Washington, D.C. 20549
ENBRIDGE INC.
200, 425 - 1st Street S.W.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
The aggregate market value of the registrant’s common shares held by non-affiliates computed by reference to the price at which the common equity was last sold on June 30, 2017,2020, was approximately US$65,416,118,124.59.2 billion.
The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, or “$” or “C$” are to Canadian dollars and all references to “US$” are to United StatesUS dollars. All amounts are provided on a before tax basis, unless otherwise stated.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impactsuccessful execution of the Merger Transaction,our strategic priorities, operating performance, legislative and regulatory parameters,parameters; litigation, including with respect to the Dakota Access Pipeline (DAPL) and the Line 5 dual pipelines; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; our dividend policy,policy; project approval and support,support; renewals of rights-of-way, weather,rights-of-way; weather; economic and competitive conditions,conditions; public opinion,opinion; changes in tax laws and tax rates,
ITEM 1. BUSINESS
Our activities are carried out through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution; GreenDistribution and Storage; Renewable Power and Transmission;Generation; and Energy Services, as discussed below.
Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing, Oklahoma. Flanagan South and associated pumping stations were completed in the fourth quarter of 2014. Flanagan South has an initial designa capacity of approximately 600,000 bpd.600 kbpd.
Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System, to Cushing, Oklahoma. The Spearhead pipeline was originally placed into servicehas a capacity of approximately 193 kbpd.
Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada and the United States.US.
The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 402-kilometers (250-miles) through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N U.S.US. The system consistshas a peak day capacity of 3.09 bcf/d of natural gas on approximately 1,835-kilometers (1,140-miles)1,820-kilometers (1,131-miles) of pipeline with associated compressor stations. We have a 92% interest in the Algonquin natural gas transmission system.
Gulfstream is an approximately 1,199-kilometer (745-mile) interstate natural gas transmission system with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc.stations. Gulfstream transportshas a peak day capacity of 1.31 bcf/d of natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is accounted for under the equity method of accounting.We have a 50% interest in Gulfstream.
Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines, or injected or withdrawn from our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
Interruptible transmission and storage services are also available where customers can use capacity if it exists at the time of the request.request and are generally at a higher toll than long-term contracted rates. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this service. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.
We have a 50% interest in the Alliance Pipeline, a 3,000-kilometer (1,864-mile) integrated, high-pressure natural gas transmission pipeline and approximately 860-kilometers (534-miles) of lateral pipelines and related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. The majority of transportation services provided by Alliance pipeline are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline. Alliance pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request.
US MIDSTREAM
US Midstream consists of our Midcoast assets, including the Anadarko, East Texas, North Texas and Texas Express NGL systems. These assets include natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Midcoast also has rail and liquids marketing operations. During 2017, we acquired all of the noncontrolling interests in these assets. For further information, refer to Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - United States Sponsored Vehicle Strategy - Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
US Midstream also includes oura 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable Midstream LLC, and a 50% interest in Aux Sable Canada LP (together,(collectively, Aux Sable). Aux Sable Liquid Products LP owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities upstream ofconnected to Alliance Pipeline that facilitate deliveriesdelivery of liquids-rich natural gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; and Aux Sable Canada’s interests in the Montney area of British Columbia,BC, comprising the Septimus Pipeline and the Septimus and Wilder Gas Plants.Pipeline. Aux Sable Canada also owns a facility which processes refinery/upgrader offgas in Fort Saskatchewan, Alberta.
US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which is accounted for as an equity investment.indirectly owns approximately 57% of DCP Midstream, gathers, compresses, treats, processes, transports, storesLP, including limited partner and sellsgeneral partner interests. DCP Midstream, LP is a master limited partnership, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas. It also produces, fractionates, transports, storesgas; producing, fractionating, transporting, storing and sells NGLs, recoversselling NGLs; and sells condensate,recovering and tradesselling condensate. DCP Midstream, LP owns and marketsoperates more than 39 plants and approximately 92,135-kilometers (57,250-miles) of natural gas and NGLs.natural gas liquids pipelines, with operations in nine states across major producing regions.
OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 active natural gas gathering and FERC regulated transmission pipelines and two activefour oil pipelines, including the Heidelberg Oil Pipeline that was placed in service in January 2016.pipelines. These pipelines are located in four major corridors in the Gulf of Mexico, extending to deepwater developments, and include almost 2,100-kilometers (1,300-miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.d.
COMPETITION
Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The flow pattern of natural gas is changing across North America due to emerging supply sources and evolving demand centers, which creates a highly competitive market to secure newcompetition for growth opportunities. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.
The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, nuclear and renewable energy. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other
forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Competition in our business exists in all of the markets wethat our businesses serve. Competitors include interstateinterstate/interprovincial and intrastateintrastate/intraprovincial pipelines or their affiliates and other midstream businesses that transport, gather, treat, process and market natural gas or NGLs. Because pipelines are generally the most efficient mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies. Pipelines typically compete with each other based on location, capacity, reputation, price and reliability.
SUPPLY AND DEMAND
Our gas transmission assets make up one of the largest natural gas transportation networks in North America, driving connectivity between prolific supply basins and major demand centers within the continent. Our systems have been integral to the transition in natural gas fundamentals over the last decade and will continue to play a part as the energy landscape evolves. Shifts in production and consumption, both domestic and foreign, will require that we continue to serve as a critical link between markets.
In 2010, natural gas production in each of the Appalachian and Permian basins were less than 5.0 bcf/d each. Today, these regions produce more than 43.0 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well, there has been and continues to be a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of producers and consumers alike. Our US Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply starved northeast markets. Our asset base now has the capability to transport diverse bi-directional supply to the northeast, southeast, midwest, Gulf Coast and LNG markets on a fully subscribed and highly utilized basis.
The northeast market continues its role as a predominantly supply constrained region with steady demand into 2040. The bi-directional capabilities offered by our US Gas Transmission system allows us to deliver in an efficient manner to our regional customers. The region has seen an increase in natural gas supply due to the development of the Marcellus and Utica shales in the Appalachia region.
The southeast market is linked to multiple, highly liquid supply pools that include the Marcellus and Utica shale developments, offering consistent supply and stable pricing to a growing population of end-use customers across our multiple systems under long term, utility-like arrangements.
With connectivity to Appalachian and western Canadian supply through our systems, the midwest market has access to two of the lowest cost gas producing regions on the continent. As demand in the region is expected to continue to grow by approximately 2.3 bcf/d over the next two decades, maintaining this link will remain important. Flexibility in supply for this market is especially critical to maintaining liquidity and price stability as natural gas continues to replace coal-fired generation.
Gulf Coast demand growth is being driven by an ongoing wave of gas-intensive petrochemical facilities, along with power generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Demand to these markets in the region is anticipated to grow by more than 23.0 bcf/d through 2040. The Gulf Coast market has been the beneficiary of low cost capacity on our assets as the relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-water market access and proximity to Mexico continue to make this region a platform of global trade as pipeline and LNG exports continue their growth trajectory. The US exported over 9 bcf/d of natural gas to LNG markets, primarily from the Gulf Coast region, at the end of 2020.
Despite there being strong growth in both supply and demand in the US, a lack of adequate transportation capacity has placed downward pressure on local natural gas pricing. The Appalachian Basin has seen price differentials of $1.00 to $2.00 per million British Thermal Units relative to Henry Hub in the Gulf Coast over the last few years. Unlike the dry gas production of the Marcellus, natural gas production growth in the Permian Basin is a result of robust crude oil production taking place in the region. Gas supplies from the region remained above prior year levels on average throughout 2020.
Western Canada, not unlike other supply hubs, is a source of low-cost supply seeking access to premium markets in North America and globally. One of the few vital links to demand centers in the pacific northwest are our own systems in the region, which are highly utilized.
Global energy demand is expected to increase approximately 30 percent23% by 2040, according to the International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas will play an important role in meeting this energy demand as gas consumption is anticipated to grow by nearly 50 percentapproximately 30% during this period as one of the world’s fastest growing energy sources, second onlysources. North American exports will play a significant part in meeting global demand, underscoring the ability of our assets to renewables. Globally, most natural gas demand will stem fromremain highly utilized by shippers, and highlighting the need for greater power generation capacity, as natural gas is a cleaner alternative to coal, which currently has the largest market share for power generation.
Withinincremental transportation solutions across North America, United States natural gas demand growth is expected to be driven by the next wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in gas-fired power generation. Canadian gas demand growth will be accelerated with implementation of proposed government regulations to replace coal fired power, designed to meet emissions targets.
North American supply from tight formations continues to create a demand and supply imbalance for natural gas and some NGL products. North American gas supply continues to be significantly impacted by development in the northeastern United States, primarily the prolific Marcellus and Utica shales in Appalachia. The abundance of supply from these shale plays continues to alter natural gas flow patterns in North America, as this region has largely displaced flows from the Gulf Coast and WCSB that historically supplied eastern markets. Similar pressures are also being felt in the Midwest United States and southern markets.
Beyond growing Appalachian production, natural gas supply growth has been largely tied to crude oil and NGL production. In the Permian Basin, for example, rapid expansion of crude oil drilling activity has increased associated gas supplies from the region by approximately 2.0 bcf/d over the past two years and growth is forecasted to continue for the next decade. Similarly, WCSB natural gas production growth has been primarily attributable to production of NGLs, which provide strong producer netbacks. However, growing local demand from gas-fired power generation and continued oil sands development should stabilize WCSB natural gas economics, even as regional exports face steeper competition in Eastern Canada and the Midwest United States.
The continued increase in North American gas production and the resulting surplus supply has limited gas price advances, which remained largely within range throughout 2017. In response to low prices, producers have introduced new technologies and more efficient drilling and completion techniques to maximize production and improve break-even economics on new wells. While domestic gas demand and growing North American gas exports provide support for future prices, abundant low cost supplies are likely to continue to limit high prices through the next decade.
Growth in global demand for natural gas will necessitate growing LNG trade to facilitate the movement of gas supply from producing regions to consuming regions. North America and the USGC in particular are positioned to benefit from this trend as low-cost tight gas production from the Permian, Eagle Ford and Appalachia continues to enable growing LNG exports. The United States exported approximately 3.0 bcf/
d of natural gas from the United States Gulf Coast at the end of 2017 with export capacity of approximately 9.0 bcf/d scheduled to be in service by 2020. While the short term outlook for LNG fundamentals points to a continued global oversupply, as the market absorbs the large volumes of new supply coming online, forecasts indicate demand will exceed projected LNG supply in the early 2020s as growing markets seek to diversify supply sources. In addition to LNG export facilities under construction, the United States remains well positioned to serve this next round of global trade expansion. Canada is well positioned to provide LNG export facilities, although these facilities are not likely to be in service in the near term.
NGL production growth is increasingly linked to growing associated gas volumes related to the development of tight oil plays such as the Permian. NGLs that can be extracted from liquids-rich gas streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial, commercial and other applications. Robust gas production has created regional supply imbalances for some NGL products and weakened the economics of NGL extraction, although these imbalances modestly improved over 2017 as crude prices have rebounded and NGL export capacity has expanded. Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental ethane demand and exports. Ethane is the key feedstock to the United States Gulf Coast petrochemical industry, which is among the world’s lowest-cost ethylene producing regions and is currently undergoing significant expansion. As this new infrastructure is completed, ethane prices and resulting extraction margins are expected to improve, reducing the amount of ethane retained in the gas stream.
In addition to ethane, the outlook for abundant propane supplies has prompted the development and expansion of export facilities forliquefied petroleum gas. Over a few short years, the United States has become the world’s largest liquefied petroleum gas exporter, which has helped to reduce the inventory overhang and provide support for propane prices.
In Canada, the WCSB is well situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney and Duvernay shale plays contain significant liquids-rich resources at highly competitive extraction costs. In response to growing regional NGL supply, several propane export solutions are being developed to move WCSB NGLs from Western Canada to global markets.
Longer term, NGL fundamentals indicate a positive outlook for demand growth and would be further supported with a continued recovery in crude oil prices.Consequently, the crude-to-gas price ratio is expected to remain well above energy conversion value levels and continue to be supportive of NGL extraction over the longer term.
America. In response to these evolving natural gas and NGLglobal fundamentals, we believe we are well positioned to provide value-added solutions to producers.shippers. We are responding to the need for regional infrastructure with additional investmentinvestments in Canadian and United StatesUS gas pipelinetransportation facilities. Progress on the development and midstream facilities.construction of our commercially secured growth projects is discussed in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.
GAS DISTRIBUTION AND STORAGE
Gas Distribution and Storage consists of our natural gas utility operations, the core of which areis Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union(Enbridge Gas), which serveserves residential, commercial and industrial customers primarily located throughout Ontario. This business segment also includes natural gas distribution activities in QuebecQuébec and New Brunswick and ouran investment in Noverco IncInc. (Noverco).
On November 2, 2017, EGD and Union Gas filed an application with the Ontario Energy Board (OEB) to amalgamate the two utilities. If approved as filed, the application will provide a 10 year framework for the utilities to identify and leverage best practices and implement integrated solutions. A decision is expected in the second half of 2018.
ENBRIDGE GAS DISTRIBUTION
EGDEnbridge Gas is a rate‑regulatedrate-regulated natural gas distribution utility servingwith storage and transmission services that have been in operation for 172 years. Enbridge Gas serves approximately 2.275% of Ontario residents via approximately 3.8 million residential, commercial and industrial customers in its franchise areas of central and eastern Ontario. In addition, EGD currently serves areas in northern New York State through St. Lawrence Gas Company Inc. (St. Lawrence Gas). In August 2017, EGD entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas. The transaction is expected to close in 2018, subject to regulatory approval and certain pre-closing conditions.meter connections.
EGD also owns and operates regulated and unregulated natural gas storage facilities in Ontario. The utility business is conducted under statutes and municipal bylaws which grant the right to operate in the areas served. The utility operations of EGD and St. Lawrence Gas are regulated by the OEB and by the New York State Public Service Commission, respectively.
As at December 31, 2017, EGD owned and operated a network of approximately 39,000-kilometers (24,233-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes to transfer natural gas from mains to meters on customers' premises.
There are fourthree principal interrelated aspects of the natural gas distribution business in which EGDEnbridge Gas is directly involved: Distribution, Service, Gas Supply, Transportation and Storage.
Distribution Service
EGD'sEnbridge Gas’ principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, small commercial and industrial heating customers are primarily on a general service basis, (withoutwithout a specific fixed term or fixed price contract).contract. The services provided to larger commercial and industrial customers are usually on an annual contract basis under firm or interruptible service contracts. Under a firm contract, Enbridge Gas is obligated to deliver natural gas to the customer up to a maximum daily volume. The service provided under an interruptible contract is similar to that of a firm contract, except that it allows for service interruption at Enbridge Gas’ option primarily to meet seasonal or peak demands. The Ontario Energy Board (OEB) approves rates for both contract and general services. The distribution system consists of approximately 146,000-kilometers (90,720-miles) of pipelines that carry natural gas from the point of local supply to customers.
Gas Supply
Customers have a choice with respect to natural gas supply. Customers may purchase and deliver their own natural gas to points upstream of the distribution system or directly into Enbridge Gas’ distribution system, or, alternatively, they may choose a system supply option, whereby customers purchase natural gas from Enbridge Gas’ supply portfolio. To acquire the necessary volume of natural gas to serve its customers, EGDEnbridge Gas maintains a diversified natural gas supply portfolio. EGD's systemportfolio, acquiring supplies on a delivered basis in Ontario, as well as acquiring supply from multiple supply basins across North America.
Transportation
Enbridge Gas contracts for firm transportation service, primarily with TransCanada Pipelines Limited (TransCanada), Vector and NEXUS, to meet its annual natural gas supply requirements. The transportation service contracts have pricing structures responsive to supply and demand conditions in the North American natural gas market. The prices in these contracts may be indexed to Alberta, Chicago or New York based prices.
Transportation
EGD relies on its long-term contractsare not directly linked with Union Gas, an affiliated company under common control, for transportationany particular source of natural gas supply. Separating transportation contracts from natural gas supply allows Enbridge Gas flexibility in obtaining its own natural gas supply and accommodating the requests of its direct purchase customers for assignment of TransCanada capacity. Enbridge Gas forecasts the natural gas supply needs of its customers, including the associated transportation and storage requirements.
In addition to contracting for transportation service, Enbridge Gas offers firm and interruptible transportation services on its own Dawn-Parkway pipeline system. Enbridge Gas’ transmission system consists of approximately 5,500-kilometers (3,418-miles) of high-pressure pipeline and five mainline compressor stations and has an effective peak daily demand capacity of 7.6 bcf/d. Enbridge Gas’ transmission system also links an extensive network of underground storage pools at the Tecumseh Gas Storage facility and Dawn Hub (Dawn), the largest integrated underground storage facility(collectively, Dawn) to major Canadian and US markets, and forms an important link in moving natural gas from western Canada and oneUS supply basins to central Canadian and northeastern US markets.
As the supply of the largest in North America, located in south-western Ontario, to EGD’s major market in the Greater Toronto Area. These contracts effectively provide EGD with access to United States sourced natural gas at Dawn. These contracts also provide transportation for natural gas receivedin areas close to Ontario continues to grow, there is an increased demand to access these diverse supplies at Dawn via Vector as well as naturaland transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern US. Enbridge Gas delivered 1,793 bcf of gas stored at EGD’sthrough its distribution and Union’s storage poolstransmission system in 2020. A substantial amount of Enbridge Gas’ transportation revenue is generated by fixed annual demand charges, with the Sarnia, Ontario area toaverage length of a long-term contract being approximately 13.5 years and the market area.longest remaining contract term being 22 years.
Storage
EGD’sEnbridge Gas’ business is highly seasonal as daily market demand for natural gas fluctuates with changes in weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits EGDEnbridge Gas to take delivery of natural gas on favorable terms during off‑peakoff-peak summer periods for subsequent use during the winter heating season. This practice permits EGDEnbridge Gas to minimize the annual cost of transportation of natural gas from its supply basins, assists in reducing its overall cost of natural gas supply and adds a measure of security in the event of any short-term interruption of transportation of natural gas to EGD'sEnbridge Gas’ franchise area.areas.
Enbridge Gas’ storage facilities arefacility at Dawn is located in south-westernsouthwestern Ontario, near Dawn, and havehas a total working capacity of approximately 10.5 billion cubic feet (Bcf).276 bcf in 34 underground facilities located in depleted gas fields. Dawn is the largest integrated underground storage facility in Canada and one of the largest in North America. Approximately 8.5 Bcf180 bcf of the total working capacity is available to EGDEnbridge Gas for utility operations. EGDEnbridge Gas also has a storage contractcontracts with Union Gasthird parties for 2.0 Bcf21 bcf of storage capacity.
UNION GAS
Union Gas is a rate‑regulated natural gas distribution utility now serving approximately 1.5 million residential, commercial and industrial customers in its franchise areas of northern, southwestern and eastern Ontario.
Union Gas' regulated and unregulated storage and transmission business offers storage and transmission services to customers at Dawn. ItDawn offers customers an important link in the movement of natural gas from western CanadaCanadian and United StatesUS supply basins to markets in central Canada and the northeastern United States. The utility business is conducted under statutes and municipal by‑laws which grant the right to operate in the areas served. The utility operations of Union Gas are regulated by the OEB.
As at December 31, 2017, Union Gas owned and operated a network of approximately 66,000-kilometers (41,010-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes to transfer natural gas from mains to meters on customers' premises.
Similar to EGD, there are four principal interrelated aspects of the natural gas distribution business in which Union Gas is directly involved: Distribution Service, Gas Supply, Transportation and Storage.
Distribution Service
Similar to EGD, Union Gas’ principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, small commercial and industrial heating customers are primarily on a general service basis (without a specific fixed term or fixed price contract). The services provided to larger commercial and industrial customers underpinned by firm or interruptible service contracts.
Gas Supply
To acquire the necessary volume of natural gas to serve its customers, Union Gas maintains a diversified natural gas supply portfolio. Union Gas' system supply natural gas contracts have pricing structures responsive to supply and demand conditions in the North American natural gas market. The prices in these contracts may be indexed to Alberta, Michigan and Chicago based prices.
Transportation
Union Gas’ transmission system consists of approximately 4,900-kilometers (3,045-miles) of high-pressure pipeline and five mainline compressor stations. Key pipeline interconnects in Canada and the United States enabled Union Gas to deliver approximately 774 Bcf of gas through Union Gas’ transmission system in 2017. Union Gas’ transmission system also links an extensive network of underground storage pools at Dawn to major Canadian and United States markets. There are multiple pipelines providing access to Dawn. Customers can purchase both firm and interruptible transportation services on the Union Gas system. As the supply of natural gas in areas close to Ontario continues to grow, there is an increased demand to access these diverse supplies at Dawn and transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern United States. To secure the continued reliable delivery of natural gas and to serve a growing demand for natural gas, Union Gas has invested $1.5 billion between 2015 and 2017 to expand the Dawn-Parkway natural gas transmission system. This has increased the takeaway capacity from Dawn to approximately 20 percent or from 6.3 bcf/d in 2014 to more than 7.5 bcf/d in 2017. A substantial amount of Union Gas’ transportation revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately 11 years, with the longest remaining contract term being 15 years.
Storage
Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 Bcf in 25 underground facilities located in depleted gas fields. Union Gas’ storage pools give customers access to all Dawn storage capacity and deliverability.northeast US. Dawn's configuration provides flexibility for injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services at Dawn. Dawn offers customers a wide range of market choices and options with easy access to upstream and downstream markets. During 2017,2020, Dawn provided services such as storage, balancing, gas loans, transport, exchange and peaking services to over 140200 counterparties.
A substantial amount of UnionEnbridge Gas’ storage revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately fivefour years withand the longest remaining contract term being 19 years.16 years.
NOVERCO
Noverco is a holding company that wholly-owns Énergir, LP (Énergir), formerly known as Gaz Metro Limited Partnership, a natural gas distribution company operating in Quebec, with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in Québec and Vermont. Énergir serves approximately 525,000 residential and industrial customers and is regulated by the Québec Régie de l’énergie and the Vermont Public Utility Commission. Noverco also holds an investment in our common shares. We own an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in its preferred shares. Noverco is a holding company that owns approximately 71% of Energir LP, formerly known as Gaz Metro Limited Partnership,
GAZIFÈRE
We wholly own Gazifère, a natural gas distribution company operatingthat serves approximately 43,000 customers in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the Province of Quebec and the State of Vermont. Noverco also holds, directly and indirectly, an investment in our Common Shares.
OTHER GAS DISTRIBUTION AND STORAGE
Other Gas Distribution and Storage includes natural gas distribution utility operations in the Provinces of New Brunswick and Quebec.
Enbridge Gas New Brunswick Inc. operates the natural gas distribution franchise in the Province of New Brunswick, has approximately 11,800 customers andwestern Québec, a market not served by Énergir. Gazifère is regulated by the New Brunswick Energy and Utilities Board (EUB).Québec Régie de l’énergie.
Gazifere is one of two distributors in Quebec serving more than 40,000 residential, commercial, institutional and industrial customers. GazifereCOMPETITION
Enbridge Gas’ distribution system is regulated by the Quebec Regie de l’energie.OEB and is subject to regulation in a number of areas, including rates. Enbridge Gas is not generally subject to third-party competition within its distribution franchise areas.
GREENEnbridge Gas competes with other forms of energy available to its customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include weather, price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels and other factors.
SUPPLY AND DEMAND
We expect that demand for natural gas in North America will continue to see low annual growth over the long term with continued growth in peak day demands. We expect demand for natural gas connections in Ontario to continue to grow due to continued population growth. Some modest growth driven by low natural gas prices is expected to continue given the significant price advantage relative to alternate energy options, even with increasing carbon charges, with specific interest coming from communities that are not currently serviced by natural gas. Enbridge Gas continues to focus on promoting conservation and energy efficiency by undertaking activities focused on reducing natural gas consumption through various demand side management programs offered across all markets.
The storage and transportation marketplace continues to respond to changing natural gas supply dynamics including a robust supply environment. In recent years, the robust North American gas supply balance, due mainly to the development of unconventional gas volumes including the Alberta, British Columbia, Marcellus and Utica supply basins, has resulted in lower commodity prices and narrower seasonal price spreads. Unregulated storage values are primarily determined based on the difference in value between winter and summer natural gas prices. Storage values have been relatively stable to slightly rising as the North American natural gas supply and demand slowly returned to a more balanced position.
RENEWABLE POWER & TRANSMISSIONGENERATION
Green
Renewable Power and TransmissionGeneration consists primarily of our investments in renewable energywind and solar assets, and transmission facilities. Renewable energy assets consist of wind, solar,as well as geothermal, and waste heat recovery, facilities and transmission assets. In North America, assets are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development located in Europe.
Green Power and Transmission includes approximately 2,500 MW of net operating renewable and alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity comes from wind farms located in the provinces of Alberta, Saskatchewan, Ontario, and QuebecQuébec and approximately 1,040 MW of net power generating capacity comes from wind farms located in the states of Colorado, Texas, Indiana and West Virginia, includingVirginia. In Europe, we hold equity interests in operating offshore wind facilities in the 249coastal waters of the United Kingdom and Germany, as well as in several projects under construction and active development in France. Further, we are pursuing new European development opportunities through Maple Power Ltd., a joint venture in which we hold a 50% interest.
Combined Renewable Power Generation investments represent approximately 1,977 MW Chapman Ranchof net generation capacity. Of this amount, approximately:
•1,392 MW is generated by North American wind facilities;
•255 MW is generated by European offshore wind facilities;
•211 MW will be generated by the Saint-Nazaire and Fécamp Offshore Wind Project (Chapman Ranch)projects, both of which are currently under construction; and
•80 MW is generated by North American solar facilities in Texas, which was placed into serviceoperation, with an additional 13 MW in late October 2017. projects under construction.
The vast majority of the power produced from these wind farmsfacilities is sold under long-term power purchase agreements. WePower Purchase Agreements (PPAs).
Renewable Power Generation also have three solar facilities locatedincludes the East-West Tie, a 450-MW transmission line in northwestern Ontario, which is currently under construction and a solar facility locatedis expected to reach commercial operation in Nevada, with 100 MW and 50 MW, respectively,the first half of net power generating capacity. Also included in Green Power and Transmission is2022. In May 2020, we sold the Montana-Alberta Tie-Line our first power(MATL), a 300-MW transmission asset, a 300 MW transmission line running from Great Falls, Montana to Lethbridge, Alberta. For further information refer to Part II. Item 8. Financial Statements and Supplementary Data -Note 8. Dispositions.
In June 2017, we announced an additional 112 MW of investmentJOINT VENTURES / EQUITY INVESTMENTS
The investments in the partnership that holdsCanadian renewable assets and two of the 610 MW Hohe See Offshore Wind ProjectUS renewable assets are held within a joint venture in Germany, wherewhich we have an effective 50% interest. Earliermaintain a 51% interest and continue to manage, operate, and provide administrative support.
We also own interests in 2016, we announced the acquisition of Chapman Ranch, as well as the acquisition of a 50% interest in a FrenchEuropean offshore wind development company, Éolien Maritime France SAS. Chapman Ranch was subsequently placed into service in late October 2017. In late 2015, we announced acquisitions offacilities through the 103-MW New Creek Wind Project in West Virginia and following joint ventures:
•a 24.9% interest in the 400 MW Rampion Offshore Wind, Projectlocated in the United Kingdom. Including these acquisitions, we have invested over $5 billionKingdom, which went into service April 2018;
•a 25% interest in renewable power generationHohe See Offshore and transmission since 2002.its subsequent expansion, located in Germany, which went into service October 2019 and January 2020, respectively;
•a 25.5% interest in the Saint-Nazaire Offshore Wind project, located in France, which is currently under construction; and
Competition•a 17.9% interest in the Fécamp Offshore Wind project, under construction in France.
The ownership interest percentages in the Saint-Nazaire and Fécamp Offshore Wind projects reflect the sale of 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) which is expected to close in the first half of 2021.
COMPETITION
Our GreenRenewable Power and TransmissionGeneration assets operate in the North American and European power markets, which are subject to competition and the supply and demand balancefundamentals for power in the provinces and statesjurisdictions in which they operate. The majority of revenue is generated pursuant to long-term PPAs or has been substantially hedged. As such, the financial performance is not significantly impacted by fluctuating power prices arising from supply/demand imbalances or the actions of competing facilities during the term of the applicable contracts. However, the renewable energy market sector includes large utilities, and small independent power producers and private equity investors, which are expected to aggressively compete with us for new project development opportunities.opportunities and for the right to supply customers when contracts expire.
SupplyTo grow in an environment of heightened competition, we strategically seek opportunities to collaborate with well-established renewable power developers and Demandfinancial partners and to target regions with commercial constructs consistent with our low risk business model. In addition, we bring to bear the expertise of completing and delivering large scale infrastructure projects.
SUPPLY AND DEMAND
The renewable power generation and transmission network in North America and Europe is expected to undergo significant growthgrow significantly over the next 20 years. years due to the replacement of older fossil fuel-based sources of electricity generation in support of announced governmental carbon emissions reduction targets. Any additional governmental actions toward reducing emissions and/or increasing electrification will further accelerate renewable electricity demand growth and electrification across all sectors.
On the demand side, North American economic growth over the longer term isand the continued electrification and decarbonization of the residential, transportation and industrial sectors are expected to drive growing electricity demand, althoughdemand. However, continued efficiency gains are expected to make the economy less energy-intensive and temper overall demand growth.
On the supply side impendingin North America, legislation in Canada is expected to accelerateaccelerating the retirement of aging coal-fired generation, plants, resulting inwhile generation from nuclear power is also forecast to decline. As a requirement forresult, North America requires significant new generation capacity. While coalcapacity and nuclear facilities will continue to be core componentsthe extension of power generation in North America, gas-firedproject lives and/or PPAs of preferred technologies. Gas-fired and renewable energy facilities, including biomass, hydro, solar and wind (which make up the bulk of our renewable power assets), are expected to begenerally the preferred sources to replace coal-fired generation due to their lowerlow carbon intensities.
North American windThe falling capital and solar resources fundamentals remain strong. In the United States, there is over 85 gigawatts (GW) of installed wind power capacity and in Canada over 12 GW of installed wind power capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 35 GW of installed solar photovoltaic capacity. In late 2015, the United States passed legislation extending the availability of certain Federal tax incentives which have supported the profitabilityoperating costs of wind and solar, projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generationcombined with their continuously improving capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not in close proximity to markets. In the near-term, uncertainty over the availability of tax or other government incentives in various jurisdictions, the ability to secure long-term power purchase agreements through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new renewable capacity development. However, continued improvement in technology and manufacturing capacity in the past few years has reduced capital costs associated with renewable energy infrastructure and has also
improved yield factors, of power generation assets. These positive developments are expected to rendercontinue the ongoing trend of making renewable energy more competitive and support ongoing investment over the long term.long-term, regardless of available government incentives. Generation from renewable sources is expected to double over the next two decades in North America. Aside from the construction of new wind and solar facilities, other growth opportunities include repowering projects to increase output from, and extending the project-life of, our existing facilities.
In Europe, the future outlook for renewable energy especially from offshore wind in countries with long coastlines and densely populated areas,outlook is very positive. According to the European Wind Energy Association, by 2030, wind energy capacity in Europerobust. Demand for electricity is expected to be 320 GW,gradually increase over the next two decades, driven by electrification of transportation and buildings. Energy efficiency gains will temper, but not eliminate, demand growth. Renewable power will play a significant role in Britain and the European Union’s ability to meet their aggressive low-carbon and renewable energy targets, particularly wind and offshore wind.
On the supply side, the International Energy Agency expects coal to fall by more than 90%, while nuclear falls by one-third, by 2040. Over the same period, it anticipates power generation from renewable sources will more than double, including 66 GW ofinstalled (onshore and offshore) wind more than doubling and photovoltaics solar power nearly tripling. We, through our European joint ventures, continue to invest in offshore capacity.There is also wide public support for carbon reduction targetswind projects in the United Kingdom, France and broader adoption of renewable generation across all governmental levels. Furthermore, governments in Europe are seekingGermany to rationalizemeet the contribution of nuclear power to the overall energy mix, which has resulted in an increased focus on alternative sources such as large scale offshore wind.growing demand.
ENERGY SERVICES
The Energy Services businesses in Canada and the United States undertakeUS provide physical commodity marketing activity and logistical services, oversee refinery supply services and manage our volume commitments on various pipeline systems.
Energy Services provides energy supply and marketing services to North American refiners, producers, and other customers. Crude oil and NGL marketing services are provided by Tidal
Energy Marketing Inc. (Tidal). We transact at many North American market hubs and provides our customers with various services, including transportation, storage, supply management, hedging programs and product exchanges. TidalServices is primarily a physical barrel marketing company focused on servicing customers across the value chain and capturing value from quality, time, and location price differentials when opportunities arise. To execute these strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rightstransports and stores on both Enbridge-owned and third party assets using a combination of contracted long-term and Enbridge-owned pipelinesshort-term pipeline, storage tank, railcar, and storage facilities. Tidal also provides natural gas and power marketing services, including marketing natural gas to optimize commitments on certain natural gas pipelines. Additionally, Tidal provides natural gas supply, transportation, balancing and storage for third parties, leveraging its natural gas marketing expertise and access to transportation capacity.truck capacity agreements.
COMPETITION
Energy ServicesServices’ earnings are primarily generated from arbitrage opportunities which, by their nature, can be replicated by other competitors. An increase in market participants entering into similar arbitrage transactionsstrategies could have an impact on our earnings. Our effortsEfforts to mitigate competition risk includesinclude diversification of ourthe marketing business by tradingtransacting at the majority of major hubs in North America and establishing long-term relationships with clients.clients and pipelines.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs and foreign exchange costs whichthat are not allocated to business segments.segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includesnew business development activities and general corporate investments.
INSURANCE
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and our affiliates. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry.
Although we believe our current coverage is adequate for our purposes, we have in the past had occurrences that led to losses exceeding our then-applicable coverage limits, and there is no assurance
that the same may not happen in the future. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries.
OPERATIONAL, ENVIRONMENTAL AND ECONOMIC REGULATION
LIQUIDS PIPELINES
Operational Regulation
Operational regulation risks relateWe are subject to compliance with applicablenumerous operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.
Regulatory scrutiny over the integrity of liquids pipeline assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on our future earnings and the cost related to the construction of new projects. We believe operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. We also develop robust response plans to regulatory changes or enforcement actions. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on us.
In the United States,US, our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the of the United States Department of Transportation (DOT). These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These laws and regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressurespipelines and to operate them at which our pipelines can operate.permissible pressures.
PHMSA is designing an Integrity Verification Process intended to createhas revised existing regulations and promulgated new regulations establishing safety standards to verify maximum allowable operating pressure, andthat are designed to improve and expand integrity management processes. Additionally, PHMSA will establish standards for storage facilities. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failuresfailure or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, earnings, cash flows and financial condition and cash flows.condition.
In Canada, our pipeline operations are subject to pipeline safety regulations overseenadministered by the NEBCER or provincial regulators. Applicable legislation and regulationregulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.
As in the United States,US, several legislative changes addressing pipeline safety in Canada have recently come into force.been enacted. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the NEBCER to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.
A key component of Liquids Pipelines safety and reliability is the approach to integrity management that uses reliability targets and safety case assessments. A long history of extensive inline inspection has provided detailed knowledge of the assets in the liquids pipeline system. Every segment of every pipeline is assessed and maintained, in a proactive manner, such that the probability of a leak is sufficiently low and that stringent reliability targets are met. Furthermore, the integrity management program has an independent step to check the results of our integrity assessments to validate the effectiveness of the program and to ensure that that the operational risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle. As inspection technology, pipeline materials and construction practices improve with time, and new data on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves; with a strong focus on continual improvement in every aspect of integrity management.
Environmental Regulation
We are also subject to numerous federal, state and provincial environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits inspections and other approvals.
In particular, in the United States,US, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs is likely tomay significantly increase our operating costs compared to historical levels.
In the United States,US, climate change action is evolving at federal, state regional and federalregional levels. The Supreme Court decision in Massachusetts v. EPAEnvironmental Protection Agency in 2007 established that greenhouse gas (GHG)GHG emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs, (exceptGHGs. The new US presidential administration has also announced that policies designed to the extent that some GHGs consist of volatile organic compoundscombat climate change and nitrous oxides thatreduce GHG emissions will be a key legislative and regulatory priority, and thus stricter emissions limits and air quality enforcement actions are subject to emission limits).possible In addition, a number of provinces and states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.
For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the United States. WhileUS. In 2019, the Government of Canada implemented a federal GHG related regulatory design details remain forthcoming, provincial authorities have been actively pursuing related initiatives.
Failuresystem of carbon pricing. The pricing applies to comply with environmental regulations may result in the imposition of fines, penaltiesprovinces and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We mayterritories that do not be able to obtain or maintain all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future will have a significant effect on our earningscarbon pricing system in place that meets the federal benchmark. On November 19, 2020, the federal Minister of Environment and cash flows.Climate Change introduced Bill C-12, the Canadian Net-Zero Emissions Accountability Act, which requires national targets for the reduction of GHG emissions in Canada be set, with the objective of attaining net-zero emissions by 2050. In December 2020, the Government of Canada announced plans to increase the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030.
