Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 4th Quarter Results and Business Outlook Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr.
Moneta.
Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 4th quarter 2016 financial results and business outlook conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Alex Pourbaix, Chief Operating Officer Carl Johansen, President of our Natural Gas Pipelines Business Paul Miller, President, Liquids Pipelines Bill Taylor, President of Energy and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some comments on our Q4 financial results as well as our business outlook. With respect to our outlook, similar information would have been covered at our annual Investor Day last November.
As a result, our comments this afternoon are expected to last approximately 45 or 50 minutes, which is longer than normal. While lengthy, we hope you will find the added information beneficial. The slide presentation that accompanies our remarks can be found on our website in the Investors section under the heading Investments and Presentations. Following Russ and Don's remarks, we will turn the call over to the conference coordinator for questions from the investment community. If you are a member of the media, please contact James Miller following this call and he would be happy to address your questions.
In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to 2 questions. If you have added questions, please reenter the queue. In the interest of time, if you have detailed questions relating to some of our smaller operations or your detailed financial models, Stuart and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.
S. Securities and Exchange Commission. Finally, during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or EBITDA, comparable funds generated from operations and comparable distributable cash flow. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non GAAP measures. As a result, they may not be comparable to similar measures presented by other entities.
They are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. A reconciliation to the nearest GAAP measure is included in the appendix.
With that, I'll now turn the call over to Russ. Thanks, David, and good afternoon, everyone, and thank you very much for joining us today. 2,006 was truly a transformational year for us here at TransCanada, as our portfolio of high quality energy infrastructure assets performed very well, While our long term strategy of national discipline enabled us to undertake unprecedented growth that will reward our shareholders for many more years to come. Our $13,000,000,000 acquisition of Columbia represented a rare opportunity to further diversify our regulated natural gas pipeline and storage operations and gave us an incumbency position in the Appalachian region, which as you know is one of the world's fastest growing and lowest cost natural gas production basins. We now own and operate 1 of North America's largest natural gas transmission businesses with a strong competitive position in the fastest growing supply regions of North America.
We also agreed to acquire the outstanding publicly held common units of Columbia Pipeline Partners for $17 per common unit or approximately US915 $1,000,000 I'm pleased to report that earlier today, the Columbia Pipeline Partners unitholders approved the transaction. And as a result, we expect to close the acquisition in the coming days. This will result in 100% ownership of Columbia's core assets and will simplify our corporate structure. Over the past year, we have added $13,000,000,000 of projects to our near term commercially secured growth portfolio. The largest addition came through our Columbia acquisition, which included over $7,000,000,000 in long term contracted expansion and modernization projects.
We also added 2 additional natural gas pipeline projects in Mexico that will see us invest an additional $1,900,000,000 in that region as well as ongoing expansions of our NGTL system. To help fund the Columbia acquisition, we decided to sell our U. S. Northeast power business and subsequently entered into 2 separate sales agreements, which are expected to close in the first half of twenty seventeen. We're also in the process of monetizing our U.
S. Northeast power marketing business. In total, we expect to realize approximately US3.7 billion dollars which will be used to retire the remainder of our acquisition bridge facility. During the year, we raised approximately $11,000,000,000 of subordinated capital through the issuance of common and preferred shares as well as hybrid securities. This allowed us to permanently fund the Columbia acquisition and maintain our A grade credit ratings.
Looking forward, these actions are expected to be accretive to both earnings and cash flow per share and drive significant shareholder value in the years ahead. Before I provide an update on our business outlook, I'd like to make a few comments on our Q4 and full year 2016 financial results. Excluding certain specific items, comparable earnings for the Q4 2016 were $626,000,000 or $0.75 a share, an increase of $173,000,000 or $0.11 per share over the same period last year. Comparable EBITDA increased $363,000,000 to approximately $1,900,000,000 while comparable funds generated from operations were $1,400,000,000 were 16% higher compared to the Q4 of 2015. For the full year, comparable earnings were $2,100,000,000 or $2.78 per share, an increase of $353,000,000 or $0.30 per share over 2015.
This equates to approximately 12% increase on a per share basis. Comparable EBITDA increased $739,000,000 to approximately 6 point comparable funds generated from operations exceeded $5,000,000,000 for the first time in our history. Don will provide you more detail on our financial results in just a few moments. Based on the strength of our financial performance and our growth outlook, TransCanada's Board of Directors today declared a quarterly dividend of $0.625 per common share, which is equivalent to $2.50 per share on an annual basis. This represents a 10.6% increase over last year and is the 17th consecutive year that the Board has raised the TransCanada dividend.
At the same time, we have maintained very strong earnings and cash flow payout ratios. Turning now to Slide 8. I'll provide a few comments on our outlook for the future. Since 2000, our strategy has essentially remained the same as we have invested approximately $70,000,000,000 in high quality, low risk growth opportunities. That investment generated significant growth in earnings and cash flow and contributed to a 14% average annual return for our shareholders.
Today, our $88,000,000,000 high quality portfolio of critical energy infrastructure assets includes natural gas pipelines in Canada, the United States and Mexico as well as liquid pipelines and energy assets in both Canada and the United States. Following the monetization of our U. S. Northeast Power business, over 95% of our EBITDA will come from regulated or long term contracted assets. As a result, our assets are well positioned to produce solid, steady results through various market cycles.
They also provide us with multiple platforms for continued growth. Today, we are advancing $23,000,000,000 of near term growth opportunities that include a series of projects in jurisdictions where we see relatively normal course permitting and construction capability. We also continue to advance over $45,000,000,000 of long term growth opportunities. Any one of these large scale initiatives would create significant incremental shareholder value and position us for continued long term growth. As a result, we expect annual dividend growth in the upper end of the 8% to 10% dividend range through 2020.
And finally, we have maintained a solid financial position. Our A grade credit ratings allowed us to access significant pools of capital at lower cost than most of our competitors and provides us with the ability to act at all points in the economic cycle. We also believe that a simple and understandable corporate structure is a competitive advantage and does differentiate us from many of our peers. Turning now to Slide 9. As I mentioned, TransCanada is focused on 3 core businesses in 3 core geographies.
We own and operate 1 of the world's or 1 of North America's largest transmission natural gas transmission systems with over 90,000 kilometers or 56 6,000 miles of pipeline that connect the fastest growing BELAY basins to the key markets. Today, our pipelines more than 25% of the daily North American demand. We are also the continent's largest provider of natural gas storage with 653,000,000,000 cubic feet of capacity. In liquids, our 4,300 kilometer Keystone system transports 545,000 barrels of crude oil per day or approximately 20 percent of Western Canadian exports to key refining markets in the U. S.
Midwest and Gulf Coast. We also currently own or have interest in 17 generation facilities with a capacity of approximately 11,000 megawatts. Following the sale of our U. S. Northeast power business, we will still be one of Canada's largest power generation companies with over 6,000 Megawatts of long term contracted power generation.
Over half of that capacity is comprised of emissionless power, including nuclear, wind and solar. Our remaining capacity consists of high efficiency natural gas fired generation facilities. Looking forward, our $23,000,000,000 of near term commercially secured projects will expand our footprint across North America. It includes approximately $19,000,000,000 of natural gas pipeline expansions that are driven by growth in North American natural gas supply in the Marcellus and Utica as well as the Western Canadian Sedimentary Basin, along with demand and growth in places like Mexico. We're also developing a regional liquids pipeline system in Alberta with $2,000,000,000 of projects expected to enter service by 2018.
