TC Energy Corp (TRP) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2014 third-quarter results conference call.

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

Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2014 third-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 of Development; Karl Johannson, President of our Natural Gas Pipeline business; Paul Miller, President, Liquids Pipelines; Bill Taylor, President, Energy; and Glenn Menuz, our 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.

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.

(Caller Instructions)

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 and Exchange Commission.

And finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings; comparable earnings per share; earnings before interest, taxes, depreciation and amortization, or EBITDA; and 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. These measures are provided 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.

Thank you, David. Good morning, everyone, and thank you very much for joining us. I'm very pleased to announce today that our three core businesses -- gas pipelines, liquids pipelines, and energy -- all generated solid earnings and cash flow for the third quarter. Compared to the third quarter of 2013, we saw growing contributions from new assets such as Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico, offsetting weakness in the Western power prices.

Again, the solid quarter highlights the benefits of our diversified and growing portfolio of blue-chip North American energy infrastructure assets. For the third quarter, TransCanada reported net income of CAD457 million, or CAD0.64 per share. Comparable earnings for the quarter were CAD450 million, or CAD0.63 a share.

Comparable EBITDA was CAD1.4 billion, and funds generated from operations were CAD1.1 billion. Year to date, EBITDA and funds generated from operations versus 2013 are up 12% and 6%, respectively. Earlier today, our Board of Directors declared a quarterly dividend of CAD0.48 per common share for the quarter ending December 31, 2014.

During the quarter, we continued to grow our capital program, including announcements today of an additional CAD2.7 billion of organic growth in the NGTL system and CAD500 million of new Canadian Mainline facilities within the Eastern Triangle. This critical infrastructure is needed to transport growing volume of shale gas from both the Western Canadian Sedimentary Basin and the Marcellus to meet the changing demands of Alberta and the recent Canadian customers who want greater access to US supply.

In addition, last week we filed an application for our CAD1.5 billion Eastern Mainline Project that is part of our eastern -- Energy East application. This new project would bring additional gas to customers in the Toronto to Montreal corridor. I will talk a little bit more about that in a second, when I talk about Energy East.

These additions to our Canadian pipeline infrastructure network are expected to generate growth in earnings and cash flow beginning in the 2015 to 2017 time frame. In total, we now have an unprecedented CAD46 billion of commercially secured projects backed by long-term contracts or cost-of-service business models. Over the remainder of the decade, completion of this blue-chip portfolio of contracted energy infrastructure projects is expected to generate significant growth in cash flow, earnings and dividends, and significant long-term shareholder value.

I'll turn the call over to Don in a moment, but before that I wanted to provide you some updates on key projects that we continue to move forward. When we look at our CAD46-billion capital program, it's important to point out that that list includes approximately CAD13.2 billion, or about one-third of the portfolio, of smaller-scale, shorter-term projects that are expected to become operational between now and 2017/2018. This shorter-term growth will provide visible benefits to our shareholders over the next three years.

The list includes CAD5.1 billion of NGTL expansions, including the CAD2.7 billion we announced today; CAD500 million in further Canadian Mainline expansions, announced this morning as well; $2 billion for Mexican natural gas pipeline projects; CAD3.5 billion in oil projects and related facilities in Alberta; the $600-million Houston Lateral project; and power projects in Ontario, including the CAD1 billion Napanee plant and the CAD500 million of solar facilities. It's an impressive list, and one that we are working very hard to expeditiously move through the regulatory process to construction [and into] operation.

During the quarter, we had some very important announcements related to that group of projects. On October 9, the Alberta Energy Regulator issued a permit approving the majority of our application to construct and operate the CAD1.5-billion Grand Rapids pipeline project.

And in July, the Alberta Energy Regulator approved our application for the CAD800-million Northern Courier pipeline project. Construction started this quarter, and the pipeline is expected to be in operation in 2017. In addition, we acquired three more Ontario solar facilities for CAD181 million, which closed in late September. All of those facilities are underpinned by 20-year contracts with the Ontario Power Authority.

We also continued to advance our portfolio of large-scale projects, including Energy East. As many of you are aware, we filed our formal project application for Energy East just days ago. The detailed 30,000-page filing was a result of more than 18 months of environmental studies, engineering work, and public consultation. It is the most comprehensive application ever filed in our Company's 63-year history.

Not since the construction of the Canadian Mainline has there been an opportunity to connect the vast resources of Western Canada to Eastern markets. It's an opportunity that will benefit all Canadians, whether it's the 14,000 jobs that this very large CAD12-billion project will support each year of development [and] construction, or the close to CAD8 billion in government tax revenues provinces will receive over its life.

Energy East will help the country eliminate the need for Eastern Canada to import most of its 700,000 barrels a day that it consumes each day. The refineries in Quebec and New Brunswick can count on security of supply that a dedicated pipeline provides to support and maintain local jobs that pay strong wages and improve the long-term competitiveness of those facilities.

The 1.1-million-barrel-a-day Energy East pipeline has 20-year contracts for approximately 900,000 barrels a day. It should begin delivering crude oil to Quebec and New Brunswick in late 2018. Once operational, the pipeline is expected to generate CAD1.7 billion in EBITDA on an annual basis.

The project involves converting 3,000 kilometers of pipeline along the Canadian Mainline system to crude oil service. This will make better use of the Mainline's overall capacity. In order to ensure there is sufficient capacity to meet the needs of our Eastern Canadian Gas customers, we also filed an application for the Eastern Mainline project on October 30. That CAD1.5-billion project will add about 250 kilometers of new natural gas pipeline and 600 million cubic feet a day of capacity through the Canadian Mainline in the Toronto to Montreal corridor, where demand is the strongest, and we can provide greater access to affordable new gas supplies from the northeast United States.

To be perfectly clear, the eastern portion of our Canadian Mainline serves two distinct markets: Canadian customers and export customers. We are only proposing to repurpose the pipeline capacity for Energy East that is currently dedicated to export markets that no longer contract for that capacity. Capacity that is contracted for, and serves, Canadian markets will not be impacted.

As I have said many times before, TransCanada remains committed to ensuring Ontario and Quebec customers will receive the gas they need to heat their homes. We have done this for more than 60 years, and that will not change. The combination of Energy East and the Eastern Mainline project will result in lower costs for transmission customers in Quebec and Ontario.

In fact, we estimate the combination of these projects will result in our Mainline customers saving more than CAD950 million over the next 15 years. This is achieved through a CAD500-million contribution by TransCanada and Energy East oil shippers, and the removal of approximately CAD1 billion of rate base, along with the associated operating, property tax, and abandonment costs associated with those transferred facilities. All of that is detailed in our 30,000-page filing.

