Item 1. Business
OVERVIEW
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:
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Approximately 6,500 miles of crude oil gathering and transportation lines and 32.0 million barrels, or MMBbl, of crude oil storage and terminaling capacity;
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Natural gas gathering and transportation lines totaling approximately 11,500 miles;
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Nine natural gas treating and 25 natural gas processing facilities with an aggregate capacity of approximately 3,255 million cubic feet per day, or MMcf/d, including plants we may idle from time to time based on current volumes;
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Trucks, trailers and railcars for transporting natural gas liquids, or NGLs, crude oil and carbon dioxide; and
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Marketing assets that provide natural gas supply, transmission, storage and sales services.
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.”
BUSINESS STRATEGY
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:
1. Operational excellence
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We will continue to focus on safety, environmental integrity, innovation and effective stakeholder relations. We strive to operate our existing infrastructure to maximize cost efficiencies, provide flexibility for our customers and ensure the capacity is reliable and available when required.
2. Expanding our core asset platforms
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We intend to acquire and develop energy transportation assets and related facilities that are complementary to our existing systems. Our core businesses provide plentiful opportunities to achieve our primary business objectives.
3. Developing new asset platforms
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We plan to develop and acquire new gathering, processing, transportation and storage assets to meet customer needs by expanding capacity into new markets with favorable supply and demand fundamentals.
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.
Liquids
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:
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Portal Reversal Expansion Project-In 2011, our North Dakota system completed the Portal Reversal Expansion Project, or PREP, which increased our system capacity by 25,000 Bpd by opening up capacity into Canada which accesses the Mainline system at Cromer, Manitoba.
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Bakken Pipeline Expansion-In August 2010, to further solidify our position as the primary transportation provider for crude oil production from the Bakken and Three Forks formations, we announced the Bakken Pipeline Expansion project, or the Bakken Project, a joint crude oil pipeline expansion project with an affiliate of Enbridge. 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 to 325,000 Bpd. The United States portion of the Bakken Project has an expected in-service date in the first quarter of 2013. The Bakken Project will follow our existing rights of way in the United States and those of Enbridge Income Fund Holdings Inc., a partially-owned subsidiary of Enbridge, to terminate and deliver to the Enbridge Mainline system’s terminal at Cromer, Manitoba, Canada. In addition, we are proposing projects to further extend and expand our North Dakota pipeline system to connect growing production in this region and to further expand the capacity of the North Dakota system.
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Bakken Access Program-In October 2011, we announced the Bakken Access Program, a series of projects which represent an upstream expansion that will further complement our Bakken Expansion, as discussed above. This access program will substantially enhance our gathering capabilities on the North Dakota system by 100,000 Bpd. This program, expected to be in-service by early 2013, involves increasing pipeline capacities, construction of additional storage tanks and addition of truck access facilities at multiple locations in western North Dakota.
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Berthold Rail Project-In December 2011, we announced the Berthold Rail Project that will provide an interim solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold terminal by 80,000 Bpd and includes the construction of a three unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing facilities. This project is expected to be in-service by early-2013.
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.
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 Lakehead system, and may lead to further expansions on our Alberta Clipper and Southern Access mainline pipelines.
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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 mid-2014.
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Seaway Crude Pipeline System-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. Enbridge and Enterprise Products Partners L.P., or 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 to Port Arthur, Texas and could offer incremental capacity in excess of 400,000 bpd and is expected to be available in early 2014.
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.
Natural Gas
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.
BUSINESS SEGMENTS
We conduct our business through three business segments:
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Liquids;
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Natural Gas; and
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Marketing.
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.
Liquids Segment
Lakehead system
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:
1. Synthetic production from one of Suncor Energy Inc.’s, or Suncor’s, upgraders with a capacity of approximately 357,000 Bpd, averaged approximately 305,000 Bpd in 2011, which was 22,000 Bpd higher than in 2010, and consistent with Suncor’s annual target. Suncor completed its Firebag Stage 3 expansion in the third quarter of 2011, thereby allowing the targeted increase in the production of bitumen of approximately 62,500 Bpd, over the next 24 month period. Since Firebag Stage 3 is now completed, Suncor intends to shift its focus to Firebag Stage 4, which has the same expected production capacity and has an expected in-service date in early 2013. Also, as disclosed in a Suncor news releases during 2011, is its strategic partnership with Total E&P Canada, which will enable both companies to jointly develop the Joslyn and Fort Hills oil sands mining projects, as well as resume construction on the Voyageur upgrader.
2. Syncrude Canada Ltd.’s, or Syncrude’s, synthetic production in 2011 averaged 288,000 Bpd matching production levels in 2010. Synthetic production for Syncrude in 2011 remained steady in spite of unplanned maintenance events on Coker 8-1 affecting average production in the fourth quarter of 2011. Syncrude’s next expansion is the Stage 3 debottleneck which will increase their current system synthetic production by approximately 75,000 Bpd. The projected in-service date of the Stage 3 debottleneck has not been established.
3. The Athabasca Oil Sands Project, or AOSP, owned by Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Corporation (20%), completed an expansion project, referred to as
the Scotford Upgrader Expansion, in May 2011. The completion of the 100,000 Bpd expansion takes upgrading capacity at Scotford to 255,000 Bpd of heavy oil from the Athabasca oil sands.
4. Canadian Natural Resources Limited’s, or CNRL’s, Horizon Oil Sands project experienced severe supply disruptions through the first two quarters of 2011 due to a fire that occurred at the CNRL coker unit in Fort McKay in January 2011. Full production capacity for Phase 1 of Horizon Oil Sands was targeted to deliver 110,000 Bpd of sweet synthetic crude oil in 2011. By October 2011, CNRL production had returned to near target levels. Incremental gains based on approved expenditures for future expansions and debottlenecking are expected to bring production from 110,000 Bpd to 250,000 Bpd in the coming years.
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:
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United States production at Clearbrook, Minnesota through a connection with our North Dakota system;
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United States production at Lewiston, Michigan; and
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Both United States and offshore production in the Chicago area.
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:
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Construction of a new 435,000 Bpd crude oil pipeline from Hardisty, Alberta to Wood River, Illinois and Patoka with capacity subsequently updated to 590,000 Bpd with an expansion to Cushing. The project came into commercial service in June 2010 with the Cushing expansion completed in February 2011.
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In 2008, commercial support was announced to construct Keystone XL, a 36-inch crude 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.
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In early 2012, sufficient commercial support was announced 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.
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.
Mid-Continent system
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.
North Dakota system
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.
Natural Gas Segment
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.
Our natural gas business consists of the following systems:
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East Texas system: Includes approximately 3,900 miles of natural gas gathering and transportation pipelines, eight natural gas treating plants and five natural gas processing plants, including two HCDP plants.
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Anadarko system: Consists of approximately 2,900 miles of natural gas gathering and transportation pipelines in southwest Oklahoma and the Texas panhandle, one natural gas treating plant and 11 natural gas processing plants, which includes the assets we obtained in September 2010 when we acquired the Elk City system.
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North Texas system: Includes approximately 4,700 miles of natural gas gathering pipelines and 9 natural gas processing plants located in the Fort Worth basin.
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.
Trucking and NGL Marketing Operations
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.
Marketing Segment
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.
REGULATION
Regulation by the FERC of Interstate Common Carrier Liquids Pipelines
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 365th 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.
FERC Return on Equity Policy for Oil Pipelines
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.
Accounting for Pipeline Assessment Costs
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.
Regulation by the FERC of Intrastate Natural Gas Pipelines
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.
Natural Gas Gathering Regulation
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.
Sales of Natural Gas, Crude Oil, Condensate and Natural Gas Liquids
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.
Other Regulation
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.
Tariffs and Transportation Rate Cases
Lakehead system
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:
(1) Pursuant to FERC Tariff No. 43.8.0 as filed with the FERC and with an effective date of July 1, 2011.
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.
Base Rates
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.
1998 Settlement Agreement
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.
SEP II Surcharge
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.
Terrace Surcharge
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.
Facilities Surcharge
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:
(1) The Griffith Hartsdale Transfer Lines Project;
(2) The Hartsdale Tanks Project;
(3) The Superior Manifold Modification Project; and
(4) The Line 17 (Toledo) Expansion Project.
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 1st 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):
(5) Southern Access pipeline;
(6) Tank 34 at Superior Terminal and Tank 79 at Griffith Terminal;
(7) Clearbrook Manifold; and
(8) Tank 35 at Superior Terminal and Tank 80 at Griffith Terminal.
On August 28, 2009, the FERC accepted the supplement to the Settlement (Docket No. OR09-5-000) to allow the following three new projects:
(9) Southern Lights Interim Period Impact;
(10) Eastern Access (Trailbreaker) Backstopping Agreement; and
(11) Line 5 Expansion Backstopping Agreement.
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:
(12) Alberta Clipper Pipeline; and
(13) Line 3 Conversion Project.
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:
(14) Line 6B Integrity:
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.
International Joint Tariff
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.
Mid-Continent system
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:
(1) Pursuant to FERC Tariff No. 48.1.0 as filed with the FERC on May 31, 2011, with an effective date of July 1, 2011.
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.
North Dakota system
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:
(1) Pursuant to FERC Tariff No. 72.16.0 as filed with the FERC on December 30, 2011, with an effective date of February 2, 2012.
(2) The looping surcharge was modified in 2009 to extend the cost recovery period by an additional four years, which reduced the rates.
(3) Pursuant to FERC Tariff No. 72.15.0 as filed with the FERC on December 28, 2011, effective immediately thru February 29, 2012.
Safety Regulation and Environmental
General
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.
Pipeline Safety and Transportation Regulation
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.
Environmental Regulation
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.
EMPLOYEES
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.
INSURANCE
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:
(1) Conversion of policy values are based on an exchange rate at December 31, 2011 of $1 CAD to $0.9833 USD.
(2) Conversion of policy values are based on an exchange rate at December 31, 2011 of $1 USD to $1.017 CAD.
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.
TAXATION
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.
AVAILABLE INFORMATION
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.
Item 1A.
Item 1A. Risk Factors
We encourage you to read the risk factors below in connection with the other sections of this Annual Report on Form 10-K.
RISKS RELATED TO OUR BUSINESS
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:
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Using cash from operations;
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Delaying other planned projects;
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Incurring additional indebtedness; or
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Issuing additional equity.
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:
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The operating performances of our assets;
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Commodity prices;
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Actions of government regulatory bodies;
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The level of capital expenditures we make;
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The amount of cash reserves established by Enbridge Management;
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Our ability to access capital markets and borrow money;
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Our debt service requirements and restrictions in our credit agreements;
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Fluctuations in our working capital needs; and
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The cost of acquisitions.
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:
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The risk of incorrect assumptions regarding the future results of the acquired operations or expected cost reductions or other synergies expected to be realized as a result of acquiring such operations;
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A decrease in liquidity as a result of utilizing significant amounts of available cash or borrowing capacity to finance an acquisition;
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The loss of critical customers or employees at the acquired business;
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The assumption of unknown liabilities for which we are not fully and adequately indemnified;
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The risk of failing to effectively integrate the operations or management of acquired assets or businesses or a significant delay in such integration; and
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Diversion of management’s attention from existing operations.
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:
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Competition;
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Regulatory action;
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Weather conditions;
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Storage levels;
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Alternative energy sources;
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Decreased demand;
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Fluctuations in energy commodity prices;
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Economic conditions;
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Supply disruptions;
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Availability of supply connected to our pipeline systems; and
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Availability and adequacy of infrastructure to move, treat and process supply into and out of our systems.
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.
Competition may reduce our revenues.
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.
Our gas marketing operations involve market and regulatory risks.
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:
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Our ability to negotiate on a timely basis natural gas purchase and sales agreements in changing markets;
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Reluctance of wholesale customers to enter into long-term purchase contracts;
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Consumers’ willingness to use other fuels when natural gas prices increase significantly;
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Timing of imbalance or volume discrepancy corrections and their impact on financial results;
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The ability of our customers to make timely payment;
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Inability to match purchase and sale of natural gas on comparable terms; and
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Changes in, limitations upon or elimination of the regulatory authorization required for our wholesale sales of natural gas in interstate commerce.
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.
Increased regulation and regulatory scrutiny may reduce our revenues.
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:
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Physical, which results from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;
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Degradation resulting from mixing at the interface within our pipeline systems or terminals and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and
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Revaluation, which are a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers.
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:
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Permits our General Partner to make a number of decisions, including the determination of which factors it will consider in resolving conflicts of interest, in its “sole discretion.” This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;
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Provides that any standard of care and duty imposed on our General Partner will be modified, waived or limited as required to permit our General Partner to act under our partnership agreement and to make any decision pursuant to the authority prescribed in our partnership agreement, so long as such action is reasonably believed by the General Partner to be in our best interests; and
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Provides that our General Partner and its directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions if they acted in good faith.
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:
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Whether we or Enbridge will pursue certain acquisitions or other business opportunities;
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Whether we will issue additional units or other equity securities or whether we will purchase outstanding units;
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Whether Enbridge Management will issue additional shares;
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The amount of payments to Enbridge and its affiliates for any services rendered for our benefit;
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The amount of costs that are reimbursable to Enbridge Management or Enbridge and its affiliates by us;
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The enforcement of obligations owed to us by Enbridge Management, our General Partner or Enbridge, including obligations regarding competition between Enbridge and us; and
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The retention of separate counsel, accountants or others to perform services for us and Enbridge Management.
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:
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Enbridge and its subsidiaries are not restricted from continuing to engage in businesses, including the normal development of such businesses, in which they were engaged at the time of our initial public offering in December 1991;
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Such restriction is limited geographically only to those routes and products for which we provided transportation at the time of our initial public offering;
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Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us as part of a larger acquisition, so long as the majority of the value of the business or assets acquired, in Enbridge’s reasonable judgment, is not attributable to the competitive business; and
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Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us if that business is first offered for acquisition to us and the board of directors of Enbridge Management and our unitholders determine not to pursue the acquisition.
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:
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The amount available for distributions on each unit may decrease;
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The relative voting power of each previously outstanding unit may decrease; and
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The market price of the Class A common units may decline.
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.
Holders of our limited partner interests have limited voting rights.
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:
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General creditors;
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Trade creditors;
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Secured creditors;
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Taxing authorities; and
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Creditors holding guarantees.
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.
RISKS RELATED TO OUR DEBT AND OUR ABILITY TO MAKE DISTRIBUTIONS
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:
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Incurring additional debt;
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Entering into mergers or consolidations or sales of assets; and
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Granting liens.
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.
TAX RISKS TO COMMON UNITHOLDERS
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.
Item 2.
Item 2. Properties
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.
Item 3.
Item 3. Legal Proceedings
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.
PART II
Item 5.
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.
Item 6.
Item 6. Selected Financial Data
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.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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.
RESULTS OF OPERATIONS-OVERVIEW
We provide services to our customers and returns for our unitholders primarily through the following activities:
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Interstate pipeline transportation and storage of crude oil and liquid petroleum;
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Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities; and
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Supply, transportation and sales services, including purchasing and selling natural gas and NGLs.
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.
Summary Analysis of Operating Results
Liquids
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:
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A decrease in environmental costs, net of insurance recoveries, of $713.7 million for the year ended December 31, 2011 when compared to the same period of 2010;
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Higher average daily delivery volumes on all three of our systems when compared to the same period in 2010;
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Additional revenues of $34.8 million when compared to the same period in 2010 due to the completion of the Alberta Clipper Pipeline in April 2010;
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Unrealized, non-cash, mark-to-market net gains of $14.4 million for the year ended December 31, 2011, associated with derivative financial instruments that do not qualify for hedge accounting treatment compared with $2.8 million of net losses we experienced in the respective period of 2010; and
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$52.2 million we received in the second quarter of 2011 for the settlement of a dispute related to oil measurement losses, which we recognized as a reduction to operating expenses.
Natural Gas
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:
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Increased natural gas gathering and processing volumes on our Anadarko system as a result of growth in the Granite Wash play and the additional 185,000 MMBtu/d of volumes associated with our acquisition of the Elk City system in September 2010;
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Increased volumes on our East Texas system due to new assets being placed in service to capture growth associated with Haynesville production;
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Decrease of $24.4 million in operating revenue less the cost of natural gas derived from keep-whole earnings offsetting the increases in volumes discussed above;
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Increase of $58.9 million due to more favorable pricing environment for the year ended December 31, 2011 compared to the same period of 2010;
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$11.4 million increase in unrealized, non-cash, mark-to-market net gains from derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with the same period of 2010; and
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Decrease of approximately $33 million in operating revenue due to accounting misstatements for NGL product purchases and sales made by our trucking and NGL marketing business for the year ended December 31, 2010 that were recorded in 2011.
Marketing
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.
Derivative Transactions and Hedging Activities
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:
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Liquids segment commodity-based derivatives-“Operating revenue” and “Power”
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Natural Gas and Marketing segments commodity-based derivatives-“Cost of natural gas”
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Corporate interest rate derivatives-“Interest expense”
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:
RESULTS OF OPERATIONS-BY SEGMENT
Liquids
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:
(1) Average barrels per day in thousands.
(2) Includes average system deliveries of 7 thousand bpd and 41 thousand bpd for the years ended 2010 and 2009, respectively, from the West Tulsa crude oil pipeline which was removed from service in September 2010.
Year ended December 31, 2011 compared with year ended December 31, 2010
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:
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Higher costs related to our pipeline integrity program;
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Additional workforce related costs associated with the operational, administrative, regulatory and compliance support necessary for our systems;
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Property tax increases associated with assets we constructed and placed in service;
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Higher costs for repair and maintenance activities; and
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Increases in other variable costs incurred in relation to our expanded pipeline systems.
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.
Operating Impact of Lines 6A and 6B Crude Oil Releases
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.
Year ended December 31, 2010 compared with year ended December 31, 2009
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.
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:
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Effective January 1, 2010, we increased the rates for transportation on our North Dakota system to include a new surcharge related to the recent completion of our North Dakota Phase VI expansion program, referred to as North Dakota Phase VI;
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Effective April 1, 2010, we increased the rates for transportation on our Lakehead system in connection with the completion of our Alberta Clipper Pipeline. We also increased the transportation rates on our Lakehead system for additional facilities we added for which we receive a cost-of-service return and a true-up for costs associated with the Southern Access Pipeline;
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Effective April 1, 2010, we extended by four years the term of the looping surcharge on our North Dakota system, which is a component of North Dakota Phase V. 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, Missouri Ridge and Alexander, North Dakota delivered to Tioga, North Dakota; and
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Effective July 1, 2010, we decreased the average transportation rates on all three of our Liquids systems in connection with the annual index rate ceiling adjustment.
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.
Operating Impact of Lines 6A and 6B Crude Oil Releases
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.
Future Prospects Update for Liquids
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.
International Joint Toll Agreement
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.
Eastern Market Expansion
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.
Berthold Rail
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.
Bakken Pipeline Expansion
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.
Bakken Access Program
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.
Cushing Terminal Storage Expansion Project
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.
Line Replacement Program
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.
Other Matters
Line 6B Pipeline Integrity Plan
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.
Natural Gas
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:
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Approximately 11,500 miles of natural gas gathering and transmission pipelines;
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Nine natural gas treating plants and 25 natural gas processing plants, excluding inactive plants and including plants that we idle from time to time based on current volumes; and
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Trucks, trailers and railcars used for transporting NGLs, crude oil and other products.
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.
(1) Average daily volumes for the year ended December 31, 2011 and 2010 include 251,000 MMBtu/d and 66,000 MMBtu/d, respectively, of volumes associated with our acquisition of the Elk City system.
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:
Fee-Based 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.
Other Arrangements
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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
INTEREST RATE RISK
We utilize both fixed and variable interest rate debt and are exposed to market risk resulting from the variable interest rates on our New Credit Facility. To the extent that we frequently issue and re-issue commercial paper at short-term interest rates and have amounts drawn under our New Credit Facility at floating rates of interest, our earnings and cash flows are exposed to changes in interest rates. This exposure is managed through
periodically refinancing floating-rate bank debt with long-term fixed rate debt and through the use of interest rate derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics. We do not have any material exposure to movements in foreign exchange rates as virtually all of our revenues and expenses are denominated in USD. To the extent that a material foreign exchange exposure arises, we intend to hedge such exposure using derivative financial instruments.
The following table presents the principal cash flows and related weighted average interest rates by expected maturity dates along with the carrying values and fair values of our third-party debt obligations as of December 31, 2011 and 2010.
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas we purchase for processing. Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our fixed and variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. 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, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.
The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations that are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional amounts and weighted average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted average variable rates are based on implied forward rates in the yield curve at December 31, 2011.
(1) Interest rate derivative contracts are based on the one-month or three-month London Inter-Bank Offered Rate, or LIBOR.
(2) The fair value is determined from quoted market prices at December 31, 2011 and 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $19.4 million of gains at December 31, 2011 and $0.5 million of gains at December 31, 2010.
(3) Settled in connection with the issuance of our 2021 Notes.
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:
(1) Fair values are presented in millions of dollars and exclude credit adjustments of approximately $19.4 million of gains at December 31, 2011.
COMMODITY PRICE RISK
Our exposure to commodity price risk exists within our Natural Gas and Marketing segments. We use derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to manage the risks associated with market fluctuations in commodity prices as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2011 and December 31, 2010.
(1) Volumes of natural gas are measured in millions of British Thermal Units, or MMBtu, whereas volumes of NGL and crude oil are measured in barrels, or Bbl. Our power purchase agreements are measured in Megawatt hours, or MWh.
(2) Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.
(3) The fair value is determined based on quoted market prices at December 31, 2011 and December 31, 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.8 million of losses and $0.6 million of gains at December 31, 2011 and December 31, 2010, respectively.
(4) For physical power, the receive price shown represents the index price used for valuation purposes.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at December 31, 2011 and 2010.
(1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2) Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3) The fair value is determined based on quoted market prices at December 31, 2011 and December 31, 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of losses at December 31, 2011 and $0.1 million of losses at December 31, 2010.
QUALITATIVE FACTORS
Hedge Accounting
We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value.
In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Operating revenue,” “Cost of natural gas” and “Power” for our commodity-based derivatives and “Interest expense” for our interest rate derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.
If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas” for commodity hedges and “Interest expense” for interest rate hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.
Non-Qualified Hedges
Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have transaction types associated with our commodity and interest rate derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas,” “Operating revenue”, “Power” or “Interest expense” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.
The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:
Commodity Price Exposures:
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Transportation-In our Marketing segment, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.
•
Storage-In our Marketing segment, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas is recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas storage activities can create volatility in our earnings.
•
Natural Gas Collars-In our Natural Gas segment, we previously entered into natural gas collars to hedge the sales price of natural gas. The natural gas collars were based on a New York Mercantile Exchange, or NYMEX, pricing index, while the physical gas sales were based on a different index. To better align the index of the natural gas collars with the index of the underlying sales, we de-designated the original cash flow hedging relationship with the intent of contemporaneously re-designating the natural gas collars as hedges of forecasted physical natural gas sales with a NYMEX pricing index. However, because the fair value of these derivative instruments was a liability to us at re-designation, they are considered net written options and, pursuant to the authoritative accounting guidance, do not qualify for hedge accounting. These derivatives are being marked-to-market, with the changes in fair value from the date of de-designation recorded to earnings each period. As a result, our operating income is subject to greater volatility due to movements in the prices of natural gas until the underlying long-term transactions are settled.
•
Optional Natural Gas Processing Volumes-In our Natural Gas segment, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
•
NGL Forward Contracts-In our Natural Gas segment, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. Prior to April 1, 2009, these forward contracts were not treated as derivative financial instruments pursuant to the normal purchase normal sale, or NPNS, exception allowed under authoritative accounting guidance, since the forward contracts resulted in physical receipt or delivery of NGLs. However, evolving markets for NGLs have increased opportunities for a portion of our forward contracts to be settled net rather than physically receiving or delivering the NGLs. Accordingly, we have revoked the NPNS election on certain forward contracts associated with the liquids marketing operations of Dufour Petroleum, L.P., our wholly-owned subsidiary, executed after April 1, 2009. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.
•
Natural Gas Forward Contracts-In our Marketing segment, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.
•
Crude Oil Contracts-In our Liquids segment, we use forward contracts to hedge a portion of the crude oil length inherent in the operation of our pipelines, which we subsequently sell at market rates. These hedges create a fixed sales price for the crude oil that we will receive in the future. We elected not to designate these derivative financial instruments as cash flow hedges, and as a result, will experience some additional volatility associated with fluctuations in crude oil prices until the underlying transactions are settled or offset.
•
Power Purchase Agreements-In our Liquids segment, we use forward physical power agreements to fix the price of a portion of the power consumed by our pumping stations in the transportation of crude oil in our owned pipelines. We designate these derivative agreements as non-qualifying hedges because they fail to meet the criteria for cash flow hedging or the NPNS exception. As various states in which our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.
Except for physical power, in all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or market basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at historical cost) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated. Relating to the power purchase agreements, commodity power purchases are immediately consumed as part of pipeline operations and are subsequently recorded as actual power expenses each period.
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:
•
Natural Gas and Marketing segments commodity-based derivatives-“Cost of natural gas”
•
Liquids segment commodity-based derivatives-“Operating revenue” and “Power”
•
Corporate interest rate derivatives-“Interest expense”
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:
Derivative Positions
Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.
We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $42.7 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the years ended December 31, 2011 and 2010, unrealized commodity hedge losses of $6.9 million and gains of $1.6 million, respectively, were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $162.0 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at December 31, 2011, will be reclassified from AOCI to earnings during the next 12 months.
In connection with our issuance of the 2021 Notes in September 2011, we paid $18.8 million to settle treasury locks we entered to hedge the interest payments on a portion of these obligations through the maturity date of the 2021 Notes. The settlement amount is being amortized from AOCI to “Interest expense” over the respective 10-year term of the 2021 Notes.
In connection with our March 2010 issuance and sale of $500 million in principal amount of our 5.20% senior notes due March 15, 2020, which we refer to as the 2020 Notes, we paid $13.2 million to settle treasury locks we entered to hedge the interest payments on a portion of these obligations through the maturity date of the 2020 Notes. We also received $10.2 million to settle treasury locks associated with our September 2010 issuance and sale of $400 million in principal amount of our 5.50% senior notes due September 15, 2040, which we refer to as the 2040 Notes, that we entered to hedge the interest payments on a portion of the obligations through the maturity date of the 2040 Notes. Both the $13.2 million and $10.2 million settlement amounts are being amortized from AOCI to “Interest expense” over the respective 10- and 30-year terms of the 2020 and 2040 Notes.
The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
* As determined by nationally-recognized statistical ratings organizations.
As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also declined. When credit thresholds are met pursuant to the terms of our International Securities Dealers Association, or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We have included any cash collateral received in the balances listed above. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.
The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.
The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties
are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.
At December 31, 2011, we were in an overall net liability position of $254.5 million, which included assets of $33.2 million. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet 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 amount of $63.9 million.
At December 31, 2011 and 2010, we had credit concentrations in the following industry sectors, as presented below:
We are holding no cash collateral on our asset exposures, and we have provided letters of credit totaling $173.2 million and $7.3 million relating to our liability exposures pursuant to the margin thresholds in effect at December 31, 2011 and 2010, respectively, under our ISDA® agreements.
Item 8.
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS,
SUPPLEMENTARY INFORMATION AND
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
ENBRIDGE ENERGY PARTNERS, L.P.
