TC Energy Corp (TRP) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to TransCanada Corporation 2013 first quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr. Moneta.

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2013 first 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, President of Energy and Oil Pipelines; Karl Johannson, President of our -- Natural Gas Pipelines; 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 it can be found in the investor section under the heading events and presentations.

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone 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 for 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 for 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'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 under US GAAP, and are therefore to be considered non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David, and good afternoon, everyone, and thank you very much for joining us. Earlier this morning, you heard me talk about our ongoing commitment to developing North America's energy future with safe, reliable energy infrastructure that will generate superior returns for our shareholders. Over the next three years, we expect to complete CAD12 billion of projects that are currently in the advanced stages of development. They include the Gulf Coast Project, Keystone XL, Keystone Hardisty Terminal, the initial phase of the Grand Rapids Pipeline, the Tamazunchale Extension, the acquisition of nine solar projects, and the ongoing expansion of the NGTL System. We've also secured an addtional CAD13 billion of projects that are expected to be operational in 2016 and beyond. They include the Coastal GasLink and Prince Rupert Gas Transmission projects, that would move natural gas to Canada’s West Coast for liquefaction and shipment to Asian markets; the Topolobampo and Mazatlan Gas Pipeline projects in Mexico; completion of the Grand Rapids and Northern Courier oil pipeline project in Northern Alberta, and the Napanee Generating Station in Eastern Ontario. All of these projects are secured by long-term contracts, and therefore TransCanada expects them to generate predictable and sustained earnings and cash flow. In addition, our CAD25 billion capital program -- in addition to our CAD25 billion capital program, we continue to advance other opportunities including the Energy East Pipeline, which would transport crude oil from Western Canada to Eastern Canadian markets.

Our three business segments performed during well during the first quarter. TransCanada reported net income of CAD446 million or CAD0.63 per share. This included CAD84 million or CAD0.12 per share for the 2012 higher allowed rate of return for the Canadian Mainline. Comparable earnings for the quarter were CAD370 million or CAD0.52 a share. Comparable EBITDA was CAD1.2 billion, and funds generated from operation, CAD916 million. The restart of Bruce Power Units 1 and 2, the return to service of Bruce Power Unit 4 in April, and the Sundance A unit this fall, along with higher allowed return on the Mainline, are all expected to have positive impact on our earnings in 2013. Today, our Board of Directors declared a quarterly dividend of CAD0.46 per common share for the quarter ending June 30, 2013. Don Marchand, our CFO, will provide more details on our financial results in a few minutes. Before that, I want to provide you some further detail on the advancements we have made on our capital projects throughout the last quarter.

We continue to make substantial progress on our Gulf Coast pipeline in Texas and Oklahoma. The CAD2.3 billion project is now 70% complete, and since starting construction last August, we have created jobs for 4,000 Americans who are building this pipeline. The demand for this project is clear. US production has been growing significantly in states such as Oklahoma, Texas, North Dakota, and Montana. Producers do not have sufficient access to pipeline capacity to move this production to the larger refining market at the US Gulf Coast. The Gulf Coast project will address that constraint, and allow US refineries to access lower cost domestic production. This pipeline will have an initial capacity of 700,000 barrels a day, and we anticipate it being in service by the end of this year. Construction of the CAD300 million, 76-kilometer Houston lateral to transport crude oil to Houston refineries expected to begin construction mid-2013 and be completed by mid-2014.

Moving to Keystone XL, the permitting process for the project has seen two key milestones achieved in the past number of months. In late January, Nebraska Governor Dave Heineman approved the reroute of Keystone XL through his state. The approval followed his lengthy and detailed review of the final evaluation report from the Nebraska Department of Environmental Quality. And on March 1, the US Federal Department of State released its draft environmental impact statement for Keystone XL. It noted that Keystone XL would have no substantive impact on global GHG emissions, would have minimal impact on the environment, and through the incorporation of 57 special safety conditions would result in the project having a degree of safety over any typically-constructed domestic pipeline system. Completing the draft supplemental environmental impact statement for Keystone XL was an important step forward to receiving the Presidential permit.

Public comments on the project are currently being reviewed by the State Department. This 45-day comment period ended four days ago. Once the Department of State completes its review, it will issue a final environmental impact statement, and then consult with the other government agencies during the national interest determination period before making a decision. The approval of the Keystone XL Pipeline system, the base system, was 21 months, and we are now into the 67th month of the Keystone XL approval process, and unfortunately, continued delays in permitting continue to have an impact on both our schedule and our costs. Based on our current assessment of timing of the permit, we would currently anticipate the pipeline could become operational in the second half of 2015. The project very much remains in the interest of the United States, and we remain confident that it will receive regulatory approval and be constructed.

