Other Matters.

We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectability is reasonably assured. We derive revenue in our Natural Gas segment from the following types of arrangements:

Under a fee-based contract, we receive a set fee for gathering, treating, processing and transporting raw natural gas and providing other similar services. These revenues correspond with the volumes and types of services we provide and do not depend directly on commodity prices. Revenues of our Natural Gas segment that are derived from transmission services consist of reservation fees charged for transmission of natural gas on some of our intrastate pipeline systems. Customers paying these fees typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transmission volumes. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transmission services.

We also use other types of arrangements to derive revenues for our Natural Gas segment. These arrangements expose us to commodity price risk, which we substantially mitigate with offsetting physical purchases and sales of natural gas, NGLs and condensate, and by the use of derivative financial instruments to hedge open positions in these commodities. We hedge a significant amount of our exposure to commodity price risk to support the stability of our cash flows. We provide additional information in Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk and Note 16. Derivative Financial Instruments and Hedging Activities of our consolidated financial statements in Item 8. Financial Statements and Supplementary Data of this report about the derivative activities we use to mitigate our exposure to commodity price risk.

The other types of arrangements we use to derive revenues for our Natural Gas business are categorized as follows:

Under the terms of each of these contract structures, we retain a portion of the natural gas and NGLs as our fee in exchange for providing these producers with our services. We are exposed to fluctuations in commodity prices in the near term on approximately 30 to 40 percent of the natural gas, NGLs and condensate we expect to receive as compensation for our services. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the processed natural gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate during that time. Many of the derivative financial instruments we use do not qualify for hedge accounting. As a result we record the changes in fair value of the derivative instruments that do not qualify for hedge accounting in our operating results. This accounting treatment produces unrealized non-cash gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

The primary factors affecting the operating income of our Natural Gas business for the year ended December 31, 2011 as compared with the same period of 2010 are as follows:

Revenue for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our customers. We are exposed to fluctuations in commodity prices in the near term on approximately 30 to 40 percent of the natural gas, NGLs and condensate we expect to receive as compensation for our services. As a result of this unhedged commodity price exposure, our gross margin, representing revenue less cost of natural gas, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. NGL prices were higher for the year ended December 31, 2011 compared to prices in the same period in 2010, which positively impacted our operating income.

Our volumes and revenues are the result of wellhead supply contracts and drilling activity in the areas served by our Natural Gas business, primarily the Bossier Trend, Barnett Shale, Granite Wash and the Haynesville Shale. During the year ended December 31, 2011, natural gas volumes on our systems increased approximately 17 percent, in relation to the same period of 2010, primarily due to production increases in the Granite Wash and new assets being placed in service to capture the growing production from the Haynesville shale play. Volumes on our Anadarko system increased 42 percent for the year ended December 31, 2011 compared with the same period in 2010, of which the majority of the increase was associated with the Elk City system we acquired in September 2010.

Although volumes were higher on the majority of our systems for the year ended December 31, 2011 compared with the same period of 2010, in February 2011 uncharacteristically cold weather and freezing precipitation moved through Oklahoma and north Texas with temperatures dropping below freezing for extended periods. These conditions resulted in mechanical issues with our producers’ equipment and impacted their ability to flow natural gas. Producers shut in significant volumes during this period, which reduced the average daily volumes on our systems by approximately 56,000 MMBtu/d, in the first quarter of 2011, or approximately 14,000 MMBtu/d for the year ended December 31, 2011. Additionally, mechanical problems on two of our plants required that they be taken out of service for extended periods during the first quarter of 2011 to correct these conditions. The adverse weather conditions and plant downtime had an approximate $13 million negative impact to the gross margin of our Natural Gas business for year ended December 31, 2011.

A variable element of the operating results of our Natural Gas segment is derived from processing natural gas on our systems. Under percentage of liquids, or POL, contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the cost of natural gas derived from keep-whole earnings for the year ended December 31, 2011 was $41.5 million, representing a decrease of $24.4 million from the $65.9 million we produced for the same period in 2010.

The reduction in keep-whole earnings is a result of the increasing production of liquids rich natural gas on our Anadarko system, excluding the Elk City acquisition, where a significant number of our contracts are POL type arrangements. This earnings decrease is largely attributable to paying natural gas producers for liquids we are unable to recover due to gas volume increasing faster than our available capacity. The rapid increase in supply exceeded our processing capacity as evidenced by the 18 percent increase in average daily volumes from 645,000 MMBtu/d to 762,000 MMBtu/d on the system for the year ended December 31, 2011 compared to the same period last year. We are constructing facilities to increase the available processing capacity on both our Anadarko and Elk City systems. The most significant of these facilities is the Allison plant, which we placed into service in November 2011. We are awaiting the completion of additional third party NGL takeaway capacity to the Allison Plant which will allow us to fully utilize its capacity. This additional third party takeaway capacity is expected to be in place during the first quarter of 2012.

Changes in the average forward prices of natural gas, NGLs and condensate from December 31, 2010 to December 31, 2011 produced unrealized, non-cash, mark-to-market net gains of $15.8 million from the non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our Natural Gas business. The net gains resulted primarily from the fractionation hedge gains on the settlement of our 2011 hedge losses as well as gains on the market movement on new fractionation hedges, offset by losses on the settlement of 2011 gas hedges.

Comparatively, changes in the average forward prices of natural gas, NGLs and condensate from December 31, 2009 to December 31, 2010, produced unrealized, non-cash, mark-to-market net gains of $4.4 million from the non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our Natural Gas business. The average forward and daily prices for natural gas at December 31, 2010 were lower relative to natural gas prices at December 31, 2009, while the average forward and daily prices of NGLs were higher though the end of 2012 and lower thereafter relative to NGL prices at December 31, 2009. As a result of the lower natural gas forward prices, we experienced unrealized mark-to-market net gains on derivatives we use to fix the price of natural gas we sell. Partially offsetting the gains were unrealized mark-to-market net losses on the derivatives that we use to hedge our fractionation margins, which represent the relative difference between the price we receive from the sale of NGLs and the corresponding cost of natural gas we purchase for processing. As a result of lower natural gas forward prices and the higher NGL forward prices, fractionation margins widened producing these derivative losses.

The following table depicts the effect that unrealized, non-cash, mark-to-market net gains and losses had on the operating results of our Natural Gas segment for the years ended December 31, 2011 and 2010:

Operating and administrative costs of our Natural Gas segment were $89.3 million higher for the year ended December 31, 2011 compared to the same period in 2010, primarily due to the expansion of our systems, including the Elk City system we acquired in September 2010 and a common carrier trucking company we acquired in October 2010. Increased maintenance costs and workforce related costs for the year ended December 31, 2011 when compared to the same period in 2010 also contributed to the increased operating and administrative costs.

In September of 2011, management began investigating possible conflict of interest transactions associated with our wholly-owned trucking and NGL marketing subsidiary. The investigations have been concluded, pursuant to which management learned that local management and certain staff at the subsidiary engaged in intentional misconduct and collusion that resulted in accounting misstatements associated with the recognition of product purchases and sales. The accounting misstatements occurred over a period from 2005 through 2011 which impacted “Accrued purchases”, “Cost of natural gas” (including natural gas liquids), “Inventory”, “Accrued receivables” and “Operating revenue”. Our net cash provided by operating activities was not affected by the accounting misstatements during these periods, and these misstatements are not expected to have an effect on our future earnings, cash flows or distributions to our unitholders.