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules not included in this report have been omitted because they are not applicable or the required information is either immaterial or shown in the consolidated financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
To the Partners of Enbridge Energy Partners, L.P.:
In our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, of comprehensive income, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of Enbridge Energy Partners, L.P. and its subsidiaries (the “Partnership”) at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the control environment at and monitoring of the Partnership’s wholly owned trucking and NGL marketing subsidiary, existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2011 consolidated financial statements, and our opinion regarding the effectiveness of the Partnership’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management’s report referred to above. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/S/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 13, 2012
ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
The accompanying notes are an integral part of these consolidated financial statements.
ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
The accompanying notes are an integral part of these consolidated financial statements.
ENBRIDGE ENERGY PARTNERS, L.P.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS
General
Enbridge Energy Partners, L.P., together with its consolidated subsidiaries, which are referred to herein as “we,” “us,” “our,” and the “Partnership,” is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets, along with natural gas gathering, treating, processing, transmission 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.”
We were formed in 1991 by Enbridge Energy Company, Inc., our General Partner, which is an indirect, wholly-owned subsidiary of Enbridge Inc., a leading energy transportation and distribution company located in Calgary, Alberta, Canada, which we refer to as Enbridge. We were formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, or the OLP, which owns 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.
We are a geographically and operationally diversified organization, providing crude oil gathering, transportation and storage services, and natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Mid-Continent regions of the United States. We hold our assets in a series of limited liability companies and limited partnerships that we own either directly or indirectly.
Our capital accounts consist of general partner interests and limited partner interests. Our limited partner interests include Class A and Class B common units and i-units, which we collectively refer to as the limited partner units. In October 2009, all of our then outstanding Class C units were converted on a one-for-one basis into Class A common units. At December 31, 2011 and 2010, our ownership interests were distributed as follows:
(1) At December 31,2011 and 2010, our General Partner owned 16.8% and 17.2%, respectively, of Enbridge Management, which owns all of our i-units.
In July 2009, the OLP amended and restated its limited partnership agreement to establish two series of partnership interests, the Series AC and Series LH interests. The two distinct series of partnership interests were created to facilitate the financing and funding of construction costs for the United States segment of the Alberta Clipper crude oil pipeline, which we refer to as the Alberta Clipper Pipeline. All assets, liabilities and operations related to the Alberta Clipper Pipeline are designated by the Series AC interests, while all other operations are captured by the Series LH interests. Our General Partner holds a 66.67 percent interest in the Series AC limited partner interest, while we hold a 33.329 percent direct Series AC limited partner interest and a 0.001 percent indirect Series AC general partner interest. We hold a 99.999 percent direct Series LH limited partner interest and a 0.001 percent indirect Series LH general partner interest.
Enbridge Energy Management, L.L.C.
Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed in May 2002. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of its directors. Enbridge Management’s listed shares are traded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of a special class of our limited partner interests that we refer to as “i-units” and derives all of its earnings from its investment in us.
Enbridge Management’s principal activity is managing our business and affairs pursuant to a delegation of control agreement among our General Partner, Enbridge Management and us. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend our partnership agreement, allow a merger or consolidation involving us, allow a sale or exchange of all or substantially all of our assets or dissolve or liquidate us without the approval of our General Partner. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being our limited partner and managing our business and affairs.
Enbridge Inc.
Enbridge is the indirect parent of our General Partner and its common shares are publicly traded on the NYSE in the United States and the Toronto Stock Exchange in Canada under the symbol “ENB.” Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines and natural gas distribution. At December 31, 2011 and 2010, Enbridge and its consolidated subsidiaries held an effective 23.0 percent and 25.5 percent ownership interest in us, respectively, through its ownership in Enbridge Management and our General Partner.
Business Segments
We conduct our business through three operating segments: Liquids, Natural Gas and Marketing.
Liquids
Our Liquids segment includes the Lakehead, North Dakota and the Mid-Continent crude oil systems. Our Lakehead system consists of a series of interstate common carrier crude oil and liquid petroleum pipelines that are regulated by the Federal Energy Regulatory Commission, the FERC, and storage assets, all of which are located in the Great Lakes and Midwest regions of the United States. Our Lakehead system, together with the Enbridge system in Canada owned by Enbridge, forms the longest liquid petroleum pipeline in the world. The Lakehead system, which spans approximately 1,900 miles and includes approximately 5,100 miles of pipe, has been in operation for more than 60 years and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States. The Lakehead system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada. Our North Dakota system includes approximately 240 miles of crude oil gathering lines with proximity to the Bakken formation of the Williston Basin, which are connected to an interstate transportation line that is approximately 730 miles long and is regulated by the FERC. The North Dakota system connects directly into the Lakehead system in the state of Minnesota. Our Mid-Continent system consists of over 430 miles of active crude oil pipelines, including the FERC-regulated Ozark pipeline and approximately 17.6 million barrels of storage capacity, which serve refineries in the United States Mid-Continent region from Cushing, Oklahoma.
Natural Gas
Our Natural Gas segment consists of natural gas gathering and transmission pipelines, treating and processing plants and related facilities, predominantly located in active producing basins in east and north Texas, as well as the Texas panhandle and western Oklahoma. At December 31, 2011, our Natural Gas segment, including the Elk City Natural Gas Gathering and Processing system, referred to as the Elk City system, which we acquired in September 2010, is comprised of 9 natural gas treating plants and 25 natural gas processing plants, excluding plants that are inactive and including plants we temporarily idle from time to time based on current volumes. In addition, our Natural Gas segment includes approximately 11,500 miles of natural gas gathering and transmission pipelines, as well as trucks, trailers and rail cars used for transporting natural gas liquids, or NGLs, crude oil and carbon dioxide. For a discussion of our Elk City system, see Note 3. Acquisitions and Dispositions.
Marketing
Our Marketing segment primarily provides natural gas supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines as well as other interconnected natural gas pipeline systems. We primarily undertake marketing activities to increase the utilization of our natural gas pipelines, realize incremental income on gas purchased at the wellhead and provide value-added services to customers.
Our Marketing business purchases third-party pipeline transportation capacity, which provides us and our customers with access to natural gas markets that might not be directly accessible from our existing natural gas pipelines. Our Marketing business also purchases third-party storage capacity, which permits us to inject and store natural gas over various periods of time for withdrawal as these products become needed by end users of natural gas. These contracts may be denoted as firm transportation, interruptible transportation, firm storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with our natural gas purchase and sale contracts and to provide us with opportunities to competitively market natural gas products.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Use of Estimates
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.
We have presented the operating results of the natural gas pipeline assets we sold in November 2009 as “Discontinued operations” in our consolidated statements of income for the year ended December 31, 2009.
Comparative Amounts
We have made reclassifications to the amounts reported in our consolidated statement of financial position, consolidated statements of cash flows, and consolidated statements of income as of December 31, 2009 to conform to our current year presentation. We reclassified $4.9 million from “Other” to “Environmental costs” in our consolidated statements of cash flows for the year ended December 31, 2009. In 2009, we also reclassified
$2.2 million and $7.3 million from “Accounts payable and other” to “Environmental liabilities” in our consolidated statements of cash flows and consolidated statements of financial position, respectfully. Additionally, we made reclassifications of $2.4 million from “Operating and administrative” to “Environmental costs, net of recoveries” in our consolidated statements of income for the year ended December 31, 2009.
Further, we have made reclassifications to the amounts reported in our consolidated statements of income of $5.6 million and $1.3 million, for oil measurement losses from “Operating and administrative” to “Oil measurement adjustments” for the years ended December 31, 2010 and 2009, respectfully.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our wholly and majority-owned subsidiaries on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. We consolidate the accounts of entities over which we have a controlling financial interest through our ownership of the general partner or the majority voting interests in the entity. Ownership interests in our subsidiaries represented by other parties that do not control the entity are presented in our consolidated financial statements as activities and balances attributable to the noncontrolling interest.
Accounting for Regulated Operations
Our interstate liquids pipelines are subject to regulation by the FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates, underlying accounting practices and ratemaking agreements with customers.
The recovery of construction, operating and other costs associated with portions of our Lakehead system are subject to the authoritative accounting provisions applicable to regulated operations. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities.
Allowance for Funds Used During Construction
During the construction of our pipelines that qualify for regulated accounting, we are allowed to capitalize costs that represent the estimated debt and equity costs of capital necessary to finance the construction of our pipelines. The debt and equity costs, referred to collectively as Allowance for Funds Used During Construction, or AFUDC, are capitalized as part of the costs of pipeline construction in “Property, plant and equipment” in our consolidated statements of financial position. The equity return component and interest costs related to the AFUDC are credited to “Other income” and “Interest expense,” respectively, on our consolidated statements of income. Entities that do not qualify for regulated accounting, are only allowed to capitalize interest costs related to its construction activities, while a component for equity is prohibited.
Deferred Return
Under our cost-of-service tolling methodology, we calculate tolls based on forecast volumes and costs. A difference between forecast and actual results causes an under or over collection of revenue in any given year. Under the authoritative accounting provisions applicable to our regulated operations, over or under collections of revenue are recognized in the financial statements currently and these amounts are realized or settled as cash the following year. This accounting model matches earnings to the period with which they relate and conforms to how we recover our costs associated with expansion projects through the annual cost-of-service filings with our customers and the regulator.
Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas
Liquids
Revenues of our Liquids segment are primarily derived from two sources, interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC and contract storage revenues related to our crude oil storage assets. The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for transportation services we provide between receipt and delivery locations and the general terms and conditions of transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectability is reasonably assured. We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on storage volumes. We recognize revenues as storage services are rendered, when pricing is determinable and collectability is reasonably assured. In our Liquids segment, we generally do not own the crude oil and liquid petroleum that we transport or store, and therefore, we do not assume significant direct commodity price risk.
Natural Gas
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:
Fee-Based 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 business that are derived from transmission services consist of reservation and commodity 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.
Other Arrangements
We also use other types of arrangements to derive revenues for our Natural Gas business. 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 with the objective of maintaining stable cash flows. We provide additional information in Note 16. Derivative Financial Instruments and Hedging Activities 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:
•
Percentage-of-Proceeds Contracts-Under these contracts, we receive a negotiated percentage of the natural gas and NGLs we process in the form of residue natural gas, NGLs, condensate and sulfur, which we then sell at market prices and retain as our fee.
•
Percentage-of-Liquids Contracts-Under these contracts, we receive a negotiated percentage of NGLs extracted from natural gas that requires processing, which we then sell at market prices and retain as our fee. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs.
•
Percentage-of-Index Contracts-Under these contracts, we purchase raw natural gas at a negotiated discount to an agreed upon index price. We then resell the natural gas, generally for the index price, keeping the difference as our fee.
•
Keep-Whole Contracts-Under these contracts, we gather or purchase raw natural gas from the producer for processing. A portion of the gathered or purchased natural gas is consumed during processing. We extract and retain the NGLs produced during processing for our own account, which we sell at market prices. In instances where we purchase raw natural gas at the wellhead, we also sell for our own account at market prices, the resulting residue gas. In those instances when we gather and process raw natural gas for the account of the producer, we must return to the producer residue natural gas with an energy content equivalent to the original raw natural gas we received as measured in British thermal units, or Btu.
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. In order to protect our unitholders from volatility in our cash flows that can result from fluctuations in commodity prices, we enter into derivative financial instruments to effectively fix the sales price of the natural gas and NGLs we anticipate receiving under the terms of these contracts. As a result of entering into these derivative financial instruments, we have largely fixed the amount of cash that we will receive in the future when we sell the processed natural gas and NGLs, although the market price of these commodities will continue to fluctuate during that time.
Marketing
Revenues of our Marketing segment are derived from providing supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to realize incremental revenues on natural gas purchased at the wellhead, and to provide other services valued by our customers. In general, natural gas purchased and sold by our Marketing business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated revenues result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At the request of some customers, we will enter into long-term fixed price purchase or sales contracts with our customers and usually will enter into offsetting positions under the same or similar terms. We recognize revenues upon delivery of natural gas to our customers, when services are rendered, pricing is determinable and collectability is reasonably assured.
Estimation of Revenue and Cost of Natural Gas
For our natural gas and marketing businesses, we must estimate our current month revenue and cost of gas to permit the timely preparation of our consolidated financial statements. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and cost of natural gas based on the best available volume and price data for natural gas delivered and received, along with a true-up of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and cost of natural gas for each of the years ended December 31, 2011, 2010 and 2009. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.
Cash and Cash Equivalents
Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have issued check payments that have not been presented to the financial institution are included in “Accounts payable and other” on our consolidated statements of financial position.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.
Inventory
Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost, as determined on a weighted average basis, or market value. Our product inventory consists of liquid hydrocarbons and natural gas. Upon disposition, product inventory is recorded to “Cost of natural gas” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.
Materials and supplies inventory is either used during operations and charged to “Operating expense” as incurred, or used for capital projects and new construction, and capitalized to “Property, plant and equipment.”
Oil Measurement Adjustments
Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include:
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Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;
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Degradation resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and
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Revaluation, which are a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers.
Quantifying oil measurement adjustments are difficult because: (1) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (2) the extensive length of our pipeline systems and (3) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined.
Operational Balancing Agreements and Natural Gas Imbalances
To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash
payments or repaid in-kind through the receipt or delivery of natural gas in the future. Natural gas imbalances are recorded as “Accrued receivables” and “Accrued purchases” on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average cost of natural gas.
Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment
We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the authoritative accounting provisions applicable to regulated operations, an equity return component.
We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment that are worn, obsolete or near the end of their useful lives. Examples of core maintenance expenditures include valve automation programs, cathodic protection, zero-hour compression overhauls and electrical switchgear replacement programs. Enhancement expenditures 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. Examples of enhancement expenditures include costs associated with installation of seals, liners and other equipment to reduce the risk of environmental contamination from crude oil storage tanks, costs of sleeving a major segment of a pipeline system following an integrity tool run, natural gas or crude oil well-connects, natural gas plants and pipeline construction and expansion. We also began including a portion of our capital expenditures for well-connects associated with our Natural Gas system assets as core maintenance expenditures beginning in 2009.
Regulatory guidance issued by the FERC requires us to expense certain costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation’s Office of Pipeline Safety. Under this guidance, costs to (1) prepare a plan to implement the program; (2) identify high consequence areas; (3) develop and maintain a record keeping system and (4) inspect, test and report on the condition of affected pipeline segments to determine the need for repairs or replacements, are required to be expensed. Costs of modifying pipelines to permit in-line inspections, certain costs associated with developing or enhancing computer software and costs associated with remedial mitigation actions to correct an identified condition continue to be capitalized. We typically expense the cost of initial in-line inspection programs, crack detection tool runs and hydrostatic testing costs conducted for the purposes of detecting manufacturing or construction defects consistent with industry practice and the regulatory guidance issued by the FERC. However, we capitalize initial construction hydrostatic testing costs and subsequent hydrostatic testing programs conducted for the purpose of increasing pipeline capacity in accordance with our capitalization policies. Also capitalized are certain costs such as sleeving or recoating existing pipelines, unless the expenditures are incurred as a single event and not part of a major program, in which case we expense these costs as incurred.
We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.
We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.
We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.
Assessment of Recoverability of Goodwill
Goodwill represents the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is allocated to two of our segments, Natural Gas and Marketing.
Pursuant to the authoritative accounting provisions for goodwill and other intangible assets, we do not amortize goodwill, but test it for impairment annually based on carrying values as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. In testing goodwill for impairment, we make critical assumptions that include but are not limited to: (1) projections of future financial performance, which include commodity price and volume assumptions, (2) the expected growth rate of our Natural Gas and Marketing assets, (3) residual values of the assets and (4) market weighted average cost of capital. Impairment occurs when the carrying amount of a reporting unit’s goodwill exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.
Assessment of Recoverability of Intangibles
Our intangible assets consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.
We evaluate the carrying value of our intangible assets whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of
intangibles, we compare the carrying value to the undiscounted future cash flows we expect the intangibles or the underlying assets to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangibles and its carrying amount exceeds its fair value, we write the intangibles down to their fair value.
Fair Value Measurements
We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.
We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:
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Level 1-We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.
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Level 2-We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument, as Level 2. This category includes both over-the-counter, or OTC, transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
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Level 3-We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources. (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include debt and derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods.
The approximate fair values of our long-term debt obligations are determined using a standard methodology that incorporates pricing points that are obtained from independent third party investment dealers who actively make markets in our debt securities, which we use to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding.
We utilize a mid-market pricing convention, or the “market approach,” for valuation as a practical expedient for assigning fair value to our derivative assets and liabilities. Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation, and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities. We present the fair value of our derivative contracts net of cash paid or received pursuant to collateral agreements on a net-by-counterparty basis in our consolidated statements of financial position when we believe a legal right of setoff exists under an enforceable master netting agreement. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
Income Taxes
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 generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the States of Texas and Michigan. The Texas tax is computed on our modified gross margin. The Michigan tax consists of two different taxes that are based on net income and modified gross receipts. We have determined these taxes to be income taxes as set forth in the authoritative accounting guidance.
We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted.
Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.
Derivative Financial Instruments
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas we purchase for processing. In order to manage the risks to unitholders, we use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity or interest rate exposures. We do not have any material exposure to movements in foreign exchange rates as virtually all of our revenues and expenses are denominated in United States dollars. To the extent that a material foreign exchange exposure arises, we intend to hedge such exposure using derivative financial instruments. In accordance with the authoritative accounting guidance, we record all derivative financial instruments to our consolidated statements of financial position at fair market value. We record the fair market value of our derivative financial instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a net basis by counterparty. Derivative balances are shown net of cash collateral received or posted where master netting agreements exist. For those instruments that qualify for hedge accounting under authoritative accounting guidance, the accounting treatment is dependent on the intended use and designation of each instrument. 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:
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Natural Gas and Marketing segments commodity-based derivatives-“Cost of natural gas”
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Liquids segment commodity-based derivatives-“Operating revenue” and “Power”
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Corporate interest rate derivatives-“Interest expense”
Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Enbridge Management or a committee of senior management of our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.
Derivative financial instruments qualifying for hedge accounting treatment that we use are cash flow hedges. We enter into cash flow hedges to reduce the variability in cash flows related to forecasted transactions.
Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
We record the changes in fair value of derivative financial instruments designated and qualifying as effective cash flow hedges as a component of “Accumulated other comprehensive income” until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized immediately in earnings.
Our earnings are also affected by use of the mark-to-market method of accounting as required under GAAP for derivative financial instruments that do not qualify for hedge accounting. We use derivative financial instruments such as basis swaps and other similar derivative financial instruments to economically hedge market price risks associated with inventories, firm commitments and certain anticipated transactions. However, these derivative financial instruments do not qualify for hedge accounting treatment under authoritative accounting guidance, and as a result we record changes in the fair value of these instruments on the statement of financial position and through earnings rather than deferring them until the firm commitment or anticipated transactions affect earnings. The use of mark-to-market accounting for derivative financial instruments can cause non-cash earnings volatility resulting from changes in the underlying indices, primarily commodity prices.
Commitments, Contingencies and Environmental Liabilities
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Environmental liabilities” and “Other long-term liabilities” in our consolidated statements of
financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities 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 evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
Asset Retirement Obligations
Legal obligations exist for a minority of our onshore right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods.
We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.
We recorded an additional ARO of $0.4 million for the year ended 2010, when we removed from service the West Tulsa pipeline on our Mid-Continent system. For the years ended December 31, 2011 and December 31, 2009, no additional AROs were recorded. We recorded accretion expense of $0.1 million, $0.5 million and $0.3 million, respectively, in our consolidated statements of income for the years ended December 31, 2011, 2010 and 2009 for previously recorded asset retirement obligation liabilities.
We do not have any assets that are legally restricted for purposes of settling our ARO at December 31, 2011 and 2010. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the years ended December 31, 2011 and 2010:
(1) Represents revaluations made to existing AROs for the year ended 2010.
3. ACQUISITIONS AND DISPOSITIONS
The acquisitions and dispositions presented below include only transactions with unrelated third-parties. We also executed transactions with related parties, which we discuss in Note 12. Related Party Transactions. We accounted for each of our completed acquisitions using the acquisition method and recorded the identifiable assets acquired and liabilities assumed at their acquisition-date fair values. We have included the results of operations from each of these acquisitions in our operating results from the acquisition date.
2011 Acquisitions
In May 2011, we acquired natural gas pipeline assets for a final purchase price of $26.7 million in cash that are complementary to our existing East Texas system assets and planned expansion into the South Haynesville area.
2010 Acquisitions
Elk City System Acquisition
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. We used the net proceeds from the $400.0 million September 2010 issuance and sale of our 5.50% senior notes due September 15, 2040 to pay for a portion of the acquisition and funded the remaining amount with short-term borrowings of commercial paper, which we subsequently repaid with proceeds from our November 2010 equity issuance. 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 final purchase price to the assets acquired and the liabilities assumed, based on their fair values:
Other 2010 Acquisitions
In June 2010, we acquired natural gas pipeline assets for $16.9 million in cash that are complementary to our existing East Texas system assets and planned expansion into the South Haynesville area. In October 2010, we acquired a common carrier trucking company for $10.3 million in cash that expanded our existing trucking fleet in order to accommodate the growing supply needs of our United States Gulf Coast customers. Both acquisitions were allocated to “Property, plant and equipment” and “Intangibles” in our consolidated statement of financial position at fair value.
2009 Disposition
Natural Gas Pipeline Disposition
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:
4. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST
In February 2011, the board of directors of Enbridge Energy Management, L.L.C., or Enbridge Management, as delegate of our General Partner, approved a split of our units, which was effected by a distribution on April 21, 2011 of one common unit for each common unit outstanding and one i-unit for each i-unit outstanding to unitholders of record on April 7, 2011. As a result of this unit split, we have retrospectively restated the computation of our “Net income per limited partner unit (basic and diluted)” in the table below and restated the number of units in our consolidated statements of financial position to present the prior year amounts on a split-adjusted basis. Additionally, the formula for distributing available cash among our General Partner and limited partners was revised to reflect this unit split, as set forth in our partnership agreement, as amended, and is presented below.
We allocate our net income among our General Partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income, including any incentive distribution rights, or IDRs, embedded in the general partner interest, to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We also allocate any earnings in excess of distributions to our General Partner and limited partners utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners based on their sharing of losses of 2 percent and 98 percent, respectively, as set forth in our partnership agreement.
We determined basic and diluted net income (loss) per limited partner unit as follows:
(1) Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.
(2) Represents the limited partners’ share (98 percent) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and under distributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.
5. CASH AND CASH EQUIVALENTS
Obligations for which we have made payments that have not yet been presented to the financial institution totaling approximately $30.8 million at December 31, 2011 and $28.9 million at December 31, 2010 are included in “Accounts payable and other” on our consolidated statements of financial position.
6. INVENTORY
Our inventory is comprised of the following:
The “Cost of natural gas” on our consolidated statements of income includes charges totaling $3.6 million, $4.1 million and $3.6 million for the years ended December 31, 2011, 2010 and 2009, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and natural gas liquids, or NGLs, to reflect the current market value.
7. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment is comprised of the following:
Based on our own internal study, with consideration of a third-party consultant’s report, revised depreciation rates for our Anadarko, North Texas and East Texas natural gas systems were implemented effective July 1, 2011. The average remaining service life of these natural gas systems was extended from 29 years to 36 years. The predominant factor contributing to the change in service lives was an increase in the estimated remaining reserves in the regions our natural gas systems serve, due to enhancements in fracturing technologies which will allow producers to have greater access to unconventional gas. The new remaining service lives will result in an approximately $34 million annual reduction in depreciation expense in future years, with a reduction of $17 million for the year ended December 31, 2011.
In September 2010, our West Tulsa crude oil pipeline was removed from service and as a result we recognized a $10.3 million impairment charge to reduce the carrying amount of the asset to zero.
8. GOODWILL
In November 2009, we sold non-core natural gas pipeline assets to an unrelated third party. In connection with the sale, we disposed of $9.8 million of goodwill associated with those operations, which we had previously impaired. For each of the years ended December 31, 2011, 2010 and 2009, the carrying amount of goodwill was $246.7 million consisting of $226.3 million and $20.4 million related to our natural gas and marketing businesses, respectively.
We test our goodwill for impairment annually primarily by using a discounted cash flow analysis. In addition, we also consider overall market capitalization of our business, cash flow measurement data and other factors. We completed our annual goodwill impairment test using amounts as of June 30, 2011, which did not indicate the existence of impairment to goodwill associated with any of our reporting units. Even if our estimate for the fair value of our assets had been reduced by ten percent in our June 30, 2011 impairment testing, no impairment charge would have resulted. The critical assumptions used in our analysis included the following:
1) A weighted average cost of capital from 8% to 9%;
2) An annual growth rate for our Natural gas and Marketing businesses of approximately 1.0% to 3.0%;
3) A capital structure consisting of approximately 40% debt and 60% equity; and
4) A long-term commodity price forecast using recent pricing information.
We did not identify or recognize any impairments to goodwill in connection with our annual testing of goodwill for impairment during the years ended December 31, 2011, 2010 and 2009. We have not observed any further events or circumstances subsequent to our analysis that would, more likely than not, reduce the fair value of our reporting units below the carrying amounts as of December 31, 2011.
9. INTANGIBLES
The following table provides the gross carrying value, accumulated amortization and activity affecting amounts comprising each of our major classes of intangible assets.
Natural gas intangibles include customer contracts and natural gas supply opportunities. Our customer contracts are comprised entirely of natural gas purchase and sale agreements associated with our Natural Gas and Marketing segments. We amortize our customer contracts on a straight-line basis over the weighted average useful life of the underlying reserves at the time of acquisition, which approximate 25 years.
We obtained a portion of the natural gas supply opportunities in conjunction with the 2003 North Texas system acquisition. We obtained an additional $189.2 million of natural gas supply opportunities in connection with our September 2010 acquisition of the Elk City system. The value of these intangible assets is derived from growth opportunities present in the Barnett Shale producing zone of North Texas and the Granite Wash reservoir of the Anadarko basin in western Oklahoma and the Texas Panhandle. The natural gas supply opportunities relate entirely to our Natural Gas segment. We are amortizing the natural gas supply opportunities on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of the acquisition, which approximate 25 to 30 years.
Our other intangible assets are comprised of contributions we made in aid of construction for our Natural Gas and Liquids businesses. We made contributions to third parties for construction of electrical infrastructure to provide utility services for our Lakehead system and for interconnections between our natural gas systems and third-party pipelines and the related measurement equipment. In connection with our October 2010 acquisition of a common carrier trucking company, we recognized $4.4 million of additional intangibles related to workforce contracts and customer relationships. We amortize our workforce contracts on a straight line basis over 3 years. We amortize customer relationships over the weighted average estimated useful life of the underlying reserves, which approximate 10 years.
In connection with our November 2009 sale of natural gas pipeline assets, we disposed of $1.6 million of intangibles associated with these operations, which we had previously impaired, primarily representing the value of customer contracts.
We estimate the aggregate amortization expense associated with our intangibles for each of the five succeeding years through December 31, 2016 to approximate $11.3 million per year.
10. DEBT
The following table presents the primary components of our outstanding indebtedness with third parties and the weighted average interest rates associated with each component at the end of each period presented, before the effect of our interest rate hedging activities as discussed in, Note 16. Derivative Financial Instruments and Hedging Activities. Our indebtedness with related parties is discussed in Note 12. Related Party Transactions.
