Good afternoon, ladies and gentlemen. Welcome to the CC Energy 2019 4th Quarter Results 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 TC Energy's 2019 Q4 conference call. With me today are Russ Kurling, President and Chief Executive Officer Don Marchand, Executive Vice President, Strategy and Corporate Development and Chief Financial Officer Francois Fourier, Chief Operating Officer and President, Power and Storage and Mexico Tracy Robinson, President, Canadian Natural Gas Pipelines Dan Chapman, President, U. S. Natural Gas Pipelines Paul Miller, President of our Liquids Pipelines Business and Glenn Manus, Vice President, Consumer Power.
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 website and 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 Jamie 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 an equal opportunity to participate, we ask that you limit yourself to queue questions.
If you have additional questions, please reenter 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 or your detailed financial models, 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 and Exchange Commission. And finally, during the 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 and comparable funds generated from operations. 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.
They are used to provide you with additional information on our operating performance, liquidity and ability to generate funds to finance our operations. With that, I'll turn the call over to Russ.
Thanks, David. Good afternoon, everyone, and thank you very much for joining us tonight in the afternoon. As highlighted in our Q4 news release, during 2019, our $100,000,000,000 portfolio of high quality long life energy infrastructure assets 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 strengthening of our balance sheet, we produced record financial results again in 2019.
Today, we are advancing $30,000,000,000 of secured capital projects that largely consist in corridor expansions of our existing assets. In addition, work continues on more than $20,000,000,000 of projects under development, including We also made significant progress in funding our secured capital 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 Korea pipeline in Alberta as well as the sale of certain Columbia 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 $2,400,000,000 Each of those transactions allowed us to surface significant value for relatively mature assets to 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 produced in 2019. We also expect our Solar's financial position to be bolstered in the first half of twenty twenty with the completion of the announced portfolio management and project financing activities. Last July, we entered into an agreement to sell our natural gas fired power plants in Ontario for approximately $2,870,000,000 subject to closing adjustments. That transaction is expected to close by the end of the Q1. And in late December, we announced an agreement to sell a 65 percent equity interest in our $6,600,000,000 Coastal GasLink pipeline project, and that is expected to close in the first half of twenty twenty.
As a result, we think that we are well positioned to fund our $30,000,000,000 portfolio secured growth projects without issuing any common equity from our dividend reinvestment plan. While we're proud of our financial performance and significant returns we've generated for our shareholders, we do know that our ongoing success depends on our ability to balance profitability with safety, environmental and social responsibility. We have a 55 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 published several investor 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 website at ttenergy.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 Q4 results and the outlook in just a few minutes. So excluding certain specific items, comparable earnings were $3,900,000,000 or $4.14 per common share for the year ended December 31, 2019, compared to $3,500,000,000 or $3.86 per share in 2018, which is an increase of about 7% on a per share basis.
Comparable EBITDA of $9,400,000,000 and comparable funds generated from operations at $7,100,000,000 were both 9% higher than last year. Each of these amounts represents record results for our company and reflect the strong performance of our legacy assets as well as contributions from $8,700,000,000 of new long term contracted or regulated assets that were placed into service in 2019. Based on the strength and our financial performance and our promising outlook for the future, TP Energy's Board of Directors declared a Q1 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 with amount declared in 2019 and is the 20th consecutive year that our Board has increased 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 5 operating businesses. Firstly, in our Canadian Natural Gas Pipeline business, customer demand for access to our systems remains strong, and we continue to work with industries on options to connect growing Western Canadian gas supply to markets across North America. Evidence that that can be seen in our announcement earlier today, you will see us invest another CAD900 1,000,000 in our 2023 NGTL Intra Basin System Expansion Program or incremental delivery capacity to serve oil sands, petrochemical demand, power generation demand and the utility sectors in Alberta. The expansion will add 309,000,000 cubic feet of capacity to the system and is underpinned by convenient contracts from shippers. Regulatory applications for that expansion are expected to be filed later this year with construction commencing as early as the Q4 of 2021, subject to receipt of regulatory approvals.
With this announcement, we are now advancing a CAD2.3 billion expansion program on Engine Scale that will add approximately 3,500,000,000 cubic feet a of incremental delivery capacity by the end of 2023. We also continue to actively work with LNG Canada on our coastal gasoline project. That's $2,600,000,000 project will have an initial capacity of 2,100,000,000 cubic feet a day with potential expansion capacity of 5,000,000,000 cubic feet a day. Coastal GasLink will play an important role in delivering Canadian natural gas overseas that will displace coal coal 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 Q4 and into 2020.
Today, we are proceeding on work at over 30 sites along the 8 30 kilometer route with over 1,000 men and women currently employed. On February 6, the RCMP began enforcing the Supreme Court of British Columbia interlocutory injunction prohibiting unlawful blockades that are preventing access to service roads in the Maurice River area of south of Houston, D. C. We're extremely disappointed. Enforcement was required to reopen the Maurice River for Service Road.