And finally, we're advancing another $2,000,000,000 of power projects, including the 900 Megawatt Napanee gas fired plant in Ontario as well as the initial work required at Bruce Power as part of the multibillion dollar life extension agreement with the Ontario government. We've invested approximately $6,000,000,000 in these projects to date with the remainder to be spent over the balance of the decade. Notably, all of these projects are underpinned by long term contracts or rate regulated business models. As a result, we have a high degree of visibility to the earnings and cash flow that they will generate as they enter service. Over the next few minutes, I'll expand on these projects and the additional organic growth opportunities that we expect to surface from the extensive North American footprint that we now enjoy.
So starting with Colombia. We spent the last 6 months integrating their operation with our U. S. Pipeline business. That process has gone extremely well, and we expect to realize a significant portion of the $250,000,000 in targeted benefits in 2017 with the remainder to follow in 2018.
On the growth side, having completed certain modernization projects in 2016, Columbia's capital program now includes $7,100,000,000 of projects that are largely expected to enter service by 2018. These projects are also proceeding according to plan. We recently received FERC permits on 2 of the larger initiatives, the U. S. Dollars 1,400,000,000 Leach Express project and the $400,000,000 U.
S. Rain Express project. Both of those are expected to be completed by the end of this year. In total, we expect approximately $2,300,000,000 of Columbia's projects to enter service in 2017. Looking forward, we expect our Columbia system to continue to generate organic growth opportunities as natural gas production in the Appalachian region grows from what is forecast today to be about 20,000,000,000 cubic feet a day to 30,000,000,000 cubic feet a day by the end of the decade.
With its highly connected network of receipt and delivery points and competitive path to markets, it's well positioned to capture its share of the infrastructure investment required to connect that growing supply to market. At the same time, we are working to identify opportunities to better integrate our U. S. Natural gas pipeline and storage assets to offer greater connectivity and enhanced services to all of our customers. While that will take us some time, it will include projects to move gas within the basin as well as westward onto A and R and onto Midwest markets, northward into Eastern Canada and then onto We're LNG markets and potentially export to Mexico.
Moving to the next slide. On this map, you can see our U. S. Pipeline network is well positioned in key areas with access to multiple basins and demand centers. This includes pipelines held through our MLP, TC pipelines LP, which are highlighted in green.
Looking forward, the U. S. Pipeline business could benefit from a number of other developments. First of all, the ANR settlement will result in higher contributions in 20 17. Of note, that settlement included $837,000,000 of future modernization expenditures.
And similar to Columbia's program, those costs are effectively included in the higher rates established under that settlement and therefore, will earn a return of and on capital related to that investment. We also continue to look at additional opportunities across the broader U. S. Natural gas pipeline forward portfolio. For example, our GTN system is well positioned to move incremental volumes as producers in the Western Canadian Sedimentary Basins continue to seek outlets for their growing production.
Great Lakes is well positioned to move additional volumes from the Western Canadian Sedimentary Basin to eastern markets as a result of its spare capacity and could be a direct beneficiary of any long term load attraction agreement on the Canadian mainline that could result in significant volumes of gas moving from Western Canada to Don. Iroquois and our Portland natural gas pipeline systems provide relatively expansion opportunities into the New York and New England markets. With greenfield projects in this region facing a number of challenges on permitting, brownfield expansions on these systems could provide competitive paths to markets. Before I leave the U. S.
Pipelines, I'd also like to reiterate the TC pipeline remains a core element of our strategy, both from a strategic perspective as to where those pipelines are positioned as well as from a financing perspective. We continue to believe that it can play a meaningful role in our funding of our sizable near term program, and Don will expand on this and other funding options in just a few minutes. Turning to Western Canada and our NGTL system. We believe that Western Canada shale plays are among the lowest cost sources of very similar, primarily in the areas of the Montney, Duvernay, Deep Basin, Horn River and the Leerds areas. Each has proven to be quite prolific with recoverable reserves in these regions having quadrupled over the last over the past decade.
Connecting production from these emerging shale plays will require additional infrastructure, and our NGTL system is ideally positioned to move that gas to market. Last year, the NGTL system transported 11,300,000,000 cubic feet a day, up from 11,000,000,000 cubic feet a day in 2015. In total, we moved about 75% of the gas production in Western Canada. We've now contracted to build $5,400,000,000 of new infrastructure through 2020 on the NGTL system to move that production to market. Approximately $1,600,000,000 is planned to be placed in service in 2017, improving the fleet capacity of the system.
As new gas production is connected to NGTL, we will likely need to increase the main export delivery points in the province. NGTL also serves a large intra Alberta market with a peak day delivery of about 6,500,000,000 cubic feet a day. We expect the Alberta demand to continue to grow as the province transitions from coal fired to gas fired generation. That will also require new pipeline infrastructure and NGTL again is well positioned to provide that service. Turning to the mainline, which continues to generate strong results with incentives leading to rates of return on equity that are at the upper end of our allowed ranges.
Our multiyear LDC settlement, which went into effect in 2015, has certain elements extending into 2,030, effectively creating long term stability for that system. Today, the system moves between 2,500,000,000 3,000,000,000 cubic feet a day from Western Canada to markets across Canada. At the same time, in the Eastern Triangle, which is depicted by the brown triangle on the map, we are adding about $300,000,000 expansion facilities to move growing amounts of U. S. Shale gas.
That investment, along with the existing rate base in the Eastern region, will continue to earn a return of and on capital under a cost of service regulated model through 2,030 under the LBC settlement. At the same time, the western portion of the system, which we'll see its investment base continue to depreciate, will continue to play an important role, as I said, in linking Western Canada and Gas supply to markets. Although we haven't concluded a load attraction deal at this time, we're very encouraged by our discussions with Western Canadian Producers over the past few weeks. Regardless of how those discussions proceed, however, both the western portion of the Canadian Mainline and the Eastern Triangle are expected to continue to generate stable returns for our shareholders. Turning to Mexico for a few moments, where we've seen significant growth over the last few years.
Today, we have 4 pipelines generating revenue under long term take or pay contracts with the CFE. Three additional pipelines are under construction that will bring our total investment in Mexico to approximately $5,000,000,000 The US600 million dollars Tula pipeline and the US550 million dollars Via Del Rey pipelines are both expected to enter service in early 2018. The $2,100,000,000 Sur de Texas offshore pipeline is anticipated being in service in late 2018. We hold a 60% interest in that joint venture we'll operate that pipeline. Looking forward, ongoing Mexico energy sector reforms as well as the continued shift to natural gas from other fuels is expected to create additional opportunities.
In addition, with a now a system that effectively extends from the U. S. Border to the most populated regions of the country, we could see demand for incremental volumes and capacity additions to our existing strategically situated network. Turning to liquids for a minute. The Keystone price pipeline has established itself as a premier crude oil transportation network by offering competitive tolls, shorter transit times and reduced product degradation.
In total, it has safely now delivered over 1,400,000,000 barrels of crude oil since entering service in 2010. It is underpinned by long haul take or pay contracts for 545,000 barrels per day with an average remaining term of 15 years providing visibility to an annual EBITDA of more than $1,000,000,000 Recent capital additions to the system have created optionality for us and to our shippers by improving access to more refining markets in the U. S. Gulf Coast. Ultimately, this is expected to provide opportunities to move increased volumes, including U.
S. Shale oil volumes on the southern portion of the line in the future. We are also advancing a number of intra Alberta liquids pipeline projects, looking first at the Northern Courier project. This project is underpinned by a 25 year contract with the Fort Hills partnership and is on track to be in service in 2017. Construction also continues on the Grand Rapids project with completion expected later this year.