(1) Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our New Credit Facility and are therefore considered long-term debt.
First Mortgage Notes
The First Mortgage Notes, or the Notes, were collateralized by a first mortgage lien on substantially all of the property, plant and equipment of the OLP, and were due and payable in equal annual installments of $31.0 million until their maturity. The Notes reached maturity and were repaid in full on December 15, 2011, at which time the related liens were released.
Credit Facility
In September 2011, we entered into a new credit agreement with a syndicate of lenders, of which Bank of America is administrative agent, and the lenders party thereto, which we refer to as the New Credit Facility. The new agreement 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.
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. At December 31, 2011, we were in compliance with the terms of our financial covenants.
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. Our current policy is 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.
Commercial Paper
We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper that is supported by our New Credit Facility. Our commercial paper program was increased from $1.0 billion in August 2011. We access the commercial paper market 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. 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. At December 31, 2010, we had $884.9 of commercial paper outstanding at a weighted average interest rate of 0.44%, excluding the effect of our interest rate hedging activities. Our policy is that the commercial paper we can issue is limited by the amounts available under our New Credit Facility.
We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our New Credit Facility. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.
Senior Notes
All of our outstanding senior notes pay interest semi-annually and have varying maturities and terms as presented in the table below. The senior notes do not contain any covenants restricting the issuance of additional indebtedness and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. The holders of our $500 million in aggregate principal amount, 9.875% senior notes due 2019 did not notify us by the established 45-day notification date of their intent to exercise an option that would have required us to repurchase all or a portion of the notes on March 1, 2012 at a purchase price of 100 percent of the principal amount of the notes tendered plus accrued and unpaid interest.
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 notes offerings in September 2011 of approximately $740.7 million after payment of underwriting discounts and commissions and 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.
Junior Subordinated Notes
The $400 million in principal amount of our fixed/floating rate, junior subordinated notes due 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. We issued the Junior Notes in September 2007 for proceeds of approximately $393 million net of underwriting discounts, commissions and offering expenses. The Junior Notes bear interest at a fixed annual rate of 8.05 percent, exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year until October 1, 2017. After October 1, 2017, the Junior Notes will bear interest at a variable rate equal to the three-month LIBOR for the related interest period increased by 3.7975 percent, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. We may elect to defer interest payments on the Junior Notes for up to ten consecutive years on one or more occasions, but not beyond the final repayment date. Until paid, any interest we elect to defer will bear interest at the prevailing interest rate, compounded semi-annually during the period the Junior Notes bear interest at the fixed annual rate and quarterly during the period that the Junior Notes bear interest at a variable annual rate.
The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make cash distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes.
The scheduled maturity date for the Junior Notes is initially October 1, 2037, but we may extend the maturity date up to two times, on October 1, 2017 and October 1, 2027, in each case for an additional ten-year period. As a result, the scheduled maturity date may be extended to October 1, 2047 or October 1, 2057. Our obligation to repay the Junior Notes on the scheduled maturity date is limited by an agreement we refer to as the Replacement Capital Covenant, which we entered into in connection with our offering of the Junior Notes, but not as part of the Junior Notes. The Replacement Capital Covenant limits the types of financing sources we can use to repay the Junior Notes. We are required to repay the Junior Notes on the scheduled maturity date only to the extent the principal amount repaid does not exceed proceeds we have received from the issuance and sale of securities, that, among other attributes defined in the Replacement Capital Covenant, have characteristics that are the same or more equity-like than the Junior Notes. We refer to the securities that meet this characterization as qualifying capital securities. If we do not receive sufficient proceeds from the sale of qualifying capital securities to repay the Junior Notes by the scheduled maturity date, we must use our commercially reasonable efforts to raise sufficient proceeds from the sale of qualifying capital securities to permit repayment of the Junior Notes on the following quarterly interest payment date, and on each subsequent quarterly interest payment date until the Junior Notes are paid in full. Regardless of the amount of qualifying capital securities that we have issued and sold, the final repayment date is initially October 1, 2067. We may extend the final repayment date for an additional ten-year period on October 1, 2017, and as a result the final repayment date may be extended to October 1, 2077. We may extend the scheduled maturity date whether or not we also extend the final repayment date, and we may extend the final repayment date whether or not we extend the scheduled maturity date.
We may redeem the Junior Notes in whole at any time, or in part, prior to October 1, 2017, for a “make-whole” redemption price, and thereafter at a redemption price equal to the principal amount plus accrued and unpaid interest on the Junior Notes. We may also redeem the Junior Notes prior to October 1, 2017 in whole, but not in part, upon the occurrence of certain tax or rating agency events at specified redemption prices. Our right to optionally redeem the Junior Notes is also limited by the Replacement Capital Covenant, which limits the types of financing sources we can use to redeem the Junior Notes in the same manner as to repay the Junior Notes, as discussed in the above paragraph.
Zero Coupon Senior Notes
In August 2009, we repaid the holder of our senior, unsecured zero coupon notes due 2022, the full amount of the outstanding balance of approximately $222.3 million. The amount repaid includes $22.3 million of interest that we added to the original $200 million of principal of the zero coupon notes, including approximately $7.6 million of interest that we added during the year ended December 31, 2009.
364-day Credit Facilities
In April 2009, we entered into two unsecured and non-guaranteed revolving credit facility agreements totaling $350 million for funding our general activities and working capital, which we refer to as the 364-day Credit Facilities. The 364-day Credit Facilities included a $200 million agreement with Barclays Bank PLC, as administrative agent, and Barclays Bank PLC and Export Development Canada as lenders. A separate $150 million affiliate credit agreement with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge, was also a component of the 364-day Credit Facilities. In December 2009, we terminated the 364-day Credit Facilities in accordance with the credit facility agreements and without penalty.
Interest
For the years ended December 31, 2011, 2010 and 2009 our interest cost is comprised of the following:
Maturities of Third Party Debt
The scheduled maturities of outstanding third party debt, excluding any discounts at December 31, 2011, are summarized as follows in millions:
Fair Value of Debt Obligations
The table below presents the carrying amounts and approximate fair values of our debt obligations. The carrying amounts of our outstanding commercial paper and borrowings under our New Credit Facility and prior credit facilities approximate their fair values at December 31, 2011 and 2010, respectively, due to the short-term nature and frequent repricing of these obligations. The fair value of our outstanding commercial paper,
borrowings under our New Credit Facility and our prior credit facilities and our Senior Notes due 2019 are included with our long-term debt obligations below since we have the ability to refinance the amounts on a long-term basis. The approximate fair values of our long-term debt obligations are determined using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding.
11. PARTNERS’ CAPITAL
Our capital accounts are comprised of a two percent general partner interest and 98 percent limited partner interests. Our limited partner interests at December 31, 2011 include Class A common units, Class B common units and i-units. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. We refer to our Class A common units and Class B common units collectively as common units. Our General Partner manages our operations, subject to a delegation of control agreement with Enbridge Management, and participates in our distributions, including certain incentive income distributions.
Split of Partnership Units
Effective April 21, 2011, the board of directors of Enbridge Management, as delegate of our General Partner, approved a two-for-one split of our common units and i-units outstanding to unitholders of record on April 7, 2011. The net income per share and weighted average shares outstanding for the years ended December 31, 2010 and 2009 presented in our consolidated statements of income and the number of units presented in our consolidated statements of financial position are presented reflecting the retroactive effects of the share split.
Class A common units
The following sections present the net proceeds from our Equity Distribution Agreements and Class A common unit issuances for each of the years ended December 31, 2011 and 2010. The proceeds from each of our offerings were generally used to repay issuances of commercial paper or amounts outstanding under our credit facilities, which we initially borrowed to finance our capital expansion projects and acquisitions, or to repay other outstanding obligations. Any proceeds we received in excess of amounts used to repay issuances of commercial paper and credit facility borrowings were temporarily invested for use in future periods to fund additional expenditures associated with our capital expansion projects.
Equity Distribution Agreement
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:
(1) Net of commissions and issuance costs of $2.2 million and $1.2 million for the years ended December 31, 2011 and 2010, respectively.
(2) Contributions made by the General Partner to maintain its two percent general partner interest.
(3) Units and unit price adjusted for the April 21, 2011 stock split.
(4) Units issued under the Amended EDA.
Issuance of Class A Common Units
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.
(1) Net of underwriters’ fees and discounts, commissions and issuance expenses if any.
(2) Contributions made by the General Partner to maintain its two percent general partner interest.
(3) The proceeds from the December 2011 and September 2011 offerings will be used to fund a portion of our capital expansion projects, while the proceeds from the July 2011 offering were used to repay a portion of our outstanding commercial paper and fund a portion of our capital expansion projects.
(4) The proceeds from the November 2010 equity issuance were used to repay short term indebtedness incurred to finance the Elk City system acquisition and capital expansion projects.
(5) All Class A common units from the October 2009 issuance were issued to our General Partner to facilitate the conversion of our Class C units.
(6) All amounts adjusted for the April 21, 2011 stock split.
In January 2011, we exchanged 50,650 Class A common units in connection with a land acquisition.
Class B common units
All of our outstanding Class B common units are held by our General Partner and have rights similar to our Class A common units except that they are not currently eligible for trading on the NYSE.
Class C units
In October 2009, the Class C units converted into Class A common units, on a one-for-one basis, resulting in the issuance of 42,666,546 Class A common units and a cash payment of $123.21 for the 5.216184 remaining fractional units. We effected the conversion of our outstanding Class C units into Class A common units in accordance with the terms of our partnership agreement. The conversion became effective upon the determination by our General Partner that the converted Class C units would have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of our outstanding Class A common units. Our General Partner made this determination after adjustments were made to the capital accounts of our limited partners in connection with the issuance of 42,490 Class A common units to our General Partner.
i-units
The i-units are a separate class of our limited partner interests, all of which are owned by Enbridge Management and are not publicly traded.
Enbridge Management, as the owner of our i-units, votes together with the holders of the common units as a single class. However, the i-units vote separately as a class on the following matters:
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Any proposed action that would cause us to be treated as a corporation for United States federal income tax purposes;
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Amendments to our partnership agreement that would have a material adverse effect on the holder of our i-units, unless, under our partnership agreement, the amendment could be made by our General Partner without a vote of holders of any class of units;
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The removal of our General Partner and the election of a successor general partner; and
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The transfer by our General Partner of its general partner interest to a non-affiliated person that requires a vote of holders of units under our partnership agreement and the admission of that person as a general partner.
In all cases, Enbridge Management will vote or refrain from voting its i-units in the same manner that owners of Enbridge Management’s shares vote or refrain from voting their shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as the i-units.
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. Subsequently, we also received contributions of $0.7 million from our General Partner to maintain its two percent general partner interest. 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.
Distributions
Our partnership agreement requires us to distribute 100 percent of our “available cash”, which is generally defined in our partnership agreement the sum of all cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. Enbridge Management, as delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.” Typically, our General Partner and owners of our common units will receive distributions in cash. We also retain reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and our General Partner and, as necessary, to comply with the terms of our agreements or obligations (including any reserves required under debt instruments for future principal and interest payments and for future capital expenditures). We make distributions to our partners approximately 45 days following the end of each calendar quarter in accordance with their respective percentage interests.
Our General Partner is granted discretion by our partnership agreement, which discretion has been delegated to Enbridge Management, subject to the approval of our General Partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future
cash requirements with which they can be associated. When Enbridge Management determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Distributions of our available cash are generally made 98 percent to holders of our limited partner units and two percent to our General Partner. However, distributions are subject to the payment of incentive distributions to our General Partner to the extent that certain target levels of distributions to the unitholders are achieved. The incentive distributions payable to our General Partner are 15 percent, 25 percent and 50 percent of all quarterly distributions of available cash that exceed target levels of $0.295, $0.35 and $0.495 per limited partner units, respectively. As set forth in our partnership agreement, we will not make cash distributions on our i-units, but instead, will distribute additional i-units such that the cash is retained and used in our operations and to finance a portion of our capital expansion projects.
Enbridge Management, as owner of the 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 preceding the ex-dividend date for Enbridge Management’s shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to our General Partner.
Through August 15, 2009, in lieu of cash distributions, the holders of our Class C units received quarterly distributions of additional Class C units with a value equal to the quarterly cash distributions we paid to the holders of our Class A and Class B common units. The number of additional Class C units we issued was determined by dividing the quarterly cash distribution per unit we paid on our common units by the average market price of a Class A common unit as listed on the NYSE for the 10 consecutive trading day period immediately preceding the ex-dividend date for our Class A common units multiplied by the number of Class C units outstanding on the record date. As a result, the number of Class C units and the percentage of our total units owned by holders of the Class C units was increased automatically under the provisions of our partnership agreement. The cash equivalent amount of the additional Class C units was treated as if it had actually been distributed for purposes of determining the distributions to be made to the General Partner. Following the October 2009 conversion of our Class C units into Class A common units, the in-kind distributions previously made to holders of the converted Class C units are now made in cash to them as holders of Class A common units.
Distribution to Partners
The following table sets forth our distributions, as approved by the board of directors of Enbridge Management, during the years ended December 31, 2011, 2010 and 2009.
(1) Distributions per unit for the distribution paid are presented retrospectively applying the two-for-one split of our units.
(2) We issued 2,420,228, 2,507,688 and 3,251,624 split adjusted i-units to Enbridge Management, the sole owner of our i-units, during 2011, 2010 and 2009, respectfully, in lieu of cash distributions.
(3) We issued 3,288,614 additional split adjusted Class C units to our Class C unitholders in lieu of cash distributions during 2009 including 1,077,218 split adjusted units to our General Partner.
(4) We retained an amount equal to two percent of the i-unit distribution from our General Partner to maintain its two percent general partner interest in us.
12. RELATED PARTY TRANSACTIONS
Administrative and Workforce Related Services
Enbridge and its affiliates provide management and administrative, operational and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.
We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. We obtain managerial, administrative and operational services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, Enbridge Management, and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse our General Partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.
Service Agreements
Our General Partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through an operational services agreement among Enbridge, Enbridge Operational Services, Inc., or EOSI, and Enbridge Pipelines, Inc., or EPI, both subsidiaries of Enbridge, all of whom we refer to as the Canadian service providers, and us, we are charged for the services of Enbridge employees resident in Canada. Through a general and administrative services agreement among us, our General Partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of our General Partner, which we refer to as EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “Operating and administrative” expenses on our consolidated statements of income.
Operational Services Agreement
We are charged an amount by the Canadian service providers for services we are provided under the operational services agreement. The amount we are charged is established as part of the annual budget and agreed upon by us and the Canadian service providers. The amount we are charged is computed based on an estimate of the pro-rata reimbursement of each Canadian service provider’s estimated annual departmental costs, net of amounts charged to other affiliates and amounts identifiable as costs of that Canadian service provider. The Canadian service providers charge us a monthly fixed fee that is computed as one-twelfth of the annual budgeted amount. Under the operational services agreement, our General Partner and Enbridge Management pay the Canadian service providers a monthly fee determined in the manner described above. At the request of Enbridge Management, the fee for these operational services provided to it in its capacity as the delegate of our General Partner are billed directly to us.
Enbridge Management and our General Partner may request that the Canadian service providers provide special additional operational services for which each, as appropriate, agrees to pay costs and expenses incurred by the Canadian service provider in connection with providing the special additional operational services. The types of services provided under the operational services agreement include:
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Executive, administrative and other services on an “as required” basis;
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Monitoring transportation capacity, scheduling shipments, standardizing integrity, maintenance and other operational requirements;
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Addressing regulatory matters associated with the liquids pipeline operations;
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Providing monthly measurement information, forecasts, oil accounting, invoicing and related services;
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Computer application development and support services, including liquid pipelines’ control center operations;
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Electrical power requirements and costs for system operations;
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Patrol and aircraft services; and
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Any other operational services required to operate existing systems and any additional systems acquired by us.
Each year, the Canadian service providers prepare annual budgets by departmental cost center for their respective operations. After establishing a budget for the following year, the costs associated with each department are allocated to us, our General Partner, Enbridge Management and other Enbridge affiliates using one of the following three methods:
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Capital assets employed as a percentage of Enbridge-wide capital assets;
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Time-based estimates; or
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Full-time-equivalent (FTE)/headcount as a percentage of Enbridge-wide FTEs.
The total amount we reimbursed the Canadian service providers pursuant to the operational services agreement for the years ended December 31, 2011, 2010 and 2009 was $97.3 million, $74.5 million and $63.4 million, respectively.
General and Administrative Services Agreement
We, Enbridge Management and our General Partner receive services from EES under the general and administrative services agreement. Under this agreement, EES provides services to us, Enbridge Management and our General Partner and charges each recipient for services, on a monthly basis, the actual costs that it incurs for those services. Our General Partner and Enbridge Management may request that EES provide special additional general services for which each, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:
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Accounting, tax planning and compliance services, including preparation of financial statements and income tax returns;
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Administrative, executive, legal, human resources and computer support services;
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Insurance coverage;
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All administrative and operational services required to operate existing systems and any additional systems acquired by us and operated by EES; and
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Facilitate the business and affairs of Enbridge Management and us, including, but not limited to, public and government affairs, engineering, environmental, finance, audit, operations and operational support, safety/compliance and other services.
EES captures all costs that it incurs for providing the services by cost center in its financial system. The cost centers are determined to be “Shared Service”, “Enbridge Energy Partners, L.P. only” or “Non-Enbridge Energy Partners, L.P.” Shared Service cost centers are used to capture costs that are not specific to a single United States Enbridge entity but are shared among multiple United States Enbridge entities. The costs captured in the cost centers that are specific to us are charged in full to us. The costs captured in cost centers that are outside of our business unit are charged to other Enbridge entities.
The general method used to allocate the Shared Service costs is established through the budgeting process and reimbursed as follows:
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Each cost center establishes a budget.
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Each cost center manager estimates the amount of time the department spends on us and entities that are not directly affiliated with us.
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Costs are accumulated monthly for each cost center.
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The actual costs accumulated monthly by each cost center are allocated to us or entities that are not directly affiliated with us based on the allocation model.
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We reimburse EES for its share of the allocated costs.
The total amount reimbursed by us for services received pursuant to the general and administrative services agreement for the years ended December 31, 2011, 2010 and 2009 was $264.3 million, $231.6 million and $225.8 million, respectively.
Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $24.9 million, $16.3 million and $10.0 million during 2011, 2010 and 2009, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
Line 6A and 6B Expense Reimbursement
For the years ended December 31, 2011 and 2010, we have reimbursed Enbridge $7.6 million and $14.9 million, respectively, for its assistance with the administration and clean-up efforts for our Line 6A and 6B crude oil releases. For further details related to our Line 6A and 6B crude oil releases, refer to Note 13. Commitments and Contingences-Lakehead Lines 6A and 6B crude oil releases.
Affiliate Revenues and Purchases
We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates. Included in our results for the twelve months ending December 31, 2011, 2010 and 2009, are operating revenues of $354.3 million, $430.4 million and $181.3 million, respectively, related to these transactions.
In 2007, we entered into an agreement with Enbridge Pipelines to install and operate certain sampling and related facilities for the purpose of improving the quality of crude oil and the transportation services on our Lakehead system, which directly increases the transportation services revenue of Enbridge Pipelines. As compensation for installing and operating these transportation facilities, Enbridge Pipelines makes annual payments to us on a cost of service basis. The income we recorded for providing these transportation services in 2011, 2010 and 2009 was approximately $0.8 million, $0.9 million and $0.8 million, respectively.
We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Included in our results for the twelve months ending December 31, 2011, 2010 and 2009, are costs for natural gas purchases of $200.8 million, $242.3 million and $53.6 million, respectively, related to these purchases.
Financing Transactions with Affiliates
EUS Credit Agreement
In December 2007, we entered into an unsecured revolving credit agreement, referred to as the EUS Credit Agreement, with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge, referred to as Enbridge U.S. The EUS Credit Agreement provided for a maximum principal amount of credit available to us at any one time of $500 million for a three-year term that was scheduled to mature in December 2010. In March 2010, we terminated our unsecured revolving credit agreement with Enbridge U.S. in accordance with the terms of the agreement and without penalty. At December 31, 2010, we had no balances outstanding under the EUS Credit Agreement.
Joint Funding Arrangement for Alberta Clipper Pipeline
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 Inc., or Enbridge. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010. In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement, a credit agreement between our General Partner and us to finance the Alberta Clipper Pipeline, 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 and is subordinate to all of our senior indebtedness. 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 Alberta Clipper Pipeline that our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement for any additional costs associated with our construction of the Alberta Clipper Pipeline that 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. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline. The approved terms for the Alberta Clipper Pipeline are described in the “Alberta Clipper United States Term Sheet,” which is included as Exhibit I to the June 27, 2008 Offer of Settlement filed with the Federal Energy Regulatory Commission, or FERC, by the OLP and approved on August 28, 2008 (Docket No. OR08-12-000).
A summary of the cash activity for the A1 Term Note for the years ended December 31, 2011, 2010 and 2009 are as follows:
The following table presents in millions, the scheduled maturities of the A1 Term Note based upon the $342.0 million outstanding at December 31, 2011.
Our General Partner also made equity contributions totaling $3.3 million, $102.3 million and $329.7 to the OLP during the years ended December 31, 2011, 2010 and 2009, respectively, to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline.
We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $53.2 million, $60.6 million and $11.4 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, 2010 and 2009, 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.
Distribution to Series AC Interests
The following table presents distributions paid by the OLP to our General Partner and its affiliate during the years ended December 31, 2011 and 2010, representing the noncontrolling interest in the Series AC and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests.
Asset Purchase and Sale Transactions with Affiliates
Line 13 Exchange and Lease
In connection with the development of a diluent pipeline being constructed by Enbridge Pipelines (Southern Lights), L.L.C., or Southern Lights, a wholly-owned subsidiary of our General Partner, we completed the transfer of a 156-mile section of pipeline, which we refer to as Line 13, from our Lakehead system to Southern Lights in exchange for a newly constructed pipeline for transporting light sour crude oil. In connection with the exchange, at the request of shippers and to ensure adequate southbound pipeline capacity prior to the completion of the Alberta Clipper Pipeline, we agreed to lease Line 13 from Southern Lights for monthly payments of $1.8 million. The transfer and lease which became effective February 20, 2009, expired in April 2010 in accordance with the lease. For the year ended December 31, 2010, we paid $5.4 million to Southern Lights to lease Line 13, which we recovered through the tariff that went into effect on April 1, 2010 on our Lakehead system.
The exchange resulted in a $166.5 million increase in “Property, plant and equipment” and the capital account of our General Partner included in “Partners’ capital” on our December 31, 2009 consolidated statement of financial position, representing the $171.5 million cost of the light sour pipeline that was in excess of the $5.0 million net book value of the Line 13 assets we exchanged. The costs were transferred to us through the capital account of our General Partner and are included in the $171.5 million. Further, $3.8 million of additional costs for the year ended December 31, 2010 were incurred and transferred by Southern Lights, which increased the total costs for the light sour crude oil pipeline at December 31, 2010 to $175.3 million. The light sour pipeline is newer and has a slightly higher capacity than Line 13, which will allow us to transport additional volumes of
light sour crude oil on our Lakehead system with less integrity and maintenance costs, although depreciation and property tax expense is anticipated to increase in future periods due to the higher book value associated with these assets.
Purchase of Line Pipe
In March 2009, we acquired, for $27.0 million, approximately 25 miles of 36-inch diameter line pipe from our General Partner. The purchase was for our use in constructing the Alberta Clipper crude oil pipeline project, referred to as the Alberta Clipper Project. The line pipe was initially obtained by our General Partner for use in constructing the Southern Access extension. The transaction was previously approved by the Enbridge Management Board of Directors.
General Partner Equity Transactions
Our General Partner owns an effective two percent general partner interest in us. Pursuant to our partnership agreement we paid cash distributions to our General Partner of $95.0 million, $69.8 million and $57.0 million for the years ended December 31, 2011, 2010, and 2009, respectively. The cash distributions we make to our General Partner exclude an amount equal to two percent of the i-units and until the conversion to Class A common units, Class C unit distributions, which we retain from the General Partner to maintain its two percent general partner interest in us.
As of December 31, 2011, our General Partner owned 46.5 million Class A common units, representing a 16.0 percent limited partner interest in us. We paid the General Partner cash distributions of $97.3 million for the year ended December 31, 2011, with respect to its ownership of Class A common units. In October 2009, we effected the conversion of all our outstanding Class C units into Class A common units in accordance with the terms of our partnership agreement. The conversion became effective upon the determination by our General Partner that the converted Class C units would have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of our outstanding Class A common units. Along with the conversion and adjusted for the 2011 split, we issued and sold 42,490 Class A common units to our General Partner for a purchase price of $23.535 per unit, or approximately $1.0 million.
As of December 31, 2011 and 2010, our General Partner also owned 7,825,500 Class B common units, representing a 2.7 percent and 3.0 percent limited partner interest in us for the respective years. We paid the General Partner cash distributions of $16.4 million, $15.8 million and $15.5 million for the years ended December 31, 2011, 2010, and 2009, respectively, with respect to its ownership of Class B common units.
As a result of the October 2009 conversion of all our outstanding Class C units into Class A common units, we did not have any Class C units outstanding at December 31, 2011 and 2010. Refer to Note 11. Partners’ Capital for additional information regarding the Class C units.
The following table presents our issuances of limited partner interests where our General Partner made a contribution to retain its two percent general partner interest:
(1) Limited partnership issuances under the EDA for the periods indicated.
(2) The offering price per unit listed for the EDA issuances is a calculated average unit price for the periods indicated.
(3) Net of underwriters’ fees and discounts, commissions and issuance expenses.
(4) All amounts adjusted for April 2011 stock split.
(5) Units issued under the Amended EDA.
Conflicts of Interest
Enbridge Management makes all decisions relating to the management of our business and affairs through a delegation of control agreement with our General Partner and us. Our General Partner owns the voting shares of Enbridge Management and elects all of its directors. Enbridge, through its wholly-owned subsidiary, Enbridge Pipelines, owns all the common stock of our General Partner. Some of our General Partner’s directors and officers are also directors and officers of Enbridge and Enbridge Management and have fiduciary duties to manage the business of Enbridge and Enbridge Management in a manner that may not be in the best interests of our unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, our General Partner, Enbridge and us. Our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of our unitholders in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.
Enbridge Management
Pursuant to the delegation of control agreement between Enbridge Management, our General Partner and us, and our partnership agreement, we pay all expenses relating to Enbridge Management. This includes Texas franchise taxes and other capital-based foreign, state and local taxes not otherwise paid or reimbursed pursuant to a tax indemnification agreement between Enbridge and Enbridge Management on behalf of Enbridge Management.
13. COMMITMENTS AND CONTINGENCIES
Environmental Liabilities
We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover environmental liabilities through insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our Liquids and Natural Gas businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.
As of December 31, 2011 and 2010, we have $31.3 million and $44.2 million, respectively, included in “Other long-term liabilities,” that we have accrued for costs we have incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets and penalties we have been or expect to be assessed.
Lakehead Lines 6A & 6B Crude Oil Releases
Line 6B Crude Oil Release
On July 26, 2010, a release of crude oil on Line 6B of our Lakehead system was reported near Marshall, Michigan. We estimate that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. We shut down our pipelines in the vicinity, notified the appropriate federal, state and local officials, and dispatched emergency response crews to oversee the containment of the released crude oil and cleanup of the affected areas. The released crude oil affected approximately 38 miles of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a unified command structure was established under the jurisdiction of the Environmental Protection Agency, or EPA, the Michigan Department of Natural Resources and Environment, or MDNRE, and other federal, state and local agencies. The cause of the release remains the subject of an investigation by the National Transportation Safety Board, or NTSB, and other federal and state regulatory agencies.