Moving to Keystone XL, an expected decision on a Presidential permit is on hold, as the US State Department has stated it wants to better understand the legal proceedings in Nebraska. The Nebraska Supreme Court heard oral arguments on September 5 related to the appeal of the lower court ruling by the Attorney General of Nebraska as to who has the right to approve the Keystone XL route in Nebraska, the Governor or the Public Service Commission. A decision is expected late in 2014 or early 2015.

On September 15, TransCanada filed its certification petition for the Keystone XL project with the South Dakota Public Utilities Commission. This certification confirmed that the conditions under which the project's construction permit was granted are as strong as they were before, and in some cases, even stronger. And we are awaiting a timeline to be released to understand when this process will come to conclusion.

September 19 marked the 6th anniversary of the filing of our application to build the final phase of the Keystone pipeline system. Inefficiency and delays in making a decision on Keystone XL have driven up the costs of the project significantly. We now estimate the cost of the project to be in the range of $8 billion. Project costs are shared by TransCanada and its shippers: 25% to TransCanada, 75% for our shippers, to a certain threshold amount. Anything above that amount is shared 50/50.

As of September 30, 2014, we had invested approximately $2.4 billion in the project. While these delays will result in higher tolls, our shippers, both the US and Canadian producers and refiners, remain solidly behind Keystone XL, and their support has not wavered over the past six years. This critical piece of energy infrastructure is vital to US energy security, and the State Department has highlighted in its [final] environmental impact statement, Keystone XL will support the creation of over 40,000 jobs. All we need is an approval to make that happen.

Moving to gas again and the west coast, we continue to advance our west coast LNG projects that are proposed to transport natural gas from British Columbia and Alberta to BC LNG export terminals. Two weeks ago, the BC Environmental Assessment Office issued an environmental assessment certificate for the Coastal GasLink project. As anticipated, the certificate was issued with a number of conditions, all of which we believe we will be able to satisfy. This is a very significant milestone for the Coastal GasLink project and for TransCanada.

TransCanada also submitted applications to the BC Oil and Gas Commission for permits to build and operate the Coastal GasLink pipeline. Regulatory review of those applications is progressing on schedule, with permit decisions expected in the first quarter of 2015. A final investment decision for Coastal GasLink is expected in early 2016.

On the Prince Rupert Gas Transmission project, our team continues answering questions related to the regulatory applications with the BC Environmental Assessment Office and the BC Oil and Gas Commission. Decisions on those filings are expected near the end of 2014. In addition, work continues towards refining the capital cost estimate for final investment decision on the Pacific Northwest LNG project, which they have indicated they will make close to the end of 2014.

In early October, we announced the sale of TransCanada's remaining 30% interest in the Bison natural gas pipeline to TC PipeLines, LP for $215 million. The sale of Bison further underscores our commitment made last November to drop all of our remaining US natural gas pipeline assets to the Partnership on a more frequent basis. This plan provides the needed capital to fund our capital program. In addition, the strategy allows us to retain operating control of key infrastructure; at the same time, gives TC PipeLines, LP visible, high-quality growth for the future.

The remaining US natural gas pipeline assets to be sold into the Limited Partnership include a 30% interest in GTN; a 45% interest in Iroquois pipeline; a 62% interest in the Portland Natural Gas Transmission System; and a 54% of Great Lakes; and 100% of ANR. In total, those assets are expected to contribute close to [$]500 million of EBITDA in the 2016 time frame.

So, in summary, all three core businesses performed well in the quarter, highlighting the benefit of diversification, and solid contractual and regulatory underpinning in each of our businesses. Contributions from new assets such as Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico continue to grow. We continue to add high-quality projects to our capital program, with the CAD4.7 billion of new projects added in the quarter, including the CAD2.7 billion of organic growth in NGTL expansions and the CAD500 million in the Canadian Mainline.

This infrastructure is necessary to meet the growing needs of customers of our natural gas pipeline systems in both Alberta and in Eastern Canada. We advanced the Energy East project by filing NEB applications for both the CAD12-billion project and the CAD1.5-billion Eastern Mainline project. To help fund these growth plans, we announced, in October, the sale of TransCanada's remaining interest in Bison.

Today, our capital program sits at an unprecedented CAD46 billion of commercially secured, high-quality North American energy infrastructure projects. I can tell you that we remain focused on our strategic plan of, firstly, maximizing the value of our existing CAD57-billion asset portfolio; second, bring that CAD46 billion of capital through approval to operation and to cash flow; thirdly, we will continue to create a high-quality portfolio of new opportunities; and lastly, we'll maintain and build on our financial capacity in order to fund that growth.

Simply, our strategy is to continue to do what we have done for the last 14 years. Since 2000, TransCanada has delivered a 15% annualized return to its shareholders, including an average increase in dividends of 7% per annum. We are well positioned to continue to grow cash flow and earnings and dividends well into the next decade.

TransCanada understands the value that our shareholders place on stability and growth in cash flow and dividends, and is wholly committed to ongoing enhancement of shareholder value, including the continuous evaluation of the Company's approach to capital allocation. We look forward to sharing additional detail of those plans with you in our upcoming investor day in Toronto in mid-November.

That completes my prepared remarks, and I'll now turn the call back to Don for more details on our quarterly results. Over to you, Don.

Thanks, Russ, and good morning, everyone.

Before I review our third-quarter results in detail, I would like to highlight a few key messages. Our core asset base generated solid third-quarter results, with CAD3.5 billion of new assets making notable contributions. We secured CAD4.7 billion of new Canadian regulated natural gas pipeline investment opportunities that are expected to enhance near-term growth in earnings and cash flow. And finally, we remain well positioned to fund our CAD46-billion portfolio of commercially secured projects, with predictable and growing cash flow, a strong balance sheet, and access to [multiple] attractive external funding sources.

Moving to our consolidated results shown on the next slide: Net income in the third quarter was CAD457 million, or CAD0.64 per share, compared to CAD481 million, or CAD0.68 per share, in the same period in 2013. Excluding unrealized gains and losses from changes to various risk management activities, comparable earnings in the third quarter of CAD450 million, or CAD0.63 per share, were in line with results for the same period last year. New contributions from the Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico, strong Bruce Power results, along with higher realized capacity prices at US Power, were offset by reduced earnings from Western Power.

Turning to our business segment results at the EBITDA level, our natural gas pipelines business generated comparable EBITDA of CAD750 million in the third quarter of 2014, compared to CAD684 million for the same period last year. Canadian gas pipelines comparable EBITDA of CAD557 million increased CAD38 million compared to 2013, principally due to flow-through items on both the Canadian Mainline and NGTL, which do not have an impact on net income. Net income from the Canadian Mainline was CAD6 million lower compared to the same period last year, as a result of a lower average investment base, as well as carrying charges owed to shippers stemming from a positive toll stabilization account balance.

