TC Energy Corp (TRP) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 fourth-quarter results conference call. I will now turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone. I'd like to welcome you to TransCanada's 2015 fourth-quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President, Corporate Development and our Chief Financial Officer; Alex Pourbaix, Chief Operating Officer; Karl Johannson, President of Natural Gas Pipelines; Paul Miller, President of our liquids pipelines business; Bill Taylor, President of Energy and Glen Menuz, Vice President and Controller.

Russ and Don will begin today with opening comments on our financial results and certain other Company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. It can be found in the investor section under the heading events and presentations.

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two 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, Stuart and I would be pleased to discuss them with you following the call.

Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the US Securities Exchange Commission.

And finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation, and amortization or EBITDA, comparable EBITDA, funds generated from operations, and distributable cash flow. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures.

As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada'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. And good afternoon, everyone. And thank you very much for joining us this afternoon. Although 2015 was a very challenging year for the energy industry across North America, I'm very proud to report our portfolio of high quality long life critical energy infrastructure assets performed very well.

Our $64 billion asset base is largely underpinned by cost to service regulated models or long-term contracts with solid counter parties. As a result, our cash flows are highly predictable, with minimal commodity and volumetric risk.

In 2015, excluding non-recurring items, comparable earnings and funds generated from operations reached record levels, while we continued to deliver the energy millions of people across North America rely on every day. In addition in 2015, we initiated a restructuring that was focused on further improving the performance of that base business and providing the organizational platform for us to continue to grow. Looking forward, we remain well positioned to continue to grow earnings, cash flow and dividends in the years ahead.

We are proceeding with CAD13 billion of near-term growth opportunities that are expected to be in service by 2018 and based on the stability of our base business, that visible near-term growth, and our financial strength, we expect to continue to grow our dividend at an average annual rate of 8% to 10% through 2020. Over the medium- to longer-term, we continue to advance CAD45 billion of commercially secured large scale projects that have the potential to transform our Company and augment and extend our dividend growth expectations and create substantial long-term shareholder value.

Obviously, we were extremely disappointed by the arbitrary and unjustified denial of the presidential permit for Keystone XL in early November. As a result of that denial, the Company recorded a CAD2.9 billion after-tax non-cash impairment charge. This impairment charge was the primary reason for the reported loss attributable to common shares of CAD1.2 billion or CAD1.75 per share for the year ended December 31, 2015.

In response to that denial, in early January, we filed a notice of intent to initiate a claim under chapter 11 of the North American free-trade agreement and in addition we filed a lawsuit in the US Federal Court in Houston, Texas, asserting that the President's decision to deny the construction of Keystone XL exceeded his power under the US Constitution.

Excluding the Keystone XL impairment charge and other non-recurring items, comparable earnings were CAD1.8 billion or CAD2.48 per share. Comparable EBITDA was CAD5.9 billion. Funds generated from operations were CAD4.5 billion and comparable distributable cash flow was CAD3.6 billion or CAD5.12 per share.

Through 2015, we continued a focus on maintaining a great credit, access to capital markets and allocating capital to enhance shareholder value. During 2015, we raised over CAD5.5 billion of debt in subordinated capital at very attractive rates to fund our capital growth program and we initiated a shareholder buyback program which saw us repurchase 7 million shares or about 1% of our outstanding common stock.

We do recognize the value our shareholders place on a stable and growing dividend. Based on continued growth in sustainable cash flow and earnings, our Board of Directors approved an annual quarterly dividend of CAD0.565 for the fourth quarter ending March 31, 2016. That equates to CAD2.26 on an annual basis for 2016, representing an CAD0.18 or 9% increase over 2015.

This is the 16th consecutive year the Board has raised the common dividend and our objective continues to be to grow the dividend in conjunction with sustainable increases in cash flow and earnings. Based on the stability of our base business, as I said, our visible near-term growth projects, financial strength, we expect to continue to grow that dividend, as I said, at an 8% to 10% rate through the rest of the decade. If we're successful in advancing additional growth initiatives, dividend growth could be augmented and extended.

Before I pass the call to Don to provide more details of the financial results of both the quarter and the year, I'd like to provide you some updates on the strategic initiatives that occurred during the last quarter starting with our gas business. In November, we announced a CAD570 million expansion of the NGTL system for 2018 that includes multiple projects.

We plan to file various applications with the National Energy Board needed to build and operate the required facilities between the second and fourth quarters of this year. Construction would start in 2017 with all of the [soes] expected to be operational in 2018.

Including the 2018 expansion, the NGTL system now has CAD5.4 billion of new supply and demand facilities under development over the next three years. CAD2.3 billion of these facilities have been approved the regulators and another CAD2 billion is working their way through the regulatory process.

In December, we reached a two-year revenue requirement agreement with our customers and other interested parties on the annual costs including return on equity and depreciation required to operate the NGTL system for 2016 and 2017. In Mexico, progress continues as well.

In November, we were awarded a contract to build and owned and operate the $500 million Tuxpan-Tula natural gas pipeline under a 25 year contract with Mexico's state-owned electric utility. Construction is expected to begin in 2016 and the pipeline should be operational in the fourth quarter of 2017. The $1 billion Topolobampo project and the $400 million Mazatlan natural gas pipeline are in the final stages of construction and are expected to be operational in late 2016.

In our US pipeline division, ANR filed a section 4 rate case in late January that requests an increase in ANR's maximum cap transportation rates. Changes in ANR's traditional supply sources, markets, necessary operational changes, needed infrastructure updates and an evolving regulatory requirement are driving the need for investment in the pipeline system as well as driving higher operating costs. As a result, current tariff rates would not provide a reasonable return on investment.

In parallel, with the FERC application process, we will pursue a negotiation with our customers in an attempt to achieve a mutually beneficial outcome and as always our preference is to settle rates with our customers if we can. ANR's last rate case filing was more than 20 years ago.

Moving over to liquid side of our business, construction continues on the $1 billion Northern Courier project. 100% of that pipeline's capacity is contracted with the Fort Hills partners under a 25-year shipping agreement. We expect that project to be ready for service in 2017.

Construction is progressing on the Grand Rapids project, a partnership with Brian Energy, with each partner owning 50% of the pipeline. Phase I of that initiative, which will require CAD900 million in investments for our share, is expected to begin transporting crude oil in 2017. We will continue to assess Phase II of the project and the in-service date will depend on there being sufficient demand for that project.

On the energy side of our business, we achieved a major milestone in the fourth quarter. In early December, we announced that Bruce Power had entered into an agreement with the Ontario Independent Electric System Operator to extend the operating life of the Bruce Power facility to 2064 or close to four decades of more operation. This agreement provides the Ontario residents with affordable, reliable, emissionless energy for decades to come and provides TransCanada shareholders with a very attractive and secure investment opportunity for many years to come.