Pursuant to an administrative order issued by the EPA under the Clean Water Act, we were directed to clean up the released crude oil and remediate and restore the affected areas, a process we had begun upon discovering the release. As of December 31, 2010, we estimated that in connection with this crude oil release we would incur $550.0 million of aggregate gross costs, before insurance recoveries, fines and penalties, and approximately $13 million of lost revenue. These costs included the emergency response, environmental remediation and cleanup activities associated with the crude oil release and potential claims by third parties. For the year ended December 31, 2010, we paid $293.6 million related to the costs on the Line 6B crude oil release and had a remaining liability of $256.4 million, a majority of which was presented as current, on our consolidated statement of financial position as of December 31, 2010.
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.
The material components underlying our total estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:
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, and have a remaining estimated liability of $194.8 million. Additionally, we recognized $335.0 million of insurance recoveries in our consolidated statements of income for the year ended December 31, 2011.
We continue to make progress on the cleanup, remediation and restoration of the areas affected by the Line 6B crude oil release. We expect to make payments for additional costs associated with extended submerged oil recovery operations including reassessment, remediation and restoration of the area and air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All the initiatives we will undertake in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.
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.
Line 6A Crude Oil Release
A release of crude oil from Line 6A of our Lakehead system was reported in an industrial area of Romeoville, Illinois on September 9, 2010. We immediately shut down the pipeline in the vicinity and dispatched emergency response crews to oversee containment, cleanup and the replacement of the pipeline segment. We estimate that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. We completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by federal and state environmental and pipeline safety regulators.
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.
As of December 31, 2010, we estimated that in connection with this crude oil release we would incur aggregate costs of approximately $45 million, excluding fines and penalties, and approximately $3 million of lost revenues. These costs included the emergency response, environmental remediation and cleanup activities associated with the crude oil release. For the year ended December 31, 2010, we paid $34.4 million related to the costs on the Line 6A release and had a remaining total liability of $10.6 million, a majority of which was presented as current, on our consolidated statement of financial position as of December 31, 2010.
As of December 31, 2011, we have revised our total estimate for this crude oil release to $48.0 million, before insurance recoveries and excluding fines and penalties. The $3.0 million increase was based on a refinement of our future costs based on additional information. 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. We have a remaining estimated total liability of $2.6 million, a majority of which is presented as current, on our consolidated statement of financial position as of December 31, 2011.
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. We have the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. We are also 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.
We included those costs we considered probable and that we could reasonably estimate for purposes of determining our expected losses associated with the Line 6A release. Our estimates do not include consideration for any unasserted claims associated with the release that may later become evident, nor have we considered any potential recoveries from third-parties that may later be determined to have contributed to the release.
Lines 6A & 6B Fines and Penalties
Our estimated environmental costs for both the Line 6A and Line 6B crude oil releases do not include an estimate for fines and penalties at December 31, 2011 and 2010, which may be imposed by the EPA and Pipeline and Hazardous Materials Safety Administration, or PHMSA, in addition to other state and local governmental agencies. Several factors remain outstanding at the end of the period that we consider critical in estimating the amount of fines and penalties that we may be assessed.
Due to the absence of sufficient information, we cannot provide a reasonable estimate of our liability for fines and penalties that we could be assessed in connection with each of the releases. As a result, we have not recorded any liability for expected fines and penalties.
Insurance Recoveries
We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates, which renews May of each year. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. Based on our
increased estimate of costs in 2011 associated with these crude oil releases, 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.
We recognized $335.0 million of insurance recoveries as reductions to “Environmental costs, net of recoveries” in our consolidated statements of income for the year ended December 31, 2011. At December 31, 2011, we have $50.0 million recorded in “Receivables, trade and other” in our consolidated statement of financial position for an insurance payment we will receive for a claim we filed in connection with the Line 6B crude oil release. We did not receive any insurance recoveries for the year ended December 31, 2010. 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.
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.
Line 6B Pipeline Integrity Plan
In connection with the restart of Line 6B of our Lakehead system, we committed to accelerate a process we had initiated prior to the crude oil release to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 crude oil release. Pursuant to this agreement with PHMSA, we completed remediation of those pipeline anomalies identified by us between the years 2007 and 2009 that were scheduled for refurbishment and anomalies identified for action in a July 2010 PHMSA notification on schedule, within 180 days of the September 27, 2010 restart of Line 6B, as required. In addition to the required integrity measures, we also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. A new line was installed beneath the St. Clair River in March 2011 and was tied into Line 6B during June 2011.
In February 2011, we filed a supplement to our Facilities Surcharge Mechanism, or FSM, which became effective on April 1, 2011 when it was approved by the FERC 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.
Line Replacement Program
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 our 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 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 our FSM.
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.
Lakehead Line 2B Crude Oil Release
On January 8, 2010, an unexpected release on Line 2B of our Lakehead system occurred in Pembina County, North Dakota. We immediately shut down our pipelines in the vicinity and dispatched emergency response crews to oversee containment, cleanup and repair of the pipeline. We completed the excavation and repairs and returned the line to service within five days. Line 2B was restarted January 13, 2010, once repairs on the pipeline were completed. The volume of oil released was approximately 3,000 barrels, which was largely contained in an area surrounding the pipeline release. We continue to work with the PHMSA which is leading the federal and state environmental and pipeline safety regulators’ investigation into the cause of the release. We have the potential of incurring additional costs in connection with this incident, including expenditures necessary to remediate any operating condition that is determined to have caused the incident. The total costs related to the Line 2B release were $3.3 million, which we paid in full as of December 31, 2010. On our consolidated statement of financial position as of December 31, 2010, we had no remaining amounts accrued for additional cleanup and repair costs associated with the incident.
Oil and Gas in Custody
Our liquids assets transport crude oil and NGLs owned by our customers for a fee. The volume of liquid hydrocarbons in our pipeline systems at any one time varies from approximately 26 million to 51 million barrels, virtually all of which is owned by our customers. Under the terms of our tariffs, losses of crude oil from identifiable incidents not resulting from our direct negligence may be apportioned among our customers. In addition, we maintain adequate property insurance coverage with respect to crude oil and NGLs in our custody.
Approximately 44 percent of the natural gas volumes on our natural gas assets are transported for customers on a contractual basis. We purchase the remaining 56 percent and sell to third parties downstream of the purchase point. At any point in time, the value of our customers’ natural gas in the custody of our natural gas systems is not significant to our operating results, cash flows, or financial position.
Rights-of-Way
As part of our pipeline construction process, we must obtain certain rights-of-way from landowners whose property the pipeline will cross. Rights-of-way that we buy are capitalized as part of “Property, plant and equipment” in our consolidated statements of financial position. Rights-of-way that we lease are expensed. We have recorded expenses of $2.5 million, $2.2 million and $2.4 million for the leased right-of-way agreements for the years ended December 31, 2011, 2010, and 2009, respectively.
Fines and Penalties
We paid $100,000 to PHMSA in October 2011 to resolve an administrative civil penalty brought against us by PHMSA for failure to follow our procedures for maintaining minimum clearance from underground facilities when excavating with powered equipment, related to one of our pipelines located in Rusk County, Wisconsin.
We paid $1.0 million to the State of Wisconsin in October 2010 to resolve fines, penalties and related matters associated with a proceeding brought against us by the State of Wisconsin Department of Justice on behalf of the Wisconsin Department of Natural Resources, for emissions and permit matters associated with our storage tanks located at the Superior, Wisconsin pipeline terminal.
In September of 2010, we paid a $2.4 million fine to settle proceedings brought against us by PHMSA for the unexpected release and fire on Line 3 of our Lakehead system that occurred in November 2007 during planned maintenance near our Clearbrook, Minnesota terminal.
Proceeds from Claim Settlements
For the year ended December 31, 2011, 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.
Legal and Regulatory Proceedings
We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.
A number of governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately twenty-five actions or claims have been filed against us and our affiliates, in state and federal courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. With respect to the Line 6B crude oil release, no penalties or fines have been assessed against us as of December 31, 2011.
Governmental agencies and regulators have also initiated investigations into the Line 6A crude oil release. One claim has been filed against us and our affiliates by the State of Illinois in state court in connection with this crude oil release, and the parties are currently operating under an agreed interim order. The costs associated with this order are included in the estimated environmental costs accrued for the Line 6A crude oil release. We are also 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.
We have accrued a provision for future legal costs associated with the Line 6A and Line 6B crude oil releases as described above in the section titled Lakehead Lines 6A & 6B Crude Oil Releases of this footnote.
Future Minimum Commitments
As of December 31, 2011, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:
(1) Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.
(2) Represents commitments to purchase power in connection with our Liquids segment.
(3) Right-of-way payments are estimated to approximate $2.0 million to $1.7 million per year for the remaining life of all pipeline systems, which has been assumed to be 25 years for purposes of calculating the amount of future minimum commitments beyond 2015.
(4) We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at prices approximating market at the time of delivery.
(5) The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.
The purchases made under our non-cancelable commitments for the years ended December 31, 2011, 2010 and 2009 were $232.0 million, $294.6 million and $345.1 million, respectively.
14. TRUCKING AND NGL MARKETING BUSINESS ACCOUNTING MATTERS
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.” The maximum cumulative aggregate overstatement of earnings occurred at December 31, 2010 in an amount of approximately $33 million, which amount was reduced by local management of the subsidiary during 2011 to $18 million. The following table presents the amounts by which the end of period balances of “Cost of natural gas,” “Accrued purchases,” “Partners’ Capital,” “Operating revenue” and “Accrued receivables” were misstated and the effect on our net income for each of the periods presented (positive amounts represent overstatements of net income and negative amounts represent understatements of net income).
We have included the aggregate amount of $32.9 million, representing the 2010 accrued purchases and sales not recognized in 2010, as cost of goods sold included in “Cost of natural gas” and “Operating revenue” in our consolidated statements of income for the year ended December 31, 2011, following our determination that the previously unrecorded amounts were not material to the current or any prior period financial statements.
15. JOINT TARIFF REVENUES
The OLP was party to a joint tariff agreement with Mustang Pipe Line, LLC, or Mustang, which owns a 100,000 barrel per day, or Bpd, crude oil pipeline that connects with our Lakehead system at Lockport, Illinois and transports crude oil to the Patoka, Illinois area. Mustang is 70% owned by a major integrated oil company that also serves as the operator and is 30% owned by Enbridge. The Mustang joint tariff arrangement is an unusual structure within our liquids pipeline system, since we have no other arrangements where neither we nor Enbridge are the billing carrier or operator of the pipeline with which we have a joint tariff arrangement.
Our joint tariff agreement with Mustang that was in place from October 2005 through March 2009 allowed for shippers on our Lakehead system to reach markets downstream of Chicago, Illinois at a discounted transportation rate for their commitments to transport crude oil on our system and then on the Mustang pipeline. From October 2005 to March 2009, we incorrectly invoiced a shipper on our Lakehead system, which was not a committed shipper, at the discounted transportation rate. Additionally, we continued to invoice two other shippers whose commitments expired in September 2008 at discounted transportation rates rather than the undiscounted non-committed shipper rates. Due to our incorrectly invoicing these shippers, we understated approximately $13.5 million of operating revenues on our Lakehead system from October 2005 through December 2008. We invoiced and collected the previously unbilled amounts from these shippers in the first quarter of 2009.
In connection with the invoicing errors noted above, we also identified volumetric differences totaling approximately 11 million barrels of crude oil for the volumes we measured as delivered to the Mustang pipeline system for five committed shippers and the volumes that Mustang reported as delivered at Patoka for the same committed shippers. The volumetric differences we identified primarily relate to our fiscal years ended December 31, 2007 and 2008, where we have determined that services provided by our Lakehead system to transport approximately 9.4 million barrels of crude oil were not invoiced. In December 2009, we invoiced an aggregate of $9.0 million for the 9.4 million barrels of crude oil we transported and had not previously invoiced, which we recognized as revenue in our consolidated statement of income for the year ended December 31, 2009. We subsequently collected the amounts we invoiced.
Subject to our routine estimates surrounding the realizability of amounts billed, we have included the aggregate amount of $22.5 million, representing the $13.5 million and $9.0 million amounts discussed above, as revenue in our consolidated statement of income for the year ended December 31, 2009, following our determination that the previously unbilled amounts were not material in 2009 or any prior period financial statements.
16. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas we purchase for processing. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. 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 interest rates
and commodity prices, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with the risks discussed above through 2017 in accordance with our risk management policies.
Accounting Treatment
We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value.
In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Operating revenue,” “Cost of natural gas” and “Power” for our commodity-based derivatives and “Interest expense” for our interest rate derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.
If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas” for commodity hedges and “Interest expense” for interest rate hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.
Non-Qualified Hedges
Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have transaction types associated with our commodity and interest rate derivative financial instruments where the hedge structure does not meet the requirements to apply
hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas,” “Operating revenue”, “Power” or “Interest expense” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.
The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:
Commodity Price Exposures:
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Transportation-In our Marketing segment, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.
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Storage-In our Marketing segment, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas is recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas storage activities can create volatility in our earnings.
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Natural Gas Collars-In our Natural Gas segment, we previously entered into natural gas collars to hedge the sales price of natural gas. The natural gas collars were based on a New York Mercantile Exchange, or NYMEX, pricing index, while the physical gas sales were based on a different index. To better align the index of the natural gas collars with the index of the underlying sales, we de-designated the original cash flow hedging relationship with the intent of contemporaneously re-designating the natural gas collars as hedges of forecasted physical natural gas sales with a NYMEX pricing index. However, because the fair value of these derivative instruments was a liability to us at re-designation, they are considered net written options and, pursuant to the authoritative accounting guidance, do not qualify for hedge accounting. These derivatives are being marked-to-market, with the changes in fair value from the date of de-designation recorded to earnings each period. As a result, our operating income is subject to greater volatility due to movements in the prices of natural gas until the underlying long-term transactions are settled.
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Optional Natural Gas Processing Volumes-In our Natural Gas segment, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
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NGL Forward Contracts-In our Natural Gas segment, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. Prior to April 1, 2009, these forward contracts were not treated as derivative financial instruments pursuant to the normal purchase normal sale, or NPNS, exception allowed under authoritative accounting guidance, since the forward contracts resulted in physical receipt or delivery of NGLs. However, evolving markets for NGLs have increased opportunities for a portion of our forward contracts to be settled net rather than physically receiving or delivering the NGLs. Accordingly, we have revoked the NPNS election on certain forward contracts associated with the liquids marketing operations of Dufour Petroleum, L.P., our wholly-owned subsidiary, executed after April 1, 2009. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.
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Natural Gas Forward Contracts-In our Marketing segment, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.
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Crude Oil Contracts-In our Liquids segment, we use forward contracts to hedge a portion of the crude oil length inherent in the operation of our pipelines, which we subsequently sell at market rates. These hedges create a fixed sales price for the crude oil that we will receive in the future. We elected not to designate these derivative financial instruments as cash flow hedges, and as a result, will experience some additional volatility associated with fluctuations in crude oil prices until the underlying transactions are settled or offset.
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Power Purchase Agreements-In our Liquids segment, we use forward physical power agreements to fix the price of a portion of the power consumed by our pumping stations in the transportation of crude oil in our owned pipelines. We designate these derivative agreements as non-qualifying hedges because they fail to meet the criteria for cash flow hedging or the NPNS exception. As various states in which our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.
Except for physical power, in all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or market basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at historical cost) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated. Relating to the power purchase agreements, commodity power purchases are immediately consumed as part of pipeline operations and are subsequently recorded as actual power expenses each period.
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:
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Natural Gas and Marketing segments commodity-based derivatives-“Cost of natural gas”
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Liquids segment commodity-based derivatives-“Operating revenue” and “Power”
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Corporate interest rate derivatives-“Interest expense”
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:
Derivative Positions
Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.
We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $42.7 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the years ended December 31, 2011 and 2010, unrealized commodity hedge losses of $6.9 million and gains of $1.6 million, respectively, were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $162.0 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at December 31, 2011, will be reclassified from AOCI to earnings during the next 12 months.
In connection with our issuance of the 2021 Notes in September 2011, we paid $18.8 million to settle treasury locks we entered to hedge the interest payments on a portion of these obligations through the maturity date of the 2021 Notes. The settlement amount is being amortized from AOCI to “Interest expense” over the respective 10-year term of the 2021 Notes.
In connection with our March 2010 issuance and sale of $500 million in principal amount of our 5.20% senior notes due March 15, 2020, which we refer to as the 2020 Notes, we paid $13.2 million to settle treasury locks we entered to hedge the interest payments on a portion of these obligations through the maturity date of the 2020 Notes. We also received $10.2 million to settle treasury locks associated with our September 2010 issuance and sale of $400 million in principal amount of our 5.50% senior notes due September 15, 2040, which we refer to as the 2040 Notes, that we entered to hedge the interest payments on a portion of the obligations through the maturity date of the 2040 Notes. Both the $13.2 million and $10.2 million settlement amounts are being amortized from AOCI to “Interest expense” over the respective 10- and 30-year terms of the 2020 and 2040 Notes.
The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
* As determined by nationally-recognized statistical ratings organizations.
As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also declined. When credit thresholds are met pursuant to the terms of our International Securities Dealers Association, or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We have included any cash collateral received in the balances listed above. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.
The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.
The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.
At December 31, 2011, we were in an overall net liability position of $254.5 million, which included assets of $33.2 million. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet 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 amount of $63.9 million.
At December 31, 2011 and 2010, we had credit concentrations in the following industry sectors, as presented below:
We are holding no cash collateral on our asset exposures, and we have provided letters of credit totaling $173.2 million and $7.3 million relating to our liability exposures pursuant to the margin thresholds in effect at December 31, 2011 and 2010, respectively, under our ISDA® agreements.
Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.
Effect of Derivative Instruments on the Consolidated Statements of Financial Position
(1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
(1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Effect of Derivative Instruments on Consolidated Statements of Income
(1) Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
Inputs to Fair Value Derivative Instruments
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.
The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2011 to December 31, 2011. No transfers of assets between any of the Levels occurred during the period.
(1) Our policy is to recognize transfers as of the last day of the reporting period.
(2) Settlements represent the realized portion of forward contracts.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2011 and December 31, 2010.
(1) Volumes of natural gas are measured in millions of British Thermal Units, or MMBtu, whereas volumes of NGL and crude oil are measured in barrels, or Bbl. Our power purchase agreements are measured in Megawatt hours, or MWh.
(2) Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.
(3) The fair value is determined based on quoted market prices at December 31, 2011 and December 31, 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.8 million of losses and $0.6 million of gains at December 31, 2011 and December 31, 2010, respectively.
(4) For physical power, the receive price shown represents the index price used for valuation purposes.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at December 31, 2011 and 2010.
(1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2) Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3) The fair value is determined based on quoted market prices at December 31, 2011 and December 31, 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of losses at December 31, 2011 and $0.1 million of losses at December 31, 2010.
Fair Value Measurements of Interest Rate Derivatives
We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.
(1) Interest rate derivative contracts are based on the one-month or three-month London Inter-Bank Offered Rate, or LIBOR.
(2) The fair value is determined from quoted market prices at December 31, 2011 and 2010, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $19.4 million of gains at December 31, 2011 and $0.5 million of gains at December 31, 2010.
(3) Settled in connection with the issuance of our 2021 Notes.
17. INCOME TAXES
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 generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the States of Texas and Michigan that are based upon many but not all items included in net income. We report these taxes as income taxes as set forth in the authoritative accounting guidance.
On May 25, 2011, the Governor of Michigan signed legislation implementing a new corporate income tax system. The new tax system became effective January 1, 2012 and repealed the Michigan Business Tax, or MBT, which imposed tax on individuals, LLCs, trusts, partnerships, S corporations, and C corporations and replaces it with the Michigan Corporate Income Tax, or CIT. The CIT only taxes entities classified as C Corporations, therefore, the Partnership is excluded from the CIT and will no longer pay Michigan income taxes beginning in 2012. Due to this change, we reversed deferred tax liabilities of $1.2 million that were previously recognized on our consolidated statements of financial position, which decreased “Income tax expense” in our consolidated statements of income for the twelve month periods ended December 31, 2011, to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting related to Michigan income taxes.
Our income tax expense is $5.5 million, $7.9 million and $8.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. We computed our income tax expense by applying a Texas state income tax rate to modified gross margin and a Michigan state income tax rate to modified gross receipts. The Texas state income tax rate was 0.5% for the years ended December 31, 2011, 2010 and 2009. The Michigan state income tax rate was 0.2% for the years ended December 31, 2011 and 2010 and 0.1% for the year ended December 31, 2009. Our income tax expense represents effective tax rates as applied to pretax book income of 0.9%, (4.1%) and 2.6% for December 31, 2011, 2010 and 2009, respectively. The effective tax rate for the Partnership is calculated by dividing the income tax expense by the pretax net book income or loss. The income base for calculating income tax expense is modified gross margin for Texas or modified gross receipts for Michigan rather than net book income or loss. The negative effective tax rate for 2010 results from pretax net book losses are coupled with positive income tax expense.
At December 31, 2011 and 2010 we have included a current income tax payable of $7.2 million and $7.9 million in “Property and other taxes payable,” respectively. In addition, at December 31, 2011 and December 31, 2010, we have included a deferred income tax liability of $2.8 million and $3.6 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.
For the years ended December 31, 2011, 2010 and 2009, we paid $7.4 million, $6.5 million and $5.4 million in income taxes, respectively. As of December 31, 2011, we have no liability reported for unrecognized tax benefits.
We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. The impact of changes in tax legislation on deferred income tax liabilities and assets is recorded in the period of enactment. The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:
Our tax years are generally open to examination by the Internal Revenue Service and state revenue authorities for calendar years ended December 2010, 2009, and 2008.
18. OIL MEASUREMENT ADJUSTMENTS
Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include:
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Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;
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Degradation resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and
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Revaluation, which are a function of crude oil prices, the level of our carriers inventory and the inventory positions of customers.
Quantifying oil measurement adjustments are difficult because: (1) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (2) the extensive length of our pipeline systems and (3) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined.
In June 2011, we recognized $52.2 million for settlement of a dispute with a shipper on our Lakehead crude oil pipeline system. We received the cash for that settlement in July 2011. The dispute related to oil measurement adjustments we had previously recognized in prior years and was therefore recorded to “Oil measurement adjustments,” as a reduction to operating expenses, for the year ended December 31, 2011 in our consolidated statements of income.
19. SEGMENT INFORMATION
Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker in deciding how resources are allocated and performance is assessed.
Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We have segregated our business activities into three distinct operating segments:
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Liquids;
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Natural Gas; and
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Marketing.
The following tables present certain financial information relating to our business segments and corporate activities:
(1) Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
(1) Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
(1) Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
20. REGULATORY MATTERS
Regulatory Accounting
We apply the authoritative accounting provisions applicable to the regulated operations of our Southern Access and Alberta Clipper pipelines. The rates for both the Southern Access and Alberta Clipper pipelines are based on a cost-of-service recovery model that follows the FERC’s authoritative guidance and is subject to annual filing requirements with the FERC. Under our cost-of-service tolling methodology, we calculate tolls based on forecast volumes and costs. A difference between forecast and actual results causes an under or over collection of revenue in any given year. Under the authoritative accounting provisions applicable to our regulated operations, over or under collections of revenue are recognized in the financial statements currently and these amounts are realized or settled as cash the following year. This accounting model matches earnings to the period with which they relate and conforms to how we recover our costs associated with these expansions through the annual cost-of-service filings with our customers and the FERC. The assets and liabilities that we recognize for regulatory purposes are recorded in “Other current assets” and “Accounts payable and other,” respectively, on our consolidated statements of financial position.
Southern Access Pipeline
For 2011, we over collected revenue for our Southern Access Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge. As a result, for the year ended December 31, 2011, we reduced our revenues by $21.9 million on our consolidated statement of income with a corresponding regulatory liability on our consolidated statement of financial position at December 31, 2011 for the differences in transportation volumes. The amounts will be refunded through our tolls beginning April 2012 when we update our transportation rates to account for the higher than estimated delivered volumes.
For 2010, we over collected revenue for our Southern Access Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge. In addition, the actual costs recognized in 2010 were lower than the forecasted costs used to calculate the toll charge. As a result, for the year ended December 31, 2010, we reduced our revenues by $3.6 million on our consolidated statements of income with a corresponding regulatory liability on our consolidated statements of financial position at December 31, 2010 for the amounts we over collected. We began to amortize this regulatory liability on a straight-line basis during 2011 to recognize the amounts we previously collected as revenue due to the lower toll rate in 2011 and to account for the over collected amounts. For the year ended December 31, 2011, we increased our revenues by $3.6 million on our consolidated statement of income with a corresponding amount reducing the regulatory liability on our consolidated statement of financial position at December 31, 2011 for the amounts we over collected. The amounts are being refunded to our customers through our tolls, which began in April 2011 when our transportation rates, which account for the higher delivered volumes and lower costs than estimated, became effective.
For the year ended December 31, 2009, we recognized $7.5 million of additional revenue on our consolidated statements of income. During 2009, we under collected revenue for our Southern Access Pipeline in part because actual volumes were lower than the forecast volumes used to calculate the toll surcharge, resulting in a regulatory receivable, the balance of which was $2.1 million, on our consolidated statement of financial position as of December 31, 2010. We collected the $2.1 million regulatory receivable in the first quarter of 2011.
Alberta Clipper Pipeline
For 2011, we have over collected revenue on our Alberta Clipper Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge. Offsetting the impact from the difference in volumes were actual costs recognized in 2011 that were higher than the forecasted costs used to calculate the toll
charge. As a result, for the year ended December 31, 2011, we reduced our revenues by $31.8 million on our consolidated statement of income with a corresponding increase in the regulatory liability on our consolidated statement of financial position at December 31, 2011 for the differences in transportation volumes and costs. We will begin to reimburse these amounts to our customers in April 2012 when we update our transportation rates to account for the higher delivered volumes and higher costs than estimated.
For 2010, we over collected revenue on our Alberta Clipper Pipeline because the actual operating costs recognized in 2010 were lower than the forecasted costs used to calculate the toll charge. For the year ended December 31, 2010, we had reduced our revenues by $10.1 million on our consolidated statements of income with a corresponding regulatory liability on our consolidated statements of financial position for the difference in costs. We began to amortize this regulatory liability on a straight-line basis during 2011 to recognize the amounts we previously collected as revenue due to the lower toll rate in 2011 and to account for the over collected amounts. For the year ended December 31, 2011, we increased our revenues by $10.1 million on our consolidated statement of income with a corresponding amount reducing the regulatory liability on our consolidated statement of financial position at December 31, 2011 for the over collected amounts. The amounts are being refunded to our customers through transportation rates, which became effective in April 2011 and account for the lower costs than estimated.
In April 2010, the Alberta Clipper Pipeline was completed and we began depreciating this regulated asset over the 30 year contract period. Under the authoritative accounting provisions applicable to regulated operations, we are permitted to capitalize and recover costs for rate-making purposes that include an allowance for equity costs during construction, referred to as AEDC. In connection with the construction of the Alberta Clipper Pipeline, we have recorded AEDC in “Property, plant and equipment, net” on our consolidated statements of financial position in amounts totaling $27.9 million at December 31, 2010. Related to the recognition of AEDC, we also recorded $15.3 million of “Other income” in our consolidated statements of income for the year ended December 31, 2010. We also recorded an allowance for interest during construction, or AIDC, that was $4.8 million for the year ended December 31, 2010.