But we will continue our efforts to attempt to engage with the hereditary chiefs of the Wet'souten and the Unistat'en in search of a peaceful long term resolution that benefits all the people in that community. We'll also continue to engage with all indigenous and local communities, including all 20 of the population communities along the route who are benefiting from the social and economic development the project offers and want to see the project move ahead. Finally, we'll continue to work with the 21st Nations on an option to acquire a 10% equity interest in the project. That option was announced in late December when we advanced funding plans for the project by selling a 65% interest into the project to KKR and Aimco. We also expect Coastal GasLink will finalize a secured 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 twenty twenty and will substantially satisfy our under requirements through the project to completion. Looking forward, we'll continue to be responsible for constructing the operating pipeline and providing a positive long term legacy for the many local communities and First Nations in North and British Columbia. Finally, in the Canadian Natural Gas Pipelines business, in December, we are pleased to complete negotiations on a 6 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 increase costs, which will be shared between us and our customers. Moving now to our U.
S. Natural gas pipelines, which serve today approximately 25% of U. S. Diesel 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 referred to as the Helper Express project will add approximately 150,000,000 cubic feet of capacity to ANR.
Customers 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 Q3 of 2021 with in service expected to commence in 2022. The Elbert Express project in combination with existing capacity on our Magnus 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 Albert Express, we are advancing $1,500,000 of other capacity projects across our U. S. Natural gas pipeline network, which include the Hawkeye Express project, GTN Express, Eastern Lateral Express, Louisiana Express, and New Branch near Express Project. Each of those projects are along our existing footprint, highlighting the value of our extensive cost competitive North American network. Turning to Mexico, where 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 2,600,000,000 cubic feet a day of low cost, clean burning natural gas supply to Mexico. With the completion of Sur de Texas, we now have 5 operating pipelines in Mexico and another 2 pipeline projects under development. They include the Viadore project, which we expect to phase into service starting in the Q2 and have fully operational by the end of the year. Finally, Mexico's new B section of the Chula pipeline is now available for interruptible transportation service, although construction on the central segment continues to face delays. Chile is expected to enter service 2 years after indigenous consultations are successfully concluded by the Mexican government.
Turning to our liquids business, which generated very strong results in 2019. Keystone continued to produce solid results in the 4th quarter, although it was impacted by system outage and a pressured sea rate.
On the southern portion of
our system or what we call the U. S. Gulf Coast segment, capacity has increased during 2018 to more than 700,000 barrels a day and we maintained strong utilization through the Q4 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 4th quarter as new pipeline capacity was growing into service between the Permian and the U. S.
Gulf Coast. And finally, in the liquids business, we continue to advance the Keystone XL project. In March, the U. S. President Trump issued a new permit for the project, which should prohibited the 2017 permit and resulted in the dismissal of a litigation related to that old permit.
In August, the Nebraska Supreme Court affirmed the November 2017 decision by the Nebraska Public Service Commission and 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 SEIS was issued, including routing in Nebraska as well as updated information and new studies that were required.
And on February 7, we received 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 percent of the right of way for the pipeline through all states of 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 supplied 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 the 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 17.
He took that unit offline. We expect to invest approximately $2,400,000,000 in that program as well as the ongoing asset management program through 2023 when the U. S. 6 refurbishment is complete and returned to service. Bruce Power's contract price increased to $278 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 improvement failure on Napanee in 2019. That failure has now been resolved and final commissioning activities are progressing with commercial operations to are expected to commence in late in Q1. As a result, we expect the sale of the facility along with the Halton Mills plant and our interest in the Portland Energy Center to close by the end of the first quarter. The proceeds of approximately $2,870,000,000 will be used to help fund our industry leading capital program. In summary, today we are advancing $30,000,000,000 of secured growth projects that are expected to enter service by 2023.
We have approximately invested approximately $8,000,000,000 into that program to date with approximately $6,000,000,000 of these projects expected to be completed by the end of 2020. Notably, they are 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 case 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 of dividends we expect to be supported by sustainable growth in earnings and cash flow per share and strong coverage ratios. To close, I'll leave you the following key messages.
Today, we are a leading North American energy infrastructure company with a very strong track record into delivering long term shareholder value. Our assets are essential to the functioning of the North American society and the economy and the demand for our services remains strong. Looking forward, we have 5 significant platforms for growth: Canadian, U. S. And Mexico natural gas pipelines, liquids pipelines and power and storage.
As we advance our CAD30 1,000,000,000 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 $20,000,000,000 of projects in advanced stages of development and expect numerous other in corridor organic opportunities to emanate from our extensive critical asset footprint. And finally, our balance sheet is back to its place with historical strength and we are well positioned to fund our security capital program without the need for any additional comps equity. In 2020 beyond, we 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 in the grocery market value and improve society's well-being for decades come. With that, I'll turn the call over to Don, who will provide more details on our Q4 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 $1,100,000,000 or $1.18 per share in the Q4 of 20 19 compared to $1,100,000,000 or $1.19 per share for the same period in 2018. 4th quarter results included a positive 190 $5,000,000 valuation allowance release, recognized in the previously unrecorded benefit of certain prior year's U. S. Tax loss carryforwards, partially offset by a $61,000,000 increase in the after tax loss on the Ontario natural gas fired power plants held for sale and a $19,000,000 adjustment for the loss on the sale of certain Columbia Midstream assets.