Due to the speculative outlook regarding any United StatesUS federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
Economic Regulation
Our liquids pipelines also face economic regulatoryregulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements including permits and regulatory approvals for both new projects. The Canadianand existing projects, upon which future and current operations are dependent. Our Mainline Lakehead System and other liquids pipelines are subject to the actions of various regulators, including the
NEB CER and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings. Delays in regulatory approvals on projects such as our L3R Program, could result in cost escalations and construction delays, which also negatively impact our operations.
We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of our liquids pipeline assets. We also involve our legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite our efforts to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements that we have entered into with shippers or deny the approval and permits for new projects.
GAS TRANSMISSION &AND MIDSTREAM
Operational Regulation
The span of regulatoryregulation risks that apply to the Liquids PipelinePipelines business as described above under Liquids Pipelines also applies to the Gas Transmission and Midstream business. Additionally, mostMost of our United StatesUS gas transmission operations are regulated by the FERC. The FERC regulates natural gas transmission in United StatesUS interstate commerce including the establishment of rates for services. The FERC also regulates the construction of United StatesUS interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transmission of gas by intrastate pipelines.
Texas Eastern reached an agreement with its shippers and filed a Stipulation and Agreement with the FERC on October 28, 2019. On February 25, 2020, Texas Eastern received approval from the FERC of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020. On July 2, 2020, Algonquin received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020. East Tennessee filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020. The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we will await FERC approval. The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval. In July 2020, the 2020-2021 rate settlement agreement with Westcoast's BC Pipeline shippers was approved by the CER. Following approval of the settlement, Westcoast applied and received approval from the CER on August 12, 2020 for the interim tolls to be made final, including the interim tolls from January 1, 2020 to March 31, 2020 as well as the revised interim tolls in effect as at April 1, 2020.
Our SEP and DCP Midstream operations are subject to the jurisdiction of the Environmental Protection Agency and various other federal, state and local environmental agencies. Our United StatesUS interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the DOT concerning pipeline safety.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state regulation. DCP Midstream's interstate NGL transportation pipelines are subject to FERC regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline safety, including the NEB andCER, the Transportation Safety Board the British Columbia Oil and Gas Commission, the Alberta Energy Regulator and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission and distribution operations and approximately two-thirds of the storage operations in Canada are subject to regulation by the NEBCER or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities and acquisitions. Our British Columbia PipelineIn addition, these assets are subject to GHG emissions regulations, including GHG emissions management and British Columbia Field Services businesscarbon pricing policies. Across Canada there are a variety of new and evolving initiatives in westerndevelopment at the federal and provincial levels aimed at reducing GHG emissions. The Government of Canada is regulated by the NEB pursuanthas finalized a federal plan to a framework for light-handed regulation under which the NEB acts on a complaints-basis for rates associated with that business. Similarly, the rates charged by ourhave carbon pricing in place in all Canadian Gas Transmission and Midstream operations for gathering and processing services in western Canada are regulated on a complaints-basis by applicable provincial regulators.jurisdictions.
GAS DISTRIBUTION AND STORAGE
EconomicOperational Regulation
Our gas distribution and storage utility operations are regulated by the OEB and the EUBQuébec Régie de l’énergie, among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or amounts that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year incentive regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).
We seek to mitigate economicoperational regulation risk. We retain dedicated professional staff and maintain strong relationships with customers, intervenors and regulators. This strong regulatory relationship continued in 2020 following OEB Decisions and Ordersapproving Phase 2 of Enbridge Gas’ application for 2020 rates and Phase 1 of Enbridge Gas’ application for 2021 rates. The termsPhase 2 Decision and Order approved the recovery of requested 2020 discrete incremental capital investments through the incremental capital module, while the Phase 1 Decision and Order approved 2021 base rate negotiations are reviewed by our legal, regulatory and finance teams.escalation under the price cap mechanism.
Enbridge Gas Distribution
Distribution rates are set underhas continued to develop opportunities to support a five-year customized incentive rate plan (IR Plan)low carbon future in Ontario. In 2020, the OEB approved Enbridge Gas' application to implement a voluntary RNG pilot program, whereby customers can voluntarily contribute towards the incremental cost of low carbon RNG which would displace regular natural gas.The OEB also approved Enbridge Gas' pilot project to construct facilities that will allow regular natural gas to be blended with hydrogen gas, in 2014 and provide a levelan isolated portion of stability by having a long-term agreementthe existing distribution system, with the OEB which allows usintent to recover our expected capital investments under the agreement, as well as an opportunity to earn above the OEB allowed ROE. Under the customized IR Plan, we are permitted to recover, with OEB approval, certain costs that were beyond management control, but that were necessary for the maintenance of our services. The customized IR Plan also includes a mechanism to reassess the customized IR Plan and return to cost of service if there are significant and unanticipated developments that threaten the sustainability of the customized IR Plan.
Union Gas
Distribution rates, beginning in 2014, are set under a five-year incentive regulation framework using price cap methodology. The price cap framework establishes new rates at the beginning of each year throughgain insight into the use of hydrogen as a pricing formula rather than through the examination of revenue and cost forecasts. The framework allowsmethod for annual inflationary rate increases, offset by a productivity factor, as well as rate increases or decreases in the small volume customer classes where use declines or increases, and certain adjustments to base rates. Further, it allowsdecarbonizing natural gas for the continued pass-throughpurpose of gas commodity, upstream transportation and demand side management costs, the additional pass-through of costs associated with major capital investments and certain fuel variances, an allowance for unexpected cost changes that are outside of management’s control, and equal sharing of tax changes between Union Gas and customers, and finally an opportunity to earn above the OEB allowed ROE.reducing GHG emissions.
Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which regulate the protection of the environment and the health and safety of workers. For the environment,Environmental legislation primarily this includes the regulation of discharges to air, land and water; theenvironmental assessment of natural gas infrastructure projects in Ontario; protection of species at risk and species at risk habitat; management and disposal of solidhazardous waste; the assessment and hazardous waste, andmanagement of contaminated soil and groundwater;sites; and the assessmentreporting and reduction of contaminated sites.GHG emissions.
The operation of our gasGas distribution system and gas facilities comesoperation, as with any industrial operation, has the potential risk of incidents, abnormal operatingor emergency conditions, or other unplanned events that could result in spillsleaks or emissions to the environment that could exceedin excess of permitted levels. These events could result in injuries to workers or the public, fines, penalties, adverse impacts to the environment in which we operate, within, and/property damage or property damage.regulatory violations including orders and fines. We could also incur future liability for environmental (soilsoil and groundwater)groundwater contamination associated with past and present site activities.
In addition to the operation of the gas distribution, system, we also operate unregulated operations includingstorage facilities and a small amount of oil and brine production and storage facilities in southwestern Ontario. Environmental risk associated with these facilities is the possibility of spills, releases or leaks.potential for unplanned releases. In the event of an incident (spill),a release, remediation of the affected area would be required. There would also be potential for fines, orders
or charges under environmental legislation, and potential third-party liability claims by any affected land owners.landowners.
The gas distribution system and our other operations must maintain a number of environmental approvals and permits from governmental authoritiesregulators to operate. As a result, these facilitiesassets and the distribution networkfacilities are subject to periodic inspection. Aninspections and/or audits. Annual reports, such as the Annual Written Summary Report isare submitted to the Ontario Ministry of the Environment, Conservation and Climate Change (MOECC)Parks (MECP) and other regulators to demonstrate we are in good standing in relation to itswith our Environmental Compliance Approvals. Failure to maintain regulatory compliance could result in operational interruptions, fines, penalties, and/or orders for additional pollution control technology or environmental remediation, etc.mitigation. As environmental requirements and regulations become more stringent, the cost to maintain compliance and the time required to obtain approvals has consistently increased.
Ontario commenced a cap and trade system on January 1, 2017. Under the cap and trade regulation, EGD and Union Gas (together, the Utilities) are required to purchase emission allowances or credits for most of our customers’ use of natural gas as well as for emissions from our own operations. This process is complex and requires ongoing monitoring of the carbon market and related climate change and carbon policies not only in Ontario but also in other newly linked jurisdictions as at January 1, 2018 - namely California and Quebec. This linkage which has been enabled in Ontario with various GHG reporting and cap and trade regulation amendments over the course of 2017 will create a larger and more liquid market for carbon allowances and credits, which may help to keep compliance costs for our customers down. However, non-compliance or unexpected policy changes may cause significant changes to the cost of maintaining compliance and needs to be closely monitored to ensure impacts are understood.
As required by the OEB Cap and Trade Framework, the Utilities each submitted 2017 Compliance Plans, which subsequently received supportive endorsement and approval of cost recovery in 2017 rates. The Utilities are in the process of defending their individually filed 2018 Compliance Plans. The OEB approved use of the 2017 final rate for recovery of 2018 cap and trade compliance costs until determined otherwise. Further, the OEB Cap and Trade Framework identifies that the Utilities are expected to file 2019/2020 Compliance Plans as well as an Annual Report summarizing 2017 results by August 1, 2018. The Compliance Plans detail how the Utilities will meet their respective carbon compliance obligations through carbon allowance and/or offset procurement as well as through customer and facility abatement projects that may be deemed cost effective. By creating prudent and thoughtful plans and executing with excellence, the Utilities can best mitigate the risk of cost disallowance.
As with previous years, in 2017 the Utilities each2020, we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to the Ontario MOECC, Environment and Climate Change Canada (ECCC), the Ontario MECP, and a number of voluntary reporting programs. Emissions from OntarioIn accordance with the provincial GHG regulations, stationary combustion sourcesand flaring emissions related to storage and transmission operations were verified in detail by a third partythird-party accredited verifier with no material discrepancies found. Additionally, operational emissions from venting, fugitive and natural gas distribution emissions were reported to the MOECC for the first time in 2017 in accordance with O. Reg. 143/16 - Quantification, Reporting, and Verification of Greenhouse
Enbridge Gas Emissions Regulation standard quantification methods ON. 350 and ON. 400, respectively. The Utilities continue to monitor developments and attend stakeholder consultations in Ontario.
The Utilities utilizeutilizes emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors will continually be updated in the system as required. Each Utility publicly reports its GHG emissions and has developed internal procedures for more frequent monthly Cap and Trade related GHG reporting. Collectively, the Utilities continueEnbridge Gas continues to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.
In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an output-based pricing system (OBPS).
The Utilitiesfederal carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural gas and is applicable to the majority of customers. Enbridge Gas is registered as a natural gas distributor with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge increases annually on April 1 of each year by 1.96 cents/m3, rising up to 9.79 cents/m3 in 2022. In December 2020, the federal government announced plans to reduceincrease the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030. Enbridge Gas estimates that this will equate to a federal carbon charge on natural gas of approximately 33.31 cents/m3 in 2030.
The OBPS component came into effect on January 1, 2019. Under OBPS, a registered facility has a compliance obligation for the portion of their emissions in 2018 are outlinedthat exceeds their annual facility emissions limit, which is calculated based on the sector specific output-based standard and annual production. Enbridge Gas is registered with ECCC as an emitter in the Facility Abatement Plan within their respective Compliance Plans.OBPS program and has an annual compliance obligation associated with the combustion and flaring emissions associated with its natural gas pipeline transmission system. As a registered facility under OBPS,Enbridge Gas submitted an annual report along with the required verification report from an accredited third-party verifier who found no material misstatements. Enbridge Gas is required to remit payment for facility emissions that exceed its annual facility emissions limit. Due to COVID-19, ECCC has delayed the payment deadline from December 15, 2020 to April 15, 2021, and therefore Enbridge Gas has deferred payment until the first half of 2021.
In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. The date of the transition has not yet been communicated. Enbridge Gas will continue to have a compliance obligation under either the OBPS or EPS program for its facility-related emissions, as well as the federal carbon charge for its customer-related emissions.
EMPLOYEES
We had approximately 12,700 employees asHUMAN CAPITAL RESOURCES
WORKFORCE SIZE AND COMPOSITION
As at December 31, 2017,2020, we had approximately 11,200 regular employees, including approximately 8,5001,600 unionized employees in Canada. Approximately 1,800 ofacross our North American operations. This total rises to more than 13,000 if including temporary employees are subject to collective bargaining agreements governing theirand contractors. We have a strong preference for direct employment with us. Approximately 48% of thoserelationships but where we have collectively bargained for employees, are covered under agreements that either have expired or will expire by December 31, 2018. We are currently going through the process of collective bargaining in respect to the expired or expiring contracts. Wewe have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.
EXECUTIVESWe believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on employee and contractor safety continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents. Refer also to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments- COVID-19 Pandemic, Reduced Crude Oil Demand and Commodity Prices.
DIVERSITY AND OTHERINCLUSION
To ensure our workforce is reflective of the communities where we operate, we have pursued efforts to increase the representation of women, ethnic and racial groups, people with disabilities and veterans. Our original ambitions were set and shared with employees in 2018 with progress toward achievement shared regularly through our Diversity Dashboard. While we have made strong progress, we are accelerating the pace of our program and we have plans in place to meet our objectives by 2025. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.
In early 2021, we added Inclusion to our core values of Safety, Integrity and Respect to demonstrate this commitment.
We are building an organization where people feel safe and welcome and have the opportunity to thrive and grow based on merit. As part of our evolving ESG strategy, we wanted to create a tighter link between our success and the workforce related ESG measures – including safety and diversity – that enable it. As a result, beginning in 2021, key metrics in these areas are embedded in our scorecards and directly impact compensation.
PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development because we recognize their success is our success. Every year, employees are provided a range of development opportunities through a variety of channels, including: educational reimbursement programs; developmental relationships with mentors; rotational assignments; and Enbridge University, which offers a large catalog of courses.
EXECUTIVE OFFICERS
The following table sets forth information regarding our executive and other officers.
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| | | | | | | |
Name | Age | Position |
Al Monaco | 5861 | President & Chief Executive Officer |
JohnColin K. WhelenGruending | 5851 | Executive Vice President & Chief Financial Officer |
Cynthia L. Hansen | 53 | Executive Vice President, Utilities & Power Operations |
D. Guy Jarvis | 54 | Executive Vice President, Liquids Pipelines |
Byron C. Neiles | 52 | Executive Vice President, Corporate Services |
Robert R. Rooney | 6164 | Executive Vice President & Chief Legal Officer |
William T. Yardley | 5356 | Executive Vice President & President, Gas Transmission &and Midstream |
Vern D. YuCynthia L. Hansen | 5156 | Executive Vice President & Chief Development OfficerPresident, Gas Distribution and Storage |
AllenByron C. CappsNeiles | 4755 | Executive Vice President, Corporate Services |
Vern D. Yu | 54 | Executive Vice President & Chief Accounting OfficerPresident, Liquids Pipelines |
Matthew Akman | 53 | Senior Vice President, Strategy & Power |
Allen C. Capps | 50 | Senior Vice President, Corporate Development & Energy Services |
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. HeMr. Monaco is also a member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco served as President, Gas Pipelines, Green Energy &and International with responsibility for the growth and operations of our gas pipelines, including the gas gathering and processing operations in the United States,US, our gulf coastGulf Coast offshore assets and our investments in Alliance Pipeline, Vector and Aux Sable, as well as our International business development and investment activities and Green Energy.Renewable Power Generation.
Colin K. WhelenGruending was appointed Executive Vice President and Chief Financial Officer of Enbridge on October 15, 2014.June 1, 2019. Previously, our Senior Vice President, Corporate Development and Investment Review, Mr. Gruending performed a number of progressively challenging executive roles such as Vice President Corporate Development and Planning and Vice President, Treasury and Tax while concurrently serving as Chief Financial Officer for Enbridge Income Fund and Enbridge Income Fund Holdings Inc. Prior to that, Mr. Gruending served as Corporate Controller and also led enterprise Investor Relations and Pension Investments.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Whelen retained executive leadership forRooney leads our financial reporting function, while assuming responsibility for our taxlegal, ethics and treasury functions.compliance, security and aviation teams across the organization.
William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream on February 27, 2017. Mr. Whelen has been partYardley, based in Houston, was previously President of Spectra Energy Corp's. (Spectra Energy) US Transmission and Storage business, leading the Enbridge team since 1992, when he assumed the Managerbusiness development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s US portfolio of Treasury role at Consumers Gas (now EGD).assets.
Cynthia L. Hansen was appointed Executive Vice President Utilities and Power Operations,President, Gas Distribution and Storage, on February 27, 2017.June 1, 2019. Ms. Hansen is responsible for the overall leadership and operations of EGDEnbridge Gas, following the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), as well as Enbridge Gas New Brunswick Inc. and Gazifère. She also holds responsibility for the operations ofPreviously, our power generating assets, which currently include renewable energy investments in wind, solar, geothermal and hydroelectric, as well as waste heat recovery facilities and power transmission lines owned in whole or in part by us.
D. Guy Jarvis was appointed Executive Vice President, Liquids PipelinesUtilities and Major Projects on May 2, 2016. Mr. Jarvis has been President of our Liquids Pipelines group since March 1, 2014,Power Operations, Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with responsibility for all of our crude oil and liquids pipeline businesses across North America. Mr. Jarvis previously held the title of Chief Commercial Officer for Liquids Pipelines, with responsibility for strategicother business unit leaders.
and integrated services, customer service, finance, and business and market development. Prior to Mr. Jarvis' work in Liquids Pipelines, he served as President, Gas Distribution, providing overall leadership to EGD, as well as Enbridge Gas New Brunswick Inc. and Gazifère.
Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles has oversight of our Technology & Information Technology,Services, Human Resources, Real Estate, Safety & Workplace Services,Reliability, Supply Chain Management, Enterprise Safety and Operational Reliability, and aviation groups.Public Affairs, Communications & Sustainability. Mr. Neiles had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational Reliability and had been Senior Vice President of Major Projects since November 2011, after joining our Major Projects group in April 2008.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Rooney leads our legal team across the organization, as well as Public Affairs and Communications (including Corporate Social Responsibility).
William T. Yardley was named Executive Vice President and President of Gas Transmission and Midstream on February 27, 2017. Mr. Yardley is also the President and Chairman of the Board of SEP. Mr. Yardley, based in Houston, was previously President of Spectra Energy’s United States Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s United States portfolio of assets.
Vern D. Yu was appointed Executive Vice President and Chief Development OfficerPresident, Liquids Pipelines on May 2, 2016. Mr. Yu leads our Corporate Development team in driving growth opportunities, while also establishing capital allocation parameters and portfolio mix. Mr. Yu also provides executive oversight to our Energy Services group, Tidal Energy.January 1, 2020. Previously, Mr. Yu served as President and Chief Operating Officer for Liquids Pipelines and prior to that served as Executive Vice President and Chief Development Officer. He had previously served as Senior Vice President, Corporate Planning and Chief Development Officer. He has been the lead of ourPrior to joining Corporate Development, team since July 1, 2014.Mr. Yu served as Senior Vice President of Business and Market Development for Enbridge’s Liquids Pipelines division and previously has held a series of roles with increasing responsibility in our corporate and financial areas.
Matthew Akman is our Senior Vice President, Strategy and Power. He is responsible for the corporate strategic planning process and all renewable power operations and development globally. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations. Prior to joining Enbridge, Mr. Akman worked primarily in banking with a focus on institutional equity research.
Allen C. Capps is theour Senior Vice President, Corporate Development and Chief Accounting Officer of Enbridge. Mr. CappsEnergy Services. He is responsible for our accounting operationscapital allocation, investment review, corporate business development and financial reporting functions, including internal and external financial reports.Energy Services. Prior to assuming his current role in 2017,June 2019, Mr. Capps served as our Senior Vice President and Chief Accounting Officer and before that Vice President and Controller of Spectra Energy, responsible for the financial accounting and reporting functions.Energy.
ADDITIONAL INFORMATION
Additional information about us is available on our website at www.enbridge.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.Securities and Exchange Commission (SEC). Reports, proxy statements and other information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov) or by visiting the Public Reference Room of the SEC at 100 F Street, N.E., Washington D.C. 20549 or calling the SEC at 1-800-SEC-0330..
ENBRIDGE ENERGY PARTNERS, L.P. AND ENBRIDGE ENERGY MANAGEMENT, L.L.C.
Additional information about EEP and Enbridge Energy Management, L.L.C. can be found in their Annual Reports on Form 10-Ks that have been filed with the SEC. These documents contain detailed disclosure with respect to EEP and Enbridge Energy Management, L.L.C., respectively, and are publicly available on EDGAR at www.sec.gov. No part of the Form10-Ks filed by EEP and Enbridge Energy Management, L.L.C. are, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE GAS DISTRIBUTION INC.
Additional information about EGDEnbridge Gas can be found in its annual information form, financial statements and management's discussion and analysis (MD&A) for the year ended December 31, 20172020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EGDEnbridge Gas and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND
Additional information about the Fund can be found in its annual information form, financial statements and MD&A as well as the financial statements and MD&A of EIPLP for the year ended December 31, 2017 which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to the Fund and are publicly available on SEDAR at www.sedar.com under the Fund's profile. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE INCOME FUND HOLDINGSPIPELINES INC.
Additional information about ENFEnbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to ENF and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE PIPELINES INC.
Additional information about EPI can be found in its annual information form, financial statements and MD&A for the year ended December 31, 20172020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
SPECTRAWESTCOAST ENERGY PARTNERS, L.P.INC.
Additional information about SEP can be found in its Annual Report on Form10-K that has been filed with the SEC. This document contains detailed disclosure with respect to SEP, and is publicly available on EDGAR at www.sec.gov. No part of the Form 10-K filed by SEP is, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
UNION GAS LIMITED
Additional information about Union GasWestcoast can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2017 which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Union Gas and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
WESTCOAST ENERGY INC.
Additional information about Westcoast Energy Inc. can be found in its annual information form, financial statements and MD&A for the year ended December 31, 20172020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast Energy Inc. and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ITEM 1A. RISK FACTORS
Execution of our capital projects subjects us to various regulatory, development, operationalThe following risk factors could materially and market risks that may affect our financial results.
Our ability to successfully execute the development of our organic growth projects is subject to various regulatory, development, operational and market risks, including:
the ability to obtain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and to maintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
potential changes in federal, state, provincial and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;
impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
opposition to our projects by third parties, including special interest groups;
the availability of skilled labor, equipment and materials to complete projects;
the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier non-performance, weather, geologic conditions or other factors beyond our control, that may be material;
general economic factors that affect the demand for our projects; and
the ability to raise financing for these capital projects.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. Recent projects that have experienced delays include the United States portion of the L3R Program (U.S. L3R Program) and NEXUS. In the fourth quarter of 2016, we determined Northern Gateway could not proceed as envisioned. New projects may not achieve their expected investment return, which could affect our financial results, and hinder our ability to secure future projects.
Cyber-attacks or security breaches could adversely affect our business, operations, financial results or financial results.
Our businessmarket price or value of our securities. This list is dependent upon information systemsnot exhaustive, and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting resultswe place no priority or likelihood based on order of operations. The secure processing, maintenance and transmissionpresentation or grouping under sub-captions. For ease of information is criticalreference, the risk factors are presented under the following sub-captions: (1) Risks Related to Operational Disruption or Catastrophic Events; (2) Risks Related to our operations. A security breach of our network or systems could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we collectBusiness and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business informationIndustry; and that of our customers, suppliers, investors(3) Risks Related to Government Regulation and other stakeholders. We have a cyber-security controls framework in place which has been derived from the National Institute of Standards and Technology Cyber-security Framework and International Organization for Standardization 27001 standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a 7X24 security operations center to monitor, detect and investigate any anomalous activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed. Despite our security measures, our information systems may become the target of cyber-attacks or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems and result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. Our current insurance coverage programs do notLegal Risks.
contain specific coverage for cyber-attacks or security breaches. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could adversely affect our business, operations or financial results.RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS
Changes in our reputation with stakeholders, special interest groups, political leadership, the media or other entities could have negative impacts on our business, operations or financial results.
There could be negative impacts on our business, operations or financial results due to changes in our reputation with stakeholders, special interest groups (including non-governmental organizations), political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which we operate as well as their opposition to development projects, such as the Bakken Pipeline System. Potential impacts of a negative public opinion may include:
loss of ability to secure growth opportunities;
delays in project execution;
increased regulatory oversight or delays in regulatory approval; and
loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups. Recent judicial decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we and others in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and shipment of production from oil sands regions.
Pipeline operations involve numerous risks that may adversely affect our business and financial results.
Operation of complex pipeline systems, gathering, treating, storing and processing 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 eventsevents; which include, but are not limited to, physical risks related to climate change, such as, explosions, fires, earthquakes, hurricanes, floods, landslides, increased volatility in season temperatures, rising sea levels or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property and our assets, 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.
We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead System. which is discussedSystem; in Part II. Item 7. Management's DiscussionOctober 2018 at the BC Pipeline T-South system; and Analysis of Financial Conditionin January 2019, August 2019 and Results of Operations - LegalMay 2020 at the Texas Eastern pipeline, and Other Updates. we cannot guarantee that we will not experience catastrophic events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events. Environmental incidents
An environmental incident is an event that may cause harm or potential harm to the environment and could also lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts to us and could impact our ability to work with various stakeholders. 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.
Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results.
A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption, or curtailment of commodity supply, operational incident or other reasons could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders and our reputation. Specifically, for Gas Distribution, any prolonged interruptions would ultimately impact gas distribution customers. Service interruptions that impact our crude oil and natural gas transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements.
Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to populated areas and a major incident could result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, material repair costs or increased costs of operating and insuring our assets.
Cyber-attacks or security breaches could adversely affect our business, operations or financial results.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects in 2016 to transform various processes, capabilitiesbusiness is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems, infrastructure to continuously improve effectivenessor the network or systems of our third-party vendors, could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we and efficiency acrosssome of our vendors collect and store sensitive data in the organization. Transformation project risk isordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders.
Cybersecurity risks have increased in recent years as a result of the risk that modernization projects carried out by usproliferation of new technologies and the increased sophistication, magnitude and frequency of cyber-attacks and data security breaches. Because of the critical nature of our infrastructure and our subsidiaries do not fully deliver anticipateduse of information systems and other digital technologies to control our assets, we face a heightened risk of cyber-attacks. We have a cyber-security controls framework in place which has been derived from the National Institute of Standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a security operations center, which operates at all times to monitor, detect and investigate activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed.
During the normal course of business, we have experienced and expect to continue to experience attempts to gain unauthorized access to, or to compromise, our information systems or to disrupt our operations through cyber-attacks or security breaches, although none to our knowledge have had a material adverse effect on our business, operations or financial results. Despite our security measures, our information systems, or those of our vendors, may become the target of further cyber-attacks (including hacking, viruses or acts of terrorism) or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems, or those of our vendors, affect our ability to correctly record, process and report transactions or financial information, or result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences or other costs or be subject to increased regulation or litigation, all of which could materially adversely affect our reputation, business, operations or financial results.
Pandemics, epidemics or disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or disease outbreaks, in locations in which we operate or globally, could materially adversely affect our business, operations, financial results and forward-looking expectations. The COVID-19 pandemic has negatively impacted us in 2020 and the impacts are expected to continue for future periods, which we are unable to reasonably predict due to insufficiently addressingnumerous uncertainties, including the duration and severity of the pandemic.
The World Health Organization declared COVID-19 to be a pandemic on March 11, 2020. In response to the rapid global spread of COVID-19, governments have enacted emergency measures to combat the spread of the virus. These measures include restrictions on business activity and travel, as well as requirements to isolate or quarantine, which could continue or expand. Certain of our operations and projects have been deemed essential services in critical infrastructure sectors and are currently exempt from certain business activity restrictions; however, there is no guarantee that this exemption will continue. These actions have interrupted business activities and supply chains; disrupted travel; contributed to significant volatility in the financial and commodity markets, resulting in lower interest rates; impacted social conditions; and adversely impacted national and international economic conditions, including commodity prices and demand for energy, as well as the labor market.
Given the ongoing and dynamic nature of the circumstances surrounding the COVID-19 pandemic, it is difficult to predict how significant the impact of this pandemic, including any responses to it, will be on North American or global economies or our business, or for how long disruptions are likely to continue. The extent of such impact will depend on future developments and factors outside of our control, which are highly uncertain, rapidly evolving and cannot be predicted, including new information which may emerge concerning the severity or duration of this pandemic (including regarding new COVID-19 strains) and actions taken by governments and others to contain or end the COVID-19 pandemic or its impact (including regarding the development and distribution of effective vaccines). Such developments, which have had or may have an adverse effect on our customers, suppliers, regulators, business, operations and financial results, include disruptions that, among other things:
•adversely impacted market fundamentals, such as commodity prices and supply and demand for energy, decreasing volumes transported on our systems, increasing our exposure to asset utilization risks and adversely affecting our results;
•adversely impacted our Liquids Pipelines investments;
•could prevent one or more of our secured capital projects from proceeding, and has delayed completion and increased anticipated costs of certain projects;
•adversely impacted the operations or financial position of our third-party suppliers, service providers or customers and increase our exposure to contract-related risks or customer credit risk;
•adversely impacted the global capital markets, which could adversely impact the ratings assigned to our securities or our credit facilities and/or impact our ability to access capital markets at effective rates;
•increased our risks associated with projectemergency measures taken (including remote working, distancing and additional personal protective equipment), including increased cyber security risks, increased costs and the potential for reduced availability or productivity of our employees or third-party contractors or service providers;
•adversely impacted our ability to accurately forecast assumptions used to evaluate expansion projects, acquisitions and divestitures on an ongoing basis;
•adversely impacted the carrying value of our equity method investment in DCP Midstream and could adversely impact the outcome of future asset impairment tests, indicating that the carrying value of such assets might be impaired;
•could adversely impact the execution of current and change management. This future trade policies between Canada and the US; and
•could result in negativefuture business interruption losses that our insurance coverage may not be sufficient to cover.
There can be no assurance that our strategies to address potential disruptions will mitigate these risks or the adverse impacts to our business, operations and financial results. Future adverse impacts to our business, operations and financial results may materialize that are not yet known. In addition, disruptions related to the COVID-19 pandemic have had, or could have, the effect of heightening many of the other risks described in this Item 1A. Risk Factors. The risk that is most significantly heightened by the COVID-19 pandemic is the impact of commodity price weakness and volatility on our Liquids Pipelines, Gas Transmission and Midstream and Energy Services businesses, as detailed in the risk factor “Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our results of operations” below. Even after the COVID-19 pandemic has subsided, we may continue to experience adverse impacts to our business as a result of its global impact, including any related recession, as well as lingering impacts on supply of, demand for and prices of crude oil, natural gas, natural gas liquids, LNG and renewable energy.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the US and Canada. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could adversely affect our business, operations or financial results.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and reputational impacts.increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.
With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas, which can adversely affect our revenues and earnings.
With respect to our Gas Distribution and Storage assets, customers are billed on a combination of both fixed charge and volumetric basis and our ability to collect their respective total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our Gas Distribution customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Our Gas Distribution business has deferral accounts approved by the OEB that provide regulatory protection against the margin impacts associated with declining annual average consumption due to efficiencies and customers’ conservation efforts. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our Gas Distribution business may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. Our Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial and industrial volumes.
With respect to our Renewable Power Generation assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity method investments, could reduce our earnings.
GAAPGenerally accepted accounting principles in the United States of America (US GAAP) requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncashnon-cash charge to earnings.
ThereOur assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are utilization risks in respect to our assets.
In respect to our Liquids Pipelinegenerally long-lived assets, we are exposed to throughput risk under the CTSand pipeline construction and coating techniques have changed over time. Depending on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelinesera of construction, some assets such asrequire more frequent inspections, which could result in increased maintenance or repair expenditures in the Lakehead System. A decreasefuture. Any significant increase in volumes transported can directly andthese expenditures could adversely affect our revenuesbusiness, operations or financial results.
Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.
We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the US and earnings. Factors such as changinginternationally and from proposed pipelines that seek to access markets currently served by our liquids pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. We also face competition from alternative gathering and storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenanceareas in the transmission and increased competition canstorage of natural gas. The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Competition in all
impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outsidebusinesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.
Execution of our control can impact both the supply ofprojects subjects us to various regulatory, operational and demand for crude oil and other liquid hydrocarbons transported on our pipelines.
In respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas, which can adverselymarket risks that may affect our revenues and earnings.financial results.
In respect to our Gas Distribution assets, customers are billed on a combination of both fixed charge and volumetric basis and EGD and Union Gas'Our ability to collect their respective total revenue requirement (the cost of providing service, including a reasonable returnsuccessfully execute our projects is subject to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sourcesvarious regulatory, operational and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of EGD and Union Gas' respective customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. EGD and Union Gas have deferral accounts approved by the OEB that provide regulatory protection against the margin impacts associated with declining annual average consumption due to efficiencies and customers’ conservation efforts. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have market risks, including:
•the ability to switchobtain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and to an alternate fuel. Evenmaintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
•potential changes in those circumstances where EGDfederal, state, provincial and Union Gas each attains their respective total forecast distribution volume, theylocal statutes and regulations, including environmental requirements, that may not earn their respective expected ROE dueprevent a project from proceeding or increase the anticipated cost of the project;
•impediments on our ability to other forecast variables, such as the mix between the higher margin residentialacquire or renew rights-of-way or land rights on a timely basis and commercial sectors and the lower margin industrial sector. EGD and Union Gas each remain at risk for the actual versus forecast large volume contract commercial and industrial volumes.on acceptable terms;
In respect•opposition to our Green Power and Transmission assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operationalprojects by third parties, including interest groups;
•the availability of these energy producing assets. While skilled labor, equipment and materials to complete projects;
•the expected energy yields for Green Power and Transmissionability to construct projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at anywithin anticipated costs, including the risk of the Green Power and Transmission facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Green Power and Transmission facilities due to operational disturbances or outagescost overruns resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier non-performance, weather, geologic conditions or other factors could also impact earnings.beyond our control, that may be material;
•general economic factors that affect the demand for our projects; and
Power produced from Green Power•the ability to raise financing for these projects.
Climate related risks are integrated into our larger risk categories that encompass operational, financial and Transmission assetsstakeholder consequences. This is also often sold to a single counterparty under power purchase agreements or other long-term pricing arrangements. In this respect, the performancedone because of the Green Powerinterconnected economic, social and Transmission assets is dependent on each counterparty performingenvironmental nature of climate impacts requires a comprehensive review within the context of other risks that impact us.
Any of these risks could prevent a project from proceeding, delay its contractual obligations undercompletion or increase its anticipated cost. Recent projects that have experienced delays include the power purchase agreements or pricing arrangement applicable to it.
We rely on access to short-termUS L3R Program, the Spruce Ridge Project and long-term capital markets to finance capital requirementsthe T-South Reliability and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often doesExpansion Program. New projects may not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity
for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility,achieve their expected investment return, which could affect cash flows or restrict business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affectfinancial results, and hinder our ability to draw undersecure future projects. For additional discussion of specific proceedings that could affect our credit facilities, borrowingoperations and financial results, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.
Changing expectations from stakeholders regarding ESG practices and climate change or erosion of stakeholder trust or confidence could influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, safety and stakeholder relations remain primary focus areas; changing expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous communities and other groups directly impacted by our activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors, investment funds and others which are increasingly focused on ESG practices. We have long been committed to strong ESG practices and performance, and in 2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include targets for GHG emissions reduction; adapting to the energy transition over time is one of our strategic priorities. Inadequately managing expectations and issues important to stakeholders, including those related to environment and climate change, could be significantly higher.impact stakeholder trust and confidence and our reputation and have negative impacts on our business, operations or financial results, including:
If we are not able to access capital at competitive rates, our•loss of business;
•loss of ability to finance operationssecure growth opportunities;
•delays in project execution;
•legal action, such as the legal challenges to the operation of Line 5 in Michigan and implement our strategy may be affected. RestrictionsWisconsin;
•increased regulatory oversight;
•loss of ability to obtain and maintain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms;
•impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•changing investor sentiment regarding investment in the oil and gas industry or our company;
•restricted access financial markets may also affect ourto and cost of capital; and
•loss of ability to execute our business plan as scheduled. An inabilityhire and retain top talent.
We are also exposed to access capital may limit ourthe risk of higher costs, delays, project cancellations, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators. Recent judicial decisions have increased the ability of groups to pursue improvements or acquisitions thatmake claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidityand others in the formenergy and pipeline businesses are facing organized opposition to oil and gas extraction and shipment of capital contributions or loans to such subsidiaries, thus reducing the liquidityoil and borrowing availability of the consolidated group.gas products.
Our forecasted assumptions may not materialize as expected on our expansion projects, acquisitions and divestitures.
We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss of our profits.
Our insurance coverage may not be sufficient to cover our losses in the event of an accident, natural disaster or other hazardous event.
Our operations are subject to many hazards inherent in our profits.industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards also can cause, and in some cases have caused, personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and certain of our affiliates to mitigate the financial impacts arising from these hazards. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry; however, insurance does not cover all events in all circumstances.