Regulatory Liability for Southern Lights Pipeline In-Service Delay
In December 2006, as part of the regulatory approval process for its pipeline, Enbridge Pipelines (Southern Lights) L.L.C., or Southern Lights, agreed to the request made by the Canadian Association of Petroleum Producers, referred to as CAPP, to delay the in-service date of its pipeline from January 1, 2010 to July 1, 2010. In exchange for Southern Light’s postponement of the in-service date of its pipeline, CAPP agreed to reimburse Southern Lights for any carrying costs incurred during this period as a result of the delayed in-service date. The carrying costs were collected by us through the transportation rates charged on our Lakehead system beginning on April 1, 2010. As of December 31, 2011, we had $26.4 million recorded as a regulatory liability on our consolidated statement of financial position for amounts we over collected in connection with the Southern Lights in-service delay. We will reduce the transportation rates we charge the shippers in the future for the additional amounts we collected beginning in April 2012 when we update the transportation rates on our Lakehead system.
FERC Transportation Tariffs
Effective April 1, 2011, we filed our annual tariff rate adjustment with the FERC to reflect true-ups for the difference between estimated and actual cost and throughput data for the prior year and our projected costs and throughput for 2011 related to our expansion projects. Also included was a supplement to our FSM for recovery of the costs related to the 2010 and 2011 Line 6B Integrity Program, including costs associated with the PHMSA Corrective Action Order and as discussed in Note 13. Commitments and Contingencies-Pipeline Integrity Plan. The FSM, which was approved in July 2004, is a component of our Lakehead system’s overall rate structure and allows for the recovery of costs for enhancements or modifications to our Lakehead system.
This tariff filing decreased the average transportation rate for crude oil movements from the Canadian border to Chicago, Illinois by approximately $0.21 per barrel, to an average of approximately $1.76 per barrel. The surcharge is applicable to each barrel of crude oil that is placed on our system beginning on the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.
On May 2, 2011, we filed FERC Tariff 45.0.0 to establish International Joint Tariff rates applicable to the transportation of petroleum from all receipt points in western Canada on Enbridge Pipelines Inc., or EPI’s, Canadian Mainline system to all delivery points on the Lakehead pipeline system owned by the OLP and delivery points on the Canadian mainline located downstream of the Lakehead system. This tariff filing became effective July 1, 2011.
Effective July 1, 2011, we increased the rates for transportation on our Lakehead, North Dakota and Ozark systems in compliance with the indexed rate ceilings allowed by the FERC. In May 2011, the FERC determined that the annual change in the Producer Price Index for Finished Goods, or PPI-FG, plus 2.65 percent (PPI-FG + 2.65 percent) should be the oil pricing index for the five year period ending July 2016. The index is used to establish rate ceiling levels for oil pipeline rate changes. The increase in rates is due to an increase in the Producer Price Index for Finished Goods as compared with prior periods. For our Lakehead system, indexing applies only to the base rates and does not apply to the SEP II, Terrace and Facilities surcharges, which include the Southern Access Pipeline and Alberta Clipper Project.
Effective December 19, 2011, we modified the terms of our transportation tariff on our Ozark system to implement a lottery process to allocate new shipper capacity if and when the number of new shippers nominating on the system precludes any individual new shipper from being allocated a minimum batch. Additionally, we increased the minimum accepted batch size from 10,000 Bpd to 30,000 Bpd to ensure accurate delivery measurement.
21. SUBSEQUENT EVENTS
Distribution to Partners
On January 30, 2012, the board of directors of Enbridge Management declared a distribution payable to our partners on February 14, 2012. The distribution was paid to unitholders of record as of February 7, 2012, of our available cash of $180.3 million at December 31, 2011, or $0.5325 per limited partner unit. Of this distribution, $159.4 million was paid in cash, $20.5 million was distributed in i-units to our i-unitholder and $0.4 million was retained from our General Partner in respect of the i-unit distribution to maintain its two percent general partner interest.
Distribution to Series AC Interests
On January 30, 2012, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP paid $15.8 million to the noncontrolling interest in the Series AC, while $7.9 million was paid to us.
Lakehead Line 5 Crude Oil Release and Pressure Restrictions
On February 15, 2012, a release of crude oil was detected on Line 5 of our Lakehead system near the town of Sterling, Michigan. The volume of the oil released was approximately 3 barrels, which was contained to an area surrounding the crude oil release. Line 5 was restarted on February 17, 2012 with pressure restrictions that are expected to be of short duration. We do not believe these pressure restrictions will have a material impact to our operating revenue revenues in 2012.
22. SUPPLEMENTAL CASH FLOWS INFORMATION
The following table provides supplemental information for the item labeled “Other” in the “Cash provided by operating activities” section our consolidated statements of cash flows.
23. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting Standards Update-Fair Value Measurement
In May 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, as part of the FASB’s joint project with the International Accounting Standards Board, or IASB, to achieve common fair value measurement and disclosure requirements in United States generally accepted accounting principles, or GAAP, and International Financial Reporting Standards, or IFRS. The key changes relevant to our business include enhanced disclosures requiring additional information about unobservable inputs and valuation methods utilized and requiring the fair value hierarchy level of assets and liabilities not recorded at fair value but where fair value disclosure is required.
The accounting update is effective for the first reporting period beginning after December 15, 2011, with early application prohibited. The guidance will require prospective application. The adoption of this pronouncement is not anticipated to have a material impact on our financial statements.
Accounting Standards Update-Presentation of Comprehensive Income
In June 2011, the FASB issued Accounting Standards No. 2011-05, Presentation of Comprehensive Income, as part of the FASB’s joint project with the IASB, requiring presentation of net income and other comprehensive income either in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements of net income and other comprehensive income. The guidance eliminated the option to report other comprehensive income and its components in the statement of changes in equity and the disclosure of reclassification adjustments in the footnotes. The guidance does not change which components of comprehensive income are recognized in net income or other comprehensive income, when an item of other comprehensive income must be reclassified to net income or the earnings-per-share computation. The accounting update is effective for the first reporting period beginning after December 15, 2011.
In December 2011, the FASB issued an amendment, Accounting Standards No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive income in Accounting Standards Update No. 2011-05, deferring the requirement to measure and present reclassification adjustments from accumulated other comprehensive income to net income by income statement line item in net income and also in other comprehensive income. As such, entities will continue to report reclassifications out of accumulated other comprehensive income consistent with the requirements in effect before adoption of the new standard. The deferral is effective at the same time that the new standard is adopted.
Accounting Standards Update-Testing Goodwill for Impairment
In September 2011, the FASB issued Accounting Standards No. 2011-08, Testing Goodwill for Impairment, which is intended to reduce the overall costs and the complexity of impairment testing. The standard allows an entity to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. An entity no longer will be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The standard does not change the current two-step test and applies to all entities that have goodwill reported in their financial statements. The standard will be effective for fiscal years beginning after December 15, 2011.
Accounting Standards Update-Balance Sheet Offsetting
In December 2011, the FASB issued Accounting Standards No. 2011-11, Disclosures about Offsetting Assets and Liabilities, as part of the FASB’s joint project with the IASB, which requires an entity to disclose information about offsetting and related arrangements. The standard will enable users of financial statements to understand the effect that offsetting and related arrangements have on an entity’s financial position. The standard will be effective for annual reporting periods beginning on or after January 1, 2013, with required disclosures presented retrospectively for all comparative period presented.
24. QUARTERLY FINANCIAL DATA (Unaudited)
(1) In the fourth quarter of 2010, we recognized $120.0 million of additional costs related to the crude oil release on Line 6B as discussed in Note 13. Commitments and Contingencies.
(2) Quarterly net income (loss) per limited partner units for 2010, are presented retrospectively applying the April 21, 2011 two-for-one split of our units.
(3) In 2011, we recognized $35.0 million, $140.0 million and $40.0 million of additional costs during the second, third and fourth quarters, respectively, related to the crude oil release on Line 6B. In 2011, we also recognized $35.0 million, $15.0 million, $85.0 million and $200.0 million of environmental insurance recoveries during the first, second, third and fourth quarters, respectively, related to the crude oil release on Line 6B.
(4) In the fourth quarter of 2011, we recognized approximately $18 million of additional expense, net related to accounting misstatements discussed in Note 14. Trucking and NGL Marketing Business Accounting Matters.
(5) Operating results for the year ended December 31, 2011 were affected by $52.2 million we received in the second quarter of 2011 for the settlement of a dispute related to oil measurement losses, which we recognized as a reduction to operating expenses.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
BACKGROUND
In September of 2011, management began investigating possible conflict of interest transactions associated with our wholly-owned trucking and NGL marketing subsidiary. As part of that process, our Audit, Finance & Risk Committee engaged outside counsel, who in turn engaged a forensic accounting firm, to assist with its investigation. In January 2012, employees working on behalf of the trucking and NGL marketing subsidiary informed our management of accounting misstatements associated with the financial statement recognition of product purchases made by the local management responsible for operating the subsidiary and certain of its staff. Management of the Partnership and the Audit, Finance & Risk Committee expanded their respective investigations which revealed accounting misstatements that led to further investigation by our management and the Audit Committee. 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 and resulted in an overstatement of the Partnership’s earnings through December 31, 2011 by a cumulative aggregate amount of approximately $18 million, prior to their correction. The maximum cumulative aggregate overstatement of earnings occurred at December 31, 2010 in an amount of approximately $33 million, which was reduced by local management of the subsidiary during 2011 to $18 million. The accounting misstatements resulted from intentional misconduct and collusion by local management responsible for operating our trucking and NGL marketing subsidiary and certain of its staff to align the financial performance of the subsidiary with its budget. This intentional misconduct and collusion violated our policies and procedures, including falsifying documents, and negatively influencing the subsidiary’s employees with respect to compliance with our policies. In addition, the intentional misconduct and collusion circumvented our control processes otherwise in place, which precluded our ability to timely detect and correct the accounting misstatements.
We determined that these misstatements had no material effect on our consolidated financial statements for the current or any prior years during which the activities above occurred. The effect of correcting these accounting misstatements is discussed in the Natural Gas segment discussion included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as Note 14. Trucking and NGL Marketing Business Accounting Matters of Item 8. Financial Statements and Supplementary Data.
DISCLOSURE CONTROLS AND PROCEDURES
We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in our annual and quarterly reports under the Exchange Act within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures as of December 31, 2011. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2011.
In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting, audit and other services on our behalf. Management performed additional analysis and other post-closing procedures to ensure that our financial statements are prepared in accordance with generally accepted accounting principles. These procedures included, among others, review of subsequent disbursements testing, and review of financial records, systems and electronic data for unusual transactions. Accordingly, management concluded that the financial statements in this report fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented, in accordance with U.S. generally accepted accounting principles.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f).
The Partnership’s internal control over financial reporting is a process designed under the supervision and with the participation of our principal executive officer and principal financial officer, and effected by the board of directors of our General Partner, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
The Partnership’s internal control over financial reporting includes policies and procedures that:
•
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect transactions and dispositions of assets of the Partnership;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with United States generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with the authorizations of the Partnership’s management and directors; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011, with the participation of our principal executive officer and principal financial officer, based on the framework established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on this assessment, management concluded that our internal control over financial reporting was not effective as of December 31, 2011 because of the material weakness described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Partnership’s annual or interim financial statements will not be prevented or detected on a timely basis. In connection with management’s assessment of our internal control over financial reporting described above, management has identified control deficiencies as of December 31, 2011 described below that represented a material weakness in internal control over financial reporting. We did not maintain an effective control environment at our wholly-owned trucking and NGL marketing subsidiary and our monitoring of the effectiveness of those controls at that subsidiary was not sufficient to deter or detect that they had been circumvented. An effective control environment is the foundation on which all other components of internal control are based. Specifically:
•
An appropriate tone and control culture was not in place associated with the referenced subsidiary, in that certain of its management and employees engaged in intentional misconduct and collusion that
violated our policies and procedures, as well as circumvented, through local management’s override of, our control processes otherwise in place. Further, these activities were not detected in a timely manner.
•
The controls associated with the referenced subsidiary were not effective to ensure that all of the assets and liabilities of the subsidiary were recorded accurately and timely in the instance of collusion by local management and staff.
•
The control associated with monitoring the control activities at the referenced subsidiary was not sufficient to detect or deter circumvention of accounting controls or accounting misstatements at the referenced subsidiary in a timely manner.
This material weakness resulted in out of period adjustments which impacted the accrued purchases, cost of natural gas (including natural gas liquids), inventory, accrued receivables and operating revenue financial statement accounts. Additionally, this material weakness, if not remediated, could result in mistatements to any of our financial statement accounts which would result in a material misstatement of our annual or interim consolidated financial statements which would not be prevented or detected.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, has issued an audit report on the effectiveness of our internal control over financial reporting as of December 31, 2011, beginning on page 114.
REMEDIATION
Management, with the participation of the principal executive officer and principal financial officer, is committed to remediating the material weakness identified above by implementing changes to the Partnership’s internal control over financial reporting related to the referenced subsidiary. Management has implemented, or is in the process of implementing, the following changes to the Partnership’s internal control systems and procedures related to the referenced subsidiary:
Changes Made in the Fourth Quarter of 2011
•
Management at the subsidiary separated from the organization, and an interim manager of operations was appointed.
•
We added an additional layer of review of payments and accounting activities at the subsidiary.
Changes Made To Date in 2012
•
An interim accounting manager of the subsidiary has been appointed.
•
We have implemented new centralized reporting structures for various groups, including risk management and information technology.
Changes in Process
•
We are centralizing critical control functions, including accounting, contract administration, and risk management into the Partnership’s corporate office.
•
We will re-train personnel at the referenced subsidiary on our statement of Business Conduct, and Whistleblower, and Conflicts of Interest policies.
Certain of the remediation measures described above are subject to our internal controls assessment, testing and evaluation processes. We believe that these measures will remediate the identified material weakness and strengthen internal control over financial reporting. As we continue to evaluate and enhance our internal control over financial reporting, we may determine that additional measures need to be taken to address the material weakness or that we need to modify or otherwise adjust the remediation measures described above.
INHERENT LIMITATIONS OVER INTERNAL CONTROLS
Our system of controls is designed to provide reasonable, not absolute, assurance regarding the reliability and integrity of accounting and financial reporting. Our management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met. These inherent limitations include the following:
•
Judgments in decision-making can be faulty, and control and process breakdowns can occur because of simple errors or mistakes.
•
Controls can be circumvented by individuals, acting alone or in collusion with each other, or by management override.
•
The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
•
The design of a control system must consider the benefits of controls relative to their costs.
Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations are known features of the financial reporting process, and while it is possible to design into the process safeguards to reduce the risk, it is not possible to completely eliminate the risk.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
The changes to our internal control over financial reporting described above under “Remediation-Changes Made in the Fourth Quarter of 2011” occurred during the fourth fiscal quarter of 2011. These changes have materially affected the Partnership’s internal control over financial reporting as it relates to the referenced subsidiary.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
We are a limited partnership and have no officers or directors of our own. Set forth below is certain information concerning the directors and executive officers of the General Partner and of Enbridge Management as the delegate of the General Partner under a delegation of control agreement among us, the General Partner and Enbridge Management. All directors of the General Partner are elected annually and may be removed by Enbridge Pipelines Inc., as the sole shareholder of the General Partner, an indirect and wholly-owned subsidiary of Enbridge. All directors of Enbridge Management were elected and may be removed by the General Partner, as the sole holder of Enbridge Management’s voting shares. All officers of the General Partner and Enbridge Management serve at the discretion of the boards of directors of the General Partner and Enbridge Management, respectively. All directors and officers of the General Partner hold identical positions in Enbridge Management, except for Mark A. Maki and Terrance L. McGill.
Name
Age
Position
Directors and Executive Officers:
Martha O. Hesse
Director and Chairman of the Board
Jeffrey A. Connelly
Director
J. Herbert England
Director
Dan A. Westbrook
Director
Mark A. Maki
President of Enbridge Management, Senior Vice President of General Partner and Director
Terrance L. McGill
President of General Partner, Senior Vice President of Enbridge Management and Director
Al Monaco
Executive Vice President-Gas Pipelines, Green Energy & International and Director
Stephen J. Wuori
Executive Vice President-Liquids Pipelines and Director
Officers:
Richard L. Adams
Vice President-U.S. Operations, Liquids Pipelines
Janet L. Coy
Vice President-Natural Gas Marketing
E. Chris Kaitson
Vice President-Law
John A. Loiacono
Vice President-Commercial Activities
Susan E. Miller
Vice President-Integrity
Byron C. Neiles
Vice President-Major Projects
Stephen J. Neyland
Vice President-Finance
Kerry C. Puckett
Vice President-Engineering and Operations, Gathering and Processing
William M. Ramos
Controller
Allan M. Schneider
Vice President-Regulated Engineering and Operations
Bruce A. Stevenson
Corporate Secretary
David K. Wudrick
Treasurer
Leon A. Zupan
Vice President-Operations, Liquids Pipelines
DIRECTORS AND EXECUTIVE OFFICERS
Martha O. Hesse
Martha O. Hesse was elected as Chairman of the Board in May 2007 and as a director of the General Partner and Enbridge Management in March 2003 and serves as a member of the Audit, Finance & Risk Committee.
Ms. Hesse was President and Chief Executive Officer of Hesse Gas Company from 1990 through 2003. She served as Chairman of the FERC from 1986 to 1989. Ms. Hesse also served as Senior Vice President of First Chicago Corporation and as Assistant Secretary for Management and Administration of the United States Department of Energy. She is a private investor and currently serves as a director of Mutual Trust Financial Group.
Ms. Hesse’s contribution to the Board is enhanced by her experience as the former Chairman of the FERC and as an Assistant Secretary with the Department of Energy in Washington, D.C. particularly since many of our operations are federally regulated. Her government experience in combination with her banking and gas marketing experience fits well with our strategic direction.
Jeffrey A. Connelly
Jeffrey A. Connelly was elected a director of the General Partner and Enbridge Management in January 2003 and serves as the Chairman of the Audit, Finance & Risk Committee. Mr. Connelly served as Executive Vice President, Senior Vice President and Vice President of the Coastal Corporation from 1988 to 2001.
Mr. Connelly brings significant financial experience to our Board because of his experience as the former Treasurer and other executive roles with Coastal Corporation, a former Fortune 500 Company whose principal business segments included gathering, processing, storage, and distribution of natural gas; oil refining and marketing; oil exploration and production; electric power production; and coal mining. He also served as the chief executive officer for several wholly owned Coastal subsidiaries.
J. Herbert England
J. Herbert England was elected a director of the General Partner and Enbridge Management in July 2010 and serves on the Audit, Finance & Risk Committee. Mr. England also serves on the Enbridge board of directors and the board of directors of FuelCell Energy, Inc. He has been Chair & Chief Executive Officer of Stahlman-England Irrigation Inc. (contracting company) in southwest Florida since 2000. From 1993 to 1997, Mr. England was the Chair, President & Chief Executive Officer of Sweet Ripe Drinks Ltd. (fruit beverage manufacturing company). Prior to 1993, Mr. England held various executive positions with John Labatt Limited (brewing company) and its operating companies, Catelli Inc. (food manufacturing company) and Johanna Dairies Inc. (dairy company).
Mr. England brings to the Board a wide range of financial executive experience because of his previous positions as well as his service with other public company audit committees.
Dan A. Westbrook
Dan A. Westbrook was elected a director of the General Partner and Enbridge Management in October 2007 and serves on the Audit, Finance & Risk Committee. In 2008, he joined the board of directors of the Carrie Tingley Hospital Foundation and currently also serves on the board of Ivanhoe Mines, an international mining company. From May 2007 until August 2008, he served on the board of directors of Synenco Energy Inc. where he was a member of their Audit & Risk and Finance Committees, until Synenco was acquired by Total E&P Canada. From January 2006 until May 2008, he served on the board of directors of Knowledge Systems Inc., a privately held United States company prior to its acquisition by Halliburton. From 2001 to 2005, Mr. Westbrook served as President of BP China Gas, Power & Upstream and Vice-Chairman of the board of directors of Dapeng LNG, a Sino joint venture between BP subsidiaries and other Chinese companies. From 1999 to 2001, Mr. Westbrook was the Associate President with BP in Argentina. Prior to that, Mr. Westbrook held executive positions with BP in Houston, Russia, Chicago and The Netherlands.
Through his long career in the petroleum exploration and production industry, including his other public company directorships and previous service as President of B.P. China, Mr. Westbrook provides our Board with extensive industry experience, leadership skills, international and petroleum development experience, as well as knowledge of our business environment.
Mark A. Maki
Mark A. Maki was elected President of Enbridge Management and Senior Vice President of the General Partner and as a director of both in October 2010. Mr. Maki previously served as Vice President-Finance of the General Partner and Enbridge Management from July 2002. Prior to that time, Mr. Maki served as Controller of the General Partner and Enbridge Management from June 2001, and prior to that, as Controller of Enbridge Pipelines from September 1999.
Mr. Maki progressed through a series of accounting and financial roles of increasing responsibility during his 26 years with Enbridge, in the United States and Canada. Through his broad range of domestic and Canadian experience in the pipeline industry Mr. Maki provides our Board with financial expertise, leadership skills in our industry and knowledge of our local community and business environment.
Terrance L. McGill
Terrance L. McGill was elected as a director and as President of the General Partner and Senior Vice President of Enbridge Management in October 2010. Prior to October 2010 Mr. McGill served as a director and President of the General Partner and of Enbridge Management since May 2006. Mr. McGill previously served as Vice President, Commercial Activity and Business Development of the General Partner and Enbridge Management from April 2002 and Chief Operating Officer from July 2004. Prior to that time, Mr. McGill was President of Columbia Gulf Transmission Company from January 1996 to March 2002.
As the President of the General Partner, Mr. McGill gives our Board insight and in-depth knowledge of our industry and our specific operations and strategies. He also provides leadership skills, pipeline operations and management expertise and knowledge of our local community and business environment, which he has gained through his long career in the oil and gas industry.
Al Monaco
Al Monaco was elected as a director of the General Partner and Enbridge Management in October 2010 and simultaneously resigned as an officer of these entities. In April of 2011, he was elected as Executive Vice President-Gas Pipelines, Green Energy & International of the General Partner and Enbridge Management. He also serves as President of Enbridge since February 2012 and prior to that as, President, Gas Pipelines, Green Energy & International of Enbridge since October 2010. Previously, Mr. Monaco was elected Executive Vice President, Major Projects of the General Partner and Enbridge Management in January 2008 and held similar responsibilities with Enbridge. Prior to that, Mr. Monaco was President of Enbridge Gas Distribution Inc., a subsidiary of Enbridge, from September 2006, Senior Vice President, Planning & Development, Enbridge from June 2003, and Vice President, Financial Services, of Enbridge from February 2002. Mr. Monaco was Treasurer of the General Partner from February 2002 and Enbridge Management from its formation until his resignation from those positions in April 2003.
Since 1995, Mr. Monaco has held multiple roles of increasing financial and managerial responsibility during his career with Enbridge. Mr. Monaco brings the Board pipeline industry experience, extensive knowledge in the areas of investor relations, treasury and corporate finance, as well as leadership skills and knowledge of his local community and business environment.
Stephen J. Wuori
Stephen J. Wuori was elected a director of the General Partner and Enbridge Management in January 2008 and is also the Executive Vice President-Liquids Pipelines for the General Partner and Enbridge Management. Mr. Wuori also was elected President, Liquids Pipelines of Enbridge in October 2010. From 2008 to October 2010, Mr. Wuori served Enbridge as Executive Vice President, Liquids Pipelines. He was previously Executive Vice President, Chief Financial Officer and Corporate Development of Enbridge from 2006 to 2008, Group Vice President and Chief Financial Officer of Enbridge from 2003 to 2006 and Group Vice President, Corporate Planning and Development of Enbridge from 2001 to 2003.
As Executive Vice President-Liquids Pipelines, Mr. Wuori provides our Board insight and in-depth knowledge of our industry and our specific operations and strategies. He also provides financial expertise, leadership skills, pipeline operations expertise and knowledge of our business environment, which he has gained through his long career with Enbridge.
OTHER OFFICERS
Richard L. Adams was elected Vice President, U.S. Operations, Liquids Pipelines of the General Partner and Enbridge Management in February 2010 prior to which he was Vice President, U.S. Engineering and Project Execution, Liquids Pipelines from June 2007 and prior to which he was Vice President, Operations and Technologies from April 2003. Prior to April 2003, he was Director of Technology & Operations for the General Partner and Enbridge Management from 2001, and Director of Field Operations and Technical Services and Director of Commercial Activities for OCENSA/Enbridge in Bogota, Colombia from 1997 to 2001.
Janet L. Coy was elected Vice President-Natural Gas Marketing of the General Partner and Enbridge Management in October 2010. Ms. Coy previously served as President of the natural gas marketing subsidiaries of Enbridge Management and the General Partner since the acquisition of Midcoast Energy Resources, Inc. and continues to serve in that capacity.
E. Chris Kaitson was elected Vice President, Law of the General Partner and Enbridge Management in May 2007. He also currently serves as Deputy General Counsel of Enbridge. Prior to that, he was Assistant General Counsel and Assistant Secretary of the General Partner and Enbridge Management from July 2004. He served as Corporate Secretary of the General Partner and Enbridge Management from October 2001 to July 2004. He was previously Assistant Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from 1997 until it was acquired by Enbridge in May 2001.
John A. Loiacono was elected Vice President, Commercial Activities, of the General Partner and Enbridge Management in July 2006. Prior to that, he was Director of Commercial Activities for the General Partner and Enbridge Management from April 2003 and commenced employment with Midcoast Energy Resources, Inc. in February 2000 as an Asset Optimizer until it was acquired by Enbridge in May 2001.
Susan E. Miller was elected Vice President-Integrity of the General Partner and Enbridge Management in October 2010. Ms. Miller previously served as Vice President, International Business Development for Enbridge since September 2009, including serving as General Manager of the OCENSA crude oil pipeline in Colombia since 2006. Ms. Miller has been an Enbridge employee since 1988.
Byron C. Neiles was elected Vice President-Major Projects of the General Partner and Enbridge Management in October 2010. Mr. Neiles was named Senior Vice President-Major Projects of Enbridge in November 2011 and previously served Enbridge as Vice President in the Major Projects division since April 2008, prior to which he was Vice President of Enbridge Gas Distribution from 2003 to 2008. Mr. Neiles joined Enbridge in 1994.
Stephen J. Neyland was elected Vice President-Finance of the General Partner and Enbridge Management in October 2010. Mr. Neyland was previously Controller of the General Partner and Enbridge Management effective September 2006. Prior to his election he served as Controller, Natural Gas from January 2005, Assistant Controller from May 2004 to January 2005, and in other managerial roles in Finance and Accounting from December 2001 to May 2004. Prior to that time, Mr. Neyland was Controller of Koch Midstream Services from 1999 to 2001.
Kerry C. Puckett was elected Vice President, Engineering and Operations, Gathering and Processing of the General Partner and Enbridge Management in October 2007. Prior to his election he served as General Manager of Engineering and Operations from 2004 and Manager of Operations from 2002 to 2004. Prior to that time, he served as Manager of Business Development for Sid Richardson Energy Services Company.