In the case of the Ontario natural gas fired power plants, the accrued loss on sale will increase each reporting period after transaction close to reflect incremental spend and interest capitalized on Napanee. 4th quarter 2018 results also included several specific items as outlined on the slide and discussed in the Q4 2019 financial highlights 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 $970,000,000 in the Q4 in 2019, dollars 24,000,000 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 4th quarter, comparable EBITDA from our 5 operating segments was approximately $2,300,000,000 a $138,000,000 increase from 2018. Canadian Natural Gas Pipelines' comparable EBITDA of $618,000,000 was $200,000,000 lower than the same period last year, primarily on account of lower flow through depreciation and income taxes as well as lower incentive earnings in the Canadian Mainline due to recording the full year impact of the NEB 2018 decision in Q4 2018. I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA, but do 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 $20,000,000 compared to Q4 2018 as a result of higher investment higher average investment base and continued system expansions. Net income for the Canadian Mainline decreased $17,000,000 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 Pipelines' comparable EBITDA of US648 million dollars or CAD855 1,000,000 in the quarter rose by CAD35 1,000,000 or CAD43 1,000,000 compared to the same period in 2018. The increase was mainly due 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 and buy ins of 2018 customer agreements to pay out their future contracted revenues and terminate their contracts. Mexico Natural Gas Pipeline has comparable EBITDA of US125 million dollars or CAD165 million of CAD10 1,000,000 or CAD13 1,000,000 above Q4 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 timing of revenue recognition in 2018. Liquids Pipeline's comparable EBITDA declined by $66,000,000 to $472,000,000 in Q4 2019, driven by lower volumes on the Keystone Pipeline system and decreased contribution from liquids marketing activities due to lower margins and reduced earnings as a result of the partial monetization of Morgan 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 $43,000,000 year over year to $210,000,000 due to higher Bruce Power results, which were elevated by an increased realized power 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 1.32 in Q4 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 a rolling 1 year forward basis. Now turning to the other income statement items on Slide 18.
Depreciation and amortization of $625,000,000 decreased $56,000,000 versus Q4 2018, largely due to reporting the full year impact of increased depreciation rates approved in the Canadian Mainline MD 2018 decision in Q4 2018, partially offset by higher depreciation in the NGTL system and U. S. Natural gas pipelines, reflecting new projects placed in service. Interest expense of $586,000,000 for Q4 2019 was $17,000,000 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 20 18 2019 net of maturities. AFUDC decreased $44,000,000 for the 3 months ended December 31, 2019, compared to the same period in 2018, primarily due to Columbia Gas and Columbia Gulf Growth Projects Placed in Service, partially offset by continued investment in our system in Mexico projects.
Comparable interest income and other increased by $66,000,000 in the 4th quarter versus 2018, primarily as a result of lower realized losses in 2019 on derivatives 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 currency movements in the business units and
comparable EBITDA.
Income tax expense included in comparable earnings was $211,000,000 in Q4 2019 compared to $268,000,000 for the same period last year. The $57,000,000 decrease was mainly on account of lower flow through income taxes in 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 $76,000,000 in the 4th quarter decreased by $10,000,000 compared to the same period last year, primarily due to lower earnings in TC PipeLines LP. And finally, preferred share dividends were comparable to Q4 2018. Now turning to Slide 19.
During the Q4, we invested approximately $2,400,000,000 in our capital program, which was largely funded with comparable funds generated from operations of $1,800,000,000 along with DRIP proceeds from the 3rd quarter dividend, cash on hand and notes payable. Over the past several years, we have taken significant steps to return our balance sheet and financial flexibility to replace historical strength. That included the partial monetization of Northern Courier as well as the sale of certain Columbia Midstream assets and the Coolidge Generating Facility in 2019 for total proceeds of approximately $3,400,000,000 As a result, we exited 2019 having attained targeted net to EBITDA in the high 4s and in a position to fund our $30,000,000,000 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 twenty twenty. More specifically, closing the sale of our Ontario natural gas fired power plants and the partial monetization of the Coastal Gas Link.
In December, we entered into an agreement to sell a 65% equity interest in Coastal GasLink. Under its terms, we will receive upfront proceeds that include reimbursement of the joint venture partners' proportionate share of project costs incurred for 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 twenty twenty and substantially satisfy our funding requirements through project completion. The previously announced sale of our Ontario natural gas fired power plants for $2,870,000,000 is also expected to close in the Q1 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 3 years is projected to be $30,000,000,000 comprised of dead end and non controlling interest distributions of approximately $11,000,000,000 and capital expenditures of approximately $19,000,000,000 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 Express. The second column highlights aggregate sources including approximately $21,500,000,000 internally generated cash flow and $2,800,000,000 of proceeds from the pending sale of our Ontario natural gas fired power plants.
It also reflects $1,600,000,000 which we expect to receive under the Coastal Gas Wind secured project level construction credit facility for amounts spent by us to the date of close. That leaves a residual requirement of approximately $4,400,000,000 in the Far East 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 a 65% interest in Coastal GasLink. In summary, our external funding needs are imminently 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 $30,000,000,000 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 is being filed on SEDAR today and available on our website. 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 Pipelines earnings are expected to be higher than 2019, mainly due to continued growth in the NGTL system investment base, with the Canadian Mainline largely stable year over year, reflecting consistent incentive earnings and investment base. U. S.
Natural Gas Pipelines earnings 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 at 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 an incremental contribution from the Villa Terreas pipeline, which 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 the 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 Q1 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 AFGDC after placing new assets in service.