WeIn the unlikely event that multiple insurable incidents that in the aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries. Additionally, even with insurance, if any natural disaster or other hazardous event leads to a catastrophic interruption in operations, we may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of capital from such asset sales. In addition, the timing to enter into and close any asset sales could be significantly different than our expected timeline.restore operations without significant interruption.
We are planning to monetize certain assets to execute on our strategic priority to focus on core assets and to accelerate debt reduction and provide capital for capital and investment expenditures. Given the commodity markets, financial markets, and other challenges currently facing the energy sector, our competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on our business, financial condition, results of operations, and cash flows.
Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Many of our operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and further substantial changes may occur.
On February 8, 2018, the Government of Canada introduced legislation to revise the process for assessing major resource projects. At this time, we are reviewing the proposed regulatory reforms and the effect upon us and our subsidiaries, whether adverse or favorable, if such legislation is passed in its current or revised form, is currently uncertain.
Compliance with legislative changes may impose additional costs on new pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.
Failure to comply with environmental laws and regulations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future will have a significant effect on our earnings and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. A significant amount of our credit exposures for transmission storage, and gathering and processingstorage services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. It is possible that customer payment defaults, if significant, could adversely affect our earnings and cash flows.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.
We use derivative financial instruments to manage the risks associated with movements in foreign exchange rates, interest rates, commodity prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.
Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects starting in 2016 to transform various processes, capabilities and reporting systems infrastructure to continuously improve effectiveness and efficiency across the organization and are involved in numerous legal proceedings, the outcomessubject to transformation project risk with respect to these projects. Such projects, some of which will continue into 2021 and 2022, including integration initiatives arising out of the merger with Spectra Energy and the amalgamation of EGD and Union Gas, are uncertain,subject to transformation project risk. Transformation project risk is the risk that modernization projects carried out by us and resolutionsour subsidiaries do not fully deliver anticipated results due to insufficiently addressing the risks associated with project execution and change management. This could result in negative financial, operational and reputational impacts.
Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our operational results.
The COVID-19 pandemic and concerns about global economic growth have caused considerable uncertainty in the market for crude oil, natural gas and other commodities, lowering demand forecasts. This, and the changing relationship dynamic among OPEC+ members, has put severe downward pressure on prices early in 2020. The economic climate in Canada, the US and abroad has deteriorated and worldwide demand for petroleum products has diminished. 2020 saw a dramatic decline in the price of crude oil, natural gas and NGL and other commodities whose prices are highly correlated to us couldcrude oil. The West Texas Intermediate benchmark prices for crude oil had been trading around US$60 per barrel in December 2019 and fell to as low as US$14 per barrel in March 2020 and into a negative value on April 20, 2020. Crude oil prices started to recover in the second and third quarters of 2020, with West Texas Intermediate benchmark prices reaching over US$40 primarily due to the announcement of crude oil productions cuts in April 2020 and June 2020. The West Texas Intermediate benchmark finished the year at US$48.35 per barrel.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the Competitive Tolling Settlement on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. The current commodity price environment has impacted both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines. This has led to a year-over-year reduction in Mainline System utilization of 80 kbpd in 2020.
While reduced demand has impacted throughput and revenue on the Mainline System, the financial results.
Weimpact of reduced throughput on our upstream regional pipelines and our downstream market extension pipelines is largely mitigated by the presence of take-or-pay contracts. The financial impact is also mitigated through cost-of-service arrangements with credit-worthy counterparties or parties that are subjectnot investment grade but have instead provided credit support in the form of letters of credit or other instruments. The existing market conditions are likely to numerous legal proceedings. Litigation is subject tostress the creditworthiness of many uncertainties,of these counterparties and we cannot predictcontinue to evaluate the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in whichsituation on an ongoing basis. To date, we are involved could require additional expenditures, in excess of established reserves, over an extended period ofhave not had any counterparty default on its obligations to maintain credit support or pay its tolls under these contracts and, at this time, and inwe do not foresee a range of amounts that could adversely affectmaterial impact to our financial results.
Terrorist attacksShippers also reduced investment in exploration and threats, escalationdevelopment programs in 2020. The decline in oil prices is also causing some sponsors of military activityoil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin.
With respect to our Gas Transmission and Midstream assets, the low commodity prices have had limited impact on demand for natural gas shipped within our long-haul Gas Transmission assets in response to these attacks or actsthe US and Canada. These assets are comprised of war,primarily cost-of-service and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions,take-or-pay contract arrangements which are not directly impacted by fluctuations in consumer confidencecommodity prices.
Within our US Midstream assets, through our investment in DCP Midstream and, spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involvingto a lesser extent, the United States, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targetsAux Sable liquids product plant, we are engaged in the United Statesbusinesses of gathering, treating and Canada. In addition, increased environmental activism against pipeline constructionprocessing natural gas and operation could potentially resultnatural gas liquids. Given the drastic decline in work delays, reduced demand forcommodity prices, DCP Midstream made the decision to decrease its distribution to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby reducing our productscash flows. Aux Sable results were also negatively impacted by these lower commodity prices.
With respect to our Energy Services business, we generate margins by capitalizing on quality, time and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increaselocation differentials when opportunities arise. The recent volatility in energycommodity prices could result in government-imposedlimit margin opportunities and impede our ability to cover capacity commitments.
At this point, given the many outstanding questions as to the length and depth of the current low commodity price controls. Itenvironment, the impact on us is uncertain; however, it is possible that any of these occurrences, or a combination of them, could adversely affectit may have an adverse impact on our business operations or financial results.and our results of operations.
Our Liquids Pipelines growth rate and results may be adverselydirectly and indirectly affected by commodity prices.prices and Government policy.
Current oil sands production is very robustThe efforts implemented in 2019 by the Alberta Government to manage supply and is expectedinventories in Western Canada continued at diminishing levels in 2020 as incremental take away capacity was introduced to grow in the futuremarket. This intervention had a negligible impact on the Mainline System throughput, as producers actively improve the competitiveness of their existing projects; however, prolonged low prices negatively impact producers' balance sheetsenough inventory existed to meet refinery customer needs and their ability to invest. Sanctioned projects due to come on stream in the next 24 months are not as sensitive to short-term declines in crude oil prices, as investment commitments have already been made. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.service our favorable markets. Wide commodity price basis between Western Canada and global tidewater markets have also negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.
The tight conventional oil plays of Western Canada and the Bakken region of North Dakota have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be well managed through active hedging programs and are positioned to react quickly at market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our pipeline systems.
Our Gas Transmission and Midstream results may be adversely affected by commodity price volatility and risks associated with our hedging activities.
Our exposure to commodity price volatility is inherent to part of our natural gas processing activities.US Midstream business. We employ a disciplined hedging program to manage this direct commodity price risk. Because we are not fully hedged, we may be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of these commodities could adversely affect our financial results.
Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we likely will be prevented from realizing the full benefits of price increases above the level of the hedges. 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.
Our Energy Services results may be adversely affected by commodity price volatility.
Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility inLower commodity prices due to changing marketingmarket conditions could limit margin opportunities and impede Energy Services' ability to cover capacity commitments.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict business. Furthermore, commodity pricesif our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. An inability to access capital may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS
Many of our operations are regulated and failure to secure regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative earnings and cash flow impacts if the cost of the commodity is greater than resale prices achieved by us.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affectimpact on our business, operations or financial results.
The nature and degree of regulation and legislation affecting energy companies in Canada and the US have changed significantly in recent years.
In Canada, the passing of the Canadian Energy Regulator Act and the Impact Assessment Act under Bill C-69, which came into force on August 28, 2019, is expected to extend timelines associated with regulatory approvals for new projects which trigger a federal impact assessment. Changes to the British Columbia regulatory framework have also been made, including a new Environmental Assessment Act, which came into force in December 2019, affecting provincially-regulated projects in a similar manner as those that are federally-regulated. Within the US and in Canada, pipelines companies continue to face opposition from anti-pipeline activists, Indigenous and tribal communities, citizens, environmental groups and politicians concerned with either the safety of pipelines or environmental effects. In the US, several federal agencies made changes to regulations that were designed to streamline permitting, including changes that the Environmental Protection Agency made in June 2020 to regulations implementing Section 401 of the Clean Water Act and the July 2020 Council on Environmental Quality revisions to regulations implementing the National Environmental Policy Act. These and many other regulations adopted during the previous US presidential administration are not only being challenged in multiple courts, but have now been expressly targeted for rollback by the new US administration, which is expected to modify or reverse the regulations.
These actions could adversely impact permitting of a wide range of energy projects. We may not be able to obtain or maintain all required regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or if laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs.
Our operations are subject to numerous environmental laws and regulations, including those relating to climate change and GHG emissions, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We use derivative financial instrumentsare subject to managenumerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.
Failure to comply with environmental laws and regulations and failure to secure permits necessary for our operations may result in the risksimposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations, including those related to climate change and GHG emissions, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities. Efforts to regulate or restrict GHG emissions could also drive down demand for the products we transport.
We may not be able to obtain or maintain all required environmental regulatory approvals and permits for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.
In November 2020, we set new ESG goals for the future, including with respect to GHG emissions reduction. Our ability to achieve these goals depends on many factors, including our ability to reduce emissions from our operations through modernization and innovation, reduce the emissions intensity of the electricity we buy, invest in renewables and low carbon energy and balance residual emissions through carbon offset credits. The cost associated with movementsour GHG emissions reduction goals could be significant. Failure to achieve our emissions targets could result in foreign exchange rates, interest rates, commodity pricesreputational harm, changing investor sentiment regarding investment in Enbridge or a negative impact on access to and our share pricecost of capital.
Our operations are subject to reduce volatilityoperational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to our cash flows. Basedcomply with applicable regulations and other requirements could have a negative impact on our risk management policies, allreputation, business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements or other agreements that provide a legal basis for our operations, breaches of our derivative financial instruments are associated withwhich could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an underlying asset, liability and/or forecasted transaction.overall increase in operating and compliance costs. We do not enter into transactionsown all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights could have an adverse effect on our reputation, operations and financial results. Scrutiny over the integrity of our assets and operations has the potential to increase operating costs or limit future projects. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the objective of speculating on commodity pricesrespective regulators directly, or interest rates. These policies cannot, however, eliminate all risk of unauthorized tradingthrough industry associations, and other speculative activity. Although this activity is monitored independently by our risk management function,developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we remain exposed tobelieve the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detectsafe and prevent all unauthorized trading and other violationsreliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, management policies and procedures, particularly if deception, collusionthe potential remains for regulators or other intentional misconduct is involved,government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.
Our operations are subject to economic regulation and any such violationsfailure to secure regulatory approval for our proposed or existing commercial arrangements could adversely affecthave a negative impact on our business, operations or financial results.
Our liquids pipelines face economic regulatory risk, the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements. We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of our liquids pipelines assets. However, there remains a risk that a regulator could modify significantly its own long-standing policies for rate making as well as overturn long-term agreements that we have entered into with shippers.
The effects
We could be subject to changes in our tax rates, the adoption of United States Government policies on trade relations betweennew US, Canadian or international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the United States are uncertain.
The United States Government has continued interestmix of earnings in renegotiatingcountries with differing statutory tax rates, changes in the valuation of deferred tax assets and alteringliabilities, or changes in tax laws or their interpretation, including in particular the North American Free Trade Agreement (NAFTA)US with a new presidential administration and in Canada and Mexico. NAFTA provides protection against tariffs, dutiesother foreign jurisdictions in which we operate.
We are also subject to the examination of our tax returns and other charges or fees and assures accesstax matters by the signatories. The NAFTA negotiations have introduced a levelUS Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of uncertaintyan adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the energy markets. TheUS or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the NAFTA negotiations could result in new rules or its collapse which may be disruptive to energy markets, and could jeopardize our ability to remain competitive and have a significant impact on us.
The effectfinal resolution of comprehensive United States tax reform legislation on us, whether adverse or favorable, is uncertain.
On December 22, 2017, President Trump signed into law H.R. 1, “An Act to provide for reconciliation pursuant to titles II and Vsome of the concurrent resolution on the budgetmatters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for fiscal year 2018” (informally titled the Tax Cuts and Jobs Act). The effecta discussion of the Tax Cuts and Jobs Act on us, our subsidiaries and our shareholders, whether adverse or favorable, is uncertain, but will become more clear as additional guidance is issued.legal proceedings.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are included in Item 1. Business.
In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private land owners,land-owners, First Nations, Native American Tribes, 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/or used by us under easements, licenses, leases 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, with the remainder used by us under easements, leases or permits.
Titles to our properties acquired in our liquids and 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. LEGAL PROCEEDINGS
We are involved in various legal and administrative proceedings and litigation arising in the ordinary course of business. The outcome of these matters is not predictable at this time. However, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial condition, results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updatesfor discussion of other legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at January 31, 2018,February 5, 2021, there were approximately 96,1072,025,495,603 holders of record of our common stock. A substantially greater number of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks, brokers and other financial institutions.
Common Stock Data by Quarter
The following table indicates the intra-day high and low prices of our common stock on the TSX (in Canadian dollars):
|
| | | | | | | | | |
| | Stock Price Range |
2017 | Q1 |
| Q2 |
| Q3 |
| Q4 |
|
High | $ | 58.28 |
| 57.75 |
| 53.00 |
| 52.59 |
|
Low | | 53.87 |
| 49.61 |
| 48.98 |
| 43.91 |
|
| | | | | |
2016 | | | | | |
High | $ | 51.31 |
| 55.05 |
| 59.19 |
| 59.18 |
|
Low | | 40.03 |
| 48.73 |
| 50.76 |
| 53.91 |
|
The following table indicates the intra-day high and low prices of our common stock on the NYSE (in U.S. dollars):
|
| | | | | | | | | |
| | Stock Price Range |
2017 | Q1 |
| Q2 |
| Q3 |
| Q4 |
|
High | US$ | 44.52 |
| 42.92 |
| 42.31 |
| 42.10 |
|
Low | | 40.25 |
| 37.37 |
| 39.01 |
| 34.39 |
|
| | | | | |
2016 | | | | | |
High | US$ | 39.40 |
| 43.39 |
| 45.77 |
| 45.09 |
|
Low | | 27.43 |
| 37.02 |
| 38.58 |
| 39.70 |
|
Dividends
The following table indicates the dividends paid per common share (in Canadian dollars):
|
| | | | |
| 2017 |
| 2016 |
|
Q1 | 0.583 |
| 0.530 |
|
Q2 | 0.610 |
| 0.530 |
|
Q3 | 0.610 |
| 0.530 |
|
Q4 | 0.610 |
| 0.530 |
|
Consistent with our objective of delivering annual cash dividend increases, we announced a quarterly dividend of $0.671 per common share payable on March 1, 2018, which represents a 10 percent increase from the prior quarterly rate. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors.
Securities Authorized for Issuance Under Equity Compensation Plans
InformationThe information required by this Item will be contained in response to this item is incorporated by reference from our Proxy Statement toForm 10-K/A, which will be filed with the SEC relating to our 2018 annual meeting of shareholders.no later than 120 days after December 31, 2020.
Recent Sales of Unregistered Equity Securities
On November 29, 2017, we entered into a private placement for common shares with three institutional investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003 common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-term indebtedness pending reinvestment in capital projects.None.
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer to Item 7 - Outstanding Share Data for further discussion of the transaction.
Issuer Purchases of Equity Securities
None.
Stock Performance GraphTotal Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 20132016 through December 31, 20172020 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the S&P/TSX Composite index, and (3) the S&P 500 index, (4) our US peer group index(comprising CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer group (comprising CU, FTS, IPL, PPL TRP, D, DTE, ETE, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB)TRP). The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
|
| | | | | | | | | | | | |
| January 1, 2013 | December 31, |
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| 2017 |
|
Enbridge Inc. | 100.00 |
| 110.93 |
| 146.76 |
| 116.80 |
| 149.53 |
| 136.37 |
|
S&P/ TSX Composite | 100.00 |
| 112.99 |
| 124.92 |
| 114.53 |
| 138.67 |
| 151.28 |
|
Peer Group1 | 100.00 |
| 126.35 |
| 158.17 |
| 121.45 |
| 158.82 |
| 163.06 |
|
| | | | | | | | | | | | | | | | | | | | |
| January 1, 2016 | December 31, |
| 2016 | 2017 | 2018 | 2019 | 2020 |
Enbridge Inc. | 100.00 | | 127.97 | | 116.65 | | 107.20 | | 138.65 | | 117.59 | |
S&P/TSX Composite | 100.00 | | 121.08 | | 132.09 | | 120.36 | | 147.89 | | 156.17 | |
S&P 500 Index | 100.00 | | 111.96 | | 136.40 | | 130.42 | | 171.49 | | 203.04 | |
US Peers1 | 100.00 | | 133.50 | | 136.67 | | 131.82 | | 162.50 | | 137.15 | |
Canadian Peers | 100.00 | | 132.07 | | 140.85 | | 126.30 | | 164.43 | | 127.61 | |
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is not necessarily indicative of results of future operations and should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.to fully understand factors that may affect the comparability of the information presented below.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars, except per share amounts) | | | | | |
Consolidated Statements of Earnings | | | | | |
Operating revenues | $ | 39,087 | | $ | 50,069 | | $ | 46,378 | | $ | 44,378 | | $ | 34,560 | |
Operating income | 7,957 | | 8,260 | | 4,816 | | 1,571 | | 2,581 | |
Earnings | 3,416 | | 5,827 | | 3,333 | | 3,266 | | 2,309 | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | | (407) | | (240) | |
Earnings attributable to controlling interests | 3,363 | | 5,705 | | 2,882 | | 2,859 | | 2,069 | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | | 2,529 | | 1,776 | |
Common Share Data | | | | | |
Earnings per common share | | | | | |
Basic | 1.48 | | 2.64 | | 1.46 | | 1.66 | | 1.95 | |
Diluted | 1.48 | | 2.63 | | 1.46 | | 1.65 | | 1.93 | |
Dividends paid per common share | 3.24 | | 2.95 | | 2.68 | | 2.41 | | 2.12 | |
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars) | | | | | |
Consolidated Statements of Financial Position | | | | | |
Total assets | $ | 160,276 | | $ | 163,157 | | $ | 166,905 | | $ | 162,093 | | $ | 85,209 | |
Long-term debt | 62,819 | | 59,661 | | 60,327 | | 60,865 | | 36,494 | |
|
| | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 20171 |
| 20161 |
| 20151 |
| 2014 |
| 2013 |
|
(millions of Canadian dollars, except per share amounts) | |
|
|
| |
Consolidated Statements of Earnings | | | | | |
Operating revenues |
| $44,378 |
| $ | 34,560 |
| $ | 33,794 |
| $ | 37,641 |
| $ | 32,918 |
|
Operating income | 1,571 |
| 2,581 |
| 1,862 |
| 3,200 |
| 1,365 |
|
Earnings/(loss) from continuing operations | 3,266 |
| 2,309 |
| (159 | ) | 1,562 |
| 490 |
|
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests
| (407 | ) | (240 | ) | 410 |
| (203 | ) | 135 |
|
Earnings attributable to controlling interests | 2,859 |
| 2,069 |
| 251 |
| 1,405 |
| 629 |
|
Earnings/(loss) attributable to common shareholders | 2,529 |
| 1,776 |
| (37 | ) | 1,154 |
| 446 |
|
Common Stock Data | | | | | |
Earnings/(loss) per common share | | | | | |
Basic | 1.66 |
| 1.95 |
| (0.04 | ) | 1.39 |
| 0.55 |
|
Diluted | 1.65 |
| 1.93 |
| (0.04 | ) | 1.37 |
| 0.55 |
|
Dividends paid per common share | 2.41 |
| 2.12 |
| 1.86 |
| 1.40 |
| 1.26 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
| 20171 |
| 20161 |
| 20151 |
| 2014 |
| 2013 |
|
(millions of Canadian dollars) | |
|
|
| |
Consolidated Statements of Financial Position | | | | | |
Total assets2 | $ | 162,093 |
| $ | 85,209 |
| $ | 84,154 |
| $ | 72,280 |
| $ | 57,196 |
|
Long-term debt including capital leases, less current portion | 60,865 |
| 36,494 |
| 39,391 |
| 33,423 |
| 22,357 |
|
| |
1 | Our Consolidated Statements of Earnings and Consolidated Statements of Financial Position data reflect the following acquisitions, dispositions and impairment: |
2017 - Spectra Merger Transaction, acquisition of public interest in Midcoast Energy Partners, L.P. and other impairment
2016 - Sandpiper Project impairment, gain on disposition of South Prairie Region assets, Tupper Plants acquisition and other
2015 - Goodwill impairment
| |
2 | We combined Cash and cash equivalents and other amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to pooling arrangements. |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONSCONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
We are a Canadian companyThis section of our Annual Report on Form 10-K discusses 2020 and a North American leader in delivering energy. As a transporter2019 items and year-over-year comparisons between 2020 and 2019. For discussion of energy, we operate, in Canada2018 items and the United States, the world’s longest crude oilyear-over-year comparisons between 2019 and liquids transportation system. Following the combination2018, refer to Part II. Item 7. Management's Discussion and Analysis of EnbridgeFinancial Condition and Spectra Energy Corp. (Spectra Energy) through a stock-for-stock merger transaction on February 27, 2017 (the Merger Transaction), we are also a leader in the natural gas transmission and midstream business moving approximately 20%Results of all natural gas in the United States, serving key supply basins and markets. As a distributorOperations of energy, we own and operate Canada’s largest natural gas distribution company and provide distribution services in Ontario, Quebec and New Brunswick. As a generator of energy, we have interests in approximately 3,500 megawatts (MW) (2,500 MW net) of renewable and alternative energy generating capacity which is operating, secured or under construction, and we continue to expand our interests in wind, solar and geothermal power.
DOMESTIC ISSUER REPORTING REQUIREMENTS
Effective January 1, 2018, we began to comply with the Securities and Exchange Commission reporting requirements applicable to United States domestic issuers and, accordingly, we are filing our annual reportAnnual Report on Form 10-K for the year ended December 31, 2019.
RECENT DEVELOPMENTS
COVID-19 PANDEMIC, REDUCED CRUDE OIL DEMAND AND COMMODITY PRICES
The COVID-19 pandemic and the emergency response measures enacted by governments in Canada, the US and around the world, have caused material disruption to many businesses resulting in a severe slow down in Canadian, US and global economies, leading to increased volatility in financial and commodity markets worldwide and demand reduction for certain commodities.
We took proactive measures to deliver energy safely and reliably during the COVID-19 pandemic. We activated our crisis management team to focus on a number of priorities, including: (i) the health and safety of our employees and the public; (ii) operational reliability for our customers and markets; (iii) identification of essential personnel and procedures; and (iv) extensive stakeholder communication and outreach including updates to our Board of Directors. We are following recommendations from public health authorities and medical experts and have taken steps to help prevent our employees’ exposure to the spread of COVID-19, including, where practical, work-at-home plans enacted in March 2020 and the implementation of business continuity plans to enable the integrity of our operations and protect the health of our employees in pipeline control functions and service centers, our field representatives and other essential functions.
With respect to the safe operation of our facilities, we continue to employ all safety processes and procedures in the normal course. Our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need to heat their homes and fuel their lives.
The COVID-19 pandemic has had a deep impact in the communities in which we operate. We are providing support in our communities by advancing funds to respond and provide relief to those who are most vulnerable. Our teams in our operating regions are working closely with our nonprofit community partners, our closest Indigenous and Tribal neighbors and local governments to identify where resources are needed most.
The COVID-19 pandemic has negatively impacted crude oil demand and increased commodity price volatility, which together present potential new or elevated risks to our business. In late March, we began to see impacts both on the supply of, and demand for, crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our crude oil pipelines responded to significantly lower demand caused by the COVID-19 pandemic, declining storage availability and refinery utilization, and commodity price declines by reducing volumes beginning in the second quarter of 2020. In the third and fourth quarters of 2020, Mainline System volumes began to recover as fourth quarter volumes increased by approximately 200 thousand barrels per day (kbpd) when compared with significantly reduced volumes in the second quarter of 2020. Year-over-year, Mainline System throughput only decreased by approximately 80 kbpd. We anticipate a return to full utilization in 2021 as economic activity gradually resumes in North America. This view is supported by our expectation that the refineries operating in our core Mainline System markets (i.e. the US Midwest, Eastern Canada and the US Gulf Coast) will continue to experience higher utilization rates given their scale, complexity and cost competitiveness. For every 100 kbpd increase or decrease in volumes on our Mainline System, our revenues, net of power savings, are expected to increase or decline by approximately $35 million per quarter.
In our US Midstream business, our equity affiliate DCP Midstream, LP, responded to the drastic decline in commodity prices by decreasing their distributions to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby modestly reducing our cash flows. As a further outcome of the drastic commodity price decline, we recorded a $1.7 billion impairment on our equity method investment in DCP Midstream in the first quarter of 2020, based on the decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020.
In addition, these circumstances have led to the deterioration of the credit profiles of some of our customers and suppliers. There have been no material defaults by customers or suppliers to date, however, we will continue to monitor this risk and take credit risk mitigating actions as appropriate.
The situation around the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices is evolving and our assessment of risks is included in Part I. Item 1A. Risk Factors.
While the length and depth of the current energy demand reduction and its impact is challenging to estimate at this time, we have completed several actions to further strengthen our resiliency and position for the future, while assuring that the safety and reliability of our operations remains our first priority. We took actions to reduce operating costs by approximately $300 million in 2020, including reductions to employee, management and Board of Director compensation, a voluntary workforce reduction program, as well as supply chain savings. We have also executed approximately $400 million of asset sales and increased our available liquidity to approximately $13 billion. We experienced a natural slowing of 2020 capital spending in light of COVID-19 and the health and safety measures put into place by federal and regional governments. In addition, we believe that the following factors further demonstrate the resiliency of our low-risk business model:
•Our assets are highly contracted and commercially underpinned by long-term take-or-pay and cost-of-service agreements;
•Approximately 95% of our customer exposure is investment grade, investment grade equivalent or non-investment grade who have provided credit enhancements;
•The acquisition of Spectra Energy in 2017 provided us with greater diversification into natural gas with embedded low risk commercial structures. We currently have approximately 40 different sources of cash flows by geography and regular periodic reports under both Canadianby different customer groups;
•A strong financial position with approximately $13 billion of net available liquidity which gives us the capacity to fund all of our capital projects and any debt maturities through 2021 without accessing the capital markets; and
•We limit the maximum cash flow loss that could arise from direct market price risks through a comprehensive long-term economic hedging program.
We will continue to actively monitor our business environment and may take further actions that we determine are in the best interests of Enbridge, our employees, customers, partners and stakeholders, or as required by federal, state or provincial authorities. At this time, given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current sustained low commodity price environment, the long term impact on us is uncertain; however, it is possible that they continue to have an adverse impact on our business and results of operations.
UNITED STATES LINE 3 REPLACEMENT PROGRAM UNDER CONSTRUCTION
The United States law thereafter.Line 3 Replacement Program (US L3R Program) is now under construction in Minnesota after receiving all necessary permits and approvals. The US L3R Program is a critical integrity project that will enhance the continued safe and reliable operations of our Mainline System well into the future, reflecting our long-standing commitment to protecting the environment.
For further details refer to Growth Projects - Liquids Pipelines - United States Line 3 Replacement Program. MERGER WITH SPECTRA ENERGY
MAINLINE SYSTEM CONTRACTING
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and tolls of each service, which would be offered in an open season following approval by the CER.
On February 27, 2017, we24, 2020, the CER issued a Notice of Public Hearing which outlined the process for participation in the hearing and identified a list of issues for discussion in the proceeding. In March 2020, letters were filed with the CER by a group of potential intervenors that requested the CER delay setting hearing dates associated with our Mainline System contract filing. Subsequently, the CER issued a letter requesting comments on the potential delay of proceedings.
We filed our response with the CER on May 1, 2020, and on May 19, 2020, the CER announced that the closingregulatory process for our proposal to offer contracted transportation service on our Mainline System will proceed in a single phase hearing process that balances the need to address COVID-19 pandemic related challenges and the CER's mandate to adjudicate in an appropriately expeditious manner.
We are currently in the midst of the Merger Transaction.regulatory process and expect an oral hearing to occur sometime after April 2021, but a hearing date has not yet been set. If a replacement agreement is not in place by June 30, 2021, the Competitive Tolling Settlement provides for tolls to continue on an interim basis.
Under
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Texas Eastern
On February 25, 2020, Texas Eastern Transmission, L.P. (Texas Eastern) received approval from the termsFederal Energy Regulatory Commission (FERC) of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020.
Algonquin
On July 2, 2020, Algonquin Gas Transmission, LLC (Algonquin) received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020.
BC Pipeline
In July 2020, the 2020-2021 rate settlement agreement with Westcoast Energy Inc.’s (Westcoast) British Columbia (BC) Pipeline shippers was approved by the CER. Following approval of the Merger Transaction, Spectra Energy shareholderssettlement, Westcoast applied and received 0.984 shares of Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra Energy shareholders owned approximately 43%.
Spectra Energy, which we now wholly-own, is one of North America’s leading natural gas delivery companies owning and operating a large, diversified and complementary portfolio of gas transmission, midstream gathering and processing and distribution assets. Spectra Energy also owns and operates a crude oil pipelinesystem that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions.Our combination with Spectra Energy has created the largest energy infrastructure company in North America with an extensive portfolio of energy assets that are well positioned to serve key supply basins and end use markets and multiple business platforms through which to drive future growth.
A more detailed description of each of the businesses and underlying assets acquired through the Merger Transaction is provided under Part I. Item 1. Business.The results of operations from assets acquired through the Merger Transaction are included in our financial statements and in this management's discussion and analysis (MD&A) on a prospective basisapproval from the closing date ofCER on August 12, 2020 for the Merger Transaction.
Subsequent to the completion of the Merger Transaction, our activities continueinterim tolls to be carried out through five business segments: Liquids Pipelines; Gas Transmission and Midstream (previously known as Gas Pipelines and Processing); Gas Distribution; Green Power and Transmission; and Energy Services. Effective February 27, 2017, as a result ofmade final, including the Merger Transaction:
Liquids Pipelines also includes resultsinterim tolls from the operation of the Express-Platte System;
Gas Transmission and Midstream also includes Spectra Energy’s United States Storage and Transmission Assets, Canadian Pipeline & Field Services, Canadian Gas Transmission and Midstream and Maritimes & Northeast U.S. and Canada businesses,January 1, 2020 to March 31, 2020 as well as the resultsrevised interim tolls in effect as at April 1, 2020.
East Tennessee
East Tennessee Natural Gas, LLC filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020.
Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we will await FERC approval.
Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2020 Rate Application
Enbridge Gas's rate applications are filed in two phases. As part of an Ontario Energy Board (OEB) Decision and Order issued in December 2019, Phase 1 of the Company’s 50% interest in DCP Midstream, LLC (DCP Midstream); and
Gas Distribution also includes results fromapplication for 2020 rates, exclusive of funding for 2020 discrete incremental capital investments requested through the operation of Union Gas Limited (Union Gas).
UNITED STATES TAX REFORM
On December 22, 2017, the United States enacted the “Tax Cuts and Jobs Act” (TCJA). Substantially allincremental capital module (ICM) mechanism, was approved effective January 1, 2020. Through a subsequent OEB Rate Order issued on June 11, 2020, Phase 2 of the provisionsapplication for 2020 rates, inclusive of requested 2020 ICM amounts, was approved effective October 1, 2020, and interim rates in effect from January 1, 2020 through September 30, 2020 were made final. The 2020 rate application, which represented the second year of a five-year term, was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism.
2021 Rate Application
On June 30, 2020, Enbridge Gas filed Phase 1 of an application with the OEB for the setting of rates for 2021. The 2021 rate application was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap IR rate setting mechanism and represents the third year of a five-year term. On October 6, 2020, Enbridge Gas filed a Phase 1 Settlement Proposal and draft Interim Rate Orders with the OEB, which were approved, on an interim basis effective January 1, 2021, on November 6, 2020. Phase 2 of the application addressing 2021 ICM funding requirements was filed on October 15, 2020.
FINANCING UPDATE
On February 20, 2020, we raised US$750 million of two-year floating rate notes in the TCJA are effective for taxation years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue CodeUS debt capital markets and on April 1, 2020, Enbridge Gas completed a $1.2 billion dual tranche offering of 1986 (as amended, the Code), including amendments which significantly change the taxation of individuals10-year and business entities, and includes specific provisions related to regulated public utilities which includes our various regulated gas pipeline businesses.The most significant changes that impact us, included30-year notes in the TCJA, are reductionsCanadian debt capital markets. On May 12, 2020, we raised $1.3 billion with a dual tranche offering of 5-year and 7-year notes in the corporate federal income tax rate from 35% to 21%, and several technical provisions including, among others, a onetime deemed repatriation or “toll” tax on undistributed earnings and profitsCanadian debt capital markets. On July 8, 2020, we raised an additional US$1.0 billion of US controlled foreign affiliates, including Canadian subsidiaries. The specific provisions related to regulated public utilities60-year hybrid subordinated notes in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, and the continuance of certain rate normalization requirements for accelerated depreciation benefits. For other operations, immediate full expensing ofUS debt capital expenditures placed into service after September 27, 2017 and before January 1, 2023 (before January 1, 2024 for qualified long production period property) will be available under the TCJA. Inversely to the regulated public utility operations, interest deductions will be more restrictive for other operations as existing interest expense limitations are broadened to apply to all interest paid and the allowable deduction is reduced from 50% to 30% of adjusted taxable income.
Changes in the Code from the TCJA had a material impact on our consolidated financial statements as at and for the year ended December 31, 2017. Under generally accepted accounting principles in the United States of America (U.S. GAAP), the tax effects of changes in tax laws must be recognized in the period in which the law is enacted, or December 22, 2017 for the TCJA. Thus, at the date of enactment, our deferred tax liability was re-measured based upon the new tax rate. For some of our gas pipeline entities with regulated cost of service rate mechanisms, the change in the deferred tax liability is offset by a regulatory liability. In the event of a future rate case, and subject to further regulatory guidance, we anticipate that the regulatory liability may be required to be amortized over the remaining useful life of the affected assets and would be one of many factors to be considered in establishing go forward rates. For all other operations, the change in the deferred tax liability is recorded as an adjustment to our deferred tax provision.
While certain elements of the TCJA require clarification through more detailed regulation or interpretive guidance, based on the information and guidance available and our analysis (including computations of income tax effects) completed to date, at this time, we do not expect that the TCJA will have a material economic impact on us going forward.
For additional information, refer to Item 8. Financial Statements and Supplementary Data - Note 24. Income Taxes.
UNITED STATES SPONSORED VEHICLE STRATEGY
In 2017, we continued the ongoing evaluation of our investment in our United States sponsored vehicles, and alternatives to such investment, and we completed or announced certain strategic reviews and transactions. We intend to review our United States sponsored vehicle strategy on a continuing basis. From time to time, we may formulate plans or proposals with respect to such matters and hold discussions with or make formal proposals to the board of directors of the sponsored vehicles or other third parties. These plans or proposals may, subject to price,markets. Through these capital market and general economic and fiscal conditions and other factors, include potential consolidations, acquisition or sale of assets or securities, changes to capital structure or other transactions.
On April 28, 2017, we announced the completion of a strategic review of Enbridge Energy Partners, L.P. (EEP). The following actions, together with the measures announced in January 2017 and disclosed in our 2016 annual MD&A, have been taken to date to enhance EEP’s value proposition to its unitholders and to us:
Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.
On April 27, 2017,activities, we completed our previously-announced merger through which2020 debt funding plan and strengthened our financial position.
In February 2020, we privatized Midcoast Energy Partners, L.P. (MEP)closed three new non-revolving credit facilities totaling US$1.5 billion and on March 31, 2020, we established a new syndicated one-year revolving credit facility in the amount of $1.7 billion. On April 9, 2020, we increased the amount of our new revolving facility by acquiring allan additional $1.3 billion, bringing the total amount to $3.0 billion, significantly enhancing our available liquidity.
In July 2020, we extended approximately $10.0 billion of the outstanding publicly-held common unitsour 364 day extendible credit facilities to July 2022, inclusive of MEP, through a wholly-owned subsidiary, for total consideration of approximately US$170 million.one-year term out provision.
On June 28, 2017, throughOctober 1, 2020, we completed a wholly-owned subsidiary,private placement of US$300 million 20-year senior notes for Texas Eastern and early redeemed US$300 million senior notes originally due December 2020.
On February 10, 2021, we acquired allentered into a three year, sustainability linked credit facility for $1.0 billion with a syndicate of EEP’s interest in the MEP gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million.
lenders. As a result of the above transactions,sustainability linked credit facility and other financing activities completed in 2020, our resilient cash flows and our current liquidity position, we now own 100%concurrently cancelled a one year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.
These financing activities, in combination with the MEP gas gatheringasset monetization activities noted below, provide significant liquidity and processing business.
Finalization of Bakken Pipeline System Joint Funding Agreement
On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System). On April 27, 2017, we entered into a joint funding arrangement with EEP whereby we own 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System (our jointly held interest). Under this arrangement, EEP has retained a five-year option to acquire fromexpect will enable us an additional 20% interest of the jointly held interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with us, which it had drawn upon to fund our current portfolio of capital projects without requiring access to the initial purchase.capital markets through 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.