In Alberta, progress on one of our key oil pipeline projects in Alberta continues. The necessary field work in Aboriginal and stakeholder engagement to allow us to file a permit for our Grand Rapids project with the Energy Resource Conservation Board in Alberta is nearly complete. The CAD3 billion crude oil project is a joint venture initiative with Phoenix Energy Holdings. The pipeline will be operated by TransCanada, and will transport crude oil and diluent between Northern Alberta and Edmonton. In addition to their 50% interest in the project, Phoenix has also signed a long-term contract to ship crude oil and diluent on the pipeline system. This combination of crude oil and diluent delivery in Alberta is quite unique, and positions our Company well to connect new supply from the emerging developments west of the Athabasca River.

We now expect to bring Grand Rapids online in multiple stages, with the initial crude oil delivery starting in mid-2015. The entire Grand Rapids pipeline should be completed in the first half of 2017, with the full system having a capacity of up to 900,000 barrels per day of crude oil moving south, and 330,000 barrels a day of diluent moving north. We expect to file an application with the ERCB in the second quarter of 2013. Grand Rapids will increase TransCanada's presence in oil transportation in Northern Alberta, building on our announcement last summer of the Northern Courier pipeline system. That CAD660 million project was initially proposed as a 90-kilometer pipeline that would transport bitumen and diluent between Fort Hills mine site and the Voyageur Upgrader located north of Fort McMurray. The Fort Hills Energy Limited Partnership has indicated that current plans for the project have not changed, and as a result of their recent decision to cancel -- as a result of their recent decision to cancel the Voyager Upgrader project, necessary field work in Aboriginal and Stakeholder engagement is nearly complete, allowing us to file a permit application with the ERCB. We expect that to file that application in the second quarter of 2013.

An important step forward was taken on April 15 with respect to converting a portion of the Canadian Mainline from gas to oil. TransCanada commenced a binding open season to obtain firm commitments from interested parties for the pipeline to transport crude oil from Western Canada to Eastern Canadian markets. The Energy East project involves converting 3,000 kilometers of the Mainline, and constructing up to 1,400 kilometers of new pipe. Subject to the results of the open season, the project will have a capacity to transport as much as 850,000 barrels a day of crude oil, greatly enhancing producer access to markets in Eastern Canada. The open season follows a successful expression of interest and subsequent discussions with prospective shippers. Following the completion of the open season, if successful, TransCanada intends to proceed with the necessary regulatory applications for approvals to build the pipeline. We expect an in-service date to be in late 2017.

TransCanada is beginning Aboriginal and stakeholder engagement and field work as part of the initial design and planning work for this project. The open season will close on June 17th. Interested parties would submit binding bids for transportation capacity crude oil from Western receipt points to delivery points in Montreal, Quebec City, and Saint John, New Brunswick. Eastern Canadian refineries import approximately 700,000 barrels a day, much of that higher priced oil based off Brent prices from Saudi Arabia, Nigeria, Libya, and other locations. The project would support the competitiveness of Eastern Canadian refineries with lower priced Western Canadian oil, and the jobs those refineries provide obviously being beneficial to Canadians in that region. The Energy East project, if approved, is expected to generate significant employment, tax, and investment benefits for all communities on the pipeline, as the pipeline crosses those communities.

Turning now to gas. During the first three months of this year, NGTL place approximately CAD340 million of pipeline projects into service. We have an additional CAD300 million of facilities that have been approved by the National Energy Board, with in-service dates planned for late 2013. The NEB has also recommended approval of the Chinchaga lateral, a CAD100 million project with a planned in-service date of early 2014. In addition, we recently applied for another CAD60 million of new facilities, and as mentioned in January, we continue to prepare our regulatory applications for the expansions in the BC, estimated to be between CAD1 billion and CAD1.5 billion to accommodate the Prince Rupert Gas Transmission Project.

On March 27, 2013, the NEB issued its decision on our application to change the business structure, and terms and conditions of service for the Canadian Mainline, including tolls, for 2012 and 2013. We, along with the National Energy Board, have recognized that our tolls and services need to change to meet the competitive forces in the marketplace. The Board accepted several of our proposed changes, but rejected other critical components of our restructuring proposal. The NEB moved to a multi-year, fixed-toll structure for long-term services, and in addition, the Board provided TransCanada with significant discretion for pricing non-firm and discretionary services. Although we don't agree with the decision, we are trying to work within it. Our R&D application will seek clarification and change of certain elements that allow us to work within the decision, rather than undo the decision. That filing will be made in the near future.