William M. Ramos was elected Controller of the General Partner and Enbridge Management in October 2010. Prior to his election he served as Assistant Controller and in other managerial roles of the General Partner with responsibility for financial accounting, reporting and control from April 2005. Mr. Ramos served in various management capacities in energy-related companies prior to 2005.
Allan M. Schneider was elected Vice President, Regulated Engineering and Operations of the General Partner and Enbridge Management in October 2007. Prior to his election he served as Director of Engineering and Operations for Regulated & Offshore and Director of Engineering Services from January 2005. Prior to that, Mr. Schneider was Vice President of Engineering and Operations for Shell Gas Transmission, L.L.C. from December 2000.
Bruce A. Stevenson was elected Corporate Secretary of the General Partner and Enbridge Management in July 2004. Between 2000 and 2004, Mr. Stevenson held management positions with Reliant Energy, Inc. and Arthur Andersen LLP. Prior to that Mr. Stevenson was General Counsel & Corporate Secretary of Alberta Natural Gas Company Ltd, a Canadian gas processing and transmission company that was acquired by TransCanada Pipelines.
David K. Wudrick was elected Treasurer of the General Partner and Enbridge Management in April 2010. He is also Director, Finance of Enbridge, a position he has held since April 2010. Previously he was Director, Treasury of Enbridge from 2007 and Treasurer of Enbridge Management Service Inc., a wholly-owned subsidiary of Enbridge from 2005.
Leon A. Zupan was elected Vice President-Operations, Liquids Pipelines of the General Partner and Enbridge Management in July 2004, and is President-Gas Pipelines of Enbridge since February 2012 and prior to that as Senior Vice President-Operations of Enbridge. Mr. Zupan previously served as Vice President, Operations of Enbridge from 2004 and Vice President, Development & Services for Enbridge Pipelines from 2000.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires our directors, executive officers and 10 percent beneficial owners to file with the SEC reports of ownership and changes in ownership of our equity securities and to furnish us with copies of all reports filed. Based on our review of the Section 16(a) filings that have been received by us and inquiries made to our directors and executive officers, we believe that all filings required to be made under Section 16(a) during 2011 and prior years were timely made.
GOVERNANCE MATTERS
We are a “controlled company,” as that term is used in NYSE Rule 303A, because all of our voting shares are owned by the General Partner. Because we are a controlled company, the NYSE listing standards do not require that we or the General Partner have a majority of independent directors or a nominating or compensation committee of the General Partner’s board of directors.
The NYSE listing standards require our principal executive officer to annually certify that he is not aware of any violation by the Partnership of the NYSE corporate governance listing standards. Accordingly, this certification was provided as required to the NYSE on March 21, 2011.
CODE OF ETHICS, STATEMENT OF BUSINESS CONDUCT AND CORPORATE GOVERNANCE GUIDELINES
We have adopted a Code of Ethics applicable to our senior officers, including the principal executive officer, principal financial officer and principal accounting officer of Enbridge Management. A copy of the Code of Ethics for Senior Financial Officers is available on our website at www.enbridgepartners.com and is included herein as Exhibit 14.1. We post on our website any amendments to or waivers of our Code of Ethics for senior officers and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to this information through such postings. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
We also have a Statement of Business Conduct applicable to all of our employees, officers and directors. A copy of the Statement of Business Conduct is available on our website at www.enbridgepartners.com. We post on our website any amendments to or waivers of our Statement of Business Conduct, and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to this information through such postings. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
We also have a statement of Corporate Governance Guidelines that sets forth the expectation of how our board of directors should function and its position with respect to key corporate governance issues. A copy of the Corporate Governance Guidelines is available on our website at www.enbridgepartners.com. We post on our website any amendments to our Corporate Governance Guidelines, and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to these amendments through such postings. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
AUDIT, FINANCE & RISK COMMITTEE
Enbridge Management has an Audit, Finance & Risk Committee, referred to as the “Audit Committee,” comprised of four board members who are independent as the term is used in Section 10A of the Exchange Act. None of these members are relying upon any exemptions from the foregoing independence requirements. The members of the Audit Committee are Jeffrey A. Connelly, Dan A. Westbrook, Martha O. Hesse and J. Herbert England. George K. Petty resigned as a Director and as a member of the Audit Committee on January 19, 2011, and J. Herbert England was elected to fill the Audit Committee vacancy on January 28, 2011. The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the report of the independent registered public accounting firm. The Audit Committee also reviews the scope and quality, including the independence and objectivity, of the independent and internal auditors and the fees paid for both audit and non-audit work and makes recommendations concerning audit matters, including the engagement of the independent auditors, to the board of directors.
The charter of the Audit Committee is available on our website at www.enbridgepartners.com. The charter of the Audit Committee complies with the listing standards of the NYSE currently applicable to us. This material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
Enbridge Management’s board of directors has determined that Jeffrey A. Connelly, Martha O. Hesse and J. Herbert England qualify as “Audit Committee financial experts” as defined in Item 407(d)(5)(ii) of Regulation S-K. Each of the members of the Audit, Finance and Risk Committee is independent as defined by Section 303A of the listing standards of the NYSE.
Mr. England serves on the Audit Committees of the General Partner and Enbridge Management, FuelCell Energy, Inc. and Enbridge Inc. In compliance with the provisions of the Audit, Finance & Risk Committee Charter, the boards of directors of the General Partner and of Enbridge Management determined that Mr. England’s simultaneous service on such audit committees does not impair his ability to effectively serve on the Audit, Finance & Risk Committee.
Enbridge Management’s Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our Audit Committee may do so by writing in care of Chairman, Audit Committee, c/o Enbridge Energy Management, L.L.C., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
EXECUTIVE SESSIONS OF NON-MANAGEMENT DIRECTORS
The independent directors of Enbridge Management meet at regularly scheduled executive sessions without management. Martha O. Hesse serves as the presiding director at those executive sessions. Persons wishing to communicate with the Company’s independent directors may do so by writing in care of Chairman, Board of Directors, Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, TX 77002.
Item 11.
Item 11. Executive Compensation
COMPENSATION DISCUSSION AND ANALYSIS
General
We are a master limited partnership and do not employ directly any employees nor do we have executive officers or directors. We are managed by Enbridge Management, as delegate of our General Partner, and the Named Executive Officers, or NEOs, are executive officers of Enbridge Management and our General Partner. Similarly, the directors are members of the boards of directors of Enbridge Management and our General Partner. Our General Partner and Enbridge Management are indirect subsidiaries of Enbridge, and we are a business unit of Enbridge. Our General Partner, Enbridge Management and Enbridge, through its affiliates, provide us with managerial, administrative, operational and director services pursuant to service agreements among them and us. Pursuant to these service agreements, we reimburse our General Partner, Enbridge Management and affiliates of Enbridge for the costs of these managerial, administrative, operational and director services, which costs include a portion of the compensation of the NEOs.
The boards of directors of Enbridge Management and our General Partner do not have compensation committees, nor do they have responsibility for approving the elements of compensation for the NEOs presented in the tables following this discussion. The boards of directors of Enbridge Management and our General Partner, as part of our annual budgeting process, however, do have responsibility for evaluating and determining the reasonableness of our overall budget. The budget includes compensation amounts to be allocated to us for managerial, administrative, operational and director support to be provided by our General Partner, Enbridge Management and Enbridge and its affiliates pursuant to the service agreements mentioned above. The budgeted amount of total compensation includes the portion of the compensation of the NEOs that will be allocated to us and is discussed in more detail below.
Since we do not have direct employees or directors, and our General Partner and Enbridge Management do not have responsibility for approving the elements of compensation for the NEOs, we, our General Partner and Enbridge Management do not have compensation policies. The compensation policies and philosophy of Enbridge govern the types and amounts of compensation of each of the NEOs. The NEOs at December 31, 2011 were:
•
Terrance L. McGill, President of Enbridge Energy Company, Inc., Senior Vice President of Enbridge Management and Director
•
Mark A. Maki, President of Enbridge Management, Senior Vice President of the General Partner and Director
•
Stephen J. Neyland, Vice President, Finance
•
Stephen J. Wuori, Executive Vice President, Liquids Pipelines and Director
•
Al Monaco, Executive Vice President, Gas Pipelines, Green Energy and International and Director
Messrs. Wuori and Monaco are also named executive officers of Enbridge. Mr. Wuori serves as President, Liquids Pipelines of Enbridge, and Mr. Monaco serves as President, Gas Pipelines, Green Energy & International of Enbridge. Since these individuals are also named executive officers of Enbridge, the Human Resources and Compensation Committee of the board of directors of Enbridge, or the HRC Committee, approves the elements of compensation of these individuals based on the recommendation of the chief executive officer of Enbridge, considering their positions within Enbridge on an enterprise-wide basis. Each of these executive officers completes a self-assessment. The chief executive officer of Enbridge documents the performance of each Enbridge executive officer during the year, reviews the compensation data provided by an outside consultant to the HRC Committee and makes a recommendation to the HRC Committee on the elements of compensation for those individuals. The HRC Committee reviews and approves the performance and compensation recommendations of the chief executive officer of Enbridge with respect to these executive officers.
The HRC Committee does not have responsibility for reviewing or approving compensation for employees, on an individual basis, who are not a part of Enbridge’s executive leadership team. Each business unit develops a salary increase budget recommendation, in consultation with the Enbridge corporate compensation department, based on a competitive analysis of the labor market for that business unit. These recommendations are presented, in summary and on a business unit basis, to the HRC Committee for approval. Individual salary increases are implemented after the HRC Committee approves the overall budget. Compensation adjustments for senior leadership of the various business units are recommended by their supervisors and reviewed by the executive leadership team of Enbridge in the aggregate before being recommended to the HRC Committee. The Enbridge executive leadership team, the chief executive officer of Enbridge and the HRC Committee do not review the elements of compensation for Messrs. McGill, Maki and Neyland on an individual basis. Mr. Monaco, a director of our General Partner and Enbridge Management and a member of the Enbridge executive leadership team, makes compensation recommendations for Messrs. McGill, Maki and Neyland, which are subject to the Enbridge enterprise-wide review process described above. Enbridge’s chief executive officer approves the aggregate of all individual salary increase recommendations, on an enterprise-wide basis, to ensure that compensation expense is within the budget approved by the HRC Committee. Each of the NEOs provides services to other affiliates of Enbridge and, therefore, his compensation is determined on the basis of his overall performance with respect to Enbridge and all of its affiliates and not solely based on his performance with respect to us.
We are a partnership and not a corporation for United States federal income tax purposes, and therefore, are not subject to the executive compensation tax deductible limitations of Internal Revenue Code §162(m). In addition, we are not the employer for any of the NEOs.
For a more detailed discussion of the compensation policies and philosophy of Enbridge, we refer you to a discussion of those items as set forth in the Executive Compensation section of the Enbridge Management Information Circular, or MIC, on the Enbridge website at www.enbridge.com. The Enbridge MIC is produced by
Enbridge pursuant to Canadian securities regulations and is not incorporated into this document by reference or deemed furnished or filed by us under the Exchange Act. We refer to the MIC to provide our investors with an understanding of the compensation policies and philosophy of the ultimate parent of our General Partner.
Elements of Compensation
The HRC Committee sets the compensation philosophy of Enbridge, which is approved by the Enbridge board of directors. Enbridge has a pay-for-performance philosophy and programs that are designed to be aligned with its interests, on an enterprise-wide basis, as well as the interests of its shareholders. A significant portion of total direct compensation of Enbridge’s senior management is dependent on actual performance measured against short and long-term performance goals of Enbridge, on an enterprise-wide basis, which are approved by the Enbridge board of directors. As a business unit of Enbridge, we contribute to its overall growth, earnings and attainment of performance goals. The following table presents our historical normalized operating results as a percentage of the normalized operating results of Enbridge for the preceding five years:
The elements of total compensation in 2011 for senior management of Enbridge, which include Messrs. Wuori and Monaco, are:
•
Base Salary-to provide a fixed level of compensation for performing day-to-day responsibilities, while balancing the individual’s role and competency, market conditions and issues of attraction and retention.
•
Short-term incentive-to provide a competitive, performance-based cash award based on pre-determined corporate, business unit and individual goals that measure the execution of the business strategy over a one-year period.
•
Medium-term and Long-term incentives-to recognize contributions and provide competitive, performance-based compensation comprised of performance stock units, performance-based stock options and incentive stock options that are tied to the share price of Enbridge common shares, and are mostly at-risk to motivate performance over the medium and long term.
•
Pension plan-to provide a competitive retirement benefit.
•
Savings plan-to promote ownership of Enbridge shares and to provide the opportunity to save additional funds for retirement or other financial goals.
•
Perquisites-to provide a competitive allowance to offset expenses largely related to the executive’s role.
•
Benefits-to provide security pertaining to health and welfare risks in a flexible manner to meet individual needs.
•
Employment agreements-to provide specific total compensation terms in situations of involuntary termination or change of control.
The elements of compensation for Messrs. McGill, Maki, and Neyland, are similar to those described above, except that none have an employment agreement, and they are not eligible for performance-based stock options. The HRC Committee makes determinations as to whether the enterprise-wide performance goals have been achieved and if adjustments are necessary to more accurately reflect whether those goals have been met or exceeded. For example, the HRC Committee may determine to disregard a non-cash gain or loss reflected in our results of operations that resulted from mark-to-market accounting for our derivative activities in determining whether certain goals have been met.
Base Salary
Base salary for the NEOs reflects a balance of market conditions, role, individual competency and attraction and retention considerations and takes into account compensation practices at peer companies of Enbridge. Increases in base pay for all NEOs are based primarily on competitive considerations.
Short-Term Incentive Plan
The Enbridge short-term incentive plan, or STIP, is designed to provide incentive for, and reward, the achievement of goals that are aligned with the Enbridge annual business plan. The target short term incentive reflects the level of responsibility associated with the role and competitive practice and is expressed as a percentage of base salary. Actual incentive awards can range from zero to two times the target. Awards under the plan are based on performance relative to goals achieved at the Enbridge corporate level, business unit level and individual level. Performance relative to goals in each of these areas is reflected on a scale of zero to two; zero indicates performance was below threshold levels, one indicates that goals were achieved and two indicates that performance was exceptional. Enbridge corporate performance is a significant factor in determining incentive awards.
The following is a summary for 2011 of the incentive targets, payout range, and relative weighting between the Enbridge corporate, business unit and individual performance:
(1) All values are expressed as percentages of base salary.
The overall performance multiplier and STIP are calculated as follows:
Performance multiplier
STIP
Corporate target incentive opportunity x (0-2)
Base Salary $
+
Business unit target incentive opportunity x (0-2)
x
Target STIP%
+
Individual target incentive opportunity x (0-2)
x
Overall performance multiplier (0-2)
=
Overall performance multiplier (0-2)
=
$ Short term incentive award
Enbridge Corporate Performance
Beginning in 2011, company-wide performance was changed to be measured by adjusted earnings per share, or EPS, rather than adjusted return on equity. This is a metric that focuses on return to shareholders and is aligned with how Enbridge believes investors assess its annual performance.
The adjusted EPS metric represents a significant component of Enbridge’s corporate named executives’ short-term incentive award at 25%. Enbridge’s 2011 EPS guidance range was $1.38 - $1.48 as approved by the Enbridge Board at the start of the year. Actual performance was $1.48. Adjustments are made to ensure the result is a fair reflection of performance. Approximately $119 million of net gains/earnings were adjusted out of the calculation, including mark to market gains, gains and losses from asset dispositions. The corporate multiplier ranges from 0 to 2, with 1.0 meaning that the performance measure was met. Based on Enbridge’s performance in 2011, the corporate multiplier was set at 2.0.
Enbridge Business Unit Performance
Business unit performance measures vary among the NEOs to reflect the annual business plans and operations for which each NEO is accountable. Performance is measured against targets that are established at the beginning of the year. The detailed business unit performance measures for each of the NEOs, other than Mr. Monaco, are set forth in the tables which follow.
For Messrs. McGill, Maki and Neyland, each of the business units for their scorecards are being weighted by business unit and the consolidated multiplier for the Gas Pipelines, Green Energy and International business unit. The business unit performance accounts for 70% of the overall business unit multiplier with the remaining 30% comprised of the consolidated performance of the Gas Pipelines, Green Energy and International business unit. For 2011, the combined Gas Pipelines, Green Energy and International multiplier was 1.64, resulting in a weighted multiplier of 0.49.
The business performance measure for each NEO is designed to reflect their multiple responsibilities at Enbridge. Mr. McGill’s performance measure is calculated at 75% for the Gas Transportation business unit and 25% for the Gas Development business unit, resulting in a business unit multiplier of 1.28 out of 2.0. Mr. Maki’s performance measure is calculated at 50% for the Gas Transportation business unit and 50% for the Shared Services business unit, resulting in a business unit multiplier of 1.30 out of 2.0. Mr. Neyland’s performance measure is calculated at 100% for the Shared Services business unit, resulting in a business unit multiplier of 1.44 out of 2.0. Mr. Wuori’s performance measure is calculated at 100% for the Liquids business unit, resulting in a business unit multiplier of 1.78 out of 2.0. Mr. Monaco’s performance measure takes into consideration performance in his role as Vice President, Gas Pipelines, Green Energy & International of Enbridge across multiple business units, resulting in a business unit multiplier of 1.64 out of 2.0.
The business unit multipliers upon which the NEO’s STIP is calculated are included in the following tables. They reflect rounding and range from 0 to 2, with 1.0 meaning that the performance measure was met. The business units include the Partnership, but also include portions of other Enbridge businesses.
Individual Performance
Each of the NEOs establishes individual goals at the beginning of each year by which individual performance is measured. These goals are based on areas of strategic and operational emphasis related to his respective portfolio, development of succession candidates, employee engagement, community involvement and leadership. The level of attainment of individual performance goals is determined by the chief executive officer of Enbridge for Messrs. Wuori and Monaco, and by Mr. Monaco and for Messrs. McGill, Maki, and Neyland.
Summary of 2011 STIP Performance Multipliers
The following table summarizes the corporate, business unit and individual performance multipliers for each executive, associated weights and overall performance multiplier result:
NEO
Corporate
Performance (a)
(Weight x Multiplier)
Business Unit
Performance (b)
(Weight x Multiplier)
Individual
Performance (c)
(Weight x Multiplier)
Overall
Performance
Multiplier
(a+b+c)
Terrance L. McGill
25% x 2.00 = 0.50
50% x 1.28 = 0.64
25% x 1.50 = 0.38
1.52
Mark A. Maki
25% x 2.00 = 0.50
50% x 1.30 = 0.65
25% x 1.50 = 0.38
1.53
Stephen J. Neyland
25% x 2.00 = 0.50
50% x 1.44 = 0.72
25% x 1.50 = 0.38
1.60
Stephen J. Wuori
25% x 2.00 = 0.50
50% x 1.78 = 0.89
25% x 1.95 = 0.49
1.88
Al Monaco
25% x 2.00 = 0.50
50% x 1.64 = 0.82
25% x 1.75 = 0.44
1.76
Based on the overall performance multiplier determined from the above table, short term incentive awards for our executives were calculated as follows:
(1) The calculated STIP may differ from the amounts presented due to rounding.
(2) The dollar amounts presented for Messrs. Wuori and Monaco have been converted from Canadian dollars, or CAD, to United States dollars, or USD, using the average exchange rate for 2011 of $0.9891 CAD = $1 USD.
The calculated STIP may be adjusted for Messrs. Wuori and Monaco by a recommendation of the chief executive officer of Enbridge to the HRC Committee, which must approve any such recommendation. Mr. Monaco may recommend adjustments to the calculated STIP for Messrs. McGill, Maki, and Neyland, which recommendations are reviewed by Enbridge’s executive leadership team for fairness and consistency with enterprise-wide compensation.
The actual STIP for all employees of Enbridge, including the NEOs, was adjusted by the board of directors of Enbridge, based upon the recommendation of the chief executive officer of Enbridge. This recommendation was made in recognition of the significant accomplishments of Enbridge as a whole over the year, including being the single largest positive point contributor to the Toronto Stock Exchange index composite. As a result of this recommendation, the board of directors of Enbridge approved an overall increase of 10 percent to the STIP payout for each employee, which is reflected in the actual STIP in the table above.
Medium and Long-Term Incentives
Enbridge has four plans that make up its medium and long-term incentive program for senior management:
•
A performance stock unit plan, or PSUP, which includes three-year phantom shares with performance conditions that impact payout;
•
A performance-based stock option plan, or PSOP, that includes eight-year options to acquire Enbridge shares with performance and time vesting conditions;
•
An incentive stock option plan, or ISOP, which includes 10-year stock options to acquire Enbridge shares with time vesting conditions; and
•
A restricted stock unit plan, or RSUP, which grants Restricted Stock Units, or RSUs, to director and manager-level employees on an annual basis. RSUs have the same value as a common share of Enbridge stock, but are not traded in external financial markets. Mr. Neyland is the only NEO that participated in this plan for the years ended December 31, 2010, and 2009.
Only the NEOs of Enbridge, including Messrs. Wuori and Monaco, are eligible to receive grants under the PSOP.
Enbridge believes that the combination of these medium and long-term incentive plans aligns a component of executive compensation with the interests of Enbridge shareholders beyond the current year. A significant percentage of the value of the annual long-term incentive awards to the NEOs is contingent on meeting performance criteria, share price targets under the PSOP and performance measures under the PSUP. Specifically, when earnings targets are achieved, the share price increases over the long term and when Enbridge shares perform well relative to its peer organizations, the value of the medium and long-term incentive is maximized for the executives while also benefitting shareholders. The mix of medium and long-term incentive programs and total target medium and long-term incentive opportunity, expressed as a percentage of base salary, are as follows:
(1) All values are expressed as percentages of base salary.
Actual award values, expressed as a percentage of base salary, range between zero and 200% of the target medium and long-term incentive opportunity, based on individual performance history, succession potential, retention considerations and market competitiveness.
PSUP
The PSUP is a three-year performance-based unit plan. Performance measures and targets are established at the start of the term to reflect the mid-term objectives of Enbridge in the execution of its strategic plan. Achievement of the performance targets can decrease or increase the final award value in a range of zero to 200%. PSUs do not involve the issuance of any shares of stock of Enbridge. Throughout the term, units are added to the grants as if dividends were received and reinvested into additional units based on the actual dividend rate for shares of Enbridge stock. Awards are granted annually and paid in cash at the end of a three-year term based on two performance criteria that were established for the 2011 grants, each of which weighted 50%, and price to earnings ratio, or P/E Ratio.
The EPS performance reflects Enbridge’s commitment to its shareholders to achieve earnings that meet or exceed industry growth rates. Enbridge established the EPS target to reflect performance that would be consistent with the average growth rate forecast of peer companies over a comparable time period. The EPS required to achieve a two multiplier (the maximum) would demonstrate achievement of the long-range strategic plan and would represent exceptional performance to the investment community. Performance must at least meet 3% compound annual growth in EPS for a threshold payment, below which the multiplier would be zero.
The second performance criterion is the Enbridge P/E Ratio relative to a selected comparator group of companies. Enbridge’s price to earnings performance has historically been very strong, therefore performance below the median of the peer group results in a multiplier of zero, performance between the median and 75th percentile results in a multiplier of one and performance above the 75th percentile results in a multiplier of two. The following table presents the comparator group for the P/E Ratio.
Price/Earnings Ratio-Comparator Group of Companies
Ameren Corp.
Canadian Utilities
Centerpoint Energy Inc.
Emera Inc.
Fortis Inc.
National Fuel Gas Corp.
Nisource Inc.
OGE Energy Corp.
Oneok Inc.
PG&E Corp.
Sempra Energy
Spectra Energy Corp.
TransAlta Corp.
TransCanada Corporation
This peer group of companies was selected because they are all capital market competitors of Enbridge, have a similar risk profile and are in a comparable sector.
PSOP
Performance stock options align the Enbridge executives, including Messrs. Wuori and Monaco, with its shareholders by tying vesting to the achievement of defined performance criteria. Once the performance targets are met, exercisability is subject to time requirements. Enbridge grants performance stock options to its executives approximately every five years with eight year terms that become exercisable over a period of five years at a rate of 20 percent per year provided the performance criteria are met. Enbridge did not grant any performance stock options in 2011. Performance stock options were most recently granted in 2007 to the executive officers at that time, and in 2008 to Mr. Monaco when he was appointed to the Enbridge executive team. The performance criteria for the 2007 and 2008 performance stock options are Enbridge share price targets of $25 CAD and $27.50 CAD, respectively, which must be met by February 2014. The approach used to determine the share price targets was determined from the Enbridge long-range plan which is integrated with the strategic growth plans of Enbridge and historic industry P/E Ratio information. As of December 31, 2011, both share price targets for the 2007 and 2008 grants have been meet, therefore 80% of the 2007 grant is exercisable and 60% of the 2008 grant is exercisable.
ISOP
Regular stock options focus the Enbridge executives on increasing shareholder value over the long-term through share price appreciation. Stock options are granted annually to Enbridge executives entitling them to acquire Enbridge shares at a price defined at the time of grant. These options become exercisable over a period of four years at a rate of 25% per year and the term of the grant is ten years.
RSUP
The RSUP is a plan that awards RSUs to director and manager-level employees based on their base salary, an RSU target incentive opportunity and the share price. Additionally the number of units can be adjusted for factors including performance, skill, potential and external market competitiveness. The final awards may be 0-150% of the RSU target incentive opportunity. Grants are made annually in February of each year and have a 35 month term. Throughout the term, units are added to the grants as if dividends were received and reinvested into additional units based on the actual dividend rate for shares of Enbridge stock. At the end of the term, the units are paid in cash based on the weighted average price of an Enbridge share on the NYSE for 20 trading days prior to the end of the term. Mr. Neyland is the only NEO that participated in this plan for the years ended December 31, 2010, and 2009.
Service Agreements and Allocation of Compensation to the Partnership
As discussed above, our General Partner, Enbridge Management and affiliates of Enbridge provide managerial, administrative, and operational and director services to us pursuant to service agreements and we reimburse them for the costs of such services. Through an operational services agreement among Enbridge, affiliates of Enbridge and us, we are charged for the services of executive management resident in Canada, including the services of two of the NEOs. Through a general and administrative services agreement among us, our General Partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of our General Partner, which we refer to as EES, we are charged for the services of executive management resident in the United States, including three of the NEOs. See Item 13. Certain Relationships and Related Transactions, and Director Independence-Other Related Party Transactions for a discussion of these two agreements.
In connection with our annual budget process, we determine a budgeted allocation rate, which represents an estimated average percentage of expected time that will be spent by each of the NEOs on our business during the succeeding year. The NEOs provide input as to what those estimated percentages should be. Those estimates are revised each year based on historical experience and business plans for the following year. The NEOs do not keep logs of their time spent on our matters. Since the allocation rate is estimated, the actual time spent by an NEO on our behalf may vary from the budgeted allocation rate, and we may be allocated more or less of that NEO’s compensation than the actual percentage of his time spent on our behalf in a given year. There were no other adjustments recognized for the years ended December 31, 2011, 2010, and 2009, for amounts reimbursed to us by Enbridge and its affiliates for the portion of the NEOs’ compensation allocated to us. For 2011, the percentage of time estimated to be spent by each of the NEOs on our matters was:
•
Terrance L. McGill - 86%
•
Mark A. Maki - 86%
•
Stephen J. Neyland - 86%
•
Stephen J. Wuori - 25%
•
Al Monaco - 40%
For services provided under the operational services agreement, as part of the annual budget process, we, Enbridge and affiliates of Enbridge, which we refer to as the Canadian service providers, agree on the amount to be allocated to us, which represents an estimate of a pro-rata reimbursement of each Canadian service provider’s estimated annual departmental costs, net of amounts charged to other affiliates and amounts identifiable as costs of that Canadian service provider. The Canadian service providers charge us a monthly fixed fee based on the budgeted amount.