For the year ended December 31, 2010, the cumulative aggregate amount of the accounting misstatements was approximately $33 million. During 2011, local management of the trucking and NGL marketing subsidiary recorded entries totaling approximately $15 million as increases to cost of goods sold included in “Cost of natural gas” and decreases to “Operating revenue” that reduced the cumulative aggregate amount to $18 million at December 31, 2011. Following further investigation and determination that the previously unrecorded amounts were not material to the current or any prior period financial statements, we recorded the cumulative aggregate amount of $18 million at December 31, 2011 as a reduction to the “Operating income” of our Natural Gas segment to correct these accounting misstatements. As a result, the “Operating income” of our Natural Gas segment for the year ended December 31, 2011 is $33 million less than what we would have reported had the accounting misstatements been recognized in the year ended December 31, 2010. The $33 million is comprised of the $15 million of adjustments recorded by local management of the trucking and NGL marketing subsidiary during 2011 and the $18 million correction we recorded at December 31, 2011.

The primary factors affecting the operating income of our Natural Gas business for the year ended December 31, 2010 as compared with the same period of 2009 are as follows:

Revenue for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our customers. We are exposed to fluctuations in commodity prices in the near term on approximately 15 to 30 percent of the natural gas, NGLs and condensate we expect to receive as compensation for our services. As a result of this unhedged commodity price exposure, our margins generally increase when the prices of these commodities are rising and generally decrease when the prices are declining.

Our volumes and revenues are the result of wellhead supply contracts and drilling activity in the areas served by our Natural Gas business, primarily the Bossier Trend, Barnett shale, Granite Wash and most recently, the Haynesville shale. During the year ended December 31, 2010, overall natural gas volumes on our systems remained relatively flat in relation to the same period of 2009. However, at a system level our East Texas system had lower volumes as a result of reduced drilling activity in the Bossier Trend, James Lime and Travis Peak formations driven by the relatively low price of natural gas. These lower volumes were slightly offset by the increased drilling activity in the Haynesville shale, which are attributable to the higher yield of natural gas per well and lower costs associated with drilling natural gas wells in this area.

We experienced a significant increase in volumes on our Anadarko system for the year ended December 31, 2010 as compared with the same period of 2009, partially offsetting the lower volumes on our East Texas and North Texas systems. The higher volumes on our Anadarko system are primarily attributable to:

The Elk City system contributed average daily volumes of approximately 228,000 MMBtu/d during the first full three month period we operated the system, which ended December 31, 2010. The operating income of our Anadarko system was also favorably affected by our operation of the Elk City system, which allowed us to capture natural gas production that was previously bypassing our system and contributed to the overall increase in operating income of our Anadarko system. The combined Anadarko and Elk City systems generated approximately $50 million more operating income for the year ended December 31, 2010 as compared to the same period in 2009. We expect the Elk City system to be fully integrated with our Anadarko system by the end of 2011.

Active drilling rigs in the areas we serve have increased 17 percent during the year ended December 31, 2010 from levels that existed in the corresponding period in 2009. As a result of the increased drilling activity in the areas we serve, we expect our volumes to increase in future periods.

Although demand for natural gas has begun to stabilize, declining natural gas prices over the past year have caused some producers to reduce their output of natural gas, which has in turn resulted in lower volumes on our systems relative to historical highs, particularly on our East Texas and North Texas systems. We are positioned to capitalize on any future increases in natural gas production, in large part due to the expansions we have completed in recent years. We anticipate the recent discovery of the Haynesville shale in western Louisiana and eastern Texas could result in greater demand for our services. In February 2010, we announced an expansion project on our East Texas system to capitalize on the growth opportunities that exist in the Haynesville shale area, referred to as the South Haynesville Shale expansion project. For a discussion of our South Haynesville shale expansion project, see Future Prospects for Natural Gas below. In June 2010 we acquired natural gas pipeline assets for $16.9 million that are complementary to our existing assets and our planned expansion into the South Haynesville area. The acquisition is expected to increase capacity of our East Texas system by connecting a portion of our East Texas system to the expansions we have underway in the South Haynesville area.

A variable element of the operating results of our Natural Gas segment is derived from processing natural gas on our East Texas, North Texas and Anadarko systems. Under POL contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the cost of natural gas derived from keep-whole earnings for the year ended December 31, 2010 was $65.9 million, representing a decrease of $2.4 million from the $68.3 million we produced for the same period in 2009.

Changes in the average forward prices of natural gas, NGLs and condensate from December 31, 2009 to December 31, 2010 produced unrealized, non-cash, mark-to-market net gains of $4.4 million from the non-qualifying commodity derivatives we use to economically hedge a portion of the commodity price exposure in our Natural Gas business. The average forward and daily prices for natural gas at December 31, 2010 were lower relative to natural gas prices at December 31, 2009, while the average forward and daily prices of NGLs were higher though the end of 2012 and lower thereafter relative to NGL prices at December 31, 2009. As a result of the lower natural gas forward prices, we experienced unrealized mark-to-market net gains on derivatives we use to fix the price of natural gas we sell. Partially offsetting the gains were unrealized mark-to-market net losses on the derivatives that we use to hedge our fractionation margins, which represent the relative difference between the price we receive from the sale of NGLs and the corresponding cost of natural gas we purchase for processing. As a result of lower natural gas forward prices and the higher NGL forward prices, fractionation margins widened producing these derivative losses.

Comparatively, the average forward and daily prices for natural gas were lower at December 31, 2009 in relation to prices at December 31, 2008, producing gains in our portfolio of natural gas derivatives, while the average forward and daily prices for NGLs and condensate were higher at December 31, 2009 than at December 31, 2008, producing losses, which more than offset the gains associated with the natural gas derivatives.

Operating and administrative costs of our Natural Gas segment were $16.1 million higher for the year ended December 31, 2010 compared to the same period in 2009, primarily due to an increase in maintenance and other activities coupled with the operating costs associated with the additional assets we have in service.

Affiliates of our General Partner charge us the costs associated with employees and related benefits for personnel who are assigned to us or otherwise provide us with managerial and administrative services. We have experienced an increase in workforce related costs for the year ended December 31, 2010 when compared to the same period in 2009.

In early 2012, we identified accounting misstatements associated with the financial statement recognition of NGL product purchases and sales that occurred at our wholly-owned trucking and NGL marketing subsidiary over a period from at least 2005 through 2011. For the year ended December 31, 2010 the “Operating income”

for our Natural Gas business was overstated by approximately $5.3 million with respect to NGL sales and purchases of our trucking and NGL marketing business, as compared with “Operating income” for the year ended December 31, 2009, which was not misstated by NGL sales and purchases of our trucking and NGL marketing subsidiary.

We intend to expand our natural gas gathering and processing services through internal growth projects designed to provide exposure to incremental supplies of natural gas at the wellhead, increase opportunities to serve additional customers, including new wholesale customers, and allow expansion of our treating and processing businesses. Additionally, we will pursue acquisitions to expand our natural gas services in situations where we have natural advantages to create additional value.

In September 2011, we announced a joint venture among us, Enterprise Products Partners L.P., or Enterprise Products, and Anadarko Petroleum Corporation, or Anadarko, to design and construct a new NGL pipeline referred to as the Texas Express Pipeline, or TEP. TEP will be owned 45 percent by Enterprise Products, 35 percent by us and 20 percent by Anadarko. Our portion of the estimated cost is $385 million. The pipeline will originate at Skellytown, Texas and extend approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas. The pipeline will have an initial capacity of approximately 280,000 Bpd and will be readily expandable to approximately 400,000 Bpd. We announced open season results on March 6, 2012, in which 232,000 Bpd of this capacity has been subscribed.

In addition, the joint venture will include two new NGL gathering systems. The first will connect TEP to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and Western Oklahoma. The second NGL gathering system will connect the new pipeline to central Texas, Barnett Shale processing plants. Volumes from the Rockies, Permian Basin and Mid-Continent regions will be delivered to the TEP system utilizing Enterprise’s existing Mid-America Pipeline assets between the Conway hub and Enterprise’s Hobbs NGL fractionation facility in Gaines County, Texas. Enterprise will construct and serve as the operator of the pipeline, while we will build and operate the new gathering systems. The pipeline and portions of the gathering systems are expected to begin service in mid-2013, subject to regulatory approvals and finalization of commercial agreements.

TEP will serve as a link between growing supply sources of NGLs in the Anadarko region and the primary end use market on the United States Gulf Coast and will be providing guaranteed NGL access to the primary United States petrochemical market located in Mont Belvieu. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide a new source of strong and stable cash flow.

In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system at a cost of $230 million, which we refer to as our Ajax Plant. The Ajax Plant will have a planned capacity of 150 MMcf/d and is intended to meet the continued strength of horizontal drilling activity in this area. The Ajax Plant is anticipated to be in service in early 2013.

The Ajax plant, when operational, in addition to the Allison Plant, will increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d.

In February 2010, we announced plans to expand our East Texas system by constructing three lateral pipelines into the East Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage which will further expand our recently completed Shelby County Loop. The expansion into the Haynesville shale area is expected to increase the capacity of our East Texas system by 900 million cubic feet per day, or MMcf/d. We completed construction of a portion of the pipeline for the project during the second quarter of 2010 and the main trunkline to Carthage in December 2010 and we expect construction of the facilities will be completed in the first quarter of 2012. Future compression will be layered in, as needed, after the completion of the facilities.

In April 2011, we announced plans to invest an additional $175 million to expand our East Texas system. We have signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering, treating and transmission services in Shelby, San Augustine and Nacogdoches counties. The projects involve construction of gathering and related market outlet pipelines and related treating facilities in the Texas Haynesville shale. In light of weak natural gas prices and lower levels of producer activity, the Partnership is evaluating deferral of portions of its Haynesville natural gas expansion.

On September 16, 2010, we acquired 100 percent ownership of the entities that comprise the Elk City system for $686.1 million in cash, including amounts for working capital. The Elk City system extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle. The Elk City system consists of approximately 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 million cubic feet per day, or MMcf/d, and a combined current natural gas liquid production capability of 20,000 barrels per day. The acquisition of the Elk City system complements our existing Anadarko natural gas system by providing additional processing capacity and expansion capability. The results of operations of the Elk City system have been included in our consolidated financial statements within our Natural Gas segment from the September 16, 2010 acquisition date. The Elk City system acquisition did not significantly impact the operating results of our Natural Gas business for the year ended December 31, 2010.

The following table presents our allocation of the purchase price to the assets acquired and the liabilities assumed, based on their fair values:

In November 2009, we sold non-core natural gas pipeline assets located predominantly outside of Texas for cash totaling approximately $150.8 million, excluding any subsequent settlement for working capital as provided in the sale agreement. The natural gas pipeline assets we sold include primarily intrastate and interstate natural

gas transmission systems and related facilities, which serve onshore and offshore markets in the southeastern United States and along the Gulf Coast. The natural gas pipeline assets include over 1,400 miles of pipeline with diameters ranging from 2 to 30 inches. The areas in which the natural gas pipeline assets operate were not strategic to the ongoing central operations of our core Natural Gas segment assets.

We have presented the operating results through October 31, 2009 of the natural gas pipeline assets we sold and additional costs we incurred related to the divestiture of these assets through December 31, 2009, as “Loss from discontinued operations” in our consolidated statements of income. Also included in “Loss from discontinued operations” for the year ended December 31, 2009 is a charge for $66.1 million we recorded as an impairment to reduce the carrying value of the assets to our estimate of the fair value of these assets, partially offset by a $1.6 million reduction to this amount we realized upon completion of the sale.

The following table presents the operating results of the discontinued operations of our natural gas pipeline assets that we derived from historical financial information and have segregated from our continuing operations in our consolidated statements of income:

The following table sets forth the operating results of our Marketing segment assets for the periods presented. The amounts have been revised to exclude the operating results associated with the non-core natural gas assets we sold in November 2009, as previously addressed in our Natural Gas segment discussion:

Our Marketing business derives a majority of its operating income from selling natural gas received from producers on our Natural Gas segment pipeline assets to customers utilizing the natural gas. A majority of the natural gas we purchase is produced in Texas markets where we have expanded access to several interstate natural gas pipelines over the past several years, which we can use to transport natural gas to primary markets where it can be sold to major natural gas customers.

Our Marketing business is exposed to commodity price fluctuations because the natural gas purchased by our Marketing business is generally priced using an index that is different from the pricing index at which the gas is sold. This price exposure arises from the relative difference in natural gas prices between the contracted index at which the natural gas is purchased and the index under which it is sold, otherwise known as the “basis spread.” The spread can vary significantly due to local supply and demand factors. Wherever possible, this pricing exposure is economically hedged using derivative financial instruments. However, the structure of these economic hedges often precludes our use of hedge accounting under authoritative accounting guidance, which can create volatility in the operating results of our Marketing segment.

In addition to the market access provided by our company-owned intrastate natural gas pipelines, our Marketing business also contracts for firm transportation capacity on third-party interstate and intrastate pipelines to allow access to additional markets. To mitigate the demand charges associated with these transportation agreements, we look for market conditions that allow us to lock in the price differential between the pipeline receipt point and pipeline delivery point. This allows our Marketing business to lock in a fixed sales margin inclusive of pipeline demand charges. We accomplish this by transacting basis swaps between the index where the natural gas is purchased and the index where the natural gas is sold. By transacting a basis swap between those two indices, we can effectively lock in a margin on the combined natural gas purchase and the natural gas sale, mitigating our exposure to cash flow volatility that could arise in markets where transporting the natural gas becomes uneconomical. However, the structure of these transactions precludes our use of hedge accounting under authoritative accounting guidance, which can create volatility in the operating results of our Marketing segment.

In addition to natural gas transport capacity and the associated basis swaps, we contract for storage to assist with balancing natural gas supply and end use market sales. In order to mitigate the absolute price differential between the cost of injected natural gas and withdrawals of natural gas, as well as storage fees, the injection and withdrawal price differential is hedged by buying fixed price swaps for the forecasted injection periods and selling fixed price swaps for the forecasted withdrawal periods. When the injection and withdrawal spread increases or decreases in value as a result of market price movements, we can earn additional profit through the optimization of those hedges in both the forward and daily markets. Although all of these hedge strategies are sound economic hedging techniques, these types of financial transactions do not qualify for hedge accounting under authoritative accounting guidance. As such, the non-qualified hedges are accounted for on a mark-to-market basis, and the periodic change in their market value, although non-cash, will impact our operating results.

Natural gas purchased and sold by our Marketing segment is primarily priced at a published daily or monthly price index. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated margins result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At their request, we will enter into long-term, fixed-price purchase or sales contracts with our customers and generally will enter into offsetting hedged positions under the same or similar terms.

Our Marketing business pays third-party storage facilities and pipelines for the right to store and transport natural gas for various periods of time. These contracts may be denoted as firm storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with sales and purchase contracts, and to take advantage of price differential opportunities.

Included in the operating results of our Marketing segment for the year ended December 31, 2011 were unrealized, non-cash, mark-to-market net gains of $0.7 million associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with the $6.7 million of unrealized non-cash, mark-to-market net losses for the same period in 2010. For the year ended December 31, 2011, the non-cash, mark-to-market net gains primarily resulted from financial instruments that we

use to hedge our storage positions. The net gains associated with our storage derivative instruments resulted from the narrowing difference between the natural gas injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. Comparatively, for the year ended December 31, 2010, the non-cash, mark-to-market net loss primarily resulted from the realization of financial transactions entered into and recognized in prior years.

Offsetting our unrealized, non-cash, mark-to-market net gains for the current period and contributing to the operating loss of our Marketing business were relatively stable natural gas prices during the year ended December 31, 2011, which limited opportunities to benefit from significant price differentials between market centers.

Operating income for the year ended December 31, 2011 was also negatively affected by non-cash charges of $2.8 million we recorded to reduce the cost basis of our natural gas inventory to net realizable value compared to $1.0 million of similar charges in the comparable period of 2010. We expect that a majority of these charges in 2011 will be recovered when the physical natural gas inventory is sold.

Contributing to the lower operating income of our Marketing business were relatively stable natural gas prices during the year ended December 31, 2010, which limited opportunities to benefit from significant price differentials between market centers. Also, included in the operating results of our Marketing segment for the year ended December 31, 2010 were unrealized, non-cash, mark-to-market net losses of $6.7 million associated with derivative financial instruments and net-settled physical transactions that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with the $20.7 million of unrealized non-cash, mark-to-market net gains for the same period in 2009. For the year ended December 31, 2010, the non-cash, mark-to-market net loss primarily resulted from the realization of financial transactions entered into and recognized in prior years. Comparatively, during the year ended December 31, 2009, we had unrealized, mark-to-market net gains of $20.7 million that was the result of narrower transportation and storage differentials from the increases in the forward and daily market prices of natural gas from December 31, 2008.

Our interest cost for the years ended December 31, 2011 and 2010 is comprised of the following:

The increase in interest expense between the year ended December 31, 2011 and 2010 is primarily the result of a higher weighted average outstanding debt balance during the year ended December 31, 2011 as compared with the same period in 2010. The increased weighted average outstanding debt balance was primarily a result of the following:

We are exposed to interest rate risk associated with changes in interest rates on our variable rate debt. The interest rates on our variable rate debt are determined at the time of each borrowing or interest rate reset based upon a posted London Interbank Offered Rate, or LIBOR, for the period of borrowing or interest rate reset, plus applicable margin. In order to mitigate the negative effect that increasing interest rates can have on our cash flows, we have purchased interest rate swaps with a total notional value of $3.9 billion. The changes in fair value of the interest rate swaps that do not qualify for hedge accounting are recorded as corresponding increases or decreases in “Interest expense” on our consolidated statements of income. For the year ended December 31, 2011, we recorded $0.8 million of unrealized, non-cash, mark-to-market net losses associated with the changes in fair value of these derivatives that resulted from the decrease in interest rates from December 31, 2010 to December 31, 2011. For the year ended December 31, 2010, we recorded $1.0 million of unrealized, non-cash, mark-to-market net losses associated with the changes in fair value of these derivatives that resulted from the decrease in interest rates from December 31, 2009 to December 31, 2010.

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are typically borne by our unitholders through the allocation of taxable income.

The tax structures that exist in Michigan and Texas impose taxes that are based upon many, but not all, items included in net income. Our income tax expense is $5.5 million and $7.9 million for the years ended December 31, 2011 and 2010, respectively, which we computed by applying a 0.5% Texas state income tax rate to modified gross margin, and a 0.2% Michigan state income tax rate to net income and modified gross receipts. Due to a change in Michigan tax legislation, we will no longer be required to pay Michigan income taxes beginning in 2012 as discussed in Note 17. Income Taxes.

Our interest cost for the years ended December 31, 2010 and 2009 is comprised of the following:

The increase in interest expense between the years ended 2010 and 2009, is primarily the result of a higher weighted average outstanding debt balance during the year ended December 31, 2010 as compared with the same period in 2009, partially offset by a lower weighted average interest rate for the 2010 period in relation to 2009 period. The increased weighted average outstanding debt balance was primarily a result of the following:

In order to mitigate the negative effect that increasing interest rates can have on our cash flows, we purchased interest rate caps, which establish a ceiling averaging approximately 1.12% on the interest rates we pay on up to $400 million of our variable rate indebtedness through January 2011. The interest rate caps do not qualify for hedge accounting, and as a result, the fair values of these derivative financial instruments are recorded as assets or liabilities on our consolidated statements of financial position with the changes in fair value recorded as corresponding increases or decreases in “Interest expense” on our consolidated statements of income. For the year ended December 31, 2010, we recorded $1.0 million of unrealized, non-cash, mark-to-market net losses associated with the changes in fair value of these derivatives that resulted from the decrease in interest rates from December 31, 2009 to December 31, 2010. For the year ended December 31, 2009, we recorded $0.5 million of unrealized, non-cash, mark-to-market net gains associated with the changes in fair value of these derivatives that resulted from the changes in interest rates from the May 2009 date these derivative financial instruments were purchased to December 31, 2009.

Our income tax expense is $7.9 million and $8.5 million for the years ended December 31, 2010 and 2009, respectively, which we computed by applying a 0.5% Texas state income tax rate to modified gross margin for the years ended 2010 and 2009, and a 0.2% and 0.1% Michigan state income tax rate to net income and modified gross receipts for the years ended December 31, 2010 and 2009, respectively.

In July 2009, we entered into a joint funding arrangement to finance construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge including our General Partner. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010. In connection with the joint funding arrangement, we allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $53.2 million and $60.6 million to our General Partner for its 66.67 percent share of the earnings of the Alberta Clipper Pipeline for the years ended December 31, 2011 and 2010, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

In connection with our application of the regulatory accounting provisions to our Alberta Clipper Pipeline, we recorded AEDC in “Other income (expense)” on our consolidated statement of income. For the year ended December 31, 2010, we recorded $15.3 million and $4.8 million, of AEDC and AIDC, or allowance for interest during construction, respectively, on our consolidated statements of income related to the Alberta Clipper Pipeline. There were no additional costs recorded in 2011 as all assets were placed into service as of December 31, 2010.

We received proceeds of $11.6 million for settlement of claims we made for payment from unrelated parties in connection with operational matters that occurred in the normal course of business. We recorded $5.6 million as a reduction to “Operating and administrative” expenses of our Liquids segment and $6.0 million as “Other income” in our consolidated statements of income for the year ended December 31, 2011 for the amounts we received in April 2011.

Our primary source of short-term liquidity is provided by our commercial paper program, which is supported by our $2 billion credit agreement with a syndicate of lenders, of which Bank of America is the administrative agent, which we refer to as our New Credit Facility. We access our commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our New Credit Facility.

As set forth in the following table, we had in excess of $1.9 billion of liquidity available to us at December 31, 2011 to meet our ongoing operational, investment and financing needs, as well as the funding requirements associated with the environmental costs resulting from the crude oil releases on Lines 6A and 6B.

Our primary operating cash requirements consist of normal operating expenses, core maintenance expenditures, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings on our New Credit Facility. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our New Credit Facility.

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses through organic growth and targeted acquisitions. We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing debt, from operating cash flows and from issuances of commercial paper and borrowings on our New Credit Facility. Likewise, we anticipate initially retiring our maturing debt with similar borrowings on our New Credit Facility. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all. In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, the General Partner has provided supplementary funding to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar supplementary funding from the General Partner.

Execution of our growth strategy and completion of our planned construction projects require access to the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions may require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. If market conditions

change and capital markets again become constrained, our ability and willingness to complete future debt and equity offerings may be limited. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

In June 2010, we entered into an Equity Distribution Agreement, or EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $150.0 million. The EDA allowed us to issue and sell our Class A common units at prices we deemed appropriate for our Class A common units. Under the EDA, we sold 2,118,025 Class A common units, representing 4,236,050 units after giving effect to a two-for-one split of our Class A common units that became effective on April 21, 2011, for aggregate gross proceeds of $124.8 million, of which $64.5 million are gross proceeds received in 2011. No further sales were made under that agreement. On May 27, 2011, we de-registered the remaining aggregate $25.2 million of Class A common units that were registered for sale under the EDA and remained unsold as of that date.

On May 27, 2011, the Partnership entered into an Amended and Restated Equity Distribution Agreement, or Amended EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $500.0 million from the execution date of the agreement through May 20, 2014. The units issued under the Amended EDA are in addition to the units offered and sold under the EDA. The issuance and sale of our Class A common units, pursuant to the Amended EDA, may be conducted on any day that is a trading day for the New York Stock Exchange, or NYSE.

The following table presents the net proceeds from our Class A common unit issuances, pursuant to the initial EDA and the Amended EDA, during the years ended December 31, 2011 and 2010:

The following table presents the net proceeds from our Class A common unit issuances for the current year other than pursuant to the EDA and the Amended EDA described above.

In November 2011, Enbridge Management completed a private offering of 860,684 listed shares, representing limited liability company interests in Enbridge Management with limited voting rights, at a price of $29.86 per listed share. Enbridge Management received net proceeds of $25.5 million which were subsequently invested in an equal number of our i-units. We intend to use the proceeds to finance a portion of our capital expansion program relating to the expansion of our core liquids and natural gas systems and for general corporate purposes.

Our two primary sources of liquidity are provided by our commercial paper program and our New Credit Facility. We have a $1.5 billion commercial paper program, which we access primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our New Credit Facility.

In September 2011, we entered into the New Credit Facility. The New Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $2 billion, a letter of credit subfacility and a swing line subfacility with a maturity date of September 26, 2016.

The New Credit Facility replaces the previously existing credit facilities of $1,167.5 million and $600 million with Bank of America and Royal Bank of Canada, respectively.

The amounts we may borrow under the terms of our New Credit Facility are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our New Credit Facility amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at December 31, 2011, we could borrow $1,551.2 million under the terms of our New Credit Facility, determined as follows:

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our New Credit Facility may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the New Credit Facility and do not require any cash repayments or prepayments. For the years ended December 31, 2010 and 2009, we renewed LIBOR rate borrowings of $1,284.0 million and $3,092.1 million, respectively, on a non-cash basis.

Effective September 30, 2011, our New Credit Facility was amended to further modify the definition of Consolidated Earnings Before Income Taxes Depreciation and Amortization, or Consolidated EBITDA, as set forth in the terms of our New Credit Facility, to increase from $550 million to $650 million, the aggregate amount of the costs associated with the crude oil releases on Lines 6A and 6B that are excluded from the computation of Consolidated EBITDA. Specifically, the costs allowed to be excluded from Consolidated EBITDA are those for emergency response, environmental remediation, cleanup activities, costs to repair the pipelines, inspection costs, potential claims by third parties and lost revenue. As of December 31, 2011, we were in compliance with the terms of our financial covenants.

At December 31, 2011, we had $275.0 million of commercial paper outstanding at a weighted average interest rate of 0.44%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net repayments of approximately $609.8 million during the year ended December 31, 2011, which include gross issuances of $12,017.3 million and gross repayments of $12,627.1 million. Our policy is that the commercial paper we can issue is limited by the amounts available under our New Credit Facility up to an aggregate principal amount of $1.5 billion. Our commercial paper program was increased from $1.0 billion in August 2011.

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $300 million of senior notes issued by the OLP, which we refer to as the OLP Notes. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. All of our senior notes either pay or accrue interest semi-annually and have varying maturities and terms.

The OLP, our operating subsidiary that owns the Lakehead system, has $300 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. All of the OLP Notes pay interest semi-annually and have varying maturities and terms.

In September 2011, we issued and sold $600 million in aggregate principal amount of senior notes due 2021, which we refer to as the 2021 Notes. The 2021 Notes bear interest at the rate of 4.20% per year and will mature on September 15, 2021. Interest on the 2021 Notes is payable on March 15 and September 15 of each year, beginning on March 15, 2012. Also in September 2011, we issued and sold an additional $150 million in aggregate principal amount of our 5.50% notes due in 2040, which we refer to as the 2040 Notes. The additional 2040 Notes will be fully fungible with, rank equally in right of payment with and form a part of the same series as the existing 2040 Notes, originally issued by us in September 2010, for all purposes under the governing indenture. We received net proceeds from the note offerings in September 2011 of approximately $740.7 million after payment of underwriting discounts and commissions and our estimated offering expenses. We used the net proceeds from these offerings to repay a portion of our outstanding commercial paper, to fund a portion of our capital expansion projects and for general corporate purposes.

The Junior Subordinated Notes, which we refer to as the Junior Notes, consist of our 8.05% fixed/floating rate, unsecured, long-term junior subordinated notes due 2067, with a principal amount outstanding of $400 million. The Junior Notes are subordinate in right of payment to all of our existing and future senior indebtedness, as defined in the related indenture.

In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement by issuing a promissory note payable to our General Partner, at which time we also terminated the A1 Credit Agreement. The promissory note payable, which we refer to as the A1 Term Note, matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the investment our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement to finance any additional costs associated with the construction of our portion of the Alberta Clipper Pipeline we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. At December 31, 2011, we had approximately $342.0 million outstanding under the A1 Term Note.

Our General Partner also made equity contributions totaling $3.3 million and $102.3 million to the Enbridge Energy Limited Partnership, or OLP, during the years ended December 31, 2011 and 2010, to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline. The OLP paid a distribution of $76.4 million and $38.6 million to our General Partner and its affiliate during the years ended December 31, 2011 and 2010 for their noncontrolling interest in the Series AC, representing limited partner ownership interests of the OLP that are specifically related to the assets, liabilities and operations of the Alberta Clipper Pipeline.

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $53.2 million and $60.6 million to our General Partner for its 66.67 percent share of the earnings of the Alberta Clipper Pipeline for the years ended December 31, 2011 and 2010, respectively. We have presented the amounts we

allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Our New Credit Facility contains restrictive covenants that require us to maintain a maximum leverage ratio of 5.00 to 1.00. At December 31, 2011, we were in compliance with the covenants associated with our New Credit Facility. Our New Credit Facility also place limitations on the debt that our subsidiaries may incur directly. Accordingly, it is expected that we will provide debt financing to our subsidiaries as necessary.

Our senior notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with our indenture agreement. We were in compliance with these covenants at December 31, 2011.

The OLP Notes do not contain any covenants restricting us from issuing additional indebtedness by the OLP. The OLP Notes are subject to make-whole redemption rights and were issued under an indenture, referred to as the OLP Indenture, containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with the OLP Indenture. We were in compliance with these covenants at December 31, 2011.

We expect to make additional expenditures during the next year for the acquisition and construction of natural gas processing and crude oil transportation infrastructure. In 2012, we expect to spend approximately $2.1 billion on system enhancements and other projects associated with our liquids and natural gas systems with the expectation of realizing additional cash flows as projects are completed and placed into service. At December 31, 2011, we had approximately $400.4 million in outstanding purchase commitments attributable to capital projects for the construction of assets that we expect to record as property, plant and equipment during 2012.

During 2011, our cash flows were impacted by the approximate $287.6 million we paid for the environmental remediation, restoration and cleanup activities, excluding recognized insurance recoveries of $335.0 million, resulting from the crude oil releases that occurred in 2010 on Lines 6A and 6B of our Lakehead system.

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to pursue potential acquisitions with a focus on natural gas pipelines, NGL pipelines, refined products pipelines, terminals and related facilities. We will seek opportunities for accretive acquisitions throughout the United States, particularly in the United States Gulf Coast area, where we anticipate making asset acquisitions in and around our existing Natural Gas business. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our New Credit Facility and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.

We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and includes the replacement of system components and equipment which are worn, obsolete or completing its useful life. We also include a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems as core maintenance expenditures. Enhancement expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards.

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth our estimates of capital expenditures we expect to make for system enhancement and core maintenance for the year ending December 31, 2012. Although we anticipate making these expenditures in 2012, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. We made capital expenditures of $1,096.6 million, including $99.1 million on core maintenance activities, for the year ended December 31, 2011. For the full year ending December 31, 2012, we anticipate our capital expenditures to approximate the following:

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs.

Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses. Our capital spending has have increased over time as our pipeline systems age.

On May 12, 2011, we announced plans to replace 75-miles of non-contiguous sections of Line 6B of our Lakehead system at an estimated cost of $286 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. Subject to regulatory approvals, the new segments of pipeline will be constructed mostly in 2012 and are targeted to be placed in-service by the first quarter of 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through the FSM that is part of the system-wide rates of the Lakehead system. We have recently revised the scope of this project to increase the cost by approximately $30 million, which will bring the total capital for this replacement program to an estimated cost of $316 million. The $30 million of additional costs do not currently have recovery under the FSM.

In February 2011, we included in the supplement to our FSM, to be effective April 1, 2011, recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, which include an equity return component, interest expense and an allowance for income taxes will be recovered over a 30 year period, while operating costs will be recovered through our annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that core maintenance capital will continue to increase due to the growth of our pipeline systems and the aging of portions of these systems. Core maintenance expenditures are expected to be funded by operating cash flows.

We anticipate funding system enhancement capital expenditures temporarily through borrowing under the terms of our New Credit Facility, with permanent debt and equity funding being obtained when appropriate.

The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at December 31, 2011 for each of the indicated calendar years:

The following table provides summarized information about the timing and estimated settlement amounts of our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at December 31, 2011 for each of the indicated calendar years:

We make quarterly distributions to our General Partner and the holders of our limited partner interests in an amount equal to our “available cash.” As defined in our partnership agreement, “available cash” represents for any calendar quarter, the sum of all of our cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. We establish reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and the General

Partner and, as necessary, to comply with the terms of any of our agreements or obligations. Enbridge Management, as the delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.”

Enbridge Management, as the owner of our i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to our General Partner and the holders of our Class A and Class B common units, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management’s listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management’s listed shares on the NYSE for the 10 consecutive trading day period immediately


Large Accelerated Filer x		Accelerated Filer ¨
Non-Accelerated Filer ¨		Smaller reporting company ¨
(Do not check if a smaller reporting company)


		Page
	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		32
Item 2.	Properties		49
Item 3.	Legal Proceedings		49
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Unitholder Matters		50
Item 6.	Selected Financial Data		51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		102
Item 8.	Financial Statements and Supplementary Data		113
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		187
Item 9A.	Controls and Procedures		187
Item 9B.	Other Information		190
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		191
Item 11.	Executive Compensation		197
Item 12.	Security Ownership of Certain Beneficial Owners and Management		225
Item 13.	Certain Relationships and Related Transactions, and Director Independence		227
Item 14.	Principal Accountant Fees and Services		237
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		237
Signatures			238


PSI Act		Pipeline Safety Improvement Act
SAGD		Steam assisted gravity drainage
SEC		United States Securities and Exchange Commission
SEP II		System Expansion Program II, an expansion program on our Lakehead system
Series AC interests		Partnership interests of the OLP related to all the assets, liabilities and operations of the Alberta Clipper Pipeline
Series LH interests		Partnership interests of the OLP related to all the assets, liabilities and operations of the Lakehead System, excluding those designated by the Series AC interests
Southern Access		Southern Access Pipeline, a 42-inch pipeline that runs from Superior, Wisconsin to Flanagan, Illinois on our Lakehead system
Suncor		Suncor Energy Inc., an unrelated energy company
Syncrude		Syncrude Canada Ltd., an unrelated energy company
Synthetic crude oil		Product that results from upgrading or blending bitumen into a crude oil stream, which can be readily refined by most conventional refineries
Tariff Agreement		A 1998 offer of settlement filed with the FERC
Terrace		Terrace expansion program, an expansion program on our Lakehead system
TSX		Toronto Stock Exchange
U.S. GAAP		United States Generally Accepted Accounting Principles
WCSB		Western Canadian Sedimentary Basin


	2011		2010		2009		2008		2007
	(thousands of Bpd)
United States
Light crude oil		473		458		467		388		346
Medium and heavy crude oil		850		841		834		876		852
NGL		4		3		4		3		4

Total United States		1,327		1,302		1,305		1,267		1,202

Ontario
Light crude oil		220		223		197		183		184
Medium and heavy crude oil		84		57		73		80		62
NGL		69		73		75		90		95

Total Ontario		373		353		345		353		341

Total Deliveries		1,700		1,655		1,650		1,620		1,543

Barrel miles (billions per year)		450		439		423		432		408


	Published Transportation Rate Per Barrel⁽¹⁾
	Light		Medium		Heavy
To Clearbrook, Minnesota	$	0.3628	$	0.3842	$	0.4218
To Superior, Wisconsin	$	0.7595	$	0.8110	$	0.9010
To Chicago, Illinois area	$	1.6625	$	1.7879	$	2.0076
To Marysville, Michigan area	$	2.0021	$	2.1545	$	2.4220
To Buffalo, New York area	$	2.0514	$	2.2080	$	2.4819
Chicago to the international border near Marysville	$	0.6807	$	0.7258	$	0.8055
Clearbrook, Minnesota to Chicago	$	1.4751	$	1.5790	$	1.7612


Title of each class		Name of each exchange on which registered
Class A common units		New York Stock Exchange


Alberta Clipper		Alberta Clipper Pipeline, a 36-inch pipeline that runs from the border near Neche, North Dakota to Superior, Wisconsin on our Lakehead system
Anadarko system		Natural gas gathering and processing assets located in western Oklahoma and the Texas panhandle which serve the Anadarko basin; inclusive of the Elk City System
AOCI		Accumulated other comprehensive income
AOSP		Athabasca Oil Sands Project, located in northern Alberta, Canada
Bbl		Barrel of liquids (approximately 42 United States gallons)
Bpd		Barrels per day
CAA		Clean Air Act
CNRL		Canadian Natural Resources Limited, an unrelated energy company
CAPP		Canadian Association of Petroleum Producers, a trade association representing a majority of our Lakehead system’s customers
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act
CAD		Amount denominated in Canadian dollars
CWA		Clean Water Act
DOT		United States Department of Transportation
East Texas system		Natural gas gathering, treating and processing assets in East Texas that serve the Bossier trend and Haynesville shale areas. Also includes a system formerly known as the Northeast Texas system
EDA		Equity Distribution Agreement
Elk City system		Elk City natural gas gathering and processing system located in western Oklahoma in the Anadarko basin
Enbridge		Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner
Enbridge Management		Enbridge Energy Management, L.L.C.
Enbridge system		Canadian portion of the liquid petroleum mainline system
Enbridge Pipelines		Enbridge Pipelines Inc.
EP Act		Energy Policy Act of 1992
EPA		Environmental Protection Agency
ERCB		Energy Resource Conservation Board, a successor regulatory body to the Alberta Energy Utility Board
Exchange Act		Securities Exchange Act of 1934, as amended
FERC		Federal Energy Regulatory Commission
General Partner		Enbridge Energy Company, Inc., the general partner of the Partnership
ICA		Interstate Commerce Act
ISDA^®		International Swaps and Derivatives Association
Lakehead Partnership		Enbridge Energy, Limited Partnership, a subsidiary of the Partnership, also referred to as the OLP
Lakehead system		United States portion of the liquid petroleum mainline system
LIBOR		London Interbank Offered Rate—British Bankers’ Association’s average settlement rate for deposits in United States dollars


Mainline system		The combined liquid petroleum pipeline operations of our Lakehead system and the Enbridge system, which is a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada
M3		Cubic meters of liquid = 6.2898105 Bbl
MDNRE		Michigan Department of Natural Resources and Environment
MLP		Master Limited Partnership
Mcf/d		Thousand cubic feet per day
MMBtu/d		Million British Thermal units per day
MMcf/d		Million cubic feet per day
Midcoast system		Natural gas gathering, treating, processing, transmission and marketing assets acquired October 17, 2002
Mid-Continent system		Crude oil pipelines and storage facilities located in the Mid-Continent region of the United States and includes the Cushing tank farm and Ozark pipeline
NEB		National Energy Board, a Canadian federal agency that regulates Canada’s energy industry
NGA		Natural Gas Act
NGL or NGLs		Natural gas liquids
NGPA		Natural Gas Policy Act
North Dakota system		Liquids petroleum pipeline gathering system and common carrier pipeline in the Upper Midwest United States that serves the Bakken formation within the Williston basin
North Texas system		Natural gas gathering and processing assets located in the Fort Worth basin serving the Barnett shale area
NTSB		National Transportation Safety Board
NYMEX		The New York Mercantile Exchange where natural gas futures, options contracts and other energy futures are traded
NYSE		New York Stock Exchange
OLP		Enbridge Energy, Limited Partnership, also referred to as the Lakehead Partnership
OPA		Oil Pollution Act
PADD		Petroleum Administration for Defense Districts
PADD I		Consists of Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West Virginia
PADD II		Consists of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin
PADD III		Consists of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas
PADD IV		Consists of Idaho, Montana, Wyoming, Colorado and Utah
PADD V		Consists of Washington, Oregon, California, Arizona, Alaska, Hawaii and Nevada
Partnership Agreement		Fourth Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P.
Partnership		Enbridge Energy Partners, L.P. and its consolidated subsidiaries
Phase VI		Phase VI Expansion Program, an expansion program on our North Dakota system
PHMSA		Pipeline and Hazardous Materials Safety Administration
PIPES of 2006		Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
PPI-FG		Producer Price Index for Finished Goods
PSA		Pipeline Safety Act


	Published Transportation Rate Per Barrel⁽¹⁾

To Wood River	$	0.5477


	Published Transportation Rate Per Barrel⁽¹⁾⁽²⁾		Subject To Embargo⁽³⁾
From Glenburn, Minot, Newberg, Sherwood, and Stanley, North Dakota to Clearbrook	$	1.4213		No
From Berthold, North Dakota to Clearbrook	$	1.4213		Yes
From Berthold, North Dakota to International boundary near Portal, North Dakota	$	1.4213		No
From Grenora, North Dakota to Clearbrook	$	1.5551		No
From Flat Lake and Reserve, Montana to Clearbrook	$	1.5847		No
From Tioga to Clearbrook, Minnesota	$	1.4507		No
From Trenton, North Dakota to Clearbrook	$	2.1340		No
From Alexander, North Dakota to Clearbrook	$	2.1783		No
From Reserve, Montana to Tioga	$	0.6541		No
From Trenton and Missouri Ridge, North Dakota to Tioga	$	0.9802		No
From Alexander, North Dakota to Tioga	$	1.0244		No
From (pump-over) Stanley, North Dakota to Stanley	$	0.2500		No
From Tioga to Stanley, North Dakota	$	0.9411		No
From Grenora, North Dakota to Stanley	$	1.0455		No
From Reserve, Montana to Stanley	$	1.0751		No
From Trenton and Missouri Ridge, North Dakota to Stanley	$	1.6244		No
From Alexander, North Dakota to Stanley	$	1.6687		No


	Coverage Limits				Deductible Amount
Insurance Type	CAD		USD		CAD		USD
	(in millions)
Property and business interruption⁽¹⁾	Up to $	700.0	Up to $	688.0	$	10.0	$	10.0
General liability⁽²⁾	Up to $	585.0	Up to $	575.0	$	0.1	$	0.1
Pollution liability⁽²⁾	Up to $	585.0	Up to $	575.0	$	5.1	$	5.0


	First		Second		Third		Fourth
2011 Quarters
High	$	33.86	$	34.58	$	30.24	$	33.22
Low	$	30.25	$	28.50	$	25.03	$	24.66
Cash distributions paid	$	0.514	$	0.514	$	0.533	$	0.533
2010 Quarters
High	$	27.87	$	26.87	$	30.10	$	31.70
Low	$	23.39	$	19.01	$	25.19	$	28.03
Cash distributions paid	$	0.495	$	0.501	$	0.514	$	0.514


	December 31,
	2011			2010			2009			2008		2007
	(in millions, except per unit amounts)
Income Statement Data:^{(2)(3)(4)(5)(6)(7)(9)(10)}
Operating revenues	$	9,109.8		$	7,736.1		$	5,731.8		$	9,898.7	$	7,172.1
Operating expenses		8,113.0			7,608.8			5,115.2			9,318.1		6,853.7

Operating income (loss)		996.8			127.3			616.6			580.6		318.4
Interest expense		320.6			274.8			228.6			180.6		99.8
Other income		6.5			17.5			13.4			1.9		4.2
Income tax expense		5.5			7.9			8.5			7.0		5.1
Noncontrolling interest		53.2			60.6			11.4			—		—

Income(loss) from continuing operations attributable to general and limited partnership interests	$	624.0		$	(198.5	)	$	381.5		$	394.9	$	217.7

Income(loss) from continuing operations per limited partner unit (basic and diluted)⁽¹⁾	$	1.99		$	(1.09	)	$	1.12		$	3.55	$	2.10