EEP Strategic Restructuring Actions
On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to us. Further, we irrevocably waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive Distribution Units (IDUs) of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver was effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit.
The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This lower contribution will be partially offset by an increased contribution of earnings as a result of our increased ownership in the Class A common units post restructuring.
Restructuring of SEP Incentive Distribution Rights
On January 22, 2018, Enbridge and Spectra Energy Partners, LP (SEP) announced the execution of a definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP into172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing approximately 83% of SEP's outstanding common units.
ASSET MONETIZATION
In conjunction with the announcement of the Merger Transaction in September 2016, we announced our intention to divest $2 billion of assets over the ensuing 12 months in order to further strengthen our post-combination balance sheetOzark Gas Transmission and enhance the financial flexibility of the combined entity.With the completion of the Secondary Offering noted below, the Ozark pipeline system sale, the Olympic refined products pipeline sale and other divestitures completed in 2016 and previously disclosed, we exceeded the $2 billion monetization target established on announcement of the Merger Transaction.
Gas Gathering
On April 18, 2017, Enbridge Income Fund Holdings Inc. (ENF) completed a secondary offering1, 2020, we closed the sale of 17,347,750 ENF common sharesour Ozark assets for cash proceeds of approximately $63 million.
Montana-Alberta Tie Line
On May 1, 2020, we closed the sale of our Montana-Alberta Tie-Line (MATL) transmission assets for cash proceeds of approximately $189 million.
Éolien Maritime France SAS
On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the public at a priceCanada Pension Plan Investment Board (CPP Investments) for initial proceeds in excess of $33.15 per$100 million. CPP Investments will fund their 49% share for gross proceeds to us of approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, we exchanged 21,657,617 Enbridge Income Fund (Fund) units we owned for an equivalent amount of ENF common shares. In order to maintain our 19.9% ownership interest in ENF, we retained 4,309,867all ongoing future development capital. Closing of the common shares we receivedtransaction is subject to customary regulatory approvals and is expected to occur in the exchange, and sold the balance to the public through the Secondary Offering. We used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment in our growing portfoliofirst half of secured projects. Upon closing of the Secondary Offering, our total economic interest in ENF decreased from 86.9% to 84.6%.
On November 29, 2017, we finalized our 2018-2020 Strategic Plan and announced that we have identified a further $10 billion of non-core assets, of which a minimum of $3 billion we intend to sell or monetize in 2018. As a result of the announcement, we are in the process of selling certain assets within the US Midstream business of our Gas Transmission and Midstream segment.2021. Refer to Item 8. Financial Statements and Supplementary Data - Note 7. Acquisitions and Dispositions.
ALBERTA CLIPPER (LINE 67) PRESIDENTIAL PERMIT
On October 16, 2017, we received a Presidential permit for Line 67, following a nearly five-year process of review. Line 67 currently operates under an existing Presidential permit that was issued by the State Department in 2009 and the 2017 Presidential permit authorizes us to fully utilize Line 67's capacity across the United States/Canada border.
Line 67 is a key component of our mainline system, which United States refineries rely on to provide vital products to consumers across the Midwest United States.
For additional information on Line 67, refer to Growth Projects - Commercially Secured Projects - Liquids Pipelines - Lakehead System Mainline Expansion.Renewable Power Generation.
TEXAS EASTERN PIPELINE RETURN-TO-SERVICE
CANADIAN RESTRUCTURING PLANOn May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no reported injuries or damaged structures as a result of the rupture.
Effective September 1, 2015, under an agreement withIn 2020, we undertook a comprehensive integrity program to ensure continued safe and reliable service. During the Fundprogram, we reduced operating pressure across the Texas Eastern system to enable necessary integrity work to be completed. In the fourth quarter of 2020, we lifted the pressure restrictions and ENF, Enbridge transferred its Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assetsreturned the system to the Fund Group (comprising the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The consideration that we received included $18.7 billion of units in the Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion.service.
RESULTS OF OPERATIONS
| | | | | | | | | | | |
| Year ended December 31, |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars, except per share amounts) | | | |
Segment earnings before interest, income taxes and depreciation and amortization | | | |
Liquids Pipelines | 7,683 | | 7,681 | | 5,331 | |
Gas Transmission and Midstream | 1,087 | | 3,371 | | 2,334 | |
Gas Distribution and Storage | 1,748 | | 1,747 | | 1,711 | |
Renewable Power Generation | 523 | | 111 | | 369 | |
Energy Services | (236) | | 250 | | 482 | |
Eliminations and Other | (113) | | 429 | | (708) | |
Earnings before interest, income taxes and depreciation and amortization | 10,692 | | 13,589 | | 9,519 | |
Depreciation and amortization | (3,712) | | (3,391) | | (3,246) | |
Interest expense | (2,790) | | (2,663) | | (2,703) | |
Income tax expense | (774) | | (1,708) | | (237) | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | |
Preference share dividends | (380) | | (383) | | (367) | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | |
Earnings per common share | 1.48 | | 2.64 | | 1.46 | |
Diluted earnings per common share | 1.48 | | 2.63 | | 1.46 | |
|
| | | | | | |
| Year ended December 31, |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars, except per share amounts) | |
| |
| |
|
Segment earnings before interest, income taxes and depreciation and amortization | |
| |
| |
|
Liquids Pipelines | 6,395 |
| 4,926 |
| 3,033 |
|
Gas Transmission and Midstream | (1,269 | ) | 464 |
| 43 |
|
Gas Distribution | 1,390 |
| 831 |
| 763 |
|
Green Power and Transmission | 372 |
| 344 |
| 363 |
|
Energy Services | (263 | ) | (183 | ) | 324 |
|
Eliminations and Other | (337 | ) | (101 | ) | (867 | ) |
| | | |
Depreciation and amortization | (3,163 | ) | (2,240 | ) | (2,024 | ) |
Interest expense | (2,556 | ) | (1,590 | ) | (1,624 | ) |
Income tax recovery/(expense) | 2,697 |
| (142 | ) | (170 | ) |
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests | (407 | ) | (240 | ) | 410 |
|
Preference share dividends | (330 | ) | (293 | ) | (288 | ) |
Earnings/(loss) attributable to common shareholders | 2,529 |
| 1,776 |
| (37 | ) |
Earnings/(loss) per common share | 1.66 |
| 1.95 |
| (0.04 | ) |
Diluted earnings/(loss) per common share | 1.65 |
| 1.93 |
| (0.04 | ) |
EARNINGS/(LOSS)EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Year ended December 31, 20172020 compared with year ended December 31, 20162019
Earnings Attributable to Common Shareholders for the year ended December 31, 2017 were positivelynegatively impacted by contributions of approximately $2,574 million from new assets following the completion of the Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders decreased by $151 million$1.9 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a loss of $4,391 million ($2,753 million after-tax attributable to us) and related goodwill impairment of $102 million resulting from the classification of certain assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell, refer to Item 8. Financial Statements and Supplementary Data - Note 7. Acquisitions and Dispositions;
employee severance and restructuring costs of $354 million ($273 million after-tax attributable to us) in 2017, compared with $82 million in the corresponding 2016 period, related to a corporate reorganization initiative and the Merger Transaction, refer to Merger with Spectra Energy;
project development and transaction costs of $205 million ($155 after-tax attributable to us) in 2017, compared with $86 million in the corresponding 2016 period, related to the Merger Transaction, refer to Merger with Spectra Energy;
the absence of a gain of $850 million ($520 million after-tax attributable to us) recorded in 2016 related to the disposition of the South Prairie Region assets, as discussed below; partially offset by
a non-cash, $1,936 million income tax benefit ($2,045 million federal tax recovery net of a $109 million state deferred tax expense) due to the enactment of the TCJA by the United States in December 2017, refer to Item 8. Financial Statements and Supplementary Data - Note 24. Income Taxes;
•a non-cash, unrealized derivative fair value gain of $1,109$856 million ($646 million after-tax) in 2017 ($624 million after-tax attributable to us),2020, compared with $543 milliona gain of $1.6 billion ($459 million after-tax attributable to us)1.2 billion after-tax) in the corresponding 2016 period2019, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;
•a combined loss of $2.1 billion ($1.6 billion after-tax) related to our equity method investment in DCP Midstream, LLC (DCP Midstream) due to a loss of $1.7 billion ($1.3 billion after-tax) resulting from an impairment to the carrying value of our investment and commodity prices risks;a loss of $324 million ($244 million after-tax) in 2020, compared with $86 million ($68 million after-tax) in 2019 resulting from further asset and goodwill impairment losses within DCP Midstream;
•a combined loss of $615 million ($452 million after-tax) in 2020 resulting from impairments to the carrying value of our equity method investments in Southeast Supply Header (SESH) and Steckman Ridge, LP (Steckman Ridge);
•a loss of $159 million ($119 million after-tax) in 2020 resulting from the February 2020 Texas Eastern rate settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; and
•employee severance, transition and transformation costs of $339 million ($256 million after-tax) in 2020, compared with $135 million ($123 million after-tax) in 2019.
The factors above were partially offset by the absence in 2020 of cumulative asset impairment chargesthe following:
•a loss of $1,561 million ($456$467 million after-tax attributable to us) recordedus ($268 million loss on sale and $199 million tax expense) in 20162019 resulting from the sale of the federally regulated portion of our Canadian natural gas gathering and processing businesses;
•a loss of $310 million ($229 million after-tax) in 2019 resulting from the review of our comprehensive long-term economic hedging program and a payment to certain hedge counterparties to pre-settle and reset the hedge rate on a portion of our hedging program;
•a loss of $297 million ($218 million after-tax) in 2019 resulting from the classification of our MATL assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell; and
•a loss of $105 million ($79 million after-tax) in 2019 resulting from the write-off of project costs related to EEP's Sandpiper Project, the Northern Gateway ProjectAccess Northeast pipeline project.
The non-cash, unrealized derivative fair value gains and Eddystone Rail,losses discussed above generally arise as discussed below.
We havea result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks whichrisks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long term,long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investorsinvestor value proposition is based.
After taking into consideration the factors above, the remaining $1,670$447 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
increased depreciation and amortization expense primarily resulting from a significant number of new assets placed into service in 2017;
increased interest expense primarily resulting from the settlement of certain pre-issuance hedges;
increased earnings attributable to noncontrolling interests and redeemable noncontrolling interests in 2017, compared with the corresponding 2016 period. The increase was driven by higher earnings attributable to noncontrolling interests in EEP during 2017 as a result of the EEP strategic restructuring actions;
the absence of•decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain assets that were divested since the third quarter of 2016; partially offset bymarkets and fewer opportunities to achieve profitable transportation margins on facilities where we hold capacity obligations;
strong•decreased contributions from our Liquids Pipelines segment due to higher throughput primarily attributable to capacity optimization initiatives implemented in 2017 which significantly reduced heavylower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil apportionment allowing incremental heavy crude oil barrelsand related products primarily during the second and third quarters of 2020;
•the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
•decreased earnings from our Gas Distribution and Storage segment due to be shipped;warmer weather experienced in our franchise areas; and
contributions from•higher depreciation and amortization expense, in addition to reduced capitalized interest, as a result of new Liquids Pipelines assets placed into service in 2017;throughout 2019 and 2020, primarily the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program).
The business factors above were partially offset by the following positive factors:
•stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark Toll;
•increased earnings from our Gas Transmission and Midstream segment in 2017 due to favorable seasonal firm revenueincreased rates on Texas Eastern and a full year of contributionsAlgonquin resulting from assets acquired in 2016.2020 rate settlements;
Lower•increased earnings per common share for 2017, compared with the corresponding 2016 period, is primarilyfrom our Gas Distribution and Storage segment due to the increasehigher distribution charges resulting from increases in common shares from the issuance of approximately 33 million common shares in December 2017 in a private placement offering, the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through the public offering of 56 million common shares in the first quarter of 2016,rates and ongoing quarterly issuances under our Dividend Reinvestment Program. Additionalcustomer base;
•increased earnings from the assets acquired in the Merger Transaction were offset by certain unusual, infrequent or other factors, as discussed above.
Year ended December 31, 2016 compared with year ended December 31, 2015
Earnings Attributable to Common Shareholders increased by $1,601 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a gain of $850 million ($520 million after-tax attributable to us) within thenew Liquids Pipelines, segment related to the disposition of the South Prairie Region assets in December 2016;
a non-cash, unrealized derivative fair value gain of $543 million in 2016, compared with a $2,017 million unrealized derivative fair value loss in the corresponding 2015 period reflecting net fair value gainsGas Transmission and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchangeMidstream, and commodity price risks;
the absence of a goodwill impairment charge of $440 million ($167 million after-tax attributable to us) recognized in the second quarter of 2015 related to EEP’s natural gas and natural gas liquids (NGL) businesses as a result of the prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL pipelines and processing systems; partially offset by
an impairment charge of $1,004 million ($81 million after-tax attributable to us) in 2016, including related project costs, on EEP's Sandpiper Project resulting from the withdrawal of regulatory applications for the project in September 2016 that were pending with the Minnesota Public Utilities Commission (MNPUC);
an impairment charge of $373 million ($272 million after-tax attributable to us) related to the Northern Gateway Project recorded in the fourth quarter of 2016, after the Canadian Federal Government directed the National Energy Board (NEB) to dismiss our Northern Gateway Project application and rescind the Certificates of Public Convenience and Necessity for the project; and
an impairment charge of $184 million ($108 million after-tax attributable to us) recorded in 2016 related to our 75% joint venture interest in Eddystone Rail, located in the Philadelphia, Pennsylvania area. Demand for Eddystone Rail services declined as a result of a significant decrease in Bakken crude oil and West Africa/Brent crude oil and increased competition in the region.
After taking into consideration the factors above, the remaining $212 million increase is primarily explained by the following significant business factors:
strong contributions from our Liquids Pipelines segment which benefited from a number of newRenewable Power Generation assets that were placed into service throughout 2019 and 2020; and
•lower operating and administrative costs in 2015;
throughput growth period over period on the Canadian Mainline, Lakehead Pipeline System (Lakehead System) and Regional Oil Sands System primarily due to strong oil sands production growth in western Canada enabled by completed pipeline expansion projects;
contributions from the United States Gulf Coast and Mid-Continent systems in 2016, attributable to increased transportation revenues mainly resulting from an increase in the level of committed take-or-pay volumes on the Flanagan South Pipeline (Flanagan South);
contributions from Enbridge Offshore Pipelines' Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and Canadian Gas Transmission and Midstream’s Tupper Main and Tupper West gas plants (the Tupper Plants) which were acquired on April 1, 2016; partially offset by
higher earnings attributable to noncontrolling interests and redeemable noncontrolling interests in 2016 compared with 2015 driven by stronger operating performance at EEP2020 as a result of stronger contributions from its liquids business;
cost containment actions.the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting in a disruption of service on our Regional Oil Sands System with corresponding impacts into and out of our downstream pipelines, including Canadian Mainline and the Lakehead System;
a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll and a lower foreign exchange hedge rate period over period used to convert Canadian Mainline United States dollar toll revenues to Canadian dollars;
the performance of the United States portion of the Bakken Pipeline System where contributions decreased period over period primarily due to a lower surcharge on tolls subject to annual adjustment;
lower contributions in 2016 from EEP’s Berthold rail facility as a result of declining volumes on expiration of contracts;
the compression of certain crude oil location and quality differentials and the impact of a weaker NGL market; and
depreciation and amortization expense increased period over period primarily as a result of a significant number of new assets placed into service in 2016.
REVENUESENERGY SERVICES
The Energy Services businesses in Canada and the US provide physical commodity marketing and logistical services to North American refiners, producers, and other customers.
Energy Services is primarily focused on servicing customers across the value chain and capturing value from quality, time, and location price differentials when opportunities arise. To execute these strategies, Energy Services transports and stores on both Enbridge-owned and third party assets using a combination of contracted long-term and short-term pipeline, storage tank, railcar, and truck capacity agreements.
COMPETITION
Energy Services’ earnings are primarily generated from arbitrage opportunities which, by their nature, can be replicated by competitors. An increase in market participants entering into similar arbitrage strategies could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the marketing business by transacting at the majority of major hubs in North America and establishing long-term relationships with clients and pipelines.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs that are not allocated to business segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes new business development activities and corporate investments.
OPERATIONAL, ENVIRONMENTAL AND ECONOMIC REGULATION
LIQUIDS PIPELINES
Operational Regulation
We generateare subject to numerous operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.
In the US, our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the of the United States Department of Transportation (DOT). These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These laws and regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines and to operate them at permissible pressures.
PHMSA has revised existing regulations and promulgated new regulations establishing safety standards that are designed to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failure or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, earnings, cash flows and financial condition.
In Canada, our pipeline operations are subject to pipeline safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.
As in the US, several legislative changes addressing pipeline safety in Canada have recently been enacted. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the CER to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.
A key component of Liquids Pipelines safety and reliability is the approach to integrity management that uses reliability targets and safety case assessments. A long history of extensive inline inspection has provided detailed knowledge of the assets in the liquids pipeline system. Every segment of every pipeline is assessed and maintained, in a proactive manner, such that the probability of a leak is sufficiently low and that stringent reliability targets are met. Furthermore, the integrity management program has an independent step to check the results of our integrity assessments to validate the effectiveness of the program and to ensure that that the operational risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle. As inspection technology, pipeline materials and construction practices improve with time, and new data on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves; with a strong focus on continual improvement in every aspect of integrity management.
Environmental Regulation
We are also subject to numerous federal, state and provincial environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits and other approvals.
In particular, in the US, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs may significantly increase our operating costs compared to historical levels.
In the US, climate change action is evolving at federal, state and regional levels. The Supreme Court decision in Massachusetts v. Environmental Protection Agency in 2007 established that GHG emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs. The new US presidential administration has also announced that policies designed to combat climate change and reduce GHG emissions will be a key legislative and regulatory priority, and thus stricter emissions limits and air quality enforcement actions are possible In addition, a number of states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.
For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the US. In 2019, the Government of Canada implemented a federal system of carbon pricing. The pricing applies to provinces and territories that do not have a carbon pricing system in place that meets the federal benchmark. On November 19, 2020, the federal Minister of Environment and Climate Change introduced Bill C-12, the Canadian Net-Zero Emissions Accountability Act, which requires national targets for the reduction of GHG emissions in Canada be set, with the objective of attaining net-zero emissions by 2050. In December 2020, the Government of Canada announced plans to increase the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030.
Due to the speculative outlook regarding any US federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
Economic Regulation
Our liquids pipelines also face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements including permits and regulatory approvals for both new and existing projects, upon which future and current operations are dependent. Our Mainline System and other liquids pipelines are subject to the actions of various regulators, including the CER and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings.
GAS TRANSMISSION AND MIDSTREAM
Operational Regulation
The span of regulation risks that apply to the Liquids Pipelines business as described above under Liquids Pipelines also applies to the Gas Transmission and Midstream business. Most of our US gas transmission operations are regulated by the FERC. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services. The FERC also regulates the construction of US interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transmission of gas by intrastate pipelines.
Texas Eastern reached an agreement with its shippers and filed a Stipulation and Agreement with the FERC on October 28, 2019. On February 25, 2020, Texas Eastern received approval from the FERC of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from three primary sources:the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020. On July 2, 2020, Algonquin received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020. East Tennessee filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020. The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we will await FERC approval. The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval. In July 2020, the 2020-2021 rate settlement agreement with Westcoast's BC Pipeline shippers was approved by the CER. Following approval of the settlement, Westcoast applied and received approval from the CER on August 12, 2020 for the interim tolls to be made final, including the interim tolls from January 1, 2020 to March 31, 2020 as well as the revised interim tolls in effect as at April 1, 2020.
Our operations are subject to the jurisdiction of the Environmental Protection Agency and various other federal, state and local environmental agencies. Our US interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the DOT concerning pipeline safety.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state regulation. DCP Midstream's interstate NGL transportation pipelines are subject to FERC regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline safety, including the CER, the Transportation Safety Board and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission operations are subject to regulation by the CER or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities and acquisitions. In addition, these assets are subject to GHG emissions regulations, including GHG emissions management and carbon pricing policies. Across Canada there are a variety of new and evolving initiatives in development at the federal and provincial levels aimed at reducing GHG emissions. The Government of Canada has finalized a federal plan to have carbon pricing in place in all Canadian jurisdictions.
GAS DISTRIBUTION AND STORAGE
Operational Regulation
Our gas distribution and storage utility operations are regulated by the OEB and the Québec Régie de l’énergie, among others. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or amounts that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year incentive regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).
We seek to mitigate operational regulation risk. We retain dedicated professional staff and maintain strong relationships with customers, intervenors and regulators. This strong regulatory relationship continued in 2020 following OEB Decisions and Ordersapproving Phase 2 of Enbridge Gas’ application for 2020 rates and Phase 1 of Enbridge Gas’ application for 2021 rates. The Phase 2 Decision and Order approved the recovery of requested 2020 discrete incremental capital investments through the incremental capital module, while the Phase 1 Decision and Order approved 2021 base rate escalation under the price cap mechanism.
Enbridge Gas has continued to develop opportunities to support a low carbon future in Ontario. In 2020, the OEB approved Enbridge Gas' application to implement a voluntary RNG pilot program, whereby customers can voluntarily contribute towards the incremental cost of low carbon RNG which would displace regular natural gas.The OEB also approved Enbridge Gas' pilot project to construct facilities that will allow regular natural gas to be blended with hydrogen gas, in an isolated portion of the existing distribution system, with the intent to gain insight into the use of hydrogen as a method for decarbonizing natural gas for the purpose of reducing GHG emissions.
Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which regulate the protection of the environment and the health and safety of workers. Environmental legislation primarily includes regulation of discharges to air, land and water; environmental assessment of natural gas infrastructure projects in Ontario; protection of species at risk and species at risk habitat; management and disposal of hazardous waste; the assessment and management of contaminated sites; and the reporting and reduction of GHG emissions.
Gas distribution system operation, as with any industrial operation, has the potential risk of abnormal or emergency conditions, or other unplanned events that could result in leaks or emissions in excess of permitted levels. These events could result in injuries to workers or the public, adverse impacts to the environment in which we operate, property damage or regulatory violations including orders and fines. We could also incur future liability for soil and groundwater contamination associated with past and present site activities.
In addition to gas distribution, we also operate storage facilities and a small amount of oil and brine production in southwestern Ontario. Environmental risk associated with these facilities is the potential for unplanned releases. In the event of a release, remediation of the affected area would be required. There would also be potential for fines, orders or charges under environmental legislation, and potential third-party liability claims by any affected landowners.
The gas distribution system and our other operations must maintain environmental approvals and permits from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/or audits. Annual reports, such as the Annual Written Summary Report are submitted to the Ontario Ministry of the Environment, Conservation and Parks (MECP) and other services,regulators to demonstrate we are in good standing with our Environmental Compliance Approvals. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation. As environmental requirements and regulations become more stringent, the cost to maintain compliance and the time required to obtain approvals has increased.
As with previous years, in 2020, we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada (ECCC), the Ontario MECP, and a number of voluntary reporting programs. In accordance with the provincial GHG regulations, stationary combustion and flaring emissions related to storage and transmission operations were verified in detail by a third-party accredited verifier with no material discrepancies found.
Enbridge Gas utilizes emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors will continually be updated in the system as required. Enbridge Gas continues to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.
In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, distribution sales and commodity sales. Transportationan output-based pricing system (OBPS).
The federal carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural gas and is applicable to the majority of customers. Enbridge Gas is registered as a natural gas distributor with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge increases annually on April 1 of each year by 1.96 cents/m3, rising up to 9.79 cents/m3 in 2022. In December 2020, the federal government announced plans to increase the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030. Enbridge Gas estimates that this will equate to a federal carbon charge on natural gas of approximately 33.31 cents/m3 in 2030.
The OBPS component came into effect on January 1, 2019. Under OBPS, a registered facility has a compliance obligation for the portion of their emissions that exceeds their annual facility emissions limit, which is calculated based on the sector specific output-based standard and annual production. Enbridge Gas is registered with ECCC as an emitter in the OBPS program and has an annual compliance obligation associated with the combustion and flaring emissions associated with its natural gas pipeline transmission system. As a registered facility under OBPS,Enbridge Gas submitted an annual report along with the required verification report from an accredited third-party verifier who found no material misstatements. Enbridge Gas is required to remit payment for facility emissions that exceed its annual facility emissions limit. Due to COVID-19, ECCC has delayed the payment deadline from December 15, 2020 to April 15, 2021, and therefore Enbridge Gas has deferred payment until the first half of 2021.
In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. The date of the transition has not yet been communicated. Enbridge Gas will continue to have a compliance obligation under either the OBPS or EPS program for its facility-related emissions, as well as the federal carbon charge for its customer-related emissions.
HUMAN CAPITAL RESOURCES
WORKFORCE SIZE AND COMPOSITION
As at December 31, 2020, we had approximately 11,200 regular employees, including 1,600 unionized employees across our North American operations. This total rises to more than 13,000 if including temporary employees and contractors. We have a strong preference for direct employment relationships but where we have collectively bargained for employees, we have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.
SAFETY
We believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on employee and contractor safety continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents. Refer also to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments- COVID-19 Pandemic, Reduced Crude Oil Demand and Commodity Prices.
DIVERSITY AND INCLUSION
To ensure our workforce is reflective of the communities where we operate, we have pursued efforts to increase the representation of women, ethnic and racial groups, people with disabilities and veterans. Our original ambitions were set and shared with employees in 2018 with progress toward achievement shared regularly through our Diversity Dashboard. While we have made strong progress, we are accelerating the pace of our program and we have plans in place to meet our objectives by 2025. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.
In early 2021, we added Inclusion to our core values of Safety, Integrity and Respect to demonstrate this commitment.
We are building an organization where people feel safe and welcome and have the opportunity to thrive and grow based on merit. As part of our evolving ESG strategy, we wanted to create a tighter link between our success and the workforce related ESG measures – including safety and diversity – that enable it. As a result, beginning in 2021, key metrics in these areas are embedded in our scorecards and directly impact compensation.
PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development because we recognize their success is our success. Every year, employees are provided a range of development opportunities through a variety of channels, including: educational reimbursement programs; developmental relationships with mentors; rotational assignments; and Enbridge University, which offers a large catalog of courses.
EXECUTIVE OFFICERS
The following table sets forth information regarding our executive officers:
| | | | | | | | |
Name | Age | Position |
Al Monaco | 61 | President & Chief Executive Officer |
Colin K. Gruending | 51 | Executive Vice President & Chief Financial Officer |
Robert R. Rooney | 64 | Executive Vice President & Chief Legal Officer |
William T. Yardley | 56 | Executive Vice President & President, Gas Transmission and Midstream |
Cynthia L. Hansen | 56 | Executive Vice President & President, Gas Distribution and Storage |
Byron C. Neiles | 55 | Executive Vice President, Corporate Services |
Vern D. Yu | 54 | Executive Vice President & President, Liquids Pipelines |
Matthew Akman | 53 | Senior Vice President, Strategy & Power |
Allen C. Capps | 50 | Senior Vice President, Corporate Development & Energy Services |
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. Mr. Monaco is also a member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco served as President, Gas Pipelines, Green Energy and International with responsibility for the growth and operations of our gas pipelines, including the gas gathering and processing operations in the US, our Gulf Coast offshore assets and our investments in Alliance Pipeline, Vector and Aux Sable, as well as our International business development and investment activities and Renewable Power Generation.
Colin K. Gruending was appointed Executive Vice President and Chief Financial Officer of Enbridge on June 1, 2019. Previously, our Senior Vice President, Corporate Development and Investment Review, Mr. Gruending performed a number of progressively challenging executive roles such as Vice President Corporate Development and Planning and Vice President, Treasury and Tax while concurrently serving as Chief Financial Officer for Enbridge Income Fund and Enbridge Income Fund Holdings Inc. Prior to that, Mr. Gruending served as Corporate Controller and also led enterprise Investor Relations and Pension Investments.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Rooney leads our legal, ethics and compliance, security and aviation teams across the organization.
William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream on February 27, 2017. Mr. Yardley, based in Houston, was previously President of Spectra Energy Corp's. (Spectra Energy) US Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s US portfolio of assets.
Cynthia L. Hansen was appointed Executive Vice President and President, Gas Distribution and Storage, on June 1, 2019. Ms. Hansen is responsible for the overall leadership and operations of Enbridge Gas, following the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), as well as Gazifère. Previously, our Executive Vice President, Utilities and Power Operations, Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with other business unit leaders.
Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles has oversight of our Technology & Information Services, Human Resources, Real Estate, Safety & Reliability, Supply Chain Management, and Public Affairs, Communications & Sustainability. Mr. Neiles had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational Reliability and had been Senior Vice President of Major Projects since November 2011, after joining our Major Projects group in April 2008.
Vern D. Yu was appointed Executive Vice President and President, Liquids Pipelines on January 1, 2020. Previously, Mr. Yu served as President and Chief Operating Officer for Liquids Pipelines and prior to that served as Executive Vice President and Chief Development Officer. He had previously served as Senior Vice President, Corporate Planning and Chief Development Officer. Prior to joining Corporate Development, Mr. Yu served as Senior Vice President of Business and Market Development for Enbridge’s Liquids Pipelines division and previously has held a series of roles with increasing responsibility in our corporate and financial areas.
Matthew Akman is our Senior Vice President, Strategy and Power. He is responsible for the corporate strategic planning process and all renewable power operations and development globally. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations. Prior to joining Enbridge, Mr. Akman worked primarily in banking with a focus on institutional equity research.
Allen C. Capps is our Senior Vice President, Corporate Development and Energy Services. He is responsible for capital allocation, investment review, corporate business development and Energy Services. Prior to assuming his current role in June 2019, Mr. Capps served as our Senior Vice President and Chief Accounting Officer and before that Vice President and Controller of Spectra Energy.
ADDITIONAL INFORMATION
Additional information about us is available on our website at www.enbridge.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC). Reports, proxy statements and other services revenuesinformation filed with the SEC may also be obtained through the SEC’s website (www.sec.gov).
ENBRIDGE GAS INC.
Additional information about Enbridge Gas can be found in its annual information form, financial statements and management's discussion and analysis (MD&A) for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Enbridge Gas and are earnedpublicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE PIPELINES INC.
Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
WESTCOAST ENERGY INC.
Additional information about Westcoast can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ITEM 1A. RISK FACTORS
The following risk factors could materially and adversely affect our business, operations, financial results or market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood based on order of presentation or grouping under sub-captions. For ease of reference, the risk factors are presented under the following sub-captions: (1) Risks Related to Operational Disruption or Catastrophic Events; (2) Risks Related to our Business and Industry; and (3) Risks Related to Government Regulation and Legal Risks.
RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS
Pipeline operations involve numerous risks that may adversely affect our business and financial results.
Operation of complex pipeline systems, gathering, treating, storing and processing 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; which include, but are not limited to, physical risks related to climate change, such as, fires, earthquakes, hurricanes, floods, landslides, increased volatility in season temperatures, rising sea levels or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property and our assets, 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.
We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead System; in October 2018 at the BC Pipeline T-South system; and in January 2019, August 2019 and May 2020 at the Texas Eastern pipeline, and we cannot guarantee that we will not experience catastrophic events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events.
An environmental incident is an event that may cause harm or potential harm to the environment and could also lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts to us and could impact our ability to work with various stakeholders. 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.
A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption, curtailment of commodity supply, operational incident or other reasons could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders and our reputation. Service interruptions that impact our crude oil and natural gas pipeline transportation businessesservices can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements.
Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to populated areas and a major incident could result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, material repair costs or increased costs of operating and insuring our assets.
Cyber-attacks or security breaches could adversely affect our business, operations or financial results.
Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems, or the network or systems of our third-party vendors, could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we and some of our vendors collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders.
Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication, magnitude and frequency of cyber-attacks and data security breaches. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cyber-attacks. We have a cyber-security controls framework in place which has been derived from the National Institute of Standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a security operations center, which operates at all times to monitor, detect and investigate activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed.
During the normal course of business, we have experienced and expect to continue to experience attempts to gain unauthorized access to, or to compromise, our information systems or to disrupt our operations through cyber-attacks or security breaches, although none to our knowledge have had a material adverse effect on our business, operations or financial results. Despite our security measures, our information systems, or those of our vendors, may become the target of further cyber-attacks (including hacking, viruses or acts of terrorism) or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems, or those of our vendors, affect our ability to correctly record, process and report transactions or financial information, or result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences or other costs or be subject to increased regulation or litigation, all of which could materially adversely affect our reputation, business, operations or financial results.
Pandemics, epidemics or disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or disease outbreaks, in locations in which we operate or globally, could materially adversely affect our business, operations, financial results and forward-looking expectations. The COVID-19 pandemic has negatively impacted us in 2020 and the impacts are expected to continue for future periods, which we are unable to reasonably predict due to numerous uncertainties, including the duration and severity of the pandemic.
The World Health Organization declared COVID-19 to be a pandemic on March 11, 2020. In response to the rapid global spread of COVID-19, governments have enacted emergency measures to combat the spread of the virus. These measures include power production revenuesrestrictions on business activity and travel, as well as requirements to isolate or quarantine, which could continue or expand. Certain of our operations and projects have been deemed essential services in critical infrastructure sectors and are currently exempt from certain business activity restrictions; however, there is no guarantee that this exemption will continue. These actions have interrupted business activities and supply chains; disrupted travel; contributed to significant volatility in the financial and commodity markets, resulting in lower interest rates; impacted social conditions; and adversely impacted national and international economic conditions, including commodity prices and demand for energy, as well as the labor market.
Given the ongoing and dynamic nature of the circumstances surrounding the COVID-19 pandemic, it is difficult to predict how significant the impact of this pandemic, including any responses to it, will be on North American or global economies or our portfoliobusiness, or for how long disruptions are likely to continue. The extent of renewablesuch impact will depend on future developments and power generation assets. Forfactors outside of our transportation assets operating under market-based arrangements, revenuescontrol, which are drivenhighly uncertain, rapidly evolving and cannot be predicted, including new information which may emerge concerning the severity or duration of this pandemic (including regarding new COVID-19 strains) and actions taken by governments and others to contain or end the COVID-19 pandemic or its impact (including regarding the development and distribution of effective vaccines). Such developments, which have had or may have an adverse effect on our customers, suppliers, regulators, business, operations and financial results, include disruptions that, among other things:
•adversely impacted market fundamentals, such as commodity prices and supply and demand for energy, decreasing volumes transported on our systems, increasing our exposure to asset utilization risks and adversely affecting our results;
•adversely impacted our Liquids Pipelines investments;
•could prevent one or more of our secured capital projects from proceeding, and has delayed completion and increased anticipated costs of certain projects;
•adversely impacted the operations or financial position of our third-party suppliers, service providers or customers and increase our exposure to contract-related risks or customer credit risk;
•adversely impacted the global capital markets, which could adversely impact the ratings assigned to our securities or our credit facilities and/or impact our ability to access capital markets at effective rates;
•increased our risks associated with emergency measures taken (including remote working, distancing and additional personal protective equipment), including increased cyber security risks, increased costs and the corresponding tollspotential for reduced availability or productivity of our employees or third-party contractors or service providers;
•adversely impacted our ability to accurately forecast assumptions used to evaluate expansion projects, acquisitions and divestitures on an ongoing basis;
•adversely impacted the carrying value of our equity method investment in DCP Midstream and could adversely impact the outcome of future asset impairment tests, indicating that the carrying value of such assets might be impaired;
•could adversely impact the execution of current and future trade policies between Canada and the US; and
•could result in future business interruption losses that our insurance coverage may not be sufficient to cover.
There can be no assurance that our strategies to address potential disruptions will mitigate these risks or the adverse impacts to our business, operations and financial results. Future adverse impacts to our business, operations and financial results may materialize that are not yet known. In addition, disruptions related to the COVID-19 pandemic have had, or could have, the effect of heightening many of the other risks described in this Item 1A. Risk Factors. The risk that is most significantly heightened by the COVID-19 pandemic is the impact of commodity price weakness and volatility on our Liquids Pipelines, Gas Transmission and Midstream and Energy Services businesses, as detailed in the risk factor “Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our results of operations” below. Even after the COVID-19 pandemic has subsided, we may continue to experience adverse impacts to our business as a result of its global impact, including any related recession, as well as lingering impacts on supply of, demand for and prices of crude oil, natural gas, natural gas liquids, LNG and renewable energy.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the US and Canada. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could adversely affect our business, operations or financial results.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.
With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas, which can adversely affect our revenues and earnings.
With respect to our Gas Distribution and Storage assets, customers are billed on a combination of both fixed charge and volumetric basis and our ability to collect their respective total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our Gas Distribution customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Our Gas Distribution business has deferral accounts approved by the OEB that provide regulatory protection against the margin impacts associated with declining annual average consumption due to efficiencies and customers’ conservation efforts. Sales and transportation services. Forservice to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our Gas Distribution business may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. Our Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial and industrial volumes.