For services provided under the general and administrative services agreement, base salary costs of EES are allocated to us based on the percentage of time spent by EES employees, including three of the NEOs, on our behalf compared with the total time of all EES employees. We are also allocated a portion of the equity-based compensation expense of EES as determined in accordance with U.S. GAAP. Pension expenses of EES, other than expenses under Enbridge’s nonqualified supplemental pension plan for U.S.-domiciled employees, which we refer to as the SPP, are allocated to us based on the proportion that the total headcount of EES employees assigned to us bears to the total headcount of EES. For this purpose, an employee of EES is deemed to be assigned to us if he or she works on assets we own. Pension expenses of EES attributable to the SPP are allocated to us based upon the average budgeted allocation rate. EES allocates to us that portion of its compensation expense for the STIP equal to the total salaries of employees who perform work for us multiplied by the average budgeted allocation rate divided by EES’s total salary expense.
The compensation of our NEOs included in the tables below is established by Enbridge as described above. We have included in the following tables the full amount of compensation and related benefits provided for each of the NEOs for 2011, 2010, and 2009, or such shorter period of time for which the individuals have served as
NEOs, together with the budgeted estimate of the approximate time spent by each NEO on our behalf and the approximate amount of compensation cost allocated to us for the years ended December 31, 2011, 2010, and 2009, as applicable. Since the amount of NEO compensation allocated to us is based on estimates of time spent on our behalf by the particular NEO, the compensation amounts allocated to us may not exactly reflect the amount of time that a certain NEO devoted to our business.
SUMMARY COMPENSATION TABLE
(1) The compensation expense associated with Performance Stock Units, or PSUs, for each NEO, and the Restricted Stock Units, or RSU’s with respect to Mr. Neyland that are reflected in this column represent one-third of the market value for each year the PSUs and RSUs are outstanding and are measured based on the number of respective units granted, dividends reinvested, the percentage vested (33%) for each year, the actual or forecast performance multiplier with respect to the PSUs, and the market value or payout amount at the end of each period. For example, 2011 includes one-third of the market values for PSUs and RSUs issued in 2011, 2010 and 2009. In 2011, the compensation expense recorded for PSUs granted in 2011, 2010 and 2009 include performance multipliers for the respective years, which are estimated at December 31, 2011 to be 2.0 and the actual multiplier of 2.0 for 2010 and 2009 based upon the expected or achieved levels of performance in relation to established targets for each year. RSUs do not have performance multipliers used in determining the payout amount. For years prior to the year a payout is made, a performance multiplier is forecast based upon the progress made in attaining the established performance criteria unless the actual multiplier has been determined. Refer also to footnote 3 of the Grants of Plan-Based Awards table for additional discussion regarding the PSUs. Mr. Neyland received RSUs in 2010 and 2009. The market value for each PSU and RSU grant represents the weighted average closing price of an Enbridge Share as quoted on the NYSE for the USD denominated PSUs and RSUs and the Toronto Stock Exchange, or TSX, for CAD denominated PSUs for the 20 consecutive days prior to the end of the performance period. PSUs granted for 2011, 2010, and 2009 were denominated in both USD and CAD, while RSUs granted to Mr. Neyland are denominated in only USD. The PSU expense in CAD is converted to USD based on the average exchange rate for the 20 trading days prior to the end of the performance period. The PSUs and RSUs were granted on January 1, 2011, 2010 and 2009, respectively. The actual payout amounts for the 2009 PSUs that vested in 2011 were based on average share prices of $35.75 USD and $36.38 CAD, for the respective USD denominated PSUs and CAD denominated PSUs and $34.57 USD for the 2009 RSUs that vested in 2011. Compensation expense as reported in the Summary Compensation Table above for Stock Awards has been determined using the following assumptions:
(a) All values adjusted for 2011 stock split.
(2) Under the authoritative accounting provisions for share-based payments, the annual expenses for option awards that are granted under the Enbridge Incentive Stock Option Plan (2002 and 2007), or ISOP, and the PSOP are determined by computing the fair value of the options on the grant date using the Black-Scholes option pricing model for ISOPs and the Bloomberg barrier option valuation model for PSOPs. Enbridge did not grant any PSOPs to the NEOs during 2011. The following assumptions were used in computing the fair value of the options on the grant date for the respective option pricing model employed and the indicated year:
The fair value of options granted as computed using the above assumptions is expensed over the shorter of the vesting period for the options and the period to early retirement eligibility. The exercise price and fair value information for all option grants has been converted to USD using the exchange rates as set forth in the tables below. The fair values of all grants on the grant date have been converted to USD using the average exchange rates, representing the exchange rate for the period during which the expense was recognized.
(a) All prices have been adjusted for 2011 stock split
(a) All fair values adjusted for 2011 stock split
(3) Non-equity incentive plan compensation represents awards that are paid in February of each year for amounts that are earned in the immediately preceding fiscal year under the Enbridge STIP as discussed in the above Compensation Discussion and Analysis.
(4) The table which follows labeled “All Other Compensation” sets forth the elements comprising the amounts presented in this column.
(5) Mr. Wuori is also an executive officer of Enbridge with responsibility for other affiliates of Enbridge in addition to those for our General Partner and Enbridge Management. Mr. Wuori is compensated by affiliates of Enbridge in CAD, which we have converted to USD using the weighted average exchange rates for the years ended December 31, 2011, 2010 and 2009 of $0.9891 CAD = $1USD, $1.0299 CAD = $1USD, and $1.142 CAD = $1USD, respectively. The costs associated with the PSUs and options Mr. Wuori was granted in 2011, 2010 and 2009 were borne by Enbridge and other affiliates where he is also an officer. We are allocated a portion of the remaining elements of Mr. Wuori’s compensation pursuant to the terms of the Operational Services Agreement among Enbridge, Enbridge Operational Services, Inc., or EOSI, and Enbridge Pipelines, both subsidiaries of Enbridge.
(6) Mr. Monaco is also an executive officer of Enbridge with responsibility for other affiliates of Enbridge in addition to those for our General Partner and Enbridge Management. Mr. Monaco is compensated by affiliates of Enbridge in CAD, which we have converted to USD using the weighted average exchange rates for the years ended December 31, 2011, 2010 and 2009 of $0.9891 CAD = $1USD, $1.0299 CAD = $1USD and $1.142 CAD = $1 USD, respectively. The costs associated with the PSUs and options Mr. Monaco was granted in 2011, 2010 and 2009 were borne by Enbridge and other affiliates where he is also an officer.
(7) Messrs. Wuori and Monaco were elected officers of Enbridge Management and our General Partner in January 2008, prior to which they held other responsibilities with Enbridge.
ALL OTHER COMPENSATION
(For the years ended December 31, 2011, 2010 and 2009)
(1) The amounts reported in this table for Messrs. Wuori and Monaco, our NEOs domiciled in Canada, have been converted from CAD to USD using the average exchange rate for the years ended December 31, 2011, 2010 and 2009 of $0.9891 CAD = $1 USD, $1.0299 CAD = $1 USD and $1.142 CAD = $1 USD, respectively.
(2) Flexible benefits for our U.S.-domiciled NEOs represent a perquisite allowance that is paid in cash as additional compensation. Our NEOs domiciled in Canada also receive flexible benefits based on their family status and base salary. For our NEOs that are domiciled in Canada, the flexible benefits can be used to purchase additional benefits, paid in cash, or be applied as contributions to the Enbridge Stock Purchase and Savings Plan; or paid as additional compensation.
(3) Our NEOs that are domiciled in the United States and participate in the Enbridge Employee Services, Inc. Savings Plan, referred to as the 401(k) Plan, may contribute up to fifty percent of their base salary, which is matched up to five percent by Enbridge. Both individual and matching contributions are subject to limits established by the Internal Revenue Service. Enbridge contributions are used to purchase Enbridge shares at market value and employee contributions may be used to purchase Enbridge shares or 23 designated funds.
(4) Other benefits include professional financial services, parking, home security, air travel benefit and internet services.
Enbridge does not maintain any compensation plans for the benefit of the NEOs under which equity interests in us or Enbridge Management may be awarded. However, Enbridge allocates to us a portion of the compensation expense it recognizes in accordance with the authoritative guidance for share-based compensation in connection with recording the fair value of its performance and restricted stock units and outstanding stock options granted to certain of its officers, including the NEOs. The costs we are charged with respect to option grants represent a portion of the costs determined in accordance with U.S. GAAP.
The PSUs are granted to the NEOs pursuant to the PSUP and stock options are granted pursuant to the ISOP and the PSOP. Awards under these plans provide long-term incentive and are administered by the HRC Committee of Enbridge. Although stock options remain outstanding that were granted under the Enbridge Incentive Stock Option Plan (2002), no further stock options will be granted under this plan. The performance stock units granted in 2009 through 2011 to our U.S.-domiciled NEOs are denominated in USD while those granted to NEOs domiciled in Canada are denominated in CAD. The three tables which follow set forth information concerning performance stock units and stock options granted during the year ended December 31, 2011, outstanding at December 31, 2011 and the number of awards vested and exercised during the year ended December 31, 2011 by each of the NEOs.
(1) The abbreviated plan names are defined as follows:
a. PSUP refers to the Enbridge Performance Stock Unit Plan (2007), an equity- based incentive plan.
b. ISOP refers to the Enbridge Incentive Stock Option Plan (2007), a qualified stock option plan.
c. STIP refers to the Enbridge Short Term Incentive Plan (2006), a non-equity performance-based incentive plan.
(2) The estimated future payouts under non-equity incentive award plans represents awards under the Enbridge STIP as presented above in the Compensation Discussion and Analysis under the section labeled Short-Term Incentive Plan.
(3) Our NEOs are eligible to receive annual grants of PSUs, under the PSUP, an equity-based, long-term incentive plan, administered by a committee of the board of directors of Enbridge. The initial value of each of these PSUs on the grant date is equivalent to the volume weighted average closing price of one Enbridge share as quoted on the TSX or NYSE for the 20 trading days immediately preceding the start of the performance period. The initial PSUs granted are increased for quarterly dividends paid during the three-year period on an Enbridge share that are reinvested in additional PSUs. Awards under the PSUP are paid out in cash at the end of a three-year performance cycle based on: (1) an EPS target for Enbridge based on the long range plan of the organization and (2) the P/E Ratio of an Enbridge share relative to a defined group of peer organizations established in advance by a committee of the board of Enbridge. Payments under the PSUP may be increased up to 200 percent of the original award when Enbridge exceeds the established targets. If Enbridge fails to meet threshold performance levels, no payments are made under the PSUP. Dividends are paid on the PSUs which are invested in additional PSUs at the then current market price for one share of Enbridge common stock, which are not included in the estimated future payout amounts, but have been included in the compensation associated with stock awards in the Summary Compensation Table. Enbridge does not issue any shares in connection with the PSUP.
The threshold at which PSUs are paid out represents 62.5 percent of the number of PSUs initially granted increased by additional PSUs resulting from reinvested dividends and is the lowest level at which PSUs will be paid out based on the performance criteria discussed above. The target level at which PSUs are issued represents 100 percent of the number of PSUs initially granted increased by additional PSUs resulting from reinvested dividends and attainment of the established performance criteria. The maximum level at which PSUs may be issued is 200 percent of the number of PSUs initially granted and may occur when Enbridge exceeds the established performance criteria. PSUs vest at the end of a three year performance period that begins on January 1 of the year granted and during the term the PSUs are outstanding, a liability and expense are recorded by Enbridge based on the number of PSUs outstanding and the current market price of an Enbridge share with an assumed performance multiplier that is determined quarterly based on progress towards achieving the established performance criteria, until the end of the performance period at which point the performance multiplier is known. The grant date fair value for each PSU granted to each of our U.S.-based NEOs was $27.71 USD, representing the volume weighted average closing price of one Enbridge share as quoted on the NYSE for the 20 trading days immediately preceding the start of the performance period that began on January 1, 2011. The grant date fair value for each PSU granted to each of our Canadian based NEOs was $27.92 CAD, representing the volume weighted average closing price of one Enbridge share as quoted on the TSX for the 20 days immediately preceding the start of the performance period that began on January 1, 2011. We have converted the grant date fair value for the Canadian PSU grants made from CAD to USD using an exchange rate of $1.0073 CAD = $1 USD, representing the weighted average noon rate for 20 trading days immediately preceding the performance period that began on January 1, 2011.
(4) The ISOP is administered by a committee of the Enbridge board of directors and if an option is granted during a trading blackout period, the exercise price of an option grant is determined as the weighted average trading price of an Enbridge share on the TSX or NYSE for the five trading days immediately prior to the effective date of the option. In the event an option grant is granted during a period a trading blackout is not in effect, the exercise price of the option grant is equal to the last reported sales price on the TSX or NYSE for the day immediately preceding the grant date. During 2011, each of the NEOs received grants of Enbridge incentive stock options that upon exercise may be exchanged for an equivalent number of shares of Enbridge common stock. The exercise price of the incentive stock options at the time of grant was $28.78CAD for Canadian-domiciled NEOs and $28.99 USD for NEOs domiciled in the United States.
The amounts included as the grant date fair value for the 2011 incentive stock option awards represent the amount determined by computing the fair value of the options in accordance with the authoritative guidance for share-based payments on the grant date using the Black-Sholes option pricing model with the following assumptions:
The fair value of options granted as computed using these assumptions is $5.11 USD or $4.00 CAD. The $4.00 CAD option value and the $28.78 CAD exercise price have been converted to USD using an exchange rate of $0.9885 CAD = $1 USD representing the noon buying rate in New York for transfers of CAD on the grant date of February 14, 2011. The grant date fair value is expensed over the shorter of the vesting period for the options, generally 4 years, and in the year granted for employees age 55 and over and eligible for early retirement. Mr. McGill was aged 55 or over and eligible for early retirement as of the grant date and as a result the grant date fair value of options they were awarded is expensed in the year granted.
(5) The PSOP is administered by a committee of the Enbridge board of directors and if a performance option is issued during a trading blackout period, the exercise price of a performance option grant is determined as the weighted average trading price of an Enbridge share on the TSX or NYSE for the five trading days immediately prior to the effective date of the performance option. In the event an option grant is issued during a period a trading blackout is not in effect, the exercise price of the performance option grant is equal to the last reported sales price on the TSX or NYSE for the day immediately preceding the grant date. PBSOs are similar to the incentive stock options, except that the quantities become exercisable subject to both the achievement of specified share price targets and time requirements.
One half of the PBSOs become exercisable if the first share price hurdle is achieved and 100% of the grant becomes exercisable if the second share price hurdle is achieved within a 6 1/2 year time period. The term of each grant is 8 years provided the performance criteria are met. PBSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge share for each option held when the specified term and share price targets are met. The grant date fair value is expensed over the shorter of the vesting period for the options (generally 5 years) and the period to early retirement eligibility. Enbridge did not grant PBSOs to any of the NEOs during the year ended December 31, 2011.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END
(1) Each ISO award has a 10-year term and vests pro-rata as to one fourth of the option award beginning on the first anniversary of the grant date; thus the vesting dates for each of the option awards in this table can be calculated accordingly. As an example, for Mr. Maki’s grant that expires on February 14, 2021, the grant date would be ten years prior or February 14, 2011 and as a result, the remaining unexercisable amounts become fully vested on February 14, 2015 representing 4 years following the grant date.
(2) PBSOs were provided to certain of our NEOs on September 16, 2002, August 15, 2007 and February 19, 2008 and are similar to the incentive stock options, except that the quantities that become exercisable are subject to both time and performance requirements. PBSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge share for each option held when the specified time and performance conditions are met. The PBSOs granted September 16, 2002, became exercisable, as to 50 percent of the grant, when the price of an Enbridge Share exceeded $30.50 for 20 consecutive days during the period September 16, 2002 to September 16, 2007, and became exercisable as to 100 percent when the price of an Enbridge share exceeded $35.50 for 20 consecutive days during the same period. As a result of achieving the established performance criteria, the initial five year term of the options was extended to 8 years expiring on September 16, 2010. In addition to the performance hurdles, the PBSOs are also time vested 20% annually over 5 years. As of December 31, 2007, 100 percent of the PBSOs granted September 16, 2002 had vested and were exercisable. As of December 31, 2011, both share price targets for the PBSOs granted August 15, 2007 and February 19, 2008 were met, therefore 80% of the 2007 grant and 60% of the 2008 grant were vested or exercisable.
(3) The exercise prices of the ISOs and PBSOs issued during 2006 and prior years are denominated in CAD and all exercise prices prior to 2011 have been adjusted for the 2011 stock split. Beginning in 2007, ISOs and PBSOs granted to NEOs domiciled in the United States are denominated in USD while those NEOs domiciled in Canada are denominated in CAD. The ISOs and PBSOs denominated in CAD have been converted to USD using the exchange rate on the grant dates as set forth below:
(4) The unearned shares, units or other rights that have not vested under stock awards represent PSUs for which the performance criteria discussed in footnote number 3 of the Grants of Plan-Based Awards table have not been achieved. The PSUs become vested upon achieving the established performance criteria. The amounts represented in the column are the number of units that have not vested at the closing share price of one Enbridge share on the NYSE at $37.41 per share or the TSX at $38.09 per share converted to USD of $37.45 per share at the conversion rate of $1.0170 CAD = $1 USD. The market or payout values presented assume a performance multiplier of 2.0 for PSUs granted in 2011, 2010 and 2009, which amounts represent the maximum level attainable based on forecasts of performance at December 31, 2011.
OPTION EXERCISES AND STOCK VESTED
(1) For Mr. Neyland, the number of shares acquired on vesting for stock awards represents the number of RSUs issued in 2009 increased by the number of additional units obtained from reinvesting dividends received. The value realized on vesting is determined based on the weighted average price of Enbridge stock for 20 trading days prior to the end of the term on December 1, 2011, which was $34.57 USD.
(2) The number of shares acquired on vesting for stock awards represents the number of PSUs issued in 2009 and the related dividends paid that were used to acquire additional PSUs, all of which matured on December 31, 2011. As discussed in footnote number 3 of the Grants of Plan-Based Awards table, no shares are issued with respect to the PSUs that become vested; rather, cash is paid in an amount based on the value of an Enbridge share at the maturity date and the level of achievement of the established performance goals. The payout for the PSUs granted in 2009 is expected to occur on or about March 15, 2012.
(3) The value realized on vesting is determined based on the final value of an Enbridge share of $35.75 USD for the NEOs domiciled in the U.S. or $36.38 CAD for the NEOs domiciled in Canada. In each case the share price is multiplied by a 2.0 performance factor multiplied by the number of PSUs, and is then converted to USD, as applicable, using an exchange rate of $1.0238 CAD = $1USD for the PSUs that matured on December 31, 2011.
Pension Plan
Enbridge sponsors two basic pension plans, the Retirement Plan for the Employees’ of Enbridge Inc. and Affiliates, or EI RPP, and the Enbridge Employee Services, Inc. Employees’ Pension Plan, or QPP. These plans provide defined pension benefits and cash balance benefits, and cover employees in Canada and the United States, respectively. Both plans are non-contributory. Enbridge also sponsors supplemental nonqualified retirement plans in both Canada, referred to as EI SPP, and the United States, referred to as US SPP, which provide defined pension benefits for the NEOs in excess of the tax-qualified plans’ limits. We collectively refer to the EI RPP, the QPP, the EI SPP and the US SPP as the “Pension Plans.” Defined pension benefits under the Pension Plans are based on the employees’ years of service and final average remuneration with an offset for Social Security benefits, while cash balance benefits are based on annual payout and interest credits to notional member accounts. Defined pension benefits are partially indexed to inflation after a named executive officer’s retirement.
For service prior to January 1, 2000, the Pension Plans provide a yearly pension payable in the normal form (60 percent joint and last survivor) equal to: (a) 1.6 percent of the average of the participant’s highest annual salary during three consecutive years out of the last ten years of credited service multiplied by (b) the number of credited years of service. For Mr. Wuori, the average salary also includes the highest three pensionable bonuses out of the last five years of continuous service, represented by the greater of 50% of the actual bonus paid or the lesser of the actual or target bonuses. The pension is offset, after age 65, by 50 percent of the participant’s Social Security benefit, pro-rated by years in which the participant has both credited service and Social Security coverage. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service, or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the United States and Canadian plans are indexed at 50 percent of the annual increase in the United States and Canadian consumer price index, respectively. For three years prior to January 1,
2000, Mr. Monaco elected to participate in the defined contribution option of the EI RPP. Mr. Monaco will receive a benefit at retirement associated with his participation in the defined contribution option of the EI RPP equal to the amounts contributed on his behalf and the earnings attributed to such amounts.
For service after December 31, 1999, the Pension Plans provide for senior management employees, including the NEOs, a yearly pension payable in the normal form (60 percent joint and last survivor) equal to: (a) 2 percent of the sum of (i) the average of the participant’s highest annual base salary during three consecutive years out of the last ten years of credited service and (ii) the average of the participant’s three highest annual performance bonus periods, represented in each period by 50 percent of the actual bonus paid, in respect of the last five years of credited service, multiplied by (b) the number of credited years of service. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the Plan are indexed at 50 percent of the annual increase in the consumer price index. For Mr. Neyland, QPP service after December 31, 2001 but prior to becoming a senior management employee includes 2.5 years of cash balance service, with annual pay credits based on his age and service with Enbridge.
Plan benefits that exceed maximum pension rules applicable to qualified plan benefits are paid from the EI SPP and US SPP. Other trusteed pension plans, with varying contribution formulae and benefits, cover the balance of employees.
Mr. Monaco accumulates pension credits equal to 2.5% for each year of service from January 1, 2008 to December 31, 2013.
The table below illustrates the total annual pension entitlements at December 31, 2011 assuming the eligibility requirements for an unreduced pension have been satisfied. We have converted pensions payable in CAD into USD at the rate of $1.017 CAD = $1.00 USD, the exchange rate at December 31, 2011. The present value of the accumulated benefits has been determined under the accrued benefit valuation method with the following assumptions:
(1) This is age 60 for all executives except for Messrs. Wuori and Maki, who are eligible for an unreduced pension at age 55.
PENSION BENEFITS
(1) Mr. Monaco’s EI RPP Service includes three years spent in defined contribution component of the Pension Plan. The current defined contribution balance has been included in the EI RPP accumulated benefit.
Employment and Severance Agreements
Enbridge entered into an executive employment agreement with each of Stephen J. Wuori, Executive Vice President-Liquids Pipelines of Enbridge Management and our General Partner, and Al Monaco, Director of Enbridge Management and our General Partner and President, Gas Pipelines, Green Energy and International of Enbridge. The agreements for Mr. Wuori were entered into effective April 14, 2003 and were amended effective June 24, 2004. On March 10, 2009, Mr. Monaco executed an employment agreement with Enbridge. Prior to that date, Mr. Monaco did not have an employment agreement with us or any Enbridge affiliate. The term of each of the agreements continues until the earlier of the applicable executive officer’s voluntary retirement in accordance with Enbridge’s retirement policies for its senior employees, voluntary resignation, death or termination of employment by Enbridge of the applicable executive officer. Messrs. McGill, Maki and Neyland do not have an employment agreement with us or any other Enbridge affiliate.
Each of the agreements provides that Enbridge will pay severance benefits to each of Messrs. Wuori and Monaco as set forth in the table below, except as noted below in respect of Mr. Monaco’s agreement, if such executive officer’s employment is terminated: (1) involuntarily without cause or because of the disability of such executive officer; (2) on the election of such executive officer within 90 days following a constructive termination; (3) on the election of such executive officer within 90 days following the one-year anniversary of a change in control of Enbridge, other than certain types of changes of control initiated by management or the board of directors of Enbridge; and (4) by Enbridge within one-year of certain types of changes of control of Enbridge, which change of control is initiated by management or the board of directors of Enbridge. Mr. Monaco’s employment agreement does not contain the “single trigger” voluntary termination right following a change of control. Since 2007, it has been Enbridge’s policy not to enter into employment agreements granting “single trigger” voluntary termination rights in favor of the executive. The agreements with the other executives were entered into prior to that time.
The following table provides a summary of the incremental compensation that Enbridge would pay to the applicable executive officer under the terms of his employment agreements upon the occurrence of one of the foregoing events:
Type of
Termination
Base
Pay
Short-term
Incentive
Long-term
Incentive
Benefits
Pension
Resignation
None
Payable in full if entire calendar year is worked. Otherwise none.
Performance options are pro-rated based on resignation date. Vested options must be exercised within 30 days post the resignation or by the end of the original term, whichever is shorter. Unvested options are cancelled. Performance units are forfeited.
None
Credited service no longer earned.
Retirement
None
Current year’s incentive for current year is pro-rated based on retirement date.
Performance options are pro-rated based on retirement date. Options continue to vest and remain exercisable for three years after the retirement date or until the end of the original term, whichever is shorter. Performance units are pro-rated based on retirement date.
Post retirement benefits begin.
Credited service no longer earned.
Involuntary Termination (Not for Cause)
Base salary is paid out in a lump sum over two years.
Two times the average of short-term incentive awards received during the past two years plus the current year’s short term incentive pro-rated based on service prior to the termination of employment.(1)
Vested options are exercisable in accordance with their terms.(2) Value of the unvested options is paid in cash. Performance units are pro-rated based on employment termination date and the value is assessed and paid at the end of the term.
Benefits value is paid out in a lump sum over two years.
Two additional years of pension accrual added to final pension calculation.
Termination (Constructive Dismissal)
Termination (Change of Control)
All options vest. All performance units mature and value is assessed and paid based upon applicable performance measures achieved to that time.
(1) For Mr. Monaco, pro-rated payment for current year is based upon the prior year’s short term incentive award.
(2) Performance stock options are valued assuming all performance measures have been met.
In addition, the executive officer will receive:
•
Up to a maximum of $10,000 for financial or career counseling assistance.
•
An amount in cash equal to the value of all of such executive officer’s accrued and unpaid vacation pay.
For purposes of each of the employment agreements of Mr. Wuori, a “change of control” means:
•
The sale to a person or acquisition by a person not affiliated with Enbridge or its subsidiaries of net assets of Enbridge or its subsidiaries having a value greater than 50% of the fair market value of the net assets of Enbridge and its subsidiaries determined on a consolidated basis prior to such sale whether such sale or acquisition occurs by way of reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or otherwise;
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Any change in the holding, direct or indirect, of shares of Enbridge by a person not affiliated with Enbridge as a result of which such person, or a group of persons, or persons acting in concert, or persons associated or affiliated with any such person or group within the meaning of the Securities Act (Alberta), are in a position to exercise effective control of Enbridge whether such change in the holding of such shares occurs by way of takeover bid, reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or otherwise; and for the purposes of this Agreement, a person or group of persons holding shares or other securities in excess of the number which, directly or following conversion thereof, would entitle the holders thereof to cast 20% or more of the votes attaching to all shares of Enbridge which, directly or following conversion of the convertible securities forming part of the holdings of the person or group of persons noted above, may be cast to elect directors of Enbridge shall be deemed, other than a person holding such shares or other securities in the ordinary course of business as an investment manager who is not using such holding to exercise effective control, to be in a position to exercise effective control of Enbridge;
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Any reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction involving Enbridge where shareholders of Enbridge immediately prior to such reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction hold less than 60% of the shares of Enbridge or of the continuing corporation following completion of such reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, transfer, sale or other transaction;
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Enbridge ceases to be a distributing corporation as that term is defined in the Canada Business Corporations Act;
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Any event or transaction which the Enbridge board of directors, in its discretion, deems to be a change of control; or
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The Enbridge board of directors no longer comprises a majority of incumbent directors, who are defined as directors who were directors immediately prior to the occurrence of the transaction, elections or appointments giving rise to a change of control and any successor to an incumbent director who was recommended for election at a meeting of Enbridge shareholders, or elected or appointed to succeed any incumbent director, by the affirmative vote of the directors, which affirmative vote includes a majority of the incumbent directors then on the board of directors.