NGTL's net income increased CAD4 million in the third quarter to CAD61 million, due to the positive impacts of a larger average investment base and a higher allowed return on equity of 10.1%. Our recently filed settlement with shippers on the NGTL system will see the current allowed return on equity and capital structure extend another year, through 2015. The one-year deal also includes a continuation of 2014 depreciation rates, and a mechanism for sharing variances above and below a fixed OM&A expense amount.

US and international natural gas pipelines comparable EBITDA of CAD188 million increased CAD16 million compared to the third quarter of 2013, primarily as a result of the commencement of contract revenues being recognized from the Tamazunchale Extension, and the positive impact of the stronger US dollar.

Moving to liquids pipelines, the Keystone pipeline system generated CAD275 million of comparable EBITDA in the third quarter. This represents an CAD82-million year-over-year increase, and is the result of the Keystone Gulf Coast Extension, which was placed into service in January, along with the favorable impact of the stronger US dollar.

Turning to energy, comparable EBITDA was CAD387 million in the third quarter, compared to CAD410 million for the same period last year. The CAD23-million decrease was the result of a combination of factors. Western Power comparable EBITDA declined CAD38 million due to lower realized power prices. Despite robust pricing in July, strong coal fleet availability, and new wind generation led to weaker prices overall. The third-quarter average pool price was CAD64 per megawatt hour compared to CAD84 in the same period last year.

Equity income from Bruce Power increased CAD6 million to CAD111 million in the third quarter, compared to 2013, primarily due to lower depreciation and operating expenses at Bruce A, partially offset by recognition of higher lease expenses. Unit 5 at Bruce B is presently undergoing a planned two-month maintenance outage that began at the beginning of October. The remaining seven units of Bruce Power are currently operating at full power, and no further maintenance outages are planned for the remainder of the year.

US power comparable EBITDA increased CAD13 million in the third quarter compared to last year, primarily due to higher realized capacity prices in New York, and the favorable impact of the stronger US dollar. In late September, the 972-megawatt unit 30 at Ravenswood experienced an unplanned outage as a result of a problem with the generator associated with the high-pressure turbine. The cause and extent of the necessary repairs is currently under investigation. Insurance is expected to cover the cost of repairs and lost revenues from the outage, net of deductible. As a result, the outage is not expected to have a significant impact on earnings. Natural gas storage comparable EBITDA of CAD3 million was down CAD6 million compared to the same period in 2013, due to lower realized storage spreads.

Now turning to the other income statement items on slide 19: Comparable interest expense rose CAD69 million in the third quarter to CAD304 million from CAD235 million in 2013. This increase was primarily due to interest charges on recent US dollar debt issues, higher foreign exchange on interest denominated in US dollars, and lower capitalized interest. As I have highlighted in the past, exposure to US dollar income is largely offset with US-dollar-denominated interest expense and financial derivatives, the net impact being that currency movements are not expected to have a material impact on earnings over a rolling 12-month-forward period.

In the third quarter, CAD57 million of interest was capitalized to assets under construction, compared to CAD80 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 Keystone XL, and other liquids and LNG-related pipeline projects.

Comparable interest income and other in third-quarter 2014 rose CAD33 million compared to the same period in 2013, primarily due to increased AFUDC related to our rate-regulated projects. These include Energy East and our Mexico pipelines, which qualify for rate-regulated accounting. 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 the strengthening US dollar on translating foreign-currency-denominated working capital balances.

Comparable income tax expense for third-quarter 2014 increased CAD58 million versus the same period last year, due to higher pre-tax earnings, changes from the proportion of income earned in higher tax jurisdictions, as well as higher flow-through taxes on Canadian regulated pipelines. Excluding Canadian regulated cost-of-service pipelines, the consolidated effective tax rate in 2014 is expected to be approximately 27% to 28%.

Net income attributable to non-controlling interests increased CAD8 million compared to the same period last year, primarily due to the redemption of TCPL Series U preferred shares in October 2013 and Series Y preferred shares in March 2014. Preferred share dividends of CAD24 million were CAD4 million higher in third-quarter 2014, as a result of the CAD450-million Series 9 issue completed in January 2014 at TransCanada Corporation.

Now, moving on to cash flow and investing activities on slide 20: Cash flow remains solid, with funds generated from operations of approximately CAD1.1 billion in the quarter, and CAD3.1 billion year to date. Capital expenditures were CAD853 million in the third quarter, driven principally by Mexican pipelines, NGTL system expansions, Energy East, and construction activities on the Houston Lateral and Tank Terminal. Equity investments of CAD66 million in the quarter reflect activities related to the Grand Rapids pipeline and Bruce Power. Finally, three additional solar facilities in Ontario were acquired at the end of September at a cost of CAD181 million.

Now, turning to slide 21, our liquidity and access to capital markets remains strong. At September 30, our consolidated capital structure consisted of 40% common equity, 5% preferred shares, 2% junior subordinated notes, and 53% debt, net of cash. We had CAD698 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.

On October 1, we closed the sale of our remaining 30% interest in the Bison pipeline to our limited partnership, TC PipeLines, LP, for cash proceeds of $215 million. The Bison transaction advances our previously stated commitment to sell the remainder of our US natural gas pipeline assets to the Partnership on a systemic basis.

The US gas pipes that continue to be directly held by TransCanada are expected to generate approximately $480 million of EBITDA in 2016 beyond. Dropping the remainder of these assets into the LP in a conveyer-belt-like approach, on a more sizable, frequent basis, into the LP is considered the optimal approach for providing us with significant cash proceeds to help fund our capital program. This will also serve to enhance the size and diversity of the Partnership's asset base, and position it with visible, high-quality future growth going forward.

As Russ highlighted, our strategic asset footprint continues to provide us with tremendous opportunities to invest capital in our core businesses. Today, we have approximately CAD13 billion to CAD14 billion of secured, small- to mid-sized projects that are expected to be placed into service over the next several years, providing strong visibility to future earnings and cash flow.

We remain well positioned to fund this suite of shorter-cycle projects with predictable and growing internally generated cash flow from our three core businesses and senior debt consistent with our A grade credit rating. Other sources of subordinated capital, including further LP dropdowns, preferred shares, and hybrid securities, will also form part of our financing strategy. Beyond these funding sources, as we progress our CAD29 billion of large-scale capital projects, we will also consider additional portfolio management activities, the introduction of partners, selective use of project financing, and reinstatement of our dividend reinvestment program from treasury, as alternatives to large-scale common equity.

