TC Energy Corp (TRP) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2014 fourth-quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, sir.

Thanks very much, and good afternoon everyone. I'd like to welcome you to TransCanada's 2014 fourth-quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, Executive Vice President and President Development; Karl Johannson, President of our Natural Gas Pipelines Business; Paul Miller, President of Liquids Pipelines; Bill Taylor, President Energy; and Glen Menuz, Vice President and Controller.

Russ and Don will begin today with some 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.

(Caller Instructions)

Also, we ask that you focus your questions on our industry, 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, Lee 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 the US Securities Exchange Commission.

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

As a result, they may not be comparable to similar measures presented by other entities. They are provided to give you some additional information on TransCanada's operating performance, liquidity and our ability to generate funds to finance our operations. With that, I'll turn the call over to Russ.

Thank you David, and good afternoon everyone and thank you very much for joining us late on this Friday afternoon. 2014 was a year of many accomplishments for here at TransCanada. We resolved a number of outstanding headwinds in our core businesses.

We successfully advanced several new pipeline and power generation projects. We captured more high quality growth opportunities directly connected to our core assets. We continued to improve on both safety and integrity performance, placing in the top quartile at the top decile of our industry. And we had strong financial performance from all three of our core businesses.

Comparable earnings increased 8% and funds generated from operations climbed 7% during the year. Net income attributable to common shares was CAD1.7 billion, or CAD2.46 a share. Comparable earnings were CAD$1.7 billion or CAD2.42 a share. As I said, funds generated from operations were up 7% to CAD4.3 billion.

Our strong financial performance combined with solid new growth opportunities and an industry-leading safety performance record is strong evidence that our strategy is working. Don will provide some more financial details on the quarter a bit later. I thought I would go through some of the highlights for 2014 with you at this time.

Specifically during 2014, we continued to focus on maximizing the value of our CAD59 billion asset portfolio. This included successfully repositioning two key long-haul pipeline systems that have been under pressure from changing market dynamics in recent years, and specifically that's the Canadian Mainline and the ANR pipeline systems.

In addition, CAD3.8 billion of new assets began operating in 2014. Those assets include the southern leg of the Keystone Pipeline, or what we call the Gulf Coast Extension, CAD300 million in new facilities on our NGTL system, the $600 million Tamazunchale pipeline extension in Mexico, and four additional solar generation facilities in Ontario.

Continued solid performance from our asset portfolio, new operating assets in 2014 combined with CAD12 billion of the small- to medium-sized projects expected to be in service by the end of 2017, provided the confidence for our Board of Directors to declare an 8%, or CAD0.16 per share, increase in the common dividend from CAD1.92 to CAD2.08 per share on an annualized basis.

We recognized the value our shareholders place on a stable and growing dividend. Our objectives continue to be focused on growing the dividend in conjunction with sustainable increases in cash flow and earnings. This is the 15th consecutive year the Board has raised the common dividend at TransCanada.

A few comments on our capital program. Our portfolio of commercially secured projects now totals CAD46 billion. It is made up of CAD12 billion of small- to medium-sized projects and CAD34 billion of large-scale longer-term projects.

The small- to medium-sized initiatives are expected to drive earnings and cash flow growth as they come onstream over the next three years and the large-scale projects are expected to come onstream later in the decade. During 2014 we advanced work on all of these projects.

During the last quarter we filed our application for Energy East, the most complex and extensive application in our Company's history. Since that time we've continued to engage with many stakeholders including land owners, municipalities, Native communities and governments to better understand their concerns and incorporate those concerns into our planning for this project. To date, the feedback we have received has been very supportive.

The many stakeholders we have engaged with indicated they understand both the energy security and economic benefits of this massive project to their communities and to Canada. But they have also been quite clear with us that it has to be done right, and that is exactly what we intend to do.

We are committed to taking the time necessary to work our way through these issues and to find workable solutions to all of their concerns. For example, the application includes a proposed marine terminal near Cacouna, Quebec.

On December 8, 2014 the Committee on the Status of Endangered Wildlife in Canada recommended that the Beluga whales be placed on the endangered species list. We made a decision in December to halt any further work at Cacouna as the terminal site is adjacent to a Beluga whale habitat.

We are currently analyzing that recommendation and assessing the impacts of the project and reviewing our options. We expect to conclude that analysis in the first quarter, and will provide you an update at that time. That's the same approach that we'll take with all issues that we encounter along these -- the system. Just to remind you that the 1.1 million barrel a day project is underpinned by 1 million barrels a day of long-term contracts and is expected to be in service by the end of 2018.

In November we completed a successful binding open season for the Upland pipeline. The CAD600 million pipeline would provide crude oil transportation between multiple points in North Dakota and connect to other inter- and intrastate pipelines.

One of those interconnects will be the Energy East pipeline system at Moosomin, Saskatchewan. As you are currently aware, tens of thousands of barrels a day of growing Canadian and US Bakken crude are being railed to markets in Central and Eastern Canada.

The volume that is contracted to connect the energy system is 70,000 barrels per day. The shippers that have committed to the contracts on the Uplands pipeline system for delivery into Energy East will have the flexibility to source their supply from receipt points in North Dakota, Saskatchewan and in Alberta.

You may have seen media reports today indicating that 300,000 barrels a day of Bakken crude would flow on the Uplands pipeline to Energy East. That is not accurate.

To reiterate, the contract volume to move on the Uplands pipeline to Energy East is 70,000 barrels per day, representing about 6% of the 1.1 million barrels a day capacity on the Energy East system. And as I said, that 70,000 barrels a day can be sourced in either Canada or the United States.

I'd also remind you that 930,000 barrels per day of long-term shipping contracts have been executed for Energy East that are exclusively sourced in Alberta. Subject to regulatory approval, we anticipate the Upland project would be operational in 2018.

Moving to Keystone XL. Some important developments have occurred in recent weeks. I suspect you're aware of those.

On January 16 the Department of State re-initiated its National Interest determination and requested the eight federal agencies involved in the review to complete and submit their comments on whether Keystone XL is in the national interest by February 2. On February -- on Wednesday by a vote of 270 to 152 the House of Representatives passed a bill that approved the construction of the Keystone pipeline.

Previously that same legislation was passed by the Senate. That bill now goes to the President for approval. We continue to see strong bipartisan support for Keystone XL, both in the Senate and the House. The American people also continue to support the pipeline, with 30 polls since 2011 showing two-thirds in favor of the project.

The final Environmental Impact Statement that was issued last year by the Department of State indicated the project would have a minimal impact on the environment. It would not increase GHG emissions. It would create jobs. It would have a positive impact on the economy and it would enhance both energy and national security.

We continue to believe the Keystone pipeline is very much in the national interest of the United States. And to be totally clear, TransCanada and its shippers remain 100% committed to building the Keystone pipeline. And we continue to believe it will be ultimately approved.

Moving over to the gas side of our business, where we continue to experience growth on the NGTL system due to growing production in both Northwest Alberta and Northeast British Colombia, and growing demand primarily by oil sands development and the demand for natural gas-fired electricity. This increased demand for NGTL service is expected to result in approximately 4 billion cubic feet a day of incremental firm receipt and firm delivery services.

As a result, and following NEB approval, we expect to build over 500 kilometers of new pipeline system, along with a number of compressor and meter stations. These facilities would be needed in 2016 and 2017 and would cost approximately CAD2.7 billion. Including these projects and the previously announced initiatives, such as the north Montney project and the Merrick project, we now have CAD6.7 billion of NGTL-related projects in development.

On the Canadian Mainline, in November we were very pleased the NEB approved the Mainline's 2015 to 2030 tolls application. The application reflected components of the settlement between TransCanada and the Ontario and Quebec local distribution companies.

Approval of the application provides a long-term commercial platform for both the Canadian Mineline and its shippers with known tolls for the 2015 to 2020 period, access to growing US supplies, and parameters for toll setting through to 2030. The application meets the needs of both our shippers and TransCanada, providing us a reasonable opportunity to recover return and on capital for both existing and new facilities.

Related to that settlement we have signed a 1.5 billion cubic feet a day of contracts in the Eastern Triangle to provide our Eastern customers with greater access to closer gas supply from the US and the Don hub. The contracts signed will require about CAD500 million of new facilities that we expect to put into service between November 2015 and November 2016.

In addition, as part of our Energy East application last October, we also filed an application for NEB approval to expand our Mainline system in Southern Ontario to ensure sufficient capacity is available to meet customer needs in both Quebec and Ontario. The CAD1.5 billion Energy East -- or Eastern Mainline project will add approximately 600 million cubic feet a day of capacity and will ensure sufficient capacity is in place to meet existing and new firm service requirements.

Moving over to the West Coast and some updates on our LNG projects. We were pleased to receive our Environmental Assessment Certificate for the Prince Rupert Gas Transmission project on November 25 of last year from the BC government.

We also submitted several pipeline permit applications to BC's Oil and Gas Commission for construction of the Prince Rupert gas line. We anticipate receiving those permits early in 2015.

In December the Progress Petronas Company deferred a final investment decision on that project. We continue to work with them and our contractors to refine our project costs in anticipation of a final investment decision sometime later this year.

The deferral of the FID, final investment decision, for the Prince Rupert project will also mean a delay in, in-service for our pipeline. All of TransCanada's costs are fully recoverable if that project doesn't proceed.

Our Coastal Gasolink project also received its Environmental Assessment Certificate from the BC government in 2014. The project team also submitted applications to the BC Oil and Gas Commission for its construction permits.

That process is proceeding and we expect to receive those permits in the first quarter of this year. We continue to expect the LNG Canada to make a final investment decision sometime in early 2016.

Moving over to Mexico. The Tamazunchale Extension became operational in mid-November. The $600 million pipeline has a 25-year natural gas transportation service contract with Mexico's state-owned power company.

In addition, permitting, engineering, construction activities continue on our two other Mexican pipelines. Both the $1 billion Topolobampo project and the $400 million Mazatlan projects are supported by similar 25-year contracts with CFD and are expected to be operational in mid to late 2016.

In energy, we are very pleased to start construction last month of the 900-megawatt Napanee power facility. We expect to invest about CAD1 billion in the Napanee facility and the plant should be operational late in 2017, early 2018. That facility is fully contracted with Ontario's independent electric system operator.

Also in Ontario we acquired our eighth solar facility in late December. This was part of the larger purchase agreement with Canadian Solar signed by TransCanada in 2011, bringing our total investment with Ontario Solar to about CAD450 million. All the solar facilities are fully contracted as well, with -- under 20-year power purchase agreements with Ontario's independent electric system operator.

In conclusion, our diverse portfolio of energy infrastructure assets generated strong earnings and cash flow in 2014. Comparable earnings increased 8% to CAD1.7 billion and funds generated from operations were up 7% to CAD4.3 billion. Our capital growth program now sits at CAD46 billion, as we captured a number of small- to medium-sized organic growth opportunities in 2014.

Looking forward, 2015 will be a challenging year for North America's energy industry as companies adjust to lower oil and gas prices. While we have some businesses with direct exposure to volatile commodity prices, the majority of TransCanada's operating assets are well positioned to continue to perform through 2015 due to a high degree of contractual underpinning and rate regulated business models.

Our focus for 2015 remains the same as it has been in the past. First it will be to maximize the value of our CAD59 billion Blue Chip portfolio of assets, move our CAD46 billion capital program from concept to cash flow, continue to cultivate new opportunities to invest our growing free cash flow, and maintain our financial flexibility and discipline to ensure we can continue to fund our growth in all markets circumstances and in all market conditions. This disciplined strategy has proven itself for the past 15 years, driving growth in cash flow, earnings and dividends and enhancing shareholder value. That completes my prepared remarks. And I'll now turn the call over to Don to discuss our financial performance in more detail. Don?

Thanks Russ, and good afternoon everyone. As highlighted in our news release this morning, net income in the fourth quarter was CAD458 million, or CAD0.65 per share, compared to CAD420 million, or CAD0.59 per share, for the same period in 2013. Excluding the CAD8 million after-tax gains from the sale of our South American pipeline assets and unrealized gains and losses and changes in various risk management activities, comparable earnings for the fourth quarter of CAD511 million, or CAD0.72 per share, increased CAD101 million, or CAD0.14 per share, compared to the same period last year.

Driving this were new contributions from the Keystone Gulf Coast extension and the Tamazunchale extension in Mexico, along with an increase in incentive earnings from the Canadian Mainline and higher realized prices at US Power, partially offset by higher interest expense.

In terms of our business segment results at the EBITDA level, our natural gas pipelines business generated comparable EBITDA of CAD884 million in fourth quarter 2014 compared to CAD778 million for the same period last year. Canadian gas pipelines comparable EBITDA of CAD646 million Increased CAD46 million compared to 2013, primarily due to higher incentive earnings on the Canadian Mainline, partially offset by higher OM&A costs on the NGTL system.

Net income from the Canadian Mainline was CAD39 million higher compared to the same period last year. With the recent NEB approval of our 2015 to 2020 tolls application, CAD59 million of after-tax incentive earnings were recorded during the fourth quarter, partially offset by carrying charges owed to shippers stemming from a positive toll stabilization account balance.

NGTL's net income decreased CAD13 million year over year to CAD59 million due to higher OM&A costs that were at risk under the terms of the 2013/2014 settlement, partially offset by a higher investment base. In addition, results in fourth quarter 2013 included the full year impact of the 2013/2014 NGTL settlement that was approved in that period.

US and international natural gas pipelines comparable EBITDA of CAD249 million increased CAD57 million compared to fourth quarter 2013, primarily as a result of higher earnings in the recently completed Tamazunchale extension, increased transportation revenue on ANR and Great Lakes, and the positive impact of a stronger US dollar.

In liquids, the Keystone pipeline system generated CAD294 million of comparable EBITDA in the fourth quarter. This represents a CAD94 million year-over-year increase. And is the result of the Keystone Gulf Coast extension which was placed into service in January 2014, along with a favorable impact of a stronger US dollar.

Turning to energy. Comparable EBITDA was up CAD39 million to CAD385 million in the fourth quarter. Within energy, Western Power comparable EBITDA increased CAD8 million due to higher purchase PPA volumes, partially offset by lower realized power prices. 76% of Western Power volumes were hedged during the quarter, which helped to offset soft Alberta spot market prices.

Eastern power EBITDA rose CAD20 million year over year due to higher contracted Becancour earnings and the contribution from four solar facilities acquired in the second half of 2014. Bruce Power equity income of CAD115 million was consistent with results in 2013.

US power comparable EBITDA increased CAD28 million in the fourth quarter compared to last year, primarily due to increased margins in sales volumes to wholesale customers, higher realized capacity prices in New York, and the favorable impact of a stronger US dollar. Natural gas storage comparable EBITDA decreased CAD15 million to CAD12 million in the fourth quarter due to lower realized storage spreads and decreased third-party sales volumes.

Now turning to the other income statement items on Slide 23. Comparable interest expense of CAD323 million in the fourth quarter increased CAD83 million compared to the year-ago period. This was primarily due to higher interest charges on recent US debt issues, higher foreign exchange on interest denominated in US dollars, carrying charges stemming from the positive Canadian Mainline TSA balance and lower capitalized interest, partially offset by Canadian and US debt maturities.

In 2014, our exposure to US dollar income was largely offset with US dollar denominated interest expense and financial derivatives. The net impact of the strengthening US dollar during the year was a small positive benefit to earnings of approximately CAD0.02 per share.

Over the next 12-month period, currency movements are not expected to have a material impact on earnings, given hedge programs in place that have a year-forward focus. Beyond 2015, we could potentially benefit from any prolonged strength in the US dollar on our structural long position resulting from our sizable ownership in US-based assets and their associated income streams, net of US dollar-denominated debt and interest expense.

In the fourth quarter CAD60 million of interest was capitalized to assets under construction compared to CAD92 million for the same period in 2013. Lower capitalized interest due to the completion of the Gulf Coast extension of the Keystone system was partially offset by higher capitalized interest for other liquids and LNG related pipeline projects.

Comparable interest income and other rose CAD30 million compared to the fourth quarter in 2013, primarily due to increased AFUDC related to our rate-regulated projects including Energy East and our Mexican pipelines. Partially offsetting the increase in AFUDC were higher realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuations on US dollar income and the impact of a strengthening US dollar on translating foreign currency-denominated working capital balances.

Comparable income tax expense for fourth quarter 2014 increased CAD45 million versus the same period last year, due to higher pretax earnings and changes in the proportion of income earned in higher tax jurisdictions. Net income attributable to non-controlling interests increased CAD5 million compared to the same period in 2013, primarily due to the sale of our remaining 30% interest in buys into TC PipeLines.

This was partially offset by the redemption of the TCPL Series Y preferred shares in March 2014. Preferred shares dividends of CAD25 million were CAD6 million higher in fourth quarter 2014 as a result of the CAD450 million Series 9 issue completed in January 2014.

Now moving onto cash flow and investing activities on Slide 24. Cash flow remains solid with funds generated from operations of approximately CAD1.2 billion in the quarter and reaching a record CAD4.3 billion for the year.

Capital spending totaled CAD1.5 billion in the fourth quarter, driven principally by Mexican pipelines, NGTL system expansions, Energy East and construction activities on the Houston Lateral and Tank Terminal. Equity investments of CAD61 million in the quarter reflect activities related to the Grand Rapids pipeline and Bruce Power. Finally under investing activities, our eighth solar facility in Ontario was acquired at the end of December at a cost of CAD60 million.

Now turning to Slide 25, our liquidity and access to capital markets remains strong. At December 31 our consolidated capital structure consisted of 38% common equity, 5% preferred shares, 2% junior subordinated notes and 55% debt net of cash.

We had CAD489 million of cash on hand, along with CAD5 billion of committed and undrawn revolving bank lines available with our high quality bank group. Our two commercial paper programs, one in Canada and one in the US, remain well supported and continue to provide flexible and very attractive sources of short-term funds.

In December the dividend rate on our Series 1 preferred shares was reset from 4.6% to 3.27% for the next five years. At that time holders elected to convert 12.5 million of our 22 million outstanding Series 1 shares into floating rate Series 2 shares, which will pay a floating quarterly dividend for the same five-year period at a rate of 90-day Canada T bills plus 192 basis points. The initial Series 2 rate-setting was a 2.82% per annum.

In January 2015 we issued $750 million of three-year senior notes in two tranches. $500 million of fixed-rate notes will bear interest at 1.875% while $250 million of floating-rate notes will bear interest at LIBOR plus 79 basis points with the initial rate setting at 1.045%.

We also continue to advance our MLP drop-down strategy with the closing of the sale of our remaining interest in Bison in October for $215 million of cash proceeds, and the announcement in November of an offer to sell our remaining 30% interest in GTN to TC PipeLines. The GTN sale is expected to close in late first quarter 2015.

Finally, we remain well positioned to finance our CAD12 billion of small- to medium-sized projects through various sources which include predictable and growing internally generated cash flow from our three core businesses, LP drop-downs and senior debt consistent with our A-grade credit rating. In addition, subordinated capital in the form of preferred shares and hybrid securities are also expected to form part of our financing strategy. Beyond these funding sources, (technical difficulties) our CAD34 billion of large-scale capital projects we will consider selective use of project financing, reinstatement of our dividend reinvestment program from Treasury, additional portfolio management activities, and the introduction of partners as alternatives to large-scale common equity.

Next I'd like to spend a moment on our 2015 outlook. More information is contained in our 2014 annual management's discussion and analysis which was filed on SEDAR earlier today and available on our website.

In natural gas pipelines, anticipated lower earnings in the Canadian Mainline as a result of its new 2015 to 2020 tolling framework is expected to be largely offset by growth in the NGTL system rate base and higher earnings from new long-term contracts on ANR. In liquids, earnings in 2015 are not expected to be significantly different than 2014. However, we will continue to seek ways to further optimize the system, which could improve capacity and flows depending on market conditions.

In energy, increased power supply in Alberta is putting pressure on power prices and is expected to negatively impact Western power results in 2015. Eastern power is forecasted to benefit from the additional solar facilities acquired throughout 2014 and higher contracted earnings at Becancour.

Bruce Power equity income is expected to be lower primarily due to increased planned maintenance activity and higher operating costs. Bruce B will undergo a 30-day [vac and] building outage that requires it to take down all four of its units to perform this critical safety inspection. This is expected to occur during the second quarter. And overall plant availability in 2015 is expected to be in the mid-80%s range for both Bruce A and Bruce B.

In US power, earnings are expected to increase as a result of higher energy margins and production, partially offset by lower New York capacity prices. Finally, lower seasonal spreads are expected to negatively impact results for natural gas storage in 2015 as compared to 2014.

In terms of planned capital expenditures and equity investments, we currently expect to invest approximately CAD6 billion in 2015, primarily related to NGTL system expansions, the Canadian Mainline, Mexico pipelines, Energy East, regional Alberta liquids pipeline projects and the Napanee power project. In summary, we expect to generate higher earnings in 2015, and continue to advance our portfolio of capital projects that will underpin significant growth over the course of the next several years.

In closing, the Company produced a strong quarter and full-year financial results. Comparable earnings per share and funds generated from operations in 2014 were up 8% and 7% respectively compared to 2013.

Earlier today we announced an 8% increase to the quarterly common share dividend. This is the 15th consecutive year of increases and is a testament to the diversity and stability of our business model.

We have made significant progress in 2014 by solidifying the market position of the Canadian Mainline with the approval of the 2015 and 2020 tolls application, fully re-contracting the Southeast leg of ANR for an average term of 23 years and placing CAD3.8 billion of new assets into service.

In terms of our growth projects, we remain well positioned to finance both our CAD12 billion of small- to medium-sized projects that are commercially secured, as well as our CAD34 billion of longer-term large-scale projects that continue to progress through their respective regulatory processes. This Blue Chip portfolio of critical energy infrastructure projects is expected to generate significant growth and earnings cash flow and dividends for our shareholders over the remainder 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.

Thanks, Don. Just a reminder before I turn it back over to the conference coordinator. We'll take questions from the financial community first, and once we've completed that we'll then turn it over to the media. With that, I'll turn it back to the conference coordinator.

Thank you. We will now take questions from analysts.

(Operator Instructions)

Our first question is from Carl Kirst from BMO Capital Markets. Please go ahead.

Thank you. Good afternoon, everybody.

Russ, appreciate the color and the clarification on the Upland contracts. And just to get maybe for further clarification, to the extent that if this goes forward we have another straw into another basin. Can you remind me as far as the full Energy East 1.1 million barrels a day, is that considered fully pressured up or will at some point in the future that have expansion capability?

Hi, Karl. It's Paul Miller here.

The 1.1 million barrels per day on Energy East is the fully powered up capacity. We'll continue to look for opportunities to increase that once we're in operation, but as of today the 1.1 is maxed out.

Thank you.

And the second question, if I could, and I guess sort of sticking with Energy East but maybe going over to the Eastern Triangle. And I just wanted to get the updated thoughts on the northern leg and some of the back and forth we've heard.

And I guess this is clearly in front of the NEB, and maybe perhaps my question can be summed up. Do you see any risk for project delay with respect to some of the consternation we've seen about the northern leg?

I'll take a first cut at it. Maybe Karl has a view as well. Both the -- I think you're speaking with respect to the issue as to whether or not there will be sufficient gas capacity available to meet Eastern Canadian concerns.

As I think both the Ontario government and the Quebec governments have engaged their respective regulators to basically inform them as to how they should respond to the National Energy Board process. One of the issues that obviously they'll review is the gas transportation issue.

The [Reggie] has completed its report and has submitted it to the government. I understand the OAB is still in the process. I think what we're seeing is that the incremental gas supply needs, or that the -- at least the Quebec regulator has indicated that the conversion of the capacity on energy to -- from gas service to oil service will provide a benefit to gas consumers.

They've indicated that it would be beneficial if we solicited for additional gas needs, and to understand gas needs better we recently completed that process. We're in the process of analyzing those open season requirements.

At the end of the day, all of that will be complete well in advance of the Energy East filing. And I wouldn't suspect that that would be a critical path item for us. We'll determine what the gas supply needs are and we'll make sure the capacity's in place for it.

I don't know, Karl, if you have anything to add to that.

No, I don't have much more to add to that. We will take this to the NEB, as Russ said. The topic of capacity will be looked at by the NEB and we're quite comfortable we have enough capacity for existing and future needs on the system.

Just to be perfectly clear. The peak day load for Eastern Canada off our system over the last four years has been just slightly greater than 1.7 billion cubic feet a day. The Triangle currently has a capacity of 3.2 billion cubic feet a day.

With the adjustments that we're planning on making it to it, it'll bring that capacity down to 2.6 billion cubic feet a day. There's ample capacity available to meet that 1.8 billion cubic feet a day of need under almost any scenario. We don't see there being an issue with gas supply in Canada.

Appreciate the extra color. Thanks, guys.

Thanks, Karl.

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

Thanks, good afternoon.

Just a first quick question to Don maybe. In the earnings outlook slide that you have with the arrows going up and down and flat for Keystone, is that in Canadian dollars? US dollars? What are we looking at there?

That would be in Canadian dollars.

So you're expecting Keystone to be flat in Canadian dollars even with the exchange rate and moving -- the Canadian dollar moving lower late in 2014? So essentially does that suggest it goes lower in US dollars, it's for Keystone in 2015?

We're just checking it, Paul. Call it flat to slightly up on a Canadian dollar basis.

Okay.

Just maybe a question on the -- given where commodity prices are, have you seen any shippers pulling out of any of these pipelines, the proposed pipelines, Energy East, Keystone XL? Any of the ones you have underway in Alberta, Northern (inaudible), Grand Rapids? Has there been any impact from the move down in oil prices to any of these projects?

Hi, Paul. It's Paul Miller here.

We haven't had any impact from the decline in the commodity price. The shippers who have signed up for these pipes are still fully behind us. We anticipate we'll see some slowing in some of the growth here in Western Canada. But today all the shippers remain fully committed to all of the projects.

And is there any, contractually any ability for them to delay or move out their commitments under current scenarios?

No, there isn't.

That's it from me. Thank you.

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

Thank you. Good afternoon.

I guess a question really relates to the financials and just your outlook for financing. And I know you mentioned a little bit of your financing expectations and really the spreads you can issue on.

Is now the opportunity just to try to go and term out some debt on a longer-term basis? And if you were to do so, in particular unregulated assets, what kind of spreads or levels do you think you can hit?

These are pretty compelling levels. We would agree on that. And we do have a need on the regulated side of the business for some debt funding this year, particularly with the growth on NGTL.

30-year money in Canada is probably in the 4% area, pretax. So that's the kind of levels we'd be looking at. Again, that, on NGTL that would be passed through the tolls.

In terms of the broader financing program, spend around CAD6 billion this year internally generated cash of around CAD3 billion, which leaves us with a funding need of probably in the CAD5 billion area including maturities. We'll be across the term spectrum on that.

You saw us do some three-year notes earlier. So we'll be across the term spectrum in both currencies there. But again, across the entire yield curve and across all products we view these levels as compelling.

Maybe just for a bit more clarity, where do you think you could issue 10-year paper on, say, unregulated assets or even regulated assets, for that matter?

Unregulated assets, 10-year paper in Canada would be probably in the 3% area.

Okay.

In the US, probably around the 3.60%, plus/minus area today.

Okay. That's helpful.

And then just how do you think this plays into the overall valuation of your stock and just the return expectations? Because obviously under the old regulated formulae that still exists under certain assets, we're really disconnected from the formulae at this point in time. And just how do you think about your stock valuation also, with just rates are so low?

Obviously there's a very high correlation to bond -- our yield to where bond yields are at. So it's certainly a tailwind to the share price here.

If your choice is investing in a stock that's paying a mid-3%s after-tax dividend or putting your money into government bonds taxable at a rate lower than that, it's from an investment proposition standpoint, it's a good news story. We think we have to sell to investors there.

If we continue to grow that dividend as we've indicated at Investor Day and since over the next several years here driven by the small- to medium-sized projects first and foremost. And then if we get some of these big projects over the finish line, it's another factor here that I think is in investors' minds.

Okay, that's great. Thank you.

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Good afternoon.

Just looking at the Mainline as you head into 2015 with the settlement. I know we're only six weeks into the year, but just wondering if you have any comments as to how you've performed so far with the discretionary?

And directionally when you just look at the settlement versus how you made the money in 2014, how are these tools impacted by the settlement agreement, thinking about things like summer storage service? Just as we think about year over year, your ability to earn the incentives over the 10.1?

Hi, Rob, it's Karl.

Maybe I'll start by talking about the revenue generation incentive that we get. We do actually have eight filings still to do, a compliance filing at the end of March where we have to update all of our numbers. That will be coming at the end of the first quarter.

But just generally speaking, the winter this year has not been as cold as last year. So I wouldn't expect as much incentive earnings as we earned last year. I think we earned last year about CAD0.08 incentive earnings, kind of CAD0.05 net of the carrying cost of the surplus cash we generated last year.

We're certainly not going to make that. The winter just hasn't materialized the same. We are on track with good FT contracts this year.

And we do expect to make our revenue requirement with the FT contracts, which will make up about 90% of our revenue requirement. So I think it's good start to the year. But it's certainly nothing compared to last year with that very cold winter we had.

Does that answer your question? I think the second part of your question was -- maybe you can remind me what the second part of your question was?

Just any structural differences with the settlement that may make it just directionally more difficult for you to earn incentives.

The incentives that we've structured on this is we're capped now. We have a collar, basically. So we can't go lower.

If we under-collect, we can't go lower than 8.7% return on equity. If we over-collect we can't go higher than 11.5%. It's structurally a little different.

I think last year we were much over 11.5% because of the incentives that we gathered. But strictly speaking we still have the same tools. We still have the pricing discretion tools that we have.

We still have the products that we can use, both the firm products and the interruptible products. I don't see a lot of difference in the tools that we can use to earn incentives this year.

It is a bit seasonally dependent and it will change a little bit as we move into the future and people start converting from long haul to short haul. That's probably the main impact on it, because once you get short haul you just have a lower overall toll and probably some lesser amount to earn incentives on a base toll that is lower. But with all the tools that we have, I don't see any difference this year over last year.

Okay.

Just my other question is for Ocean State. With the capacity auction for 2018/2019 in New England and Ocean State being in that Rhode Island pocket, just wondering, have you looked at expansion opportunities either on the site or near the site that you might be able to take advantage of into the future?

Yes, Robert, it's Bill Taylor here.

Obviously we're quite pleased with that result. We actually did anticipate improvement in the Rhode Island zone, and that was proven out in the results of the auction that you mentioned.

So we're continually looking at opportunities there. And we do have some initiatives to look at what opportunity there may be on the site. It's a limited -- there's not a lot of geography that isn't used up at the site.

So we have limited ability to do something there. But it may also be a re-powering opportunity as well.

Okay. That's great. Thanks, Karl. Thanks, Bill.

Thank you. The next question is from Matthew Akman from Scotiabank. Please go ahead.

Hi, good afternoon.

On Western power, is there anything you can say about your hedging over the next couple years?

It's Bill again.

We don't provide any forward indication for competitive reasons on kind of what our hedging approach is. As you can see from the results in the quarter, we were positioned fairly well, given the low price environment that occurred over the last quarter through that period. And we will continue going forward to try to opportunistically take advantage of opportunities in the market to improve our results.

Okay.

Staying with power, Becancour. Can you make any comments on kind of the contract structure?

There's obviously a bump up that's occurred. Is that sort of permanent to end of contract now?

Well, the contract at Becancour has not been revised. We did make some adjustments to the transportation contracts that were originally in place, the natural gas transportation contracts that were originally in place for Becancour.

And so part of the impact that you're seeing is a result of those adjustments that were made in respect of that gas transportation. And that, you can expect that we would see that continued effect to occur in 2015.

And anything you can say beyond 2015? Do you expect that to be ongoing?

It may depend on the expiry of those transportation agreements and what we intend to do with that going forward. So it's kind of speculative at this point.

Okay. Thanks.

Last question then, just sticking with power. On Ravenswood, there was an unplanned outage in 4Q. Is that going to be material, you think, to capacity over the next couple years or was it pretty short?

Well, we have -- the station is still -- unit 30, I should say, is still being repaired at Ravenswood. Work on that is going well. There will be some impact that will come in primarily in 2016 and a little bit into 2017 that will be -- that will result from having occurred -- had that outage occur.

Thank you very much, guys. Those are my questions.

Thanks, Matthew.

Thank you. Our next question is from Linda Ezergailis from TD Securities. Please go ahead.

Thank you.

In your MD&A you mentioned that there's a possibility to implement some operational efficiencies at Keystone to improve capacity and flows. It sounds like there's a possibility to do that even with Energy East down the road.

Can you talk about what that might be and how much capacity you might unlock? Is that drag reducing agent or something else, batching or --

Hi, Linda. It's Paul Miller here.

That's exactly what it is. On Keystone we've increased our flows probably by about 20,000 barrels per day so far by the use of drag reducing agents, as well as other efficiencies that we've found in the pipeline.

So we'll continue to explore those on Keystone. And once in operation on all of our pipes we'll explore these opportunities, so Energy East included. With Energy East today we believe the capacity's 1.1 million barrels per day. We're always looking for ways to improve the reliability and the efficiency of our operations.

Thank you.

And just a follow-up question with respect to the landowner lawsuit in Nebraska. Can you walk us through how long that will take to resolve and what the bookends of the outcome will be? I'm not a legal expert, so I'm wondering what also the basis is in terms of Constitutional consideration?

Linda, it's Alex.

So we had that decision come out of the Nebraska Supreme Court a little while ago. And basically what happened was three of the four judges found that the plaintiffs did not have standing.

And given that you require a super majority to find that a law is unconstitutional, the existing Nebraska legislation and the process we went through to determine the route in Nebraska was therefore valid. One of the outcomes of that, though, was, because the decision was made basically on this lack of standing, it left the opportunity open for landowners with standing to make a claim.

So that process has -- now that has occurred. And we have a couple of lawsuits that are seeking to determine the constitutionality of the route. I think you're going to see the same -- it should be the same process. There will be a trial.

Because the only issue at stake is this issue of Constitutionality, it should be able to be concluded very quickly. And if it is found that the -- if it is found to be Constitutional by that same super majority, that is the end of the case and our route is Constitutional.

If it is, on the other hand, found by a super majority -- or sorry found by the trial that it is unconstitutional, then there would obviously be an appeal to the Nebraska Supreme Court in the same manner as the previous round of cases. Once again, I think the good news about this is there is only one issue at stake. It's the Constitutionality.

And I think we can probably get through the two cases sometime, give or take, in about a year or so. And I would just -- the other point that I would say is, in Nebraska, right now, we already have 90% of those easements have been signed voluntarily. And in the other states along the route we have 100% of the easements signed voluntarily. So we really are talking about a very small number of landowners that we haven't resolved things amicably with.

Great. Thank you.

Thank you. The next question is from Rob Hope from Macquarie. Please go ahead.

Hello. Good afternoon. Maybe just shifting a little bit north to South Dakota.

Just wondering about the formal hearing regard the recertification of the permit. How long do you think that could potentially take?

I'm trying to remember the exact time.

I believe that our thoughts is that we would be through that process sometime -- I think the hearing's in June and that we would see a decision sometime around September-ish, if I recall.

Yes, I believe it's set for May. So just a little bit earlier than what Russ highlighted.

I'm sorry. When would you expect a resolution?

Sometime in Q3.

Thank you.

We don't have an exact date, but that would be our speculation.

All right. Very helpful.

Maybe just one follow-up question. Broadly speaking with the commodity price environment and your access to capital, are you taking a harder look at acquisitions either for individual assets or potentially larger packages?

No question. We've been through these cycles before as a company. And there's several assets of out there in the marketplace that we covet. But obviously in certain market cycles they're not available to us. So we'll remain attentive to that.

I think if you look back in our history, when we've seen market downturns like this we have acted. We bought GTN in that kind of an environment. We bought our Northeast hydro assets in that kind of environment. So several assets that we've acted on.

And I do believe that that is a possibility. If we see a sustained downturn in commodity prices, there could be really good assets that are freed up and we have the [financial] capacity to actually act on that currently.

So that is one of the reasons why we try to maintain a strong balance sheet and financial flexibility to do those things. And if we see some of our capital programs being pushed out, like Keystone XL and that sort of thing, again it gives us more capacity to be able the do those kinds of things in the short run.

Great. Thank you.

Thanks, Rob.

Thank you. The next question is from Steven Paget from First Energy. Please go ahead.

Good afternoon, and thank you. When you consider your US gas pipelines and contracts, are all these pipelines now ready for at least potential drop down into TC Pipes?

Yes, Steven. It's Karl.

I think that we said years ago, I think on ANR, we want to do a little bit of work selling it and we have actually sold it out now. I think all the assets are what I would call drop-down ready.

We are -- I'll defer this further comment on this to Don, but we are in a process right now kind of dropping down one at a time. And we've made a commitment to keep that process up. So I'd say there's nothing inhibiting us from moving these assets into the LP at the proper time -- timing.

I'll just echo comments made at Investor Day, we're on the conveyor belt approach here. The intent is to collect cash from these assets while maintaining control of them and being cognizant of the capacity limitations at the LP to absorb these assets.

We think the LP has capacity of CAD1 billion-plus per annum. We've got buys (technical difficulties) DGTN is set to close here in this quarter.

Then we'll continue to move forward with the rest of them. There's been no change to the strategy we outlined back in November.

Karl, Don, thank you. This question I guess would be for Bill or Alex.

Could I ask what the internal timeline might be for securing the future of Bruce Power Units 3 through 8? There's been media reports that the Unit 4 refurbishment process will begin in the summer of 2016.

Sure. I can try and give you a brief update on that. Discussions are being led by Bruce Power, and they're still actively in those discussions with the ISO and representatives from the government of Ontario.

So there's not really any detail I can provide on that at the moment, other than to say that the discussions are still ongoing. As for the timing, I would say it's really premature to try to focus on any single timeframe at the moment, given the status of those discussions.

Thank you, Bill. Those are my questions.

Thank you. Your next question is from Carl Kirst from BMO Capital Markets. Please go ahead.

Thanks, guys. Appreciate the follow-up here.

I was just curious, Russ, on XL you guys obviously responded to the EPA letter. I haven't seen anything in the public record with respect to the State Department, but have any of the other agency waived in, Homeland Security on energy security, et cetera, that you guys are aware of?

I believe that the State Department has said that all of the agencies have commented. We don't know what's in those comments, but my understanding is they have commented, and at least to this point in time the State Department has said that those are internal documents and they're not making them public.

Understood. Okay. I appreciate that.

Two micro questions, if I could. Just one, Don, can you actually say how much right now of 2016 net currency exposure is floating versus hedged? 80% hedged, or something less than that?

Sure. Let me give you some color on the currency. I guess my earlier question I should have clarified that -- I talked about Keystone being flat to slightly up on a Canadian dollar basis.

Had a more modest exchange rate factored into that than the current spot levels we're seeing today. So for 2015, we are largely hedged. There might be a couple pennies of pickup in there, but it's not material.

Looking out into 2016 and onward, our run rate is about $600 million after-tax US dollar income as exposed. That is after natural hedges in the form of US dollar debt. So that's before financial derivatives but after US dollar debt.

For every CAD0.10 move you get year over year you're looking at something in the order of CAD60 million of after-tax income that would fall to the bottom line.

Don, sorry. That would be on an unhedged basis then? You're indicating that we don't have any hedges layered on for 2016?

Not beyond US dollar debt and interest associated with it. So that would be -- it's about CAD150 million a quarter run rate going for 2016 onward of exposed currency from a P&L perspective.

Understood. Very much appreciate that.

And then last question, if I could, just a very small one. Bruce Power, and you guys may have already said this so I apologize. But Bruce Power this quarter, I think was Bruce A, there was an out-of-period generation adjustment. Could I get the size of that?

Out-of-period generation adjustment?

There was a, quote, deemed generation adjustment, of a prior period. I'll follow-up offline.

We'll give it a quick look, Carl, but we'll be happy to follow up offline. (Multiple speakers)

it was just an adjustment for -- there was a substation outage that was classified or qualified as deemed generation in the third quarter and it was trued-up in the fourth quarter. Our share of that was about a CAD0.01.

Okay. Perfect. Thanks, guys.

Thank you. Our next question is from Andy Gupta from HITE Hedge. Please go ahead.

Mr. Gupta, your line is open. Please proceed.

Hi, thank you so much for taking my question. Just a quick follow-up on your comment about there being capacity at TCP. It seems with the share price that's come off since last November, do you still think TCP has got the capacity to absorb greater than CAD1 million of (inaudible)?

Yes, we do. The share price is still fairly robust. I think it's in the high CAD60s.

Yes.

Yes, and as well at current debt levels, debt forms part of the equation at TCP as well. I think they're (technical difficulties) assets. The debt levels are -- the debt funding levels are more attractive than they were back then.

Understood. From what I understand from the Investor Day as well is that these drops, which will generate about CAD5 billion of proceeds to TRP, is really to fund your near-term projects, right? Like Energy East or Keystone XL, that's not being funded by this. This is more the near term, CAD12 billion to CAD13 billion of projects?

Yes. We're not color-coding any specific drop to any specific CapEx project. But collectively with CAD12 billion of high visibility, small- to medium-sized projects, we feel quite comfortable that there's a logical home for CAD5 billion-ish of proceeds from these drop-downs (technical difficulties).

Understood. Thank you so much.

You're welcome.

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

(Operator Instructions)

We have a question from [Julian Arseno] from The [French] Canadian. Please go ahead.

Regarding Energy East, it seems less and less likely that there will be a marine terminal in Cacouna. Why wait until the end of the quarter to confirm the news?

It's Alex Pourbaix.

We, as Russ said in his comments, we expect to announce it in Q1. It doesn't mean that we're going to wait to the end of Q1.

But there really is a lot a that goes into the discussion and the analysis of this. But we expect to make a decision fairly quickly on that.

Is it possible to realize Energy East without a marine terminal in the province of Quebec? Because, I mean, there's a lot of position and some other town that has been mentioned to be a potential side business seems open to get one?

Sure. I mean, I think the number one priority for the project is that we ensure that we are connected to the refineries in Quebec. And I think under any option we'd be looking at, that would obviously continue.

Assuming that that was the case, there are any number of configurations or options that could be anywhere from locating another terminal in Quebec to having one terminal in New Brunswick. So that's actually the process we're going through right now, to find out what are the best of the options.

Okay. But you're confident that you will have a marine terminal in Quebec?

What I'm saying is I'm absolutely confident that we're going to be connected to the Quebec refineries. And we're doing that analysis of where or if we have a terminal in Quebec. And that work isn't completed at this point.

It's a triangulation of commercial interest, environmental interest and job creation and those kinds of interests. And within there we'll try to optimize the answer to maximize the benefits to Quebec, minimize environmental impact and do it in a way that's economic for our shippers.

That's the making of a good project and a win/win/win for everybody. That is a complex analysis with lots of stakeholders involved. That's why it's taking us the time to get through this process.

Maybe just to clarify. There's a lot of news report here saying that you have already quit on the Cacouna project. Maybe just finish your stand on this?

I think what we said at the time that we put all the work on hold remains true. And that was we take the concern over the Beluga whale in the St. Lawrence very seriously. That is why when that recommendation came from that federal commission, that we immediately put all work on hold.

And whatever resolution we come to, we're going to make sure that it's a resolution that in our minds will absolutely protect that population of whales. And beyond that, we're just once again doing that analysis to see sort of what options look the best.

Thank you.

Thank you. Our next question is from Ben Dummett from the Wall Street Journal. Please go ahead.