Both Messrs. Wuori and Monaco are subject during his employment (and for two years thereafter with regard to disclosure of confidential information) to restrictions on (1) any practice or business in competition with Enbridge or its affiliates and (2) disclosure of the confidential information of Enbridge or its affiliates.
In the event of a termination that would result in severance benefits to either Messrs. Wuori or Monaco, Enbridge would owe incremental benefits with a value of approximately $11 million for each. Such amounts assume that termination was effective as of December 31, 2011, and as a result include amounts earned through such time and are estimates of the amounts which would be paid out to each of Messrs. Wuori and Monaco upon termination under such circumstances. The actual amounts to be paid out can only be determined at the time of such executive’s separation from Enbridge.
Director Compensation
As a partnership, we are managed by Enbridge Management, as the delegate of our General Partner. The boards of directors of Enbridge Management and our General Partner, which are comprised of the same persons, perform for us the functions of a board of directors of a business corporation. We are allocated 100 percent of the director compensation of these board members. Enbridge employees who are members of the boards of directors of our General Partner or Enbridge Management do not receive any additional compensation for serving in those capacities. Effective January 19, 2011, George Petty retired as a member of the boards of directors of Enbridge Management and our General Partner.
Under the Director Compensation Plan, directors receive an annual retainer of $95,000 and no additional fees for attending regular meetings. The annual retainer paid to the Chairman of the Board is $15,000 and the annual retainer paid to the Chairman of the Audit Committee is $10,000. The out-of-state travel fee is $1,500 per meeting. The Corporate Governance Guidelines provide an expectation that independent directors will hold a personal investment in either or both of us or Enbridge Management, of at least two times the annual board retainer, which currently would be $190,000 (i.e., 2 X $95,000 = $190,000). Directors would be expected to achieve the foregoing level of equity ownership by the later of January 1, 2011 or five years from the date he or she became a director. In addition, on January 30, 2009, the Director Compensation Plan was amended to increase the retainer paid to a Director serving as Chairman of any Special Committee that may be constituted from time to time to $5,000 for each assignment plus additional amounts to be paid at the Board’s discretion depending on the complexity of the project and time involved. In addition, each member of the Special Committee receives $1,500 per meeting.
DIRECTOR COMPENSATION
The General Partner indemnifies each director for actions associated with being a director to the fullest extent permitted under Delaware law and maintains errors and omissions insurance.
On December 5, 2011, the boards of directors amended the Director Compensation Plan effective January 1, 2012, under which the directors shall receive an annual retainer of $115,000, which was increased from $95,000, with no additional fees for attending regular meetings. In addition, the annual retainer paid to the Chairman of the Board was increased to $20,000 from $15,000 and the annual retainer paid to the Chairman of the Audit Committee was increased to $15,000 from $10,000.
COMPENSATION REPORT OF THE BOARD OF DIRECTORS
The Board of Directors of Enbridge Energy Management, L.L.C., as delegate of the General Partner of Enbridge Energy Partners, L.P., has reviewed and discussed the Compensation Discussion and Analysis section of this report with management and, based on that review and discussion, has recommended that the Compensation Discussion and Analysis be included in this report.
/S/ MARK A. MAKI
/S/ TERRANCE L. MCGILL
Mark A. Maki
President and Director
(Principal Executive Officer)
Terrance L. McGill
President of General Partner and
Director
/S/ STEPHEN J. WUORI
/S/ AL MONACO
Stephen J. Wuori
Executive Vice President-Liquids
Pipelines and Director
Al Monaco
Director
/S/ MARTHA O. HESSE
/S/ JEFFREY A. CONNELLY
Martha O. Hesse
Director
Jeffrey A. Connelly
Director
/S/ DAN A. WESTBROOK
/S/ J. HERBERT ENGLAND
Dan A. Westbrook
Director
J. Herbert England
Director
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information as of March 13, 2012 with respect to persons known to us to be the beneficial owners of more than five percent of any class of the Partnership’s units:
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table sets forth information as of March 13, 2012 with respect to each class of our units and the listed shares of Enbridge Management beneficially owned by the NEOs and directors of the General Partner and Enbridge Management and all executive officers and directors of the General Partner and Enbridge Management as a group:
* Less than one percent.
(1) Unless otherwise indicated, each beneficial owner has sole voting and investment power with respect to all of the Class A common units or Listed Shares attributed to him or her.
(2) The 50,800 Listed Shares beneficially owned by Ms. Hesse are held in an Individual Retirement Account established for her benefit.
(3) Of the 20,000 Class A common units deemed beneficially owned by Mr. Connelly, 20,000 Class A common units are held in the Susan K. Connelly Family Trust of which Mr. Connelly is the trustee and a beneficiary.
(4) Of the 21,000 Class A common units deemed beneficially owned by Mr. Westbrook, 16,000 Class A common units are held by The Westbrook Trust, for which Mr. Westbrook is the trustee and beneficiary, and 5,000 Class A common units are held by the Mary Ruth Westbrook Trust, for which Mr. Westbrook is the sole trustee and beneficiary.
(5) The 500 Class A common units beneficially owned by Ms. Coy are held in an Individual Retirement Account established for her benefit.
(6) The 2,893 Listed Shares beneficially owned by Mr. Neyland are held in a Family Trust for which Mr. Neyland is a co-trustee as well as a beneficiary.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
INTEREST OF THE GENERAL PARTNER IN THE PARTNERSHIP
At December 31, 2011, our General Partner had the following ownership interests in us:
INTEREST OF ENBRIDGE MANAGEMENT IN THE PARTNERSHIP
At December 31, 2011, Enbridge Management owned 38,566,334 i-units, representing a 13.3% limited partner interest in us. The i-units are a special class of our limited partner interests. All of our i-units are owned by Enbridge Management and are not publicly traded. Enbridge Management’s limited liability company agreement provides that the number of all of its outstanding shares, including the voting shares owned by the General Partner, at all times will equal the number of i-units that it owns. Through the combined effect of the provisions in the Partnership Agreement and the provisions of Enbridge Management’s limited liability company agreement, the number of outstanding Enbridge Management shares and the number of our i-units will at all times be equal.
CASH DISTRIBUTIONS
As discussed in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, we make quarterly cash distributions of our available cash to our General Partner and the holders of our common units. The holders of our i-units and Class C units, prior to their conversion to Class A common units in October 2009, received in-kind distributions under the Partnership Agreement. Our General Partner receives incremental incentive cash distributions on the portion of cash distributions that exceed certain target thresholds on a per unit basis as follows:
During 2011, we paid cash and incentive distributions to our General Partner for its general partner ownership interest of approximately $95.0 million and cash distributions of $97.3 million and $16.4 million in connection with its ownership of the Class A and Class B common units, respectively. The cash distributions we make to our General Partner for its general partner ownership interest exclude an amount equal to two percent of the i-unit distributions to maintain its two percent general partner interest.
IN-KIND DISTRIBUTIONS
Enbridge Management, as owner of our i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to the General Partner and the holders of our Class A and Class B common units, we
issue additional i-units to Enbridge Management in an amount determined by dividing the cash amount distributed per limited partner unit by the average price of one of Enbridge Management’s listed shares on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for Enbridge Management’s shares multiplied by the number of shares outstanding on the record date. In 2011, 2010 and 2009, distributed a total of 2,420,228, 2,507,688 and 3,251,624 i-units to Enbridge Management, on a split-adjusted basis, and retained cash totaling approximately $75.7 million, $68.3 million and $61.1 million in connection with these in-kind distributions.
Prior to the conversion of the Class C units to Class A common units in October 2009, holders of our Class C units received quarterly distributions of additional Class C units with a value equal to the quarterly cash distribution we paid to the holders of our Class A and Class B common units. We determined the additional Class C units we issued by dividing the quarterly cash distribution per unit we paid on our Class A and Class B common units by the average market price of a Class A common unit as listed on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for our Class A common units multiplied by the number of Class C units outstanding on the record date. In 2009, we distributed a total of 1,077,218 split adjusted Class C units to our General Partner in lieu of making cash distributions and retained cash totaling approximately $19.7 million in connection with these in-kind distributions.
GENERAL PARTNER CONTRIBUTIONS
Pursuant to our partnership agreement, our General Partner is at all times required to maintain its two percent general partner ownership interest in us. During 2011 and 2010, in connection with our various issuances and sales of Class A common units, our General Partner contributed approximately $18.2 million and $8.6 million, respectively, to us to maintain its two percent general partner ownership interest.
OTHER RELATED PARTY TRANSACTIONS
We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. We obtain managerial, administrative and operational services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, Enbridge Management and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse our General Partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.
Administrative and Workforce Related Services
Enbridge and its affiliates provide management and administrative, operational and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.
We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. We obtain managerial, administrative and operational services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, Enbridge Management, and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse our General Partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.
Service Agreements
Our General Partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through an operational services agreement among Enbridge, Enbridge Operational Services, Inc., or EOSI, and Enbridge Pipelines, Inc., or EPI, both subsidiaries of Enbridge, all of whom we refer to as the Canadian service providers, and us, we are charged for the services of Enbridge employees resident in Canada. Through a general and administrative services agreement among us, our General Partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of our General Partner, which we refer to as EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “Operating and administrative” expenses on our consolidated statements of income.
Operational Services Agreement
We are charged an amount by the Canadian service providers for services we are provided under the operational services agreement. The amount we are charged is established as part of the annual budget and agreed upon by us and the Canadian service providers. The amount we are charged is computed based on an estimate of the pro-rata reimbursement of each Canadian service provider’s estimated annual departmental costs, net of amounts charged to other affiliates and amounts identifiable as costs of that Canadian service provider. The Canadian service providers charge us a monthly fixed fee that is computed as one-twelfth of the annual budgeted amount. Under the operational services agreement, our General Partner and Enbridge Management pay the Canadian service providers a monthly fee determined in the manner described above. At the request of Enbridge Management, the fee for these operational services provided to it in its capacity as the delegate of our General Partner are billed directly to us.
Enbridge Management and our General Partner may request that the Canadian service providers provide special additional operational services for which each, as appropriate, agrees to pay costs and expenses incurred by the Canadian service provider in connection with providing the special additional operational services. The types of services provided under the operational services agreement include:
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Executive, administrative and other services on an “as required” basis;
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Monitoring transportation capacity, scheduling shipments, standardizing integrity, maintenance and other operational requirements;
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Addressing regulatory matters associated with the liquids pipeline operations;
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Providing monthly measurement information, forecasts, oil accounting, invoicing and related services;
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Computer application development and support services, including liquid pipelines’ control center operations;
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Electrical power requirements and costs for system operations;
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Patrol and aircraft services; and
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Any other operational services required to operate existing systems and any additional systems acquired by us.
Each year, the Canadian service providers prepare annual budgets by departmental cost center for their respective operations. After establishing a budget for the following year, the costs associated with each department are allocated to us, our General Partner, Enbridge Management and other Enbridge affiliates using one of the following three methods:
•
Capital assets employed as a percentage of Enbridge-wide capital assets;
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Time-based estimates; or
•
Full-time-equivalent (FTE)/headcount as a percentage of Enbridge-wide FTEs.
The total amount we reimbursed the Canadian service providers pursuant to the operational services agreement for the years ended December 31, 2011, 2010 and 2009 was $97.3 million, $74.5 million and $63.4 million, respectively.
General and Administrative Services Agreement
We, Enbridge Management and our General Partner receive services from EES under the general and administrative services agreement. Under this agreement, EES provides services to us, Enbridge Management and our General Partner and charges each recipient of services, on a monthly basis, the actual costs that it incurs for those services. Our General Partner and Enbridge Management may request that EES provide special additional general services for which each, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:
•
Accounting, tax planning and compliance services, including preparation of financial statements and income tax returns;
•
Administrative, executive, legal, human resources and computer support services;
•
Insurance coverage;
•
All administrative and operational services required to operate existing systems and any additional systems acquired by us and operated by EES; and
•
Facilitate the business and affairs of Enbridge Management and us, including, but not limited to, public and government affairs, engineering, environmental, finance, audit, operations and operational support, safety/compliance and other services.
EES captures all costs that it incurs for providing the services by cost center in its financial system. The cost centers are determined to be “Shared Service”, “Enbridge Energy Partners, L.P. only” or “Non-Enbridge Energy Partners, L.P.” Shared Service cost centers are used to capture costs that are not specific to a single United States Enbridge entity but are shared among multiple United States Enbridge entities. The costs captured in the cost centers that are specific to us are charged in full to us. The costs captured in cost centers that are outside of our business unit are charged to other Enbridge entities.
The general method used to allocate the Shared Service costs is established through the budgeting process and reimbursed as follows:
•
Each cost center establishes a budget.
•
Each cost center manager estimates the amount of time the department spends on us and entities that are not directly affiliated with us.
•
Costs are accumulated monthly for each cost center.
•
The actual costs accumulated monthly by each cost center are allocated to us or entities that are not directly affiliated with us based on the allocation model.
•
We reimburse EES for its share of the allocated costs.
The total amount reimbursed by us for services received pursuant to the general and administrative services agreement for the years ended December 31, 2011, 2010 and 2009 was $264.3 million, $231.6 million and $225.8 million, respectively.
Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $24.9 million, $16.3 million and $10.0 million during 2011, 2010 and 2009, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
Line 6A and 6B Expense Reimbursement
For the years ended December 31, 2011 and 2010, we have reimbursed Enbridge $7.6 million and $14.9 million, respectively, for its assistance with the administration and clean-up efforts for our Line 6A and 6B crude oil releases. For further details related to our Line 6A and 6B crude oil releases, refer to Note 13. Commitments and Contingences-Lakehead Lines 6A and 6B crude oil releases.
Affiliate Revenues and Purchases
We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates. Included in our results for the twelve months ending December 31, 2011, 2010 and 2009, are operating revenues of $354.3 million, $430.4 million and $181.3 million, respectively, related to these transactions.
Facilities Cost Reimbursement Agreement
In 2007, we entered into an agreement with Enbridge Pipelines to install and operate certain sampling and related facilities for the purpose of improving the quality of crude oil and the transportation services on our Lakehead system, which directly increases the transportation services revenue of Enbridge Pipelines. As compensation for installing and operating these transportation facilities, Enbridge Pipelines makes annual payments to us on a cost of service basis. The income we recorded for providing these transportation services in 2011, 2010 and 2009 was approximately $0.8 million, $0.9 million and $0.8 million, respectively.
We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Included in our results for the twelve months ending December 31, 2011, 2010 and 2009, are costs for natural gas purchases of $200.8 million, $242.3 million and $53.6 million, respectively, related to these purchases.
Financing Transactions with Affiliates
EUS Credit Agreement
In December 2007, we entered into an unsecured revolving credit agreement, referred to as the EUS Credit Agreement, with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge, referred to as Enbridge U.S. The EUS Credit Agreement provided for a maximum principal amount of credit available to us at any one time of $500 million for a three-year term that was scheduled to mature in December 2010. In March 2010, we terminated our unsecured revolving credit agreement with Enbridge U.S. in accordance with the terms of the agreement and without penalty. At December 31, 2010, we had no balances outstanding under the EUS Credit Agreement.
Joint Funding Arrangement for Alberta Clipper Pipeline
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 Inc., or Enbridge. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010. In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement, a credit agreement between our General Partner and us to finance the Alberta Clipper Pipeline, 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 and is subordinate to all of our senior indebtedness. 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 Alberta Clipper Pipeline that our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement for any additional costs associated with our construction of the Alberta Clipper Pipeline that 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. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline. The approved terms for the Alberta Clipper Pipeline are described in the “Alberta Clipper United States Term Sheet,” which is included as Exhibit I to the June 27, 2008 Offer of Settlement filed with the Federal Energy Regulatory Commission, or FERC, by the OLP and approved on August 28, 2008 (Docket No. OR08-12-000).
A summary of the cash activity for the A1 Term Note for the years ended December 31, 2011, 2010 and 2009 are as follows:
The following table presents in millions, the scheduled maturities of the A1 Term Note based upon the $342.0 outstanding at December 31, 2011.
Our General Partner also made equity contributions totaling $3.3 million, $102.3 million and $329.7 to the OLP during the years ended December 31, 2011, 2010 and 2009, respectively, to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline.
We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $53.2 million, $60.6 million and $11.4 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, 2010 and 2009, 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.
Distribution to Series AC Interests
The following table presents distributions paid by the OLP to our General Partner and its affiliate during the years ended December 31, 2011 and 2010, representing the noncontrolling interest in the Series AC and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests.
EUS Credit Facility
In April 2009, we entered into a $150 million unsecured and non-guaranteed revolving credit facility agreement with Enbridge (U.S.) Inc., which we terminated in December 2009 as discussed in Note 10. Debt-364-day Credit Facilities. In connection with our termination of the Enbridge (U.S.) Inc. portion of the 364-day Credit Facilities, we recognized $1.5 million of debt origination fees on our consolidated statement of income for the year ended December 31, 2009.
Hungary Note Payable
In November 2009, we repaid the $130.0 million outstanding balance of our notes payable to Enbridge Hungary Ltd., an affiliate of our General Partner (the “Hungary Note”). At December 31, 2009 we had no amounts outstanding under the Hungary Note. We paid interest at a fixed rate of 8.4% per annum on the Hungary Note semi-annually in June and December of each year through November 2009 when we repaid the outstanding balance and accrued interest due. For the year ended December 31, 2009, we made interest payments of approximately $9.3 million.
Asset Purchase and Sale Transactions with Affiliates
Line 13 Exchange and Lease
In connection with the development of a diluent pipeline being constructed by Enbridge Pipelines (Southern Lights), L.L.C., or Southern Lights, a wholly-owned subsidiary of our General Partner, we completed the transfer of a 156-mile section of pipeline, which we refer to as Line 13, from our Lakehead system to Southern Lights in exchange for a newly constructed pipeline for transporting light sour crude oil. In connection with the exchange, at the request of shippers and to ensure adequate southbound pipeline capacity prior to the completion of the Alberta Clipper Pipeline, we agreed to lease Line 13 from Southern Lights for monthly payments of $1.8 million. The transfer and lease which became effective February 20, 2009, expired in April 2010 in accordance with the lease. For the year ended December 31, 2010, we paid $5.4 million to Southern Lights to lease Line 13, which we recovered through the tariff that went into effect on April 1, 2010 on our Lakehead system.
The exchange resulted in a $166.5 million increase in “Property, plant and equipment” and the capital account of our General Partner included in “Partners’ capital” on our December 31, 2009 consolidated statement of financial position, representing the $171.5 million cost of the light sour pipeline that was in excess of the $5.0 million net book value of the Line 13 assets we exchanged. The costs were transferred to us through the capital account of our General Partner and are included in the $171.5 million. Further, $3.8 million of additional costs for the year ended December 31, 2010 were incurred and transferred by Southern Lights, which increased the total costs for the light sour crude oil pipeline at December 31, 2010 to $175.3 million. The light sour pipeline is newer and has a slightly higher capacity than Line 13, which will allow us to transport additional volumes of light sour crude oil on our Lakehead system with less integrity and maintenance costs, although depreciation and property tax expense is anticipated to increase in future periods due to the higher book value associated with these assets.
Purchase of Line Pipe
In March 2009, we acquired, for $27.0 million, approximately 25 miles of 36-inch diameter line pipe from our General Partner. The purchase was for our use in constructing the Alberta Clipper crude oil pipeline project, referred to as the Alberta Clipper Project. The line pipe was initially obtained by our General Partner for use in constructing the Southern Access extension. The transactions were previously approved by the Enbridge Management Board of Directors.
Spearhead Pipeline Acquisition
In May 2009, we purchased a portion of a crude oil pipeline system from CCPS Transportation, L.L.C., a wholly-owned subsidiary of our General Partner, for approximately $75 million, representing the carrying value in the records of our General Partner. The portion of the system, which we refer to as Spearhead North, includes approximately seven storage tanks and 75 miles of pipeline that our General Partner reversed to provide northbound service from Flanagan, Illinois to Griffith, Indiana. The acquisition of Spearhead North complements the existing operations of our Lakehead system, as our newly-constructed Southern Access pipeline ends in Flanagan where it connects to Spearhead North. The transaction was previously approved by the Enbridge Management Board of Directors.
UTOS Disposition
In January 2009, we sold the member interests of our UTOS system for minimal consideration to Enbridge Offshore (Gas Transportation), L.L.C., a wholly-owned subsidiary of Enbridge. The UTOS system transports natural gas from offshore platforms on a fee for service basis to other pipelines onshore for further delivery and does not have long-term contracts. The UTOS system was not considered strategic to our ongoing central operations, but is strategically aligned with Enbridge’s offshore operations.
General Partner Equity Transactions
Our General Partner owns an effective two percent general partner interest in us. Pursuant to our partnership agreement we paid cash distributions to our General Partner of $95.0 million, $69.8 million and $57.0 million for the years ended December 31, 2011, 2010, and 2009, respectively. The cash distributions we make to our General Partner exclude an amount equal to two percent of the i-units and until the conversion to Class A common units, Class C unit distributions, which we retain from the General Partner to maintain its two percent general partner interest in us.
As of December 31, 2011, our General Partner owned 46.5 million Class A common units, representing a 16.0 percent limited partner interest in us. We paid the General Partner cash distributions of $97.3 million for the year ended December 31, 2011, with respect to its ownership of Class A common units. In October 2009, we effected the conversion of all our outstanding Class C units into Class A common units in accordance with the terms of our partnership agreement. The conversion became effective upon the determination by our General Partner that the converted Class C units would have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of our outstanding Class A common units. Along with the conversion and adjusted for the 2011 split, we issued and sold 42,490 Class A common units to our General Partner for a purchase price of $23.535 per unit, or approximately $1.0 million.
As of December 31, 2011 and 2010, our General Partner also owned 7,825,500 Class B common units, representing a 2.7 percent and 3.0 percent limited partner interest in us for the respective years. We paid the General Partner cash distributions of $16.4 million, $15.8 million and $15.5 million for the years ended December 31, 2011, 2010, and 2009, respectively, with respect to its ownership of Class B common units.
As a result of the October 2009 conversion of all our outstanding Class C units into Class A common units, we did not have any Class C units outstanding at December 31, 2011 and 2010. Refer to Note 11. Partners’ Capital for additional information regarding the Class C units.
For further discussion of these and other related party transactions, refer to Note 12. Related Party Transactions in the consolidated financial statements of this Annual Report on Form 10-K.
REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS
If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our General Partner or Enbridge Management, as appropriate. The board of directors then determines whether it is advisable to constitute a special committee of independent directors to evaluate the proposed transaction. If a special committee is appointed, the committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the special committee retains such counsel or financial advisor, it considers the advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair to us and all of our unitholders.
Potential transactions with related persons that are not financially significant so as to require review by the board of directors are disclosed to the President of Enbridge Management and our General Partner and reviewed for compliance with the Enbridge Statement on Business Conduct. The President may also consult with legal counsel in making such determination. If a related person transaction occurred and was later found not to comply with the Statement on Business Conduct, the transaction would be reported to the board of directors for further review and ratification or remedial action.
During 2011, we had the following “related person” transactions (as the term is defined in Item 404 of Regulation S-K):
•
An affiliate of Enbridge which provides employee services to the Partnership continued a previously existing employment relationship with Jan Connelly, the sister of Jeffrey A. Connelly, a member of the Board of Directors. Ms. Connelly is employed in our Houston office as the Manager, Optimization. During 2011, she received total compensation of $323,158.12 and benefits estimated at approximately 37% of her base compensation for a total of $372,340.40. This amount includes $78,624.24 of imputed income which Ms. Connelly was deemed to have received in connection with moving expenses incurred in her transfer from our Michigan office to Houston during 2011.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table sets forth the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP, our principal independent auditors, for each of our last two fiscal years.
(1) Audit fees consist of fees billed for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, audits of various subsidiaries for statutory and regulatory filing requirements and our debt and equity offerings.
(2) Tax fees consist of fees billed for professional services rendered for federal and state tax compliance for Partnership tax filings and unitholder K-1’s.
Engagements for services provided by PricewaterhouseCoopers LLP are subject to pre-approval by the Audit, Finance & Risk Committee of Enbridge Management’s board of directors; however, services up to $50,000 may be approved by the Chairman of the Audit, Finance & Risk Committee, under the board of directors’ delegated authority. All services in 2011 and 2010 were approved by the Audit, Finance & Risk Committee.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as a part of this report:
(1) Financial Statements.
The following financial statements and supplementary data are incorporated by reference in Part II, Item 8. Financial Statements and Supplementary Data beginning on page 113 of this Form 10-K.
a. Report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
b. Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009.
c. Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009.
d. Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009.
e. Consolidated Statements of Financial Position as of December 31, 2011 and 2010.
f. Consolidated Statements of Partners’ Capital for the years ended December 31, 2011, 2010 and 2009.
g. Notes to the Consolidated Financial Statements.
(2) Financial Statement Schedules.
All schedules have been omitted because they are not applicable, the required information is shown in the consolidated financial statements or Notes thereto or the required information is immaterial.
(3) Exhibits.
Reference is made to the “Index of Exhibits” following the signature page on page 239, which is hereby incorporated into this Item.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENBRIDGE ENERGY PARTNERS, L.P.
(Registrant)
By:
Enbridge Energy Management, L.L.C.,
as delegate of the General Partner
By:
/S/ MARK A. MAKI
Mark A. Maki
Date: March 13, 2012
(President)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 13, 2012 by the following persons on behalf of the Registrant and in the capacities indicated.
/S/ MARK A. MAKI
/S/ TERRANCE L. MCGILL
Mark A. Maki
President and Director
(Principal Executive Officer)
Terrance L. McGill
President of General Partner and
Director
/S/ STEPHEN J. WUORI
/S/ AL MONACO
Stephen J. Wuori
Executive Vice President-Liquids
Pipelines and Director
Al Monaco
Director
/S/ STEPHEN J. NEYLAND
/S/ WILLIAM M. RAMOS
Stephen J. Neyland
Vice President-Finance
(Principal Financial Officer)
William M. Ramos
Controller
/S/ JEFFREY A. CONNELLY
/S/ J. HERBERT ENGLAND
Jeffrey A. Connelly
Director
J. Herbert England
Director
/S/ MARTHA O. HESSE
/S/ DAN A. WESTBROOK
Martha O. Hesse
Director
Dan A. Westbrook
Director
Index of Exhibits
Each exhibit identified below is filed as a part of this annual report. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan arrangement required to be filed as an exhibit to this report pursuant to Item 15(c) of Form 10-K.
Copies of Exhibits may be obtained upon written request of any Unitholder to Investor Relations, Enbridge Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.