With respect to our Renewable Power Generation assets, operating under take-or-pay contracts, revenues reflectearnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity method investments, could reduce our earnings.
Generally accepted accounting principles in the United States of America (US GAAP) requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate non-cash charge to earnings.
Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results.
Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.
We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access markets currently served by our liquids pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. We also face competition from alternative gathering and storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.
Execution of our projects subjects us to various regulatory, operational and market risks that may affect our financial results.
Our ability to successfully execute our projects is subject to various regulatory, operational and market risks, including:
•the ability to obtain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and to maintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
•potential changes in federal, state, provincial and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the underlying contractproject;
•impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•opposition to our projects by third parties, including interest groups;
•the availability of skilled labor, equipment and materials to complete projects;
•the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier non-performance, weather, geologic conditions or other factors beyond our control, that may be material;
•general economic factors that affect the demand for servicesour projects; and
•the ability to raise financing for these projects.
Climate related risks are integrated into our larger risk categories that encompass operational, financial and stakeholder consequences. This is done because of the interconnected economic, social and environmental nature of climate impacts requires a comprehensive review within the context of other risks that impact us.
Any of these risks could prevent a project from proceeding, delay its completion or capacity.increase its anticipated cost. Recent projects that have experienced delays include the US L3R Program, the Spruce Ridge Project and the T-South Reliability and Expansion Program. New projects may not achieve their expected investment return, which could affect our financial results, and hinder our ability to secure future projects. For rate-regulated assets, revenuesadditional discussion of specific proceedings that could affect our operations and financial results, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.
Changing expectations from stakeholders regarding ESG practices and climate change or erosion of stakeholder trust or confidence could influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results.
Companies across all sectors and industries are charged in accordancefacing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, safety and stakeholder relations remain primary focus areas; changing expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with tolls establishedkey stakeholders, including local communities, Indigenous communities and other groups directly impacted by the regulator,our activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors, investment funds and others which are increasingly focused on ESG practices. We have long been committed to strong ESG practices and performance, and in most cost-of-service based arrangements are reflective2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include targets for GHG emissions reduction; adapting to the energy transition over time is one of our strategic priorities. Inadequately managing expectations and issues important to stakeholders, including those related to environment and climate change, could impact stakeholder trust and confidence and our reputation and have negative impacts on our business, operations or financial results, including:
•loss of business;
•loss of ability to secure growth opportunities;
•delays in project execution;
•legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin;
•increased regulatory oversight;
•loss of ability to obtain and maintain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms;
•impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•changing investor sentiment regarding investment in the oil and gas industry or our company;
•restricted access to and cost of capital; and
•loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays, project cancellations, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators. Recent judicial decisions have increased the ability of groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we and others in the energy and pipeline businesses are facing organized opposition to oil and gas extraction and shipment of oil and gas products.
Our forecasted assumptions may not materialize as expected on our expansion projects, acquisitions and divestitures.
We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss of our profits.
Our insurance coverage may not be sufficient to cover our losses in the event of an accident, natural disaster or other hazardous event.
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards also can cause, and in some cases have caused, personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and certain of our affiliates to mitigate the financial impacts arising from these hazards. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry; however, insurance does not cover all events in all circumstances.
In the unlikely event that multiple insurable incidents that in the aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries. Additionally, even with insurance, if any natural disaster or other hazardous event leads to a catastrophic interruption in operations, we may not be able to restore operations without significant interruption.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. A significant amount of our credit exposures for transmission and storage services are with customers who have an investment-grade rating (or the service plusequivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a regulator-approved rateresult of return. Higher transportationfuture capital projects for which natural gas and oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. It is possible that customer payment defaults, if significant, could adversely affect our earnings and cash flows.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.
We use derivative financial instruments to manage the risks associated with movements in foreign exchange rates, interest rates, commodity prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other servicesspeculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.
Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects starting in 2016 to transform various processes, capabilities and reporting systems infrastructure to continuously improve effectiveness and efficiency across the organization and are subject to transformation project risk with respect to these projects. Such projects, some of which will continue into 2021 and 2022, including integration initiatives arising out of the merger with Spectra Energy and the amalgamation of EGD and Union Gas, are subject to transformation project risk. Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries do not fully deliver anticipated results due to insufficiently addressing the risks associated with project execution and change management. This could result in negative financial, operational and reputational impacts.
Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our operational results.
The COVID-19 pandemic and concerns about global economic growth have caused considerable uncertainty in the market for crude oil, natural gas and other commodities, lowering demand forecasts. This, and the changing relationship dynamic among OPEC+ members, has put severe downward pressure on prices early in 2020. The economic climate in Canada, the US and abroad has deteriorated and worldwide demand for petroleum products has diminished. 2020 saw a dramatic decline in the price of crude oil, natural gas and NGL and other commodities whose prices are highly correlated to crude oil. The West Texas Intermediate benchmark prices for crude oil had been trading around US$60 per barrel in December 2019 and fell to as low as US$14 per barrel in March 2020 and into a negative value on April 20, 2020. Crude oil prices started to recover in the second and third quarters of 2020, with West Texas Intermediate benchmark prices reaching over US$40 primarily due to the announcement of crude oil productions cuts in April 2020 and June 2020. The West Texas Intermediate benchmark finished the year at US$48.35 per barrel.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the Competitive Tolling Settlement on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues reflected increasedand earnings. The current commodity price environment has impacted both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines. This has led to a year-over-year reduction in Mainline System utilization of 80 kbpd in 2020.
While reduced demand has impacted throughput and revenue on the Mainline System, the financial impact of reduced throughput on our coreupstream regional pipelines and our downstream market extension pipelines is largely mitigated by the presence of take-or-pay contracts. The financial impact is also mitigated through cost-of-service arrangements with credit-worthy counterparties or parties that are not investment grade but have instead provided credit support in the form of letters of credit or other instruments. The existing market conditions are likely to stress the creditworthiness of many of these counterparties and we continue to evaluate the situation on an ongoing basis. To date, we have not had any counterparty default on its obligations to maintain credit support or pay its tolls under these contracts and, at this time, we do not foresee a material impact to our financial results.
Shippers also reduced investment in exploration and development programs in 2020. The decline in oil prices is also causing some sponsors of oil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin.
With respect to our Gas Transmission and Midstream assets, the low commodity prices have had limited impact on demand for natural gas shipped within our long-haul Gas Transmission assets in the US and Canada. These assets are comprised of primarily cost-of-service and take-or-pay contract arrangements which are not directly impacted by fluctuations in commodity prices.
Within our US Midstream assets, through our investment in DCP Midstream and, to a lesser extent, the Aux Sable liquids pipeline assets combinedproduct plant, we are engaged in the businesses of gathering, treating and processing natural gas and natural gas liquids. Given the drastic decline in commodity prices, DCP Midstream made the decision to decrease its distribution to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby reducing our cash flows. Aux Sable results were also negatively impacted by these lower commodity prices.
With respect to our Energy Services business, we generate margins by capitalizing on quality, time and location differentials when opportunities arise. The recent volatility in commodity prices could limit margin opportunities and impede our ability to cover capacity commitments.
At this point, given the many outstanding questions as to the length and depth of the current low commodity price environment, the impact on us is uncertain; however, it is possible that it may have an adverse impact on our business and our results of operations.
Our Liquids Pipelines growth rate and results may be directly and indirectly affected by commodity prices and Government policy.
The efforts implemented in 2019 by the Alberta Government to manage supply and inventories in Western Canada continued at diminishing levels in 2020 as incremental revenuestake away capacity was introduced to the market. This intervention had a negligible impact on the Mainline System throughput, as enough inventory existed to meet refinery customer needs and service our favorable markets. Wide commodity price basis between Western Canada and global tidewater markets have negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.
The tight conventional oil plays of Western Canada and the Bakken region of North Dakota have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be well managed through active hedging programs and are positioned to react quickly at market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our pipeline systems.
Our Gas Transmission and Midstream results may be adversely affected by commodity price volatility and risks associated with our hedging activities.
Our exposure to commodity price volatility is inherent to our US Midstream business. We employ a disciplined hedging program to manage this direct commodity price risk. Because we are not fully hedged, we may be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of these commodities could adversely affect our financial results.
Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we likely will be prevented from realizing the full benefits of price increases above the level of the hedges. 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.
Our Energy Services results may be adversely affected by commodity price volatility.
Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Lower commodity prices due to changing market conditions could limit margin opportunities and impede Energy Services' ability to cover capacity commitments.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. An inability to access capital may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS
Many of our operations are regulated and failure to secure regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative impact on our business, operations or financial results.
The nature and degree of regulation and legislation affecting energy companies in Canada and the US have changed significantly in recent years.
In Canada, the passing of the Canadian Energy Regulator Act and the Impact Assessment Act under Bill C-69, which came into force on August 28, 2019, is expected to extend timelines associated with regulatory approvals for new projects which trigger a federal impact assessment. Changes to the British Columbia regulatory framework have also been made, including a new Environmental Assessment Act, which came into force in December 2019, affecting provincially-regulated projects in a similar manner as those that are federally-regulated. Within the US and in Canada, pipelines companies continue to face opposition from anti-pipeline activists, Indigenous and tribal communities, citizens, environmental groups and politicians concerned with either the safety of pipelines or environmental effects. In the US, several federal agencies made changes to regulations that were designed to streamline permitting, including changes that the Environmental Protection Agency made in June 2020 to regulations implementing Section 401 of the Clean Water Act and the July 2020 Council on Environmental Quality revisions to regulations implementing the National Environmental Policy Act. These and many other regulations adopted during the previous US presidential administration are not only being challenged in multiple courts, but have now been expressly targeted for rollback by the new US administration, which is expected to modify or reverse the regulations.
These actions could adversely impact permitting of a wide range of energy projects. We may not be able to obtain or maintain all required regulatory approvals for our operating assets placed into serviceor development projects. If there is a delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or if laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs.
Our operations are subject to numerous environmental laws and regulations, including those relating to climate change and GHG emissions, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.
Failure to comply with environmental laws and regulations and failure to secure permits necessary for our operations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations, including those related to climate change and GHG emissions, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities. Efforts to regulate or restrict GHG emissions could also drive down demand for the products we transport.
We may not be able to obtain or maintain all required environmental regulatory approvals and permits for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.
In November 2020, we set new ESG goals for the future, including with respect to GHG emissions reduction. Our ability to achieve these goals depends on many factors, including our ability to reduce emissions from our operations through modernization and innovation, reduce the emissions intensity of the electricity we buy, invest in renewables and low carbon energy and balance residual emissions through carbon offset credits. The cost associated with our GHG emissions reduction goals could be significant. Failure to achieve our emissions targets could result in reputational harm, changing investor sentiment regarding investment in Enbridge or a negative impact on access to and cost of capital.
Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase in operating and compliance costs. We do not own all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights could have an adverse effect on our reputation, operations and financial results. Scrutiny over the past two years.
Gas distribution sales revenues are recognizedintegrity of our assets and operations has the potential to increase operating costs or limit future projects. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in a manner consistentwhich we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the underlying rate-setting mechanism mandatedrespective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the regulator. Revenues generated bysafe and reliable operation of our assets and adherence to existing regulations is the gas distribution businessesbest approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.
Our operations are primarily driven by volumes delivered, which varysubject to economic regulation and failure to secure regulatory approval for our proposed or existing commercial arrangements could have a negative impact on our business, operations or financial results.
Our liquids pipelines face economic regulatory risk, the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements. We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with weather and customer composition and utilization,shippers that govern the majority of our liquids pipelines assets. However, there remains a risk that a regulator could modify significantly its own long-standing policies for rate making as well as regulator-approved rates. The costoverturn long-term agreements that we have entered into with shippers.
We could be subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation, including in particular the US with a new presidential administration and in Canada and other foreign jurisdictions in which we operate.
We are also subject to the examination of our tax returns and other tax matters by the US Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of legal proceedings.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are included in Item 1. Business.
In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private land-owners, First Nations, Native American Tribes, 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 passedowned by us and/or used by us under easements, licenses, leases 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, with the remainder used by us under easements, leases or permits.
Titles to our properties acquired in our liquids and 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. LEGAL PROCEEDINGS
We are involved in various legal and administrative proceedings and litigation arising in the ordinary course of business. The outcome of these matters is not predictable at this time. However, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial condition, results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at February 5, 2021, there were 2,025,495,603 holders of record of our common stock. A substantially greater number of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks, brokers and other financial institutions.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item will be contained in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2020.
Recent Sales of Unregistered Equity Securities
None.
Issuer Purchases of Equity Securities
None.
Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2016 through December 31, 2020 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the S&P/TSX Composite index, (3) the S&P 500 index, (4) our US peer group (comprising CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer group (comprising CU, FTS, IPL, PPL and TRP). The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
| | | | | | | | | | | | | | | | | | | | |
| January 1, 2016 | December 31, |
| 2016 | 2017 | 2018 | 2019 | 2020 |
Enbridge Inc. | 100.00 | | 127.97 | | 116.65 | | 107.20 | | 138.65 | | 117.59 | |
S&P/TSX Composite | 100.00 | | 121.08 | | 132.09 | | 120.36 | | 147.89 | | 156.17 | |
S&P 500 Index | 100.00 | | 111.96 | | 136.40 | | 130.42 | | 171.49 | | 203.04 | |
US Peers1 | 100.00 | | 133.50 | | 136.67 | | 131.82 | | 162.50 | | 137.15 | |
Canadian Peers | 100.00 | | 132.07 | | 140.85 | | 126.30 | | 164.43 | | 127.61 | |
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is not necessarily indicative of results of future operations and should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data to customers through ratesfully understand factors that may affect the comparability of the information presented below.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars, except per share amounts) | | | | | |
Consolidated Statements of Earnings | | | | | |
Operating revenues | $ | 39,087 | | $ | 50,069 | | $ | 46,378 | | $ | 44,378 | | $ | 34,560 | |
Operating income | 7,957 | | 8,260 | | 4,816 | | 1,571 | | 2,581 | |
Earnings | 3,416 | | 5,827 | | 3,333 | | 3,266 | | 2,309 | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | | (407) | | (240) | |
Earnings attributable to controlling interests | 3,363 | | 5,705 | | 2,882 | | 2,859 | | 2,069 | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | | 2,529 | | 1,776 | |
Common Share Data | | | | | |
Earnings per common share | | | | | |
Basic | 1.48 | | 2.64 | | 1.46 | | 1.66 | | 1.95 | |
Diluted | 1.48 | | 2.63 | | 1.46 | | 1.65 | | 1.93 | |
Dividends paid per common share | 3.24 | | 2.95 | | 2.68 | | 2.41 | | 2.12 | |
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars) | | | | | |
Consolidated Statements of Financial Position | | | | | |
Total assets | $ | 160,276 | | $ | 163,157 | | $ | 166,905 | | $ | 162,093 | | $ | 85,209 | |
Long-term debt | 62,819 | | 59,661 | | 60,327 | | 60,865 | | 36,494 | |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and does not ultimately impact earnings dueanalysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
This section of our Annual Report on Form 10-K discusses 2020 and 2019 items and year-over-year comparisons between 2020 and 2019. For discussion of 2018 items and year-over-year comparisons between 2019 and 2018, refer to its flow-through nature.
Commodity salesPart II. Item 7. Management's Discussion and Analysis of $26,286 million, $22,816 millionFinancial Condition and $23,842 millionResults of Operations of our Annual Report on Form 10-K for the year ended December 31, 2017, 20162019.
RECENT DEVELOPMENTS
COVID-19 PANDEMIC, REDUCED CRUDE OIL DEMAND AND COMMODITY PRICES
The COVID-19 pandemic and 2015, respectively, were generated primarily throughthe emergency response measures enacted by governments in Canada, the US and around the world, have caused material disruption to many businesses resulting in a severe slow down in Canadian, US and global economies, leading to increased volatility in financial and commodity markets worldwide and demand reduction for certain commodities.
We took proactive measures to deliver energy safely and reliably during the COVID-19 pandemic. We activated our Energy Services operations. Energy Services includescrisis management team to focus on a number of priorities, including: (i) the contemporaneous purchasehealth and salesafety of our employees and the public; (ii) operational reliability for our customers and markets; (iii) identification of essential personnel and procedures; and (iv) extensive stakeholder communication and outreach including updates to our Board of Directors. We are following recommendations from public health authorities and medical experts and have taken steps to help prevent our employees’ exposure to the spread of COVID-19, including, where practical, work-at-home plans enacted in March 2020 and the implementation of business continuity plans to enable the integrity of our operations and protect the health of our employees in pipeline control functions and service centers, our field representatives and other essential functions.
With respect to the safe operation of our facilities, we continue to employ all safety processes and procedures in the normal course. Our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need to heat their homes and fuel their lives.
The COVID-19 pandemic has had a deep impact in the communities in which we operate. We are providing support in our communities by advancing funds to respond and provide relief to those who are most vulnerable. Our teams in our operating regions are working closely with our nonprofit community partners, our closest Indigenous and Tribal neighbors and local governments to identify where resources are needed most.
The COVID-19 pandemic has negatively impacted crude oil natural gas,demand and increased commodity price volatility, which together present potential new or elevated risks to our business. In late March, we began to see impacts both on the supply of, and demand for, crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our crude oil pipelines responded to significantly lower demand caused by the COVID-19 pandemic, declining storage availability and refinery utilization, and commodity price declines by reducing volumes beginning in the second quarter of 2020. In the third and fourth quarters of 2020, Mainline System volumes began to recover as fourth quarter volumes increased by approximately 200 thousand barrels per day (kbpd) when compared with significantly reduced volumes in the second quarter of 2020. Year-over-year, Mainline System throughput only decreased by approximately 80 kbpd. We anticipate a return to full utilization in 2021 as economic activity gradually resumes in North America. This view is supported by our expectation that the refineries operating in our core Mainline System markets (i.e. the US Midwest, Eastern Canada and the US Gulf Coast) will continue to experience higher utilization rates given their scale, complexity and cost competitiveness. For every 100 kbpd increase or decrease in volumes on our Mainline System, our revenues, net of power and NGLssavings, are expected to generate a margin, which is typically a small fraction of gross revenue. While sales revenue generated from these operations are impactedincrease or decline by commodity prices, net margins and earnings are relatively insensitiveapproximately $35 million per quarter.
In our US Midstream business, our equity affiliate DCP Midstream, LP, responded to commodity prices and reflect activity levels which are driven by differencesthe drastic decline in commodity prices between locations, gradesby decreasing their distributions to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby modestly reducing our cash flows. As a further outcome of the drastic commodity price decline, we recorded a $1.7 billion impairment on our equity method investment in DCP Midstream in the first quarter of 2020, based on the decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020.
In addition, these circumstances have led to the deterioration of the credit profiles of some of our customers and pointssuppliers. There have been no material defaults by customers or suppliers to date, however, we will continue to monitor this risk and take credit risk mitigating actions as appropriate.
The situation around the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices is evolving and our assessment of risks is included in Part I. Item 1A. Risk Factors.
While the length and depth of the current energy demand reduction and its impact is challenging to estimate at this time, rather thanwe have completed several actions to further strengthen our resiliency and position for the future, while assuring that the safety and reliability of our operations remains our first priority. We took actions to reduce operating costs by approximately $300 million in 2020, including reductions to employee, management and Board of Director compensation, a voluntary workforce reduction program, as well as supply chain savings. We have also executed approximately $400 million of asset sales and increased our available liquidity to approximately $13 billion. We experienced a natural slowing of 2020 capital spending in light of COVID-19 and the health and safety measures put into place by federal and regional governments. In addition, we believe that the following factors further demonstrate the resiliency of our low-risk business model:
•Our assets are highly contracted and commercially underpinned by long-term take-or-pay and cost-of-service agreements;
•Approximately 95% of our customer exposure is investment grade, investment grade equivalent or non-investment grade who have provided credit enhancements;
•The acquisition of Spectra Energy in 2017 provided us with greater diversification into natural gas with embedded low risk commercial structures. We currently have approximately 40 different sources of cash flows by geography and by different customer groups;
•A strong financial position with approximately $13 billion of net available liquidity which gives us the capacity to fund all of our capital projects and any debt maturities through 2021 without accessing the capital markets; and
•We limit the maximum cash flow loss that could arise from direct market price risks through a comprehensive long-term economic hedging program.
We will continue to actively monitor our business environment and may take further actions that we determine are in the best interests of Enbridge, our employees, customers, partners and stakeholders, or as required by federal, state or provincial authorities. At this time, given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current sustained low commodity price environment, the long term impact on absolute prices. Any residual commodity margin riskus is closely monitoreduncertain; however, it is possible that they continue to have an adverse impact on our business and managed. Revenues from theseresults of operations.
UNITED STATES LINE 3 REPLACEMENT PROGRAM UNDER CONSTRUCTION
The United States Line 3 Replacement Program (US L3R Program) is now under construction in Minnesota after receiving all necessary permits and approvals. The US L3R Program is a critical integrity project that will enhance the continued safe and reliable operations of our Mainline System well into the future, reflecting our long-standing commitment to protecting the environment.
dependFor further details refer to Growth Projects - Liquids Pipelines - United States Line 3 Replacement Program.
MAINLINE SYSTEM CONTRACTING
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on activity levels, which vary from year-to-year depending on marketour Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and commodity prices.tolls of each service, which would be offered in an open season following approval by the CER.
Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impactsOn February 24, 2020, the comparabilityCER issued a Notice of revenuesPublic Hearing which outlined the process for participation in the short-term,hearing and identified a list of issues for discussion in the proceeding. In March 2020, letters were filed with the CER by a group of potential intervenors that requested the CER delay setting hearing dates associated with our Mainline System contract filing. Subsequently, the CER issued a letter requesting comments on the potential delay of proceedings.
We filed our response with the CER on May 1, 2020, and on May 19, 2020, the CER announced that the regulatory process for our proposal to offer contracted transportation service on our Mainline System will proceed in a single phase hearing process that balances the need to address COVID-19 pandemic related challenges and the CER's mandate to adjudicate in an appropriately expeditious manner.
We are currently in the midst of the regulatory process and expect an oral hearing to occur sometime after April 2021, but a hearing date has not yet been set. If a replacement agreement is not in place by June 30, 2021, the Competitive Tolling Settlement provides for tolls to continue on an interim basis.
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Texas Eastern
On February 25, 2020, Texas Eastern Transmission, L.P. (Texas Eastern) received approval from the Federal Energy Regulatory Commission (FERC) of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020.
Algonquin
On July 2, 2020, Algonquin Gas Transmission, LLC (Algonquin) received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020.
BC Pipeline
In July 2020, the 2020-2021 rate settlement agreement with Westcoast Energy Inc.’s (Westcoast) British Columbia (BC) Pipeline shippers was approved by the CER. Following approval of the settlement, Westcoast applied and received approval from the CER on August 12, 2020 for the interim tolls to be made final, including the interim tolls from January 1, 2020 to March 31, 2020 as well as the revised interim tolls in effect as at April 1, 2020.
East Tennessee
East Tennessee Natural Gas, LLC filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020.
Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we believe overwill await FERC approval.
Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the long-term,second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2020 Rate Application
Enbridge Gas's rate applications are filed in two phases. As part of an Ontario Energy Board (OEB) Decision and Order issued in December 2019, Phase 1 of the economic hedging program supports reliableapplication for 2020 rates, exclusive of funding for 2020 discrete incremental capital investments requested through the incremental capital module (ICM) mechanism, was approved effective January 1, 2020. Through a subsequent OEB Rate Order issued on June 11, 2020, Phase 2 of the application for 2020 rates, inclusive of requested 2020 ICM amounts, was approved effective October 1, 2020, and interim rates in effect from January 1, 2020 through September 30, 2020 were made final. The 2020 rate application, which represented the second year of a five-year term, was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism.
2021 Rate Application
On June 30, 2020, Enbridge Gas filed Phase 1 of an application with the OEB for the setting of rates for 2021. The 2021 rate application was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap IR rate setting mechanism and represents the third year of a five-year term. On October 6, 2020, Enbridge Gas filed a Phase 1 Settlement Proposal and draft Interim Rate Orders with the OEB, which were approved, on an interim basis effective January 1, 2021, on November 6, 2020. Phase 2 of the application addressing 2021 ICM funding requirements was filed on October 15, 2020.
FINANCING UPDATE
On February 20, 2020, we raised US$750 million of two-year floating rate notes in the US debt capital markets and on April 1, 2020, Enbridge Gas completed a $1.2 billion dual tranche offering of 10-year and 30-year notes in the Canadian debt capital markets. On May 12, 2020, we raised $1.3 billion with a dual tranche offering of 5-year and 7-year notes in the Canadian debt capital markets. On July 8, 2020, we raised an additional US$1.0 billion of 60-year hybrid subordinated notes in the US debt capital markets. Through these capital market activities, we completed our 2020 debt funding plan and strengthened our financial position.
In February 2020, we closed three new non-revolving credit facilities totaling US$1.5 billion and on March 31, 2020, we established a new syndicated one-year revolving credit facility in the amount of $1.7 billion. On April 9, 2020, we increased the amount of our new revolving facility by an additional $1.3 billion, bringing the total amount to $3.0 billion, significantly enhancing our available liquidity.
In July 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2022, inclusive of a one-year term out provision.
On October 1, 2020, we completed a private placement of US$300 million 20-year senior notes for Texas Eastern and early redeemed US$300 million senior notes originally due December 2020.
On February 10, 2021, we entered into a three year, sustainability linked credit facility for $1.0 billion with a syndicate of lenders. As a result of the sustainability linked credit facility and other financing activities completed in 2020, our resilient cash flows and dividend growth.our current liquidity position, we concurrently cancelled a one year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.
DIVIDENDS
We have paid common share dividendsThese financing activities, in every year since we became a publicly traded company in 1953. In November 2017, we announced a 10% increase in our quarterly dividend to $0.671 per common share, or $2.684 annualized, effectivecombination with the dividend payable on March 1, 2018.asset monetization activities noted below, provide significant liquidity and we expect will enable us to fund our current portfolio of capital projects without requiring access to the capital markets through 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.
BUSINESS SEGMENTSASSET MONETIZATION
Effective December 31, 2017, we changed our segment-level profit measure to EBITDA from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment toOzark Gas Transmission and Midstream. The presentationOzark Gas Gathering
On April 1, 2020, we closed the sale of our Ozark assets for cash proceeds of approximately $63 million.
Montana-Alberta Tie Line
On May 1, 2020, we closed the sale of our Montana-Alberta Tie-Line (MATL) transmission assets for cash proceeds of approximately $189 million.
Éolien Maritime France SAS
On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) for initial proceeds in excess of $100 million. CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the prior years' tables has been revisedtransaction is subject to customary regulatory approvals and is expected to occur in orderthe first half of 2021. Refer to align withGrowth Projects - Commercially Secured Projects - Renewable Power Generation.
TEXAS EASTERN PIPELINE RETURN-TO-SERVICE
On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the current presentation.Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no reported injuries or damaged structures as a result of the rupture.
In 2020, we undertook a comprehensive integrity program to ensure continued safe and reliable service. During the program, we reduced operating pressure across the Texas Eastern system to enable necessary integrity work to be completed. In the fourth quarter of 2020, we lifted the pressure restrictions and returned the system to service. LIQUIDS PIPELINES
RESULTS OF OPERATIONS
| | | | | | | | | | | |
| Year ended December 31, |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars, except per share amounts) | | | |
Segment earnings before interest, income taxes and depreciation and amortization | | | |
Liquids Pipelines | 7,683 | | 7,681 | | 5,331 | |
Gas Transmission and Midstream | 1,087 | | 3,371 | | 2,334 | |
Gas Distribution and Storage | 1,748 | | 1,747 | | 1,711 | |
Renewable Power Generation | 523 | | 111 | | 369 | |
Energy Services | (236) | | 250 | | 482 | |
Eliminations and Other | (113) | | 429 | | (708) | |
Earnings before interest, income taxes and depreciation and amortization | 10,692 | | 13,589 | | 9,519 | |
Depreciation and amortization | (3,712) | | (3,391) | | (3,246) | |
Interest expense | (2,790) | | (2,663) | | (2,703) | |
Income tax expense | (774) | | (1,708) | | (237) | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | |
Preference share dividends | (380) | | (383) | | (367) | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | |
Earnings per common share | 1.48 | | 2.64 | | 1.46 | |
Diluted earnings per common share | 1.48 | | 2.63 | | 1.46 | |
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATIONATTRIBUTABLE TO COMMON SHAREHOLDERS
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Earnings before interest, income taxes and depreciation and amortization | 6,395 |
| 4,926 |
| 3,033 |
|
Year ended December 31, 20172020 compared with year ended December 31, 20162019
EBITDA for the year ended December 31, 2017 was positivelyEarnings Attributable to Common Shareholders were negatively impacted by $285 million of contributions from new assets following the completion of the Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA increased by $1,312 million$1.9 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
•a non-cash, unrealized derivative fair value gain of $875$856 million ($646 million after-tax) in 20172020, compared with $474 milliona gain of $1.6 billion ($1.2 billion after-tax) in 20162019, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;
the absence•a combined loss of $2.1 billion ($1.6 billion after-tax) related to our equity method investment in DCP Midstream, LLC (DCP Midstream) due to a loss of $1.7 billion ($1.3 billion after-tax) resulting from an impairment chargeto the carrying value of $1,004our investment and a loss of $324 million recorded($244 million after-tax) in 2016, including related project costs, on EEP's Sandpiper Project2020, compared with $86 million ($68 million after-tax) in 2019 resulting from further asset and goodwill impairment losses within DCP Midstream;
•a combined loss of $615 million ($452 million after-tax) in 2020 resulting from impairments to the carrying value of our equity method investments in Southeast Supply Header (SESH) and Steckman Ridge, LP (Steckman Ridge);
•a loss of $159 million ($119 million after-tax) in 2020 resulting from the withdrawalFebruary 2020 Texas Eastern rate settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; and
•employee severance, transition and transformation costs of the regulatory applications$339 million ($256 million after-tax) in September 2016 that2020, compared with $135 million ($123 million after-tax) in 2019.
The factors above were pending with the MNPUC;
the absence of an impairment charge of $373 million recorded in 2016 related to the Northern Gateway Project due to our conclusion that the project could not proceed as envisioned as a result of the Federal Government's decision to dismiss the application for Certificate of Public Convenience and Necessity;
the absence of an impairment charge of $184 million recorded in 2016 related to our 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility;
a gain of $72 million on sale of pipe partially offset by project wind-down costs related to EEP’s Sandpiper Project; partially offset by
the absence of a gain of $850 million recorded in 2016 related to the sale of non-core South Prairie Region assets.
After taking into consideration the factors above, the remaining $128 million decrease is primarily explained by the following significant business factors:
a lower contribution of $46 million from Mid-Continent assets primarily due to lower contracted storage revenues and the sale2020 of the Ozark Pipeline systemfollowing:
•a loss of $467 million after-tax attributable to us ($268 million loss on sale and $199 million tax expense) in the first quarter of 2017;
a lower contribution of $76 million2019 resulting from the sale of the South Prairie Region assets in December 2016;federally regulated portion of our Canadian natural gas gathering and processing businesses;
higher Lakehead System operating costs including costs to implement EEP’s signed settlement agreement regarding the Lines 6A and 6B crude oil releases (the Consent Decree) approved by the United States Department of Justice (DOJ) in May 2017;
the unfavorable effect of translating United States dollar EBITDA at •a lower United States to Canadian dollar average exchange rate (Average Exchange Rate) as compared with 2016, inclusive of the impact of settlements under our foreign exchange hedging program; partially offset by
contributions of from new assets placed into service including the Regional Oil Sands Optimization Project and the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System that went into service in June 2017; and
higher Canadian Mainline and Lakehead System throughput period over period resulting from capacity optimization initiatives.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $1,177 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a non-cash, unrealized gain of $474 million in 2016 compared with an unrealized loss of $1,500$310 million ($229 million after-tax) in 2015 reflecting net fair value gains and losses on derivative financial instruments used to manage foreign exchange and commodity price risks;
a gain of $850 million in 2016 related to the sale of non-core South Prairie Region assets;
the absence of an impairment charge of $86 million recorded in 2015 related to EEP's Berthold rail facility due to contracts that were not renewed beyond 2016;
hydrostatic testing recoveries of $15 million in 2016 compared with charges of $72 million in 2015; partially offset by
an impairment charge of $1,004 million in 2016, including related project costs, on EEP's Sandpiper Project2019 resulting from the withdrawal of the regulatory applications in September 2016 that were pending with the MNPUC;
an impairment charge of $373 million in 2016 related to the Northern Gateway Project due to our conclusion that the project could not proceed as envisioned as a result of the Federal Government's decision to dismiss the application for Certificate of Public Convenience and Necessity;
an impairment charge of $184 million in 2016 related to our 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility; and
the absence of a gain of $91 million recorded in 2015 related to the sale of non-core assets.
After taking into consideration the factors above, the remaining $716 million increase is primarily explained by the following significant business factors:
higher throughput period over period resulting from strong oil sands production in western Canada enabled by pipeline capacity expansion projects placed into service in 2015;
increased transportation revenues in 2016 resulting from an increase in the level of committed take-or-pay volumes on Flanagan South;
the favorable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016, inclusive of the impact of settlements under our foreign exchange hedging program; partially offset by
the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which led to a temporary shutdown of certainreview of our upstream pipelinescomprehensive long-term economic hedging program and terminal facilities resulting in a disruption of service.
Supplemental information on Liquids Pipelines EBITDA for the years ended December 31, 2017, 2016 and 2015 is provided below.
|
| | | | | | | | | |
December 31, | 2017 |
| 2016 |
| 2015 |
|
(United States dollars per barrel) | |
| |
| |
IJT Benchmark Toll1 |
| $4.07 |
|
| $4.05 |
|
| $4.07 |
|
Lakehead System Local Toll2 |
| $2.43 |
|
| $2.58 |
|
| $2.44 |
|
Canadian Mainline IJT Residual Benchmark Toll3 |
| $1.64 |
|
| $1.47 |
|
| $1.63 |
|
| |
1 | The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2015, this toll increased from US$4.02 to US$4.07. Effective July 1, 2016, this toll decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07. |
| |
2 | The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39 and effective July 1, 2015, this toll increased to US$2.44. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US$2.58. Effective April 1, 2017, this toll decreased to US$2.43. |
| |
3 | The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective April 1, 2015, this toll increased from US$1.53 to US$1.63. Effective April 1, 2016, this toll decreased to US$1.46, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1, 2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll increased to US$1.64. |
Throughput Volume
|
| | | | | | | | | | |
| Q1 |
| Q2 |
| Q3 |
| Q4 |
| Full Year |
|
(thousands of barrels per day (bpd)) | |
| |
| |
| |
| |
|
Canadian Mainline1 | | | | | |
2017 | 2,593 |
| 2,449 |
| 2,492 |
| 2,586 |
| 2,530 |
|
2016 | 2,543 |
| 2,242 |
| 2,353 |
| 2,481 |
| 2,405 |
|
2015 | 2,210 |
| 2,073 |
| 2,212 |
| 2,243 |
| 2,185 |
|
| | | | | |
Lakehead System2 | | | | | |
2017 | 2,748 |
| 2,604 |
| 2,620 |
| 2,724 |
| 2,673 |
|
2016 | 2,735 |
| 2,440 |
| 2,495 |
| 2,624 |
| 2,574 |
|
2015 | 2,330 |
| 2,208 |
| 2,338 |
| 2,388 |
| 2,315 |
|
| |
1 | Average throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada. |
| |
2 | Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada. |
Average Exchange Rate
|
| | | | | | | | | | |
| Q1 |
| Q2 |
| Q3 |
| Q4 |
| Full Year |
|
(United States dollar to Canadian dollar) | |
| |
| |
| |
| |
|
2017 | 1.32 |
| 1.34 |
| 1.25 |
| 1.27 |
| 1.30 |
|
2016 | 1.37 |
| 1.29 |
| 1.31 |
| 1.33 |
| 1.32 |
|
2015 | 1.24 |
| 1.23 |
| 1.31 |
| 1.34 |
| 1.28 |
|
GAS TRANSMISSION AND MIDSTREAM
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Earnings/(loss) before interest, income taxes and depreciation and amortization | (1,269 | ) | 464 |
| 43 |
|
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $2,557 million of contributions from new assets following the completion of the Merger Transaction. When compared to pre-merger results from the prior year, operating results from the new assets include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $4,287 million duepayment to certain unusual, infrequent or other market factors primarily explained byhedge counterparties to pre-settle and reset the following:hedge rate on a portion of our hedging program;
•a loss of $4,391$297 million and related goodwill impairment of $102($218 million after-tax) in 2019 resulting from the classification of certain United States Midstreamour MATL assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell, refersell; and
•a loss of $105 million ($79 million after-tax) in 2019 resulting from the write-off of project costs related to Item 8. Financial Statements and Supplementary Data - Note 7. Acquisitions and Dispositions; partially offset by
the Access Northeast pipeline project.a
The non-cash, unrealized loss of $1 million in 2017 compared with $139 million in 2016 reflecting netderivative fair value gains and losses arising from the change in the mark-to-marketdiscussed above generally arise as a result of derivative financial instruments useda comprehensive long-term economic hedging program to managemitigate interest rate, foreign exchange and commodity price risk.risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.