Cash distributions paid per limited partner unit	$	2.0925		$	2.0240		$	1.9800		$	3.8800	$	3.7250

Financial Position Data (at year end):^{(2)(3)(4)(5)(6)(7)(9)(10)}
Property, plant and equipment, net	$	9,439.4		$	8,641.6		$	7,716.7			6,722.9		5,554.9
Total assets		11,370.1			10,441.0			8,988.3			8,300.9		6,891.6
Long-term debt, excluding current maturities		4,816.1			4,778.9			3,791.2			3,223.4		2,862.9
Loans from General Partner and affiliates		342.0			347.4			269.7			130.0		130.0
Partners’ capital:
Class A common units		3,386.7			2,641.0			2,884.9			2,104.0		1,340.7
Class B common units		82.2			64.9			78.6			85.0		72.9
Class C units⁽⁸⁾		—			—			—			886.5		874.1
i-units		728.6			579.1			588.8			553.8		515.3
General Partner		285.6			256.8			251.1			84.7		62.9
Accumulated other comprehensive income (loss)⁽¹⁾		(316.5	)		(121.7	)		(74.6	)		12.9		(294.4	)
Noncontrolling interest		445.5			465.4			341.1			—		—

Partners’ capital	$	4,612.1		$	3,885.5		$	4,069.9		$	3,726.9	$	2,571.5

Cash Flow Data:^{(2)(3)(4)(5)(6)(7)(9)(10)}
Cash flows provided by operating activities	$	1,045.6		$	377.9		$	728.4			543.3		463.4
Cash flows used in investing activities		1,099.0			1,427.8			1,173.6			1,428.3		1,765.0
Cash flows provided by financing activities		331.4			1,051.2			248.9			1,174.4		1,167.5
Additions to property, plant and equipment and acquisitions included in investing activities, net of cash acquired		1,143.2			1,429.5			1,292.1			1,387.1		1,980.2


	For the years ended December 31,
	2011			2010
	(in millions)
Hedge ineffectiveness	$	(5.3	)	$	3.5
Non-qualified hedges		21.1			0.9

Derivative fair value gains	$	15.8		$	4.4


	(in millions)
Other current assets	$	3.9
Property, plant and equipment, net		489.5
Intangibles		189.2
Other assets		4.7

Total assets acquired		687.3
Other long-term liabilities		1.2

Net assets acquired	$	686.1


	For the year ended December 31, 2009
	(in millions)
Operating revenue	$	173.6

Operating expenses
Cost of natural gas		143.3
Operating and administrative		19.1
Depreciation and amortization		11.6

		174.0

Operating loss		(0.4	)
Interest Expense		—
Other expense		(64.5	)

Loss from discontinued operations	$	(64.9	)


	(in millions)
Cash and cash equivalents	$	422.9
Total credit available under New Credit Facility		2,000.0
Less: Amounts outstanding under New Credit Facility		—
Principal amount of commercial paper issuances		275.0
Letters of credit outstanding		173.8

Total	$	1,974.1


Issuance Date	Number of Class A common units Issued		Average Offering Price per Class A common unit		Net Proceeds to the Partnership⁽¹⁾		General Partner Contribution⁽²⁾		Net Proceeds Including General Partner Contribution
	(in millions, except units and per unit amounts)
2011
January 1 to March 31⁽³⁾		1,773,448	$	32.26	$	55.9	$	1.2	$	57.1
April 1 to May 26⁽³⁾		225,200	$	32.16		7.0		0.1		7.1
May 27 to June 30⁽⁴⁾		333,794	$	30.30		9.9		0.2		10.1
July 1 to September 30⁽⁴⁾		751,766	$	28.38		20.8		0.4		21.2

2011 Totals		3,084,208			$	93.6	$	1.9	$	95.5

2010
April 1 to June 30⁽³⁾		574,690	$	26.26	$	14.8	$	0.3	$	15.1
July 1 to September 30⁽³⁾		1,373,482	$	27.11		36.3		0.7		37.0
October 1 to December 31⁽³⁾		289,230	$	27.85		7.6		0.2		7.8

2010 Totals⁽³⁾		2,237,402			$	58.7	$	1.2	$	59.9


Issuance Date	Number of Class A common units Issued⁽⁶⁾		Offering Price per Class A common unit⁽⁶⁾		Net Proceeds to the Partnership⁽¹⁾		General Partner Contribution⁽²⁾		Net Proceeds Including General Partner Contribution
	(in millions, except units and per unit amounts)
2011
December⁽³⁾		9,775,000	$	30.85	$	292.0	$	6.1	$	298.1
September⁽³⁾		8,000,000	$	28.20	$	218.3	$	4.6	$	222.9
July⁽³⁾		8,050,000	$	30.00	$	233.7	$	4.9	$	238.6

2011 Totals		25,825,000			$	744.0	$	15.6	$	759.6

2010
November⁽⁴⁾		11,960,000	$	30.06	$	347.4	$	7.4	$	354.8

2009
October⁽⁵⁾		42,490	$	23.54	$	1.0	$	—	$	1.0


	Total Forecasted Expenditures
	(in millions)
Capital Projects
System enhancements	$	705
Liquids integrity program		325
Natural Gas integrity program		30
Core maintenance activities		115
North Dakota Expansion Program		395
Line 6B Replacement Program		210
Ajax Cryogenic Processing Plant		130
Joint Venture Projects
Texas Express Pipeline		210

	$	2,120


	Notional		2012			2013			2014			2015		2016		Total⁽⁴⁾
	(in millions)
Swaps
Natural gas⁽¹⁾		113,981,412	$	1.0		$	6.5		$	0.1		$	—	$	—	$	7.6
NGL⁽²⁾		5,319,859		(13.9	)		(8.2	)		(1.1	)		0.5		—		(22.7	)
Crude Oil⁽²⁾		4,834,191		(12.1	)		(6.3	)		1.8			5.6		0.4		(10.6	)
Options
Natural gas—puts purchased⁽¹⁾		1,642,500		—			1.2			—			—		—		1.2
NGL—puts purchased⁽²⁾		1,650,582		7.3			0.9			—			—		—		8.2
Crude Oil —puts purchased⁽²⁾		64,050		0.7			—			—			—		—		0.7
Forward contracts
Natural gas⁽¹⁾		37,177,357		1.2			0.5			0.1			0.1		0.1		2.0
NGL⁽²⁾		6,073,379		4.6			0.3			—			—		—		4.9
Crude Oil⁽²⁾		1,771,728		(1.0	)		—			—			—		—		(1.0	)
Power⁽³⁾		163,862		(0.5	)		(0.3	)		(0.5	)		—		—		(1.3	)

Totals			$	(12.7	)	$	(5.4	)	$	0.4		$	6.2	$	0.5	$	(11.0	)


	Notional Amount		2012			2013			2014			2015			2016			Thereafter		Total⁽¹⁾
	(in millions)
Interest Rate Derivatives
Interest Rate Swaps:
Floating to Fixed	$	1,925.0	$	(25.8	)	$	(23.0	)	$	(6.2	)	$	(3.3	)	$	(1.0	)	$	—	$	(59.3	)
Fixed to Floating	$	125.0		4.9			2.6			—			—			—			—		7.5
Pre-issuance hedges	$	1,850.0		(123.7	)		(63.1	)		(23.4	)		—			—			—		(210.2	)

			$	(144.6	)	$	(83.5	)	$	(29.6	)	$	(3.3	)	$	(1.0	)	$	—	$	(262.0	)