Thanks very much, and good morning, everyone. I'd like to welcome you to TC Energy's 2019 fourth quarter conference call.

With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President of Strategy and Corporate Development and Chief Financial Officer; Francois Poirier, Chief Operating Officer and President of Power and Storage and Maxico; Tracy Robinson, President of Canadian Natural Gas Pipelines; Stan Chapman, President U.S. Natural Gas Pipelines; Paul Miller, President of our Liquid Pipelines business and Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our Web site, which can be found in the Investors section under the heading Events and Presentations.

Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Jaimie Harding following this call, and she’d 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 additional questions, please re-enter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations for your detailed financial model, Duane and I'd 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 TC Energy with Canadian securities regulators and with the U.S.

Securities Exchange Commission. And 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 comparable EBITDA; comparable funds generated from operations; and comparable distributable cash flow.

These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities.

These measures are used to provide you with additional information on TC Energy's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David. Good morning, everyone.

And thank you very much for joining us late in the afternoon. As highlighted in our fourth quarter new release, during 2019, our $100 billion portfolio of high-quality long life energy structure asset continue to profit from strong supply and demand fundamentals.

And we continue to realize the growth expected from our industry leading capital expansion program. As a result, despite significant asset sales that accelerated the strengthening of our balance sheet, we produced record financial results again in 2019.

Today, we are advancing $30 billion of secured capital projects that largely consisted in corridor expansions of our existing assets. In addition, work continues on more than $20 billion under projects under development, including Keystone XL and refurbishment of five reactors at Bruce Power as part of their long-term life extension program.

We also made significant progress in funding our secured capital program through various portfolio management activities last year. Specifically, we completed the partial monetization of our Northern Courier pipeline in Alberta, as well as the sale of certain Colombian midstream assets in the Appalachian region.

These initiatives combined with the sale of our Coolidge generating station in Arizona, resulted in combined proceeds of approximately $3.4 billion. Each of those transactions allowed us to serve a significant value for relatively mature assets and redeploy the money into our capital program, thereby reducing our need for external funding.

As a result, we exited 2019 with debt-to-EBITDA in the high 4s, as we had planned. Looking forward, we expect our strong operating and financial performance to continue with 2020 comparable earnings per share expected to be consistent with the record results we've produced in 2019.

We also expect our solid financial position to be bolstered in the first half of 2020 with the completion of announced portfolio management and project financing activities. Last July, we entered into an agreement to sell our natural gas power plants in Ontario for approximately $2.87 billion.

Subject to closing adjustments, that transaction is expected to close by the end of the first quarter. And in late December, we announced an agreement to sell a 65% equity interest in our $6.6 billion Coastal GasLink pipeline project and that is expected to close in the first half of 2020.

As a result, we think that we are well-positioned to fund our $30 billion portfolio of secured growth projects without issuing any common equity from our dividend reinvestment plan. We're proud of our financial performance and the significant returns we've generated for our shareholders.

We do know that our ongoing success depends on our ability to balance profitability with safety and environmental and social responsibility. We have a 65 year track record of safe and reliable operations, but we recognize there's always room for us to improve.

That's why in 2019, we created a Chief Sustainability Officer role at the executive level of our company, and added sustainability to what is known as the Health, Safety and now Sustainability Environment Committee of our Board of Directors. To keep you better informed, we've published several investor focused ESG documents informed by the task force on climate related financial disclosure, the Sustainability Accounting Standards Board and the global reporting initiative.

Those documents describe some of the work we're doing to ensure our business remains resilient in an ever evolving energy landscape. All of that can be found on our Web site at tcenergy.com.

So with that as an overview, I'll expand on some of the recent developments, beginning with a brief overview of our 2019 financial results. Don will provide more detail on the fourth quarter results and the outlook in just a few minutes.

So excluding certain specific items, comparable earnings were $3.9 billion or $4.14 per common share for the year ended December 31, 2019 compared to $3.5 billion or $3.86 per share in 2018, which is an increase of about 7% on a per share basis. Comparable EBITDA of $9.4 billion and comparable funds generated from operations of $7.1 billion were both 9% higher than last year.

Each of these amounts represents record results for our company and reflects the strong performance of our legacy assets, as well as contributions from $8.7 billion of new long-term contracted or rate-regulated assets that were placed into service in 2019. Based on the strength in our financial performance and our promising outlook for future, TC Energy's Board of Directors declared first quarter of 2020 dividend of $0.81 per common share, which is equivalent to $3.24 per share on an annual basis.

This represents an 8% increase over the amount declared in 2019 and is the 20th consecutive year that our Board has increased the dividend. Over that same timeframe, we have maintained consistently strong coverage ratios with our dividend on average representing a payout of approximately 80% of comparable earnings and 40% of comparable funds generated from operations, leaving us with significant internally generated cash flow to invest in our core businesses.

Next, I'll make a few comments on our five operating businesses. Firstly, in our Canadian natural gas pipeline business, customer demand for access to our systems remained strong and we continue to work with industry on options to connect growing Western Canadian gas supply to markets across North America.

Evidence of that can be seen in our announcement earlier today that will see us invest another $900 million in our 2023 NGTL Intra-Basin System Expansion program for incremental delivery capacity to serve oil sands, petrochemical demand, power generation demand and the utility sectors in Alberta. The extension will add 309 million cubic feet a day of capacity to the system, and is underpinned by 15 year contracts with shippers.

Regulatory applications for that expansion are expected to be filed later this year with construction commencing as early as the fourth quarter of 2021, subject to receipt of those regulatory approvals. With this announcement, we are now advancing $9.3 billion expansion program on NGTL that will add approximately 3.5 billion cubic feet a day of incremental delivery capacity by the end of 2023.

We also continue to actively work with LNG Canada on our Coastal GasLink project, that $6.6 billion project will have an initial capacity of 2.1 billion cubic feet a day with potential expansion capacity up to 5 billion cubic feet a day. Coastal GasLink will play an important role in delivering Canadian natural gas overseas that will displace coal fire generation in Asia and contribute to the reduction in global greenhouse gas emissions.

Construction activities continued on many locations along the pipeline route during the fourth quarter and into 2020. Today, we are proceeding on work at over 30 sites along these 670 kilometer routes with over 1,000 thousand men and women currently employed.

On February 6th, the RCMP began enforcing the Supreme Court of British Columbia interlocutory injunction prohibiting unlawful blockades that were preventing access to service roads in the Morris river area of south of Houston DC. We're extremely disappointed, enforcement was required to reopen the Morris River for service road, but we will continue our efforts to attempt to engage with the hereditary chiefs of the West Hilton and the units [indiscernible] in search of a peaceful long-term resolution that benefits all of the people in that community.

We will also continue to engage with all indigenous and local communities, including all 20 of the First Nation communities along the route who are benefiting from the social and economic development the project offers and want to see that project move ahead. Finally, we'll continue to work with the 20 First Nations on an option to acquire 10% equity interest in the project that option was announced in late December when we got funding plans for the project by selling 65% interest in the project to KKR and Amco.

We also expect Coastal GasLink will finalize a secure project financing construction credit facility with a syndicate of banks to fund up to 80% of the project’s capital expenditures during construction. Both of those transactions are expected to close in the first half of 2020, and will be substantially satisfy our under requirements through the project to completion.

Looking forward, we'll continue to be responsible for constructing and operating the pipeline and providing a positive long-term legacy for the many local communities in First Nations in Northern British Columbia. Finally, in the Canadian natural gas pipelines business, in December, we were pleased to complete negotiations on a six year settlement with our customers on the Canadian mainline.

The settlement, which will run from January 2021 through December 2026, sets a base equity return of 10.1% on 40% deemed common equity and includes incentives to increase revenues and decrease costs, which will be shared between us and those customers. Moving now to our U.

S. natural gas pipelines, which serve today approximately 25% of U.

S. daily demand.

In conjunction with the 2023 NGTL System Expansion that we announced earlier today, we also announced an expansion of our ANR System. Expansion projects we referred to as the Alberta Xpress Project will add approximately 160 million cubic feet a day of capacity to ANR.

Customers have signed agreements, which include customary conditions proceedings with an average weighted term of 19 years. Regulatory applications to construct the facilities will be filed with the FERC in 2020 and subject to regulatory approvals, construction is expected to commence as early as the third quarter of 2021 with in service expected to commence in 2022.

The Alberta Xpress Project, in combination with existing capacity on our Great Lakes Transmission System, the Canadian mainline system will provide Western Canadian production with a seamless path to growing LNG export markets and other markets along the U. S.

Gulf Coast. In addition to Alberta Xpress, we are advancing $1.5 billion of other capacity projects across our U.

S. natural gas pipeline network, which includes the Buckeye Xpress Project, GTN Xpress, Eastern Lateral Xpress, Louisiana Xpress and the Grand Shenir Xpress Project.

Each of those projects are along our existing footprint, highlighting the value of our extensive cost competitive North American network. Turning to Mexico.

With the Sur de Texas pipeline began commercial operations in September, following the execution of an amending agreement with CFE Sur de Texas has a capacity to provide up to 2.6 billion cubic feet a day of low cost clean burning natural gas supply to Mexico. With the completion of Sur de Texas, we now have five operating pipelines in Mexico and another two pipeline projects under development.

They include the Villa de Reyes project, which we expect to phase into service starting in the second quarter and have fully operational by the end of the year. Finally in Mexico, the east section of the Tula Pipeline is now available for interruptible transportation service, although, construction on the central segment continues to face delays.

Tula is expected to enter answer service two years after indigenous consultations are successfully concluded by the Mexican government. Turning to our liquids business, which generated very strong results in 2019.

Keystone continue to produce solid results in the fourth quarter, although, was impacted by system outage and a pressured Villa de Reyes. On the southern portion of our system or that what we call the U.S.

Gulf Coast segment, capacity was increased during 2018 to more than 700,000 barrels a day and we maintained strong utilization through the fourth quarter of 2019. In addition, for much of the year, we benefited from higher contribution from liquids marketing due to improved volumes and margins.

Although, those margins weakened in the fourth quarter as new pipeline capacity was brought into service between the Permian and the U.S. Gulf coast.

And finally, in the Liquids business, we continued to advance the Keystone XL project. In March, the U.

S. President, Trump issued a new permit for the project, which superseded the 2017 permit and resulted in the dismissal of the litigation related to that old permit.

In August, the Nebraska Supreme Court affirmed the November 2017 decision by Nebraska Public Service commission that approved the Keystone XL pipeline route through the state. In December, the U.S.

department of state issued a final supplementary environmental impact statement for the project that report considered the changes in the project since 2014 when the 2014 Keystone XL FDIS was issued, including rooting in Nebraska, as well as updated information in the new studies that were required. And on February 7th, we receive approval from the U.S.

Bureau of Land Management, allowing for construction of pipeline across federally managed lands. In addition, we have now acquired nearly 100% of the right of way for the pipeline through all states, Montana, South Dakota and Nebraska.

Keystone XL continues to be a very important project for both Canada and the United States. It will create jobs and advance energy security in both nations in an environmentally sustainable and very responsible way.

As such, it continues to be fully subscribed by our customers under long-term take or pay contracts. Moving forward, we will continue to carefully and methodically manage various legal and regulatory matters before we consider advancing this commercially secured project into construction.

Turning to power and storage business where work continues on the Bruce life extension project. After years of preparation, Bruce Power's Unit 6 MCR outage commenced on January 17th, when we took that unit offline.

We expect to invest approximately $2.4 billion in that program, as well as the ongoing asset management program through 2023 when the UN 6 refurbishment is complete and return to service. Bruce Power’s contract price increased to approximately $78 per megawatt hour on April 1, 2019, to reflect the capital to be invested under these programs, as well as normal annual inflation adjustments.

Also in power, as you know we experienced an equipment failure on Napanee in 2019, that failure has now been resolved and final commissioning activities are progressing with commercial operations are expected to commence late in the first quarter. As a result, we expect the sale of the facility along with the Halton Hills plant and our interest in the Portland Energy Center to close by the end of the first quarter.

The proceeds of approximately $2.7 billion will be used to help fund our industry leading capital program. In summary, today we are advancing $30 billion of secured growth projects that are expected to enter service by 2023.

We have invested approximately $8 billion into that program to-date with approximately $6 billion of these projects expected to be completed by the end of 2020. Notably, they're all underpinned by cost of service regulation or long-term contracts, giving us visibility to earnings and cash flow that they will generate as they enter service.

Based on the continued strong performance of our base businesses, combined with our organic growth programs, we expect to grow our dividend at an average annual rate of 8% to 10% through 2021 and 5% to 7% thereafter. As always has been our practice, the growth in dividend is expected to be supported by sustainable growth in earnings and cash flow per share and strong coverage ratios.

To close, I'd leave you with the following key messages. Today, we are a leading North American energy infrastructure company with a very strong track record of delivering long-term shareholder value.

Our assets are essential to the functioning of the North American society and to the economy, and the demand for our services remains strong. Looking forward, we have five significant platforms for growth, Canadian, U.S.

and Mexico natural gas pipelines, liquids pipelines and power storage. As we advance our $30 billion secured capital program, we expect to build on our long track record of growing earnings, cash flow and dividends per share.

We also have more than $20 billion of projects in advanced stages of development and expect numerous other in-corridor organic opportunities to M&A from our extensive critical asset footprint. And finally, our balance sheet is back to its historical strength, and we are well positioned to fund our secured capital program without the need for any additional common equity.

In 2020 and beyond, we will remain disciplined continuing our focus on safety, sustainability and working according to our values and responding quickly to market signals and signposts to ensure we remain industry-leading and resilient as we grow shareholder value and improve society's wellbeing for decades to come. With that, I'll turn the call over to Don who’ll provide more details on our fourth quarter results and our future outlook.

Thanks, Russ and good afternoon, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $1.1 billion or $1.18 per share in the fourth quarter of 2019, compared to $1.1 billion or $1.19 per share for the same period in 2018.

Fourth quarter results included a positive $195 million valuation allowance release, recognizing the previously unrecorded benefit of certain prior year’s U.S. tax loss carry forwards, partially offset by $61 million increase from the after tax loss on the Ontario natural gas fired power plants held-for-sale and $19 million adjustment to the loss on the sale of certain Columbian midstream assets.

In the case of the Ontario natural gas fired power plants, the accrued loss on sale will increase each reporting period up to transaction close to reflect incremental spend and interest capitalized on Napanee. Fourth quarter 2018 results also included several specific items as outlined on the slide and discussed in the fourth quarter 2019 financial highlight’s release.

All of these specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings, which reached $970 million in the fourth quarter in 2019, $24 million higher than last year. After taking into account the dilutive impact of common shares issued under our dividend reinvestment program, comparable earnings per share of $1.03 were consistent with last year.

Turning to our business segment results on Slide 17. In the fourth quarter, comparable EBITDA from our five operating segments was approximately $2.3 billion, a $138 million decrease from 2018.

Canadian natural gas pipeline's comparable EBITDA of $618 million was $200 million lower than the same period last year, primarily on account of lower flow-through depreciation and income taxes, as well as lower incentive earnings from the Canadian mainline due to recording the full year impact of the NEB 2018 decision in fourth quarter of 2018. I would note that for Canadian natural gas pipelines, changes in depreciation, financial charges and income taxes, impact comparable EBITDA but they did not have a significant effect on net income as they are almost entirely recovered in revenues on a flow-through basis.

Net income for the NGTL system increased $20 million, compared to fourth quarter 2018 as a result of higher average investment base from continued system expansions. Net income for the Canadian mainline decreased $17 million year-over-year, primarily due to lower incentive earnings as a result of the NEB 2018 decision, partially offset by decreased carrying charges on the 2019 revenue surplus.

U. S.

natural gas pipeline's comparable EBITDA of $648 million or CAD855 million in the quarter, rose by $35 million U.S. or $43 million Canadian compared to the same period in 2018.

The increase was mainly due to contributions from Columbia gas and Columbia Gulf growth projects placed in service, partially offset by the sale of certain Columbia midstream assets in August 2019 and lower earnings from buys and due to 2018 customer agreements to pay out their future contracted revenues and terminated their contracts. Maxico natural gas pipeline's comparable EBITDA of $125 million U.

S. or $165 million Canadian was $10 million U.

S. or $13 million Canadian above fourth quarter 2018 due to higher equity earnings from the Sur de Texas pipeline, which was placed in service in September 2019 at which time we began recording equity income from operations.

Prior to in service, Sur de Texas equity income primarily reflected AFUDC net of our proportionate share of interest expense on inter-affiliate loans. The interest expense on the Sur de Texas inter-affiliate loans are fully offset in interest income and other.

Lower earnings from other operations are primarily a result of changes in the timing of revenue recognition in 2018. Liquids pipeline’s comparable EBITDA declined by $66 million to $472 million in fourth quarter 2019, driven by lower volumes on the Keystone pipeline system, a decreased contribution from liquids marketing activities due to lower margins and reduced earnings as a result of the partial monetization of Northern Courier in July 2019.

These decreases were partially offset by a contribution from the White Spruce pipeline placed in service in May 2019. Power and storage comparable EBITDA rose by $43 million year-over-year to $210 million due to higher Bruce Power results, which were elevated by an increased realized our price and higher volumes resulting from fewer outage days.

This was partially offset by decreased Canadian power results, largely due to greater outage days at our Alberta cogeneration plants, a prior period billing adjustment, as well as the sale of the Coolidge generating station in May 2019. For all our businesses with U.

S. dollar denominated income, including U.

S. natural gas pipelines, Mexico natural gas pipelines and parts of liquids pipelines, EBITDA was translated into Canadian dollars using an exchange rate of 132 in fourth quarter 2019 similar to the rate for the same period in 2018.

Therefore, foreign exchange had little impact on year-over-year business unit results. As a reminder of our approach to managing foreign exchange exposure, our U.

S. dollar denominated revenue streams are partially hedged by interest on U.

S. dollar denominated debt.

We then actively manage the residual exposure on our rolling one year forward basis. Now turning to the other income statement items on Slide 18.

Depreciation and amortization of $625 million decreased $56 million versus fourth quarter 2018, largely due to recording the full year impact of increased depreciation rates approved in the Canadian mainline NEB 2018 decision in fourth quarter 2018, partially offset by higher depreciation in the NGTL system and the U. S.

natural gas pipelines reflecting new projects placed in service. Interest expensive of $586 million for fourth quarter 2019 was $17 million lower year-over-year, primarily due to higher capitalized interest related to Keystone XL, Coastal GasLink and Napanee, partially offset by the impact of long-term debt and junior subordinated note issuances in 2018 and 2019 net of maturities.

AFUDC decreased $44 million for the three months ended December 31, 2019 compared to the same period in 2018, primarily due to Colombia gas and Columbia Gulf growth projects placed in service, partially offset by continued investment in our NGTL system in Mexico projects. Comparable interest income and other increased by $66 million in the fourth quarter versus 2018, primarily as a result of lower realized losses in 2019 on derivatives, it was used to manage our net exposure to foreign exchange rate fluctuations on U.

S. dollar denominated income.

As noted earlier, along with U. S.

dollar interest expense, these activities serve to offset the impact of currency movements in the business units and comparable EBITDA. Income tax expense included in comparable earnings was $211 million in fourth quarter 2019 compared to $268 million for the same period last year.

The $57 million decrease was mainly on account of lower flow through income taxes and Canadian rate regulated pipelines and decreased comparable earnings before income taxes, partially offset by lower foreign tax rate differentials. Comparable net income attributable to non-controlling interest of $76 million in the fourth quarter decreased by $10 million compared to the same period last year, primarily due to lower earnings in TC Pipelines LP.

And finally, preferred share dividends were comparable to fourth quarter 2018. Now turning to Slide 19.

During the fourth quarter, we invested approximately $2.4 billion in our capital program, which was largely funded with comparable funds generated from operations of $1.8 billion along with drift proceeds from the third quarter dividend, cash on hand in those payable. Over the past several years, we have taken significant steps to return our balance sheet and financial flexibility to their place of historical strength.

That included the partial monetization of Northern Courier, as well as the sale of certain Columbian midstream assets and the Coolidge generating facility in 2019 for total proceeds of approximately $3.4 billion. As a result, we exited 2019 having attained targeted debt-to-EBITDA in the high 4s, and in a position to fund our $30 billion portfolio of secured growth projects without further issuance of common equity.

As Russ mentioned, the company's strong financial position will be further bolstered by the completion of pending portfolio management and project financing activities expected in the first half of 2020. More specifically, closing the sale of our Ontario natural gas fired power plants and the partial monetization of Coastal GasLink.

In December, we entered into an agreement to sell our 65% equity interest in Coastal GasLink. Under its terms, we will receive upfront proceeds that include reimbursement of the joint venture partner’s proportionate of share of project costs incurred to the date of close, as well as additional payment streams through construction and operation of the project.

Concurrent with the completion of the sale, we expect Coastal GasLink will enter into a secured project level credit facility to fund up to 80% of costs through construction. These transactions are expected to close in the first half of 2020 and substantially satisfy our funding requirements through project completion.

The previously announced sale of our Ontario natural gas fired power plants for $2.87 billion is also expected to close in the first quarter of 2020. Now turning to Slide 20.

This graphic highlights our forecasted sources and uses of funds from 2020 through 2022. Starting in the left column, the total funding requirement over the next three years is projected to be $30 billion comprised of dividend and non-controlling interest distributions of approximately $11 billion and capital expenditures of approximately $19 billion, including maintenance capital.

This also reflects the inclusion of capital spend on Coastal GasLink prior to the close of the equity sell down, as well as the additions of the 2023 NGTL system expansion program and Alberta Xpress. The second column highlights aggregate sources, including approximately $21.5 billion of internally generated cash flow and $2.8 billion of proceeds from the pending sale of our Ontario natural gas fired power plants.

It also reflects $1.6 billion, which we expect to receive under the Coastal GasLink secured project level construction credit facility for amount spent by us to the date of close. That leaves a residual requirement of approximately $4.4 billion in the far right column.

We expect to fund this through a combination of incremental debt within the constraints of our targeted debt-to-EBITDA in the high 4s range, and FFO-to-debt of approximately 15% supplemented by the reimbursement of equity contributions and other payments to be realized from the sale of 65% interest in Coastal GasLink. In summary, our external funding needs are eminently manageable in the context of our significant internally generated cash flow and the multiple financing levers available to us.

We reiterate we do not foresee a need for common equity to complete our secured $30 billion capital program. Now, turning to Slide 21.

Next, I'd like to spend a moment on our 2020 comparable earnings outlook. Additional information is contained in our 2019 annual management's discussion and analysis, which has been filed on SEDAR today and available on our Web site.

Overall, comparable earnings in 2020 on a per share basis are expected to be consistent with the record results achieved in 2019. Canadian natural gas pipeline’s earnings are expected to be higher than 2019, mainly due to continued growth in the NGTL system investment base, with the Canadian mainland largely stable year-over-year, reflecting consistent incentive earnings and investment base.

U. S.

natural gas pipeline’s earnings are expected to be in line with 2019 due to increased revenues, following the completion of expansion projects on the Columbia gas and Columbia Gulf systems in 2019, offset by the sale of certain Columbia midstream assets in August 2019. In Mexico, we expect earnings to be higher year-over-year, primarily due to a full year of operations for the Sur De Texas pipeline, along with some incremental contribution from the Villa de Reyes pipeline, which is anticipated to be fully in service by the end of the year.

In liquids, earnings are expected to be significantly lower than 2019 in both Keystone pipeline system and liquids marketing business, as a result of lower margins and volumes due to changing market conditions as significant opportunities that existed in 2019 are not anticipated to persist in 2020. Earnings in 2020 will also be impacted by the partial monetization of Northern courier in July 2019.

Comparable earnings for the power and storage segment are expected to be lower than 2019, primarily as a result of a decreased contribution from Bruce Power due to the Unit 6 MCR outage, which commenced in January 2020, the sale of our Ontario natural gas fired power plants in the first quarter of 2020, as well as the completed sale of the Coolidge generating station in May 2019. Comparable earnings per share in 2020 will also be impacted by development fees related to certain capital projects, offset by higher financial charges as a result of lower capitalized interest and reduced AFUDC after placing new assets in service.

With respect to income taxes, excluding Canadian regulated pipelines where income taxes are a flow through item and our best quite variable along with equity AFUDC income in U. S.

and Mexico natural gas pipelines. We expect our 2020 full year effective rate to be lower than 2019 of still in the mid to high-teens range subject to the uncertain impact of pending final U.

S. tax regulations, and recently enacted tax reforms in Mexico.

Finally, as part of the 2020 outlook, I would note that our exposure to interest rate, foreign exchange and commodity price variability remains quite limited in our diversified portfolio. In terms of capital spending, we expect to invest approximately $8 billion in 2020 on growth projects, maintenance capital and contributions to equity investments.

The majority of the capital expenditures are attributable to NGTL system expansions, Columbia gas modernization projects, the Bruce Power life extension program, normal course maintenance and Coastal GasLink prior to closing the sale of 65% interest in the project. Subsequent to closing and the contemporary establishment of the security construction credit facility, we expect our investment in Coastal GasLink will be accounted for under the equity method and future capital expenditures will be predominantly funded by project level financing and our equity partners.

Lastly, turning to Slide 22. In closing, I offer the following comments.

Our solid financial and operational results in the fourth quarter once again highlight our diversified low risk business strategy and reflect the robust performance of both our blue chip legacy portfolio along with the contribution of equally high quality assets from our ongoing capital program. Today, we are advancing $30 billion suite of secured projects and have five distinct platforms for future growth in Canadian, U.

S. and Mexico natural gas pipelines, liquids pipelines and Power and Storage.

Our overall financial position remains strong. We are well placed to fund our secured capital program through resilient and growing internally generated cash flow, access to debt capital markets, the pending sale of our Ontario natural gas-fired power plants along with the partial monetization of project level financing of Coastal GasLink.

Our portfolio of critical energy infrastructure projects is poised to generate high-quality long life earnings and cash flow for our shareholders, as well as germinate further attractive and executable in-corridor opportunities. That is expected to support annual dividend growth of 8% to 10% through 2021 and 5% to 7% organic growth thereafter.

Finally, we will continue to maintain financial strength and flexibility at all points of the economic cycle. That will leave us well positioned to capture transformational opportunities that could supplement our organic growth should they arise in the future.

That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.

Thanks. Don.

Just a reminder before I turn it over to the conference coordinator for questions from the investment community. We ask that you limit yourself to two questions.

If you have additional questions, please re-enter the queue. With that, I'll turn it over to the conference coordinator.

Thank you. I appreciate how your ESG reporting continues to evolve.

But I'm wondering if you could give us maybe a bit of a better sense about how you might evolve, how these ESG and sustainability principles might guide your business decisions in terms how you also you look at future scenarios, and maybe just provide some context around that?

I'll take a first shot at it, Linda. Obviously, the issues related to sustainability have always been sort of foremost in our minds with that I think our safety environmental, our stewardship, the working with the communities that the benefit from our projects, we will continue to do those things.

As you know, we've heightened our awareness around safety for example. We've been implemented zeroing program inside the company.

We've made real progress. We achieved zeroing in a lot new pockets of our business this year that continues to be very important.

We continue to invest in technology that will improve our ability to detect and act on your potential for leaks in our pipeline systems. And we continue to evolve our processes in investment in the communities in which we operate, offering continually greater benefits for those communities and understanding what their concerns are.

So they're foremost in our mind. What we've been doing from a reporting perspective is correlating that information and providing it to the investment community in a way that we hadn't in the past, because folks are asking for that kind of information.

And based on that feedback as well we’ll continue to evolve that reporting around those kinds of issues. But what I can tell you each year and each year that I've been at the company over the last 25 years, we've continued to make improvements on how we do business in all areas whether that’d be in environmental footprint, social responsibility, the diversity in our employment and management ranks.

I think you just look at the results and see that we have continuous improvement in goals on an annual basis to continue to improve those things.

How does it inform your capital allocation decisions and how you might think about terminal values and discount rates, et cetera?

Well, I think clearly it’s in our business. Those are concepts that we've thought about for a long time.

If you think about life span of assets, depreciation is a concept that we have worked with our shippers and our regulators over the years. As we've seen times in the past where supply demand for other fundamentals would point you to a shorter asset life we accelerate depreciation, increasing dynamics surcharges for example and the opposite when we see that at certain locations, those assets are going to be around for longer we extend those depreciation timeframes.

And we continue to look at return of the non-capital and adjust our investments and revenues in a way that best allows us to capture those for our shareholders. When I think about other things like weather related risks, for example, again those aren't issues that are new to us.

If you think of the way that we approached putting in river crossings, for example, where we used to cut the middle of the river and put the pipe four feet under the river, we changed our practices today. And major river crossings, we drill underneath those rivers, especially if you have your 100 -- year flooding kind of scenarios that’s scouring in those kinds of things doesn't expose our pipe anymore.

So we continue to evolve our practices on all of these fronts as I think about the risks inherent. We have been on top of those for some time.

But in addition, this last year we introduced and it's outlined in our reports that we made public. We do look at scenario analysis and we've looked at different supply demand scenarios that could evolve in the future, including a 2 degrees reduction scenario that was put together which is by a consultant.

And then from that we look at the resilience of our assets in those supply demand scenarios. And we have -- I think what we found is in our portfolio performed very well.

And as you know, one of the benefits of the large diverse footprint that we have that goes from wellhead to market and is well depreciated, those assets become the ones that people want to use going forward, because of their low cost base and the location and our ability to expand them because of existing relationships with communities and things like that where it's difficult to build in those markets today. So these are all concepts that have been on our mind for some time.

We've collated them and we provided them via those reports. I guess what I would tell you about our business is we believe under almost every scenario that we see going forward, we're part of the solution to achieving reductions in greenhouse gas emissions, for example, with single greatest reduction in greenhouse gas emissions in North America has been the displacement of coal fire generation in United States, we played a large role in that.

We've played a large role in the reduction and elimination of coal fired generation in Ontario with the construction of gas fired generation there, our building of solar facilities there, as well as our investments in the Bruce Power refurbishment. So as we think about the resilience of our assets, they appear to be very resilient and be very relevant in the marketplace for a long time.

That said, we continue to monitor that via the scenario analysis that we do, and we're very comfortable with where we are today. In fact, see great opportunity as the marketplace evolves and looks for better and better environmental performance from the energy infrastructure, the supply, the energy that people need.

If I can ask a second question just really quickly. You're in the process of discussing with your customers the NGTL settlement for 2020 and beyond.

If you can just comment on how close do you think you might be to concluding those discussions? And how the attributes might be similar or change versus what was in place for 2018 and 2019?

Linda, this is Tracy here. Those dialogs continue, I would say -- what I would say tell you is on very collaborative basis.

We all understand the importance of the NGTL system in the health and the growth basin as we come together with our customers that kind of forms the principle around the solutions that we're looking for. The dialog is going very well.

And I would expect that we would have something we could talk about within the next two to three months.

And the range of outcomes?

Those of course would be subject to what the guys are talking about at the table, it'd be inappropriate I think right now to talk about what those are. Let's let them get through and into an agreement and then we'd be happy to have a conversation around what that looks like.

I just wanted to see kind of next steps forward here with KXL, given that you've kind of crossed a lot of the regulatory and legal hurdles. Seems like you have more clear site I guess to what could happen than you have at points in the past.

And just wondering if you've seen any kind of acknowledgment from the Federal Government or from the local government as far as if the project does go forward, I imagine that they would reap very significant benefits. And so it seems like they'd be incentivized, the stakeholders in this project as well to support the development.

So I didn't know if you'd heard anything from the EDC as far as support there or anything else you could comment on this topic?

Jeremy, this is Paul here. I'll just talk a little bit about the progress we have made and what is in front of us.

So we did make some progress in the last few quarters. We've seen just recently the approval from the Bureau of Land Management for the access to all the federally managed land, as well as the affirmation from the Nebraska Supreme Court of new route in Nebraska, as well as the receipt of the final supplemental environmental impact statement from the State Department, which together has allowed us to secure almost 100% of the land we need to Canada and U.

S. to build the pipeline.

Going forward, we still require a approval from the Army Corps of Engineers for access to waters in the U. S.

and there is outstanding litigation in federal court in Montana, contesting the 2018 presidential permit. So those two items we need to get behind us before we move forward to an FID.

Jeremy, its Don here. I'll keep it at a fairly high level.

But this is a very compelling project with substantial benefits for many parties if we get this done. The conversation on aligning the risks and rewards of this project amongst those parties has been underway for quite some time and I described it as constructive.

And as Paul mentioned, we're in the final stage gates here of getting through remaining approvals, tossing the project, looking at execution plans. If we can get comfort that the risk reward proposition is attractive to us, we will proceed.

And if we can't line all that up then the project will stay where it is right now. So there's some positive moving parts here but that's kind of the high level is how we see things.

And maybe if I could just go to Mexico for a minute here and there's been some time since the developments that happened last year, some of the changes in the market and changes in contracts there. Just wondering if you could refresh us on your views for Mexico, whether that's an area you’d like to expand or shrink.

And just as far as some of the pipeline that came online, seemed like Tula, there's room for IT there. Just wondering what the scope of those opportunities could be, any comments on that would be helpful.

Jeremy, its Francois. First of all, you alluded to negotiations, I think negotiations continue with the CFE and the government of Mexico, and we would certainly characterize them as being constructive.

As far as the fundamentals, they're still favorable and compelling. Demand for energy in Mexico remains strong and is growing.

Low cost natural gas from the U. S.

is available will will lower the cost of electricity and reduce particulate emissions as it replaces diesel and fuel oil for power generation in various parts of the country. I would say that successful negotiations on Sur De Texas serve as a good blueprint for how we're discussing, advancing negotiations on Villa de Reyes and Tula.

And I think we would see a successful conclusion of those negotiations as demonstrating willingness for further foreign capital investment, and that would be a basis upon which we would look at as future opportunities.

And just as far as how big could the IT opportunity be there in I guess your appetite for Mexico within the portfolio, if you're at the right size or if this could be bigger or smaller?

I think until we resolve, as I alluded to, until we conclude negotiations on the two other contracts, I think we're comfortable with our exposure in Mexico. And with respect to IT volumes, I would characterize them as modest that is part of the solution set as we look to renegotiate the package of pipelines providing service into Central Mexico.

I'll start just on the interest rate environment. We're seeing some pretty low rates on the corporate bond side.

I'm wondering if there's any more opportunities for you to recycle capital or refinance in a way where the benefits accrue to shareholders?

It's Don here. There's a few pockets where that opportunity might present itself but they're more of bespoke rather than across our whole portfolio.

The portfolio is pretty long-term and pretty fixed rated, of about 22 year average life including hybrids to final coal. Average rate is 5.2%, 90% area fixed.

A lot of the higher rate stuff is legacy debt that we use to finance rate-based expansion in Canada many years ago. So this flows through in any refinance that which we do look at from time-to-time what accrued to the shippers.

We have issued a fair bit of debt in the past few years, but it was generally in the low rate environment. So there's nothing that jumps out that there is some material compelling opportunity to refinance large pockets of our portfolio that would accrue to the shareholder.

And then I assume now that you have the leverage down where you want it, there's no particular incentive just based on valuation to accelerate capital recycling and portfolio management?

The metrics are where we want them. We believe the high 4s and debt-to-EBITDA 15% FFO to debt area are the right places for us, given our -- when you look at it as a holistic portfolio, they’re quite utility like in terms of our business position.

And so our balance sheet is where we wanted. We pretty much like everything in our portfolio, never say never, whenever we have an opportunity that arise, is that may require share count growth.

We will obviously look at our portfolio and scour that to see if there is something some more compelling opportunity than increasing share count growth.

And then just finally last question I had is on the option for the First Nation on Coastal GasLink. Is there anything you can tell us there in terms of what term that option has, and maybe you can speak to the sense of desired exercise at that option?

I'm just trying to get to what you might have as a final interest. Is there an option, for example, if the First Nations don't exercise, would you consider selling down the extra 10% to third-party?

Thank you.

It's Don again here. I won't get into the details of where we are on the option process other than to say that it's our expectation we’ll end up at a 25% ownership stake in Coastal GasLink.

I guess one to just start on the Canada mainline. Just wondering if you could tell us how much capacity is currently available.

And do you think the new tolling arrangement will help fill up some of that capacity?

We have some capacity available on the Mainline, the Western Mainline right now between now and kind of late 2020 early 2021. After that much in the Western Mainline has earned operating capacity, up and contracted.

The Eastern Mainline, in Eastern triangle we had different pieces of, so that’s contracted as well. So it is when you get the NGTL 2021 volume, we deliver the [indiscernible] Mainline that we see that asset showing up.

So beyond that, we do have as you would recall additional capacity that's not operational right now in the Mainline, Western Mainline and that provides us with some options to get more of the basin’s gas into market ais our customers are interested in talking about that.

And then just turning to the U. S.

northeast. Just wondering just given the low gas price environment.

Are you seeing any of your producer customers come to you asking for total relief? And maybe tied to that, what ability do you have to resell capacity if any of your customers really come under financial distress?

This is Stan. I can give you some color on that.

With respect to our northeast customers, first of all, we're holding well over a billion dollars of collateral, mostly in the form of letters of credit. And you can think of it averaging about one year's worth of coverage for any single customer.

Most importantly though we're seeing really strong usage on our pretty produce contracts, as a matter of fact our top producers are flowing load factors anywhere between 80% to 96% which basically tell me that they're getting proper value for their capacity. And we're seeing strong load factors across our entire system.

As a matter of fact, last year at January of 2019, we said a new peak day send that record across all 13 pipes at 33 Bcf. This winter has been relatively mild in terms of weather standards.

But notwithstanding that on January 20th, we had our second highest all time send out of 30 Bcf, so again strong demand across the entire system. I think most importantly with respect to the producer customers that we have in the Appalachian basin.

Not to get too far into the weeds, but there are three liquid pricing points at Appalachia, Columbia, Dominion and Tetco. Most of our customers have access to Columbia's pool, which is also known as TCO pool, and TCO pool trades about $0.10 higher than Dominion’s pool or Tetco’s pool.

And then furthermore, most of our customers have access to Gulf Coast markets via the Columbia Gulf system and that's raised at a 20% premium to Tetco or Dominion pool, so lot of value in the proposition relative to some of the other pipes for our customers. I think most importantly out of the Appalachian basin where we're finally starting to see the producers tap the brakes and that production has declined, seem to have hit a bit of a peak here in November at just over 33 Bcf a day through the first 10 days or so through February, production is down to about 31.8 Dcf, which is about 5% decline.

So as production continues to stabilize or decline, as LNG exports and other Gulf Coast markets continue to ramp up, I think we'll see producers grow out of this. With respect to relief, we haven't provided any relief to our customers other than working with them in the normal course of business to maybe amend receipt points or delivery points and give them flexibility to get the greatest usage they can out of their contracts.

I'll just ask questions here around Keystone/Keystone XL, I guess just on the existing system. If you can an update or have you been able to restore flow rates on the system?

And if you haven't, just what's the schedule of strongest flow rates to full capacity? The second just around KXL, Don, you talked about kind of the risk-reward.

I'm just wondering as you think about managing risk. Has anything changed in terms of the desire for something more tangible around backstopping, whether that's CGO line curve maybe an equity stake?

Robert, its Paul here, I'll speak to the existing system. We have not yet restored pressure to Keystone.

We don't have a timeline when we will. But we are managing that lower pressure through the use of DRA.

As we moved into Q1 here, I would anticipate that we would increase our flows as we implement the DRA back to normal operating levels. We saw reduced flows in Q4, because of, of course the outage we had and the time it took to restart.

And then it just takes time to catch up and restart your system.

Robert, its Don here. In terms of the risk-reward on XL, the conversations is much on a cadence and how we would parcel out or mitigate some of the risks that we don't have control over, such as last mile in that.

So that's being factored into it. In terms of a sell down to a CGO like to ownership level, that's not where we see this going.

We see ourselves controlling this project going forward. But absolutely in line to bring in partners here and we actually don't see ourselves proceeding on our own on this one.

Do you have in your mind how much, let's say, capital at least for 2020 that you would be willing to spend of your own ahead of the election?

I wouldn't go there at this point. There's a lot of scenario planning right now and we have to get through to the final stage gates and in terms of the final permits and legal issues right now.

So that's part of the conversation underway. But I can't give you a tangible dollar figure on that now.

And if I can just finish with, Don, the topic that you talked about Investor Day and you mentioned again today, potential for transformational opportunities. So just on that, you laid out your history at Investor Day, the types of things you've done typically for NGL asset with companies that have maybe had some trouble and there's been a lot of talk around gathering processing, the gathering processing has never really been your things.

So I guess as you think about maybe some of those crown jewel type assets, is there any kind of further things that have popped up any prospects? And then if you can maybe just talk about, would that really from your perspective, be confined to pipelines and then what would you be thinking in terms of any new geographies?

Yes, I described what we're looking at are our long-term secure annuity streams in businesses that we are comfortable with and that generally be very blue chip energy infrastructure. No, we haven't -- nothing has moved along or popped up that's got our attention.

We always have our perpetual wish lists at probably unrealistic prices that we would never transact that. But at this point in time, our plate is pretty full with $30 billion of stuff on the go and some potential large scale opportunities that may or may not advance here.

So we've got the balance to where we want it to be where we can actually actively think about these things if they do present themselves. But at this point in time, I would say the landscape is pretty spartan for anything transformational.

In the Q4 reports, there's commentary around converting our merchant revenues to long life annuity and cash flows. And perhaps you can remind us of what the sources of the merchant revenues are for your business and how I think interpretation, why's that?

Is that really just replacing contracts that are rolling off the contract, are you looking to bump at 95% plus, which is already pretty high to be in one?

Where we do have variability in our portfolio was really in two places. Volumetrically, it's pushing it south to the Gulf Coast on the Keystone market system.

And in terms of commodity price risk, it's generally restricted to the Alberta power market and some merchant gas storage in Alberta. So on the commodity price side generally it’s this quite small.

We're talking a couple of points here on EBITDA. In terms of the cushion at south assets if Keystone XL did go ahead, that would solve the problem right there by basically turning all that capacity or most of that capacity into 20-year contract.

And I'll add to that Ben, over the course of 2019 as we increase the capacity on Marketlink, we were able to increase the contracts. So we mean about 80% contracted on market link.

And we looked at our performance quarter-after-quarter relative to Q4 ’18 rather. Our contribution from Marketlink is higher in 2019 than it was in 2018.

We had much softer spot but we had converted some of that capacity to contracted revenue.

So it sounds that our opportunity is for cushion, which I had thought and then it's really the preference for you guys to get to pretty much almost close to 100% contract regulated. And then contract duration and I know there's a question around term of value assumptions and risk.

But I guess when I look at some of the projects you've announced last few years, Bruce Power, NGTL, KXL, I know there are 20, 35, 15 year contracts that you're adding. So is it fair to say that today or going forward your average contract on your assets?

I know you don't disclose this. Are they much longer than where they were say five, 10 years ago?

I would say it's a fair characterization. And again, I’d point you at Investor Day.

I showed a slide showing EBITDA through to 2030, that we have fairly high visibility of $10 billion of EBITDA walked in through the decade. And that's a testament to the contract length and the regulatory structures behind the vast majority of our assets here.

We wouldn't attribute a whole of recontracting risk into that profile either. So I think that statement that our average contract length is, duration is quite a bit longer today than it was five years ago is correct.

I think what we found Ben over the last few years is demand has continued to grow at that before in the gas business primarily for LNG export, but as well domestically as industries petrochemical, fertilizer and others, have returned to North America looking for long-term secure natural gas at low prices and looking for the cheapest way of getting that natural gas to their market and trying to secure that, either existing capacity or Brownfield capacity, because it's considerably cheaper. In Greenfield capacity it doesn't have, come with the same potential risks of not being able to build the Greenfield capacity.

So what we've seen is across the system, whether it’d be A&R, the Columbia systems, GTN, pretty much across the board, the mainline, refilling, what we're seeing is people wanting to secure that capacity and secure it for the long-term. So you think this is something like Coastal GasLink for example, 25 year contracts return of the capital.

They have the option of extending those contracts further, will adjust appreciation to allow a longer term to recover return on capital, but return on capital stays the same as you pointed out 2064 for Bruce Power. I think about the negotiation that we just went through with CFE for Sur de Texas, for example, we've actually converted from a 25 year contract to a 30 year contract.

So what we're seeing is the demand for existing capacity is very strong and people want to secure that capacity for a long period of time. And as you pointed out, we pretty much experienced that across our system.

I think about it on the oil side, to the extent that we are able to eat-out more capacity from the existing Keystone system, for example, we've talked a little bit about how we might be able to do that. And what we know is that if we had any more capacity on the Keystone system, we'd be able to sell it multiple times over under 20 year term.

So the existing capacity is becoming rare commodity and people want to sign up for and then secure it for the long-term.

There's a few pipelines now being built across North America with size, which is a change from the past few years. Are you seeing any signs of labor rate pressures or any supply chain impacts?

Andrew, it’s Paul here. I'll start.

We see a tighter market in Canada than we do in the United States and seeing contractors and suppliers and as part of our pre-construction activities the Keystone XL we are satisfied with the quality and the quantity of resources we have in U. S.

Canada is a little tighter than what we're seeing in the U. S.

but still ample capacity.

I'll add to that, Andrew. It's Tracy here.

We experienced the same things as Paul, of course we’re in the same markets and we've got a fairly substantial program on the NGTL system. We've got coastal gas kind of weigh in.

Of course, there's a few other projects that are going. The key to this is to contract well in early to make sure that you have the capacity from a prime perspective, but also that you moved to name certain folks from a labor perspective, because the supervision with some of these -- on some of these spreads is critical.

So we're doing that and we're satisfied so far that we're getting the right folks, and we're getting those contracts done. We are seeing some pressure from a labor perspective on prices as we go forward, and we're doing what we can to mitigate that.

And then maybe just to follow up somewhat related is just on some of the compressor upgrades that you've announced that you’ve got extra capacity on some of the lines. But could you maybe give a bit more color on just maybe some of the fuel efficiencies, lower emissions profiles and the other benefits that happen for shippers and for yourselves?

This is Stan. I can give you a real good example of projects that we have on our North Baja system where we're going to replace three old inefficient compressors with three new state-of-the-art compressors that in the end is going to reduce our GHG footprint on that pipe by 30%.

That in of itself is a big win for us. Similarly, when you look at Columbia's modernization program which year two of which -- or part two of which is going to be completed at the end of this year.

So far to date we reduced our emissions profile by about 150,000 tons and we've done this by not only mothballing inefficient compressions, but by putting new efficient facilities in place and by remediating a lot of leaks, particularly methane leaks where we reduced our footprint by 40% from 2016 to 2018. So this is something that we do just as a matter of course every time we have a project that we're looking to build.

We're asking ourselves how we can improve our environmental footprint as well.

Just kind of look at the capital plan, the annual report of the 8 billion the Investor Day out of that 7.2 billion. Just wondering if you can get some puts and takes on the higher capital plan moving forward?

Rob, that's fairly simple, it is our spend on Coastal GasLink until expected close of the JV and project financing transaction. At Investor Day, I was assumed to be around year-end but that will be sometime in Q1, Q2, probably Q2 here.

And then just when you take a look at your Alberta power exposure as it moves down in overall EBITDA percentage at some point, does it just make sense to exit that business and focus on the pipelines?

Rob, it’s Francois. I think that we see some strategic value in that portfolio.

The contracts are going to be rolling off over the next several years. We do have a strategic imperative to diversify our fuel mix, learn and familiarize our self with other technologies here in terms of broadening our technology base.

We have strong marketing and trading capability in Alberta. We're one of the incumbent traders in this market that affords us the opportunity to be active in that market, and it's a good market for us to experiment in.

We've underwritten solar PPAs that we talked about that last year. We're looking at some waste feed opportunities off of our natural gas compressors, as well as a combined solar and slow battery project.

So yes, it is modest in size relative to the size of the overall company. But strategically, we see it as an important line of business in our tool kit for potential future growth and we want to retain some of those core competencies.

A question on just liquids pipelines volumes outlook for next year. I wanted to confirm it sounds like it’s the combination of just from the ramp up gradually in volumes as you kind of get the resolution from the disruption last fall.

Is it also just a factor of I don't know maybe competitive volumes for the Permian in the sense of built out. Just kind of curious about how you look at this kind of beyond just the early 2020 scenario?

Alex, this is Paul here. I'll start with Keystone.

Keystone from Hardisty down to Cushing, Patoka, U. S.

Gulf Coast that pipeline is 94% contracted. We saw the lower volumes in Q4, because of the outage.

We continue under a de-rate, but we are managing the impact of that de-rate by using DRA. So I see the volumes on Keystone long haul ex-Hardisty to increase back to our 590,000 barrel per day range here in Q1, and will continue throughout 2020 and beyond.

Where we will see some variability is in our Marketlink system south of Cushing. We've seen a significant buildup of pipe buying capacity in the 2 million to 3 million barrel range over the course of about two year period, and that puts tremendous pressure on the Brent TI spread, which is pretty impressive back on the transportation days.

We consciously took what contracts we could during the course of 2018, 2019 so that we can maintain high flows on that pipeline, so about 80% contract there. Where we will see some softness is in the spot component on Marketlink.

There's some fairly intensive pipeline type competition. We are partially insulated with the contracts but we will see some soft spot buys, I think throughout 2020.

Just back to the base Keystone system here. Would you have an update on timing for the third party analysis of this bill?

And perhaps you could provide us with a base case assumption for when you might be in a position to bring on the incremental 50,000 barrels a day of capacity?

I don't have a timeline for the analysis that's with the third party consultant and we don't have anything in hand yet. We've been working with them on information exchange, et cetera, but that is something I just don't have any visibility into.

Until then under the corrective action order that we have with them, so we will stay in this de-rate situation. Until then, until the pressures are restored and we can continue on our capacity enhancement program, we will be operating at that somewhere around 590,000 barrel per day range.

If I had to venture a guess, I would say we would look to start increasing our capacity to accommodate the new contracts we achieved earlier this year in the open season. But it won't be until late this year and probably early 2021 before we stop ramping up those volumes.

And then any comment on how the upcoming regulatory decision here on the frontier project could impact the outlook for KXL directly or indirectly? Perhaps you could provide some color on what percentage of KXL commercial contracts are earmarked for oil sands projects that have already been fully approved or may still need [indiscernible] blessing?

We pick up our barrels at out of market hub at Hardisty. We don't have visibility upstream of Hardisty on the source of that crude.

Keystone XL today is fully contracted. It's fully contracted with the major producers in Alberta, the creditworthy counterparties.

So where we sit today, we have a fully contracted pipe. We're going to pick up of barrels at Hardisty and we look forward to providing the marketplace with those barrels.

And if I can just sneak in one last one here on the ESG front. And I agree with you Russ, I think you guys have a great story to tell.

And obviously, you will always target zero incidents on the safety front. But just curious if you'll be unveiling any five or 10-year targets throughout the course of the year as it relates to reducing emissions intensities or any other social or governance metrics?

I think we're continuing to work on what is it that our shareholders are looking to see. As you probably heard from Stan, internally, we have our own targets with inside of our businesses of what we're trying to achieve from environmental footprint perspective.

And what we have to do sort of what the marketplace wants to understand was that a lot of data, a lot of information and we're working with our shareholders to understand what is it they want to see. So we already have targets internally around what we're trying to achieve on a lot of fronts.

And I guess you'll stay posted in the coming months as we expand our disclosure around that front there. What I can tell you is there will be more.

Actually we have more to tell you. We have lots of data we're just trying to put it in a format that it’s useful for people and it’s what they want to hear and what they want to see.

On the temporary service protocol from the NGTL system, certainly been a positive pricing response there. I'm just curious can you comment on whether you've accomplished the short term goal there, and expect it to revert back?

Or do you expect this to come in and if so, when?

It's Tracy here. So the TFC of course is not in effect right now.

It’s something that'll be was in effect for the last section of the summer month of 2019, it will go into effect again in April and conclude in October to cover off the summer months. And what it’s intended to do is to -- it dictates how we will kind of impact flow when we're in for maintenance.

It has us impact flow by restricting receipts onto the system, which has the impact of allowing IT on the delivery side. And it’s storage that we're going after.

The fact that all storage access on IT basis, allows those summer flows to move into storage more effectively. And of course, the issue in the summer in the basin is that a good chunk of demand disappears as the weather gets better.

So you have a lot of supply looking for a market can't find it in needs to get to that that storage outlet. So we have been in the past and continue to work with our customers on alternative solutions for storage access in the summer months and actually all year round.

And we're working very actively right now on that file as to what the agreement is, its temporary service protocol will remain in place through the end of December period and it won't be extended.

And then just one last one, if I may. Can you provide some -- you touched on this at Investor Day.

But if you can provide some updated views on M&A, especially we're seeing in the LNG market, we've seen some pretty step downs in global pricing there. Any opportunity you see there or any other interests you might have sort of comment on.

So it’s Don again here. As I mentioned earlier, our plate is pretty full right now with our secured program and potentially moving projects more -- development program into our secured program.

We keep a pretty close eye on everything out there. At this point, I would say the landscape from our perspective hasn't changed.

There would be a very select number of opportunities we'd be interested in and possibly at prices that we’d never transact at. But no, I wouldn't say there's anything in our scopes at this point in time.

I wanted to follow up maybe on Praneeth’s question for Stan, you’d respond to his question about shippers in the northeast, specifically around the EMP or producer customers, but you also mentioned in your response production is started to decline a little bit. How do you feel about the marketing volumes that are on the pipe in terms of those contracts renewing and so forth?

The spreads in the different pools or a different hubs and they'll still stay on or is that a risk where they can potentially roll off and not be renewed?

This is Stan and most of our contracts are long-term in nature. So if you look across the entire Columbia gas system, their contract terms of eight years or more, A&R is about 10 years and more.

And specifically to the producer contracts, their initial terms were 15 and 16 year contracts that started two years ago. So we have another 12 or 13 years before we need to worry about contracts rolling off in any material size or scale with respect to our assets.

And maybe wondering if we can just sort of pivot to the dividend guidance that was presented today, you have a dividend guidance for this year and then you've got for 2021 of 8% to 10% EPS flat this year, but dividend is growing. So I assume the payout ratio is increasing.

With the growth next year as well, should we expect that the payout ratio is rising as well or is there growth offset? I'm just trying to square with all the efforts you've made to bring your leverage down.

Does this cause leverage to start going back up, especially with a little bit higher CapEx, or the agency is okay with that? Just wondering if you can sort of comment about the thought process with the Board with the targets that were set?

It's Don here. We take a pretty long-term view on this.

When you look back over a 20 year time horizon, we've largely been in the 80% to 90% of comparable earnings pay-out, and that's about 40% of cash flow. And given the robust 2019 that we've come off, we're probably below those ranges.

So we’ll grow back into them and our guidance going forward of 8% to 10% through '21 and then 5% to 7% thereafter, factors in no change to payout ratios and full compliance with the credit metrics I outlined earlier.

Interesting you said that, so when you’re saying that there'd be no change in payout ratio. Does that mean that we should sort of think that EPS will effectively grow in 2021 by 10% the fact that you…

No, we're probably below the 80% to 90% comparable earnings. If you look at 3.24 dividend on 4.14 of earnings, we're well below that range right now.

So again, if you're looking at this more less like an EKG chart more something that's long-term linear logarithmic, it 80% to 90% of comparable earnings. We’ll stray-in out of it from time-to-time but there's been no change over 20 years here on that.

You've heard us say at Investor Day and we’ve said it a number of times over the last 20 years or so. By allocating 40% of our free cash slow to dividends and 60% to growing our businesses, mathematically if we invest that 60% cash flow in that 7% to 8% kind of return range, we generate a long-term growth rate of 6%, 7%, 8%.

And over the last 20 years, we've reinvested about $100 billion. We generated growth rate of earnings and cash flow per share of about 7%, and hence the dividend growth rate of about 7%.

I think what Don is saying is over the long term, I don't think about it in annual terms, think about it over the next five years. Our expectation would be that we’d revert back to that, we've had some what we would call hyper growth in our world of about 8 to 10 over the last couple years, but we've got some tailwinds of interest rate reduction demand for our system buying Columbia.

They gave us some tailwinds to get into that 8% to 10% range. But I think what we're saying is long-term you can expect this to grow earnings and cash flow in that kind of range of your 5% to 7%.

And that you’ve’ got long-term track record of us doing that. And as we've always said, our dividend is based on sustainable increases in earnings and cash flow and those ratios that Don gave you are the ratios that we've used for the last 20 years.

So that's -- I think you look at our history and as we said this year, I mean we had a pretty good 2019 at the tailwinds of some pretty good commodity markets on our liquid side. Some tailwinds in filling all of our businesses, things that we don't expect to have reoccurring next year, I'd say we're in sort of hundred range on that 5% of our portfolio that’s variable.

And we're going to be -- in 2020, our expectations will be closer to P50 or less on that variable component. But overall, if you look at the growth rate of our earnings and cash flow per share, and that's our dividends per share, you see a number of 7% to 8% over 20-year period.

And the guidance introduced at Investor Day post 21 was 5% to 7%. And consistent with the long-term view and pay out some credit metrics and the like, where we are in that range and that's organic 5% to 7%.

It could be bolstered by transformational activity in the future that we never budget for but it's the mix of projects, the cadence of the projects and how we execute on those projects where we end up in those range. We added another 1.3 billion of projects today.

We think our asset base will continue to generate new opportunities in corridor here going forward. So again get long winded answer, but we're comfortable in that range.

But don't see any change to long-term payout metrics here at all.

When we think about the Bruce units 6 in CR this year, say just from a economic perspective to assume that the biggest impact is simply the lost megawatt hours. And if so how long -- is it a full year, is it just a couple of months?

How should we think about what the extent of those lost megawatt hours are during the year?

Michael, it's Francois. So the NCR Unit 6, we opened breaker on January 7th as expected and it's not expected, the MCR program is not expected to conclude on that unit 2023.

For the balance of the units, the other seven units that remain in operation you can expect there roughly mid-80% range availability on average over the course of this year and frankly over the next couple of years as well.

Thanks very much. And thanks to all of you for participating this afternoon.

We very much appreciate your interest in TC Energy, and we look forward to speaking with you again soon. Bye for now.