TC Energy Corp (TRP) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 fourth-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 fourth-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; Karl Johannson, 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 fourth-quarter financial results as well as our business outlook. With respect to our outlook, similar information would've 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 investor section under the heading Events and Presentation.

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 two 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 US Securities Exchange Commission.

Finally, during this presentation we will 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. 2006 (sic - see press release "2016") was truly a transformational year for us here at TransCanada as our portfolio of high quality energy infrastructure assets performed very well. Our long-term strategy of financial discipline enabled us to undertake unprecedented growth that will reward our shareholders for many more years to come.

Our $13 billion 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 one 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 common -- outstanding publicly held common units of Columbia Pipeline Partners for $17 per common unit or approximately $950 million. I'm pleased to report that earlier today, the Columbia Pipeline Partners unit holders 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 CAD13 billion of projects were near-term commercially secured growth portfolio. The largest addition came through our Columbia acquisition, which included over CAD7 billion in long-term contracted expansion and modernization projects. We also added two additional natural gas pipelines projects in Mexico that will see us invest an additional $1.9 billion in that region as well as ongoing expansions of our NGTL system.

To help fund the Columbia acquisition, we decided to sell our US Northeast Power Business and subsequently entered into two separate sales agreements, which are expected to close in the first half of 2017. We are also in the process of monetizing our US Northeast Power Marketing Business. In total we expect to realize approximately $3.7 billion, which will be used to retire the remainder of our acquisition bridge facility.

During the year we raised approximately CAD11 billion 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 fourth-quarter and full-year 2016 financial results. Excluding certain specific items, comparable earnings for the fourth quarter 2016 were CAD626 million or CAD0.75 share, an increase of CAD173 million or CAD0.11 per share over the same period last year. Comparable EBITDA increased CAD363 million to approximately CAD1.9 billion, while that comparable funds generated from operations were CAD1.4 billion and were 16% higher compared to the fourth quarter of 2015.

For the full-year, comparable earnings were CAD2.1 billion or CAD2.78 per share, an increase of CAD353 million or CAD0.30 per share over 2015. This equates to approximately 12% increase on a per-share basis. Comparable EBITDA increased CAD739 million to approximately CAD6.6 billion while comparable funds generated from operations exceeded $5 billion 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 CAD0.625 per common share, which is equivalent to CAD2.50 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've invested approximately CAD70 billion 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 CAD88 billion 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 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 CAD23 billion 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 CAD45 billion 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's focused on three core businesses in three core geographies. We own and operate one of the world's -- or one of North America's largest transmission -- natural gas transmission systems with over 90,000 kilometers, or 56,000 miles of pipeline, that connect the fastest-growing [supply] basins to the key markets. Today, our pipelines transport more than 25% of the daily North American demand.

We are also the continent's largest provider of natural gas storage, with 653 billion cubic feet of capacity. In liquids, our 4,300 kilometer Keystone system transports 545,000 barrels of crude oil per day, or approximately 20% of Western Canadian exports to key refining markets in the US 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 US 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 emission-less power, including nuclear, wind and solar. Our remaining capacity consists of high-efficiency natural gas-fired generation facilities.

Looking forward, our CAD23 billion of near-term commercially-secured projects will expand our footprint across North America. It includes approximately CAD19 billion 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 are also developing a regional liquids pipeline system in Alberta with CAD2 billion of projects expected to enter service by 2018.

And finally we are advancing another CAD2 billion of power projects including the 900 megawatts Napanee gas-fired plant in Ontario as well as the initial work required at Bruce Power as part of the multi-billion dollar life extension agreement with the Ontario government. We've invested approximately CAD6 billion in these projects to date with the remainder of these 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 expansive North American footprint that we now enjoy. So starting with Columbia, we spent the last six months integrating their operation with our US pipeline business. That process has gone extremely well and we expect to realize a significant portion of the $250 million 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 $7.1 billion 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 two of the larger initiatives the $1.4 billion Leach XPress project and the $400 million Rayne XPress project. Both of those are expected to be completed by the end of this year. In total, we expect approximately $2.3 billion 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 billion cubic feet a day to 30 billion cubic feet a day by the end of the decade. With its highly connected network of receipt and delivery points and competitive paths-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 US 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 that will include projects to move gas within the basin as well as westward onto ANR and onto Midwest markets, northward into Eastern Canada and then on to the Canadian Mainlines Iroquois and Portland pipelines for service into the US north to east or even southward to the US Gulf Coast to service domestic markets, LNG markets and potentially export to Mexico.

Moving to the next slide, on this map you can see our US 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 US pipeline business could benefit from a number of other developments. First of all, the ANR settlement will result in higher contributions in 201. Of note that settlement included CAD837 million 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 US natural gas pipeline 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 Dawn. The Iroquois and our Portland natural gas pipeline systems provide relatively easy expansion opportunities into the New York and New England markets, with green field projects in this region facing a number of challenges on permitting, brown field expansions on these systems could provide competitive paths to markets.

Before I leave the US pipelines I'd also like to reiterate that 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 along the lowest-cost sources of supply in North America. Although development has been a little bit slower than in the Marcellus and Utica, it's evident that this resource base is very similar primarily in the areas of the Montney, Duvernay, Deep Basin, Horn River and Liard areas. Each has proven to be quite prolific with recoverable reserves in these regions having quadrupled over the last -- 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 11.3 billion cubic feet a day, up from 11 billion 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 CAD5.4 billion of new infrastructure through 2020 on the NGTL system to move that production to market. Approximately CAD1.6 billion is planned to be placed in service in 2017, improving their [feed] 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 6.5 billion 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 return on equity that are at the upper end of our allowed ranges. Our multi-year LDC settlement, which went into effect in 2015, has certain elements extending into 2030, effectively creating long-term stability for that system. Today the system moves between 2.5 billion and 3 billion 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 CAD300 million of expansion facilities to move growing amounts of US 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 2030, under the LDC settlement.

At the same time the western portion of the system, which will see its investment base continue to appreciate, will continue to play an important role, as I said, in linking Western Canada and getting gas supply to markets. Although we haven't concluded a load attraction deal at this time, we are 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 four 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 billion. The $600 million Tula pipeline and the $550 million Villa de Reyes pipelines are both expected to enter service in early 2018. The $2.1 billion Sur de Texas offshore pipeline is anticipated to be in service in late 2018. We hold a 60% interest in that joint venture and will 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 US 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 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 1.4 billion 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 CAD1 billion.

Recent capital additions to the system have created optionality for us and to our shippers by improving access to more refining markets in the US Gulf Coast. Ultimately, this is expected to provide opportunities to move increased volumes, including US shale oil volumes on the southern portion of the line in the future. We are also advancing a number of Intra-Alberta liquids 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 CAD200 million 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 fourth quarter 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. That resulted in a non-cash charge related to the carrying value of those credits.

The sale of our US Northeast Power Business also continues to progress and we expect those transactions to close in the first half of 2017. Once completed we will have substantially reduced 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 CAD765 million of EBITDA -- or they did generate about CAD765 million of EBITDA in 2016, a number that we expect to grow to more than CAD1 billion 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 six in approximately 2020. Looking forward, we will continue to assess opportunities in the renewable and gas-fired generation markets across our geographies as they come available.

Before I leave energy, just a few additional comments on Bruce Power, where we've been very pleased with its operating and 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 2064 will begin, as I said, with unit six in 2020 and continue through 2033. This CAD6.4 billion investment will see us invest approximately CAD1.1 billion between now and the end of the decade with the remainder being invested between 2020 and 2033.

So in summary, today we are advancing a CAD23 billion 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 CAD5.9 billion in 2015 to approximately CAD9.3 billion 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 or extend our dividend growth outlook through 2020 and beyond.

Finally a few words on our CAD45 billion portfolio of medium- to long-term projects. We expect to continue to develop these long-term options. It includes our two West Coast LNG projects that are not now fully permitted, liquefaction facilities associated with those pipelines are also fully permitted and we are awaiting final investment decision's 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 CAD900 million. The portfolio also includes our two large-scale liquids pipeline projects. We continued to advance the Energy East project through the permitting process in Canada and currently we are waiting 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 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 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 US 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 US energy security. It will create significant employment for many US 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 who will provide more details on our fourth-quarter and our longer-term financial outlook. Don, over to you.

Thanks, Russ, and good afternoon, everyone. During the next 25 to 30 minutes my intent is to briefly touch on the fourth-quarter results and 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 2030. First, the highlights of our fourth-quarter 2016 financial results.

As outlined in our financial highlights news release issued earlier today, we've reported a net loss attributable to common shares in the fourth quarter of CAD358 million, or CAD0.43 per share, compared to a net loss of CAD2.5 billion or CAD3.47 per share for the same period in 2015. Our results included a non-cash after-tax loss of CAD870 million related to the monetization of our US Northeast Power Business, an additional CAD68 million non-cash after-tax charge to settle the termination of our Alberta PPAs, an after-tax charge of CAD67 million for costs associated with the acquisition of Columbia and certain other specific items.

Fourth-quarter 2015 included a CAD2.9 billion non-cash after-tax impairment charge related to Keystone XL, as a result of the previous US 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 fourth-quarter 2016 rose by CAD173 million to CAD626 million or CAD0.75 per share compared to CAD453 million or CAD0.64 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 three separate segments under the inventive monikers of Canadian, US and Mexico Natural Gas pipelines. There are no changes to our other two segments Liquids Pipelines and Energy. In the fourth quarter, comparable EBITDA from these five businesses of approximately CAD1.9 billion was CAD363 million higher than the approximate CAD1.5 billion reported for the same period in 2015.

The increase was largely driven by the following factors. US natural gas pipelines EBITDA of CAD569 million increased by CAD281 million, mainly due to the acquisition of Columbia on July 1, 2016 and higher ANR transportation revenues resulting from higher rates that went into effect on August 1, 2016, as part of a rate settlement.

Mexico Natural Gas Pipelines EBITDA of CAD120 million increased by CAD69 million due to incremental earnings from Topolobampo and Mazatlan, which began collecting revenue in July and December 2016, respectively. Energy EBITDA of CAD305 million, increased CAD35 million, 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 for natural gas storage due to an increase in realized gas storage spreads.

Fourth-quarter 2016, energy EBITDA included a CAD97 million contribution from our US 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 CAD49 million 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 positive variances were partially offset by a CAD34 million decline in liquids pipelines as a result of the net effect of lower volumes on Marketlink and higher volumes on Keystone and a CAD37 million 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 CAD16 million in the fourth quarter compared to the same period last year mainly due to a higher investment base, while net income for the Canadian Mainline increased CAD2 million 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 CAD514 million in the fourth quarter increased by CAD62 million, 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 CAD542 million increased by CAD162 million 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 the part of interest and other income was essentially unchanged year-over-year.

Finally, comparable income tax expense of CAD211 million in fourth-quarter 2016 was CAD24 million 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 2017 and 2018 to be in the high-teens to 20% range excluding the Canadian government-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 CAD1.4 billion in the fourth quarter increased by CAD196 million, or 16% when compared to the same period in 2015. The increase was primarily due to higher comparable earnings. For the fourth quarter, comparable distributable cash flow was CAD964 million or CAD1.16 per common share, compared to CAD797 million or CAD1.13 per common share in 2015.

Maintenance capital expenditures were CAD357 million in the fourth quarter, similar to the level of spend last year. This amount includes CAD142 million 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 CAD143 million on our US natural gas pipelines was up CAD25 million year-over-year and primarily related to ANR. These expenditures are also reflected in rates under ANRs recent settlement.

For full-year 2016 distributable cash flow was approximately CAD3.7 billion or CAD4.83 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 will 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 CAD88 billion 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 unit holders of 14% since 1999.

Turning now to our growth program, where we are advancing an industry-leading CAD23 billion portfolio of near-term commercially-secured projects. It includes CAD19 billion of natural gas pipeline projects, primarily related to Columbia, NGTL and Mexico, CAD2 billion of liquids pipelines projects in Alberta, including Grand Rapids, Northern Courier and White Spruce, and CAD2 billion of power projects at Napanee and Bruce Power. All are underpinned by regulated business models or long-term contracts.

We've invested CAD5.8 billion in these projects to date, with the remainder to be largely spent over the next three 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 at each of these areas in a few minutes, but before I do I want to spend a couple minutes on the key commercial and financial variability factors we face, the sensitivity to them and the steps we have taken to mitigate them. From a volume perspective, the vast majority of our business is underpinned by a 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 two places.

The first is on the southern end of Keystone between Cushing, Oklahoma, and the US Gulf Coast, on what we refer to as Marketlink. 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 Marketlink.

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 their life extension agreement with the Ontario IESO. That said, we are not exposed to any commodity price risk if 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 2064.

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 US Northeast Power assets. Once the monetization of our US Northeast Power Business is completed, our consolidated commodity price exposure will largely be limited to our energy business in Alberta where we own 440 megawatts of merchant gas-fired co-generation and 118 bcf of unregulated natural gas storage capacity. While we contract forward in both instances, on an unhedged basis a CAD1 change of power prices in Alberta would equate to less than a CAD2 million change in EBITDA, while a CAD0.10 change in gas storage spreads would result in a CAD9 million 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, subject to a prudency standard to manage our business in conjunction with the terms set out in our tariffs. In the US, our natural gas pipeline shipper complement has historically been largely comprised of LDCs and other industrial customers. That has evolved more recently with the 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 supportive 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've taken the opportunity to extend the average term of our debt in this historically low interest rate environment. Today, aside from the remaining $3.7 billion floating rate Columbia acquisition bridge facility, which we expect to fully retire upon closing of the Northeast -- US 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 in 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 [our odd] 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 $26 billion of US dollar-denominated assets, including our interests in Mexico. Those assets and their associated revenue streams are naturally hedged with $20 billion of US-denominated debt and the associated interest expense. This results in an approximate annual $1 billion long US dollar after-tax income position which will grow. It's for the US dollar-denominated projects enter service. We actively manage this residual exposure on a rolling one-year forward basis. For purposes of this presentation we have assumed an average Canadian/US exchange rate in the low CAD1.30s through the end of the decade.

Now turning to slide 30, which highlights our capital expenditure outlook over the next three years by business segment. It includes approximately CAD17 billion that remains to be spent to complete much of our near-term capital program, CAD3.8 billion of maintenance capital, CAD600 million of capitalized interest and debt AFUDC on our rate-regulated projects and CAD300 million 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 cost associated with asset preservation and development.

In total, it equates to approximately $22 billion over the three-year period. As highlighted by the bars on the chart, much of that is weighted for the first two years in the forecast period with capital spending of approximately CAD9.4 billion in 2017 and CAD8.3 billion in 2018, followed by CAD4 billion in 2019.

Now turning to slide 31, which outlines our current funding plans for our near-term growth program. The first column on the slide represents forecast cash outflows over the next three years. It includes aggregate capital expenditures over the 2017 to 2019 period of approximately CAD22 billion from the previous chart. In addition, we expect to close the acquisition of Columbia Pipeline Partners tomorrow for an aggregate amount of approximate $915 million, 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 CAD8.5 billion in common and preferred share dividends, as well as distributions to non-controlling interests over this time frame. 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 CAD31.5 billion over the three-year period.

So 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 second column, or the green bar, represents anticipated funds generated from operations, which are expected to total approximately CAD18.2 billion over the three-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 third quarter dividend. This resulted in approximately CAD175 million, or 39%, of common dividends being reinvested in common shares in each of the last two quarters.

Assuming this rate of participation continues, we expect approximately CAD2.8 billion 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 CAD10.5 billion over the three-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 third column.

We will continue to access the senior debt preferred share and 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 five times. Achieving those metrics while holding the use of preferred shares and hybrid securities to approximately 13% or 14% of our capital structure leaves us with capacity to raise approximately CAD7.5 billion across these product lines as represented by the gray and burgundy bars on the chart.

We anticipate approximately CAD2 billion coming from senior debt, our proportionate share of Bruce Power entity-level financings, commercial paper and cash on hand. The remaining CAD5.5 billion is expected to be made up of preferred shares and hybrid securities, which currently make up 10% or 11% of our capital structure. As a reminder, preferred shares and hybrid securities attract 50% equity credit from the rating agencies. That leaves approximately $3 billion over the three 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 and mature assets are expected to play a role in meeting our funding needs. We have a large inventory of MLP qualifying US FERC-regulated pipelines and believe that the LP has the financial capacity to fund $1 billion 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 drop-down activity thereby creating a win-win scenario for TransCanada shareholders and LP unit holders. 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 CAD8 billion to CAD9 billion capital expenditure program in each of the next two years.

These programs have been used extensively in the US market by many in our sector, including TC Pipelines, LP, which has successfully raised approximately $330 million of ATM equity since 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-supported 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 billion 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 $4.25 billion and CAD665 million that will be refinanced over the next three years. We consider this to be in the normal course. The 2018 amount is elevated as a result of the $500 million 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 three well-supported commercial paper programs backed by approximately CAD9 billion of undrawn committed credit facilities and our ongoing access to global capital markets. At December 31, 2016, we had approximately CAD1 billion of cash on hand and we continue to maintain significant capacity in 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 US Northeast Power and then including the $23 billion 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 CAD6.6 billion of comparable EBITDA in 2016, a 12% increase over the CAD5.9 billion reported in 2015. Looking forward, we have removed the CAD525 million of EBITDA generated by our US Northeast Power assets in 2016 as we expect the sale of that business to be completed in first half 2017.

On the growth side, we expect approximately CAD1.85 billion of incremental EBITDA from Columbia 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 $7 billion of expansion projects enter service and we realize $150 million of targeted cost synergies over the next two 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 $100 million of financing synergies that we expect to realize as they are reflected below EBITDA and other income statement line items.

In other US natural gas pipelines, we expect approximately $100 million of additional EBITDA, largely, as a result of the full-year impact on the ANR rate settlement that went into effect August 1, 2016, as well as slightly better performance from certain other US pipelines, including Great Lakes.

In Mexico, we see EBITDA growing by CAD450 million, which would bring the total from this business to approximately CAD700 million, consistent with the $575 million 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 Topolobampo and Mazatlan, which began generating revenue in mid-to-late 2016, as well as the completion of three new pipelines in 2018: Tula, Villa de Reyes, and Sur de Texas.

Next, Canadian Natural Gas Pipelines add approximately CAD200 million in 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 CAD300 million, as we complete Northern Courier, Grand Rapids and White Spruce. And finally, Energy EBITDA is also expected to grow by approximately CAD300 million 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 approximately CAD2.7 billion between now and 2020, bringing the total to approximately CAD9.3 billion. That represents an annual growth rate of approximately 10% between 2015 and 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. 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 on November 15, in homage to my roots, I believe I affectionately referred to it as the Saskatchewan Earnings Cliff, as flat as the eye can see.

Essentially, it illustrates that if we complete our CAD23 billion of near-term capital program and do nothing else but spend maintenance capital through 2025, we would generate approximately CAD8.4 billion of EBITDA in 2025 from regulated or long-term contracted assets. Another CAD400 million, 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 US natural gas pipelines that are subject to recontracting risk over this time frame.

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 or new projects in Mexico, additional regional liquids pipelines or contracted power plants, along with one or more of our CAD45 billion 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 business 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 maintain -- to remain robust in support 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 CAD1.1 billion per year which equates to 1.5% of our gross plant, property and equipment; however, we expect to spend an elevated CAD1.5 billion on maintenance in 2017, largely as a result of the work being done on NGTL and ANR.