In early January, we were selected by Progress Energy to design, build, own, and operate the proposed CAD5 billion Prince Rupert Transmission Project. That pipeline would transport natural gas primarily from the North Montney gas-producing region near Fort Saint John to the recently announced Pacific Northwest LNG export facility in Prince Edward, near Prince Rupert, British Columbia. We are now working to initiate the environmental assessment process through the filing of the project description. That will be submitted to the British Columbia Environmental Assessment Office and the Canadian Environmental Assessment Agency in the second quarter of 2013. This is the second major natural gas pipeline proposed to Canada's West Coast for TransCanada, following our earlier announcement of the CAD4 billion Coastal GasLink pipeline project.

The project team is currently focused on community and landowner, government, Aboriginal and First Nations engagement, as it advances the project through the regulatory process with the BC Environmental Assessment Office and the Canadian Environmental Assessment Agency. NGTL is developing plans for its upcoming open season to provide delivery service to Vanderhoof, BC on the Coastal GasLink pipeline. That open season is expected to occur in the second quarter of 2013. If approved, the Prince Rupert Gas Transmission Project and the Coastal GasLink Project would together add more than 1,400 kilometers to TransCanada's Western Canadian natural gas transmission systems. We expect both projects to be in service near the end of the decade.

Turning now to energy and Bruce Power. The availability percentages for Units 1 and 2 increased through the first quarter of 2013. These units are now able to operate at full power. However, as Units 1 and 2 have not operated for an extended period of time, they may experience slightly higher forced outage rates and reduced availability percentages in 2013 than we would expect them to deliver in the longer term. Bruce Power returned Unit 4 to service in April -- on April 14, 2013, after completing upgrades which began in August of 2012. It is anticipated that this investment will allow Unit 4 to operate until at least 2021. Bruce currently has all eight reactors online, producing in excess of 6,000 megawatts of electricity. This is the first time in over two decades all eight reactors at Bruce have been simultaneously operating.

In addition in Ontario, in late 2011, we agreed to buy nine solar projects with a combined capacity of 86 megawatts from Canadian Solar Solutions for CAD476 million. All of the power produced will be sold under 20-year contracts with the Ontario Power Authority. We expect to close the acquisition of the first three of these projects by mid-2013, for a total cost of CAD175 million. Subject to regulatory approvals, we expect to acquire the other six projects later in 2013 and 2014.

So in conclusion, TransCanada has captured significant opportunities for growth, based on the enormous need for new and improved energy infrastructure in Canada, the United States, and Mexico. We are also exploring ways of building off our existing footprint, in order to maximize the value of our assets and improve the efficiency of our operations. The scope of this growth is truly unprecedented in the history of our Company, and touches all areas of our business. In the last three years, we have placed CAD13 billion of new projects into service. In 2012, we secured CAD16 billion of new projects, bringing our total secured capital projects to CAD25 billion to be completed by the end of the decade. We remain confident in our ability to continue to grow earnings, cash flow, and dividends, as we complete that capital program, and benefit from an anticipated recovery in natural gas and power prices, and recapture other value-creating opportunities. I'll turn the call over to Don, to provide some additional details on our first quarter 2013 financial results. Don?

Thanks, Russ, and good afternoon, everyone. Before discussing our first quarter results, I'd just like to highlight a few key messages. First, all three of our business segments generated solid results in the quarter. Second, we continued to progress our CAD25 billion portfolio of commercially-secured projects with the advancement of the Gulf Coast project, the Tamazunchale pipeline extension, ongoing expansions on our NGTL system, and the closing of the public comment period on Keystone XL's draft supplemental environmental impact statement, all of which will serve to further diversify the Company's portfolio, and contribute to sustainable earnings cash flow and dividend growth in the future. Third, as Russ has already discussed, we have achieved a significant number of other milestones to date in 2013. These include receiving the NEB decision on our Canadian restructuring proposal as it pertains to the Mainline, Bruce Power now operating as an eight-unit site with the return to service of Unit 4, and the launch of the open season that is currently under way for our Energy East Project. And finally, we remain well positioned to fund our current capital program, as well as pursue other growth initiatives.

Now moving to our consolidated results. Net income attributable to common shares in the first quarter was CAD446 million or CAD0.63 per share. Our first quarter results include CAD84 million or CAD0.12 per share related to 2012 for the NEB decision that was received in the period on our Canadian restructuring proposal. Excluding this and certain other minor amounts, comparable earnings were CAD370 million or CAD0.52 per share, compared to CAD363 million or CAD0.52 per share for the same period last year. Higher contributions from the Canadian Mainline, Bruce Power, and US Power were offset by lower contributions from US natural gas pipelines and Western Power.

I will now briefly review the results in further detail at the EBITDA level for each business segment, starting with natural gas pipelines. The business segment generated comparable EBITDA of CAD746 million in the first quarter 2013, compared to CAD725 million for the same period last year. The CAD21 million net increase was the result of a few items. Canadian gas pipelines EBITDA of CAD497 million increased CAD31 million compared to the same period last year. The improvement was primarily due to a higher contribution from the Canadian Mainline, as a result of the NEB decision on our Canadian restructuring proposal in which the NEB approved, among other things, a return on equity of 11.5% on an income and equity ratio of 40%, compared to the last approved return on equity of 8.08%. Earnings from ongoing expansions on the NGTL system also had a positive impact on Canadian gas pipelines in the quarter.

Conversely, our US natural gas pipelines continued to experience headwinds during the quarter, resulting in a CAD12 million year-over-year decline in EBITDA. Decreased revenues in Great Lakes, due to lower tariff rates and uncontracted capacity, as well as higher costs at ANR associated with services provided by other pipelines, continued to have an impact on our results. Partially offsetting declines at Great Lakes and ANR were higher short-term and interruptible revenues at Portland, which occurred as a result of weather-related events as well as other supply disruptions in the region. Overall weakness in certain US pipelines, due to lower revenues and higher operating costs, is expected to continue. We do, however, anticipate this business will recover over the longer term, as our assets adjust to the changing market conditions and pipeline flows.

Turning to oil pipelines. Keystone generated CAD186 million of EBITDA in the first quarter. The CAD12 million of incremental EBITDA versus first quarter 2012 was due to increased revenues as a result of higher contracted volumes, and the impact of a positive adjustment to the final fixed tolls on committed pipeline capacity, which came into effect in July 2012. Business development costs increased CAD6 million compared to the same period last year, and reflect heightened levels of development activity.

In energy, comparable EBITDA was CAD277 million in the first quarter, compared to CAD244 million for the same period last year. The CAD33 million year-over-year increase was the result of a combination of factors. Western Power's EBITDA was CAD52 million lower in first quarter 2013 than for the same period last year. The decrease was primarily due to the Sundance A PPA force majeure, as well as lower realized power prices and lower purchased PPA volumes during periods of low spot prices.

As you may recall, in first quarter 2012, we recorded CAD30 million of EBITDA related to the Sundance A PPA, as we believed the outage of Units 1 and 2 was an interruption of supply in accordance with the terms of the PPA. In July 2012, we received the arbitration decision that determined the units were in force majeure in first quarter 2012. As a result, we reversed the amount in second quarter 2012. Going forward, until the Sundance A units are returned to service, TransCanada will not realize the generation or related revenues it would otherwise be entitled to under the PPA, and it will be relieved of the associated capacity payments. TransAlta has indicated it expects to return the units to service in the fall of 2013. Lower realized prices in the first quarter compared to the same period last year, due to contracting activities, along with lower utilization of the Sheerness and Sundance B PPAs, also had a negative impact on Western Power's EBITDA.

Equity income from Bruce Power increased CAD44 million in the first quarter compared to the same period last year. Higher equity income from Bruce A, as a result of the restart of Units 1 and 2, and the recognition of a business interruption insurance recovery related to the Unit 2 generator failure, were partially offset by lower revenues and higher costs at Bruce B, as a result of increased planned outage days. In terms of specific unit performance, Bruce A Units 1 and 2 are now capable of operating at full power. While Unit 4 did not generate any revenue in the first quarter, it did return to service on April 13 from its life extension outage. The work completed on Unit 4 during the prolonged outage will allow it to operate until at least 2021. Looking forward, planned maintenance outages on two of the Bruce B units and one of the Bruce A units are expected to be completed in the second quarter. No further outages are planned for 2013. Taking all of this work into consideration, the overall plant availability for 2013 is expected to be in the mid-80% range at Bruce A and in high 80% range at Bruce B.

US Power EBITDA increased CAD32 million in the first quarter compared to the same period last year. The increase was primarily due to higher realized power prices, continued firming of the New York Zone J capacity market, and higher net revenues on wholesale, industrial, and commercial power sales. Finally, natural gas storage EBITDA increased CAD5 million in the quarter, mainly due to higher earnings from CrossAlta, resulting from the acquisition of the remaining 40% interest in December 2012.

Now turning to the other income statement items on slide 26. Comparable interest expense in the first quarter was CAD257 million, compared to CAD242 million in the same period last year. The CAD15 million increase primarily reflects lower capitalized interest, as a result of the completion of the restart of Bruce A Units 1 and 2, partially offset by increased capitalized interest related to the Gulf Coast project. In the first quarter, CAD55 million of interest was capitalized to assets under construction, compared to CAD74 million for the same period in 2012. Comparable interest income and other for first quarter 2013 decreased CAD7 million from 2012, primarily due to realized losses in 2013 compared to gains in 2012 on derivatives used to manage the Company's net exposure to foreign exchange fluctuations on US dollar income. In combination with US dollar denominated interest expense, this hedging program largely counter-balances the currency impact of translating US dollar pipeline and energy income reported in the business segments. Comparable income taxes for the first quarter 2013 increased CAD19 million compared to the same period last year, due to higher pretax earnings and a change in the proportion of income earned from higher tax jurisdictions.

Moving on to cash flow and investing activities on slide 27. Funds generated from operations totaled CAD916 million in the first quarter, an increase of CAD45 million from the same period last year, and reflective of our higher earnings in the period. Turning to investing activities, capital expenditures were CAD929 million in the first quarter, driven primarily by the Gulf Coast project as well as ongoing expansion of the NGTL system, in which approximately CAD340 million of new assets were placed into service. Equity investments totaled CAD32 million, and relate to our investments in Bruce Power and our Grand Rapids Pipeline Project.

Now looking at slide 28, our liquidity position and access to capital markets remain strong. At the end of the first quarter, our consolidated capital structure consisted of 41% common equity, 5% preferred shares, 2% junior subordinated notes, and 52% debt net of cash. At March 31, we had CAD443 million of cash on hand, along with CAD4 billion of committed and undrawn revolving bank lines with our high-quality bank group. Our three commercial paper programs, one in the US and two in Canada, are well supported and provide flexible and very attractive sources of short-term funds. In January, we issued US$750 million of three-year senior notes at an attractive coupon of 0.75%, and in March we completed a CAD600 million preferred share issue, the largest transaction of its kind in Canada, with an initial dividend set at 4.0%. Proceeds from these offerings will be used to fund our capital program for general corporate purposes, and to reduce short-term indebtedness.

We remain well positioned to finance our current committed capital program through funds generated from operations, new senior debt, as well as subordinated capital in the form of additional preferred shares, hybrid securities, and portfolio management, including LP dropdowns. As we go forward, our limited partnership could take on a larger role in our financing plans. The possibility of bending in further interests in our mature US natural gas pipeline assets, through a series of dropdowns, provides us with a significant amount of financial flex -- a significant amount of financial flexibility.

In closing, TransCanada's diverse suite of high quality energy infrastructure assets produced solid earnings and cash flow in the first quarter. Going forward, the restart and ramp-up of Bruce Power Units 1 and 2, along with the return of Unit 4 in April, Sundance A in the fall, and a higher Canadian Mainline return on equity, are all expected to have a positive impact on earnings in 2013. We also continue to advance a number of other initiatives, including construction of the Gulf Coast project, ongoing expansions of the NGTL system, the Tamazunchale Pipeline Extension, Hardisty Terminal, and the acquisition of fully contracted Ontario Solar assets, which are expected to be placed into service by 2014. In addition, we continue to progress, and are well positioned to fund the remainder of our CAD25 billion capital program, including Keystone XL. Each of those projects are underpinned by long-term contracts with strong counter-parties, or regulated cost-of-service business models. As a result, we expect to generate significant growth in earnings and cash flow that could be used to invest in new opportunities, grow the dividend, and further enhance our financial strength and flexibility in the years ahead. That's the end of my prepared remarks, so now I'll 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'll then turn it over to the media. With that, I'll turn it back to the conference coordinator for your questions.

Thank you. We'll now take questions from the telephone lines.

(Operator Instructions)

The first question is from Linda Ezergailis from TD Securities.

Thank you. Just a question on Keystone XL. When in your view do you think would be the latest you could get a presidential permit to achieve an in service date in the middle of 2015? And could you perhaps more broadly provide us with an updated time line on your expectation of the approval process?

Sure, Linda. It's Alex. I think probably the best way to think about this is especially for the northern route, the present Keystone XL route, it is -- we need summer construction periods and we need sort of one full construction period in the better part of another construction period. So in order to be in service in the second half of 2015, we need -- we'll obviously need a good portion of construction season in 2013 and 2014.

I've always said if we're looking at a permit. We think that we can be in a position to have a permit around this summer. We think there's ample information in front of the State Department for them to make that decision. And obviously if it slips significantly after the middle of the year, ultimately we would put that earlier 2015 in jeopardy.

So just to clarify, if you get a permit by this summer then early 2015 is still possible?

I think we've said the second half of 2015 and that would presume that we get a permit sometime during the summer, a little later.

Okay. Great. And just a follow-up question.

What are the book ends of what's possible in terms of a cost range for the Keystone XL Northern leg? And can you confirm the sharing mechanism in place with shippers for that? And I guess another question related to that would be are the delays alone putting pressure on costs or is there something else playing into that cost pressure?

Sure. The way the deal works with our shippers and any cost increases would be shared 25% by TransCanada, 75% by the shippers. At this time, we think it's probably premature to give too much granularity around the cost increase. Really, what we wanted to do with that disclosure on cost is it's probably been well over a year and-a-half since we updated the Keystone XL costs. And obviously with that passage of time there's going to be some impact and we wanted to directionally let our stakeholders know that that was the case.

A significant amount of the exposure would be delay. But there's a few other elements. There's obviously interest on the capital we've already put in place. We did a reroute in Nebraska which had some costs and we've experienced significantly higher regulatory cost. So all that kind of goes together.

I think as a lot of these costs are related to timing and schedule, I think what we'll do is we'll wait and see when we get a decision on the permit. And at that point we'll be able to give much clearer guidance on the cost increase.

Great, thank you. I'll jump in the queue.

The next question is from Juan Plessis from Canaccord Genuity. Please go ahead.

You mentioned that you'll seek regulatory and potentially legal review on certain aspects of the Mainline decision. Can you tell us what aspects of that decision you'll be challenging.

Also you're recording earnings based on 11.5% ROE. You obviously believe you can generate that return over the next five years. Can you talk about some of the things you're doing to enhance revenue on that system to get you to your returns?

It's Karl. I'll start with the first one on the aspects of our review and variance.

At a very high level, we're still working on the details of this. But on a very high level, I can say that we are trying to work within the framework proposed to us by the Board. We are going to deal with things that will make that framework more viable. One of them will be the timing of when these rates go into effect. The Board is set up for July 1st.

We think there's a couple issues with that. Number one is that's -- we have 1,500 delivery and receipt points in the system. That's not very long to get the pricing and all of our customer work done by that time. And the second is during the summer you don't have much opportunity to sell discretionary services, so we're going to ask for that to be adjusted.

The second is how the tolls are determined. We have presented for evidence with the Board that our short haul service on the pipeline, the eastern triangle of our pipeline is full at the current rates. We are full on that pipeline and we are going to ask the Board to re-look at how the tolls are determined. Right now they are determined by setting the long haul toll and then all the other tolls being factored off that long haul toll, and we are going to ask them to take at look at that.

We have other issues we're going to bring up with the Board like some of our service packages up, alterations to our service packages to make our likelihood of us earning revenue better and how to deal with other costs that come on the system.

As for earnings, the reality is they set the firm tariff at a level CAD1.42 which is below the full cost of service of the pipeline. We are expected to make up the deficit by selling discretionary service either at higher price or more volumes. Our objective is over an extended period of time we're going to attract more volume on the pipeline and we're going to be able to charge the discretionary services more for their service.

I think the Board expected a bit of a deficit up front and the idea is that any deficits up front will be worked off later as the price of gas and our volumes improve. We will be using that price discretion that we get and we will be marketing these services and pricing these services at the market so that we can achieve as much revenue on it as we can.

It's Don here. With respect to the 11.5% on 40%, we continue to meet the criteria to employ rate regulated accounting. And part of the cost buildup by the NEB was factoring in 11.5% on 40% return in determining the rates here. So we consider that to be the appropriate amount to record and we'll continue to do so.

Okay. Thank you for that.

And Karl, just another question for you. ANR, GTN, and Great Lakes pipelines systems earnings and throughput continue to decline. Can you tell us what actions or what options are being considered to improve those earnings and the outlook for that system?

Sure. Maybe I'll deal with Great Lakes for the most part here because I think that's a system that has declined the most. We are in the process of filing an application with FERC.

The issue with this system is we just lost billing determinants, long haul billing determinants. It's turned into more of a storage and a short haul system, filling up storage in winter peaking, short haul LBC systems. So we have approached our customers and we are preparing a filing to FERC to change the rate structures on that so we collect more of our revenue from the short haul in the storage, seasonal storage related services.