In closing, the Company produced solid third-quarter results, which highlight the benefits of our broad base of blue-chip pipeline and energy assets. CAD3.5 billion of new assets have been placed into service in 2014, and are now contributing to earnings and cash flow, including the Keystone Gulf Coast Extension, the Tamazunchale Extension, as well as various expansions of the NGTL system. An additional CAD180 million of newly acquired solar facilities is set to add to this list in the fourth quarter.

Furthermore, we continue to make significant progress in advancing our CAD46 billion of commercially secured projects, and are well positioned to finance the capital program that lies ahead. This industry-leading portfolio of critical energy infrastructure projects is expected to generate significant growth in earnings, cash flow, and dividends for our shareholders 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 over to the conference coordinator, we will take questions from the financial community first, and once we've completed that, we will then turn it over to the media. With that, I'll turn it to the conference coordinator for your questions.

(Operator Instructions)

Paul Lechem, CIBC.

Thank you. Good morning.

Just with regard to the NGTL system expansions you've announced this morning, in the press release, you mentioned 3.1 Bcf a day of volume relating to firm receipt service. I was wondering if you can give us some details around that. Where is the 3.1 Bcf a day of demand coming from? Is any of that specifically related to any of the LNG projects on the west coast? Is any of this 3.1 Bcf a day at risk if some of these projects don't proceed?

Hi, Paul. It's Karl. I could say that all this receipt volume is what we call organic growth. It is not contingent on any LNG projects going forward. It is meant to go into our overall system and through our net system and to various markets on our system, so it wouldn't be contingent to any LNG going forward. I would say that, of our announcement here, that 3.1 Bcf a day is made up of about 21 different receipt sites and projects, so it's well diversified through our system and from various receipt points.

Okay. Thank you. Switching gears to Keystone XL, just a couple of related questions, maybe just on the cost increase. You mentioned in the presentations that there's a threshold in terms of the split, 75%/25% split. Can you give us some detail around when that threshold -- at what level does that switch over to 50%/50%?

And then secondly, given the increase in the costs now, can you give us some sense of what it will cost on a per barrel basis from Alberta down to the Gulf Coast if you shipped through Keystone XL versus through Energy East and then on a tanker down to the Gulf Coast? Can you give us some sense of how those two measure up? Thank you.

Hi, it's Paul Miller here. In regard to the first question, with this new cost estimate for Keystone XL, we have rebased our toll at the new cost estimate and the 50%/50% sharing begins at this point. In regard to the tolls down to the Gulf Coast, we haven't published those tolls yet. I can tell you, though, relative to the other opportunities, relative to the other land-based opportunities, Keystone XL toll at this capital cost remains competitive. It remains under the other land-based opportunities and it remains under the opportunities to Energy East and then moving down to the Gulf Coast.

Okay. Thank you.

You're welcome.

Thanks, Paul.

Linda Ezergailis, TD Securities.

Thank you. Just a follow-up question on the new Keystone XL cost estimate. Can you give us a sense of either what your assumed in-service date is embedded in cost, or how much contingency you have provided for further delays in a presidential permit, i.e., what is the risk of that cost increasing further? And you can you just give us an update on your expected returns from the project? We could probably calculate it, but you obviously have better sense of that than we do?

Sure, Linda. It's Alex. I would say right now where we are in the process, as Russ said, we're really in a bit of a waiting mode on Keystone XL, so we've really limited capital and any growth in capital costs right now. I don't expect a lot of impact. In that number that we quoted, we do have a contingency that we think is reasonable to get the project done. As for returns, we're still in that range that we've quoted in the past.

Okay that's helpful. With respect to capital costs, the CAD1 billion drop versus prior plan in 2014, is that a shift to 2015, or some sort of a change in scope? Maybe you could provide some context?

Hi Linda. It's Don here. Firstly, it's fairly across the board. There's no specific project that you can pin down with the CAD1 billion move. It is largely a time shift, as we just look at different construction profiles and regulatory approval processes.

Okay, that's helpful. Thank you.

Thanks, Linda.

Carl Kirst, BMO Capital Markets.

Thank you. Good morning, everybody. Maybe if I could start, Russ, I'd like to get a little bit better clarification on the Eastern Mainline project. In your prepared remarks, you said that this is specifically going towards -- to replace capacity to the export market to the US market, so not necessarily to address some of the concerns the utilities have. I'm just trying to get a better sense of what perhaps some of the contentious issues are still out there and what still needs to be overcome?

The two issues that have been raised are, firstly, will there be sufficient capacity available to meet the needs of the Eastern Canadian consumers? And the answer to that is yes, and like I said, we're committed to doing that. And that the costs that are borne by our Eastern Canadian gas shippers should not be negatively impacted by the Energy East, and again, we have said that that won't occur.

We've committed to that. In fact, in our filing, the way that we've structured it, with the Eastern Mainline project and the contributions and whatnot that we have made, they are all detailed in the filing, results in a savings through to 2030 of about CAD950 million. So we believe we have satisfied those questions.

Maybe I can just provide some clarity on that -- my comment that this is export capacity. The eastern delivery area of our system has a capacity of 3.2 billion cubic feet a day. What we've said that we're going to do is we're going to remove about 1.2 billion cubic feet a day of that capacity, and via the Eastern Mainline project, we will add back 600 million cubic feet a day. So essentially we're reducing the capacity from 3.2 billion to 2.6 billion.

Historically, that system has been used probably 50%/50%, I would say, by export gas shippers and domestic gas shippers. Domestic shippers for contract to the tune of about 1.6 billion cubic feet a day, and in a recent times, they've increase that contractual level to about 1.8 billion cubic feet a day, and slightly greater than 1.8 billion cubic feet a day. So we feel totally comfortable at 2.6 billion of installed capacity, that we'll have ample opportunity to meet domestic load.

On the flip side, export contracts have fallen from about 1.6 billion cubic feet a day that we in 2007 to about 700 million cubic feet a day, today, so we have lost about 900 million cubic feet a day of export contract and it is that export contract capacity that we are converting, that 900 million. We have taken about 600 million of it and we've converted it to Energy East.

So our view is simply there is sufficient capacity to meet the needs. We've held several open seasons and we'll continue to converse with our customers to ensure that we understand their need to make sure that the capacity is available. But certainly our objective is to make sure that we right-size our system and to optimize its usage for all the users of it. If we optimize the usage for all users, certainly unit costs come down, and unit cost reductions means everybody saves and we think that's a good thing, and as I said, that is detailed in our application.

Helpful. Very helpful color. Thank you. Just to be clear then, the Eastern Mainline is basically an integral, or it's incorporated into the larger Energy East filing. It's not going to have its own procedural schedule?

It will have its own procedure. They are two separate applications that are tied together. That was a (technical difficulties) request from the National Energy Board to have the application separate but together, if you will.