Recall that under ANRs recent rate settlement, we will invest CAD837 million over the 2016 to 2018 period to enhance the efficiency and the reliability of the system with the full amount reflected in higher rates. This is essentially growth capital that happens to be defined as maintenance under GAAP. Approximately $350 million, or CAD450 million 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 CAD100 million higher than normal in 2017 as a result of ongoing work on NGTL which is included in the dark blue colored box. Again, any spend on NGTL or the Canadian Mainline is also reflected in their respective rate bases in net income. So while our coverage ratio declines this year, it returns to approximately 2.0 times by 2020, as maintenance capital returns to more normal levels and cash flow growth accelerates as CAD23 billion of commercially secured projects enter service.

So in closing, I will 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 CAD23 billion near-term capital program and have five distinct platforms for future growth in Canadian, US 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 and 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 expand the Company's dividend growth outlook through 2020 and beyond.

That's the end of my prepared remarks. I will now turn the call back over to David for Q&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 two questions. And if you have any additional questions, we'd ask you to please re-enter the queue. With that, I'll now turn the call back to the conference coordinator.

(Operator Instructions)

Linda Ezergailis from TD Securities.

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 workstreams, 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 got done here commercial discussions cost estimate timeline so I'll answer those and if I missed anything, please remind me.

Our first cost 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 are working through their analysis but a lot has changed since November of 2015 when Keystone was denied the Presidential permit so it's just going to take some time for these shippers to assess their volume commitment. There is a sense of urgency on their part but they do have their government to go through.

On the cost side, $8 billion is our most recently prepared cost estimate I would anticipate, we will look to refresh that sometime during 2017 but our cost estimate is $8 billion.

And as far as the timeline goes, we filed the Nebraska application for the road 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'd require. At that point, we would start to do some of the staging activities that you speak of. I would not anticipate it be ready for construction until well into 2018 and that construction cost estimates, we are 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 US on tax reform. 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 the reductions in corporate tax rates and what the net effects might be on your business?

Hi, Linda, it's Don. The simple answer is no. We haven't run any quantitative sensitivities at this point in time. We are 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, it's really difficult so as there's more definition on top this might play out, we will start doing that. But at this point, we are just in the monitoring phase.

Okay, thanks. I'll jump back in the queue.

Robert Kwan from RBC Capital Markets.

Just looking at the financing plan, you talk about it being -- maintaining the credit rating and Don, you mentioned 15% FFO. I'm just wondering -- is that a discussion you had with S&P or how do you think about 2015 versus the 2018?

Yes, at this point, just looking back at what we've done here with that $11 billion of subordinated capital over the last year changed the business position and are viewed substantially for the better by selling our merchant assets and we see 95%-plus EBITDA coming from regulated cost of service businesses going forward. And achieving certain 15% FFO, getting 5 times debt to EBITDA in 2018.

I guess I best direct this at S&P as to how they would weigh the quants versus the qualitative side of this going forward. So we are on track in 2018 to get 15% and 5 times but I'll defer to discussion with S&P as to -- they weigh the quants versus the qualitative.

I guess if I could just turn to the Mainline and you have -- you've been -- as you've acknowledged in discussions with potential shippers, have you had any either formal or informal discussions with other parties that would likely be interested in this? And I'm just wondering if you've assessed the risk on the intervention side, just given what you've already seen on the much smaller [Herbert LTFP] service?

Robert, it's Karl. Yes, the -- I understand your question. We are -- we have been keeping all of our customers up to date on what we are thinking on what it would look like. I'm expecting if we do come to an agreement and as Russ said, I'm encouraged especially since we come to an agreement, and I'd expect that we would have more conversations with them.

But as you said, as we were experiencing with the smaller lower traction rate in Saskatchewan, I would expect there would be some questions and some opposition to it in a hearing. And I believe that our -- any deal that we would strike we would strike it with the idea of making it reasonable for the regulators to see the benefits of the system. So I'm -- we're willing to -- we are expecting some opposition if we do go forward and we're willing to put our case forward, but it's good for the entire system.

That's great. Thanks Don. Thanks Carl.

Rob Hope, Scotiabank.

Just want to circle back on Keystone XL and just on your conversations, there were shippers in 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 culminate TMX or do you see a need for a number of pipelines.

Hi, Rob. It's Karl here. I think there's various projects out there that are 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 all serve different markets with different shipper groups and it's not an industry-led approach to pipeline capacity plan.

So our business model, answer the shippers call into 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 in the international markets. In the case of Keystone, it's the Keystone XL to the US Gulf Coast.

So our business model supports these choices that the shippers make that provide the secured access to the markets of their choice and this is supported by and taken up 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 the potential revenue benefits of adding the Columbia system with your other gas systems could be additive. Do you have any targets that you can share with us or timing of when you can start realizing revenue synergies between TransCanada and Columbia System?

Yes, hi, it's Karl again. We have obviously we are working on that as we speak on how we can interconnect these systems and get those going in between systems. We don't have any answers right now. The reason we never published this is because they are kind of a sub -- they are three years out and they're not within the range of the initial CAD250 million a year that we published. They generally require some construction of contracts or 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 inter-connected but know at this time we haven't put out any number of what we expect to realize from it.

Thank you.

Andrew Kuske from Credit Suisse.

Obviously, there's a pretty big wedge of EBITDA growth coming from the US gas pipelines, really, in the foreseeable future. So I guess maybe the question is to Karl, just is, what have you seen and what have you noticed in I guess the first seven months post-close of Columbia on just differences in customer behavior between those in the Marcellus and those in the Montney?

Hello Andrew. This is Karl. It's essentially -- maybe I'll start by saying this. I guess what we found -- what I found in the Appalachia 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 discussion with the producers of the [WCSB] and that's something relatively new for them. They have been very used to producing and selling into net, and not having to market those lines elsewhere, which I think is changing for them which is why we are spending so much time trying to do some more traction deals.

I think one of the big differences is the attitude towards signing up for long-term project, the attitude towards backstopping of construction of the gas pipelines and so forth is one of the bigger differences that I've seen between the two basins. Having said that, I think the -- our customer base, the two bases, 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% is now produced and driven the rest is LDC. We have similar customers there, with similar requirements to get the 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, 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, CAD2.9 billion is what you posted on an average basis through the year and then CAD4.5 billion on 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 are looking this is a fully integrated system at least?

Yes, I do look at this as a fully integrated system and I can tell you right now, we are working very hard with customers out in the Northeast to market the Mainline as part of their Northeast gas price strategy. There's been severe difficulty putting new greenfield gas pipelines into 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 (inaudible) maybe through Chippewa or Niagara and then move that through our Mainline, the Eastern segment of our Mainline out to [Airaqua, 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 particular customers that need incremental supply. So that's one of the priority marketing areas that we have right now is talking to both the LDCs and load the market in the Northeast area and talking to producers in Appalachia and WCSB and trying to match something through our Mainline into the new US Northeast.

That's great. Thank you.

Ben Pham from BMO.

Just on that last comment about moving a gas (inaudible) into the Northeast market through ERCOT and potential brownfield expansions. Is there any repertory issues there that the buyers (inaudible) if you have move gas during your contract?

I'm sorry. The regulatory issues with the buyers moving gas under --

Just some of the electricity distribution companies.

I don't think there is any regulatory issues. Clearly, the companies we are dealing with right now and we've actually gone down, quite far down the path with some companies. Clearly, they would have to get their own public utility commission's approval with any big supply deal, long-term supply deal that they would do. But I don't think those approvals aren't unusual for any type transaction like that. And there is certainly not approvals that are needed just because they are using the Canadian Mainline assets vis-a-vis a local US asset. So I guess 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 was some commentary about the qualitative impact of merchant power assets, and I'm just wondering, there's no commentary about additional merchant exposures going forward. It looks like over time, you could be almost be sitting at pretty minimal commodity exposure. Are you -- your appetite for merchant power, would you say that's very low right now at the moment?

It's Russ again. 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, CAD23 billion of it, that can be invested in less volatile streams so for the foreseeable future, that is the direction that we will be going.