With respect to income taxes, excluding Canadian rate regulated pipelines where income taxes are a flow through item and are thus 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, but 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 $8,000,000,000 in 20 on growth projects, maintenance capital and contributions to equity investments. The majority of the capital expenditures are attributable to NGTL system expansions, gas modernization projects, the Bruce Power Life Extension program, normal course maintenance and Coastal GasLink prior to closing the sale of a 65% interest in the project. Subsequent to closing and the contemporaneous establishment of the secured construction plant 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 Q4 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 a $30,000,000,000 suite of secured projects and have 5 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 and 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 terminate further attractive and executable in corridor opportunities. That is expected to support annual dividend growth of 8% to 10% in 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 and 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 questions. If you have additional questions, please reenter the queue. With that, I'll turn it over to the conference coordinator.
And the first question is from Linda Vergari from TD Securities.
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 of how you also look at future scenarios and maybe just provide some context around that?
I'll take a first shot at it. Obviously, the issues related to sustainability have always been sort of far most in our minds, but that's the environmental stewardship, working with the communities that benefit from our projects. So we will continue to do those things. As you know, we've tightened our awareness around safety, for example. We've implemented a 0 is real program inside the company to make real progress.
We achieved 0 in a lot of 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 potential for at least in our pipeline systems. And we continue to evolve our processes and in the communities in which we operate, offering continually greater benefits for those communities and understanding what their concerns are. So with the foremost in our mind, what we've been doing from a reporting perspective is collating that information and providing into the investment community in a way that we hadn't in the past because folks are asking for that kind of information.
Based on that feedback as well, we'll continue to evolve that reporting around those kinds of issues. But what I can tell you is just 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 be environmental footprint, social responsibility, the diversity in our employment and management ranks. I think you just look at the results and see the continuous improvement and meet goals on an annual basis to continue to improve those things.
How does that inform your capital allocation decisions and how you might think about terminal values and discount rates, etcetera? Well,
I think clearly, I mean, it's in our business, those are concepts that we've thought about for a long time. If you think about lifespan of assets, depreciation is a concept that we have worked with our shippers and our regulators on over the years, as we've seen more times in the past where support demand or other fundamentals would point you to a shorter asset life, we accelerate depreciation, increase in abandonment surcharges, for example, and the opposite when we see that at certain locations, those assets are going to be around for longer. We expand those depreciation timeframes. So we continually look at that return of and on 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, put the pipe 4 feet under the river. We've changed our practices today. There are major river crossings. We drill underneath those rivers. And such that if you have the 100 year flooding kind of scenarios, the scouring and those kinds of things doesn't expose our price anymore.
So we continue to evolve our practices on all of these fronts. So when 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 have been made public. We do look at scenario analysis and we've looked at different supply demand scenarios that we could evolve in the future, including a 2 degrees reduction scenario that was put together with the supply by consultants. And then from that, we look at the revaluation 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 the people want to use going forward because of their low cost mix and their location and our ability 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 collated them and we provided them. You'll see 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. The single greatest reduction in greenhouse gas emissions in North America has been the displacement of coal fired generation in the United States. We played a large role in that. We 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 investment 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 B and B scenario analysis that we do and we're very comfortable with where we are today. And it's actually great opportunity as the marketplace evolves and looks for better and better environment performance from the energy infrastructure that supplies the energy that people need.
Okay. Thank you. If I can ask the 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 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 2019?
Hi, Linda. It's Tracy here. We those dialogues continue, I would say. What I would say to you is on a very collaborative basis, we all understand the importance of the NGTL system in the health and the growth of the basin as we come together with our customers to kind of form the principles around the solutions that we're looking for. The dialogue is going very well, and I would expect that we would have something we could talk about within the next 2 to 3 months.
And the range of outcomes?
Yes. Those, of course, would be subject to there's what the guys are talking about at the table. So it would be inappropriate, I think, right now to talk about what those are. Let them get through an interim agreement and then we'd be happy to have a conversation around what that looks like. Thank you.
Thank you. And the next question is from Jeremy Tonet from JPMorgan. Please go ahead.
Good afternoon. I just want 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. It seems like you have more clear sight, I guess, to what had happened 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 it does go forward, I imagine that they would reap very significant benefits. And so it seems like you'd be incentivized to the stakeholders in this project as well to support the development.
So I didn't know if you've heard anything from the EDC as far as support there or anything else you could comment on this topic.
Jeremy, it's Paul here. I'll just talk a little bit about the progress we have made and what is in front of us yet. So we did make some good progress here in the last few quarters. Receiving 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 our 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 percent of our land we need through Canada and U. S.
To build the pipeline. Going forward, we still require approval from the Encore Engine Jets for access to waters in the U. S. And there is outstanding litigation in federal court in Montana suggesting the 2019 presidential permit. Leave behind us before we move forward to an FID.
Yes.
Jeremy, it's Don here. We 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 describe it as constructive. And as Paul mentioned, we're in the final stage 8 here of getting through remaining approvals, cost in 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 moving positive moving parts here, but that's kind of the high level is how we see things.
That's helpful. And maybe if I could just go to Mexico for a minute here and spend 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 pipelines that came online, it seemed like Tula, there's room for IT there. Just wondering what the scope of those opportunities could be.
Any comments from that would be helpful. Yes, Jean Marie, it's Francois. First of all, you alluded to negotiations.
I think negotiations continue with the CSE and
the government of Mexico, and we would certainly characterize them as being constructive. As far as the fundamentals, there's still favorable and compelling demand for energy in Mexico remains strong and
is growing.
Low cost natural gas from the U. S. Is available and will lower the cost of electricity and reduce particulate emissions to replace diesel and fuel oil for power generation in various parts of the country. I would say that successful negotiations on sort of Texas serve as a good blueprint for how we're discussing
advancing negotiations on VDR
or Vila de Reyes and Tula.
And I think we would see
a successful conclusion of those negotiations as demonstrating a willingness for further foreign capital investment. And that would be a basis upon which we would look at future opportunities. Got I think I think until we resolve, as I alluded to, until we conclude negotiations on the 2 other contracts, I think we're comfortable with our exposure in Mexico. And with respect to equity volumes, I would characterize them as modest. But that is part of the solution set as we look to renegotiate the package of pipelines providing service, which is Central Mexico.
And the next question is from Robert Couillard from CFC. Please go ahead.
Okay. I'll start just on the interest rate environment. We're seeing some pretty low rates on the corporate bond side. Wondering if there's any more opportunities for you to recycle capital or refinance in a way where it benefits a Purdue shareholders?
It's Don here. There's a few pockets where that might that opportunity might present itself, But they're more bespoke rather than across our whole portfolio. The portfolio is pretty long term and pretty fixed rate. It's about 23 year average life, including hybrids to final call. Average rate is 5.2%, 90% area fixed.
A lot of the higher rate stuff is legacy debt that we used to finance rate base expansion in Canada many years ago. So it's flow through and any refinancing that, which we do look at from time to time would accrue 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. There's nothing that jumps out that there is some material compelling opportunity to refinance large profits
of our portfolio that would accrue
to the shareholder.
Okay. I assume now that you have the leverage where you want it, there's no particular incentive, just based on valuation to accelerate people recycling and portfolio management?
Yes, the metrics are where we want them. We believe the high 4s and debt to EBITDA, 15 percent FFO to debt area are the right places for us, given our when you look at it as a holistic portfolio, quite utility like in terms of our business position. And our balance sheet is where we want it. We pretty much like everything in our portfolio. Never say never.
Whenever we have an opportunity that arises that may require share count growth, we will obviously look at our portfolio and scour that to see if there is something there's some more compelling opportunity than increasing share
count. Okay. And then just finally, the last question I had is on the option for the 1st station on Colesogastric. Is there anything you could tell us there in terms of what term that option has? And maybe you can stick to their sense of desire to exercise 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 slowing down the extra 10% to third party? Thank you.
Yes, it's Don again here. I won't get into the details of where we are on the auction process other than to say that it's our expectation we'll end up at a 25 percent ownership stake in Coastal GasLink. Okay. Thanks very much.
Thanks, Rob.
Thank you. And the next question is from Shneesh Satish from Wells Fargo. Please go ahead.
Hi, thanks. Good afternoon. Just wanted to start on the Canadian 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?
Happy to. It's Tracy here. 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 of the Western mainline has or an operating capacity have been contracted. The Eastern Mainline, Eastern Triangle, we have different people with that's largely contracted as well.
So it is when we get the NGTL 2021 volume in the Northeast is not the main line that we see that asset. 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 as our customers are interested in talking about that. Okay. Thanks.
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?
Sure. 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 $1,000,000,000 of collateral, mostly in
the form of letters of credit.
And you can think of that as averaging about 1 year's worth of coverage for any single customer. Most importantly though, we're seeing really strong usage on our producer contracts. Matter of fact, our top producers are following 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, January of 2019, we set a unique day send out record across all 13 hikes at 32 Bcf.
This winter has been relatively mild in terms of weather standards, But notwithstanding that on January 20, we had our 2nd highest all time send out of 32 DCF. 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 deep into the weeds, but there are 3 liquid pricing points in Appalachia, Columbia, Dominion and TETCO. Most of our customers have access to Columbia's pool, which is also known as TECO pool. And TECO pool trades about $0.10 higher than Dominion's pool or TECO's pool.
And furthermore, most of our customers have access to Gulf Coast markets via the Columbia Gulf system and that trades at a 20% premium to TETCO or Dominion Pool. So, a lot of value in the proposition relative to some of the other pipes for our customers. And most importantly, out the Appalachian Basin, we're probably starting to see the producers tap the brakes and that production has declined. We've seen capped a bit of a peak here in November at just over 33 Bcf a day. Through the 1st 10 days or so through February, production is down to about 31.8 Bcf, which is about a 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.
And the next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Great. Good afternoon. I'm going to ask questions here around KeystoneKeystone XL, I guess just on the existing system. Is there 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 restoring the 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 said about managing risk, has anything changed in terms of the desire for something more tangible around backstopping, whether that's CGL like or maybe in Fintech.
Robert, it's Paul here. I'll speak to the existing system. We have not yet restored pressure to Keystone. We don't have a time line 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 course, the outage we had and the time to ship to restart. And then it just takes time to catch up and restart
your new system. Yes, Robert. It's Don here. In terms of the risk reward on XL, the conversation is as much on cadence and how we would parcel out or mitigate some of the risks that we don't have control over such as last mile and that. So that's being said.