This agreement is an extension and a material amendment to the earlier agreement that led to the refurbishments of units one and two at the site. The agreement provides a framework to refurbish the remaining six units at the site between 2020 and 2033. Our estimated share of investment in the asset management capital program to be completed over the life of the agreement is approximately CAD2.5 billion, and that's in 2014 dollars, and our share of the major component replacement work is approximately CAD4 billion for work on units three through eight over the 2020 to 2033 timeframe. Again, those are in 2014 dollars.

TransCanada also exercised its option to acquire an additional 14.89% interest in Bruce B for CAD236 million from the Ontario municipal employees retirement system, equalizing our ownership with our major partner in that facility. Bruce A and Bruce B merged into one entity and we now hold 48.5% interest in the combined Bruce entity.

Also in February, we completed an agreement to acquire the 778-megawatt Ironwood Power Plant in Lebanon, Pennsylvania from Cowen Energy for $657 million. That acquisition is expected to be immediately accretive to cash flow and earnings and generate approximately $90 million to $110 million of EBITDA. The Ironwood Power Plant delivers energy into the PJM power market and will provide us with a solid back stop to our existing marketing business in that region.

Construction continues on the 900-megawatt Napanee plant and located in eastern Ontario and is now about 25% complete. The facility will provide clean energy under a 20-year supply contract with the provincial Independent Electric System Operator and that CAD1 billion plant is expected to be operational in late 2017 or early 2018.

Moving to our longer term projects, on Energy East we filed an amendment in mid-December to the existing application with the National Energy Board that adjusts the proposed pipeline route, scope and capital costs, which now sits at approximately CAD15.7 billion. We also updated information related to our CAD2 billion Eastern Mainline Project, highlighting an agreement with eastern local distribution companies that resolves their issues with Energy East.

What we know is that pipelines remain the safest and least greenhouse gas intensive way of transporting oil to Canadian refineries. Energy East has the capacity to displace approximately 1,570 rail cars of crude oil per day to eastern Canada. We are in the process of assessing the potential impacts to Energy East of the Federal Government's announced changes to the regulatory review for pipelines, however we remain committed to a 2020 in-service date at this time.

In the quarter, we continued to advance our two west coast large scale gas transmission projects, the CAD5 billion Prince Rupert Gas Transmission Project now has all the primary regulatory permits required from the BC Oil and Gas Commission and the BC Environmental Assessment Office. Pacific Northwest LNG is awaiting a positive regulatory decision related to an environmental assessment that has been conducted by the government of Canada and we saw a drop report today which we continue to review.

We remain on target to begin construction of the Prince Rupert Project following confirmation of a final investment division from Pacific Northwest LNG. The in-service date is estimated to be 2020, but will be aligned with Pacific Northwest LNG's liquefaction facility timeline.

On our CAD4.8 billion Coastal GasLink Project, we signed five more project agreements with First Nations in northern BC during the quarter, bringing that overall total to 11. We've received 8 of our 10 permits from the BC Oil & Gas Commission for that project and we anticipate receiving the remaining two permits need in the first quarter of this year.

The Coastal GasLink Project has also received its environmental permits from the BC Environmental Assessment Office. The project team continues to work with our partner through the regulatory process with a focus on supporting a positive final investment decision later this year.

Before I wrap up, I'd like to make a few more comments regarding the restructuring and transformation initiatives that we began implementing in the middle of last year. In order to streamline our decision-making processes at the Company, improve efficiencies and our competitiveness, enhance our capacity to grow our existing portfolio of projects, we initiated a plan to decentralize many of our operating, project and functional support groups, placing greater responsibility and accountability on our business unit leaders for decisions that impact their areas of responsibility.

The restructuring will provide a clear focus of safety, generate efficiencies and operations, optimize availability, streamline decision-making, and maximize the value of each of our business units. This will lower our costs for both TransCanada and our customers. Don will provide you a few more details on the financial impacts of that reorganization in a minute, but what I would say is that it has moved along very well to date.

So to conclude, our portfolio of high-quality energy infrastructure assets performed very well in the quarter and in the year. Excluding non-recurring items, comparable earnings, and funds generated from operations in 2015, reached record levels. Looking forward, our base business will continue to grow with CAD13 billion of commercially secured projects coming into service by 2018 and because all of those projects are largely regulated or contracted, our future cash flows will become proportionally even more stable and predictable than they are today.

Our strong financial position, our growing cash flow means that we are well positioned to prudently fund our capital programs and continue to grow our dividend at an average annual rate of 8% to 10% through the end of the decade. Over the medium- to longer-term, as I said, we continue to advance CAD45 billion of commercially secured large scale projects that have the potential to create substantial additional long-term shareholder value.

It is our expectation that disciplined execution of our plan will lead to growth in cash flow, earnings, and dividends and create enduring long-term shareholder value. I'll now turn the call over to Don for a few more details on our financial performance in both the fourth quarter and 2015. Don?

Thanks, Russ, and good afternoon, everyone. As highlighted in our news release this morning, we reported a net loss in the fourth quarter of CAD2.5 billion after-tax or CAD3.47 per share. This compares to reported net income in the same quarter of 2014 of CAD458 million or CAD0.65 per share. As Russ indicated, the loss primarily stems from a non-cash impairment charge of CAD2.9 billion related to our investment in Keystone XL.

In addition, there were a number of other specific non-comparable items in the fourth quarter. These include an CAD86 million after-tax loss on the sale of TC Offshore, a CAD60 million after-tax charge for our restructuring and business transformation initiative, a CAD43 million after-tax charge related to an impairment of turbine equipment held for future use in energy, a debt retirement charge of CAD27 million after-tax related to the merger of Bruce A and Bruce B, and a positive CAD199 million impact to our non-controlling interests in TC Pipelines LP related to the impairment of their equity investments in Great Lakes.

Excluding these items, comparable earnings for fourth quarter 2015 were CAD453 million or CAD0.64 per share compared to CAD511 million or CAD0.72 per share for the same period last year. For the year ended December 31, 2015, comparable earnings reached a record CAD1.8 billion or CAD2.48 per share compared to CAD1.7 billion or CAD2.42 per share in 2014. Lower contributions in the quarter from Canadian Power and the Canadian Mainline were partially offset by higher earnings from the Keystone System compared to 2014.

In terms of our business segment results at the EBITDA level, our Natural Gas Pipelines business generated comparable EBITDA of CAD984 million in fourth quarter 2015 compared to CAD884 million for the same period last year. Canadian gas pipelines comparable EBITDA of CAD645 million was largely unchanged compared to 2014.

For the quarter, net income from the Canadian Mainline decreased by CAD63 million compared to the same period last year. The reduction was primarily related to a lower ROE of 10.1% in 2015 versus 11.5% in 2014 and CAD59 million of full-year after-tax incentive earnings that were recorded in the fourth quarter of 2014 following the NEB approval of our 2015, 2020 tools application.

NGTL's quarterly net income increased CAD10 million year-over-year to CAD69 million due to a higher average investment base and OMNA incentive losses realized in 2014 that were not repeated in 2015. US and International Natural Gas Pipelines comparable EBITDA of CAD347 million increased CAD98 million compared to fourth quarter 2014, primarily as a result of higher contracted transportation revenue on ANR's southeast mainline and the positive impact of a stronger US dollar.

In liquids, the Keystone pipeline system generated CAD348 million of comparable EBITDA in the fourth quarter. This represents a CAD54 million year-over-year increase and is the result of higher contracted transportation volumes along with the favorable impact of a stronger US dollar.

Turning to energy, comparable EBITDA was down CAD110 million to CAD275 million in the fourth quarter. Within the energy segment, Western Power comparable EBITDA decreased CAD60 million due to lower realized power prices and lower purchased EPA volumes.

Eastern Power EBITDA fell CAD26 million year-over-year, primarily due to lower earnings in the sale of unused natural gas transportation. Bruce Power equity income of CAD83 million declined CAD32 million from 2014 due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, partially offset by higher volumes resulting from fewer planned outage days and lower lease expenses at Bruce B.

US Power comparable EBITDA increased by CAD12 million compared to last year due to a stronger US dollar and higher generation at Ravenswood, partially offset by lower capacity revenue at Ravenswood and lower realized prices in New England. Natural Gas Storage comparable EBITDA decreased CAD5 million to CAD7 million in fourth quarter 2015 due to lower realized storage spreads.

Now turning to the other income statement items on slide 22. Comparable interest expense of CAD380 million in the fourth quarter increased CAD57 million compared to the same period last year. This was primarily due to higher interest charges on recent US debt issues, partially offset by scheduled debt maturities, higher foreign exchange on interest denominated in US dollars, and lower capitalized interest primarily due to the cessation of interest capitalization on Keystone XL following the November 6, 2015 denial of the US Presidential Permit.

In fourth quarter 2015, comparable interest income and other increased by CAD36 million over the same period in 2014 due to the net effect of increased AFUDC related to our rate regulated projects, primarily Energy East and Mexico. Higher realized losses on derivatives used to manage our net exposure to foreign exchange fluctuations on US dollar denominated income, and a negative impact on the translation of foreign currency denominated working capital.

In 2016, translation of our US dollar denominated income streams net of the natural hedge of interest on our US dollar debt and our active foreign currency management program is expected to have a positive year-over-year impact on our Canadian dollar earnings. Comparable income tax expense for fourth quarter 2015 decreased CAD8 million versus the same period last year, mainly as the result of lower pretax earnings and changes from the proportion of income earned between Canadian and foreign jurisdictions.

Comparable net income attributable to non-controlling interests increased by CAD17 million for the three months ended December 31, 2015, compared to the same period in 2014, primarily due to the sale of our remaining 30% direct interest in GTN in April 2015 to TC Pipelines LP, along with the impact of a stronger US dollar on the Canadian dollar equivalent earnings from the LP. Preferred share dividends were CAD23 million for the three months ended December 31, 2015, similar to 2014 levels.

Now moving on to cash flow and investing activities on slide 23. As discussed at Investor Day in November, we are now including a distributable cash flow as a supplementary performance metric. We do, however, reiterate our old school view that earnings matter and EPS continues to be our primary performance measure. Cash flow remains solid with funds generated from operations of approximately CAD1.2 billion in the quarter and reaching a record CAD4.5 billion for the year.

For the fourth quarter, comparable distributable cash flow was CAD778 million or CAD1.10 per share. On a full year basis, comparable DCF rose to CAD3.5 billion or CAD5 per share from CAD3.4 billion or CAD4.81 per share in 2014 driven by higher funds generated from operations, partially offset by higher maintenance capital primarily on ANR. Maintenance capital in our Canadian-regulated natural gas pipelines was CAD347 million in 2015 versus CAD355 million in 2014.

Capital spending totaled CAD1.2 billion in the fourth quarter, driven principally by construction activities in Mexico, on the NGTL system, ANR, Northern Courier, and the Canadian mainline, as well as at the Napanee power generating facility. Equity investments of CAD190 million in the quarter related to spending at Bruce Power in Grand Rapids, while acquisitions of CAD236 million reflects the exercise of an option to acquire the additional ownership stake in Bruce B from OMERS in December.

Now turning to slide 25, liquidity and access to capital remains strong. At December 31, our consolidated capital structure consisted of 30% common equity, 5% preferred shares, 4% junior subordinated notes and 61% debt net of cash. Book equity in the quarter was negatively impacted by the non-cash impairment charge on Keystone XL. Our flagship A grade senior unsecured credit ratings at TCPL were however reaffirmed all with a stable outlook.

Our liquidity remains sound comprised of predictable and growing cash flow generated from operations, well supported commercial paper programs backed by approximately CAD7 billion of undrawn committed credit facilities, and our ongoing access to capital markets in both Canada and the US across our capital structure on compelling terms. At December 31, we had CAD850 million of cash on hand and we continue to maintain significant capacity on all of our debt and equity shelves.

On January 1, 2016, we closed the sale of 49.9% of our total 61.7% interest in PNGTS to TC Pipelines LP for $223 million, including the assumption of $35 million of proportional PNGTS debt. The drop down of our remaining US natural gas pipeline assets into TC Pipelines LP remains an important financing lever for us, subject to actual funding needs, market conditions, the relative attractiveness of alternate capital sources, and the approvals at TC Pipeline's board and our Board.

Also in January, we raised $1.25 billion through issuance of $400 million of 3 1/8% coupon three-year notes and $850 million of 4 7/8% 10-year notes. Along with prefunding activity completed in late 2015, over half of our current 2016 financing needs are already in place.

Looking forward, we are developing high quality assets under our capital program. These long life infrastructure projects are supported by long-term commercial arrangements and, once completed, are expected to generate significant growth in earnings and cash flow. Our capital program is comprised of CAD13 billion of near-term projects and CAD45 billion of commercially secured medium- and longer-term projects, each of which remain subject to key commercial or regulatory approvals.

The portfolio is expected to be financed through our growing internally generated cash flow and a combination of funding options including senior debt, preferred shares, hybrid securities, additional drop downs of our US natural gas pipe assets and TC Pipelines LP, subject to the criteria I outlined, as well as, where appropriate, project financing and portfolio management, including the potential introduction of partners.

Additional financing alternatives available include common equity through a dividend reinvestment program or lastly, discrete equity issuance. These various levers will be assessed on a relative basis in the context of market conditions, maintenance of key credit metrics, and through the lens of per share economics.

Next I'd like to spend a moment on our 2016 outlook. More information is contained in our 2015 annual managements discussion and analysis can was filed on SEDAR earlier today and available on our website. The Canadian Mainline will continue to operate under the terms of the NEB 2015 to 2020 tolls decision and we expect 2016 earnings to be slightly lower than 2015 due to a declining investment base.

We expect the NGTL system investment base to continue to increase as we connect new natural gas supply in northeastern BC and western Alberta and respond to continued growth in market demand, which will have a positive impact on NGTL system earnings in 2016. Under the current regulatory model earnings from Canadian-regulated natural gas pipelines are not materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.

Many of our US natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance. In January, ANR Pipeline filed a section 4 rate case with the Federal Energy Regulatory Commission for increased rates on that system.

We anticipate that the proposed rates will take effect in the third quarter of this year. These rates are subject to customer refund depending on the level ultimately approved FERC which is based on the outcome of the regulatory process or settlement negotiations with ANR's customers.

Earnings from our Mexican business are expected to increase in 2016 due to the addition of two new pipelines, Topolobampo and Mazatlan, which are anticipated to be placed in service in the fourth quarter. Results from our current operating assets in Mexico are expected to be consistent with 2015 due to the nature of the long-term contracts underpinning our Mexican pipeline systems.

In liquids, excluding specified items, our 2016 earnings are expected to be slightly lower than 2015 due to short-term contracts expiring on Cushing Marketlink and weakened market conditions related to the lower crude oil price environment.

Subsequent to the Presidential Permit denial, future expenditures on Keystone XL will be expensed pending further advancement of this project. As well as mentioned earlier, we've also ceased to capitalize the interest on the project, effective November 6, 2015. Over time we, expect Liquids Pipeline's earnings to increase as projects currently under construction and in development are placed in service.

In energy, we expect 2016 earnings to be similar to 2015 assuming the net effect of the following: The acquisition of the Ironwood Power Plant in Pennsylvania, an increased ownership in Bruce Power offset by increased plant maintenance activity at Bruce, a lower US power marketing contribution, lower realized capacity prices in New York, lower contributions from our power operations in Quebec, lower North American energy commodity prices, and higher GHG emission costs in Alberta.

Although a significant portion of energy's output is sold under long-term contracts, revenue from power and capacity that is sold under shorter-term forward arrangements, or at spot prices, will continue to be impacted by fluctuations in commodity prices and changes in seasonal natural gas storage price spreads will impact natural gas storage earnings.

We continue to progress our corporate restructuring and business transformation initiative. In 2015, we incurred CAD99 million pre-tax in restructuring costs net of flow through and sharing arrangements with our customers. Looking forward, net of the flow through of realized benefits under these arrangements, we expect to see approximately CAD50 million or CAD0.05 per share in annual cost savings to the bottom line beginning in 2016.

In summary, we expect our 2016 earnings, after excluding specific items, to be higher than 2015. In terms of capital expenditures, we expect to spend approximately CAD6 billion in 2016 on growth projects, maintenance capital, and contributions to equity investments.

Capital spending related to natural gas pipeline projects includes NGTL system expansion, and investments in the Canadian Mainline, Tuxpan-Tula and Topolobampo. Liquids Pipeline's projections include Grand Rapids, Northern Courier and Energy East, while energy projects include Bruce Power and Napanee.

The total includes approximately CAD1.2 billion for maintenance capital of which approximately CAD450 million will be for Canadian natural gas pipelines. The CAD1.2 billion is up from Investor Day, partly due to timing, as some 2015 spend has shifted to 2016 and the recategorization of some ANR CapEx from growth to maintenance which, regardless, will accommodate increased volumes and foreign part of rate base for rate making.

In closing, despite the various specific items, the Company produced strong full-year and fourth-quarter operating results under challenging energy market conditions. Comparable annual earnings per share and funds generated from operations in 2015 were up 3% and 6% respectively compared to 2014.

As was mentioned, earlier today, we announced a 9% increase to the quarterly common share dividend. This is the 16th consecutive year of increases and is a testament to our resilient business model.

With a focus on capital discipline and long-term shareholder value, balanced with maintaining key credit metrics, we have to date repurchased 7.1 million common shares, representing approximately 1% of our float under our normal course issuer bid.

We made good progress in 2015 in adding to our near-term capital project inventory and advancing others through the construction phase. Our complimentary portfolio of assets is expected to continue to deliver positive results through all phases of the business cycle.

We remain well positioned to fund our CAD13 billion of near-term commercially secured projects, underpinned by our enduring financial strength and our A grade credit ratings. Our blue chip portfolio of critical energy infrastructure projects is expected to generate significant growth in earnings and cash flow for our shareholders and, as a result, we expect to continue growing our dividend by 8% to 10% annually through the end of the decade. That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.

Great. Thanks, Don. And before, just a reminder, before I turn the conference call back over to the conference coordinator, reminder that we will take questions from the investment community first and then once we've completed that, we'll turn it over to the media. With that, I'll turn it back to the conference coordinator.

Thank you.

(Operator Instructions)

Our first question is from Linda Ezergailis of TD Securities. Please go ahead.

Thank you. I have a question about your Alberta or Western Power operations. I don't know maybe if, Bill, you can help me out. I think this is the first quarter, I can remember you actually lost money, so I'm a bit surprised to see an expectation that 2016 comparable earnings in Western Power is supposed to be flat year-over-year on a full year basis.

So I'm just wondering what informs that outlook and what sort of strategic thinking you're putting forward with respect to your PPAs and whether or not you might consider doing what NMAX did and just putting it back to the balancing pool.

Sure, Linda. It's Bill here. Well, as you may realize, there's a lot of turmoil in the Western Power market right now. Still question as to exactly how the government policies and when they will be implemented with regards to increased carbon costs. As well, there's discussions that are just beginning between government representatives and coal powered producers in Alberta that will result in some timing discussions around changes to the supply mix. So there's a fair bit of uncertainty.

With regards to your question on the PPA turn back, we are aware that discussions, I guess are under way between NMAX and the balancing pool with regards to that potential turn back, but again it's preliminary in terms of understanding how that may impact the market.

But we would view that as a supply response. We think that the current price environment is not sustainable and that to the extent that the government policies are aimed at promoting renewables and new supply to come into replace the retiring coal capacity, price response is going to have to occur. So at this point, it's a period of turmoil, but we're optimistic that things will turn around.

Thank you. And just a follow-up question with respect to the corporate expenses. The CAD50 million savings, off of what base is that? Q4 corporate expenses were a little bit higher, so I'm wondering if I should take kind of a 2015 full-year base to generate those CAD50 million savings, or is there something unusual that was going on in Q4?

Yes, Linda it's Don here. The CAD50 million is actually spread out across the organization. It's not all domiciled in corporate. I'll let Glenn speak to the change in the corporate section.

Hi, Linda. It's Glenn. So included in our comparable corporate EBITDA is the portion of the 2015 severance cost recovered through our regulatory structures and our existing tolling arrangements. There's no bottom line impact to that, because although we do show the costs here, that they are recovered, either in gas pipelines or in liquids pipelines. So there's no bottom-line impact.

That's why we didn't strip anything out, but what we were trying to do is keep all of the restructuring costs together in corporate and only strip out those anomalous ones that were hitting the bottom line.

Okay, thank you. So I'll just take on an aggregated consolidated basis a CAD50 million improvement year-over-year. Thanks.

Thank you.

Thanks, Linda.

Thank you. The next question is from Paul Lechem of CIBC. Please go ahead.

Thanks. Good afternoon. Just wondering, given the relative performance of TransCanada's stock versus TC Pipeline's year-to-date, if you've had any updated thoughts about the speed or the timing of further drop downs, and if TransCanada were to sell finance, if you chose not to do drop downs, would that change your dividend growth outlook through the period? Thanks.

Hi, Paul. It's Don here. The LP remains an important lever for the Company, but as I mentioned, the criteria are our actual funding needs, market conditions and the relative attractiveness of alternate capital sources here. So currently, the LP market is clearly strained at present and we would have more compelling sources for subordinated capital in the form of preferred shares and hybrid securities and the like. So we're fortunate we have the option to move to different products in which we have a long history in.

That said, it's the pipe LP is all FERC regulated pipes and once that market stabilizes, and certainly in a declining interest rate environment, we'll see how it stacks up against those other sources. So we haven't closed the door on the LP at this point by any stretch but certainly we have better options at this point.

In terms of changing the growth rate of overall TransCanada by self-funding, the LP's a couple billion dollar vehicle in the context of a CAD65 billion, CAD70 billion company, so I don't think it would have much of an impact on the growth rate of broader TransCanada by changing that relationship.

Thanks. Second question, on the gas pipelines, Coastal GasLink and PRGT, how much is been spent getting them through the regulatory process to date? I understand it's recoverable. And then related question, do you have the same recovery mechanism with Energy East in terms of regulatory cost if by chance in the event it didn't go forward? Thanks.

Sorry, Paul. It's Alex. I missed the very first part of your question about the two PC --

Sorry. How much is been spent on getting them through the regulatory process to date on those two?

Yes, the amounts -- Paul, it's David. The amounts are, they're highlighted in our quarterly, about CAD300 million spent on Coastal GasLink, approximately CAD400 million on PRGT.

Okay and do you have a recovery mechanism on Energy East for the regulatory cost if it didn't go through?

Hi, Paul. It's Paul Miller here. We do. We have a development cost recovery mechanism with those shippers.

Okay. Thanks very much.

Thanks, Paul.

Thank you. The next question is from Ben Pham of BMO Capital Markets. Please go ahead.

Thanks. Good afternoon. I wanted to go back to the question on Alberta Power and the results in the quarter, and maybe just ask the question again; maybe just missed the response. If you guys are losing money in Q4, and that's pretty much the first quarter you'd be seeing that in 2015, why you're expecting your Alberta Power to be flat coming into 2016 versus 2015?

Well, I guess the first thing would be that the results in one quarter may not be predictive of what the full year outlook would be in 2016. I'd go back to what I just said, I guess, in response to Linda's question that there's a lot of things in play at the moment, and we believe that things will have to and will return to more normal levels in order to incentivize the necessary supply response that's going to be needed in Alberta, as the coal PPAs and the coal plants come to an end.

Prices in the CAD30 to CAD33 range, which is what we saw in the fourth quarter, or I'm sorry I guess that was on the year, are just not adequate to incentivize the necessary new supplies that are needed, let alone the much higher-cost renewable power, which the policies of the new Alberta government are aimed at promoting that renewable power and doing so in the context of the competitive market.

So you add those things up, Ben, and we just have a more optimistic view that prices will return to higher levels, notwithstanding the obvious difficult quarter that we had.

Okay, I got you. More pricing outlook, and maybe can you expand on what happened in the quarter in power? You were, I think more than half hedged, and spot was pretty much down about CAD10 or so, and was it some sort of carbon tax that you were off there, or some sort of maintenance you had to put in there, you're expensing? What was going on there?

Well I guess, without getting into specifics of how we may availability and how we may dispatch our facility, it's a combination of volume produced and net realized prices. We did have improved results versus spot as a result of our comprehensive hedging program, but I think that's about as far as I can go on that.

Okay. That's it for me. Thanks.

Thanks, Ben.

Thank you. The next question is from Andrew Kuske of Credit Suisse. Please go ahead.

Good afternoon and maybe just building upon Don's comments on the EPS matters in old school kind of way. Do you think there's some opportunities in the market environment to really pit old school versus new school, given we've seen such a sharp sell off in the MLPs that have really followed this new school format?

It's Alex. From our perspective, there's many ways we can grow the Company. At times in the past we've been very active on the M&A front. For much of the past decade, we just haven't seen values on asset acquisitions or corporate acquisitions, and so you've seen us get involved in a lot of greenfield and brownfield situations. I think that it is very clear that there has been a shakeout in terms of valuations of companies.

We're going to be very, very disciplined, but at the same time, it's situations like this that we do maintain that A credit rating and that very strong balance sheet, so we're, as I said we're going to be cautious, we're going to be disciplined, we're going to look for transactions that are accretive, that fit our strategy, but we do think we're in a pretty good opportunity phase right here from that perspective.

Okay, that's very helpful. And then maybe just a bit more specifically with the Canadian 10-year sitting below 1% today. How do you think about capital market access, in particular debt markets, and Don, I know you went through some of the parameters earlier on in the issuance you've done already on the debt side, but how do you think about your relative spreads versus say others, especially in the new school category?

Yes, we've, well we just did 10-year money in the states of 4 7/8% with a pretty healthy blue chip order book there. Spreads have elevated for us as well, but certainly not to the same extent as many other participants in the sector right now. It is what it is. We look in terms of decades here. There will be times where it's very buoyant markets and times where it's a little tougher.

We won't be cute on funding. When there's opportunities to get money in the door, as we just did, with good market demand, we'll take advantage of that. We have seen some other elements of the capital structure pricing move out. We've seen the pref market move more into the 5% plus area. A year ago, we were issuing prefs at CAD3.80.

The hybrid market in the US is probably a 7% handle pre-tax, probably 5% area after-tax at this moment in time, so we'll be prudent in how we approach this. We've already got half of our funding for the year already in place here and we'll just chunk away the rest. But again, we won't be cute on trying to get the last two basis points or five basis points here when the market's there.

Okay, that's very helpful. Thank you.

Thanks, Andrew.

Thank you. The next question is from Robert Kwan of RBC Capital Markets.

Thank you. Good afternoon. Historically, you've, on the M&A side, you've typically taken advantage to get at assets that might not otherwise come available from sellers that have been under pressure, or out of bankruptcy proceedings, so I'm just wondering, as you guys look at your wish list within the landscape, do you see that, are we getting any closer as you look at specific assets that you might want to get, to seeing those shaking loose or are you actually even going out, and then trying to initiate a few discussions to get at some assets that on your wish list?

I think in all three of our core businesses, Robert, there are assets that we obviously covet and keep on our watch list, and it's usually that the highest quality of assets that are on our wish list, and a lot of times those aren't the ones that are going to be in financially distressed situations. So some of those are still going to be relatively expensive.

But I think your point's well taken is that there are situations in the current marketplace that may reveal themselves to buy, what I would say, is generational assets at reasonable prices, and we've maintained our financial capacity to be able to take advantage of times like that and if those opportunities arise, as Alex said, we're extremely disciplined in how we look at them, but certainly, you've seen us historically move when good opportunities arise. We do have the capacity to execute on them if they're there.

I guess, Russ, more specifically, do you think that there's a reasonable probability that some of these things on your wish list might shake loose in 2016?

I think that's really, really hard to say at the current time, Robert. Is I think we're fairly early into the current financial situation out there and how it sort of plays itself over out in the coming months with counter parties, we'll be -- it's still uncertain, so I'd say that we're where we're watching and attentive, but it's still premature.

Fair enough. If last, I can just turn back to the Alberta power market and maybe, Bill, you answered the question with respect to needing to see a supply response or a price response to get new capacity in, but I'm just wondering, as the consultations are going on in terms of how to implement the climate change rules and the power market design going forward, what's your recommendation?

Are you guys of the camp that the spot market is what's going to be needed maybe outside of renewables, or even having this quasi-rec plus spot, or are you guys pushing for something more highly contracted, both on the renewables and the gas side?

Great question. Robert, it's Bill here. And our official submission that we made to government in regards to the climate change debate suggested that, to the extent that they wanted to achieve meaningful change to the supply mix in Alberta, which does appear now that we've seen their policy statement to be the direction they want it to go, we specifically suggested to them that they indeed needed to move to a more highly planned and contracted approach.

We've also augmented our discussions in consultation with government to suggest to them that there's other means to do that instead of contracts if that's not something government wants to pursue, and that would be forms of capacity markets. There are some other things that I think are under discussion and consideration, but again, this goes back to my earlier comments that these are changing times.

This current structure is not sustainable in terms of it promoting the necessary supplies and the desired supply mix that has been outlined in the policy, so we do expect that, to your question, that there will be change. Exactly what that will look like is a work in progress and we're fully engaged in those discussions.

That's great. Thank you very much.

Thank you. The following question is from a Steven Paget, FirstEnergy Capital. Please go ahead.

Thank you and good afternoon. Grand Rapids and Houston Lateral, have the in-service dates been delayed into 2017, and what was the reason for those delays?

Steven, it's Paul Miller here. Grand Rapids, we plan on having the first phase mechanically completed here by the end of this year and then we'll fill the line for in-service into 2017, and then that has actually been our plan. Houston Lateral has been delayed. It's going to be delayed into the first half of 2017, and we continue to experience delays, attributable partially to weather and partially to project execution challenges.

Thank you. Looking at overall business development and acquisitions, how is the team dividing its time between divisions, gas pipelines, versus oil pipelines, versus power, versus new ventures?

Steven, it's Alex. I would say that TransCanada, we don't suffer from a shortage of development opportunities, as you've heard us talk about. Even without looking at new initiatives, we have about CAD13 billion of new projects coming down the pipe. But we, and as a result of that, we really try to focus on the opportunities that we think are going to create the most value for our shareholders longer-term.

We don't sort of designate dollars to any of our businesses. We really have all those businesses compete for capital, and I would say that, traditionally, we've seen opportunities at different times in all of those business areas.

Thank you, Alex. Paul, thank you as well. And Don, let me just say this: If you can't finance cute, I'm sure many on the call would help you finance ugly.

Thanks, Steven.

Thank you. The following question is from Jeremy Tonet of JPMorgan. Please go ahead.

Good afternoon.

Hi, Jeremy. How are you?

Good, thanks. Turning to the US transmission business, there's a lot of stress in the E&P space these days and the questions around counter party risk and credit risk is a big topic of conversation. How do you see that risk within your business right now, and how do you look to manage that?

I'll start and I'll let Karl jump in here. A pretty healthy compliment of our customer base in our US gas pipelines is highly rated LDCs, utilities. Where we do have a cluster of E&P exposure would be on the, out of the Utica Marcellus at the top end of ANR, and we haven't seen any real wavering there, and I think our path to market is highly competitive on that asset, and so we continue to see volumes ramping up there and no strains on that front at this point. Karl?

I don't know if I have much to add to that. We have a good base of credit worthy LDC type of companies and, as Don said, maybe some of the producer segment and mostly coming out of the Marcellus in the US, probably are not investment grade, but yet so far, we haven't seen a deterioration in their ability to stand with their contracts, but obviously, we're watching it closely.

In terms of the broader portfolio, the E&P exposure would be again top end of ANR, and then in the NGTL system where we do have a significant queue for those wanting to get on the system, and any counter party losses suffered are foreign part of cost to service.

The balance of the portfolio is, of counter party risk, is pretty solid and most of the energy business is A, AA, AAA in some cases. Customer basis, Mexico is all CFE. And the liquids business is the top end of shippers, and in most of these cases, our assets, the path to market, the cost of not getting to market on these is highly competitive. So we're monitoring closely, but we feel okay on a portfolio basis on counter party risk.

Great. So if I heard you right, would it be safe to say where there is exposure, they're very competitive path and the recontracting process would probably be pretty easy there?

Yes, I think that's a fair comment. If you lock at our ANR system, it's still pretty cheap even after our filing for our new rates, it's still pretty cheap to get to the Gulf Coast using our system. We do believe if we lose customers along there, that ultimately, we'll be able to fill that path up again with other customers and/or other new sources of gas.

Great. Thanks for that. And then just turn to maintenance CapEx real quick. Just wondering if you could expand on the step up there. If you could provide any details and is this kind of a new run rate going forward, what you talked about for 2016? And do you still expect DCF coverage to be similar to the targets you had discussed in the past?

It's Don here. Maintenance CapEx is elevated in 2016 in the CAD1.2 billion range. Again, CAD450 million of that is Canadian regulated gas pipes. We continued to execute the, in accordance with NEB want, accelerated maintenance capital on the NGTL system.

As well as, I noted, ANR is elevated at this time to accommodate increased volumes and what we previously classified as growth capital some of that has been reclassified as maintenance, but it will form part of rate base for our rate making. Once we're through these programs, we should see that start dropping next year into 2017 and further in 2018. We see a stabilized maintenance capital run rate of CAD700 million-ish off our base business and then probably another CAD100 million at Bruce, again, which we are in a return on.

So the DCF coverage ratio is longer-term. Those targets remain kind of unchanged at this point?

Yes. We see DCF coverage of with the two handle the next couple years here, and as we look out, at least that going forward.

Great. Thank you very much.

Thank you. We will now take questions from members of the media.

(Operator Instructions)

First question is from Geoffrey Morgan of The Financial Post. Please go ahead.

Hi, good afternoon. Thank you for taking my question. Relating to some of the downsizing that the Company had done I believe in December, wanted to ask if that process is now complete and how many staff that may have affected? And furthermore, whether or not the Company intends to do any further through this year.

Yes, it's Don here. The staffing levels that were affected were probably around 10% of our staff in the fall with higher percentages of the more senior levels, the BP and director probably in that 20% range. So that's the quantum of people we dealt with in the fall here.

In terms of going forward, we continue with additional phases here of efficiency and effectiveness work, and as we've reorganized the Company and pushed more tasks into the business units, we now are focusing our attention on making that more efficient at those levels and avoiding any duplication, so I wouldn't say we're done at this point.

Okay, thank you.

Thank you. The next question is from Ashok Dutta of Platts. Please go ahead.

Hi, good afternoon. Just had a couple of quick questions, if I may. You talk about, in your press release, about the Keystone pipeline system and taking on board additional long-term contracts. Just wanted to find out how much, what was the volume for that, the additional capacity?

Hi, Ashok. It's Paul Miller here. We took on an additional 15,000 barrels per day of 20-year contracts.

And, Paul, it was primarily the heavy barrels?

The way our toll structure is set up is, it's a fixed variable structure, so the shipper will pay a fixed toll for the capacity and then they can elect whether it's a light barrel or a heavy barrel, and they just play the appropriate barrel toll associated with the type of crude that they move (multiple speakers).

And just to follow-up on that, so I presume you still have about 45,000 spare capacity on that line?

We do. I think it's probably closer to 40,000, but in that range, yes.

Okay. And that's available for spot?

It is.

Okay and another very quick question about the Houston Lateral. I did hear you talking about project execution challenges. Could you elaborate just a little bit as to what that is?

Sure, and maybe I'll back up a little bit. On the weather side, there's been a lot of rain in the Houston marketplace, or in the Houston area, and that has hampered our ability to bring the Houston Lateral and the terminal into service as originally contemplated here in 2016. The project execution risk that I spoke to earlier, we're having some, let's call it, performance and productivity issues with some of the contractors that we engage to build the terminal for us.

Okay, all right. Thank you very much, Paul.

You're most welcome.

Thank you. The next question is from Rebecca Penty of Bloomberg News.

Hi, there. Thanks for taking my question. I have a follow-up from some of the discussion earlier about M&A and whether TransCanada is looking at any assets right now. As you know, the US power market has been interesting for a lot of companies, including FORDIS earlier this week, and I'm just curious whether, if you could add some color to what's going on there, whether you see any opportunities, whether it's getting, their valuations are getting too pricey, et cetera.

Rebecca, it's Alex. Yes, there's certainly been a lot of, a few interesting things going on in the power markets. I think from our perspective, as I said, we're really focused on opportunities that are going to be in line with our strategy, with the regions that we have competitive advantages in, and we are looking at opportunities that are going to be accretive to our shareholders on both an EPS basis and a value perspective. And I never say never, but we keep looking, but we're a long way from, or a fair bit away from anything right now.

Thank you.

Thank you. The next question is from Lauren Krugel of the Canadian Press. Please go ahead.

Good afternoon. The other week, the NEB directed TransCanada to do some additional work on its application for Energy East, I guess to refine and organize it a little bit more. Just wondering if you had an idea of how much work that's going to end up being on your part, as well as how long it's expected to take to get in a complete application to the NEB?

This thing, really, from our perspective, and sorry, it's Alex Pourbaix, by the way. This is kind of a more of a housekeeping kind of activity. The original application was over 30,000 pages. Since that time, we've made amendments and what the NEB, I think, in essence, is asking us to do is to really kind of put all of, put those various documents together into one easily read document. I think it's quite a reasonable request. It'll take us a bit of time and a bit of effort to do it, but it's just really pretty simple stuff.

I think just to be clear, Lauren, we don't expect that, in and of itself, will impact the timeline of the National Energy Board completing its completeness review and then moving to the next step of setting here in process.

Okay and so and no change to the start-up date? You're still committed to the 2020 I heard you say earlier?

Hi, Lauren. It's Paul Miller here. We're still assessing the impact of the NEB changes, both with the review period as well as the other conditions they've attached to it. So we're still targeting 2020, but I think it's fair to assume, with a extension of the regulatory process, may translate into delay in bringing Energy East into the in-service, but we're still reviewing the impact.

Okay, thank you.

You're welcome.

Thank you. The next question is from [Mejudia Finot] of the Canadian Press. Please go ahead.

Hi. Thanks for taking my question. You said regarding the work that the NEB asked you to do, the original application was over 30,000 pages. At the time all of the documentation was in French, so can we assume that the whole application will be translated in French?

Yes, ultimately, the application will be done in French also.

Okay, and maybe if I may, there was an announcement last week in Quebec in the province to a potential creation of 120 jobs. Since then, it seems to get more, we still have some critics regarding the project in the province. Have you did any reflection of why the message doesn't seem to pass in the province regarding this project?

It's Alex Pourbaix responding again. We obviously have some work to do in the province. I think the people of Quebec have some very legitimate concerns about the environmental impact, the economic impact of the project. That announcement that you referred to with, the ABB announcement, that's just the first of many examples of the kind of opportunities that we think this project is going to provide to, not just the people of Quebec, but to the people across Canada where the project is located.

I think a big part of this is communication. We have spent a lot of time communicating with stakeholders, with land owners. We've had many, many thousands of meetings, we've had 130 open houses, we've met with 7,000 land owners, and I just, I think the perspective, really, that we need, that we view is that we just, we need to continue to get our message out.