Excellent. And then one clarification, just on the cost of Energy East, and certainly appreciate the CAD1.7 billion guidance on EBITDA. Historically, we've talked about the CAD12 billion of Energy East being what you might call the external capital. Is it correct we should still be using CAD1 billion of assets transference from the Mainline, and then it looks like, with the Eastern mainline, there may be an additional CAD250 million contribution. So should we think of Energy East CAD13.25 billion and that CAD1.7 billion of EBITDA -- are those the apples-to-apples numbers we should think about?

That's a good way to look at it, Carl. In addition, there's another CAD250 million in there because there's a CAD500 million contribution, but essentially that CAD250 million will be absorbed by TransCanada and won't go into the Energy East rate base.

Understood. Then last question, if I could, just for Don, and Don, as you try and manage here the portfolio, and just thinking the potential lumpiness here for if Petronas moves forward, if XL moves forward, et cetera. As you get some larger projects happening, and perhaps in light of the current volatility we're seeing in the equity markets today, how comfortable are you with the equity requirements being, perhaps, if we have a three-year project, for instance, that the equity requirements can be done over that period of three years, or if we see all of a sudden CAD10 billion-plus worth of projects, we need to somehow raise all that equity, be it synthetic or otherwise, very quickly, upfront? And I didn't know if that was something you could give more color to?

Yes, it's a good question. We take some comfort from the fact that pretty much the entire portfolio is contracted or cost of service regulated assets, so pretty low volatility assets. I'll walk you through the thought process here, starting with the small- to mid-size projects, which totaled probably CAD12 billion to CAD13 billion.

We do have debt capacity within the constraints of the A credit rating. We pointed to the amount of assets we're going to vend into the Pipe LP, and then we'll look to preferred shares and hybrid securities to probably about 12% of our capital structure, they're around 7% right now. So that part of the portfolio looks eminently financeable with those instruments.

As we move to the bigger, more binary outcome projects here, a couple of points to note there. For the LNG projects to the West Coast, we would consider project financing of those. They are very tightly commercially constructed and that's something that we would potentially be able to attract a different source of capital for those projects. That something we would definitely look at for those.

As the balance sheet grows, we'll again chew through the cheaper sources of capital. Eventually, we'll get to a point where we'll either have to sell something, introduce partners, or issue equity. At that point in time, we'll weigh the various costs of those various alternatives. We're not emotionally against selling assets, but again it would be weighed against those other two potential sources of capital. We receive a lot of inbound calls from parties looking to co-invest in these projects, so we think partners are certainly something that is in the league, introduceable into all of the large projects before we start getting to equity.

Equity, we look at in two forms. Firstly would be turning on the dividend reinvestment program. Generally, we believe we could attract CAD100 million to CAD125 million a quarter of common equity by turning the DRIP on. That lines up very nicely with a long-tail construction program, where money is going out the door on a continuous basis, but we've got equity capital coming in.

In terms of large-scale equity, we would put that at the bottom of the list, and again, it's really somewhat dependent on how many of these goes and what time frame they go into. Not the clearest of answers here, but that is our thought process as we look at this. We view it as a high-grade problem to have, if many of these did move forward in the same time frame. They are large dollar figures, but again given the very solid cash flows and blue-chip energy infrastructure qualities of all of them, we think the capital is available there.

Excellent. Thanks so much for the color.

Thanks, Carl.

Matthew Akman, Scotiabank.

Hi. Good morning. A few questions on the power business. One is just on the US power business. I noticed that your capacity payments continue to trend upward, but there was -- and production is also trending upward, but there was a reduction in EBITDA. I'm just wondering if that's primarily due to compressed margins at Ravenswood for the energy portion of the revenue?

No, the answer to your question, in this quarter anyway, would relate more to -- there is some timing differences with some of our marketing transactions that affected US power, where, given the structure of the way some of our retail transactions are put together, flat pricing is applied to customer loads, and then we can end up getting movement of revenue between quarters. That's primarily what's going on with Q3 in the US.

So is that a more normal quarter or was it abnormally high in prior quarters?

I'd say it was a little abnormal in light of some of the success we had with some of our load marketing businesses, in terms of--

Okay.

We put some term on in the load side that pushed things out for a couple of years.

Okay, thanks for that. Moving to Alberta, the acquisition of a little bit more PPA through Genesee, I'm just wondering strategically what's behind the thought process. Is that a bet that Alberta power prices are bottoming out here? Is it just enhancing the overall presence in Alberta and the strategic direction in Alberta generally, given the reduction in price we have seen?

You are correct with those reasons as to why we found this attractive. We're always active in the market. This opportunity only comes up periodically. We believe that the market in Alberta is, at the moment, suffering a little bit from some very good performance on the fleet overall. As Don mentioned in his remarks, wind generation has been high, so yes, one could conclude that we may be looking at some structural lows here right now for the markets, so not a bad time to be a buyer.

Good. Okay, thanks. Then my last question on power is, you have had good success in Mexico on pipeline. Is there any interest in the Company in doing contracted power in Mexico, as well?

Yes, for sure. We, as you know, as I just highlighted, we have had good success overall with our program in Mexico and that continues. We are looking, indeed, at the opportunities that are on the horizon on the power side.

Okay. Great. Thanks. Those are my questions.

Thanks, Matthew.

Andrew Kuske, Credit Suisse.

Thank you, good morning. Just a question, maybe directed to Russ, on Alaska, and just an update on what's going on there. There is a few things to ask about Alaska. Just to the extent that you've really done a lot of new things versus just really knocking the dust off of some of the old files, because this has been in the portfolio in one way or another for the last 30, 35 years. So just give us some perspective on that and then really the momentum behind this, at this point in time?

As you point out, we've been at this for some time in Alaska, and it transcends a few careers here. We've had a few folks retire that started their career working on the project and actually ended their project with another tour on the project. It is taken some time. What we know about Alaska is that the gas is produced is associated gas with the oil.

It's in the neighborhood of about 7 to 8 Bcf a day, today. It's reinjected into the gas cap. At some point in time, the gas/oil ratio gets to a point where it's uneconomic to produce or to continue to reinject the gas and produce the oil in that way. We're not the reservoir owners or developers, so we don't know when that exact date is going to arise, but our feeling is, is that it's some time into the next decade and that's why we're seeing the continued push to want to redirect that gas to market. As I said, it's being produced today; it just needs to be redirected to market.

The most positive thing about the recent developments in Alaska is that we have all parties working on the same project in the same direction. There is ourselves, obviously, but probably more importantly, the three core producers ConocoPhillips, ExxonMobil, and BP, as well as the Alaska government, all working and rowing in the same direction on a single export project. That's what gives me confidence, that we are rowing in the same direction. This is the first time in my history at the Company working on the project, that we're all working in the same direction.

Obviously, the capital costs are enormous, but given that the resource itself, you could think of it as having almost a CAD0 cost, so you look at the competitiveness of that product into the LNG market on a unit basis. If you build a large-scale pipeline and liquefaction facility and your resource cost is essentially CAD0, you're in a pretty competitive situation and that's the way that producers are looking at it.

The key issue remains, what are the fiscal terms under which that gas is going to get produced and that's why I'm saying, as we talk about taxes and royalties and gain -- things that aren't in our purview necessarily to be involved in. But we understand that those conversations are active between the producers and the state, and again, all rowing in the same direction, because if you get those right, that will give the producers the confidence to make the capital investment and bring that product to market.

So it's out there into the next decade, but we are, as a group, spending money on the feasibility and I'm confident that, at the end of the day, that gas will go to market and it will go through a pipeline. So our guess is early to mid-decade that we will have a pretty good handle on when that is going to happen.

Okay, that's helpful. And just as a follow-up to that, if we look back about 10 years ago when Conoco and BP were pursuing the Denali project, and you were aligned with Exxon, now that you're all under one roof, so to speak, that gives you a lot more confidence that something happens early in the next decade?

That's a hugely significant development, that everybody is moving in the same direction on this project.

If I can just get one other question in, on a warmer climate. Any interest in electricity transmission in Mexico?

Transmission in Mexico is not something that we've been focused on at the moment. We have, over time, looked at a few opportunities to enter that space in Canada, and a couple in the US that you may recall, but it's a highly competitive space and not something that we have historically done. We are not adverse to that side of the power business, but we would look carefully at it before jumping into that.

Okay that's very helpful. Thank you.

Robert Kwan, RBC.

Good morning. If I can just follow up here, just on your power outlook in the Genesee PPA, I'm wondering, I'm sure you probably don't want to get specifically into price, but is it fair to say you bought the PPA materially below the curve instead of just going out in the market and buying back 100 megawatts of hedges?

Yes, to your point, I'm not sure I want to get into specifics of the pricing approach that we took, but I would just suggest that you can assume that purchase price was competitive with the markets, with the caveat that, as you know, there's a fair bit of thinness in the forward market in Alberta, so there's people taking views on that three-year outlook, including ourselves.

Okay, Bill, just with that three-year term, obviously, you are seeing upside from current levels and even what the curve might imply. Can you just talk about the timing over that three-year period as to how you see the price evolving? Is it something where you think that the price expectation right out of the gate into 2015 is too low or do you think it's more something that will evolve as we chew through Shepard capacity?

A couple of things. As Don mention, and as I reiterated in my prior answer, the Alberta market at the present time has been plagued with some really excellent performance out of the current fleet. That drives a lot of the future volatility. We're somewhat bullish on 2015 being above certainly where it's currently trading. I'd leave it at that and say we're comfortable with the Genesee acquisition that we made and we hope that it will be a good transaction for our overall portfolio.

Okay. And if I can just ask one more, shifting to Energy East. There's been some articles here just around some local opposition in and around the Cacouna part of the project. Just with the Saint John deepwater port, how integral is Cacouna to Energy East, as you see it?

It's Alex. I will take a shot at that, and Paul might want to jump in. Obviously, Quebec Marine terminal was very integral to our service offering in this project and it makes a lot of sense for a lot of our shippers, depending on where their ultimate markets for that oil are.

Yes, Rob, it's Paul Miller here. I don't have much to add. As we've said in the past, we anticipate to serve both the Eastern Canadian market, as well as the export markets. The Quebec location at Cacouna is an ideal port to access some of those nearer and so it's a real economic opportunity for our shippers to move their crude out of the Cacouna port. From a total integrated perspective, both Saint John and Cacouna provide tremendous opportunities for the shippers and we'd look to move forward with both facilities.

Just to be clear, it is an integral part of our service offering. We have customers that have signed up to that location. The folks in the Cacouna would like to see a terminal built there. It will a create a significant amount of economic activity, as well as probably draw on further economic activity. So, it's something that all parties want to happen.

That said, it is like with any part of the project, if it has a material negative impact on the community, in this case on the beluga whales, once we collect the information, if that's determined to be the case, then we just won't be able to do it in that way and we will have to figure out how we are going to do this project in a different way. So it's integral, but at the end of the day, our objective is to build a project that is acceptable and workable for all parties and we're committed to that, not just in Cacouna, but right across the pipeline.

That's great. Just to be clear though, is that just because of the way you set up the terminal in Saint John, the idea is that you would just be bottle-necked with the VLCCs coming in there, that you wanted to have that extra port to put smaller boats in?

No, Rob. It's Paul Miller here. The way we will operate our pipeline is we will run full line rates effectively to the Cacouna port while we are loading Cacouna and we will run full line rates to Saint John. So when you asked specifically about the Saint John, it's a great departer port. It would have the capacity to facilitate full line rates and full movements through VLC. So I don't anticipate there would be any bottlenecks under that scenario.

Okay. That's great. Thank you.

Steven Paget, FirstEnergy Capital.

Thank you and good morning still. Mainline earnings are down 8% year-to-date, but EBITDA is up 15%. How much of the incremental EBITDA flows through to cash flows?

Steven, this is Karl. Most of that EBITDA increase is flow-through items. It's mainly because of the overcollection that we have had this year, in short-term adjusted account and the taxes paid on that, so most of it does flow through to our customers.

Okay. Thanks, Karl. This question, I'm not sure who it would be for, but TransCanada has had success as an active participant in the Alberta power market, but its long-term presence in the market -- your long-term presence will decrease considerably within just over six years when all the PPAs are expired. So how should we think of TransCanada's future in Alberta Power? Are you considering active measures to increase your Alberta presence in the next decade, or increase beyond the PPAs?

What I could tell you, Steven, is Alberta is a core market for us. We do have a pretty significant generation position that we have built outside of the PPA, so that will be core and endure. I would say that we see the reduction in the coal fleet as an opportunity to add new generation to this marketplace going forward.

We have a lot of experience in both the market itself, from a commercial perspective, as well as from a technical perspective, and a construction perspective, so we think we are well-positioned to compete as the market transitions from what is primarily a coal-fired fleet today, to whatever that is going to look like in the future. We suspect that there's going to be a fair bit of gas added to that portfolio. So we continue to look for opportunities to do that, but under the right structures and at the right time, those things will make sense to us. It's our strategic intent to continue to be a long-term player in the Alberta business.

Thank you, Russ. If I could follow-up. Would that Alberta market need to have capacity pricing or would you build into the merchant market as it now is?