After taking into consideration the factors above, the remaining $3$447 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
lower•decreased earnings from our Energy Services segment due to the significant compression of $127 million period over periodlocation and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities where we hold capacity obligations;
•decreased contributions from our Liquids Pipelines segment due to lower commodity prices which impacted production volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products primarily during the second and third quarters of 2020;
•the absence of earnings in areas served by some2020 from the federally-regulated portion of our US Midstream assets;Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
•decreased earnings from our Gas Distribution and Storage segment due to warmer weather experienced in our franchise areas; and
•higher depreciation and amortization expense, in addition to reduced capitalized interest, as a result of new assets placed into service throughout 2019 and 2020, primarily the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program).
The business factors above were partially offset by the following positive factors:
increased earnings of $19 million period over period•stronger contributions from our Alliance joint venture due to favorable seasonal firm revenues that resulted from wider basis differentials;
increased earnings of $16 millionLiquids Pipelines segment due to a full year of contributions from the Tupper Plants that were acquired in April 2016;higher International Joint Tariff (IJT) Benchmark Toll;
•increased fractionation margins of $45 million period over period driven by higher NGL prices and increased demandearnings from our Aux Sable joint venture;Gas Transmission and Midstream segment due to increased rates on Texas Eastern and Algonquin resulting from 2020 rate settlements;
•increased earnings of $41 million period over period from our Offshore assets driven byGas Distribution and Storage segment due to higher volumesdistribution charges resulting from increases in rates and highercustomer base;
•increased earnings from certain joint venture pipelines.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $370 million due to certain unusual, infrequent or other market factors primarily explained by the following:
the absence of a goodwill impairment charge of $440 million recorded in 2015 related to our United States natural gasnew Liquids Pipelines, Gas Transmission and NGL businesses due to a prolonged decline in commodity prices which reduced producers' expected drilling programsMidstream, and negatively impacted volumes on our natural gas and NGL systems; partially offset by
a non-cash, unrealized loss of $139 million in 2016 compared with $77 million in 2015 reflecting net fair value gains and losses arising from the change in the mark-to-market of derivative financial instruments used to manage foreign exchange and commodity price risk.
After taking into consideration the factors above, the remaining $51 million increase is primarily explained by the following significant business factors:
operational efficiencies achieved in 2016 on Alliance Pipeline due to lower operating costs;
contributions from the Heidelberg Pipeline which wasRenewable Power Generation assets that were placed into service throughout 2019 and 2020; and
•lower operating and administrative costs in January 2016;2020 as a result of cost containment actions.
contributions from the Tupper Plants acquired in April 2016; partially offset by
unfavorable market conditions in 2016 resulting from lower volumes due to reduced drilling by producers on our United States Midstream assets.
GAS DISTRIBUTION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Earnings before interest, income taxes and depreciation and amortization | 1,390 |
| 831 |
| 763 |
|
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA for the year ended December 31, 2017 was positively impacted by $545 million of contributions from Union Gas following the completion of the Merger Transaction. When compared to pre-merger results from prior years, Union Gas' operating results benefited mainly from higher transportation revenue from the Dawn-Parkway expansion projects, increased storage optimization and increases in delivery rates, partially offset by higher operating costs.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA increased by $14 million due to certain unusual, infrequent and other business factors, primarily explained by the following:
a non-cash, unrealized gain of $16 million in 2017 compared with an unrealized loss of $6 million in 2016 arising from the change in the mark-to-market value of Noverco Inc.'s (Noverco) derivative financial instruments;
warmer than normal weather experienced during 2017 which negatively impacted EBITDA by $15 million compared with $18 million in 2016; partially offset by
the absence of other regulatory adjustments at Noverco of $17 million recorded in 2016.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $11 million due to certain unusual, infrequent and other market factors, primarily explained by the following:
warmer than normal weather experienced during 2016 which negatively impacted EBITDA by $18 million compared with colder than normal weather during 2015 of $15 million; partially offset by
other regulatory adjustments at Noverco of $17 million recorded in 2016 compared with $6 million in 2015.
After taking into consideration the factors above, the remaining $79 million increase is primarily explained by the following significant business factor:
higher distribution charges arising from growth in rate base, including customer growth in excess of expectations embedded in rates.
GREEN POWER AND TRANSMISSION
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Earnings before interest, income taxes and depreciation and amortization | 372 |
| 344 |
| 363 |
|
Year ended December 31, 2017 compared with year ended December 31, 2016
EBITDA increased by $4 million due to certain unusual, infrequent and other factors, primarily explained by the following:
the absence of an investment impairment loss of $13 million recorded in 2016; partially offset by
a $9 million loss that resulted from the sale of an investment.
After taking into consideration the factors above, the remaining $24 million increase is primarily explained by the following significant business factors:
stronger wind resources of $12 million at Canadian and United States wind farms period over period; and
contributions of $9 million from new United States wind projects placed into service in 2016 and 2017.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $13 million due to an unusual and infrequent investment impairment loss in 2016.
After taking into consideration the factor above, the remaining $6 million decrease is primarily explained by the following significant business factors:
disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016 due to weather conditions which caused a higher degree of icing on wind turbine blades;
weaker wind resources experienced at certain facilities in Canada period over period; partially offset by
stronger wind resources at United States wind farms during the second half of 2016.
ENERGY SERVICES
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATIONThe Energy Services businesses in Canada and the US provide physical commodity marketing and logistical services to North American refiners, producers, and other customers.
Energy Services is primarily focused on servicing customers across the value chain and capturing value from quality, time, and location price differentials when opportunities arise. To execute these strategies, Energy Services transports and stores on both Enbridge-owned and third party assets using a combination of contracted long-term and short-term pipeline, storage tank, railcar, and truck capacity agreements.
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Earnings/(loss) before interest, income taxes and depreciation and amortization | (263 | ) | (183 | ) | 324 |
|
COMPETITION
Energy Services’ earnings are primarily generated from arbitrage opportunities which, by their nature, can be replicated by competitors. An increase in market participants entering into similar arbitrage strategies could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the marketing business by transacting at the majority of major hubs in North America and establishing long-term relationships with clients and pipelines.
ELIMINATIONS AND OTHER
Eliminations and Other includes operating and administrative costs that are not allocated to business segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes new business development activities and corporate investments.
OPERATIONAL, ENVIRONMENTAL AND ECONOMIC REGULATION
LIQUIDS PIPELINES
Operational Regulation
We are subject to numerous operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.
In the US, our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the of the United States Department of Transportation (DOT). These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These laws and regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines and to operate them at permissible pressures.
PHMSA has revised existing regulations and promulgated new regulations establishing safety standards that are designed to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failure or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, earnings, cash flows and financial condition.
In Canada, our pipeline operations are subject to pipeline safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.
As in the US, several legislative changes addressing pipeline safety in Canada have recently been enacted. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the CER to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.
A key component of Liquids Pipelines safety and reliability is the approach to integrity management that uses reliability targets and safety case assessments. A long history of extensive inline inspection has provided detailed knowledge of the assets in the liquids pipeline system. Every segment of every pipeline is assessed and maintained, in a proactive manner, such that the probability of a leak is sufficiently low and that stringent reliability targets are met. Furthermore, the integrity management program has an independent step to check the results of our integrity assessments to validate the effectiveness of the program and to ensure that that the operational risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle. As inspection technology, pipeline materials and construction practices improve with time, and new data on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves; with a strong focus on continual improvement in every aspect of integrity management.
Environmental Regulation
We are also subject to numerous federal, state and provincial environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits and other approvals.
In particular, in the US, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs may significantly increase our operating costs compared to historical levels.
In the US, climate change action is evolving at federal, state and regional levels. The Supreme Court decision in Massachusetts v. Environmental Protection Agency in 2007 established that GHG emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs. The new US presidential administration has also announced that policies designed to combat climate change and reduce GHG emissions will be a key legislative and regulatory priority, and thus stricter emissions limits and air quality enforcement actions are possible In addition, a number of states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.
For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the US. In 2019, the Government of Canada implemented a federal system of carbon pricing. The pricing applies to provinces and territories that do not have a carbon pricing system in place that meets the federal benchmark. On November 19, 2020, the federal Minister of Environment and Climate Change introduced Bill C-12, the Canadian Net-Zero Emissions Accountability Act, which requires national targets for the reduction of GHG emissions in Canada be set, with the objective of attaining net-zero emissions by 2050. In December 2020, the Government of Canada announced plans to increase the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030.
Due to the speculative outlook regarding any US federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
Economic Regulation
Our liquids pipelines also face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements including permits and regulatory approvals for both new and existing projects, upon which future and current operations are dependent. Our Mainline System and other liquids pipelines are subject to the actions of various regulators, including the CER and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings.
GAS TRANSMISSION AND MIDSTREAM
Operational Regulation
The span of regulation risks that apply to the Liquids Pipelines business as described above under Liquids Pipelines also applies to the Gas Transmission and Midstream business. Most of our US gas transmission operations are regulated by the FERC. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services. The FERC also regulates the construction of US interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transmission of gas by intrastate pipelines.
Texas Eastern reached an agreement with its shippers and filed a Stipulation and Agreement with the FERC on October 28, 2019. On February 25, 2020, Texas Eastern received approval from the FERC of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020. On July 2, 2020, Algonquin received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020. East Tennessee filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020. The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we will await FERC approval. The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval. In July 2020, the 2020-2021 rate settlement agreement with Westcoast's BC Pipeline shippers was approved by the CER. Following approval of the settlement, Westcoast applied and received approval from the CER on August 12, 2020 for the interim tolls to be made final, including the interim tolls from January 1, 2020 to March 31, 2020 as well as the revised interim tolls in effect as at April 1, 2020.
Our operations are subject to the jurisdiction of the Environmental Protection Agency and various other federal, state and local environmental agencies. Our US interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the DOT concerning pipeline safety.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state regulation. DCP Midstream's interstate NGL transportation pipelines are subject to FERC regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline safety, including the CER, the Transportation Safety Board and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission operations are subject to regulation by the CER or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities and acquisitions. In addition, these assets are subject to GHG emissions regulations, including GHG emissions management and carbon pricing policies. Across Canada there are a variety of new and evolving initiatives in development at the federal and provincial levels aimed at reducing GHG emissions. The Government of Canada has finalized a federal plan to have carbon pricing in place in all Canadian jurisdictions.
GAS DISTRIBUTION AND STORAGE
Operational Regulation
Our gas distribution and storage utility operations are regulated by the OEB and the Québec Régie de l’énergie, among others. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or amounts that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year incentive regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).
We seek to mitigate operational regulation risk. We retain dedicated professional staff and maintain strong relationships with customers, intervenors and regulators. This strong regulatory relationship continued in 2020 following OEB Decisions and Ordersapproving Phase 2 of Enbridge Gas’ application for 2020 rates and Phase 1 of Enbridge Gas’ application for 2021 rates. The Phase 2 Decision and Order approved the recovery of requested 2020 discrete incremental capital investments through the incremental capital module, while the Phase 1 Decision and Order approved 2021 base rate escalation under the price cap mechanism.
Enbridge Gas has continued to develop opportunities to support a low carbon future in Ontario. In 2020, the OEB approved Enbridge Gas' application to implement a voluntary RNG pilot program, whereby customers can voluntarily contribute towards the incremental cost of low carbon RNG which would displace regular natural gas.The OEB also approved Enbridge Gas' pilot project to construct facilities that will allow regular natural gas to be blended with hydrogen gas, in an isolated portion of the existing distribution system, with the intent to gain insight into the use of hydrogen as a method for decarbonizing natural gas for the purpose of reducing GHG emissions.
Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which regulate the protection of the environment and the health and safety of workers. Environmental legislation primarily includes regulation of discharges to air, land and water; environmental assessment of natural gas infrastructure projects in Ontario; protection of species at risk and species at risk habitat; management and disposal of hazardous waste; the assessment and management of contaminated sites; and the reporting and reduction of GHG emissions.
Gas distribution system operation, as with any industrial operation, has the potential risk of abnormal or emergency conditions, or other unplanned events that could result in leaks or emissions in excess of permitted levels. These events could result in injuries to workers or the public, adverse impacts to the environment in which we operate, property damage or regulatory violations including orders and fines. We could also incur future liability for soil and groundwater contamination associated with past and present site activities.
In addition to gas distribution, we also operate storage facilities and a small amount of oil and brine production in southwestern Ontario. Environmental risk associated with these facilities is the potential for unplanned releases. In the event of a release, remediation of the affected area would be required. There would also be potential for fines, orders or charges under environmental legislation, and potential third-party liability claims by any affected landowners.
The gas distribution system and our other operations must maintain environmental approvals and permits from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/or audits. Annual reports, such as the Annual Written Summary Report are submitted to the Ontario Ministry of the Environment, Conservation and Parks (MECP) and other regulators to demonstrate we are in good standing with our Environmental Compliance Approvals. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation. As environmental requirements and regulations become more stringent, the cost to maintain compliance and the time required to obtain approvals has increased.
As with previous years, in 2020, we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada (ECCC), the Ontario MECP, and a number of voluntary reporting programs. In accordance with the provincial GHG regulations, stationary combustion and flaring emissions related to storage and transmission operations were verified in detail by a third-party accredited verifier with no material discrepancies found.
Enbridge Gas utilizes emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors will continually be updated in the system as required. Enbridge Gas continues to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.
In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an output-based pricing system (OBPS).
The federal carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural gas and is applicable to the majority of customers. Enbridge Gas is registered as a natural gas distributor with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge increases annually on April 1 of each year by 1.96 cents/m3, rising up to 9.79 cents/m3 in 2022. In December 2020, the federal government announced plans to increase the federal carbon price by $15 per year, rising to $170 per tonne of carbon dioxide equivalent in 2030. Enbridge Gas estimates that this will equate to a federal carbon charge on natural gas of approximately 33.31 cents/m3 in 2030.
The OBPS component came into effect on January 1, 2019. Under OBPS, a registered facility has a compliance obligation for the portion of their emissions that exceeds their annual facility emissions limit, which is calculated based on the sector specific output-based standard and annual production. Enbridge Gas is registered with ECCC as an emitter in the OBPS program and has an annual compliance obligation associated with the combustion and flaring emissions associated with its natural gas pipeline transmission system. As a registered facility under OBPS,Enbridge Gas submitted an annual report along with the required verification report from an accredited third-party verifier who found no material misstatements. Enbridge Gas is required to remit payment for facility emissions that exceed its annual facility emissions limit. Due to COVID-19, ECCC has delayed the payment deadline from December 15, 2020 to April 15, 2021, and therefore Enbridge Gas has deferred payment until the first half of 2021.
In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. The date of the transition has not yet been communicated. Enbridge Gas will continue to have a compliance obligation under either the OBPS or EPS program for its facility-related emissions, as well as the federal carbon charge for its customer-related emissions.
HUMAN CAPITAL RESOURCES
WORKFORCE SIZE AND COMPOSITION
As at December 31, 2020, we had approximately 11,200 regular employees, including 1,600 unionized employees across our North American operations. This total rises to more than 13,000 if including temporary employees and contractors. We have a strong preference for direct employment relationships but where we have collectively bargained for employees, we have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.
SAFETY
We believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on employee and contractor safety continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents. Refer also to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments- COVID-19 Pandemic, Reduced Crude Oil Demand and Commodity Prices.
DIVERSITY AND INCLUSION
To ensure our workforce is reflective of the communities where we operate, we have pursued efforts to increase the representation of women, ethnic and racial groups, people with disabilities and veterans. Our original ambitions were set and shared with employees in 2018 with progress toward achievement shared regularly through our Diversity Dashboard. While we have made strong progress, we are accelerating the pace of our program and we have plans in place to meet our objectives by 2025. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.
In early 2021, we added Inclusion to our core values of Safety, Integrity and Respect to demonstrate this commitment.
We are building an organization where people feel safe and welcome and have the opportunity to thrive and grow based on merit. As part of our evolving ESG strategy, we wanted to create a tighter link between our success and the workforce related ESG measures – including safety and diversity – that enable it. As a result, beginning in 2021, key metrics in these areas are embedded in our scorecards and directly impact compensation.
PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development because we recognize their success is our success. Every year, employees are provided a range of development opportunities through a variety of channels, including: educational reimbursement programs; developmental relationships with mentors; rotational assignments; and Enbridge University, which offers a large catalog of courses.
EXECUTIVE OFFICERS
The following table sets forth information regarding our executive officers:
| | | | | | | | |
Name | Age | Position |
Al Monaco | 61 | President & Chief Executive Officer |
Colin K. Gruending | 51 | Executive Vice President & Chief Financial Officer |
Robert R. Rooney | 64 | Executive Vice President & Chief Legal Officer |
William T. Yardley | 56 | Executive Vice President & President, Gas Transmission and Midstream |
Cynthia L. Hansen | 56 | Executive Vice President & President, Gas Distribution and Storage |
Byron C. Neiles | 55 | Executive Vice President, Corporate Services |
Vern D. Yu | 54 | Executive Vice President & President, Liquids Pipelines |
Matthew Akman | 53 | Senior Vice President, Strategy & Power |
Allen C. Capps | 50 | Senior Vice President, Corporate Development & Energy Services |
Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. Mr. Monaco is also a member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco served as President, Gas Pipelines, Green Energy and International with responsibility for the growth and operations of our gas pipelines, including the gas gathering and processing operations in the US, our Gulf Coast offshore assets and our investments in Alliance Pipeline, Vector and Aux Sable, as well as our International business development and investment activities and Renewable Power Generation.
Colin K. Gruending was appointed Executive Vice President and Chief Financial Officer of Enbridge on June 1, 2019. Previously, our Senior Vice President, Corporate Development and Investment Review, Mr. Gruending performed a number of progressively challenging executive roles such as Vice President Corporate Development and Planning and Vice President, Treasury and Tax while concurrently serving as Chief Financial Officer for Enbridge Income Fund and Enbridge Income Fund Holdings Inc. Prior to that, Mr. Gruending served as Corporate Controller and also led enterprise Investor Relations and Pension Investments.
Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Rooney leads our legal, ethics and compliance, security and aviation teams across the organization.
William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream on February 27, 2017. Mr. Yardley, based in Houston, was previously President of Spectra Energy Corp's. (Spectra Energy) US Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s US portfolio of assets.
Cynthia L. Hansen was appointed Executive Vice President and President, Gas Distribution and Storage, on June 1, 2019. Ms. Hansen is responsible for the overall leadership and operations of Enbridge Gas, following the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), as well as Gazifère. Previously, our Executive Vice President, Utilities and Power Operations, Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with other business unit leaders.
Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles has oversight of our Technology & Information Services, Human Resources, Real Estate, Safety & Reliability, Supply Chain Management, and Public Affairs, Communications & Sustainability. Mr. Neiles had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational Reliability and had been Senior Vice President of Major Projects since November 2011, after joining our Major Projects group in April 2008.
Vern D. Yu was appointed Executive Vice President and President, Liquids Pipelines on January 1, 2020. Previously, Mr. Yu served as President and Chief Operating Officer for Liquids Pipelines and prior to that served as Executive Vice President and Chief Development Officer. He had previously served as Senior Vice President, Corporate Planning and Chief Development Officer. Prior to joining Corporate Development, Mr. Yu served as Senior Vice President of Business and Market Development for Enbridge’s Liquids Pipelines division and previously has held a series of roles with increasing responsibility in our corporate and financial areas.
Matthew Akman is our Senior Vice President, Strategy and Power. He is responsible for the corporate strategic planning process and all renewable power operations and development globally. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations. Prior to joining Enbridge, Mr. Akman worked primarily in banking with a focus on institutional equity research.
Allen C. Capps is our Senior Vice President, Corporate Development and Energy Services. He is responsible for capital allocation, investment review, corporate business development and Energy Services. Prior to assuming his current role in June 2019, Mr. Capps served as our Senior Vice President and Chief Accounting Officer and before that Vice President and Controller of Spectra Energy.
ADDITIONAL INFORMATION
Additional information about us is available on our website at www.enbridge.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC). Reports, proxy statements and other information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov).
ENBRIDGE GAS INC.
Additional information about Enbridge Gas can be found in its annual information form, financial statements and management's discussion and analysis (MD&A) for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Enbridge Gas and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ENBRIDGE PIPELINES INC.
Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
WESTCOAST ENERGY INC.
Additional information about Westcoast can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2020, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.
ITEM 1A. RISK FACTORS
The following risk factors could materially and adversely affect our business, operations, financial results or market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood based on order of presentation or grouping under sub-captions. For ease of reference, the risk factors are presented under the following sub-captions: (1) Risks Related to Operational Disruption or Catastrophic Events; (2) Risks Related to our Business and Industry; and (3) Risks Related to Government Regulation and Legal Risks.
RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS
Pipeline operations involve numerous risks that may adversely affect our business and financial results.
Operation of complex pipeline systems, gathering, treating, storing and processing 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; which include, but are not limited to, physical risks related to climate change, such as, fires, earthquakes, hurricanes, floods, landslides, increased volatility in season temperatures, rising sea levels or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property and our assets, 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.
We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead System; in October 2018 at the BC Pipeline T-South system; and in January 2019, August 2019 and May 2020 at the Texas Eastern pipeline, and we cannot guarantee that we will not experience catastrophic events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events.
An environmental incident is an event that may cause harm or potential harm to the environment and could also lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts to us and could impact our ability to work with various stakeholders. 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.
A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption, curtailment of commodity supply, operational incident or other reasons could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders and our reputation. Service interruptions that impact our crude oil and natural gas transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements.
Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to populated areas and a major incident could result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, material repair costs or increased costs of operating and insuring our assets.
Cyber-attacks or security breaches could adversely affect our business, operations or financial results.
Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems, or the network or systems of our third-party vendors, could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we and some of our vendors collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders.
Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication, magnitude and frequency of cyber-attacks and data security breaches. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cyber-attacks. We have a cyber-security controls framework in place which has been derived from the National Institute of Standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a security operations center, which operates at all times to monitor, detect and investigate activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed.
During the normal course of business, we have experienced and expect to continue to experience attempts to gain unauthorized access to, or to compromise, our information systems or to disrupt our operations through cyber-attacks or security breaches, although none to our knowledge have had a material adverse effect on our business, operations or financial results. Despite our security measures, our information systems, or those of our vendors, may become the target of further cyber-attacks (including hacking, viruses or acts of terrorism) or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems, or those of our vendors, affect our ability to correctly record, process and report transactions or financial information, or result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences or other costs or be subject to increased regulation or litigation, all of which could materially adversely affect our reputation, business, operations or financial results.
Pandemics, epidemics or disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or disease outbreaks, in locations in which we operate or globally, could materially adversely affect our business, operations, financial results and forward-looking expectations. The COVID-19 pandemic has negatively impacted us in 2020 and the impacts are expected to continue for future periods, which we are unable to reasonably predict due to numerous uncertainties, including the duration and severity of the pandemic.
The World Health Organization declared COVID-19 to be a pandemic on March 11, 2020. In response to the rapid global spread of COVID-19, governments have enacted emergency measures to combat the spread of the virus. These measures include restrictions on business activity and travel, as well as requirements to isolate or quarantine, which could continue or expand. Certain of our operations and projects have been deemed essential services in critical infrastructure sectors and are currently exempt from certain business activity restrictions; however, there is no guarantee that this exemption will continue. These actions have interrupted business activities and supply chains; disrupted travel; contributed to significant volatility in the financial and commodity markets, resulting in lower interest rates; impacted social conditions; and adversely impacted national and international economic conditions, including commodity prices and demand for energy, as well as the labor market.
Given the ongoing and dynamic nature of the circumstances surrounding the COVID-19 pandemic, it is difficult to predict how significant the impact of this pandemic, including any responses to it, will be on North American or global economies or our business, or for how long disruptions are likely to continue. The extent of such impact will depend on future developments and factors outside of our control, which are highly uncertain, rapidly evolving and cannot be predicted, including new information which may emerge concerning the severity or duration of this pandemic (including regarding new COVID-19 strains) and actions taken by governments and others to contain or end the COVID-19 pandemic or its impact (including regarding the development and distribution of effective vaccines). Such developments, which have had or may have an adverse effect on our customers, suppliers, regulators, business, operations and financial results, include disruptions that, among other things:
•adversely impacted market fundamentals, such as commodity prices and supply and demand for energy, decreasing volumes transported on our systems, increasing our exposure to asset utilization risks and adversely affecting our results;
•adversely impacted our Liquids Pipelines investments;
•could prevent one or more of our secured capital projects from proceeding, and has delayed completion and increased anticipated costs of certain projects;
•adversely impacted the operations or financial position of our third-party suppliers, service providers or customers and increase our exposure to contract-related risks or customer credit risk;
•adversely impacted the global capital markets, which could adversely impact the ratings assigned to our securities or our credit facilities and/or impact our ability to access capital markets at effective rates;
•increased our risks associated with emergency measures taken (including remote working, distancing and additional personal protective equipment), including increased cyber security risks, increased costs and the potential for reduced availability or productivity of our employees or third-party contractors or service providers;
•adversely impacted our ability to accurately forecast assumptions used to evaluate expansion projects, acquisitions and divestitures on an ongoing basis;
•adversely impacted the carrying value of our equity method investment in DCP Midstream and could adversely impact the outcome of future asset impairment tests, indicating that the carrying value of such assets might be impaired;
•could adversely impact the execution of current and future trade policies between Canada and the US; and
•could result in future business interruption losses that our insurance coverage may not be sufficient to cover.
There can be no assurance that our strategies to address potential disruptions will mitigate these risks or the adverse impacts to our business, operations and financial results. Future adverse impacts to our business, operations and financial results may materialize that are not yet known. In addition, disruptions related to the COVID-19 pandemic have had, or could have, the effect of heightening many of the other risks described in this Item 1A. Risk Factors. The risk that is most significantly heightened by the COVID-19 pandemic is the impact of commodity price weakness and volatility on our Liquids Pipelines, Gas Transmission and Midstream and Energy Services businesses, as detailed in the risk factor “Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our results of operations” below. Even after the COVID-19 pandemic has subsided, we may continue to experience adverse impacts to our business as a result of its global impact, including any related recession, as well as lingering impacts on supply of, demand for and prices of crude oil, natural gas, natural gas liquids, LNG and renewable energy.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the US and Canada. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could adversely affect our business, operations or financial results.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.
With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas, which can adversely affect our revenues and earnings.
With respect to our Gas Distribution and Storage assets, customers are billed on a combination of both fixed charge and volumetric basis and our ability to collect their respective total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our Gas Distribution customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Our Gas Distribution business has deferral accounts approved by the OEB that provide regulatory protection against the margin impacts associated with declining annual average consumption due to efficiencies and customers’ conservation efforts. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our Gas Distribution business may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. Our Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial and industrial volumes.
With respect to our Renewable Power Generation assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity method investments, could reduce our earnings.
Generally accepted accounting principles in the United States of America (US GAAP) requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate non-cash charge to earnings.
Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results.
Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.
We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access markets currently served by our liquids pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. We also face competition from alternative gathering and storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.
Execution of our projects subjects us to various regulatory, operational and market risks that may affect our financial results.
Our ability to successfully execute our projects is subject to various regulatory, operational and market risks, including:
•the ability to obtain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and to maintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
•potential changes in federal, state, provincial and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;
•impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•opposition to our projects by third parties, including interest groups;
•the availability of skilled labor, equipment and materials to complete projects;
•the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier non-performance, weather, geologic conditions or other factors beyond our control, that may be material;
•general economic factors that affect the demand for our projects; and
•the ability to raise financing for these projects.
Climate related risks are integrated into our larger risk categories that encompass operational, financial and stakeholder consequences. This is done because of the interconnected economic, social and environmental nature of climate impacts requires a comprehensive review within the context of other risks that impact us.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. Recent projects that have experienced delays include the US L3R Program, the Spruce Ridge Project and the T-South Reliability and Expansion Program. New projects may not achieve their expected investment return, which could affect our financial results, and hinder our ability to secure future projects. For additional discussion of specific proceedings that could affect our operations and financial results, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.
Changing expectations from stakeholders regarding ESG practices and climate change or erosion of stakeholder trust or confidence could influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, safety and stakeholder relations remain primary focus areas; changing expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous communities and other groups directly impacted by our activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors, investment funds and others which are increasingly focused on ESG practices. We have long been committed to strong ESG practices and performance, and in 2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include targets for GHG emissions reduction; adapting to the energy transition over time is one of our strategic priorities. Inadequately managing expectations and issues important to stakeholders, including those related to environment and climate change, could impact stakeholder trust and confidence and our reputation and have negative impacts on our business, operations or financial results, including:
•loss of business;
•loss of ability to secure growth opportunities;
•delays in project execution;
•legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin;
•increased regulatory oversight;
•loss of ability to obtain and maintain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms;
•impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•changing investor sentiment regarding investment in the oil and gas industry or our company;
•restricted access to and cost of capital; and
•loss of ability to hire and retain top talent.
We are also exposed to the risk of higher costs, delays, project cancellations, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators. Recent judicial decisions have increased the ability of groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we and others in the energy and pipeline businesses are facing organized opposition to oil and gas extraction and shipment of oil and gas products.
Our forecasted assumptions may not materialize as expected on our expansion projects, acquisitions and divestitures.
We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss of our profits.
Our insurance coverage may not be sufficient to cover our losses in the event of an accident, natural disaster or other hazardous event.
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards also can cause, and in some cases have caused, personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and certain of our affiliates to mitigate the financial impacts arising from these hazards. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry; however, insurance does not cover all events in all circumstances.
In the unlikely event that multiple insurable incidents that in the aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries. Additionally, even with insurance, if any natural disaster or other hazardous event leads to a catastrophic interruption in operations, we may not be able to restore operations without significant interruption.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. A significant amount of our credit exposures for transmission and storage services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. It is possible that customer payment defaults, if significant, could adversely affect our earnings and cash flows.
Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.
We use derivative financial instruments to manage the risks associated with movements in foreign exchange rates, interest rates, commodity prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.
Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
Our transformation projects may fail to fully deliver anticipated results.
We launched projects starting in 2016 to transform various processes, capabilities and reporting systems infrastructure to continuously improve effectiveness and efficiency across the organization and are subject to transformation project risk with respect to these projects. Such projects, some of which will continue into 2021 and 2022, including integration initiatives arising out of the merger with Spectra Energy and the amalgamation of EGD and Union Gas, are subject to transformation project risk. Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries do not fully deliver anticipated results due to insufficiently addressing the risks associated with project execution and change management. This could result in negative financial, operational and reputational impacts.
Weakness and volatility in commodity prices increase utilization risks with respect to our assets and has had and may have an adverse effect on our operational results.
The COVID-19 pandemic and concerns about global economic growth have caused considerable uncertainty in the market for crude oil, natural gas and other commodities, lowering demand forecasts. This, and the changing relationship dynamic among OPEC+ members, has put severe downward pressure on prices early in 2020. The economic climate in Canada, the US and abroad has deteriorated and worldwide demand for petroleum products has diminished. 2020 saw a dramatic decline in the price of crude oil, natural gas and NGL and other commodities whose prices are highly correlated to crude oil. The West Texas Intermediate benchmark prices for crude oil had been trading around US$60 per barrel in December 2019 and fell to as low as US$14 per barrel in March 2020 and into a negative value on April 20, 2020. Crude oil prices started to recover in the second and third quarters of 2020, with West Texas Intermediate benchmark prices reaching over US$40 primarily due to the announcement of crude oil productions cuts in April 2020 and June 2020. The West Texas Intermediate benchmark finished the year at US$48.35 per barrel.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk under the Competitive Tolling Settlement on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. The current commodity price environment has impacted both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines. This has led to a year-over-year reduction in Mainline System utilization of 80 kbpd in 2020.
While reduced demand has impacted throughput and revenue on the Mainline System, the financial impact of reduced throughput on our upstream regional pipelines and our downstream market extension pipelines is largely mitigated by the presence of take-or-pay contracts. The financial impact is also mitigated through cost-of-service arrangements with credit-worthy counterparties or parties that are not investment grade but have instead provided credit support in the form of letters of credit or other instruments. The existing market conditions are likely to stress the creditworthiness of many of these counterparties and we continue to evaluate the situation on an ongoing basis. To date, we have not had any counterparty default on its obligations to maintain credit support or pay its tolls under these contracts and, at this time, we do not foresee a material impact to our financial results.
Shippers also reduced investment in exploration and development programs in 2020. The decline in oil prices is also causing some sponsors of oil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin.
With respect to our Gas Transmission and Midstream assets, the low commodity prices have had limited impact on demand for natural gas shipped within our long-haul Gas Transmission assets in the US and Canada. These assets are comprised of primarily cost-of-service and take-or-pay contract arrangements which are not directly impacted by fluctuations in commodity prices.
Within our US Midstream assets, through our investment in DCP Midstream and, to a lesser extent, the Aux Sable liquids product plant, we are engaged in the businesses of gathering, treating and processing natural gas and natural gas liquids. Given the drastic decline in commodity prices, DCP Midstream made the decision to decrease its distribution to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby reducing our cash flows. Aux Sable results were also negatively impacted by these lower commodity prices.
With respect to our Energy Services business, we generate margins by capitalizing on quality, time and location differentials when opportunities arise. The recent volatility in commodity prices could limit margin opportunities and impede our ability to cover capacity commitments.
At this point, given the many outstanding questions as to the length and depth of the current low commodity price environment, the impact on us is uncertain; however, it is possible that it may have an adverse impact on our business and our results of operations.
Our Liquids Pipelines growth rate and results may be directly and indirectly affected by commodity prices and Government policy.
The efforts implemented in 2019 by the Alberta Government to manage supply and inventories in Western Canada continued at diminishing levels in 2020 as incremental take away capacity was introduced to the market. This intervention had a negligible impact on the Mainline System throughput, as enough inventory existed to meet refinery customer needs and service our favorable markets. Wide commodity price basis between Western Canada and global tidewater markets have negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.
The tight conventional oil plays of Western Canada and the Bakken region of North Dakota have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be well managed through active hedging programs and are positioned to react quickly at market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our pipeline systems.
Our Gas Transmission and Midstream results may be adversely affected by commodity price volatility and risks associated with our hedging activities.
Our exposure to commodity price volatility is inherent to our US Midstream business. We employ a disciplined hedging program to manage this direct commodity price risk. Because we are not fully hedged, we may be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of these commodities could adversely affect our financial results.
Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we likely will be prevented from realizing the full benefits of price increases above the level of the hedges. 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.
Our Energy Services results may be adversely affected by commodity price volatility.
Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Lower commodity prices due to changing market conditions could limit margin opportunities and impede Energy Services' ability to cover capacity commitments.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. An inability to access capital may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS
Many of our operations are regulated and failure to secure regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative impact on our business, operations or financial results.
The nature and degree of regulation and legislation affecting energy companies in Canada and the US have changed significantly in recent years.
In Canada, the passing of the Canadian Energy Regulator Act and the Impact Assessment Act under Bill C-69, which came into force on August 28, 2019, is expected to extend timelines associated with regulatory approvals for new projects which trigger a federal impact assessment. Changes to the British Columbia regulatory framework have also been made, including a new Environmental Assessment Act, which came into force in December 2019, affecting provincially-regulated projects in a similar manner as those that are federally-regulated. Within the US and in Canada, pipelines companies continue to face opposition from anti-pipeline activists, Indigenous and tribal communities, citizens, environmental groups and politicians concerned with either the safety of pipelines or environmental effects. In the US, several federal agencies made changes to regulations that were designed to streamline permitting, including changes that the Environmental Protection Agency made in June 2020 to regulations implementing Section 401 of the Clean Water Act and the July 2020 Council on Environmental Quality revisions to regulations implementing the National Environmental Policy Act. These and many other regulations adopted during the previous US presidential administration are not only being challenged in multiple courts, but have now been expressly targeted for rollback by the new US administration, which is expected to modify or reverse the regulations.
These actions could adversely impact permitting of a wide range of energy projects. We may not be able to obtain or maintain all required regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or if laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs.
Our operations are subject to numerous environmental laws and regulations, including those relating to climate change and GHG emissions, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.
Failure to comply with environmental laws and regulations and failure to secure permits necessary for our operations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations, including those related to climate change and GHG emissions, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities. Efforts to regulate or restrict GHG emissions could also drive down demand for the products we transport.
We may not be able to obtain or maintain all required environmental regulatory approvals and permits for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.
In November 2020, we set new ESG goals for the future, including with respect to GHG emissions reduction. Our ability to achieve these goals depends on many factors, including our ability to reduce emissions from our operations through modernization and innovation, reduce the emissions intensity of the electricity we buy, invest in renewables and low carbon energy and balance residual emissions through carbon offset credits. The cost associated with our GHG emissions reduction goals could be significant. Failure to achieve our emissions targets could result in reputational harm, changing investor sentiment regarding investment in Enbridge or a negative impact on access to and cost of capital.
Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase in operating and compliance costs. We do not own all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights could have an adverse effect on our reputation, operations and financial results. Scrutiny over the integrity of our assets and operations has the potential to increase operating costs or limit future projects. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.
Our operations are subject to economic regulation and failure to secure regulatory approval for our proposed or existing commercial arrangements could have a negative impact on our business, operations or financial results.
Our liquids pipelines face economic regulatory risk, the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements. We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of our liquids pipelines assets. However, there remains a risk that a regulator could modify significantly its own long-standing policies for rate making as well as overturn long-term agreements that we have entered into with shippers.
We could be subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation, including in particular the US with a new presidential administration and in Canada and other foreign jurisdictions in which we operate.
We are also subject to the examination of our tax returns and other tax matters by the US Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of legal proceedings.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are included in Item 1. Business.
In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private land-owners, First Nations, Native American Tribes, 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/or used by us under easements, licenses, leases 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, with the remainder used by us under easements, leases or permits.
Titles to our properties acquired in our liquids and 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. LEGAL PROCEEDINGS
We are involved in various legal and administrative proceedings and litigation arising in the ordinary course of business. The outcome of these matters is not predictable at this time. However, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial condition, results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at February 5, 2021, there were 2,025,495,603 holders of record of our common stock. A substantially greater number of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks, brokers and other financial institutions.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item will be contained in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2020.
Recent Sales of Unregistered Equity Securities
None.
Issuer Purchases of Equity Securities
None.
Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2016 through December 31, 2020 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the S&P/TSX Composite index, (3) the S&P 500 index, (4) our US peer group (comprising CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer group (comprising CU, FTS, IPL, PPL and TRP). The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
| | | | | | | | | | | | | | | | | | | | |
| January 1, 2016 | December 31, |
| 2016 | 2017 | 2018 | 2019 | 2020 |
Enbridge Inc. | 100.00 | | 127.97 | | 116.65 | | 107.20 | | 138.65 | | 117.59 | |
S&P/TSX Composite | 100.00 | | 121.08 | | 132.09 | | 120.36 | | 147.89 | | 156.17 | |
S&P 500 Index | 100.00 | | 111.96 | | 136.40 | | 130.42 | | 171.49 | | 203.04 | |
US Peers1 | 100.00 | | 133.50 | | 136.67 | | 131.82 | | 162.50 | | 137.15 | |
Canadian Peers | 100.00 | | 132.07 | | 140.85 | | 126.30 | | 164.43 | | 127.61 | |
1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is not necessarily indicative of results of future operations and should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data to fully understand factors that may affect the comparability of the information presented below.
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars, except per share amounts) | | | | | |
Consolidated Statements of Earnings | | | | | |
Operating revenues | $ | 39,087 | | $ | 50,069 | | $ | 46,378 | | $ | 44,378 | | $ | 34,560 | |
Operating income | 7,957 | | 8,260 | | 4,816 | | 1,571 | | 2,581 | |
Earnings | 3,416 | | 5,827 | | 3,333 | | 3,266 | | 2,309 | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | | (407) | | (240) | |
Earnings attributable to controlling interests | 3,363 | | 5,705 | | 2,882 | | 2,859 | | 2,069 | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | | 2,529 | | 1,776 | |
Common Share Data | | | | | |
Earnings per common share | | | | | |
Basic | 1.48 | | 2.64 | | 1.46 | | 1.66 | | 1.95 | |
Diluted | 1.48 | | 2.63 | | 1.46 | | 1.65 | | 1.93 | |
Dividends paid per common share | 3.24 | | 2.95 | | 2.68 | | 2.41 | | 2.12 | |
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | 2019 | 2018 | 2017 | 2016 |
(millions of Canadian dollars) | | | | | |
Consolidated Statements of Financial Position | | | | | |
Total assets | $ | 160,276 | | $ | 163,157 | | $ | 166,905 | | $ | 162,093 | | $ | 85,209 | |
Long-term debt | 62,819 | | 59,661 | | 60,327 | | 60,865 | | 36,494 | |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
This section of our Annual Report on Form 10-K discusses 2020 and 2019 items and year-over-year comparisons between 2020 and 2019. For discussion of 2018 items and year-over-year comparisons between 2019 and 2018, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2019.
RECENT DEVELOPMENTS
COVID-19 PANDEMIC, REDUCED CRUDE OIL DEMAND AND COMMODITY PRICES
The COVID-19 pandemic and the emergency response measures enacted by governments in Canada, the US and around the world, have caused material disruption to many businesses resulting in a severe slow down in Canadian, US and global economies, leading to increased volatility in financial and commodity markets worldwide and demand reduction for certain commodities.
We took proactive measures to deliver energy safely and reliably during the COVID-19 pandemic. We activated our crisis management team to focus on a number of priorities, including: (i) the health and safety of our employees and the public; (ii) operational reliability for our customers and markets; (iii) identification of essential personnel and procedures; and (iv) extensive stakeholder communication and outreach including updates to our Board of Directors. We are following recommendations from public health authorities and medical experts and have taken steps to help prevent our employees’ exposure to the spread of COVID-19, including, where practical, work-at-home plans enacted in March 2020 and the implementation of business continuity plans to enable the integrity of our operations and protect the health of our employees in pipeline control functions and service centers, our field representatives and other essential functions.
With respect to the safe operation of our facilities, we continue to employ all safety processes and procedures in the normal course. Our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need to heat their homes and fuel their lives.
The COVID-19 pandemic has had a deep impact in the communities in which we operate. We are providing support in our communities by advancing funds to respond and provide relief to those who are most vulnerable. Our teams in our operating regions are working closely with our nonprofit community partners, our closest Indigenous and Tribal neighbors and local governments to identify where resources are needed most.
The COVID-19 pandemic has negatively impacted crude oil demand and increased commodity price volatility, which together present potential new or elevated risks to our business. In late March, we began to see impacts both on the supply of, and demand for, crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our crude oil pipelines responded to significantly lower demand caused by the COVID-19 pandemic, declining storage availability and refinery utilization, and commodity price declines by reducing volumes beginning in the second quarter of 2020. In the third and fourth quarters of 2020, Mainline System volumes began to recover as fourth quarter volumes increased by approximately 200 thousand barrels per day (kbpd) when compared with significantly reduced volumes in the second quarter of 2020. Year-over-year, Mainline System throughput only decreased by approximately 80 kbpd. We anticipate a return to full utilization in 2021 as economic activity gradually resumes in North America. This view is supported by our expectation that the refineries operating in our core Mainline System markets (i.e. the US Midwest, Eastern Canada and the US Gulf Coast) will continue to experience higher utilization rates given their scale, complexity and cost competitiveness. For every 100 kbpd increase or decrease in volumes on our Mainline System, our revenues, net of power savings, are expected to increase or decline by approximately $35 million per quarter.
In our US Midstream business, our equity affiliate DCP Midstream, LP, responded to the drastic decline in commodity prices by decreasing their distributions to us by 50% (beginning with the first quarter distribution paid in May 2020), thereby modestly reducing our cash flows. As a further outcome of the drastic commodity price decline, we recorded a $1.7 billion impairment on our equity method investment in DCP Midstream in the first quarter of 2020, based on the decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020.
In addition, these circumstances have led to the deterioration of the credit profiles of some of our customers and suppliers. There have been no material defaults by customers or suppliers to date, however, we will continue to monitor this risk and take credit risk mitigating actions as appropriate.
The situation around the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices is evolving and our assessment of risks is included in Part I. Item 1A. Risk Factors.
While the length and depth of the current energy demand reduction and its impact is challenging to estimate at this time, we have completed several actions to further strengthen our resiliency and position for the future, while assuring that the safety and reliability of our operations remains our first priority. We took actions to reduce operating costs by approximately $300 million in 2020, including reductions to employee, management and Board of Director compensation, a voluntary workforce reduction program, as well as supply chain savings. We have also executed approximately $400 million of asset sales and increased our available liquidity to approximately $13 billion. We experienced a natural slowing of 2020 capital spending in light of COVID-19 and the health and safety measures put into place by federal and regional governments. In addition, we believe that the following factors further demonstrate the resiliency of our low-risk business model:
•Our assets are highly contracted and commercially underpinned by long-term take-or-pay and cost-of-service agreements;
•Approximately 95% of our customer exposure is investment grade, investment grade equivalent or non-investment grade who have provided credit enhancements;
•The acquisition of Spectra Energy in 2017 provided us with greater diversification into natural gas with embedded low risk commercial structures. We currently have approximately 40 different sources of cash flows by geography and by different customer groups;
•A strong financial position with approximately $13 billion of net available liquidity which gives us the capacity to fund all of our capital projects and any debt maturities through 2021 without accessing the capital markets; and
•We limit the maximum cash flow loss that could arise from direct market price risks through a comprehensive long-term economic hedging program.
We will continue to actively monitor our business environment and may take further actions that we determine are in the best interests of Enbridge, our employees, customers, partners and stakeholders, or as required by federal, state or provincial authorities. At this time, given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current sustained low commodity price environment, the long term impact on us is uncertain; however, it is possible that they continue to have an adverse impact on our business and results of operations.
UNITED STATES LINE 3 REPLACEMENT PROGRAM UNDER CONSTRUCTION
The United States Line 3 Replacement Program (US L3R Program) is now under construction in Minnesota after receiving all necessary permits and approvals. The US L3R Program is a critical integrity project that will enhance the continued safe and reliable operations of our Mainline System well into the future, reflecting our long-standing commitment to protecting the environment.
For further details refer to Growth Projects - Liquids Pipelines - United States Line 3 Replacement Program.
MAINLINE SYSTEM CONTRACTING
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and tolls of each service, which would be offered in an open season following approval by the CER.
On February 24, 2020, the CER issued a Notice of Public Hearing which outlined the process for participation in the hearing and identified a list of issues for discussion in the proceeding. In March 2020, letters were filed with the CER by a group of potential intervenors that requested the CER delay setting hearing dates associated with our Mainline System contract filing. Subsequently, the CER issued a letter requesting comments on the potential delay of proceedings.
We filed our response with the CER on May 1, 2020, and on May 19, 2020, the CER announced that the regulatory process for our proposal to offer contracted transportation service on our Mainline System will proceed in a single phase hearing process that balances the need to address COVID-19 pandemic related challenges and the CER's mandate to adjudicate in an appropriately expeditious manner.
We are currently in the midst of the regulatory process and expect an oral hearing to occur sometime after April 2021, but a hearing date has not yet been set. If a replacement agreement is not in place by June 30, 2021, the Competitive Tolling Settlement provides for tolls to continue on an interim basis.
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Texas Eastern
On February 25, 2020, Texas Eastern Transmission, L.P. (Texas Eastern) received approval from the Federal Energy Regulatory Commission (FERC) of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020.
Algonquin
On July 2, 2020, Algonquin Gas Transmission, LLC (Algonquin) received approval from the FERC of its uncontested rate case settlement with customers. In the third quarter of 2020, Algonquin recognized revenues from the settled rates retroactive to June 1, 2020, and put the settled rates into effect on September 1, 2020.
BC Pipeline
In July 2020, the 2020-2021 rate settlement agreement with Westcoast Energy Inc.’s (Westcoast) British Columbia (BC) Pipeline shippers was approved by the CER. Following approval of the settlement, Westcoast applied and received approval from the CER on August 12, 2020 for the interim tolls to be made final, including the interim tolls from January 1, 2020 to March 31, 2020 as well as the revised interim tolls in effect as at April 1, 2020.
East Tennessee
East Tennessee Natural Gas, LLC filed a rate case in the second quarter of 2020 and customer settlement discussions commenced in the fourth quarter of 2020.
Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in December 2020. A Stipulation and Agreement will be filed in February 2021 and we will await FERC approval.
Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement was reached in principle with shippers in January 2021. A Stipulation and Agreement will be filed in March 2021 and we will await FERC approval.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2020 Rate Application
Enbridge Gas's rate applications are filed in two phases. As part of an Ontario Energy Board (OEB) Decision and Order issued in December 2019, Phase 1 of the application for 2020 rates, exclusive of funding for 2020 discrete incremental capital investments requested through the incremental capital module (ICM) mechanism, was approved effective January 1, 2020. Through a subsequent OEB Rate Order issued on June 11, 2020, Phase 2 of the application for 2020 rates, inclusive of requested 2020 ICM amounts, was approved effective October 1, 2020, and interim rates in effect from January 1, 2020 through September 30, 2020 were made final. The 2020 rate application, which represented the second year of a five-year term, was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism.
2021 Rate Application
On June 30, 2020, Enbridge Gas filed Phase 1 of an application with the OEB for the setting of rates for 2021. The 2021 rate application was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap IR rate setting mechanism and represents the third year of a five-year term. On October 6, 2020, Enbridge Gas filed a Phase 1 Settlement Proposal and draft Interim Rate Orders with the OEB, which were approved, on an interim basis effective January 1, 2021, on November 6, 2020. Phase 2 of the application addressing 2021 ICM funding requirements was filed on October 15, 2020.
FINANCING UPDATE
On February 20, 2020, we raised US$750 million of two-year floating rate notes in the US debt capital markets and on April 1, 2020, Enbridge Gas completed a $1.2 billion dual tranche offering of 10-year and 30-year notes in the Canadian debt capital markets. On May 12, 2020, we raised $1.3 billion with a dual tranche offering of 5-year and 7-year notes in the Canadian debt capital markets. On July 8, 2020, we raised an additional US$1.0 billion of 60-year hybrid subordinated notes in the US debt capital markets. Through these capital market activities, we completed our 2020 debt funding plan and strengthened our financial position.
In February 2020, we closed three new non-revolving credit facilities totaling US$1.5 billion and on March 31, 2020, we established a new syndicated one-year revolving credit facility in the amount of $1.7 billion. On April 9, 2020, we increased the amount of our new revolving facility by an additional $1.3 billion, bringing the total amount to $3.0 billion, significantly enhancing our available liquidity.
In July 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2022, inclusive of a one-year term out provision.
On October 1, 2020, we completed a private placement of US$300 million 20-year senior notes for Texas Eastern and early redeemed US$300 million senior notes originally due December 2020.
On February 10, 2021, we entered into a three year, sustainability linked credit facility for $1.0 billion with a syndicate of lenders. As a result of the sustainability linked credit facility and other financing activities completed in 2020, our resilient cash flows and our current liquidity position, we concurrently cancelled a one year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.
These financing activities, in combination with the asset monetization activities noted below, provide significant liquidity and we expect will enable us to fund our current portfolio of capital projects without requiring access to the capital markets through 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.
ASSET MONETIZATION
Ozark Gas Transmission and Ozark Gas Gathering
On April 1, 2020, we closed the sale of our Ozark assets for cash proceeds of approximately $63 million.
Montana-Alberta Tie Line
On May 1, 2020, we closed the sale of our Montana-Alberta Tie-Line (MATL) transmission assets for cash proceeds of approximately $189 million.
Éolien Maritime France SAS
On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) for initial proceeds in excess of $100 million. CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the first half of 2021. Refer to Growth Projects - Commercially Secured Projects - Renewable Power Generation.
TEXAS EASTERN PIPELINE RETURN-TO-SERVICE
On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no reported injuries or damaged structures as a result of the rupture.
In 2020, we undertook a comprehensive integrity program to ensure continued safe and reliable service. During the program, we reduced operating pressure across the Texas Eastern system to enable necessary integrity work to be completed. In the fourth quarter of 2020, we lifted the pressure restrictions and returned the system to service.
RESULTS OF OPERATIONS
| | | | | | | | | | | |
| Year ended December 31, |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars, except per share amounts) | | | |
Segment earnings before interest, income taxes and depreciation and amortization | | | |
Liquids Pipelines | 7,683 | | 7,681 | | 5,331 | |
Gas Transmission and Midstream | 1,087 | | 3,371 | | 2,334 | |
Gas Distribution and Storage | 1,748 | | 1,747 | | 1,711 | |
Renewable Power Generation | 523 | | 111 | | 369 | |
Energy Services | (236) | | 250 | | 482 | |
Eliminations and Other | (113) | | 429 | | (708) | |
Earnings before interest, income taxes and depreciation and amortization | 10,692 | | 13,589 | | 9,519 | |
Depreciation and amortization | (3,712) | | (3,391) | | (3,246) | |
Interest expense | (2,790) | | (2,663) | | (2,703) | |
Income tax expense | (774) | | (1,708) | | (237) | |
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests | (53) | | (122) | | (451) | |
Preference share dividends | (380) | | (383) | | (367) | |
Earnings attributable to common shareholders | 2,983 | | 5,322 | | 2,515 | |
Earnings per common share | 1.48 | | 2.64 | | 1.46 | |
Diluted earnings per common share | 1.48 | | 2.63 | | 1.46 | |
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Year ended December 31, 2020 compared with year ended December 31, 2019
Earnings Attributable to Common Shareholders were negatively impacted by $1.9 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
•a non-cash, unrealized derivative fair value gain of $856 million ($646 million after-tax) in 2020, compared with a gain of $1.6 billion ($1.2 billion after-tax) in 2019, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;
•a combined loss of $2.1 billion ($1.6 billion after-tax) related to our equity method investment in DCP Midstream, LLC (DCP Midstream) due to a loss of $1.7 billion ($1.3 billion after-tax) resulting from an impairment to the carrying value of our investment and a loss of $324 million ($244 million after-tax) in 2020, compared with $86 million ($68 million after-tax) in 2019 resulting from further asset and goodwill impairment losses within DCP Midstream;
•a combined loss of $615 million ($452 million after-tax) in 2020 resulting from impairments to the carrying value of our equity method investments in Southeast Supply Header (SESH) and Steckman Ridge, LP (Steckman Ridge);
•a loss of $159 million ($119 million after-tax) in 2020 resulting from the February 2020 Texas Eastern rate settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; and
•employee severance, transition and transformation costs of $339 million ($256 million after-tax) in 2020, compared with $135 million ($123 million after-tax) in 2019.
The factors above were partially offset by the absence in 2020 of the following:
•a loss of $467 million after-tax attributable to us ($268 million loss on sale and $199 million tax expense) in 2019 resulting from the sale of the federally regulated portion of our Canadian natural gas gathering and processing businesses;
•a loss of $310 million ($229 million after-tax) in 2019 resulting from the review of our comprehensive long-term economic hedging program and a payment to certain hedge counterparties to pre-settle and reset the hedge rate on a portion of our hedging program;
•a loss of $297 million ($218 million after-tax) in 2019 resulting from the classification of our MATL assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell; and
•a loss of $105 million ($79 million after-tax) in 2019 resulting from the write-off of project costs related to the Access Northeast pipeline project.
The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.
After taking into consideration the factors above, the remaining $447 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
•decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities where we hold capacity obligations;
•decreased contributions from our Liquids Pipelines segment due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products primarily during the second and third quarters of 2020;
•the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
•decreased earnings from our Gas Distribution and Storage segment due to warmer weather experienced in our franchise areas; and
•higher depreciation and amortization expense, in addition to reduced capitalized interest, as a result of new assets placed into service throughout 2019 and 2020, primarily the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program).
The business factors above were partially offset by the following positive factors:
•stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark Toll;
•increased earnings from our Gas Transmission and Midstream segment due to increased rates on Texas Eastern and Algonquin resulting from 2020 rate settlements;
•increased earnings from our Gas Distribution and Storage segment due to higher distribution charges resulting from increases in rates and customer base;
•increased earnings from new Liquids Pipelines, Gas Transmission and Midstream, and Renewable Power Generation assets that were placed into service throughout 2019 and 2020; and
•lower operating and administrative costs in 2020 as a result of cost containment actions.
REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution sales and commodity sales.
Transportation and other services revenues of $16.2 billion, $16.6 billion and $14.4 billion for the years ended December 31, 2020, 2019 and 2018, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator, and in most cost-of-service based arrangements are reflective of our cost to provide the service plus a regulator-approved rate of return.
Gas distribution sales revenues of $3.7 billion, $4.2 billion and $4.4 billion for the years ended December 31, 2020, 2019 and 2018, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature.
Commodity sales of $19.3 billion, $29.3 billion and $27.7 billion for the years ended December 31, 2020, 2019 and 2018, respectively, were generated primarily through our Energy Services operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas, power and Natural Gas Liquids (NGLs) to generate a margin, which is typically a small fraction of gross revenue. While sales revenue generated from these operations are impacted by commodity prices, net margins and earnings are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.
Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but we believe over the long-term, the economic hedging program supports reliable cash flows.
BUSINESS SEGMENTS
LIQUIDS PIPELINES
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings before interest, income taxes and depreciation and amortization | 7,683 | | 7,681 | | 5,331 | |
Year ended December 31, 2020 compared with year ended December 31, 2019
EBITDA was negatively impacted by $139 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, unrealized gain of $545 million in 2020 compared with a gain of $976 million in 2019 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks. This negative factor was partially offset by the absence in 2020 of a loss of $310 million in 2019 resulting from the review of our comprehensive long-term economic hedging program and a payment to certain hedge counterparties to pre-settle and reset the hedge rate on a portion of our hedging program.
After taking into consideration the factors above, the remaining $141 million increase is primarily explained by the following significant business factors:
•contributions from the Canadian L3R Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of US$0.20 per barrel for the IJT Benchmark Toll;
•a higher average IJT Benchmark Toll on our Mainline System of US$4.24 in 2020 compared with US$4.18 in 2019; and
•higher Flanagan South Pipeline throughput and contribution.
The positive business factors above were partially offset by:
•lower Mainline System ex-Gretna throughput of 2,622 kbpd in 2020 compared with 2,705 kbpd in 2019 due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products primarily during the second and third quarters of 2020; and
•lower spot throughput on our Bakken Pipeline System and Seaway Crude Pipeline System driven by the significant impact of lower crude oil prices and the COVID-19 pandemic on supply and demand for crude oil and related products primarily during the second and third quarters of 2020.
GAS TRANSMISSION AND MIDSTREAM
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings before interest, income taxes and depreciation and amortization | 1,087 | | 3,371 | | 2,334 | |
Year ended December 31, 2020 compared with year ended December 31, 2019
EBITDA was negatively impacted by $2.3 billion due to certain unusual, infrequent or other non-operating factors primarily explained by the following:
•a combined loss of $2.1 billion related to our equity method investment in DCP Midstream due to a loss of $1.7 billion resulting from an impairment to the carrying value of our investment and a loss of $324 million in 2020, compared with $86 million in 2019 resulting from further asset and goodwill impairment losses within DCP Midstream;
•a combined loss of $615 million in 2020 resulting from impairments to the carrying value of our equity method investments in SESH and Steckman Ridge; and
•a loss of $159 million in 2020 resulting from the February 2020 Texas Eastern rate settlement that re-established the EDIT regulated liability that was previously eliminated in December 2018.
The factors above were partially offset by the following positive factors:
•the absence in 2020 of a loss of $268 million in 2019 resulting from the sale of the federally regulated portion of our Canadian natural gas gathering and processing businesses; and
•the absence in 2020 of a loss of $105 million in 2019 resulting from the write-off of project costs related to the Access Northeast Pipeline project.
After taking into consideration the factors above, the remaining $27 million increase is primarily explained by the following significant business factors:
•higher revenues from increased rates on Texas Eastern and Algonquin resulting from 2020 rate settlements; and
•contributions from the Stratton Ridge project and the second phase of the Atlantic Bridge project that were placed into service in the second and fourth quarters of 2019, respectively.
The positive business factors above were partially offset by:
•the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
•lower revenues on our US Gas Transmission assets due to pressure restrictions on Texas Eastern;
•narrowed AECO-Chicago basis at our Alliance Pipeline joint venture; and
•lower commodity prices impacting our Aux Sable joint venture.
GAS DISTRIBUTION AND STORAGE
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings before interest, income taxes and depreciation and amortization | 1,748 | | 1,747 | | 1,711 | |
Year ended December 31, 2020 compared with year ended December 31, 2019
EBITDA was positively impacted by $1 million primarily explained by the following significant business factors:
•higher distribution charges resulting from increases in rates and customer base; and
•synergy capture realized from the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas).
The positive business factors above were partially offset by the following factors:
•warmer weather experienced in our franchise service areas in 2020 when compared with the colder than normal weather experienced in 2019. When compared with the normal weather forecast embedded in rates, the warmer weather in 2020 negatively impacted 2020 EBITDA by approximately $33 million while the colder weather in 2019 positively impacted 2019 EBITDA by approximately $67 million; and
•the absence of earnings in 2020 from Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB) and St. Lawrence Gas Company, Inc. (St. Lawrence Gas) which were sold on October 1, 2019 and November 1, 2019, respectively.
RENEWABLE POWER GENERATION
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings before interest, income taxes and depreciation and amortization | 523 | | 111 | | 369 | |
Year ended December 31, 2020 compared with year ended December 31, 2019
EBITDA was positively impacted by $329 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the absence in 2020 of a loss of $297 million in 2019 resulting from the classification of our MATL assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell.
After taking into consideration the factors above, the remaining $83 million increase is primarily explained by the following significant business factors:
•contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019 and the Albatros expansion, which was placed into service in January 2020;
•stronger wind resources at Canadian and US wind facilities; and
•reimbursements received at certain Canadian wind facilities resulting from a change in operator.
ENERGY SERVICES
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings/(loss) before interest, income taxes and depreciation and amortization | (236) | | 250 | | 482 | |
EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.
Year ended December 31, 20172020 compared with year ended December 31, 20162019
EBITDA increasedwas negatively impacted by $2$98 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
•a non-cash, net positive adjustment to crude oil and natural gas inventories of $5 million in 2020 compared with a net positive adjustment of $91 million in 2019; and
•a non-cash, unrealized loss of $200$122 million in 20172020, compared with $205a loss of $110 million in 20162019, reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions, andas well as manage the exposure to movements in commodity prices.
After taking into consideration the factors above, the remaining $82$388 million decrease is primarily explained byreflects the following significant business factor:
weaker performance from Energy Services’ Canadian and United States operations due to the compression of certain crude oil and NGL location and quality differentials in 2017 which limitedcertain markets and fewer opportunities to generateachieve profitable margins.transportation margins on facilities in which Energy Services holds capacity obligations, partially offset by favorable storage opportunities.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA decreased by $477 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a non-cash, unrealized loss of $205 million in 2016 compared with an unrealized gain of $264 million in 2015 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices.
After taking into consideration the factor above, the remaining $30 million decrease is primarily explained by the following significant business factor:
weaker performance from Energy Services’ Canadian and United States operations due to the compression of certain crude oil and NGL location and quality differentials in 2016 which limited opportunities to generate profitable margins.
ELIMINATIONS AND OTHER
LOSS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION | | | | | | | | | | | |
| 2020 | 2019 | 2018 |
(millions of Canadian dollars) | | | |
Earnings/(loss) before interest, income taxes and depreciation and amortization | (113) | | 429 | | (708) | |
|
| | | | | | |
| 2017 |
| 2016 |
| 2015 |
|
(millions of Canadian dollars) | |
| |
| |
|
Loss before interest, income taxes and depreciation and amortization | (337 | ) | (101 | ) | (867 | ) |
Eliminations and Other includes operating and administrative costs which are not allocated to business segments and the impact of foreign exchange hedge settlements which are not allocated to business segments.settlements. Eliminations and Other also includes the impact of new business development activities generaland corporate investments and a portion of the synergies achieved thus far on integration of corporate functions in relation to the Merger Transaction.investments.
Year ended December 31, 20172020 compared with year ended December 31, 20162019
EBITDA decreasedwas negatively impacted by $315$678 million due to certain unusual, infrequent and otheror other-non-operating factors, primarily explained by the following:
project development and transaction costs of $197 million incurred in 2017 compared with $81 million in 2016 related to the Merger Transaction;
employee severance and restructuring costs of $292 million in 2017 compared with $92 million in
2016 related to a corporate reorganization initiative and the Merger Transaction; partially offset by
•a non-cash, unrealized intercompanygain of $318 million in 2020 compared with a gain of $671 million in 2019 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
•employee severance, transition and transformation costs of $279 million in 2020 compared with $84 million in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;
•a loss of $29$74 million in 2017 compared with2020 from non-cash changes in a corporate guarantee obligation; and
•a loss of $43 million in 2016 under our foreign exchange risk management program.2020 from the write-down of certain investments in emerging energy and other technologies.
After taking into consideration the factors above, the remaining $79$136 million increase is primarily explained by the following significant business factor:
lower operating and administrative costs in 2020 as a realized lossresult of $173 million in 2017 compared with $281 million in 2016 related to settlements under ourcost containment actions and lower realized foreign exchange risk management program.settlement losses.
Year ended December 31, 2016 compared with year ended December 31, 2015
EBITDA increased by $854 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized gain of $417 million in 2016 compared with an unrealized loss of $694 million in 2015 resulting from our foreign exchange hedging program; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $43 million in 2016 compared with a gain of $131 million in 2015;
project development and transaction costs of $81 million incurred in 2016 in relation to the Merger Transaction; and
employee severances costs of $92 million in 2016 compared with $47 million in 2015 related to a corporate reorganization initiative.
After taking into consideration the factors above, the remaining $88 million decrease is primarily explained by the following significant business factor:
a realized loss of $281 million in 2016 compared with $203 million in 2015 related to settlements under our foreign exchange risk management program.
GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
A key element of our corporate strategy is the successful execution of our growth capital program. In 2017, we successfully placed into service approximately $12 billion of growth projects across several business units and we expect to place a further $22 billion of commercially secured projects into service through 2020.
The following table summarizes the status of our commercially secured projects, organized by business segment:
| | | | | | | | | | | | | | | | | | | | |
| | Enbridge's Ownership Interest | Estimated Capital Cost1 | Expenditures to Date2 | Status | Expected In-Service Date |
(Canadian dollars, unless stated otherwise) | | | | |
LIQUIDS PIPELINES | | |
1. | Canadian Line 3 Replacement Program | 100 | % | $5.3 billion | $5.0 billion | Complete | In-service |
2. | United States Line 3 Replacement Program | 100 | % | US$4.0 billion | US$2.0 billion | Under construction | Q4 - 2021 |
3. | Southern Access Expansion3 | 100 | % | US$0.5 billion | US$0.5 billion | Under construction | Q4 - 2021 |
4. | Other - United States | 100 | % | US$0.1 billion | US$0.1 billion | Under construction | Q1 - 2021 |
GAS TRANSMISSION AND MIDSTREAM | | |
5. | T-South Reliability & Expansion Program | 100 | % | $1.0 billion | $0.7 billion | Under construction | Q4 - 2021 |
6. | Spruce Ridge Project4 | 100 | % | $0.5 billion | $0.2 billion | Under construction | Q4 - 2021 |
7. | Other - United States5 | Various | US$1.0 billion | US$0.5 billion | Various stages | 2020 - 2023 |
GAS DISTRIBUTION AND STORAGE | | |
8. | Windsor Line Replacement & Owen Sound Reinforcement | 100 | % | $0.2 billion | $0.1 billion | Various stages | In-service |
9. | London Line Replacement Project | 100 | % | $0.2 billion | No significant expenditures to date | Pre-construction | 2H - 2021 |
10. | Storage Enhancements | 100 | % | $0.1 billion | No significant expenditures to date | Pre-construction | 2021 - 2022 |
RENEWABLE POWER GENERATION | | |
11. | East-West Tie Line | 25.0 | % | $0.2 billion | $0.1 billion | Under construction | 1H - 2022 |
12. | Saint-Nazaire France Offshore Wind Project6 | 25.5 | % | $0.9 billion | $0.1 billion | Under construction | 2H - 2022 |
(€0.6 billion) | (€0.1 billion) |
13. | Fécamp Offshore Wind Project7 | 17.9 | % | $0.7 billion | $0.1 billion | Under construction | 2023 |
(€0.5 billion) | (€0.1 billion) |
| | | | | | |
| | | | | | |
|
1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
|
| | | | | | | | | | | | | |
| | | Enbridge's Ownership Interest |
| | Estimated Capital Cost1 | | Expenditures to Date2 | | Status | | Expected In-Service Date |
(Canadian dollars, unless stated otherwise) | | | | | | | | |
LIQUIDS PIPELINES | | | | | | | | | |
1 |
| | Norlite Pipeline System (the Fund Group) | 70 | % | | $1.3 billion | | $1.1 billion | | Complete | | In service |
|
| | | | | | | | | | |
2 |
| | Bakken Pipeline System (EEP)3 | 27.6 | % | | US$1.5 billion | | US$1.5 billion | | Complete | | In service |
|
| | | | | | | | | | |
3 |
| | Regional Oil Sands Optimization Project (the Fund Group) | 100 | % | | $2.6 billion | | $2.3 billion | | Complete | | In service |
| | | | | | | | | | |
|
| | | | | | | | | | |
4 |
| | Lakehead System Mainline Expansion - Line 61 (EEP)4 | 100 | % | | US$0.4 billion | | US$0.4 billion | | Substantially | | 2H - 2019 |
| | | | | | | | complete | | |
5 |
| | Canadian Line 3 Replacement | 100 | % | | $5.3 billion | | $2.3 billion | | Under | | 2H - 2019 |
|
| | Program (the Fund Group) | | | | | | | construction | | |
6 |
| | U.S. Line 3 Replacement Program (EEP)4 | 100 | % | | US$2.9 billion | | US$0.7 billion | | Under | | 2H - 2019 |
|
| | | | | | | | construction | | |
7 |
| | Other - Canada | 100 | % | | $0.2 billion | | $0.2 billion | | Various | | 2018 |
| | | | | | | | | stages | | |
GAS TRANSMISSION & MIDSTREAM | | | | | | | | |
8 |
| | Sabal Trail (SEP)5 | 50 | % | | US$1.6 billion | | US$1.5 billion | | Complete | | In service |
| | | | | | | | | | | |
9 |
| | Access South, Adair Southwest and Lebanon Extension (SEP)5 | 100 | % | | US$0.5 billion | | US$0.3 billion | | Complete | | In service |
| | | | | | | | | | |
| | | | | | | | | | |
10 |
| | Atlantic Bridge (SEP)5 | 100 | % | | US$0.5 billion | | US$0.3 billion | | Under | | Q4 - 2018 |
|
| | | | | | | | | construction | | |
11 |
| | NEXUS (SEP)5 | 50 | % | | US$1.3 billion | | US$0.6 billion | | Under | | Q3 - 2018 |
| | | | | | | | | construction | | |
12 |
| | Reliability and Maintainability Project5 | 100 | % | | $0.5 billion | | $0.4 billion | | Under | | Q3 - 2018 |
| | | | | | | | construction | | |
13 |
| | Valley Crossing Pipeline5 | 100 | % | | US$1.5 billion | | US$1.1 billion | | Under | | Q4 - 2018 |
| | | | | | | | | construction | | |
14 |
| | Spruce Ridge Program5 | 100 | % | | $0.5 billion | | $0.1 billion | | Pre- | | 2019 |
|
| | | | | | | | | construction | | |
15 |
| | T-South Expansion Program5 | 100 | % | | $1.0 billion | | No significant | | Pre- | | 2020 |
| | | | | | expenditures to date | | construction | | |
16 |
| | Other - United States5 | 100 | % | | US$1.9 billion | | US$1.0 billion | | Various | | 2017-2019 |
| | | | | | | | | stages | | |
17 |
| | Other - Canada5 | 100 | % | | $0.9 billion | | $0.7 billion | | Various | | 2017-2018 |
| | | | | | | | | stages | | |
GAS DISTRIBUTION | | | | | | | | | |
18 |
| | 2017 Dawn-Parkway Expansion5 | 100 | % | | $0.6 billion | | $0.6 billion | | Complete | | In service |
| | | | | | | | | | |
19 |
| | Panhandle Reinforcement Project5 | 100 | % | | $0.3 billion | | $0.2 billion | | Complete | | In service |
| | | | | | | | | | |
2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2020.
3 The status and in-service date will coincide with the status and in-service date of the US L3R Program.
4 Expenditures were revised in the second quarter of 2020 due to scope modifications. |
| | | | | | | | | | | | | |
GREEN POWER & TRANSMISSION | | | | | | | | |
20 |
| | Chapman Ranch Wind Project | 100 | % | | US$0.4 billion | | US$0.3 billion | | Complete | | In service |
| | | | | | | | | | |
21 |
| | Rampion Offshore Wind Project | 24.9 | % | | $0.8 billion | | $0.6 billion | | Under | | Q2 - 2018 |
|
| | | | (£0.37 billion) | | (£0.3 billion) | | construction | | |
22 |
| | Hohe See Offshore Wind Project and Expansion | 50 | % | | $2.1 billion | | $0.5 billion | | Pre- | | 2H - 2019 |
|
| | | | (€1.34 billion) | | (€0.4 billion) | | construction | | |
| |
1 | These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects. |
| |
2 | Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2017. |
| |
3 | On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0 billion (US$1.5 billion). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. |
| |
4 | The Lakehead System Mainline Expansion project is funded 75% by Enbridge and 25% by EEP, and the project will be operated by EEP on a cost-of-service basis. The U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP. |
| |
5 | Project acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy. |
5 Includes the US$0.1 billion Sabal Trail Phase II project placed into service in the second quarter of 2020 and the US$0.1 Atlantic Bridge Phase III project placed into service in January 2021.