We need to do it at a grassroots level and the kind of announcements you see and the kind of engagement we're doing, we're very confident that, over time, people in all of the provinces are going to see the benefits of the project and how seriously we take our commitment to transport the commodity safely.

Okay, thanks.

Thank you. The following question is from [Shawn Pulzer] of Merger. Please go ahead.

Hi. I'm not sure if I heard properly earlier in the call. I think Russ was saying that you might be willing to consider partners on the specific projects and I'm just kind of wondering what kind of projects those would be and what kind of partners you'd be looking for?

It's Don Marchand here. I did mention it as a lever from a financing perspective. Some of our large scale projects, depending on the timing as to how they're sequenced and how many happen at once, one potential avenue for us to fund projects is to bring in partners.

We continue to have a lot of inbound calls from long duration asset managers looking to co-invest in many of these 20-, 30-, 40-year potential secured revenue streams, so it's something we would contemplate, but depending on the circumstances.

But would those be oil pipelines or power plants or all of the above?

Could be all of the above.

Okay, and then a second question is I saw a report that pipelines and those kind of assets are actually attractive acquisition candidates. There's a lot of interest from pension plans and potential buyers. Some companies are marketing these assets, like MEG has the access pipeline going. Are these assets that you would be interested buying or even alternatively maybe selling?

I think, as we said earlier, is that the changes in the marketplace, from both the commodity perspective, but as well, from a financial perspective, with both the MLP market, the high yield market has changed the nature of financing alternatives available to a number of people that hold those assets in the marketplace. And as a result of those things, good assets appear to potentially be coming to market in a few months and we'll remain attentive to those kinds of things.

I think as I said earlier, I think it's logical that they may come. They're high quality assets and as long as they can be transacted at a reasonable price, we're going to be very interested those that fit, as Alex said, our long-term strategy as well as can provide the financial accretion and return metrics that we have in place for all of our investments.

Okay. Thank you very much. Just one little quick question. Would that include say some of these regional oil sands gathering systems or pipeline networks in Northeast BC? Would you be prepared to go down to that macro level or are you still preferring to do these big mega projects?

I'd say that, historically, you've seen us move on assets from the tens of millions to the multi-billions of dollars, as long as there are good strategic fits with our existing portfolio of assets, and we have reasonable ability to add value and have a competitive advantage, that's the kind of thing that we're looking for. So we aren't really price driven at all and, in terms of the mega projects, we do have a portfolio of what we call four of those right now and they're across all three of our businesses.

There's two major LNG lines going to the west coast, there's Keystone XL and Energy East on the crude side and we recently announced the refurbishment of six reactors at Bruce Power. So certainly, we've got lots of long-term, what I called, mega projects. In the short run, as Alex said, we've got CAD13 billion of projects that we currently have under way. They gain or across all three of our business units. We expect them to come in service between now and 2018, and in that fair way, what I would call organic growth, there continues to be opportunity.

We think of places like Mexico, for example, the CFE is coming out with a number of bids on the horizon that we're very interested in. We built ourselves a very competitive position in Mexico on our NGTL system, there still continues to be demand for increased both receipt capacity on our system and potentially delivery capacity on our system, so we see incremental growth opportunities there.

Our US pipeline systems, through things like ANR, for example, GTN, where folks want to get access for new and growing gas supplies to market, we're well positioned for those. Even within that sort of fair way of what I'd call smaller projects that are closer to home, more organic growth, I would expect that CAD13 billion of projects to continue to expand as well. I think Alex said earlier, we're not constrained by opportunities and we'll be very disciplined to allocate our capital to those that provide the best returns for our shareholders over the long term.

Excellent and then finally just one last one. Are you planning to reapply for KXL? Is there any thought given to that or is it basically a dead project? I noticed you wrote it down too (multiple speakers).

The Keystone XL project, the demand for the Keystone XL project I think remains as strong today as it was when we made our application. Is that the US is a very, very attractive market. It's where the bulk of Canadian production goes today and it traverses through a large part of the most prolific part of the US new production in the Bakken, so it's very much still in demand.

Our shippers remain very interested in seeing that project move forward, and we'll continue to look for an opportunity to advance that project in the future. But as a result of the denial, we are in a situation where we have to take the write down as well as look to recover those amounts that, what we call arbitrary denial, has cost us, but make no mistake that the need for the project is unchanged and as long as, as I've always said, as long as our shippers remain interested in the project and committed to doing it, TransCanada will look for a way to make that project work some time in the future.

Excellent, Russ. Thanks for your answers. Thorough and awesome, as always.

Thanks very much, Shawn. Just a reminder to remaining participants, if you could just limit your questions to essentially one and then a follow-up just in the interest of insuring everybody has an opportunity. Thanks again.

Thank you. The next question is from Chester Dawson from The Wall Street Journal.

Yes, thanks. I just wanted to clarify. I think Paul Miller earlier said in response to a question that the in-service date for Energy East might be pushed back from the 2020 timeline on the basis of the various policy changes that are being mulled in Ottawa, and I'm curious to know whether that likely means a year or two, or are we talking about until much later in the decade?

First of all, this is a very complex project that had many facets, one of which is the regulatory process, and certainly, we're assessing the impact of those at the current time. Our current thinking is that we still believe that we can bring that pipeline into service by the end of 2020, that's currently our plan. The announced changes have not impacted that at the current time, but we'll continue to assess all of these factors as we move forward and we'll update the marketplace if there are changes in our in-service date, but at the current time, our thinking remains for a late 2020 in-service.

Okay, thank you.

Thank you. The next question is from Elsie Ross of the Daily Oil Bulletin.

Hi. The mayor of the Quebec City recently was quoted as suggesting that, was quite critical, even though he supports Energy East, critical of the consultation process, and Alex talked about all of the thousands of people you've met with in the process, but are there things that you would look at changing or possibly to perhaps address some of those concerns of the mayor?

Elsie, it's a good question. I think one of the things that we would acknowledge here is that we have to continue and probably get better at listening to our stakeholders. Russ mentioned this is a very complex project, but I would just point you to one I think pretty powerful fact.

Since we originally applied for the energies pipeline, we have made over 700 amendments to the route of that pipeline, and those amendments have been made overwhelmingly because of consultations that we've done with communities and stakeholders along the route, so I really do think that we really are listening to people. When mayors have ideas, we are very anxious to sit down with them and get their views and if we can accommodate, we're very willing to do so. It's all about communication.

Okay and that's Alex speaking?

Yes.

Okay, thank you.

Thank you. This concludes the question-and-answer session. I'd like to turn the meeting back over to Mr. Moneta.

Thanks very much and thanks to all of you for participating today. We very much appreciate your interest in TransCanada and we look forward to speaking to you again soon. Bye for now.

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