So we expect to have any negotiated settlement done by the summer. If we're not successful in negotiating a settlement, we'll be filing an application with the FERC and that will come probably in the fall. My expectation with that system is that once we get our new rates in place from either the settlement or the filing, that that system will improve. It may not get back to where it was a couple years ago but I think that we could still make that system a pretty decent looking US pipeline system.

As for ANR, ANR right now is just suffering from low transportation spreads. The volumes are still good in the pipeline. This is a unique pipeline.

It has lots of load on it. It's got lots of volumes. It's bidirectional. The volumes are still on the system. We just see poor transportation spreads.

Our efforts on this system are same as efforts we've had the last couple years, quite frankly. We're looking to tie more load into it. We are actively involved in all expansions of industrials and into new local distribution areas. And we'll continue to add volume onto this system on both the load side and the supply side, and we expect that this will come back as the transportation spreads improve.

Thank you very much.

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

On the Portland pipeline, you talk about the open season there for an expansion of that pipeline. Can you remind us again what that would entail, what kind of pricing cost that would be? And also, you mentioned that it would be subject to an assessment of the implications of the recent NEB decision on the Mainline restructuring proposal. What does that mean?

Well, with the Portland system right now, maybe I'll just give a little bit of background on that. That pipeline goes into the Boston, the New England area and supply has been altered in that area. There's the production is fairly unstable. The Penn-York is not performing as well as people thought and the LNG that's coming in on the East Coast is sporadic at best. There have been some supply issues there.

As well I think we tested some normal winter, maybe in a little bit colder winter this year, the demand response was greater than people thought. There seems to be good demand. There seems to be people interested in more capacity into that system.

So we are entering an open season right now. That open season will be going on for another month and-a-half and we are looking for firm commitments. We have some expansion capability there that we can do if we get the firm commitments at the prices that we're looking for.

As for the expansion on the Mainline, anybody who gets -- who does bid on capacity on PNGTS will need to get Mainline capacity from either the Dawn area or Empress area to East Hereford which is the inlet to the Portland system. They will need to come with us and we will at that time hold open season to construct new capacity for them at that time. We currently don't have spare capacity going into the inlet of the Portland system so they will need to contract with us and if we get a sufficient contract we will expand the Mainline system to accommodate that.

So what is the bottleneck on the Mainline system? It seems the Mainline has plenty of spare capacity right now. Where exactly is the shortfall?

Also, and what is the comment and the write up about the implications of the NEB decision on this? How does that impact it?

The first question is where are the bottlenecks. The bottlenecks on the Mainline system are in the eastern triangle. We'll need to construct more there. We do have spare capacity coming out of Empress and we spare capacity coming out of Northern Ontario but in the eastern triangle, we're quite full right now.

So that's where we'd be looking to build. So you'll need to build that regardless of where the origination point is.

And the implications of the NEB decision. Well, the implication of the NEB decision now because of the fixed rate tolling that they have, people willing have to when people come to us wanting transportation to the Portland, to the inlet of the Portland system, they'll have to sign incremental contract with us that will cover the full cost of that expansion.

Okay. And then if I could sneak a second one in. Northern Courier, who's at risk if that project ultimately does get cancelled in terms of the cost you put into this project already and how much have you actually spent on that project to date.

I don't have the amount right in front of me that we spent. It's not a very significant amount right now but I think importantly if the project doesn't go ahead we would be reimbursed by our counter-parties. I think the important thing to remember is even in the event that the Upgrader doesn't go ahead, the Fort Hills Mine is going ahead and our counter-parties are still going to need a pipeline coming out of that mine. So we think under any scenario there's still a pretty good opportunity for TransCanada there.

Great. Thank you.

The next question is from Carl Kirst from BMO. Please go ahead.

Thanks. Good afternoon, everybody.

I was wondering if I could start, Don, Karl, as far as the Mainline, I think there was recognition that the NEB sort of expects to start in a deficit period. Can you help us out with what the baseline of that deficit is? Maybe asked another way, what's the cash under collection at this point at March 31st relative to say for instance the earnings we've booked here, 11.5%, just to kind of put us on the same page?

Well, the cash deficit right now is actually zero. The way the Board has set it up is they've asked that we do a deferral that is planned, which is the long-term deferral, and that will come in every year. So we haven't actually done that yet under this program. And they've asked that we do a short-term deferral which is actually the difference between our revenue and costs every year and that's a TSA and that is not -- that's at zero right now.

We do have some deferrals coming out of last year that we have put into long-term deferral. But those are deferrals that were already existing and aren't incremental to this decision. As of right now, the TSA, the utilization account is zero.

Great. Thank you. Another question with respect to the Gulf Coast project part of XL.