As you say, 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 and to any great extent for the foreseeable future.

It's Bill here. I'll just add to Russ' comments and say 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 that Bruce, the growth at Nappanee and some the other activities that we've undertaken, we would expect to continue to try to land the opportunities like that in the regions in which we operate.

Okay. That's helpful. Thanks everybody.

Ted Durbin from Goldman Sachs.

Thanks just on Keystone XL. You before said that you were looking for around CAD1 billion of EBITDA and CAD8 billion of capital; is that still the kind of return you're looking for on Keystone?

Yes, the -- Ted, it's Paul. The CAD8 billion 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 supporting our commercial terms. So it's a little premature to provide any guidance on EBITDA front, but we would anticipate trying to achieve the 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 cautionary 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 that 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 mentioned in the Presidential memorandum of sourcing US deal to build it? Where you are with what actually you have in inventory that you can use kind of how you work through the mechanics of that?

Yes, it's Paul again. We are 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 will analyze the plan when it's released to determine any impact it may have on Keystone itself.

Okay, that's it for me. Thank you.

Robert Catellier from CIBC World Markets.

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 US administration might want in terms of profit-sharing?

Rob, it's Paul here. First off, as far as where we are at with the shippers, again, appreciate that as a lot has occurred since November 2015. The shippers, they have a different price environment they are operating in, they -- different supply forecast, different competition out there, so the shippers are going through on their own analysis. We are providing them with the detail we do have around Keystone XL as well 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 love to go to an open season, but at this point, we don't have any plans at that point -- at this point.

In regard to some of the other matters that we spoke of, we are not aware of any additional terms that might be required for us to achieve a 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 will continue to work with the shippers and to the extent that something does occur, we will provide some visibility at that point.

Okay. And then on the mainline, Karl, maybe you could 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 a hearing?

Yes, sure. I think there's two real main benefits that I see to the system from doing a longer-term deal. Number one, the Eastern LDCs have been very clear and vocal and part of that is actually the [LDC] settlement was us facilitating a change in how they prepare natural gas. They have wanted very much to procure natural gas at the arm, 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 shipper, so they have the contract and they have already contracted before we even did the settlement and they contracted almost -- [it's been] a few days since the LDC settlement went into place. So they sent a very strong message to the market that they are waiting to purchase at dawn, which is fine in TransCanada, that's facilitated after the LDC settlement.

Our goal is to not let that pipeline capacity be -- remain empty with our exit. Our goal is to move gas and we believe that we can make a 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 which helps everybody working on the system.

The LDCs out east get more gas supply adds on to compete. The other shippers on the Mainline get extra revenue to help shoulder the burden the cost of the Mainline.

So that's our basic argument and it's clearly an economic argument of where we are placing volumes. We believe the LDCs have exited and they are -- we have 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 that there was so much push-back from the producers on the, what I thought was a reasonable term expectation in the first place?

The term is something -- quite frankly, terms we have been discussing for a very long time. As I talked about earlier, the producers in the WCSB are not all that familiar, not all that comfortable with taking longer-term contracts. I think the Mainline is basically on the year-to-year term. But we are talking with producers and again, I have to remind you that we have not come to agreement. We are talking to them as a 10-year term with various off ramps as fixed 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.

(Operator Instructions)

Faisel Khan from Citigroup.

Thanks. It's Faisel from Citi. Just two questions, the first one is on the approval for the pipelines on the Columbia system, I guess, WCSB XPress, Mountaineer XPress, Gulf XPress. How do the lack of a quorum right down to 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 become eminently 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're hoping that 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 that being (inaudible) Xpress and [Marine] XPress, but having said that, we are like most others in the industry, watching anxiously to see how the process will unfold to get a quorum back.

Okay and got you. 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. No, we reached the quorum we needed to get that over the finish line.

Okay, understood.

Great, thanks Faisel.

Thank you. There are no further question registered at this time. I would like to turn it back over to Mr. Moneta.

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 future. Thank you.

Thank you. The conference has now ended. Please disconnect your lines at this time and thank you for your participation.