6 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments which is expected to close in the first half of 2021. After closing, our equity contribution will be $0.15 billion, with the remainder of the project financed through non-recourse project level debt.
7 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments which is expected to close in the first half of 2021. After closing, our equity contribution will be $0.10 billion, with the remainder of the project financed through non-recourse project level debt.
Risks related to the development and completion of growth projects are described under Part I. Item 1A.Risk Factors.
LIQUIDS PIPELINES
The following commercially secured growth projects were placed into service in 2017:
Norlite Pipeline System (the Fund Group)- a diluent pipeline originating from our Stonefell Terminal and terminating at our Fort McMurray South facility, with a transfer line to Suncor's East Tank Farm. The project provides an initial capacity of approximately 218,000 bpd, with the potential to be further expanded to approximately 465,000 bpd with the addition of pump stations. The project was placed into commercial service on May 1, 2017.71
Bakken Pipeline System (EEP) -a pipeline system that transports crude oil from the Bakken formation in North Dakota to markets in eastern PADD II, and the United States Gulf Coast. The system's initial capacity is approximately 470,000 bpd of crude oil and has the potential to be expanded to 570,000 bpd. The system was placed into service on June 1, 2017.
Regional Oil Sands Optimization Project (the Fund Group)- the Athabasca Pipeline Twin portion of the project, which includes twinning of the southern section of the crude oil Athabasca Pipeline from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta provides an initial capacity of approximately 450,000 bpd, with the potential to be further expanded to approximately 800,000 bpd. This portion of the project was placed into service on January 1, 2017. The Wood Buffalo Extension portion of the project includes a crude oil pipeline expansion between Cheecham, Alberta and Kirby Lake, Alberta that provides an initial capacity of approximately 635,000 bpd, with the potential to be further expanded to approximately 800,000 bpd. This portion of the project was placed into service on December 1, 2017.
JACOS Hangingstone Project (the Fund Group) -a crude oil pipeline connecting the Japan Canada Oil Sands Limited (JACOS) Hangingstone project site to our existing Cheecham Terminal that provides an initial capacity of approximately 40,000 bpd. The project was placed into service on August 29, 2017.
The following commercially secured growth projects are expected to be placed into service in 2018 and 2019:2021:
Lakehead System Mainline Expansion (EEP) - the remaining scope of the project includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois that will increase capacity from 950,000 bpd to 1,200,000 bpd, which was substantially completed in June of 2017. We currently anticipate an in-service date in the second half of 2019 for this phase to more closely align
with the anticipated in-service date for the Line 3 Replacement Program (U.S. L3R Program). For additional updates on the project, refer to Growth Projects - Regulatory Matters.
Canadian Line 3 Replacement Program (the Fund Group)- replacement of the existing Line 3 crude oil pipeline between Hardisty, Alberta and Gretna, Manitoba. The L3R Program will not provide an increase in the overall capacity of the mainline system, but will restore approximately 370,000 bpd and supports the safety and operational reliability of the overall system, enhances flexibility and will allow us to optimize throughput from western Canada into Superior, Wisconsin. The L3R Program is expected to achieve the original capacity of approximately 760,000 bpd. Construction commenced in early August 2017. For additional updates on the project, refer to Growth Projects - Regulatory Matters.
•United States Line 3 Replacement Program (EEP) - replacement of the existing Line 3 crude oil pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S.US L3R Program along with the Canadian L3R Program discussed above, will support the safety and operational reliability of the mainline system,Mainline System, enhance system flexibility and allow the Company and EEPus to optimize throughput on the mainline. The US L3R Program is expected to achieverestore the original capacity of 760 kbpd and bring the total Mainline System capacity to approximately 760,000 bpd. Construction commenced on the3.2 million barrels per day (bpd). The Wisconsin portion of the U.S.US L3R Program is in late June 2017service. The Minnesota portion is now under construction after receiving all necessary permits and approvals. While complete, the North Dakota portion will be substantially completeplaced into service when Minnesota construction concludes.
Estimated capital costs for the Line 3 Replacement Program, including the Canadian segment already in February 2018. service, have been updated from $8.2 billion to $9.3 billion (in source currency). The increase in costs reflects winter construction, further enhancements to industry-leading environmental protections and construction techniques, the extended regulatory and permitting timeframe, higher capitalized interest and COVID-19 protocols.
Upon the Line 3 Replacement Program being placed fully into service a surcharge of US$0.895 per barrel will be applied, inclusive of the current interim US$0.20 surcharge for the Canadian portion of Line 3. In addition, incremental throughput related to the restored Line 3 capacity will receive an international joint toll charge for each barrel.
For additional regulatory updates on the project, refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program.
•Southern Access Expansion - an expansion of our existing Southern Access crude oil pipeline from 996 kbpd to approximately 1,200 kbpd.
GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects were placed into service in 2017:
Sabal Trail (SEP) - a natural gas pipeline connecting Alexander City, Alabama to the Central Florida Hub in Kissimmee, Florida that provides capacity of approximately 1.1 billion cubic feet per day (bcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are completed. Facilities include a new 749-kilometer (465-mile) pipeline, laterals and various compressor stations. The project was placed into service on July 3, 2017.
in 2020:
Access South, Adair Southwest•Sabal Trail Phase II -an expansion of our existing Sabal Trail pipeline through the addition of two new greenfield compressor stations in Albany, Georgia and Lebanon Extension (SEP) - natural gas pipeline extensions connecting the Appalachian region of the United States to markets in the Midwest and Southeast regions of the United States. The combined projects provide an initial capacity of 622 million cubic feet per day (mmcf/d) of gas to customers in Ohio, Kentucky and Mississippi. The Lebanon extension was placed into service early, on August 1, 2017 and the majority of the Access and Adair portions of the project were placed in service in November 2017 with the final 20 mmcf/d expected to be placed in service in the first quarter of 2018.
Dunnellon, Florida.
The following commercially secured growth projects are expected to be placed into service in 2018 to 2020:2021:
•Atlantic Bridge (SEP) Phase III - an expansion of SEP’sthe Algonquin Gas Transmissionnatural gas transmission systems to transport 133 mmcf/dmillion cubic feet per day (mmcf/d) of natural gas to the New England Region.region. The expansion primarily consiststhird and final phase of Atlantic Bridge fully commenced service in January 2021 with the replacement of a natural gas pipeline, meter station additions, compression additions in Connecticut, and a newWeymouth compressor station in Massachusetts. The Connecticut portion of the project was placed into service in the fourth quarter of 2017. The remainder of the project is expected to be in-service during the fourth quarter of 2018.
being brought online.
NEXUS (SEP)•T-South Reliability & Expansion Program - a natural gas pipeline system connecting SEP’s Texas Eastern pipeline systemexpansion of Westcoast's BC Pipeline in Ohio to the Union Gas Dawn hub in Ontario, via Vector Pipeline L.P.,southern BC that will provide capacity of up to approximately 1.5 bcf/d. The project received a Notice to Proceed from the Federal Energy Regulatory Commission (FERC) in August 2017improved compressor reliability and construction activities have commenced.
Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system. The project involves adding new compressor units at three compressor stations along the pipeline system as well as upgrading existing pipeline crossovers and adding new crossovers at key locations. During 2017, six crossovers were placed into service.
Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 bcf/d.
Spruce Ridge Program - natural gas pipeline expansion of Westcoast Energy Inc.’s British Columbia Pipeline in northern British Columbia, which consists of the Aitken Creek Looping project and the Spruce Ridge Expansion project. The combined projects will provide additional capacity of up to 402 mmcf/d.
T-South Expansion Program - natural gas pipeline expansion of Westcoast Energy Inc.’s T-South system that will provide additional capacity of approximately 190 mmcf/d into the Huntington/Sumas market at the United States/US/Canada border.The projects were approved by the CER in September 2019 and has phased in-service dates with final completion in the fourth quarter of 2021.
•Spruce Ridge Project - a natural gas pipeline expansion of Westcoast's BC Pipeline in northern BC. The project will provide additional capacity of up to 402 mmcf/d. Due to commercial delays, the revised expected in-service date is the fourth quarter of 2021.
GAS DISTRIBUTION AND STORAGE
In addition to normal course investment to support customer additions, the
The following commercially secured growth projects were placed into service in 2017:2020:
2017 Dawn-Parkway Expansion •Windsor Line Replacement & Owen Sound Reinforcement Projects - the expansionreplacement of approximately 64-kilometers of the existing Dawn-ParkwayWindsor Line with a new 6-inch natural gas pipeline system, which provides transportation service from Dawn toand the Greater Toronto Area,reinforcement of the Owen Sound System through the additionconstruction of new compressors at each34-kilometers of 12-inch natural gas pipeline in southwestern Ontario. Although the Dawn, Lobo and Bright compressor stations in Ontario. The project provides additional capacity of approximately 419 mmcf/d andWindsor Line Replacement was placed into service, there is continuing work on the west portion to be completed in October 2017.
2021.
Panhandle Reinforcement Project - the expansion of the existing Panhandle pipeline from Dawn to the Dover transmission station in Chatham-Kent, Ontario. The project serves firm demand growth in southwestern Ontario and was placed into service in November 2017.
GREEN POWER AND TRANSMISSION
The following commercially secured growth project wasis expected to be placed into service in 2017:2021:
Chapman Ranch Wind•London Line Replacement Project - a wind project that consistswill replace the two current pipelines known collectively as the London Line and includes the construction of 81 Acciona Windpower North America, LLC (Acciona) turbines locatedapproximately 90.5-kilometers of natural gas pipeline and ancillary facilities in Nueces County, Texas which generate approximately 249-MW of power and weresouthern Ontario.
The following commercially secured growth project is expected to be placed into service onin two phases, occurring in 2021 and 2022:
•Storage Enhancements - an enhancement of our unregulated storage facilities at Dawn, Ontario.
In October 25, 2017. Acciona provides turbine operations2020, due to changes in demand and maintenance services under a five-year fixed-price contractuncertainties resulting from the COVID-19 pandemic, Enbridge Gas withdrew the Dawn-Parkway Expansion leave to construct application with an optionthe OEB. Enbridge Gas will continue to extend. The project is backed by a 12-year power offtake agreement.assess demand requirements for the expansion and refile as needed in the future.
RENEWABLE POWER GENERATION
The following commercially secured growth projects are expected to be placed into service in 2018 and 2019:2022:
•East-West Tie Line - a transmission project that will parallel an existing double-circuit, 230 kilovolt transmission line that connects the Wawa Transformer Station to the Lakehead Transformer Station near Thunder Bay, Ontario, including a connection midway in Marathon, Ontario.
Rampion
•Saint-Nazaire Offshore Wind Project - a wind project located off the Sussexwest coast in the United Kingdom, consisting of 116 turbines, which willFrance that is expected to generate approximately 400-MW when complete. We hold an effective 24.9% interest, United Kingdom’s Green Investment Bank plc holds480-megawatts (MW). Project revenues are backed by a 25% interest and E.ON SE holds the remaining 50.1% interest20-year fixed price power purchase agreement (PPA) with added power production protection.
The following commercially secured growth project is expected to be placed into service in the project, which was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. The Rampion2023:
•Fécamp Offshore Wind Project is backed by revenues from- an offshore wind project that will be comprised of 71 wind turbines located off the United Kingdom’s fixed-price Renewable Obligation certificates program and a 15-year power purchase agreement. The project generated first power in November 2017northwest coast of France and is currentlyexpected to generate approximately 500-MW. Project revenues are underpinned by a 20-year fixed price PPA.
On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in EMF to CPP Investments, inclusive of the commissioning phase.
Hohe SeeSaint-Nazaire France Offshore Wind Project, the Fécamp Offshore Wind Project and Expansion the Courseulles-sur-Mer Offshore Wind Project. CPP Investments will fund their 49% share of all ongoing future development capital. The transaction is expected to close in the first half of 2021.
GROWTH PROJECTS - REGULATORY MATTERS
United States Line 3 Replacement Program
On February 3, 2020, and through its subsequent order on May 1, 2020, the Minnesota Public Utilities Commission (MNPUC) deemed the second revised final Environmental Impact Statement (EIS) adequate and reinstated the Certificate of Need and Route Permit, allowing for construction of the pipeline to commence following the issuance of required permits. On May 21, 2020, various parties filed petitions for reconsideration with the MNPUC contesting the adequacy of the EIS and the MNPUC’s restored grant of the Certificate of Need and Route Permit. On June 1, 2020, Enbridge and various supporting parties filed responses to those filed petitions for reconsideration. On June 25, 2020 the MNPUC denied all petitions for reconsideration reaffirming its prior decisions in all three dockets. After each environmental permitting agency issued their respective permits, the MNPUC issued its Authorization to Construct to Enbridge. Currently, construction in Minnesota continues despite the EIS, Certificate of Need and Route Permit undergoing appellate review; however judicial decisions may impact construction activities.
As for environmental permits, we have received all Minnesota Department of Natural Resources licenses and permits. The Minnesota Pollution Control Agency (MPCA) released a winddraft of the revised 401 Water Quality Certificate (WQC) in February 2020. Following a public comment period, the MPCA announced on June 3, 2020 that it would conduct a contested case hearing regarding the 401 Water Quality Certificate. After an Administrative Law Judge (ALJ) was assigned to the case, the contested case hearing schedule was established on June 23, 2020. The MPCA contested case hearing was completed in August and on October 16, 2020, the MPCA received a favorable recommendation from the ALJ on all five of the issues considered. On November 12, 2020, the MPCA Commissioner issued a 401 WQC to us. Subsequently, the United States Army Corps of Engineers (Army Corps) issued its 404 Permit. With all required permits received, we commenced construction on December 1, 2020. Currently, construction in Minnesota continues despite the 401 WQC and the 404 Permit undergoing appellate review; however judicial decisions may impact construction activities.
SOLAR SELF-POWER PROJECTS
Lambertville Compressor Station
In October 2020, we announced the completion of project development and construction of the first solar power plant in the US designed to directly help power an interstate natural gas pipeline compressor station. The 2.25-MW solar project, located in West Amwell Township, New Jersey, will provide solar energy to the North Sea, offTexas Eastern Lambertville compressor station.
Alberta Solar One
In October 2020, we announced the coaststart of Germanyconstruction on our first solar generation facility in Alberta. The 10.5-MW solar project, located near Burdett, Alberta, will produce a portion of our Canadian Mainline power requirements with solar energy. The project is expected to achieve commercial operations in the first quarter of 2021.
Heidlersburg Compressor Station
In November 2020, we announced the start of construction on the Heidlersburg solar project. The project will produce 2.5-MW of solar energy for our Heidlersburg compressor station, offsetting a portion of the station’s electric load and helping power the compressor units that will generate approximately 497-MW, with an additional 112-MW fromkeep gas flowing along our Texas Eastern pipeline. The project is expected to achieve commercial operations in the expansion. The Hohe See Offshore Wind Project and Expansion will be constructed under fixed-price engineering, procurement, construction and installation contracts, which have been secured with key suppliers. The Hohe See Project and Expansion is backed by a government legislated 20-year revenue support mechanism.
second quarter of 2021.
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following projects have been announced by us, but have not yet met our criteria to be classified as commercially secured:
LIQUIDS PIPELINES
Gray Oak Pipeline•Sea Port Oil Terminal Project - the Sea Port Oil Terminal (SPOT) project consists of onshore and offshore facilities, including a 385,000 bpd pipelinefixed platform located approximately 30 miles off the coast of Brazoria County, Texas. SPOT is designed to load very large crude carriers at rates of approximately 85,000 barrels per hour, or up to approximately 2 million bpd. Along with Enterprise Products Partners, L.P., we announced our intent to jointly develop and market SPOT, and we will work to finalize an equity participation agreement. The agreement will allow us to purchase an ownership interest in SPOT, subject to SPOT receiving a deep-water port license.
•Jones Creek Crude Oil Storage Terminal - the Jones Creek terminal is expected to have an ultimate capability of up to 15 million barrels of storage, access to crude oil from all major North American production basins and will be fully integrated with the Seaway Pipeline system to provide producersallow for access to Houston-area refineries, existing export facilities, the SPOT project and other shippers the opportunity to secure crude oil transportation from West Texas to the destination markets of Corpus Christi, Freeport, and Houston, Texas with connectivity to over 3 million bpd of refining capacity and multiple dock facilities capable of crude oil exports. The project is a joint development with Phillips 66 and would be placed into service during the second half of 2019 depending on shipper interest expressed in the recently closed open season.
future.
GAS TRANSMISSION AND MIDSTREAM
•Rio Bravo Pipeline - the Rio Bravo Pipeline is designed to transport up to 4.5 billion cubic feet per day (bcf/d) of natural gas from the Agua Dulce supply area to NextDecade's Rio Grande liquefied natural gas (LNG) export facility in the Port of Brownsville, Texas. We have acquired the Rio Bravo Pipeline development project from NextDecade. In addition, we have executed a precedent agreement with NextDecade under which we will provide firm transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a term of at least twenty years. Construction of the pipeline will be subject to the Rio Grande LNG export facility reaching a final investment decision.
Gulf Coast Express Pipeline78
•Annova LNG - we have executed a precedent agreement to supply the 6.5 million tonnes per annum Annova LNG export facility in the Port of Brownsville, Texas for a term of at least twenty years, by expanding our existing Valley Crossing system. The expansion will be subject to the Annova LNG facility reaching a final investment decision.
•Texas Eastern Venice Extension Project - a natural gasreversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline connecting the Waha,just south of Texas area to Agua Dulce, Texas that will provide capacity up to approximately 1.7 bcf/d.Eastern’s Larose compressor station. The project is a joint development between our equity investment DCP Midstream, Kinder Morgan Texas Pipeline LLC and an affiliate of Targa Resources Corp, and is expected to be placed into service during the second halfdeliver 1.26 bcf/d of 2019,feed gas to Venture Global’s proposed Plaquemines LNG export facility located in Plaquemine Parish, Louisiana. The expansion will be subject to obtaining sufficient shipper commitments.
the Plaquemines LNG export facility reaching a final investment decision.
RENEWABLE POWER GENERATION
Alliance Pipeline Expansion
•Courseulles-sur-Mer Offshore Wind Project - Alliance Pipeline announced a non-binding request for expressions of interest for additional transportation service on the Alliance Pipeline Canada and Alliance Pipeline US systems. Alliance Pipeline continues to engage with interested parties and assess the addition of more compression facilities along the system in order to increase throughput capacity by up to 500 mmcf/d. The projected in-service date for the potential capacity expansion is the second half of 2021.
Access Northeast - Access Northeast is a project that will bring affordable energy to New England consumers. Natural gas pipeline capacity scarcity and system reliability remains a primary issue for New England and one that must be resolved for the region to meet its energy supply needs. The project's partners continue to pursue a viable commercial and operational model to provide natural gas to the region.
GREEN POWER AND TRANSMISSION
Éolien Maritime France SAS - a 50% interest in Éolien Maritime France SAS (EMF), a Frenchan offshore wind development company, which is co-owned by EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF holds licenses for three large-scale offshore wind farmsproject located off the northwest coast of France that wouldis expected to generate approximately 1,428 MW. The development of these projects is subject448-MW. Project revenues are underpinned by a 20-year fixed price PPA. We expect to reach a final investment decision and regulatory approvals, the timing of which is not yet certain.
in 2021.
We also have a large portfolio of additional projects under development that have not yet progressed to the point of public announcement.securement.
GROWTH PROJECTS - REGULATORY MATTERS
Lakehead System Mainline Expansion (EEP)
On October 16, 2017, the United States Department of State issued a Presidential permit to EEP to operate Line 67 at its design capacity of 888,889 bpd at the international border of the United States and Canada near Neche, North Dakota.
Canadian Line 3 Replacement Program (the Fund Group)
In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC) applied to the Federal Court of Appeal for leave, which was subsequently granted, to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF discontinued its judicial review application. On October 25, 2017, the AMC discontinued its judicial review application. As a result, no further challenges to the Government of Canada's decision to approve the Canadian L3R Program may be brought by any party.
All required pre-construction filings have been approved by the NEB.
United States Line 3 Replacement Program (EEP)
EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the MNPUC. The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the filing of intervenor testimony in the Certificate of Need and Route Permit processes. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final EIS to be inadequate in four specific areas on December 7, 2017. The DOC provided a supplemental EIS on February 12, 2018, and the MNPUC will determine its adequacy in the second quarter of 2018. In the parallel Certificate of Need and Route Permit dockets, public and evidentiary hearings were held at locations along the proposed route and in Saint Paul, Minnesota from September to November 2017 and are now complete. The MNPUC is expected to vote on the Certificate of Need and Route Permit at the end of the second quarter of 2018.
LIQUIDITY AND CAPITAL RESOURCES
The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends.We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.
Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including utilizationalternatives. Our current financing plan does not include any issuances of additional common equity and was the primary consideration for the suspension of our sponsored vehicles. ForDividend Reinvestment and Share Purchase Plan in November 2018.
As discussed within Recent Developments - Financing Update, as a result of the COVID-19 pandemic and the corresponding impact on the capital markets, we have elected to increase our liquidity through additional information, refercredit facilities to Sponsored Vehicles below.ensure we will not have to access the capital markets through 2021 to fund our current portfolio of capital projects if market access is restricted or pricing is unattractive.
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with our funding plan, we completed the following long-term debt issuances totaling $2.5 billion and US$2.1 billion in 2017:
|
| | | | | | | |
Entity | Type of Issuance | Amount |
|
(in millions of Canadian dollars, unless stated otherwise) | |
|
Enbridge Inc. | Common shares (via share exchange*)Medium-term notes | 37,429 | $1,300 |
Enbridge Inc. | Common shares (by private placement) | 1,500 |
|
Enbridge Inc. | Preference shares | 500 |
|
Enbridge Inc. | Fixed-to-floating rate subordinated notes | 1,650 |
|
Enbridge Inc. | Floating rate notes | US$750 |
|
Enbridge Inc. | Medium-termFixed-to-fixed subordinated term notes | 1,200 | US$1,000 |
Enbridge Gas Inc. | US$ Fixed-to-floating rate subordinatedMedium-term notes | US$1,000 |
|
Enbridge Inc. | US$ Floating rate notes | US$$1,200 |
|
Enbridge Inc. | US$ Senior notes | US$1,400 |
|
Enbridge Income Fund Holdings Inc.
| Common shares | 575 |
|
Enbridge Income Fund Holdings Inc.
| Common shares (Secondary offering by Enbridge) | 575 |
|
Enbridge Gas Distribution Inc. (EGD) | Medium-term notes | 300 |
|
Spectra Energy Partners, LP1 | Floating rateSenior notes | US$400 |
|
Union Gas Limited | Medium-term notes | 500 | 300 |
* In connection with the Merger Transaction
On January 9, 2018,1Issued through Texas Eastern, Transmission, LP, a wholly-owned operating subsidiary of SEP, completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively.Spectra Energy Partners, LP (SEP).
Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities at December 31, 2017.2020:
| | | | | | | | | | | | | | |
| | Total | | |
| Maturity | Facilities | Draws1 | Available |
(millions of Canadian dollars) | | | | |
Enbridge Inc. | 2021-2024 | 11,854 | | 8,719 | | 3,135 | |
Enbridge (U.S.) Inc. | 2022-2024 | 7,007 | | 492 | | 6,515 | |
Enbridge Pipelines Inc. | 20222 | 3,000 | | 1,278 | | 1,722 | |
Enbridge Gas Inc. | 20222 | 2,000 | | 1,121 | | 879 | |
Total committed credit facilities | | 23,861 | | 11,610 | | 12,251 | |
1Includes facility draws and commercial paper issuances that are back-stopped by the credit facility.
|
| | | | | | | |
| | 2017 |
| | Total |
| |
| |
|
December 31, | Maturity | Facilities |
| Draws1 |
| Available |
|
(millions of Canadian dollars) | | |
| |
| |
|
Enbridge Inc.2 | 2019-2022 | 7,353 |
| 2,737 |
| 4,616 |
|
Enbridge (U.S.) Inc. | 2019 | 3,590 |
| 490 |
| 3,100 |
|
Enbridge Energy Partners, L.P.3 | 2019-2022 | 3,289 |
| 1,820 |
| 1,469 |
|
Enbridge Gas Distribution Inc. | 2019 | 1,016 |
| 972 |
| 44 |
|
Enbridge Income Fund | 2020 | 1,500 |
| 766 |
| 734 |
|
Enbridge Pipelines (Southern Lights) L.L.C. | 2019 | 25 |
| — |
| 25 |
|
Enbridge Pipelines Inc. | 2019 | 3,000 |
| 1,438 |
| 1,562 |
|
Enbridge Southern Lights LP | 2019 | 5 |
| — |
| 5 |
|
Spectra Energy Partners, LP4,5 | 2022 | 3,133 |
| 2,824 |
| 309 |
|
Union Gas Limited5
| 2021 | 700 |
| 485 |
| 215 |
|
Westcoast Energy Inc.5
| 2021 | 400 |
| — |
| 400 |
|
Total committed credit facilities | | 24,011 |
| 11,532 |
| 12,479 |
|
| |
1 | Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. |
| |
2 | Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively. |
| |
3 | Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.
|
| |
4 | Includes $421 million (US$336 million) of commitments that expire in 2021.
|
| |
5 | Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction. For additional information, refer to Merger with Spectra Energy.
|
2Maturity date is inclusive of the one-year term out option.
During the first quarter of 2017,
On February 24, 2020, Enbridge establishedInc. entered into a five-year, termtwo year, non-revolving credit facility for $239 million (¥20,000 million)US$1.0 billion with a syndicate of Japanese banks. Principallenders.
On February 25, 2020, Enbridge Inc. entered into two, one year, non-revolving, bilateral credit facilities for a total of US$500 million.
On March 31, 2020, Enbridge Inc. entered into a one year, revolving, syndicated credit facility for $1.7 billion. On April 9, 2020, Enbridge Inc. exercised an accordion provision and interest on thisincreased the facility have been converted to United States dollars using$3.0 billion.
On July 23 and 24, 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2022, inclusive of a cross currency interest rate swap.one-year term out provision.
On February 10, 2021, we entered into a three year, sustainability linked credit facility for $1.0 billion with a syndicate of lenders. As a result of the sustainability linked credit facility and other financing activities completed in 2020, our resilient cash flows and our current liquidity position, we concurrently cancelled a one year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.
In addition to the committed credit facilities noted above, we have $792$849 million of uncommitted demand facilities, of which $518$533 million were unutilized as at December 31, 2017.2020. As at December 31, 2016,2019, we had $335$916 million of uncommitted credit facilities, of which $177$476 million were unutilized.
As at December 31, 2020, our net available liquidity of $12,959 million at December 31, 2017 wastotaled $12.7 billion, inclusive of $480$452 million of unrestricted cashCash and cash equivalents as reported on the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2017,2020, we were in compliance with all debt covenants and expect to continue to comply with such covenants.
Strong growth in internal cash flow, proceeds from non-core asset dispositions, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at December 31, 2017, our debt capitalization ratio was 48.3% compared with 61.8% as at December 31, 2016. The improvement in the ratio reflected an increase in equity that resulted from the Merger Transaction.EBITDA.
During 2017,2020, our credit ratings were affirmed as follows:
•On July 23, 2020, DBRS Limited confirmedaffirmed our issuer rating and medium-term notes and unsecured debentures rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), all with stable outlooks;
•On April 13, 2020, Fitch Rating services affirmed long-term issuer default rating and changed theirsenior unsecured debt rating outlook from under reviewof BBB+, preference share rating of BBB-, junior subordinated note rating of BBB- and short-term and commercial paper rating of F2 with developing implications to stable.a stable rating outlook;
•On December 22, 2020, Moody’s Investor Services, Inc. affirmed our issuer and senior unsecured ratings of Baa2, subordinated rating of Ba1 and preference share rating of Ba1 all with positive outlooks. In addition, the commercial paper rating for Enbridge (U.S.) Inc. was affirmed at P-2; and
•On December 1, 2020, Standard & Poor’s Rating Services (S&P) affirmed our corporate credit rating and senior unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed our global overall short-term rating of A-2.
In June 2017, we obtained Fitch long-term issuer default rating and senior unsecured debt rating of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term and commercial paper rating of F2 with a stable rating outlook.
On December 22, 2017, Moody’s Investor Services, Inc. downgraded our issuer and senior unsecured ratings from Baa2 to Baa3, subordinated rating from Ba1 to Ba2, preference share rating from Ba1 to Ba2, commercial paper rating for Enbridge (U.S.) Inc. from P-2 to P-3, and changed the outlook on all of these ratings from negative to stable.
We invest surplus cash in short-term investment grade money market instruments with highly creditworthy counterparties. Short-term investments were $70 millionas at December 31, 2017 compared with $800 million as at December 31, 2016. The higher short-term investment balances at the end of 2016 reflect the temporary investment of a portion of the proceeds of capital markets offerings undertaken by us in the fourth quarter of 2016, pending its redeployment in our growth capital program.
There are no material restrictions on our cash. Total restricted cash of $107$38 million, includes EGD’s and Union Gas’ receiptas reported on the Consolidated Statements of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cashFinancial Position, primarily includes cash collateral and amounts receivedfuture pipeline abandonment costs collected and held in respect of specific shipper commitments.trust. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by us until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative usesuse by us.
Excluding current maturities of long-term debt, as at December 31, 20172020 and 20162019, we had a negative working capital position of $2,538 million$3.7 billion and $456 million,$2.8 billion, respectively. In both periods, the major contributing factor to the negative working capital position was the ongoing funding ofcurrent liabilities associated with our growth capital program.
To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at December 31, 2017 and 2016, our net available liquidity totaled $12,959 million and $14,274 million, respectively, on a consolidated basis. It is anticipated that any current maturities of long-term debt will be refinanced upon maturity.
SOURCES AND USES OF CASH
| | December 31, | 2017 |
| 2016 |
| 2015 |
| |
Year ended December 31, | | Year ended December 31, | 2020 | 2019 | 2018 |
(millions of Canadian dollars) | |
| |
| |
| (millions of Canadian dollars) | | |
Operating activities | 6,584 |
| 5,211 |
| 4,571 |
| Operating activities | 9,781 | | 9,398 | | 10,502 | |
Investing activities | (11,002 | ) | (5,192 | ) | (7,933 | ) | Investing activities | (5,177) | | (4,658) | | (3,017) | |
Financing activities | 3,476 |
| 840 |
| 3,074 |
| Financing activities | (4,770) | | (4,745) | | (7,503) | |
Effect of translation of foreign denominated cash and cash equivalents | (72 | ) | (19 | ) | 143 |
| Effect of translation of foreign denominated cash and cash equivalents | (20) | | 44 | | 68 | |
Increase/(decrease) in cash and cash equivalents | (1,014 | ) | 840 |
| (145 | ) | |
Net increase/(decrease) in cash and cash equivalents and restricted cash | | Net increase/(decrease) in cash and cash equivalents and restricted cash | (186) | | 39 | | 50 | |
Significant sources and uses of cash for the years ended December 31, 20172020 and 20162019 are summarized below:
Operating Activities
20172020
•The growthincrease in cash flow deliveredprovided by operations in 2017 is a reflection of the positive operating factors discussed under Results of Operations, whichduring 2020 was primarily included contributions from new assets of approximately $2,574 million following the completion of the Merger Transaction.
For the year ended, partially offsetting the increase in cash flows from operating activities are transaction costs in connection with the Merger Transaction, as well as employee severance costs in relation to our enterprise-wide reduction of workforce.
Changesdriven by changes in operating assets and liabilities to $314 million from $358 million for the years ended December 31, 2017 and 2016, respectively, reflected negative working capital in each of those years.liabilities. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within the Energy Services and Gas Distributionour business segments, the timing of tax payments, as well as timing of cash receipts and payments.payments generally. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 28. Changes in Operating Assets and Liabilities.
•The factor above was partially offset by the impact of certain unusual, infrequent and other non-operating factors as discussed under Results of Operations.
2016
2019
•The growthdecrease in cash flow deliveredprovided by operations in 2016during 2019 was a reflection of the positive operating factors discussed under Results of Operations, which primarily included stronger contributions from the Liquids Pipelines segment, partially offsetdriven by higher financing costs resulting from the incurrence of incremental debt to fund asset growth and the impact of refinancing construction debt with longer-term debt financing.
Changeschanges in operating assets and liabilities, included withinpartially offset by stronger contributions from our operating activities were $358 million for the year ended December 31, 2016 compared with $645 million for the comparative 2015 year. Our operating assets and liabilities fluctuate in the normal course due to various factors including fluctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, general variations in activity levels within our businesses, as well as timing of cash receipts and payments.segments.
Investing Activities
We continue with the execution of our growth capital program which is further described in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects –- Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.
A summary of additions to property, plant and equipment for the years ended December 31, 2017, 20162020, 2019 and 20152018 is set out below:
| | Year ended December 31, | 2017 |
| 2016 |
| 2015 |
| Year ended December 31, | 2020 | 2019 | 2018 |
(millions of Canadian dollars) | |
| |
| |
| (millions of Canadian dollars) | | |
Liquids Pipelines | 2,797 |
| 3,956 |
| 5,882 |
| Liquids Pipelines | 2,032 | | 2,548 | | 3,102 | |
Gas Transmission and Midstream | 3,883 |
| 176 |
| 385 |
| Gas Transmission and Midstream | 2,066 | | 1,695 | | 2,578 | |
Gas Distribution | 1,177 |
| 713 |
| 858 |
| |
Green Power and Transmission | 321 |
| 251 |
| 68 |
| |
Gas Distribution and Storage | | Gas Distribution and Storage | 1,134 | | 1,100 | | 1,066 | |
Renewable Power Generation | | Renewable Power Generation | 81 | | 23 | | 33 | |
Energy Services | 1 |
| — |
| — |
| Energy Services | 2 | | 2 | | — | |
Eliminations and Other | 108 |
| 32 |
| 80 |
| Eliminations and Other | 90 | | 124 | | 27 | |
Total capital expenditures | 8,287 |
| 5,128 |
| 7,273 |
| Total capital expenditures | 5,405 | | 5,492 | | 6,806 | |
2020
The increase in cash used in investing activities was primarily attributable to capital expenditures of $8,287 millionresulted from the following factors:
•Lower proceeds from asset dispositions in 2020 compared with $5,128 million for2019, primarily due to the comparable period, which include capital expendituressale of the federally regulated portion of our Canadian natural gas gathering and processing businesses assets on assets and growth projects acquired through the Merger Transaction, and increased investment in equity investments. During the first half of 2017, we paid cash consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken Pipeline System. In addition, we also made an equity investment of $0.5 billion in connection with our 50% interest in the Hohe See Offshore Wind Project.
December 31, 2019.Most of the guarantee arrangements that we enter into enhance the credit standings of certain subsidiaries, non-consolidated entities or less than 100%-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk which are not included on our Consolidated Statements of Financial Position. The possibility of us having to honor our contingencies is largely dependent upon the future operations of our subsidiaries, investees and other third parties, or the occurrence of certain future events. Issuance of these guarantee arrangements is not required for the majority of our operations.
We do not have material off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Payments due under contractual obligations over the next five years and thereafter are as follows:
The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.
Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:
St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas). St. Lawrence Gas assets were included in the Gas Distribution and Storage segment. On November 1, 2019 we closed the sale of St. Lawrence Gas for cash proceeds of approximately $88$72 million. After closing adjustments, a loss on disposal of $10 million (US$70 million). Subject to regulatory approval and certain pre-closing conditions,was included in Other income/(expense) in the transaction is expected to close in
Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows, and such charges are included in Impairment of property, plant and equipment on the Consolidated Statements of Earnings.flows.
Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi Wind Project (Keechi), and New Creek and Chapman Ranch wind farms.facilities. These wind farmsfacilities are considered VIEs as they do not have sufficient equity at riskdue to the members’ lack of substantive kick-out rights and are partially financed by tax equity investors.participating rights. We are the primary beneficiary of these VIEs by virtue of our voting rights, our power to direct the activities that most significantly impact the economic performance of the wind farms,facilities, and our obligation to absorb losses.losses and the right to receive benefits that are significant.
Enbridge Holdings (DakTex) L.L.C.
The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.
We currently hold several equity investments in limited partnerships that are assessed to be VIEs due to limited partners not having substantive kick-out rights or participating rights. We have determined that we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee whothat makes significant decisions for the VIE and none of the partners may make major decisions unilaterally.
The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 20172020 and 20162019 are presented below:
We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 20172020 and 2016.2019.
Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date. As at December 31, 2017,2020, this was comprised of $2.0$1.8 billion in Goodwill and $643$657 millionin amortizable assets. As at December 31, 2016,2019, this was comprised of $859 million$2.1 billion in Goodwill and $687$681 million in amortizable assets.
Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows:
Noverco Inc.
As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 20172020 and 2016,2019, we had an indirect pro-rata interest of 0.7%0.1% and 1.3%0.2%, respectively, in our own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $102$29 million and $51 million as at December 31, 20172020 and 2016.2019. Noverco records dividends paid fromby us as dividend income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our investment in Noverco.
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all NEBCER regulated pipelines as a result of the NEB’sCER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the NEBCER decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position.
We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the United StatesUS and Canada.
The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets:
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2017,2020, we were in compliance with all debt covenants.
The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position:
Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares.