TC Energy Corp (TRP) 2015 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 third-quarter results conference call.

I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.

Thanks, very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2015 third-quarter conference call.

With me today are Russ Girling, President and Chief Executive Officer, Don Marchand, Executive Vice President, Corporate Development and Chief Financial Officer, Alex Pourbaix, Chief Operating Officer, Karl Johannson, President of our Natural Gas Pipelines business, Paul Miller, President of Liquids Pipelines, Bill Taylor, President of Energy and Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com and 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 will 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 re-enter the queue.

Also we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations, 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 with the US Securities Exchange Commission.

Finally, I'd also like to point out that during the presentation, we'll refer to measures, such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, comparable EBITDA and funds generated from operations. These and certain other comparable measures do not have any standardized meaning enter 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 intended 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 morning, everyone, and thank you very much for joining us.

I'm pleased to report, today, another quarter of strong, consistent financial results from each of our three core businesses, reflecting the high percentage of contractual and regulatory underpinning of the revenues across our diverse fleet of critical energy infrastructure assets.

Only a small portion, less than 10%, of our cash flow is exposed to commodity price volatility, primarily in the Western power business in Alberta, and the US Northeast power business, where our asset portfolio primarily consists of the lowest cost base load power in those regions. Despite the continued weakness of Alberta power prices over the last nine months, we have seen comparable earnings and funds generated from operations rise 8% and 9%, respectively, compared to the same period last year.

During the quarter, we continued to advance our portfolio of shorter term critical energy infrastructure projects. We acquired the Ironwood power plant in Pennsylvania, and we initiated measures to improve our efficiency and streamline our costs. These initiatives, combined with the stability of our base business, gives us the capacity to continue to grow our dividend at 8% to 10% through 2017.

In addition, we continue to advance our CAD35 billion portfolio of longer term projects, including receiving all of the required permits for our Prince Rupert gas transmission project, and concluding an agreement with Eastern Canadian local gas distribution companies, to allow the conversion of the eastern section of the Canadian Mainline, for our energies project.

These larger scale projects, combined with the ongoing investment to growth in our core businesses, will provide us with the opportunity to enhance our growth rate in earnings, cash flow and dividends for many years to come. I'll spend the next few minutes highlighting our progress on many fronts during the quarter, and then our CFO, Don Marchand, will follow with more details on our financial performance in the third quarter.

TransCanada reported net income of CAD402 million, or CAD0.57 per share, in the third quarter. Comparable earnings for the quarter were CAD440 million, or CAD0.62 per share. Comparable EBITDA was CAD1.5 billion, and funds generated from operations were CAD1.1 billion.

Earlier today, our Board of Directors declared a quarterly dividend of CAD0.52 per common share for the quarter ending December 31, 2015. TransCanada has raised the dividend in each of the last 15 years from an annual CAD0.80 in 2000 to the current CAD2.08, a rate which is 8% over last year's rate.

As I said, looking forward, continued strong performance of our core businesses and CAD12 billion of visible near-term growth is expected to provide the foundation to continue to grow our dividend at an annual rate of 8% to 10% through 2017.

So, to get to the specifics on our growth initiatives, I'll start with our gas pipelines. Nearly CAD7 billion of new supply and demand facilities are under development on our NGTL system. Approximately CAD2.8 billion of those facilities have received regulatory approval, and CAD800 million of those facilities are currently under construction. An additional CAD500 million are currently being reviewed by the regulator.

NGTL continues to be the pipeline of choice for connecting new production volumes in the Alberta deep gas basin, Montney, and Duberney regions of the Western Sedimentary Basin. We've received a very positive response to our 2008 NGTL open season that we anticipate will result in a substantial volume of new receipt and delivery contracts. This additional contracted demand for system capacity will increase the overall capital spend on the NGTL system beyond the approximate CAD7 billion that has been previously announced. We expect to be able to provide more specific updates on the NGTL open season in the coming weeks.

On our Prince Rupert gas transmission project, we announced, just days ago, that we received the final permits from the BC Oil and Gas Commission, giving us regulatory approval to construct and operate the pipeline. We now have the full compliment of 11 pipeline and facility permits required from the BC Oil and Gas Commission. Just to remind you, we have also received environmental permits for the project from BC Environmental Assessment Office in late 2014.

During the third quarter we also continued our engagement with aboriginal communities and have now signed project agreements with nine first nation groups along the route and expect to conclude more in the coming weeks and months. We remain on target to begin construction of the Prince Rupert project following confirmation of a final investment decision from Pacific Northwest LNG.

On our Coastal GasLink project, we have received 8 of the 10 permits from the BC oil and gas commission. We anticipate receiving the remaining 2 permits needed in the fourth quarter of this year.

The Coastal GasLink project has also received its environmental permits from the BC Environmental Assessment Office. Like Prince Rupert, we're continuing our engagement with aboriginal communities, and have signed project agreements with eight first nation groups along that pipeline route, and, again, we look forward to concluding additional agreements with these communities. The project team continues to work through the regulatory process with a focus on achieving a positive final investment decision for the project.

In Mexico, we are currently investing approximately CAD1.5 billion constructing two large natural gas pipelines, further building our presence in that country. The CAD1 billion Topolobampo natural gas pipeline is now 70% complete and the CAD400 million Mazatlan project is just over 80% complete. Both pipelines are located in northwest Mexico and are expected to be operational in 2016, and we continue to pursue additional opportunities for new energy infrastructure projects in Mexico.

Moving over to crude oil, after announcing in early April that we would not build a Marine terminal at Cacouna in Quebec, we continue to review potential alternative export terminal options with our shippers and other stakeholders. We expect that we will be in a position to offer further update on that shortly. During the past 12 months, the national energy board has continued to review our October 2014 filing.

In a related announcement, in late August, we reached an agreement with local gas distribution companies in Eastern Canada, Gaz Metro, Enbridge Gas Distribution and Union Gas that resolves their issues with Energy East and the Eastern mainline project. The agreement ensures that Energy East and Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduce transmission costs. The Eastern Mainline Project's capital cost is now estimated at CAD2 billion reflecting the refinements to scope and routing necessary to complete the project.

Moving to Keystone XL, in early October, we filed an application with the Nebraska Public Service Commission to seek approval for the Keystone XL route through that state. We believe that going through the Public Service Commission process is the clearest and quickest path to achieving route certainty for Keystone XL in Nebraska. The proposed route is the route that was evaluated by the Nebraska Department of Environmental Quality and approved by the governor of Nebraska in 2013.

Yesterday, we sent a letter to US Secretary of State, John Kerry, asking the State Department pause its review of the presidential permit application for Keystone XL.

We believe that a pause to resolve the Nebraska route gives the best opportunity to achieve overall approval for the project. As of September 30, 2015, we have invested CAD2.4 billion in the project and we have capitalized CAD400 million of interest.

Construction continues on the Houston lateral pipeline and tank terminal, which will extend the Keystone pipeline to Houston and the refineries in that region. The terminal is expected to have an initial storage capacity of 700,000 barrels of crude oil. The Houston Lateral pipeline and terminal are anticipated to be operational in the second quarter of 2016.

Continuing with our liquids business, construction of the Northern Courier project is on schedule. The CAD1 billion Northern Courier project consists of the 24-inch bitumen pipeline and a 12-inch diluent pipeline, that will run between the Fort Hills mine and the bitumen extraction facility and Suncor's east tank farm. 100% of the pipeline's capacity is contracted to the Fort Hills partners under a 25 year agreement. Approximately 30% of the construction has been completed, and we're scheduled to be in service in Q2 of 2017.

In August, we announced an agreement where the southernmost portion of the 20 inch diluent Grand Rapids pipeline will become part of the 50/50 joint venture with Keyera Corporation. The 45 kilometer pipeline will extend from Keyera's Edmonton terminal to TransCanada's Heartland terminal near Fort Saskatchewan. This strategic partnership with Keyera will give Alberta oil sands producers access to reliable and cost effective sources of diluent. We expect the total conservation to the joint venture will be approximately CAD140 million from Grand Rapids. The expected in-service date is the second half of 2017, subject to regulatory approval.

Moving over to energy, where construction started earlier this year on the 900 megawatt, natural gas-fired, Napanee Generating Station located in Eastern Ontario: it is now 20% complete. The facility will provide clean energy under a 20 year supply contract with the province's independent electric system operator, or the IESO. The CAD1 billion Napanee project is expected be operational in late 2017 or early 2018.

Also in energy, a few weeks ago, we reached an agreement to acquire the 778 megawatt Ironwood power plant in Lebanon, Pennsylvania from Talen Energy, for $654 million. The acquisition presents a very unique opportunity in the current market environment to acquire a quality asset at a reasonable price. The Ironwood deal is a natural extension of our US Northeast power business, strengthening our overall portfolio and assets in the region. This relatively new and highly efficient gas-fired power plant provides us with a solid platform to backstop and grow our already substantial wholesale, commercial and industrial customer base in Pennsylvania, New Jersey and Maryland.

On a peakload basis, our customer commitments, in the PJM market, will now largely be matched by the Ironwood plant. The acquisition is expected to be immediately accretive to earnings and cash flow and will generate approximately $90 million to $110 million in earnings before interest, taxes, depreciation, amortization annually through a combination of both capacity payments and energy sales. Ironwood complements our US Northeast operations which now total over 4500 megawatts.

The acquisition continues our disciplined approach to growth in this important region where we have been operating on the power side since 1998. The deal will be financed with a combination of cash and debt capacity, and the transaction is expected to close in the first quarter of 2016.

Finally in energy, consistent with Ontario's long-term energy plan, Bruce Power has been in discussions with the Ontario IESO for some time to reach an agreement regarding additional investment that would extend the life of this very important facility. We remain optimistic that an agreement can be reached that will ultimately provide emissionless energy to consumers of Ontario for many decades to come.

Before I wrap up, I wanted to highlight some management changes and corporate restructuring that we have implemented that was effective October 1, 2015. Earlier this year, we initiated a plan to decentralize many of our operating project and functional support groups placing greater accountability on our business units to determine optimal resourcing requirements for their businesses. Alex Pourbaix was appointed Chief Operating Officer. Don Marchand was appointed Executive Vice President, Corporate Development and Chief Financial Officer. And Kristine Delkus was appointed Executive Vice President, Stakeholder Relations and General Counsel. Jim Baggs, Executive Vice President of operations and engineering has announced his intention to retire in early 2016.

The restructuring will provide a clear focus on safety management, generating efficiencies in operations, streamlining decision-making and maximizing the value of each business unit. This will result in lower costs for both TransCanada and for our customers. We expect further changes in the fourth quarter of 2015, and those changes will continue into 2016.

To conclude, we had another strong quarter that builds on the company's performance over the last nine months where we saw a comparable earnings and funds generated from operations rise 8% and 9%, respectively, compared to the same period last your.

Looking forward, our focus remains on the following: First, to maximize the performance of our stable portfolio of critical energy infrastructure assets; second, to bring into service CAD12 billion of shorter term projects on time and on budget. That growth, combined with our base business cash flows, allows us to continue to grow our dividend at 8% to10% through 2017. Third, we will continue to pursue the organic investment initiatives in our current portfolio, and we will advance our CAD35 billion of large-scale projects which will augment and extend our growth well into the next decade.

I will now turn the call over to Don for further details on our Q3 financial performance. Don?

Thanks, Russ, and good morning, everyone.

As highlighted in our news release, our core asset base continued to perform well in a challenging industry environment in the third quarter, with net income attributable to common shares of CAD402 million, or CAD0.57 per share compared to CAD457 million, or CAD0.64 per share for the same period in 2014. Excluding a CAD6 million, after tax, restructuring charge, stemming from our efforts to maximize the effectiveness and efficiency of our existing operations, as well as unrealized gains, from various risk management activities, comparable earnings in the third quarter are CAD440 million, or CAD0.62 per share, were largely in line with the CAD450 million, or CAD0.63 reported in the same period last year. Higher earnings from the Keystone system, natural gas pipelines, and US power, were offset by depressed power prices in Alberta and planned maintenance outages at Bruce Power.

In terms of our business segment results at the EBITDA level, the natural gas pipelines business generated comparable EBITDA of CAD812 million in the third quarter 2015, compared to CAD750 million for the same period last year.

Canadian natural gas pipelines comparable EBITDA of CAD548 million decreased CAD9 million compared to 2014 primarily due to lower earnings on the Canadian mainline, partially offset by higher earnings in the NGTL system. Canadian mainline net income decreased CAD14 million in third quarter 2015 to CAD47 million, largely due to a lower achieved ROE of 10.1%, which included CAD7 million of after tax incentive earnings versus 11.5% last year and a smaller investment base.

NGTL's net income increased by CAD9 million in the third quarter, compared to the same period last year, primarily as a result of its growing investment base, and OM&A incentive losses realized in 2014. US and international pipelines comparable EBITDA rose CAD88 million to CAD276 million in third quarter 2015, primarily as a result of higher transportation revenue on the ANR system and the positive impact of a stronger US dollar. Natural gas pipelines business development costs have risen for the 3- and 9-month periods in 2015, primarily as a result of increased activity along with the recovery of expenses from partners in 2014 for 2013 Alaska Gasline Inducement Act costs.

In liquids, the Keystone pipeline system generated CAD363 million of comparable EBITDA in the third quarter, an increase of CAD88 million from the same period last year. This was a result of higher uncontracted volume throughput and the favorable impact of a stronger US dollar. Business development costs in liquids increased CAD14 million year-over-year as a result of increased activities.

Turning to energy, comparable EBITDA declined CAD42 million to CAD345 million in third-quarter 2015 versus the same period in 2014 due to a combination of factors. Western power comparable EBITDA decreased CAD51 million due to lower realized prices. The Alberta power market continues to be well supplied, and, with weak economic conditions expected to persist in the near-term, lower demand growth for power is expected to continue to weigh on power prices.

The third quarter Bruce Power equity income decreased CAD54 million to CAD57 million, primarily as a result of a higher number of planned outage days, partially offset by lower lease expenses. While operating performance at Bruce B was strong, the extended planned outage on unit four at Bruce A contributed to lower overall results, compared to the same period in 2014. The approximate 100-day outage on unit four is nearing completion, bringing the planned major maintenance events at Bruce to an end for the year.

Eastern power continued to generate solid and predictable results with comparable EBITDA up CAD11 million year-over-year due to the incremental earnings from solar facilities acquired in the second half of 2014. US power comparable EBITDA of CAD183 million increased CAD55 million in the third quarter, compared to the same period in 2014, primarily due to stronger margins, higher sales volumes to wholesale customers and a stronger US dollar, partially offset by lower realized power prices and reduced generation in New England, along with softer capacity prices in New York.

Now turning to the other income statement items on slide 22, comparable interest expense of CAD341 million in the third quarter increased CAD37 million compared to the same period last year. This was primarily due to interest charges on recent Canadian and US debt issues and higher foreign exchange on interest denominated in US dollars, partially offset by Canadian and US debt maturities and higher capitalized interest.

Comparable interest income and other was down CAD7 million compared to third quarter 2014, mainly due to 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.

Partially offsetting the higher foreign currency hedging costs, was increased AFUDC related to our rate regulated projects including Energy East and Mexican pipelines. We saw minimal year-over-year net benefit from the strengthening US dollar in our third quarter due to our hedging activity. As a reminder, our exposure to US dollar income is largely offset with US dollar interest expense and financial derivatives.

Going forward, we will see future results positively impacted from the stronger US dollar as legacy hedges roll off and our reinstated at higher levels. Comparable income tax expense of CAD236 million in the third quarter increased CAD6 million versus the same period last year due to higher pretax earnings and changes in the proportion of income earned in higher tax jurisdictions, partially offset by lower flow through taxes in Canadian regulated pipelines. Net income attributable to non-controlling interest increased CAD21 million compared to the same period in 2014, primarily due to the sale of our remaining 30% interests in GTN and Bison to TC Pipelines, LP in April 2015 and late 2014, respectively, along with the foreign currency translation impact of US dollar minority interest in the LP.

Now moving on to cash flow and investing activities on slide 23, despite challenging industry conditions, or high quality asset base, continues to generate robust cash flow with funds generated from operations of approximately CAD1.1 billion in the quarter and CAD3.4 billion year-to-date, which represents 6% and 9% increases year-over-year.

Capital spending, including projects under development, totaled CAD1.1 billion in the quarter, driven primarily by NGTL system growth, construction activities on Mexican pipelines and Northern Courier in Napanee, along with ongoing expansion work at ANR in the Canadian mainline. Equity investments of approximately CAD100 million reflected activities related to the Grand Rapids Pipeline and Bruce Power.

Turning next to our liquidity and access to capital markets on slide 24, our financial position remains strong. At September 30, our consolidated capital structure consisted of 35% common equity, 5% preferred shares, 4% junior subordinated notes and 56% debt net of cash. From a liquidity perspective, we had approximately CAD750 million of cash on hand, CAD5 billion of committed and undrawn revolving bank lines available with our high quality bank group, as well as two well-supported commercial paper programs.

In terms of financing activity in 2015, to date we have raised in excess of CAD5 billion on compelling terms in order to fund our capital program and refinance scheduled debt maturities. Most recently we issued CAD750 million of 10-year medium term notes in July, at a rate of 3.3% and another $400 million of long-dated MTNs in October at 4.55% to fund the growing NGTL system rate base.

Our diversified asset footprint continues to provide us with significant opportunities to invest capital in the businesses, while our robust internally generated cash flow, access to capital markets and numerous funding levers available, will enable us to source attractive funding for the CAD12 billion of near-term growth initiatives that are expected to be placed into service over the next three years.

In summary, the company's blue-chip portfolio of critical energy infrastructure assets continues to produce strong results in challenging energy market conditions. For the first nine months of 2015, comparable earnings per share and funds generated from operations were up 8% and 9%, respectively, compared to the same period in 2014. With solid foundation in the form of a high quality and diversified suite of assets and CAD12 billion of near-term growth projects, we remain committed to increasing the dividend at an annual rate of 8% to 10% through 2017.

Our financial strength and flexibility, supported by our A grade credit is a distinct competitive advantage in the current environment, giving us the confidence to fund our substantive capital program at all points of the economic cycle. We also continue to advance numerous other investment opportunities, including CAD35 billion of commercially secured projects. While the timing around these longer term projects remains subject to certain regulatory processes and final investment decisions by our customers, they are significantly underpinned by long term contracts, underscoring the need for new infrastructure that connects supply to market. As we await visibility on the timing of our larger scale projects, we are confident that our current asset footprint will allow us to capture incremental investment opportunities that will lead to sustained 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 will take questions from the financial community first, and once we have completed that, we will turn it over to the media. With that, I will turn it back to the conference coordinator.

(Operator Instructions)

Paul Lechem, CIBC.

Good morning, just a question, first on the Mexican gas pipes, you mentioned you are reviewing further opportunities there, can you discuss what the opportunities are and the time frames?

Sure, Paul. It's Karl.

Right now, the CFE has issued a number of pipelines that they intend to put out an RFP process. TransCanada, right now, has one bid in with an RFP, the [Turpan-Tula] project, the we are awaiting a final decision on, which will come next week. And the CFE has about six more projects that they plan to issue for RFPs over the next, I would say until the end of first quarter, so TransCanada's reviewing all of those projects, and we intend to participate on the ones that fit with our capabilities.

Can you give us a sense of the magnitude of those projects?

They run the whole spectrum, for example the (inaudible) is about $0.5 billion project that we are right now waiting for a decision. All the way up to their planning an offshore pipeline from really the border of Mexico down into the central part of Mexico, which will be probably in the CAD3.5 billion to CAD4 billion range, so most of the projects I would say, land between the half a billion to slightly over a billion, but there are some larger ones in that portfolio as well.

Maybe a bigger picture question, looking at the Ironwood acquisition, and thinking about your investments plans over the next few years, given that your major projects seem still to be a ways off. Can you talk about, how do you balance the (inaudible) capital potential major projects down the road versus the amount of investments in acquisitions in other areas that you are willing to do in the short to mid-term. Can you discuss the thoughts about the potential magnitude of any major investments that you're willing to make?

I think, as we've always said, our decisions will be disciplined and they'll be based on where we can add shareholder value. With respect to Ironwood, it's a very unique opportunity in that market region to buy an asset in what was a combination of two companies where certain assets were being sold, so we had an opportunity to buy an asset that was a perfect fit for our business in the region. So we moved on it. That is why we have the financial capacity that we have. We retain it for being able to act on those kinds of things. With respect to our capital programs, being pushed further out in the future. That does provide us with financial capacity in the short run, but we will only allocate our capital acquisitions that make sense. As I said, this was a unique one. We do not have a whole bunch of those kinds of things on our drawing board, today, but we will be very disciplined in how we allocate our capital, both between developments and acquisitions.

Paul, it's Don. I'll just add to that. There are two other aspects that we look at here. First is these large-scale projects are extremely well, if not fully, contracted, which gives us a lot of confidence that they would attract capital in virtually all economic conditions, so we're not necessarily storing capacity, today, for these projects that, in our view, are eminently financeable when they go ahead.

Secondly, the A credit rating is very important to us, in allowing us to access capital in virtually all conditions, and that is a safety net for us as we look at the world unfold here. And, again, we have a parking capital right now for stuff on the come. That's an important element that gives us confidence that we get the money when it is required.

Robert Kwan, RBC Capital Markets.

Just wondering, as you look at some of the financing options that you have in your quiver and specifically TCP and as you talk more about Mexico, project financing there to release capital, how do you think about doing that in a current CapEx environment where you're pretty well funded out of FFO and the debt markets. Is that is something where you might be leaving that out there for the future, or in the case of TCP are you committed to continuing the drop down program?

It's Don, here, good morning, Robert. There is no substantive change in our long term thinking on the drop down program. We're still on the path within the balance of our US gas pipeline assets, doing the LP on a systematic basis over the coming years, so the LP enterprise and our capital needs are always a consideration, but, again, no fundamental change in our thinking there.

In terms of other levers we can pull, aside -- equity is lowest on the list here, but we continue to be active in the hybrid market. We watch the preferred market here in Canada where we can attract 50% equity credit for issuing those securities. As well, we will explore project financing where we can get that off credit. Places we would look to would be potentially our LNG pipelines to the West Coast and Mexico would be two primary ones we would look at.

At this point we're not actively looking at project financing Mexico. We have assets in construction there right now. It is something I think is a more viable alternative for us once they are in service, and there is no construction risk outstanding on them. Again, we think we have lots of levers we can pull across the portfolio to source capital on attractive terms, and these ebb and flow based on market conditions, but we're pretty comfortable with our ability to fund the program.

On Ravenswood, I think you have an application out to mothball some of the smaller units, and I think there were some also smaller units that you have already mothballed. I am just wondering, what are the plans there for Ravenswood going forward, specifically repowering? And then is there anything to be concerned about with respect to some of the things you highlighted as to why you want to mothball, with respect to the larger units at Ravenswood?

Robert, it is Bill.

The units that we filed documents with the New York ISO for consideration of the mothballing, were some of the smaller, older machines in the peaking plant portion of Ravenswood. And that portion of the plant was always considered, by us, when we acquired the facility in 2007 and 2008 that as the first area of the plant which would reach technical or operational obsolescence and that is sort of what we are running into there.

We are cognizant, obviously, of the safety of our personnel in our operations and those proportions of the plant are difficult to keep running, so we are considering our options there and in consultation with the ISO as it relates to their reliability assessments.

So I think you can look at it, that it will be that portion of the plant were any repowering options would be considered first. And to your question on the other portions of the plant, they are in much better shape in terms of not only the importance to the region but also the operating efficiency and capability to continue operating and the other portions of the plant are not in question.

Linda Ezergailis, TD Securities.

I am wondering about Keystone XL. I am wondering, I'm assuming that the Department of State grants pause in your application processing. How might we think of an earliest in-service date and is it reasonable to assume that if your capital spending on that project effectively goes to almost $0 until that process resumes?

Linda, it is Alex.

The capital spending is already really at a very low level, all we are really spending is what is required to maintain the equipment and to advance the regulatory processes we are involved in, so it is at a very low level right now. With respect to timing of in-service, we have always said that the pipeline is going to take about 2 to 2.5 years until the time we receive our permits, so you can just do the math from there. Nothing has changed in that regard.

Moving on to Energy East, I guess there was some discussion in the liberal platform about potentially maybe changing how the NEB operates. Have you had any discussions with the liberal government as to how that might affect Energy East or any of your other projects on the east or the west coast?

No, we have not and I think our perspective on that is, we have always followed whatever regulatory processes is in place in any of the jurisdictions we operate in to the extent that the new government decides to modify the rules or procedures, we are confident we will be able to manage within those new rules.

While we're talking about various and several governments, maybe can you provide some comments on how your discussions with the Ontario government are proceeding with the Bruce Power life extensions and when that might be concluded?

Brenda, it is Bill Taylor. I can report that the discussions with the ISO and government are continuing, they are progressing well. I can't speculate at this time as to when we would reach a conclusion on that matter, but as I said, I think things are progressing well.

It is a complicated set of discussions. I think both parties are, obviously being cautious, but you shouldn't take the long time that it is taking to conclude this discussion as any indication that the opportunity is in jeopardy, it is quite the contrary.

Andrew Kuske, Credit Suisse.

I guess the question is for Russ. If you look over the last few years, we saw pretty big divergence in multiples that the market was rewarding to high payout vehicles and particularly the MLPs in the US and more conventional Sea Corps and that has changed a lot in the last few months. And we are seeing that the target deal this morning, I've got to ask how do you look at the US landscape, potential M&A opportunities, that may exist and really that valuation divide that became very exaggerated in the last few years to dial back in.

I think we've had a pretty focus strategy on building our cash flow earnings and dividends, I think we have done a good job of that as we said we planned to continue to grow our dividend over the foreseeable future. What we have seen with the fall in oil prices primarily, but liquids prices in general across the US MLP space, there has been some rebasing of what those assets are worth.

We will continue to look at those businesses, but I think as we have said before, we haven't been focused on midstream assets that come with commodity exposure. We've been in those businesses before, they haven't been terribly successful for our company and that we look at our organic growth and growth opportunities that are emanating from our core businesses, gas across the western basin, the Marsalis into Mexico on the power side, our renewables portfolio, things like Bruce Power, our ability to build projects like that, the whole migration from coal fire power to gas fire power is going to present significant new opportunities from Alberta right through North America.

When we look at the oil side, it is a tougher business at the current time, but we continue to see lateral and other opportunities emanating from those businesses in the short run. We have a lot of opportunity that we are pursuing that is near term and it is tangible and as you saw, with something like the Ironwood acquisition, if we see good opportunities to acquire that fit our portfolio that are reasonably priced, we will pursue those. We think that those add shareholder value.

To the extent that things are priced at the upper end of the spectrum and that we don't see a way that we can add shareholder value by acquiring those assets, we've tended not to go after them, whether they be in a fully contracted asset or merchant assets; and they're still valuations that are very high out there that cause us to be very cautious about allocating our capital that direction.

Does that answer your question?

That is very helpful, and then specifically on Ironwood, do you see opportunities to deploy more capital, either at that facility or really around it, to really enhance the network of assets?

This is Bill Taylor, Andrew.

That would be an opportunity but I would say that would be longer term. There is some limited available space with the acquisition.

We haven't assessed that in any detail and that wouldn't be something that you could expect in the immediate future, but there certainly is some optionality in that regard with that location and it is very well situated from a gas supply point of view and a power injection point of view in PJM.

Matthew Akman, Scotiabank.

Couple of questions on Keystone, the results were quite strong in the quarter. I am just wondering if you could characterize a little bit the dynamic on Keystone shipping and tolling and what is driving the strong results and your outlook for the next year, given I guess on the one hand, lower oil price, but on the other hand, scarcity of pipeline capacity.

Matthew, this is Paul Miller here. We had a good third quarter. Much of our capacity is brought down by long-term contracts, but we do have spare capacity that we offer to the marketplace on a one contract at a supply basis, and we had a number of events in the past quarter where we had some midwest refineries go down. We had other events, which caused the differentials to increase, and a lot of crude on its way to the marketplace and Keystone capacity was available. So we were able to move probably upwards of 30,000 or 40,000 barrels per day of spot on average over the last quarter, taking advantage of these good market opportunities.

Our spot rate is about with the regulators and we do adjust our spot rate as the market conditions do change and we're able to take advantage of that over the quarter. Going forward, again with the resiliency of our business largely contracted across the board, we do not anticipate material change in our performance or the spot opportunities are going to be really a function of (inaudible).

Can I ask a follow up on Keystone? I guess this relates to the XL piece. If the State Department grants your request, can you guys sort of shift around some of the physical pipes that you have acquired for that project and then maybe shift then back later when the timing comes for XL, assuming it does get permitted?

Matthew, it is Alex.

Yes, to some degree we have already been doing that and to the extent that we have projects that can make use of that pipe, we're taking advantage of that.

Robert Catellier, GMP Securities

I just have a couple questions on energies. First, can you update the status in terms of finding an alternate [facility]?

It is Paul Miller here, Robert. We continue to look at options around the terminal facilities for Energy East and we are very close to reaching a decision here, we anticipate making an announcement here very shortly.

Can you confirm whether the LDC agreement has been finalized or not, and what the gating factors might be to cementing that [NED] application?

I'm sorry couldn't catch the second half of that question.

Just the gating factors with respect to cementing the revised NED application.

The question revolving around the NED application for Energy East?

Yes, so there are two parts. One, I want to know if you have in fact finalized the LDC agreement, and second, what work's left before you can submit the revised application on Energy East.

I will take the latter half of the question.

We continue to do some welding analysis, as well as some consultation around potential alternative lead facilities in pipeline routing. We did state that, that work would be complete and we would be in the position to file an amendment with the NED by year end.

It is Karl, I can address the other on [LDC] settlement on Energy East.

It is finalized now, the long form agreement has actually been signed by all parties, it was signed late last week, so my suspicion is it will make it's way to the NED shortly.

Rob Hope, Macquarie.

Just a question on the US power, similar to your Keystone results, you had fairly strong results from your US power operations. I'm trying to get a sense for the oil performance, how much was related to being able to purchase advantageous power in the market versus a general expanding of your marketing book and PJM in other regions?

Rob, it is Bill.

Our results in the US is kind of a mixed bag I guess, I would say. We have had some challenges with capacity prices, as was noted in our release, that were a drag, but on the positive side, our marketing business has performed exceptionally well for us this year and some of that, while we're expecting some continued growth and particularly we're hopeful we will have continued growth in the PJM region going forward, as a result of the Ironwood acquisition, I think you can expect that our marketing results would retract a little bit going forward in 206. We had a pretty exceptional year in the current year and some of that is showing up in this quarter.

Maybe just shifting gears, one last question on Energy East. In terms of your discussions with shippers, are any shippers looking to potentially defer the timeline beyond 2020?

Rob, it is Paul Miller here. No they're not. 2020 is our current schedule and the shippers remain supportive of Energy East as we navigate this alternative terminal design configuration, and at this point we continue to march toward the 2020 timeline.

Steven Paget, FirstEnergy.

When looking at corporate restructuring, how do you look at the efficiency of TransCanada to determine when and if restructuring is needed?

I think as all businesses evolve, Steven, and they grow, you have to continually look at how you do business and determine whether or not that is a solid enough platform to move forward. We built all of our businesses substantially over the last, say, ten years. We have been focused primarily on growing those business and as you put them together and you acquire things and you add new things in, you band aid together business processes.

I think one of the best examples I would give you is with respect to the project that we undertook last year on redesigning our underlying IS systems. We had put together a group of systems that we called best of breed, we attached them together with Excel spreadsheets and those kinds of things and a lot of the vendors that supplied those systems to us were coming to the end of their ability to continue to support them. So we moved ourselves to an SAP platform, which gave us greater efficiencies, consolidated the number of systems that we had outstanding and had them talking to each other. And I think that is analogous to the rest of the business and the business processes in the way that the decisions are made in the organization.

As we look at where we want to go over the next ten years, there's going to be substantial growth and we need to have a more efficient processes put together that better relate to the business that we are today. It is an evolutionary thing, there is no, aha moment, that you say this is the time but as things have evolved here, we have determined that this is the time to move to greater accountability within the business units, as they become large operating units by themselves. If you look at the size of any one of those businesses, they are large mid-cap to large-cap companies on a standalone basis.

They need to have their own processes of making decisions and streamlining such that they can deliver the best bottom line results possible. That is the direction that we have moved here recently and I would say that, so far, what we have seen in terms of the systems that we changes, process we changed have streamlined things, they have made things more efficient and better quality decisions are coming from them.

That is the primary focus of what we're trying to do. An obvious benefit to both our company, our shareholders, but as well as our customers, is with greater efficiency is lower costs. We will be able to pass some of that through to both our shareholders and to our customers. We're still getting into the details of how big those numbers will be and we will share those with both our customers and shareholders in the coming weeks and months.

Alex, if I may direct my question to you, you are back in filling the COO role, a role that has not been at TransCanada for a little while, and what are your goals in your first year in that chair?

It's an interesting question, I might build off a number of the comments that Russ just talked about. These businesses are getting very large and they take a significant amount of oversight and I think certainly from my perspective, what I hope to be able to do is work with the respective presidents. I think my primary focus is to ensure that this reorganization that we are in the middle of, that it gets completed as expediently as possible, and that the end result is that we are a more efficient organization, a more profitable organization, and we deliver better and cheaper service at the same quality to our customers.

So I think that is going to be a real focus over the next year. I think another thing we are sort of hoping of doing, this is that at least certainly hope that I have is, that we can by doing this we should be able to free up a little bit more of our CEO's time to focus on some of the week strategic issues that are pressing on the organization.

Ben Pham, BMO Capital Markets.

I just wanted to go back to Ironwood and just looking at the US power business year-to-date for the pricing condition. Doesn't that concern you with respect to some of your modeling assumptions for Ironwood going forward? I'm not sure you highlighted the capacity payment portion or not.

Yes, I guess a couple of comments I would make, it is Bill. On the Ironwood projections going forward that we release when we release the information on the acquisition, one thing that I would highlight that may not have been obvious is that there is a fair operating synergy that we see with the acquisition. We've got other plants in the region, we have got a strong complement of staff, so we think there is some opportunity there to improve our operating efficiency with that facility versus the cost that we have seen historically spent at it.

So that is one thing. The overall market circumstance in PJM is we think quite favorable. There is a retirement potential or conversion potential with a lot of the coal facilities that are coming under increased pressure with low gas prices and higher compliance costs that they are facing.

This is going to drive some transformational change in that market and we think Ironwood is well positioned, not only in respect of that, but also relative to supporting our ongoing and we have been in operator in PJM for some time without an asset in our marketing and trading business, so we're pretty comfortable. We understand that market well and are confident that we will be delivering good results from that facility.

If I may, a question on the Bruce refurb negotiations. I am just wondering if you can comment on some of the big picture discussion points that need to resolve to get those book ends closed and I'm also curious how dependent is the timing on an updated long-term energy plan in Ontario?

I will start with the latter half of your question.

The basis of the negotiations that continue, that are being led by Bruce Power are really driven by the late 2013 long-term energy plan. Any possible update that the government or the ISO may be doing in regards to their long-term energy plan, we cannot speculate on what that would be, but we remain confident that the nuclear element in Ontario is an extremely important part of their long-term plan as they continue to transform their power mix to an emissionless or a GHT emission-free power portfolio so we are confident that that will continue. As for the specifics of the negotiations, I won't comment on that. As I said, Bruce Power is actively in the midst of that and we remain optimistic that there will be a positive outcome in that regard, but just hang tough on it.

Steven Paget, FirstEnergy.

One more question if I might, on Grand Rapids. What is the status of the larger line, the 42 inch line? Will the start of construction on the bigger pipeline wait on higher volumes or is it going ahead given the deal with Keyera?

Hi Steven, it is Paul Miller here.

So as you know, Grand Rapids is a dual pipeline system and it's a 20 inch into a 36 inch and we're under construction proceeding with the smaller 20 inch line for initial service in crude oil late in 2016 and are expecting the 20 inch to be running at near capacity. So we're going to stage the 36 inch into service to immediate increases in the market demand for the transportation.

The Keyera deal doesn't really impact the 36 inch crude line. The Keyera deal revolves around the 20 inch pipeline in between Heartland in Edmonton and we're proceeding with the construction of that as well, having entered into this joint venture to provide the extra dealing with supply to the Grand Rapids shippers.

Rob Hope, Macquarie.

Just a quick follow up on Steven's question. Can you remind us the breakdown between the $1.5 billion cost for the 20 inch line and the 42 inch line and when your internal projections have the larger lines entering service?

Rob it is Paul Miller.

So the total cost of the dual system is approximately $3 billion and that is the 100% and TransCanada share is one half of that, the $1.5 billion, but I will speak to in regard to the 100% interest. The breakdown is approximately equal with the 20 inch line being slightly less than 1.5 billing and the 36 inch line being slightly above $1.5 billion. We are targeting the 20 inch line to be in initial crude oil service here by late 2016 and the 36 inch line into 2017.

There are no further questions from analysts at this time.

(Operator Instructions)

Ashat Dutta, Plattes.

I just had two quick questions. When are you expecting to hear from Secretary of State on the letter that was sent yesterday please?

We do not have a timeframe.

The second question is, with the new liberal government Russ, how have things changed for companies like you which are planning to build new pipelines? Will you see a realignment of focus? Just wanted to see the crystal ball from your side.

I wouldn't expect any major changes. The resource industry in Canada, specifically the oil and gas industry in Canada, is extremely important to Providence and Alberta, but probably more important to our country and developing market access for those resources, whether they be crude oil or natural gas, are critical component of maximizing the value of those resources for all Canadians.

I believe that at the strategic level, that we're going to continue to pursue market access as we have done historically. We have been at this for the last 60 years and I fully expect that we will be at it for the next 60 years. Demand continues to grow, supply is abundant, and the need for efficient, modern, safe transportation remains critical. I don't think that changes of government change that, it hasn't in the past and I wouldn't expect that it does in the future.

Nia Williams, Reuters.

I wanted to ask you if, with the (inaudible) KXL review, will you be redoubling assets and putting all of those into Energy East?

No, both of these projects are extremely important to our shippers and we'll put the appropriate amount of resources to move them both to regulatory approval.

As a quick follow up, does asking for a pause in KXL show that you are expecting Obama to refuse the project?

No.

Rebecca Penty, Bloomberg News.

I actually have two related to Keystone XL. Russ, I'm hoping you can elaborate on your point earlier in the call, you mentioned that a pause would help TransCanada when overall approval for the pipeline, and I'm hoping you can spell out exactly what you mean about how having a pause in the State Department review helps.

Secondly, I am just wondering, there has been some discussion where I am about the idea that if TransCanada had had a rejection that the company would have to write off some of its investment in Keystone XL, and if you guys are successful in getting approval through this pause, that you could avoid that. I'm wondering if you could just speak to that issue.

On the first question, just remind me of the first question as I listen to the second question?

I'm a little long-winded, I was just wondering if you can elaborate on how exactly putting a pause on the project helps you when overall approval?

The process in Nebraska will take some time. We know it will take some time. It is at the federal level, there is not much left to be done. The final environmental impact statement was complete, but we do recognize the potential root changes in Nebraska and the process there may change things going forward.

So our view is, as it has been in the past, we have been through this process before, upon our filing within the Nebraska Public Service Commission, we believe that was the right thing to do at the current time to let us get through that process to determine what changes may arise out of that process and then ensure that those changes our best incorporated into the final decision by the Department of State. So it just makes sense at the current time to allow that regulatory process to unfold.

On the second part of your question, this project remains very much in demand by our customers. The production in the western sedimentary basin has grown quite substantially, it's probably up 1.5 million barrels since we made our application, somewhere between 1 million and 1.5 million barrels. A lot of those barrels are now moving via rail, a lot of them still moving to the Gulf coast.

The Gulf coast is still importing some 4 million barrels a day, 2.5 million barrels of those are heavy oil barrels. It is logical to connect the large, a lot of them US multinational players, but most of them having refinery interest in the Gulf coast aligning their large investment that they've made in the current oil stands in their production with the refining capacity in the Gulf coast and that hasn't changed at all. With respect to your second question, we have indicated how much we have spent on the project to date, but our strategy is still on gaining approval and delivering on the demand that those customers have to get this critical infrastructure built and efficiently and safely move their product to market.

Daniel Wallach, Beaumont Texas Enterprise Newspaper.

I was wondering whether you had any contingency plan to reroute around Nebraska so you might gain approval from the State Department and ultimately from a US President, whether it is this one or the next one, and how much more delivery can be made to the Gulf coast terminal that already exists in Nederland, Texas?

I'm not sure if I understand the second part of the question, but I will try the first. Maybe Paul might be able to help me out with the second one.

On the first part of the question again, the route through Nebraska, we have looked at several routes for this project through the various iterations of environmental review that have taken place, both in Nebraska and at the State Department level. The route that we currently have chosen is one that was selected after consultation with the Nebraska Department of Environmental Quality and several meetings with landowners and open houses that we conducted with stakeholders along that route.

That route was subsequently approved by the Governor of Nebraska, so we think it is a sound route that makes sense, so that is the route that we think has the greatest potential of achieving approval by the Public Utilities Commission in Nebraska. The final environmental impact statement from the department indicated that the route would have minimal impact on the environment and again, from a landowner perspective, we have been able to negotiate a large percentage of voluntary easements along that route. I believe that we are in excess of 90% today for easements along that route in Nebraska.

We have a minority of landowners that are outstanding and we would expect that as we go through this process we would be able to obtain a higher level of voluntary easement agreements with the landowners along that route. That is our current process and as we said, that process takes time, which is the rationale for pausing in the process to let us get our work done and work with the stakeholders in Nebraska to come to a mutually agreeable route through the state. On the second one, I'll pass that one to Paul.

Hello Daniel, it is Paul Miller here. Keystone XL is an 830,000 barrel per day pipeline and we have set aside 100,000 barrels per day to pick up US-produced crude out of the Williston Basin and in the Montana, North Dakota area, which means about 70,000 barrels per day of capacity originating out of Canada. But those origination points will vary depending on the receipt demand. But ultimately it would have the capacity to move the entire 830,000 barrels per day down to the US Gulf coast again with the origination point being split between Canada and the United States.

What if the State Department does not grant the pause?