And today, we added a new project to our near term portfolio, the White Spruce Pipeline, which will transport crude oil from a major oil sands plant in Northeast Alberta to the Grand Rapids pipeline. This $200,000,000 project is underpinned by a long term contract and also provides additional long term contracted volumes on the Grand Rapids system. We expect White Spruce to be in service in 2018. Turning now to the Energy business. In the Q4, we finalized the terms of a settlement with respect to the termination of our Alberta power purchase agreements.
It included the transfer to the Alberta balancing pool of a package of environmental credits held to offset the PPA emission costs. This that resulted in a non cash charge related to the carrying value of those credits. The sale of our U. S. North East Power business also continues to progress, and we expect those transactions to close in the first half of twenty seventeen.
Once completed, we will substantially reduce our merchant power exposure. The remaining 6,200 megawatts of power generation assets in our portfolio will largely be underpinned by long term contracts with strong counterparties. Those remaining assets will generate approximately $765,000,000 of EBITDA. They did generate about say 7 $65,000,000 of EBITDA in 2016, a number that we expect to grow to more than $1,000,000,000 by 2020 as we complete the Napanee and advance work on the Bruce Power projects. Construction on Napanee continues and expected to be in service by 2018.
Work also continues on the asset management program at Bruce Power. Those activities are being carried out in advance of the major component replacement work that will begin on Unit 6 in approximately 2020. Looking forward, we will continue to assess opportunities in the renewable and gas fired generation markets across our geographies as they become available. Before I leave energy, just a few additional comments on Bruce Power, where we've been very pleased with its operating financial performance over the past number of years. Bruce's average availability in 2016 was approximately 83%.
In 2017, we expect that availability to increase to approximately 90%. As part of Ontario the Ontario government's long term energy plan, the province has maintained their commitment to increase emission free electricity generation. Bruce is very well positioned to supply this much needed power on a cost competitive basis. Major investments to extend the operating life of Bruce Power to 2,000 and 64 will begin, as I said, with Unit 6 in 2020 and continue through 2,030. This $6,400,000,000 investment will see us invest approximately $1,100,000,000 between now and the end of the decade, with the remainder being invested between 20 20 2,033.
So in summary, today, we are advancing a $23,000,000,000 near term capital program that is expected to drive significant growth in EBITDA between now and the end of the decade. As you can see from this chart, comparable EBITDA is expected to grow from $5,900,000,000 in 2015 to approximately $9,300,000,000 in 2020. That equates to a compound average growth rate of approximately 10%. Also of note, over 95% of that EBITDA will be derived from regulated or long term contracted assets. Approximately 72% will come from natural gas pipelines, 15% from liquids pipelines and 12% from energy.
Based on the stability of our base business and our confidence in our growth plans, we expect to grow the dividend at an average annual rate at the upper end of an 8% to 10% range through 2020. This will be supported by expected earnings growth and growth in cash flow and strong distributable cash flow coverage ratios. Success in advancing other growth initiatives over the forecast period could augment our standard dividend growth outlook through 2020 beyond. Finally, a few words on our $45,000,000,000 portfolio of medium to long term projects. We expect to continue to develop these long term options.
It includes our 2 West Coast LNG projects that are now fully permitted. The liquefaction facilities associated with those pipelines are also fully permitted, and we are awaiting final investment decisions from those project sponsors. As we have said, in the event that those projects do not proceed, we will be entitled to full recovery of our development costs, which today total approximately $900,000,000 The portfolio also includes our 2 large scale liquids pipeline projects. We continue to advance the Energy East project through the permitting process in Canada, and currently, we are awaiting direction from the newly appointed NEB panel that will oversee the regulatory review. And finally, the Keystone XL project, which began to advance again following the President of the United States' invitation to reapply for presidential permit.
As a result of that invitation, as you know, on January 26, we filed a presidential permit application with the Department of State for the project. And earlier today, we filed with the Nebraska Public Service Commission for the approval of the project route through Nebraska. Given the passage of time since November of 2015, we are also updating our commercial arrangements with our shippers. While some of the shippers may increase or decrease their volume commitments, we do expect to retain sufficient commercial support to underpin the project. We continue to believe that the U.
S. Gulf Coast is the largest and most attractive market for growing volumes of Canadian heavy oil. We also believe that the Keystone XL system is the safest, most efficient and most environmentally sound way to move that crude oil from Western Canada to the Gulf Coast. This project will enhance U. S.
Energy security. It will create significant employment for many U. S. Citizens and it will generate significant and much needed tax revenues. This project very much remains in the national interest of both Canada and the United States.
That concludes my remarks. And now I'll turn it over to Don Marchand to provide more details on our Q4 and our longer term financial outlook. Don, over to you.
Great. Thanks Russ and good afternoon everyone. During the next 25 to 30 minutes, my intent is to briefly touch on the 4th quarter results, provide an overview of our financial outlook, including our capital spending and related funding plans, comparable EBITDA growth and finally, dividend growth and related distributable cash flow payout ratios through 2,030. First, the highlights of our Q4 2016 financial results. As outlined in our financial highlights news release issued earlier today, we reported a net loss attributable to common shares in the 4th quarter of $358,000,000 or $0.43 per share compared to a net loss of $2,500,000,000 or $3.47 per share for the same period in 2015.
Our results included a non cash after tax loss of $870,000,000 related to the monetization of our U. S. Northeast Power business, an additional $68,000,000 non cash after tax charge to settle the termination of our Alberta PPAs, an after tax charge of $67,000,000 for costs associated with the acquisition of Columbia and certain other specific items. Q4 2015 included a $2,900,000,000 non cash after tax impairment charge related to Keystone XL as a result of the previous U. S.
Government's decision to deny our request for a presidential permit in November 2015 as well as certain other specific items. Excluding these items, comparable earnings for Q4 2016 rose by $173,000,000 to 626,000,000 dollars or $0.75 per share compared to $453,000,000 or $0.64 per share in the same period last year, a 17% increase on a per share basis. Turning to our business segment results at the EBITDA level on slide 25. In an effort to continuously improve our disclosure, we have split natural gas pipelines into 3 separate segments under the inventive monikers of Canadian, U. S.
And Mexico Natural Gas Pipelines. There are no changes to our other two segments, Liquids Pipelines and Energy. In the Q4, comparable EBITDA from these five businesses of approximately $1,900,000,000 was $363,000,000 higher than the approximate $1,500,000,000 reported for the same period in 2015. The increase was largely driven by the following factors: U. S.
Natural gas pipelines EBITDA of $569,000,000 increased by $281,000,000 mainly due to the acquisition of Columbia on July 1, 2016, and higher ANR transportation revenues resulting from higher rates went into effect on August 1, 2016, as part of a rate settlement. Mexico Natural Gas Pipelines EBITDA of $120,000,000 increased by $69,000,000 due to incremental earnings from Topolobambo and Mazatlan, which began collecting revenue in July December 2016, respectively. Energy EBITDA of $305,000,000 increased $35,000,000 primarily as a result of a higher contribution from Western Power due to an increase in realized prices and termination of the Alberta PPAs, as well as higher earnings from natural gas storage due to an increase in realized gas storage spreads. 4th quarter 2016 energy EBITDA included the $97,000,000 contribution from our U. S.
Northeast power assets, similar to the amount reported for the same period in 2015. As assets held for sale, they will continue to contribute to comparable earnings and funds generated from operations until the sales are completed in 2017. And finally, a $49,000,000 year over year reduction in net corporate costs as 2015 included a portion of our corporate restructuring charges that were recovered through tolling mechanisms. These variances were partially offset by a $34,000,000 decline in liquids pipelines as a result of the net effect of lower volumes on Market Link and higher volumes on Keystone and a $37,000,000 decline in Canadian Natural Gas Pipelines, primarily due to flow through items that did not have an impact on net income. As outlined in our quarterly news release, net income for the NGTL system increased $16,000,000 in the 4th quarter compared to the same period last year, mainly due to a higher investment base, while net income for the Canadian Mainline increased $2,000,000 due to higher incentive earnings, partially offset by a lower investment base.
Now, turning to the other income statement items on slide 26. Depreciation and amortization of $514,000,000 in the 4th quarter increased by $62,000,000 largely due to the acquisition of Columbia, increased depreciation rates on ANR as a result of its rate settlement and new facilities being placed into service. Interest expense of $542,000,000 increased by $162,000,000 compared to the same period in 2015, mainly due to debt assumed as part of the Columbia acquisition, draws on the acquisition bridge facility and new long term debt issuances primarily used to fund our capital program, partially offset by debt maturities. Allowance for funds used during construction or AFUDC, which is now included as a separate line item rather than part of interest and other income was essentially unchanged year over year. Finally, comparable income tax expense of $211,000,000 in Q4 2016 was $24,000,000 less than last year.
The decrease was mainly due to a change in the proportion of income earned between Canadian and foreign jurisdictions and lower flow through taxes in 2016 on Canadian regulated pipelines, partially offset by higher pre tax earnings in 2016 compared to 2015. Looking forward, we expect the effective tax rate for 20172018 to be in the high teens to 20% range, excluding the Canadian Motor Regulated Entities and AFUDC on Energy East and Mexico pipelines. Now moving to cash flow and distributable cash flow coverage ratios on Slide 27. Comparable funds generated from operations of approximately $1,400,000,000 in the 4th quarter increased by $196,000,000 or 16% when compared to the same period in 2015. The increase was primarily due to higher comparable earnings.
For the 4th quarter, comparable distributable cash flow was 9 $64,000,000 or $1.16 per common share compared to $797,000,000 or $1.13 per common share in 2015. Maintenance capital expenditures were $357,000,000 in the 4th quarter, similar to the level of spend last year. This amount includes $142,000,000 related to our Canadian regulated natural gas pipelines, which is consistent with 2015 and reflected in the NGTL and Canadian mainline rate basis and net income. Maintenance capital of $143,000,000 on our U. S.
Natural gas pipelines was up $25,000,000 year over year and primarily related to ANR. These expenditures are also reflected in rates under ANR's recent settlement. For full year 2016, distributable cash flow was approximately $3,700,000,000 or $4.83 per common share, resulting in a very strong DCF coverage ratio of 2.1 times. Turning now to where we are today and our outlook through 2020, I'll start by highlighting that we have built a business that is resilient and well positioned to prosper through all phases of the economic cycle. Our $88,000,000,000 of high quality blue chip assets are almost entirely made up of regulated or long term contracted assets.
We have financed these assets with long term capital, effectively locking in a margin between secure revenues and our largest cost of doing business, the cost of money. Fundamental to that is our A grade credit rating. It allows us to continuously access sizable amounts of capital across the term security and market spectrum at a lower cost than many of our competitors. We also believe in the simplicity and understandability of our corporate structure as evidenced by our long standing aversion to unwarranted complication. That said, we do employ alternative approaches to financing where it makes sense, including the use of TC PipeLines LP, which has served both as an important funding vehicle for TransCanada's growth and generated an average annual return for its unitholders of 14% since 1999.
Turning now to our growth program, where we are advancing an industry leading $23,000,000,000 portfolio of near term financially secured projects. It includes $19,000,000,000 of natural gas pipeline projects primarily related to Colombia and GTL in Mexico, $2,000,000,000 of liquids pipelines projects in Alberta, including Grand Rapids, Northern Courier and White Spruce and $2,000,000,000 of power projects at Napanee and Bruce Power. All are underpinned by regulated business models or long term contracts. We have invested $5,800,000,000 in these projects to date with the remainder to be largely spent over the next 3 years. As they enter service, they are expected to generate significant growth in earnings and cash flow.
Obviously, a program of this magnitude will require a significant amount of capital over the next few years, but we believe our needs are manageable. Finally, as Russ highlighted, we believe we are well positioned to deliver on an expected annual dividend growth rate at the upper end of an 8% to 10% range through 2020. That growth is expected to be underpinned by per share earnings and cash flow growth and therefore we expect to maintain our very strong coverage ratios going forward. I'll expand on our outlook in each of these areas in a few minutes. But before I do, I want to spend a couple of minutes on the key commercial and financial variability From a volume perspective, the vast majority of our business is underpinned by cost of service regulation or long term take or pay contracts.
As a result, we have relatively modest volumetric risk. Where it does exist is found in 2 places. The first is on the southern end of Keystone between Cushing, Oklahoma and the U. S. Gulf Coast on what we refer to as Market Link.
A sizable portion of the volumes that flow on this portion of the line are underpinned by shorter term contracts or move on a spot basis. This line was originally built in anticipation of moving long term contracted Keystone XL volumes. If Keystone XL were to proceed, it would significantly reduce volumetric risk on market link. And second, you can expect to see some variability at Bruce Power as a result of plant availability, which will fluctuate as Bruce performs work under the life extension agreement with the Ontario IESO. That said, we are not exposed to any commodity price risk as all of the power produced by the facility is sold to the ISO at a fixed price that escalates over time under the refurbishment agreement, which extends to 2,064.
Turning now to the few elements of our portfolio where we continue to have commodity price risk. Our exposure in this area has been substantially reduced as a result of our decision to terminate the Alberta PPAs and sell our U. S. Northeast power assets. Once the monetization of our U.
S. Northeast power business is completed, our consolidated commodity price exposure will largely be limited to our energy business in Alberta, where we own 4 40 megawatts of merchant gas fired cogeneration and 118 Bcf of unregulated natural gas storage capacity. While we contract forward in both instances, on an unhedged basis, a $1 change in power prices in Alberta would equate to less than a $2,000,000 change in EBITDA, while a $0.10 change in gas storage spreads would result in a $9,000,000 change in EBITDA. On the counterparty side, our Canadian Natural Gas Pipeline business is sheltered from the impact of any counterparty defaults under the regulatory compact compact subject to a prudency standard to manage our business in conjunction with the terms set out in our tariffs. In the U.
S, our natural gas pipeline shipper complement has historically been largely compromised of LDCs and other industrial customers. That has evolved more recently with a growing amount of capacity, particularly on our Columbia expansion projects and ANR being contracted for by lower rated producers. We do, however, take comfort in the fact that we are connecting some of the lowest cost, most prolific reserves in North America through our highly competitive transportation paths to liquid hubs in premium growing markets. In many cases, shippers have posted meaningful collateral in support of our adding needed expansion capacity. Moving to interest rates.
I mentioned earlier that we purposely finance our long term assets with long term capital. As such, over the past couple of years, we have taken the opportunity to extend the average term of our debt in this historically low interest rate environment. Today, aside from the remaining US3 $700,000,000 floating rate Columbia Acquisition Bridge facility, which we expect to fully retire upon closing of the Northeast U. S. Northeast power asset sales.
Over 90% of our debt is fixed rate in nature with an average term of 17 years and an average coupon of 5.3%. If rates do rise, we have the ability to fully pass those increases along our Canadian Regulated Natural Gas Pipeline business as well as interest rate tracking mechanisms on certain of our longer dated projects. Furthermore, our operating cash flow is largely immune to interest rate movements. And in some circumstances, we could actually see a rising interest rate environment benefit earnings and cash flow as we would expect the allowed rates of returns on our regulated pipelines to track upwards, albeit on a lag basis. I would also add that as we evaluate investing in new projects, we incorporate a more normalized interest rate environment in our economics rather than assuming these unprecedented low levels will persist indefinitely.