Could you just elaborate on the reasons behind doing the Upland pipeline? I realize you referenced the fact that there's all this Bakken oil that's being moved by rail. But is it just a matter of trying to win share of that business?

Hi, Dan. It's Paul Miller here.

I think to start off with, our business model is, we're business responsive and we're reacting to a desire in part for market access and in desire by the producers to get some of their product off the rail.

And so in response to that desire and to off [up] that market access, we went to an open season to gauge what sort of interest was there. We were able to secure enough contracted volume to move forward with the project and provide that access for those Williston Basin producers.

We will, as Russ indicated in his prepared remarks, we've contracted 70,000 barrels a day that will move on Upland and connect to Energy East. We will also provide transportation services within the Williston Basin from various gathering systems, from various feeder pipelines to connect with other pipelines beyond Energy East to take barrels out of the Williston Basin.

And we will continue to provide the transportation for the Bakken producer once we move forward with Keystone XL. We've set aside 100,000 barrels a day for the North Dakota producer and Montana producer on Keystone XL as well.

So it's a combination of market demand and where those barrels want to go to, and it's an opportunity that we looked at and responded.

And just at the macro level, there's no question that the production is up in North America across the board. Canadian production's up since we made our application on Keystone by about 1 million barrels a day, and US production is up by about 2 million barrels a day.

All of that production is moving on rail today and it wants to get off rail as quickly as possible. And so those producers are talking to TransCanada and other service operators, pipeline service operators, to look for alternatives and to move it off the rails onto a less expensive, more efficient, safer system.

And so I think you'll see more of this down the road where people will try to find innovative solutions to move that volume off the rails. And this is actually a very visible volume that has been moving for several months from the Bakken by rail through Canada right to refineries in Quebec and in New Brunswick. And this is a safe solution to optimizing that movement.

And then how long is this, the Upland pipeline? How many miles? How long will it be?

The Upland pipeline itself I believe is about 300 kilometers, or about just under 200 miles.

Okay.

I can validate that for you if you'd like.

That would be good, if you could just do that, I guess.

One last thing. You're going to need State Department approval for this.

Given the difficulties that you've had with Keystone, there's this little irony here. Do you expect the same kind of difficulties?

I really can't tell you that. This has been extraordinarily difficult process. Our historic experience of gaining approval to cross the border has taken 24 months.

Other pipelines that have exactly the same characteristics have taken 24 months. This particular one has taken 6.5 years. I hope that's an anomaly in Canada/US trade of energy and that isn't the situation going forward.

Obviously the market isn't waiting for the regulators to catch up with their decision. They're moving the oil now. My view is eventually that oil has to move, and eventually we'll obtain the permits.

Whether that be a Keystone XL permit or the permit for the pipeline like Uplands. These are necessary pieces of infrastructure that are required to efficiently move volumes that are being produced today between production locations and markets. It's a necessity that has to be done and has to be done safely. But these things have to get completed.

That's Russ that spoke there, right?

Correct.

Ben, it's Paul Miller again. I misspoke earlier. Upland pipeline is 460 kilometers or 285 miles.

Great. Thanks for your help.

You're welcome.

Thank you. Our next question's from Jennifer Diouhy from Houston Chronicle. Please go ahead.

Thanks for taking my question, most of which has been asked. But with regard to Upland, could you talk about the potential border crossing, where that would be located, if that's been determined at this point?

Hi, Jennifer. It's Paul Miller here.

It hasn't been determined definitively, but it will be between Saskatchewan and North Dakota.

If you look at a place called Moosomin, Saskatchewan, and go straight south, it's a point just east of the Manitoba/Saskatchewan border. It's beyond the probably Central North Dakota and Eastern Saskatchewan is the best I can provide. But straight south of Moosomin, Saskatchewan is a best guess right now.

That makes sense. Thanks very much.

You're welcome.

Thank you. The next question is from Iris Kuo from Argus Media. Please go ahead.

Hi. Thanks for taking my question.

In the past you've talked about building a rail bridge in lieu or in addition to Keystone XL. Just wondering where you are with that project right now?

Hi, iris. It's Paul Miller here.

We continue to explore rail as a transportation solution for the producer, separate and apart from Keystone XL. Not necessarily a Keystone XL bridge, but a reflection of the producers having to get to the market until a pipeline's developed.

As we said previously, we do believe rail will be a permanent part of the producers' transportation solution, in part to access niche markets and in part to manage around kind of the lumpiness, if you wish, of pipeline implementation. So we continue to work with a number of prospective shippers in this regard.

It's something that they want to move forward with. It's something that we're working together with to bring to fruition here. It just takes time because these are major decisions for a lot of these producers. And it's the type of transportation that they haven't used traditionally.

So it's just a bit of a learning curve as well. So it's taken some time, a little longer than we thought and had hoped. But it's something we are still pursuing.

Okay. Do you have a timeline for when you might make a decision, or is it just ongoing?

It's pretty much ongoing. We typically disclose a project once we have it locked down with all the commercial support. So we'll continue to pursue the commercial support and make the appropriate announcement at the time.

Okay. And have the current low oil prices impacted at all the shipper interest in the rail project?

Not really. Ultimately the netbacks are going to determine rail usage, and we have seen some softening of rail transportation rates. Not as much as I would have anticipated.

But I think it becomes almost self-fulfilling. As we see increased production you see bigger differentials and lower netbacks if you can't access the efficient transportation.

So it drives people to pursue rail. And the producers are taking a long-term perspective. There's nothing worse than having traffic deductions.

So they're making long-term commitments on a resource, particularly out of Canada here that has 100-year life. And so they want to ensure that they have the access to the market that they need to realize on their investment in this upstream. So we haven't really seen any softening in the motivation.

Okay. Great.

And finally, could you give us some sense of what flows are right now on the Gulf Coast pipeline?

Yes. The Gulf Coast flow's about 400,000 barrels per day.

Okay.

Probably just under 400,000 barrels per day.

All right. Great. Thank you very much.

You're welcome.

Thank you. We have no further questions at this time. I'd like to return the meeting back to Mr. Moneta.

Thanks very much. And thanks to all of you for participating this afternoon. We very much appreciate your interest late on a Friday afternoon before a long weekend for many.

So thanks again, and we look forward to speaking to you soon. Bye for now.

Thank you. The conference call has now ended. Please disconnect your lines at this time, and we thank all who participated.