In terms of a sell down to a CGL like ownership level, that's not where we see this going. We see ourselves controlling this project going forward. But absolutely, we don't be reminded to bringing 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, 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 the final stage gates in terms of 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.
Okay, understood. If I can just finish with the topic that you talked about at Investor Day and you mentioned again today, potential for transformational opportunities. So just on that, you laid out your history at Investor Day, types of things you've done, particularly crown jewel assets, other companies that have maybe had some trouble and there's been a lot of talk around gathering process and gathering processing has never really been your thing. 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 describe what we're looking at are long term secure annuity streams in businesses that we are comfortable with and that is generally very blue chip energy infrastructure. No, we haven't nothing has moved along or popped up that's caught our attention. We always have our perpetual wish lists at roughly unrealistic prices that we would ever transact at. But at this point in time, our plate is already full with $30,000,000,000 of stuff on the go and some potential large scale opportunities that may or may not advance here.
So we're we've got the balance sheet 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.
Okay. That's great. Thanks very much.
Thanks, Robert.
Thank you. And the next question is from Ben Pham from BMO.
In the Q4 report, there is a commentary around converting merchant revenues to long life annuity cash flows? And perhaps you can remind us what the sources of the merchant revenues are for your business? And I'm also curious, interpretation wise, is that really just replacing contracts that are rolling off the contract? Or are you looking to bump to 95% plus, which is already pretty high to begin with?
Yes. It's Don again here. Where we do have variability in our portfolio is really in 2 places. Volumetrically, it's pushing south to the Gulf Coast on the Keystone Market Link 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 that on the commodity price side, generally, it's quite small. We're talking a couple of points here on EBITDA. In terms of the Cushing South asset, 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 contracts.
Yes, I'll add to that. And over the course of 2019, as we increased the capacity on Market Link, we were able to increase the contracts. So we remain about 80% contracted on Market Link. When you look at our performance quarter after quarter relative to Q4 'eighteen rather, our contribution from market length is higher in 2019 than it was in 2018. We got much softer spot, but we had converted some of that capacity to the contracted revenue.
Okay. So it sounds like opportunity is a question which I had thought and then it's really preference for you guys to get to almost close to 100% contract regulated. And then contract duration, 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 mean those are 20, 35, 50 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 if you don't disclose this, are they much longer than where they were, say, 5, 10 years ago?
Yes, I would say that's a fair characterization. And again, I would point you at Investor Day, I showed a slide showing EBITDA through to 2,030 that we have fairly high visibility of $10,000,000,000 of EBITDA locked 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. You wouldn't attribute a whole lot of the contracting risk into that profile either. So yes, I think that statement that our average contract length is duration is quite a bit longer today than it was 5 years ago is correct.
I think what we found, Dan, over the last few years is, as you know, demand has continued to grow at that peak for in the gas business, primarily for LNG export, but as well domestically as industries, chemical fertilizer and others have returned to North America, looking for long term secured natural gas at low prices and looking for the cheapest way of getting that natural gas to the market and trying to secure that either existing capacity around field capacity is considerably cheaper than greenfield capacity doesn't have. They'll come with the same potential risk to not be able to build the greenfield capacity. So all we're seeing is across the system, whether it be here in our Columbia systems, GTN, pretty much across the board, the main line we're refilling up. What we're seeing is people wanting to secure that capacity and secure it for the long term. So you think that something like Coastal GasLink, for example, 25 year contracts return to the non capital, They have the option of extending those contracts further.
We'll adjust depreciation to allow a longer term to recover return on capital, but return on capital stays the same as you pointed out 2,064 for Bruce Power. I think about the negotiation that we just went through with CFE for Southern 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 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. Thinking about it on the oil side, to the extent that we are able to eke out more capacity from your 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, I think capacity is becoming a rare commodity and people want to sign up for and then secure for the long term. All right. That's great. Thanks, everybody.
Okay. Thanks, Ben.
Thank you.
And the
next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Suisse. There's a few pipelines
now being built across North America with size, which has changed 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 in camera scene, contractors and suppliers and as part of our construction activity for Keystone XL, we are satisfied with the quality and the quantity of materials we have in the 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're experiencing the same thing as Paul. Of course, we're in the same markets, and we've got a fairly substantial program.
On the MGTL system.
We've got Coastal Gas and Counterweight and of course there's a few other projects that are going. The key to this is to contract well and early to make sure that you have the capacity from a prime perspective, but also that you move to name certain folks from a labor perspective because the supervision of some of these on some of these spreads there 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.
Okay. That's helpful color. And then maybe just a follow-up on somewhat related just on some of the compressor upgrades that you've announced to keep the 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 just some other benefits that happen for shippers and for yourself? Shakir, this is Stan.
I can give you a real good example project that we have on our Norcross system where we're going to replace 3 old inefficient compressors with 3 new state of the art compressors that in the end is going
to reduce our GHG footprint
on that pipe by 30%. That in and of itself is a big win for us. Similarly, when you look at Columbia's modernization program, which year 2 of part 2 of which is going to be completed at the end of this year. So far to date, we've reduced our emissions profile by about 150,000 tonnes and we've done that by not only mothballing inefficient compression, but by putting that new efficient facilities in place and by remedying 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.