Lastly, with respect to sensitivity to foreign exchange rates, today we have approximately US26 $1,000,000,000 of US dollar denominated assets, including our interests in Mexico. Those assets and their associated revenue streams are naturally hedged with US20 $1,000,000,000 of US denominated debt and the associated interest expense. This results in an approximate annual US1 $1,000,000,000 long after tax income position, which will grow as further U. S. Dollar denominated projects enter service.
We actively manage this residual exposure on a rolling 1 year forward basis. For purposes of this presentation, we have assumed an average Canadian U. S. Exchange rate in the low 130s through the end of the decade. Now turning to slide 30, which highlights our capital expenditure outlook over the next 3 years by business segment.
It includes approximately $17,000,000,000 that remains to be spent to complete much of our near term capital program, $3,800,000,000 of maintenance capital, dollars 600,000,000 of capitalized interest and debt AFUDC on our rate regulated projects, and $300,000,000 of development costs associated with medium to longer term projects including Energy East and our West Coast LNG projects. It does not include any amounts for Keystone XL as we continue to expense all costs associated with asset preservation and development. In total, it equates to approximately $22,000,000,000 over the 3 year period. As highlighted by the bars on the chart, much of that is weighted for the 1st 2 years in the forecast period with capital spending of approximately $9,400,000,000 in 20 17, dollars 8,300,000,000 in 20.18, followed by $4,000,000,000 in 20.19. Now turning to Slide 31, which outlines our current funding plans for our near term growth program.
The first column on this slide represents forecast cash outflows over the next 3 years. It includes aggregate capital expenditures over the 2017 to 2019 period of approximately $22,000,000,000 from the previous chart. In addition, we expect to close the acquisition of Columbia Pipeline Partners tomorrow for an aggregate amount of approximately $915,000,000 or CAD1.2 billion, bringing our total spend to approximately CAD23 billion between now and the end of 2019. Finally, we expect to pay approximately $8,500,000,000 in common and preferred share dividends as well as distributions to non controlling interest over this timeframe. This amount assumes our common share dividend continues to grow at the upper end of an 8% to 10% range annually over the forecast period.
In total, we see cash outflows of approximately $31,500,000,000 over the 3 year period. While this represents a sizable amount, we believe our funding needs are manageable and will be met through our predictable and growing internally generated cash flow as well as a variety of financing levers available to us across the capital spectrum. As you can see on the chart, the 2nd column or the green bar represents anticipated funds generated from operations, which are expected to total approximately $18,200,000,000 over the 3 year period. In addition, we expect a healthy portion of our dividends to be reinvested through our dividend reinvestment plan or DRIP. In July, we reinstated the issuance of common shares from treasury at a 2% discount under DRIP commencing with the 3rd quarter dividend.
This resulted in approximately $175,000,000 or 39 percent of common dividends being reinvested in common shares in each of the last two quarters. Assuming this rate of participation continues, we expect approximately $2,800,000,000 of common dividends to be reinvested in the company over the forecast period. This aligns well with our spending profile over the next few years and should provide a meaningful portion of the subordinated capital needed through a growth program of this magnitude. That leaves us with a net external funding requirement of approximately $10,500,000,000 over the 3 year period that we believe can be sourced through the broad suite of funding options we have available to us. They are outlined on the slide and included in the 3rd column.
We will continue to access the senior debt preferred share in hybrid markets in a manner that is consistent with achieving targeted A grade credit metrics in 2018, including minimum funds from operations to debt of 15% and maximum debt to EBITDA of 5 times. Achieving those metrics while holding the use of preferred shares in hybrid securities to approximately 13% or 14% of our capital structure leaves us with capacity to raise approximately $7,500,000,000 across these product lines as represented by the gray and burgundy bars on the chart. We anticipate approximately $2,000,000,000 coming from senior debt, our proportionate share of Bruce Power entity level financings, commercial paper and cash on hand. The remaining $5,500,000,000 is expected to be made up of preferred shares in hybrid securities, which currently make up 10% or 11% of our capital structure. As a reminder, preferred shares in hybrid securities attract 50% equity credit from the rating agencies.
That leaves approximately $3,000,000,000 over the 3 year period that is expected to be financed through portfolio management, including potential dropdowns to TC PipeLines LP and at the market or ATM equity issuance program or other sources. As highlighted previously, TC PipeLines LP remains a core element of TransCanada's strategy and future dropdowns of mature assets are expected to play a role in meeting our funding needs. We have a large inventory of MLP qualifying U. S. PIRC regulated pipelines.
We believe that the LP has the financial capacity to fund US1 $1,000,000,000 of dropdowns per year in the normal course. As we have highlighted in the past, the competitive cost of capital at the LP will help drive dropdown activity, thereby creating a win win scenario for TransCanada shareholders and LP unitholders. While there are currently no specific plans, we remain open minded towards further asset sales if attractive on an after tax basis to other alternatives. We have not factored in any project cost recoveries into these numbers as we continue to actively progress our slate of longer term opportunities. So turning now to the potential introduction of an at the market equity program.
Such a program would allow us to opportunistically issue common shares in a very cost effective, efficient manner and, as necessary, provide additional meaningful subordinated capital to support an A grade credit rating along with an $8,000,000,000 to $9,000,000,000 capital expenditure program in each of the next 2 years. These programs have been used extensively in the U. S. Market by many in our sector, including TC PipeLines LP, which has successfully raised approximately US330 million dollars of ATM equity 2014. Our use of an ATM program will be shaped by our spend profile as well as the availability and relative cost of the other funding mechanisms discussed.
So in summary, while our external funding needs are sizable, they are viewed as eminently achievable given the clear, accretive and credit supportive use of proceeds. Notably, with the dividend reinvestment plan, issuance of preferred shares and hybrid securities, LP dropdowns and the potential select use of an ATM program, we do not foresee a need for additional discrete equity to finance our current $23,000,000,000 portfolio of near term growth projects. Turning now to slide 32. In addition to the growth funding program I just outlined, we also have debt maturities of approximately CAD4.25 billion and CAD6.65 $1,000,000 that will be refinanced over the next 3 years. We consider this to be in the normal course.
2018 amount is elevated as a result of the US500 $1,000,000 of Columbia debt assumed as part of the acquisition that comes due in that year. From a liquidity perspective, we remain in excellent position with 3 well supported commercial paper programs backed by approximately $9,000,000,000 of undrawn committed credit facilities and our ongoing access to global capital markets. At December 31, 2016, we had approximately $1,000,000,000 of cash on hand and we continued to maintain significant capacity on all of our debt and equity shelves. Turning now to slide 33. This highlights our outlook for comparable EBITDA growth based on our existing asset portfolio, factoring in the sale of U.
S. Northeast Power and then including the $23,000,000,000 of commercially secured projects that are expected to enter service over the remainder of the decade. Russ provided an overview of this earlier, so my intent here is to provide a little more granularity on what contributes to the growth. As you can see on the left hand side of the chart, we generated approximately $6,600,000,000 of comparable EBITDA in 2016, a 12% increase over the $5,900,000,000 reported in 2015. Looking forward, we have removed the $525,000,000 of EBITDA generated by our U.
S. Northeast power assets in 2016 as we expect the sale of that business to be completed in first half twenty seventeen. On the growth side, we expect approximately $1,850,000,000 of incremental EBITDA from Colombia through the end of the decade. This represents a full year contribution from the underlying assets we acquired on July 1, 2016, as well as additional EBITDA expected to be generated as US7 $1,000,000,000 of expansion projects enter service and we realize US150 $1,000,000 of targeted cost synergies over the next 2 years. It does not include any amounts for future capital expansion projects or revenue benefits, both of which could add to this growth over the forecast period.