I think that is speculative at this point in time and again, I would just reiterate that the demand for the pipeline doesn't dissipate with the negative decision. The need to move this crude oil safely between supply location and market location doesn't go away. What we have seen is in the delay process we have just seen, those producers find alternative means of getting their production to markets and those means have been, I would say, imposed greater environmental risks, imposed greater safety risk on the public; and at the end of the day, it makes sense to replace that inefficient and more costly and potentially more harmful transportation with the safe modern pipeline.

Rob Gillies, the Associated Press.

Russ, there's wide expectation that Obama would reject the pipeline. Is that not play in as a factor for delaying, asking for a pause in this and hoping for a Republican administration potentially to approve it?

As we have said many times, we have tried to stay out of the politics of the situation and focus on the things that we are capable of doing and can control. That is the regulatory process. We have worked very hard for seven years to try to keep our head down and work our way through every twist and turn and every additional request through the regulatory process and we are intent on continuing to do that until we get the regulatory approval and we have solved people's issues through that process. There are things we can control, there are things we can't control and obviously, we're focused on those that we can.

That is a political reality that you have to manage and this request last night certainly is a way of managing that political reality right?

Again, our focus is not on getting on involved in politics at all. We have a regulatory process in Nebraska that is going to take us time to prosecute and we need the time to make that happen, so we have requested that time.

Just one more, the fact that prices for oil are so low, you are saying that the pipeline still remains viable, right?

Absolutely. What we know is that oil prices won't stay low forever, but even if you think of when we made this application in 2008, the price of oil was $40 a barrel. The price of oil is $40 a barrel again today.

We have been through the market volatility of it being well over $100 a barrel and then back to $40 per barrel. That will, and I've been at this business for 30 years, and I have seen that cycle a number of times and I'm sure that I will see that cycle a number of times going forward. That said, the production has grown in Canada since we made that application well over 1 million barrels a day. Growth in the Balkan region of the United States has grown by a couple million barrels a day. I fully expect that those will continue into the future.

If you look at Canada even at the low oil prices with the investment that has been committed to, we'd see another 500,000 barrels a day of production growth between now and the end of the decade. All of that volume has to move to market and to date what we have seen is a huge increase in both loading capacity and railcar movement in order to move that product to market.

So, it is not like we are waiting for new production to come on to build these pipelines, the production already exists. It will just be shifted from less efficient needs of transportation to this pipeline. It is cheaper, it is more efficient, it's safer, it has less greenhouse gas emissions and so everybody is focused on making that happen irrespective of the current low price environment that we have.

The next question is from [Jenna] (inaudible) from [LePeje].

Have you asked for a meeting with the new government regarding the process in the NAB and Energy East?

Not at this time as we would wait until the new government is in place and (inaudible) are defined and we would then work to try to ensure that those folks understood our projects and our plan would be to work with them in whatever way was necessary to help them do their jobs in the future. That will take place in the coming weeks and months.

(Inaudible) promised to modify some practices of the NAB. Could that be more of a longer delay than 2024 for you guys and if there are changes, could it drive costs up more than $12 billion for energy?

I do not know the answer to those questions today but, as Alex pointed out earlier in the call -- I have been at this for 30 years and we have seen many changes in the regulatory process over that period of time. The company has always complied with those and found a way to meet -- what we see is an ever-changing and more stringent standard for the work that we do. We're actually leaders in trying to make that happen.

We work with the national energy board to try to constantly improve the standards and I suspect that if we go through another iteration of review, that would be positive and it will raise the bar and we will have to work through that process. No question these things cost more money going forward, but at the end of the day, if the result is a safer, more reliable set of infrastructure, then that make sense for us.

So you are not bothered at all by any changes that could apply to the NAB process in the near term?

We will work through all of those processes with both the national energy board and the governments as they arise.

Jeffrey Morgan, the Financial Post.

First of all, I wanted to ask whether or not you received any advice on how long the new regulatory application in Nebraska could take and could last, and whether or not it could last longer through 2016?

My understanding, Alex can jump in if I'm incorrect here, but my understanding is the stated timeframe by the commission is 7 months, but it can take up to 12 months.

Yes, I think that is correct.

Second question is on Energy East. I wanted to ask for your reaction to the meeting recently between Premier Notley and Premier [Harper] in Edmonton about the energies pipeline, both premieres restating their support.

I think it is, obviously a very important project for both provinces and for Canada so it is very encouraging to see the leadership of those provinces, stating their confidence and reiterating the importance for both their jurisdictions. I think that is positive for a project that is, as I said, critical to our nation, and it is going to require that kind of political vision to bring it to fruition.

Kelly Cryderman, The Globe and Mail.

I am just wondering how you avoid the decision to write the State Department and ask for a delay in the process, how you avoid that being a political matter just because the Nebraska process does not require you to ask the State Department to put a pause on the process as it proceeds. How do you respond to critics who say this is just kicking the can down the street to hopefully an administration that is more favorable to the project?

I think if you look through the department's state process in which they move from final environmental assessment to the next stages in the process, it doesn't make sense to move to those next stages in the process until you finish the routing in environmental review is our view, and again, that will be up to the State Department to determine at the end of the day.

But it is our view that the State Department process should not continue at the current time on its current path if there's new information that is going to be provided from a review in Nebraska. That is the way that it has been managed to date and the way that we are expecting it is going to be managed in the future.

If I could interject Sebastian, our conference coordinator, as we very much appreciate everyone's interest in the company obviously, as we are approaching 10:30 we have got time for one more question.

Lauren Krugel, Canadian Press.

With the new liberal government in Ottawa, I am just wondering if there is anything you can see Justin Troudeau and his team doing differently that the previous government didn't do that would help along the case for Keystone XL? Any clarity there would be helpful.

Again, once they are sworn in as the government, we will start to see what their policy and strategic platforms are and we will be able to make those assessments at that point in time. Our current plan, as I said is, on both sides of the border, is to continue to try to work through our regulatory processes to the extent that changes in government have an impact on those. We will work through those with those governments when they occur.

There are no further questions at this time I would like to turn it back over to Mr. Moneta.

Thanks very much and thanks to all of you for participating today. We obviously, very much appreciate your interest in TransCanada. To the extent you do have further questions, Lee and I will certainly be available on the investors side and James Miller and his team are available from a media relations perspective. Thanks again and we look forward to speaking to you soon.

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