And the next question is from Rob Hope from Deutsche Bank.
Afternoon, everyone. Just taking a look
at the capital plan, the annual report has it at $8,000,000,000
The Investor Day has it at $7,200,000,000 Just wondering if you can get some puts and takes on the higher capital plan moving forward?
Yes, 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, that was assumed to be around year end, but that will be sometime in Q1, Q2, probably Q2 here.
All right. That's helpful. And then just when you take
a look at your Alberta power exposure,
that it moves down an overall EBITDA percentage. At some point, does it just make sense to exit that business and focus on the pipelines? I think Rob, it's Francois. I think we see some strategic value in that portfolio, yes. But 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 ourselves 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 heat opportunities off of our natural gas compressors as well as a combined solar and flow 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 and a toolkit for potential future growth, and we want to receive some of those core competencies.
All right. Thank you.
All right. Thanks, Rob.
Thank you. And the next question is from Alex Kania from Wolfe Research. Please go ahead.
Thanks very much. A question on
the liquids pipelines volume outlook for next year. I wanted to confirm, it sounds like it's a combination of just gradually in volumes as you as a resolution from the disruption last fall. Is it also just a factor of, I don't know, maybe competitive volumes for the Permian as that's built out. I'm just kind of curious about how you look at this kind of beyond just the early 2020 scenario.
Alex, it's Paul here. I'll start with Keystone. Keystone on Hardisty down to Pershing, Petrola, U. S. Gulf Coast.
That pipeline is 90% contracted. We saw the lower volumes in Q4 because of the outage. We continue under a derate, but we are managing the impact of that derate by using DRA. So I see the volumes on Keystone long haul ex pharmacy to increase back to our 590,000 sale per day range here in Q1 and will continue throughout 2020 beyond. Where we will see some variability is in our marketing system south of Cushing.
We've seen a significant buildup of pipe, mine capacity in the 2 to 3000000 barrel range over the course of about a 2 year period. And that puts tremendous pressure on the Brent TI spread, which is putting pressure back on the transportation values. We consciously took what contracts we put during the course of 20 18, 2019 so that we can maintain high flows on that pipeline. So we're about 80% contracted there. Where we will see some softness is in the spot component on Market Link.
There's some fairly intensive pipe on pipe competition. We are partially insulated with the contracts, but we will see some soft spot volumes, I think, throughout 2020.
And the next question is from Patrick Kenny from National Bank. Please go ahead.
Yes. Hey, guys. Just back to
the base Keystone system here. Would you have an update on timing for the 3rd party analysis of the still? And perhaps you can 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 capacity?
Hi, Patrick. It's Paul here. I don't have a time line for the cause failure analysis. That's with a 3rd party consultant. And we don't have anything in hand yet.
We've been working with them on information exchange, etcetera. But that is something I just don't have any visibility into. Until then, under the effective action
order that we have with FEMSA, we
will stay in this E Rate situation. Until then, until the pressures are restored and we can continue on our capacity enhancement program, we will be operating assets somewhere around the 590,000 barrels per day range. If I had to make sure I guess, I would say we would look to start increasing our capacity to accommodate the new contracts we had seen earlier this year in the open season. But it won't be until late this year and probably early 2021 before we start ramping up those volumes.
Okay. That's great. And then could you comment on how the upcoming regulatory decision here on the Frontier project could impact the outlook for KXL directly or indirectly? First, if 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 otherwise blessing?
Yes. 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. Shipton XL today is fully contracted. It's formally contracted with the major producers in Alberta, the creditworthy counterparty.
So, we think today we have a fully contracted fleet. We're going to pick up our barrels at Hardisty and
we look forward to providing the marketplace
with those barrels.
Okay, great. I'll 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 0 incidents on the safety front. But just curious if you'll be unveiling any 5 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, certainly 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. We've got a lot of data, a lot of information, and we're working with our shareholders to understand what it is that they want to see. So, clearly have targets internally around what we're trying to achieve on a lot of fronts. And I guess, just 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 because we have more to tell you. We have lots of data. We're just trying to put it in a format that is useful for people and it's what they want
to hear and what they
want to see.
And the next question is from Mark Taylor from Tudor, Pickering, Holt.
Yes. Thanks for taking my questions here. On the temporary service protocol from the NGTL system, certainly been a positive pricing response there. I'm just curious if you can comment on whether you've accomplished the short term goal there and expect to take a word back or do you expect this to come permanent if that one?
It's Tracy here. So the TSG course is not in effect right now. It's something that will be was in effect for the last section of the summer months of 2019. It will go into effect again in April and concluded in October to cover off the summer months. And what it's intended to do is to indicate how we will kind of impact flow when we're in for maintenance.
It has us impact flow by researching 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 an IT basis allows those summer flows to move into storage more effectively. Of course, the issue in the summer in the basin is that a good chunk of demand disappears as the market gets better. So you have a lot of supply looking for a market, can't find it and needs to get to that storage outlet.
So we have been in the past and continue to work with our customers on alternative solutions for storage access the summer months and actually all year round. And we're working very actively right now on that file. So what the agreement is, is temporary service protocol will remain in place through the end of this summer period and it won't be extended.
Great. Thanks for that, Tracy. And then just one last one, if I may. Can you provide some in terms of this at Investor Day, we could provide some updated views on M and A, especially we're seeing in the LNG market, we've seen some pretty split downs in global pricing there. Any opportunities to see there?
Any other interest you might have just commenting on?
Yes. It's Don again here. As I mentioned earlier, our plate is pretty full right now with our secured program and potentially moving projects from our and 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'd 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 scope at this point in time.
And the next question is from Shneur Gershuni from UBS. Please go ahead.
Hi, good afternoon, everyone. I wanted to follow-up on the question before Stan. You had responded to his question about shippers in the Northeast, specifically around E and Ps or producer customers. But you also mentioned in your response, production has started to decline a little bit. How do you
feel about the marketing volume on the
pipe in terms of new contracts renewing into the 4th, the spreads in different pools or the different hubs, I mean they'll still stay on? Or is that a risk that they can potentially roll off and not be renewed? This is Stan. Most of our contracts are long term in nature. So if you look across the entire Columbia Gas system, there are contract terms of 8 years or more.
ANR is about 10 years and more. And specifically to the producer contracts, their initial terms were 15 16 year contracts that started 2 years ago. So we have another 12 or 13 years before we need to worry about contracts rolling off and any material size or sale with respect to our assets. Okay. Fair enough.
And maybe wondering if we can just sort of pivot to the dividend guidance that was presented today. Your dividend guidance for this year and then you've got for 2021 of 8% to 10%. EPS is
flat this year, but the
dividend is characterized here and 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 that growth offset? I'm just trying to square it with all the efforts you've made
to bring your leverage down, business calls, 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 target that we're set.
It's Don here. We take a pretty long term view on this. We when you look back over a 20 year time horizon, we've largely been in the 80% to 90% of comparable earnings payout, and that's about 40% of cash flow. And given the robust 2019 that we've come off of, we're probably below those ranges. So we'll go back into them.
And our guidance going forward of 8% to 10% through 'twenty one and then 5% to 7% thereafter factors in no change to payout ratios and full compliance with the credit metrics I have learned earlier.
Interesting you
said that.
So when you're saying that you see no change to carry, so does that mean that we should sort of think that EPS will affect your EBITDA in 2021 by 10% effective in the stock price?
No, we're probably below the 80% to 90% comparable earnings. If you look at the 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's 80% to 90% of profitable earnings. We'll stay in and out of it from time to time. But that's there's been no change over 20 years here on that.
I think you 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 flow to dividends and 60% just growing our businesses mathematically if we invest that 60 percent cash flow in that 7% to 8% kind of return range, we generate a long term growth rate of 6%, 7%, 8%. Over the last 20 years, we've reinvested about $100,000,000,000 We've generated growth rate of earnings and cash flow per share above 7% and hence the dividend growth rate of about 7%. I think what John is saying is over the long term, I don't think about it in annual terms, think about it over the next 5 years. Our expectation would be is that we would revert back to that. I mean, we've had some what we would call hyper growth in our world of about 8% to 10% over the last couple of years, but we've had some tailwinds of new interest rate reduction demand for our system.
Buying Colombia, they gave us some tailwinds to turn in at 8% to 10% range. But I think what we're saying is a long term, you can expect us to grow earnings and cash flow in that kind of range of 5% to 7%. And you've got a 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, it's on the ratio that we've used for the last 20 years. So that's when you look at our history, and as we said this year, we had a pretty good 2019.
We had tailwinds of some pretty good commodity markets on our liquids side, some tailwinds in filling all of our businesses, things that we don't expect to have recurring next year. I'd say we're in sort of 800 range on that 5% of our portfolio that's variable. In 2020, our expectations will be closer to $50,000,000 or less on that variable component. But overall, if you look at the growth rate of our earnings cash flow per share and that's our dividend per share, you'd see a number of 7% to 8% over a 20 year period.
Yes. And the guidance introduced at Investor Day post 'twenty one was 5% to 7%. And consistent with the long term view and payouts and credit metrics and the like, where we are in that range, and that's organic by 7%. It could be bolstered by transformational activity in the future that we have a 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 on those range.
We added another $1,300,000,000 of projects today. We think our asset base will continue generate new opportunities in corridor here going forward. So, again, long winded answer, but we're comfortable in that range, but don't see any change to long term payout metrics here at all.
All right. Perfect. Thank you very much and I appreciate the
And the next question is from Michael Lapides from Goldman Sachs.
I'll be real quick. When we think about the Bruce unit 6 in CR this year, 6 just from an economic perspective to assume that the biggest impact is simply the loss of 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 expense of those lost megawatt hours are during the year? Michael, it's Francois. So the MCR Unit 6, we opened breaker on January 7 as expected, and it's not expected the MCR program is not expected to conclude on that unit until 2023. For the balance of the units, the other 7 units that remain in operation, you can expect roughly mid-eighty percent range availability on average over the course of this year and frankly over the next couple of years as well.
Got it. Thank you, guys. Much appreciated.
Thanks, Michael.
Thank you. Ladies and gentlemen, this concludes the question and answer session. If there are any further questions, please contact TC Energy Investor Relations. I will now turn the call over to Mr. Moneta.
Please go ahead, Mr. Moneta.
Thanks very much, and thanks to all of you for participating this afternoon. We very much appreciate your interest in TPMG, and we look forward
to speaking with you again soon. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.