Similarly, it does not include the U. S. $100,000,000 of financing synergies that we expect to realize as they are reflected below EBITDA and other income statement line items. In other U. S.
Natural gas pipelines, we expect approximately $100,000,000 of additional EBITDA largely as a result of the full year impact from the A and R rate settlement that went into effect August 1, 2016, as well as slightly better performance from certain other U. S. Pipelines including Great Lakes. In Mexico, we see EBITDA growing by $450,000,000 which would bring the total from this business to approximately CAD700 1,000,000 consistent with the US575 million dollars we forecast in November when we decided to maintain our full ownership interest in the business. The increase is driven by a full year contribution from Topolobambo and Mazatlan, which began generating revenue in mid to late 2016, as well as the completion of 3 new pipelines in 2018, Tula, Villa de Reyes and Sur de Texas.
Next, Canadian Natural Gas Pipelines add approximately $200,000,000 of incremental EBITDA as a result of the significant expansion program on the NGTL system, partially offset by the impact of depreciation of the investment basis of both NGTL and the Canadian Mainline. In Liquids Pipelines, EBITDA is expected to grow by approximately $300,000,000 as we complete Northern Courier, Grand Rapids and White Spruce. And finally, energy EBITDA is also expected to grow by approximately $300,000,000 due to the addition of Napanee and a higher contribution from Bruce Power, largely as a result of increases in the price received for power under the life extension agreement. So in total, we see EBITDA growing by $2,700,000,000 between now and 2020, bringing the total to approximately $9,300,000,000 That represents an annual growth rate of approximately 10% between 2015 2020. To the extent we capture additional investment opportunities or identify revenue enhancements or operating efficiencies from our existing base businesses, that growth rate could be augmented over the forecast period.
So turning now to slide 34. While this slide is quite busy, the message is important as it highlights the long life nature and resiliency of our EBITDA and cash flow streams. When I introduced it at our Investor Day in November 15, in homage to my roots, I believe I affectionately refer to it as the Saskatchewan earnings cliff, as flat as the eye can see. Essentially, it illustrates that if we complete our $23,000,000,000 near term capital program and do nothing else but spend maintenance capital through 2025, we would generate approximately $8,400,000,000 of EBITDA in 2025 from regulated or long term contracted assets. Another $400,000,000 which is shown in the other variable line on the top of the chart in dark green will come from our remaining merchant energy business in Alberta and market facing assets such as the southern portion of Keystone and certain U.
S. Natural gas pipelines that are subject to recontracting risk over this timeframe. That said, as highlighted by Russ, we expect to continue to grow the business by capturing additional high quality, low risk investment opportunities over the forecast period and that is conceptually reflected in the Purple Wedge. It could include further expansions of our NGTL or Columbia systems, adding compression laterals to new projects in Mexico, additional regional liquids pipelines or contracted power plants along with 1 or more of our $45,000,000,000 of medium to longer term projects. By investing our discretionary cash flow after dividends and our debt capacity within the parameters of A grade credit metrics, we are positioned to continue to grow well beyond 2020.
If we can't find attractive opportunities in our core businesses and within our risk tolerances, we will look to accelerate the return of capital to shareholders either through increased dividends or by proportionally shrinking the balance sheet in line with A grade credit metrics. Turning now to slide 35. This slide provides our outlook for distributable cash flow coverage ratios and maintenance capital through 2020. As outlined in the chart on the left, given the forecasted growth in comparable EBITDA and cash flow, we expect distributable cash flow coverage ratios to remain robust and supportive of an expected annual dividend growth rate at the upper end of an 8% to 10% range through 2020. While our DCF coverage ratio is expected to drop to approximately 1.6 times in 2017, the decline is largely due to a temporary increase in maintenance capital as highlighted in the chart on the right.
Overall, we see normalized maintenance capital at approximately $1,100,000,000 per year, which equates to 1.5 percent of our gross plant property and equipment. However, we expect to spend an elevated $1,500,000,000 on maintenance in 2017, largely as a result of the work being done on NGTL and ANR. Recall that under ANR's recent rate settlement, we will invest US837 million dollars over the 2016 to 2018 period to enhance the efficiency and reliability of the system with the full amount reflected in higher rates. This is essentially growth capital that happens to be defined under GAAP. Approximately US350 $1,000,000 or CAD450 $1,000,000 of that amount is forecast to be spent in 2017 as depicted in the light blue colored box.
In addition, we see maintenance on our Canadian regulated systems running about $100,000,000 higher than normal in 2017 as a result of ongoing work on NGTL, which is included in a dark blue colored box. Again, any spend on NGTL or the Canadian Mainline is also reflected in the respective rate basis and net income. So while our coverage ratio declines this year, it returns to approximately 2.0x by 2020 as maintenance capital returns to more normal levels and cash flow growth accelerates as $23,000,000,000 of commercially secured projects enter service. So, in closing, I would offer the following comments. Our diverse portfolio of high quality long life assets generated very strong comparable results in 2016.
The acquisition of Columbia as well as certain other initiatives over the past year represent truly transformational events for TransCanada. Today, we are advancing an industry leading $23,000,000,000 near term capital program and have 5 distinct platforms for future growth in Canadian, U. S. And Mexico natural gas pipelines, liquids pipelines and energy. Our overall financial position remains strong supported by our A grade credit ratings.
We remain well positioned to fund our near term capital program through resilient and growing internally generated cash flow and strong access to capital markets on compelling terms. Our industry leading suite of critical energy infrastructure projects is expected to generate significant growth in high quality earnings and cash flow for our shareholders. That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook through 2020 beyond. That's the end of my prepared remarks.
I'll now turn the call back over to David for Q and A.
Thanks, Don. Just a reminder, before I turn the call over to the conference coordinator for questions from the investment community, we ask that you limit yourself to 2 questions. And if you have any additional questions, we'd ask you to please reenter the queue. With that, I'll now turn the call back to the conference
The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. Thanks for the comprehensive business update. Looking at Keystone XL, I see you filed again in Nebraska today with an expected completion in 2017. Can you give us an update on your assumptions around key work streams, including beyond the regulatory process, a timeline on commercial discussions and when you expect to complete that, as well as your cost estimates updated along with your engineering work and when you might be able to start construction?
Linda, it's Paul Miller here. I've got down here commercial discussions, cost estimate, time line. So I'll answer it all. And if I miss anything, please remind me. First course of action here is we are engaged with our shippers.
There's a lot of interest in Keystone XL as a result of the Presidential Memorandum. So we're working through the shipper group and they're working through their analysis. But a lot has changed since November 2015 when Keystone was denied the presidential permit. So it is going to take some time for these shippers to assess their volume commitment. There is a sense of urgency US8 $1,000,000,000 is our most recently prepared cost estimate.
I would anticipate we would look to refresh that sometime during 2017, but our cost estimate at this point is the US8 $1,000,000,000 And as far as the time line goes, we filed the Nebraska application for the route through Nebraska with the Public Service Commission today. That process could take the better part of 2017 to conclude. I would anticipate towards the end of 2017 into 2018, we would have the various permits that we would require. At that point, we would start to do some of the staging activities that you speak of. I would not anticipate we'd be ready for construction until well into 2018.
And that construction process although we're still going through the implementation planning right now is the better part of 2 years plus.
Okay. So if it's later into 2018, you'd miss one of those construction windows. So it would be okay. Just a follow-up maybe on just staying in the U. S.
On tax reforms. Has TransCanada started to run some sensitivities and scenarios around what might happen if interest expense deductibility and changes in deductibility of capital investments are implemented along with reductions in corporate tax rates and what the net effects might be on your business?
Linda, it's Don. The simple answer is no. We haven't run any quantitative sensitivities at this point in time. We're monitoring like everybody else. And to look at any of these things in isolation and versus what a package might ultimately look like in a phase in period is just really difficult.
So, as there's more definition put on how this play out, we'll start doing that. But, at this point, we're just in the monitoring phase.
Okay. Thanks. I'll jump back in the queue.
Okay. Thanks, Linda.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Good afternoon. Just looking at the financing plan, you talked about it being geared to maintaining the credit rating. And I think Don you mentioned 15% FFO to debt. I'm just wondering is that a discussion you've had with S and P? Or how do you think about the 15% versus the 18%
Yes. At this point, just looking back at what we've done here, we've added $11,000,000,000 of subordinated capital over the last year, changed the business position in our view substantially for the better by selling our merchant assets. And we see 95 plus percent EBITDA coming from regulated cost of service businesses going forward and achieving certainly 15% FFO to debt and 5 times debt to EBITDA in 2018. So, I guess, I'd best direct this at S and P as to how they would weigh the quants versus the qualitative side of this going forward. So, we're on track in 2018 to hit 15% and 5 times.
But I'll defer to discussions with S and P as to where they weigh the declines versus the qualitative.
Okay. And if I guess, I guess, just turn to the mainline and you've been as you've acknowledged in discussions with potential shippers, have you had any either formal or informal discussions with other parties who would likely be interested in this. And I guess I'm just wondering if you're you've assessed the risk on the intervention side just given what you've already seen on the much smaller Herbert LTF P service?
Robert, it's Karl. I understand your question. We have been keeping all of our customers up to date on kind of what we're thinking on what a load traction deal would look like. I'm expecting if we do come to agreement, and as Russ said, we're encouraged with the discussions, but we haven't come to agreement, I'm expecting we'd have more conversations with them. But yes, as you said, as we're experiencing with the smaller low traction rate in Saskatchewan, I would expect there would be some questions and some opposition to it in hearing.
And I believe that our any deal that we would strike with we would strike it with the idea of making it reasonable for regulators to see the benefits of the system. So we're willing to we're expecting some opposition if we do go forward and we're willing to put our case for it that it's good for the entire system.
The next question is from Rob Hope from Scotiabank. Please go ahead.
Yes, good afternoon. Just want to circle back on Keystone XL and just on your conversations there with shippers and the timeline there. Just want to get a sense of your understanding of the need, just given the fact that we also do have TMX on potentially on the go as well as Line 3. Are you looking to potentially be later on in the next decade to potentially accommodate TMX? Or do you see a need for a number of
pipelines? Hi, Rob. It's Paul here. I think there's various projects out there. They're in various stages of development and various degrees of uncertainty.
And I think it's important to remember that these pipelines or these proposed pipelines, they will serve different markets with different shipper groups. And it's not an industry led approach to pipeline capacity planning. So our business model answers the shippers' call and to what market they want to access. Shippers will make a call on the markets that they want to access with their supply. In the case of Energy East, for example, it's the Eastern Canadian refinery market, PADD 1 and PADD 3 and the international markets.
And in the case of Keystone, it's the Keystone excels the U. S. Gulf Coast. So our business model supports these choices that the shippers make that providing the secured access to the markets of their choice, and this is supported by them taking out long term take or pay contracts on our pipeline. So we will meet whatever our shipper group requirements are in regard to implementation of Keystone XL.
All right. That's very helpful. And then just looking at your long term EBITDA outlook, you did mention that potential revenue benefits of adding the Columbia system with your other gas systems could be additive. Or do you have any targets that you can share with us or timing of when you could start realizing revenue synergies between TransCanada and Columbia system?
It's Karl
again. Yes, we have obviously, we're working on that as we speak on how we can interconnect these systems and get flows going in between systems. We don't have any estimates right now. The reason we never published estimates to begin with is because they're kind of a sub they're 3 years out. They are not within the range of the initial $250,000,000 a year that we published.
They generally require some construction, they will require contracts over car customers. So we are working on that. We expect it to be we expect there to be some synergies there when we get these physical systems interconnected. But no, at this time, we haven't put out any number of what we expect to realize from
that. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Thank you. Good afternoon. Obviously, there's a pretty big wedge of EBITDA growth coming from the U. S. Gas pipelines really in the foreseeable future.
So I guess maybe the question is to Carl and is just what have you seen and what have you noticed in, I guess, the 1st 7 months post close of Columbia on just differences in customer behavior between those in the Marcellus and those in the Montney?
Andrew, this is Karl. It's an interesting question. Maybe I'll start by saying this. I guess what we found what I found in the Appalachian area is that the customers are far more willing to and far more comfortable with signing longer term contracts to create takeaway capacity. Obviously, you've probably followed our discussions with the producers out of the WCSB and that's something relatively new for them.
They have used to they've been very used to producing and selling into net and not having to market those volumes elsewhere, which I think is changing for them, which is why we're spending so much time trying to do some low traction deals. So I think one of the big difference is the attitude towards signing up for long term contract, the attitude towards backstopping of construction of gas pipelines and so forth is one of the bigger differences that I have seen between the two basins. Having said that, I think our customer base in the 2 basins is very much the same right now. When we look at NGTL, it's very much a producer driven system. When you look at the Columbia assets, probably about 46% now is producer driven, the rest is LDC.
So we have similar customers there, similar requirements to get their production out and so forth. So the main issue would be just a comfort level with taking the gas, moving it away from the production area into the market area and signing longer term contracts.
Okay. I appreciate that. And then maybe just sticking towards on the Marcellus and just the Eastern Triangle area. It's very noticeable that the volumes on the Alberta, Saskatchewan side, 2.9 is what you posted on an average basis through the year and then 4, 5 on the average of the system. So how do you think about just the changing nature of the mainline and the ability now to a greater degree to really move volumes around the Northeast and the compounding of opportunities that happen off that?
What are you seeing now that you're looking at this as a fully integrated system in the East?
Yes. I do look at
the East as being a fully integrated system. And I can tell you right now we're working very hard with customers out in the Northeast to market the mainline as part of their Northeast gas supply strategy. There's been severe difficulty putting new greenfield gas pipelines through the Northeast and into the New England, New York market area. And we think we have a great option to bring the gas up through Don and maybe through Chippewa or Niagara and then move that through our Mainline, eastern segment of our Mainline out to Iroquois or PNGTS as Russ was saying earlier in his speech and expanding those systems. Up.
I think the pipe in the ground right now is very valuable to these customers that need incremental supply. So that's one of the priority market areas that we have right now is talking to both the LDCs and load to market in the Northeast area and talking to the producers in Appalachia and WCSB and trying to match something through our mainline into the U. S. Northeast.
Okay. That's great. Thank you.
Thanks, Andrew.
Thank you. The next question is from Ben Pham from BMO. Please go ahead.
Good afternoon. Just on that last comment about moving gas potentially into the Northeast market through Iroquois central brownfield expansion. Is there any regulatory issues there with the buyer of that if you were to move gas during your contract?
I'm sorry, the regulatory issues with buyers moving gas under?
Just with some of the electricity distribution companies?
I don't think there is any regulatory issues. Clearly, the companies we're dealing with right now, and we've actually gone down quite far down the path of some companies. Clearly, they would have to get their own public utility commissions approval than a big supply deal, long term supply deal that they would do. But I don't think those approvals aren't unusual for any type of transaction like that. And they're certainly not approvals that are needed just because they are using the Canadian mainline assets visavis a local U.
S. Asset. So I guess the short answer would be no. I have not run up against any regulatory impediment to doing a transaction like that yet.
Okay. And then on the there's some commentary about the qualitative impact of merchant power assets. And I'm just wondering, there's no commentary about additional merchant exposure going forward. It looks like over time, you could be almost sitting at pretty minimal commodity exposure. Are you your appetite for merchant power, is that would you say it's very low right now at the moment?
Hi, it's Sebastien. I can maybe take a shot at that at the corporate level. At the current time, we see an opportunity to migrate our EBITDA to a more predictable stream. We see that the opportunity to invest our capital for the coming next number of years, dollars 23,000,000,000 of it that can be invested in less volatile streams. So for the foreseeable future, that is the direction that we'll be going.
As we said, we understand commodity risk very well. We've managed it extraordinarily well in the past, But it's not something that we see a need to be involved with to any great extent for the foreseeable future.
It's Bill here. Ben, I'll just add to Russ' comments and say that you shouldn't ignore that we have managed and continue to grow our energy platform in ways that aren't structured in the merchant manner. So the growth at Bruce, the growth at Napanee and some of the other activities that we've undertaken, we would expect to continue to try to land opportunities like that in the regions in which we operate.
The next question is from Ted Durbin from Goldman Sachs. Please go ahead.
Thanks. Just on Ketan XL, you before said that you were looking for around $1,000,000,000 of EBITDA and the $8,000,000,000 of capital. Is that still the kind of return you're looking for on Keystone?
Yes. Ted, it's Paul here. The $8,000,000 is our previous estimate. It was completed, I believe, back in 2014. So that's our current estimate.
And then on the EBITDA, we are in the process now of firming up our commercial support in our commercial terms. So it's a little premature to provide any guidance on the EBITDA front, but we would anticipate trying to achieve what type of returns we typically achieve on these type of projects in the 7% to 9% range. Given the passage of time and some of our historical cost sharing agreement with the shippers, I would anticipate being at the lower end of that range. But we don't have any EBITDA guidance at this point.
And Ted, as you know, the range Paul is referring to that would be after tax return on total capital as opposed to a return on equity, if you will.
Yes. Understood. That's helpful. And then could you speak to the ability, I was kind of mentioned in the Presidential memorandum of sourcing U. S.
Steel to build it, where you are with what actually you have in inventory that you can use, kind of how you'll work through the mechanics of that?
Yes. It's Paul again. We're aware of the Presidential Memorandum and we understand the Secretary of Commerce is charged with implementing the provisions of the memorandum. We don't have the visibility today. We'll analyze the plan when it's released to determine any impact it may have on Keystone XL.
Okay. That's it for me. Thank you.
Thanks, Ted.
Thank you. The next question is from Robert Catellier from CIBC World Markets. Please go ahead.
Yes. Hi. I just have a couple of follow ups on Keystone XL. Maybe you can provide a little bit more color on the where you are with the shippers, specifically whether or not you anticipate a need for an open season? And in addition, how are you providing clarity to the shippers on the toll while at the same time protecting returns when there is a little bit of uncertainty on in terms of what the U.
S. Administration might want in terms of profit sharing?
Rob, it's Paul here. First of all, as far as where we're at with the shippers,
again,
I appreciate that it's a lot has occurred since November 2015. The shippers, they have a different price environment. They're operating in a different supply forecast. There's different competition out there. So the shippers are going through their own analysis.
We are providing them with the detail we do have around Keystone XL as well as our commercial terms. And ultimately, we will look to amend the contracts we do have in place To the extent that we have additional capacity available on Keystone XL, we would look to go to an open season. At this point, we don't have any plans at that point at this point. In regard to some of the other matters that you spoke of, we're not aware of any additional terms that might be required for us to achieve the presidential permit. We currently are working through the regulatory process as we understand it and we'll work with the administration to that end.
And we'll continue to work with the shippers. And to the extent that something does occur, we'll provide some visibility at that point.
Okay. And then on the mainline Carl, maybe you can give a little bit more color as to what the approach would be for the LDCs and how you position any new long term fixed price agreement with the on the mainline and how you would position that to be successful in the hearing?
Yes, sure. I think there's 2 real main benefits that I see to the system from doing a longer term deal. Number 1, the eastern LDCs have been very clear and vocal. And part of that actually the LDC settlement was us facilitating a change in how they procure natural gas. They have wanted very much to procure natural gas at dawn closer to the market hub and not have to go back to the supply hubs to get it.
They are our traditional ship long haul shippers. So they have been de contracting. They have already de contracted before we even did the settlement. They have de contracted almost 1.3 feet a day since the LDC settlement went into place. And so they sent a very strong message to the market that they're waiting to purchase at dawn, which is fine.
And TransCanada has facilitated that through the LDC settlement. Our goal is to not let that pipeline capacity remain empty with their exit. Our goal is to move gas. And we believe that we can make the case that this is incremental movement as gas that wouldn't happen otherwise from this particular deal. And that equates to incremental revenue on the system, helps everybody working on the system.
The LDCs out east get more gas supply heads on to compete. The other shippers on the mainline get extra revenue to help shoulder the burden of the cost of the mainline. So that's our basic argument. And it's clearly an economic argument that we are replacing volumes that we believe the LDCs have exited and they are with no intention of going back and we will replace it with producer volume. So I'm quite certain that that economic argument will be quite compelling.
Yes. That's a fulsome answer. I'm just a little curious as to how you navigate the issue of term given there was so much pushback from the producers on the what I thought was a reasonable term expectation in the first place?
The term is something that frankly, in terms of that we have been discussing for a very long time. Again, as I talked about earlier, the producers in the WCSB are not all that familiar and not all that comfortable with taking longer term contracts. I think the mainline is basically the year to year term. What we are talking with the producers, and again, I have to remind you that we have not come to an agreement. What we are talking to them a 10 year term with various off ramps if penalties are paid, so to speak.
The mainline is essentially everything else in the main is running from year to year. So I think that the term that we got is actually quite compelling for a mainline shipment.
Okay. Thank you very much.
Thanks, Rob.
Thank you. The next question is from Faisal Khan from Citigroup. Please go ahead.
Hi, thanks. It's Faisal from Citi. Just two questions. The first one is on the approval for the pipelines on the Columbia system, I guess, WB Express, Mountain Air Express, Gulf Express. How does the lack of a quorum right now at
the FERC
affect the in service date of these pipelines?
And then
I have a follow-up.
Well, right now, I think we are fine. We weren't expecting the decisions on those particular pipelines to come imminently anyways. I would have to say where we are, we are looking anxiously, as I know everybody else in the industry is, at the replacement to get a quorum back on FERC. And we are hoping that it will be dealt with expeditiously. But right now, we don't consider that to be on the critical path.
We got the permits we need that are on the critical path right now and not the Leach Express and the Rain Express. But having said that, we are, like most others in the industry watching anxiously to see how the process will unfold to get corn back.
Okay. Got you. And then last question. On the CPPL transaction, were you able to get the 100% or do you not need the 100% to close the transaction?
It's Don here. We reached the core and we needed to get that over the finish line.
Okay, understood.
Great. Thanks, Faz.
Thank you. There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Monera.
Great. Thanks very much. We very much appreciate your interest in TransCanada and your patience this afternoon. Again, I know our remarks were a little longer than normal, but hopefully, you found the incremental information useful. We look forward to speaking to you again in the not too distant Bye, Praful.
Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.