Those are all dependent upon how things unfold over the coming years. Certainly, we have built some capacity in this merchant market, but it has been limited. If the marketplace gives us the right signals, we would go down that path. But the question looms as to what will the market structure be in order to make that transition from the coal-fired base load that exists today to whatever that future is going to look like, and I think that's an element of government policy that has yet to be written.

What I can tell you is that we have participated in both structured markets and what I call open markets, we are in New York, New England, Quebec, Ontario, Alberta, and various other markets in the Pacific Northwest and the like. To understand all the different structures, all of them have their pros and cons, and we'll look at those structures and determine how best to invest under those structures.

Thank you, Russ, Karl. Those are my questions.

Thanks, Steven.

Ted Durbin, Goldman Sachs.

Thank you. The first question here is just coming back to BC LNG and thoughts around, whether it's Prince Rupert or Kitimat, moving to FID here, particularly given the lower oil price environment. We did see one of the other Prince Rupert developers, looks like they pushed out their development time frame. I'm wondering if you could just talk about that?

Sure, it's Alex. If you look at the two projects we're involved in the Petronas project in Prince Rupert and the Shell consortium in Kitimat, Petronas is -- I think they are very focused on moving to an FID in the relatively near future. Certainly, we're going to have done our work to allow them to be in a position to make an FID decision around the end of the year. I expect that, that decision will be made either around there or shortly thereafter. Obviously, we believe that we're going to have all the permits in place then or about then for that project to go ahead.

I would say the same thing with our Coastal GasLink project with Shell. It's probably following about, give or take, about a year behind, but once again, we think we'll be in position for them to make those decisions. In terms of the competitiveness of the project, both of those counterparties benefit from being at the front end of this process and being among, if not the most advanced projects, and certainly from our perspective, they still look to be very commercially viable.

Okay, great. Second one just on Energy East, now that you have the filing in there, can you just walk us through the time frames that we should be thinking about, in terms of the milestones that you expect to hit from a regulatory perspective?

Sure. Here is the simple way to think about it. Now that we have filed, the regulator, the NEB, now has to come back with a determination that the filing is complete. There is no legislated time frame for that, but probably, historically, it's been anything from two to five months. Then once they determine that the filing is complete, they are mandated by legislation that they have to make a decision within 15 months. Then it goes to the Cabinet, the Federal Cabinet, and they have a short period in which to make a decision, so right now we are probably thinking sometime around mid-2016 to get through the entirety of the regulatory process.

Very helpful, thank you. If I can get one more in, just thinking about, you have really highlighted in your language recently, you are evaluating your push to capital allocation. I'm wondering if you could just expand on that. You've talked about it, Don, but especially as we look at the dividend, here as we move into year-end, is usually when you consider it. I'm just wondering if you can balance dividend growth versus potential equity needs and financing needs given the large capital program?

The dividend is generally looked at by the Board in the February time frame. We wouldn't constrain dividend growth to backfill equity for the capital program. Our thought process going into this cycle of dividend consideration would be, in looking at some of the advances we have made on some of our core assets here, the Mainline is in pretty good shape here, ANR is fully contracted, we have got the Gulf Coast completed to Texas. That will form part of our thinking.

As we announce another CAD4.7 billion of near-term projects today, that gives us greater visibility on the near- to mid-term growth outlook for earnings. Those are the elements that we are looking at right now, but don't look for us to constrain dividend growth just to hold back equity for the capital program.

Great. I'll leave it at that. Thank you.

Thanks, Ted.

Faisel Khan, Citigroup.

Thanks, good morning. I wonder if you could just elaborate a little bit more on the -- you talked about the conveyer belt of MLP dropdowns into TC PipeLines. What's the pace of that conveyer belt? Is it a Bison dropdown every quarter or how are you looking at that?

It's Don here. We don't have any specific time frame on that. What we have indicated is, and part of our thought process here is, what's the use of proceeds? Keeping the conveyer belt running for visibility and putting these assets into the LP, and thirdly, capacity limits at the LP, as well.

So again, we are trying to extract cash for our capital program from this strategy here. As the LP gets bigger and bigger, it's a CAD5 billion enterprise right now, we're looking at probably putting CAD5 billion of assets into there, so we have to bear capacity limits in mind, if we are going to extract cash from that.

So probably look for a couple of transactions a year of size here. That's not hard and fast in terms of a rule. It could be more, it could be less, but it will be somewhat driven by our needs for the capital program.

Okay. That makes sense. And then just you talked about other sources of equity capital as you potentially move forward with your lumpier projects. I was wondering, one of the things that I didn't hear, is that you could drop down the existing Keystone Oil Pipeline into the MLP, so I am just wondering, is that completely off the table or is that also a potential source of capital, if you move forward with these larger lumpier projects in the next few years?

I was remiss in not including that. Based on probably CAD750 million of US-based EBITDA on the base Keystone system and a multiple on that of 11, 12, 13 times, you're probably looking at something of CAD8 billion to CAD10 billion that we could extract in terms of cash to fund the capital program. That debt is still something we would consider.

Okay. Understood. And then just on the Mainline, the Eastern Triangle expansion, roughly CAD475 million of expansion, what are the contract terms on that short-haul capacity? Or is it just rolled into the Eastern Triangle rates?

It's Karl here. This is in response to the LDC settlement and two open seasons that we have held. The contract terms of both of those open seasons were 15 years.

Okay. Great. Understood. Then also on the NGTL expansions, the CAD2.7 billion you announced, what are the durations on those contracts and how do those work into the rates, too?

Those contracts are generally between eight and 10 years.

Okay. Understood.

I would also highlight, Faisal, it does also fall under, if you will, the Canadian cost of service approach, if you will. Karl has highlighted for you the contract terms associated with it, but the expectation would be that the capital would form part of rate base and a return of it on capital would be captured over time, obviously.

So that's the 10% ROE?

That's right. Currently 10.1% on 40% equity.

Got it. Okay. Great. Thanks for the time. Appreciate it.

Robert Kwan, RBC.

Just wanted to ask a quick follow-up on the Ravenswood outage. The insurance proceeds, at least your expectation of what you're going to get back, is that going to cover as well the lost revenue associated with the reduction in the UCAP on the rolling basis over the next -- as we go forward here?

Yes, Robert. It's Bill here. The insurance coverage that we have in place for Ravenswood includes both physical damage and a business interruption element, so answer would be yes, subject to, as Don mentioned, the deductibles that would apply there.

Right. But to be clear, is it lost -- but it's a combination of both the lost revenue while the unit is completely out and then it will also include the rollback in on the U count?

Yes that's right. That's the business interruption element of it. It does cover that lost revenue. Yes.

Perfect. Thank you.

We will now take questions from the media.

(Operator Instructions)

Nia Williams, Reuters.

Hi, there. Thanks for taking my question.

I just wanted to ask, looking at US, it looks like the Republicans are going to make some major gains and possibly even recapture the Senate. Do you think that will help with Keystone XL's cause in any way?

I don't know. We've -- since 2008, the Keystone project has enjoyed the support of the majority of Americans. We continuously poll, it's 25 polls that we've track since that point in time. The number appears to be two-thirds on a continuous basis. From a Congressional perspective, we enjoy the majority of support in both the House and the Senate.

The project in the national interest, so what we would hope is a decision gets made somehow or another, as quickly as possible, and we can get on with construction and providing job opportunities for thousands of Americans that want to go to work. I can't really predict what the outcome of this particular election might have on Keystone. Just suffice to say that we are supportive of any process that can help advance the decision on the project, given that the environmental review is completed, and at this point in time, we're just sitting waiting for someone to say go.

Okay thanks.

Chester Dawson, The Wall Street Journal.

My question. Just a quick question in regard to the pipelines to the West Coast for the potential LNG projects, which you addressed earlier. What I'm interested in knowing is, I'm wondering how close are you to finalizing the route, particularly for the Prince Rupert project, which will be used for the Petronas facility, especially if they are that close to making a decision, how close are you to finalizing your route? And how many First Nations do you still need to deal with in order to finalize that?

We have a proposed route that is been filed with the provincial regulator. We are, I would say we're in the process now where we're considering relatively modest route changes in a response to requests of our stakeholders, including aboriginal groups. We have, on the PRGT right-of-way, we are presently negotiating with give or take around 19 or 20 First Nations and I would describe those negotiations as going well.

We have a productive dialogue with them. We certainly have great deal of respect for their position and I'm personally pretty confident that over the next few months, we're going to reach agreement with the vast majority of those groups.

Chester, maybe to be clear on what we're hoping to get on the PGRT route, is there is two main assessments that we've asked for, one is from the BC Environmental Assessment Office, and we would expect them to issue an environmental assessment certificate, probably some time, we're hoping, towards the end of this year, early next year. And the second one is permits from the BC Oil and Gas Commission, and again, we expect the regulatory process to conclude around that same time in Q1, so we're trying to be in a position where we will have all of our approvals or regulatory approvals, our key regulatory approvals for Petronas to make their final investment decision.

Okay, great. Thank you.

Sheela Tobben, Bloomberg.

Hi there. Good afternoon. My question is basically regard to your Energy East project, it would seem fairly recently there have been some Canadian crude exports from Montreal. With that in mind, and since you have noted that you have some 20-year contracts in place in support of Energy East, I was wondering if you can shed some color, maybe detail about whether you are in any talks to supply crude to foreign buyers through the Energy East project?

Any term contract you might have in place, or maybe in discussions? And if not, if you cannot you talk about who those companies are, maybe you can tell us what those destinations are for those supplies via the Energy East project? Thank you

Hi Sheila, it's Paul Miller here. We provide the transportation service for our shippers. Our shippers include producers and refiners. So our obligation is to accept their crude at various receipt points and deliver it to the delivery points, which include Montreal, Cacouna, and Saint John. From that point, it's up to the shipper to determine the use and the further movement of that crude oil, so we are not in any discussions with any foreign purchasers of crude oil, and thankfully, we're not in any discussions with any domestic purchasers of crude oil. We leave that to the producers.

Okay. Thank you.

Faisel Khan, Citigroup.

Hi, thank you. Just a quick question.

This is Blake Clayton at Citi. Our question is regarding what have been the incremental costs associated with Xcel, getting up to that $8 billion figure. If you could just provide some color around what additional costs have come into play there?

Sure, it's Alex. I would say that, that difference, my recollection was, that previous number that we had talked about and had held stable for many years was $5.3 billion, give or take. And as we said at the time, two or three years ago, we were going to hold off on updating, we just didn't see the value in updating it quarter-to-quarter. We think now it probably is worthwhile to give some color on that; hence, we came up with the $8 billion.

Just to give you an idea, I would say that the difference between those numbers is really overwhelmingly the presidential permit delays. If you break it down, we go into this process, we probably anticipated somewhere in the region of about a two-year regulatory process, in line with what we saw for our base Keystone project. We're now in a six to seven-year process, so you can imagine the costs that are associated with that regulatory process.

On top of that, there's also, just frankly, at the time we proposed this project, it was a pretty good market for constructing pipeline projects. It's a lot tighter market now in North America. We've had six or seven years of inflation. So you add those two together and you get the lion's share of the difference between the $5.3 billion and the $8 billion. And just one other comment I would say on that is, the losers in this whole process ultimately are consumers of energy in North America, because that's who ultimately bear the cost for these delays and the cost impacts.

Thanks that's all for us. Appreciate it.

No problem.

Thanks.

Elsie Ross, Daily Oil Bulletin.

Just a fast question about the proposed Merrick Mainline. You think it's going to be delayed into the first quarter of 2016, the application to the NEB. What's -- is there a special reason for that?

No. There's no particular reason for that. We're just right now doing our fieldwork and prepping the application, and that's really the reason for the revised date. This is the project -- the Merrick project is the project that Apache and Chevron are sponsoring. There has been some questions over the status of that, but I can tell you that the word we're getting from the project proponents is go full steam ahead, so the delay has nothing to do with the ownership issues or potential for Apache to leave the partnership. It's more of just from a process perspective on the application.

Okay. Thank you.

Geoff Morgan, Financial Post.

Good morning. Thank you for taking my question.

My question is with regards to your announcement this morning of the Canadian Mainline system and development of natural gas infrastructure for collaboration between Gaz Metro and Union Gas. How has this announcement improved relations with those two companies in light of the fact that they were looking for cheaper gas for their customers?

It's Karl. What I can say is the facilities we're putting in place really are a result of the collaboration that we had with all the Eastern Canadian LDCs a couple of years ago, when we did the original LDC settlement. We have been to the Board now and the Board has adjudicated this and we are waiting for a decision, which should come before the end of the year. So the LDC settlement, as you may recall from previous discussions, it was a settlement -- a design that we open up more capacity in our Eastern Triangle for Marcellus and Utica and other sources of natural gas into the system.

In conjunction with that, the LDCs agreed to certain provisions, like a no-bypass provision for 15 years and to pay the full cost of service of that system. So from that perspective, the relationship with the LDCs on that particular settlement and adjudication was very, very good. As you can see right now in the newspaper, we may have some difference of opinions on energy use with them, but certainly with our construction, to fulfill our obligations to bring in more diversity of supply in the Eastern Triangle, it's going pretty good with our LDC partners there.

Thank you.

There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Moneta.

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

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