Maybe the longer perhaps that the Gulf Coast project will be standing on its own, can you help us out with what you think the annualized EBITDA earnings power of Gulf Coast would be, say for instance in 2014? Is this something where you would go after market based rates? I don't believe you have market based rates now but correct me if I'm wrong. Just trying to get a better feel for that the longer this project is on.

Sure, Carl. I think we've given a little bit of guidance over the past year or so on this and I think there's sort of two pieces we've given which is number one, you can look at the capital from this project and compare it to the capital, the base Keystone system and contribution would be roughly equivalent. I think we've also given a range of kind of CAD200 million a year EBITDA moving up to CAD300 million.

What I would say is we've been pretty active on the marketing side and so I think we're feeling pretty positive about the contribution that this project is going to make going forward in advance of Keystone XL. We have not yet filed for market based rates. That's something we're looking at and we're going to see what success some of our competitors in that region have. But that is an opportunity ahead of us also.

Great. And then last question, if I could, and this really speaks to ANR and understanding that the volumes are high. Granted, this is a hypothetical, but if energy transfer really does convert a piece of trunk line and takes some of the excess capacity out of that market, are you expecting that to tighten up that capacity? Or is it by the nature of what you're flowing, more seasonal, et cetera, that maybe that wouldn't tighten up?

I think directionally that's positive. I don't know how much extra volumes we would attract from that but I think directionally that will make the transportation values better in that area so I think that would be a positive for ANR, yes.

Great. Thanks, guys.

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

I guess just first ask Alex, just on your comments at the end on Northern Courier, I'm just wondering, Northern Courier would get them out of the Fort Hills Mine. I'm just wondering what's been contemplated with your discussion? Is the possibility of a direct connection into Grand Rapids or an extension to Grand Rapids something that you're pursuing or do you think they'll want to go in a different direction?

I think they have a number of options. I think we would think that Grand Rapids would potentially be a pretty good fit for their needs also. So that's something we're definitely going to look at with them if they're interested.

Okay. But there's nothing in the Northern Courier agreement that would contemplate a direct Grand Rapids connection?

Not at this time, no.

Okay. Just the other question I've got is you're certainly not capital constrained but if Keystone XL is pushed back into second half of 2015 and if some of the other spending starts to kick up, as you evaluate new projects do you think about if their spending or the acquisitions are in the 2014, 2015, 2016 even time frame, have you been thinking about trying to increase hurdle rates or rationing capital in that two to three year period?

Not sure if I truly understood you, Robert. It's Russ. Maybe Don might want to jump in here as well.

I think your question is you how are we going to finance essentially if we're so fortunate as to have all of these projects approved? What does that mean for our ability to fund them?

And I think the way we're looking at it right now is we'll use as I said all the traditional sources of capital that we have in the past, starting with the cheapest one which is our cash flow and then our debt capacity, preferred securities. I think that you can expect us to be using our MLP a lot more actively than we have in the past. We've always said that that's a financing vehicle that's available to us to the extent that we do get capital constrained. And then obviously we'd look to the balance of our portfolio, are there certain assets in our portfolio that are fully valued and maybe more valuable to others than they are to us.

It's kind of a stack-up of the way we look at it. We'd also look at with some of these projects that they're open to strategic partnerships and in the case of our LNG projects, for example, those counter-parties still have the option to take up some equity in those projects.

So we're trying to be as flexible as we can in going after those projects. I wouldn't say that we've moved our hurdle rates yet in terms of a method of rationing capital but we're able to I think ration our capital in a way that we have allocated it all to this fully contracted long-term fully contracted kind of structure and away from sort of commodity exposure or other kind of market exposures.

It's a unique time in the industry to be able to capture these opportunities. And I think our thinking would be is as long as they're soundly contracted and if you think of those projects like the LNG projects, for example, which are sort of a cost of service like approach where we're not taking construction risk or payback our money if they don't go forward. Those are conducive to other forms of financing, less strategic partnerships or other things down the road.

I think that's where we probably turn our heads to. As long as we can keep the contractual structures tight and valuable, then I think financing isn't going to be an issue at the kind of hurdle rates that we have in place right now. Don, if you want to add to that?

I'll just concur. Our hurdle rates aren't that dynamic over time. They're fairly sticky and we're not devoid of opportunity. Keystone XL aside here over the next few years.

Just give you a sense as to what the capital program looks like let's say through 2015 over the -- this three year period right now. We've got about CAD4 billion of oil projects, Gulf Coast and the Alberta regional opportunities, about CAD4 billion in the gas side with NGTL Mexico. And some pre-spend on our LNG projects getting to final investment determination which amounts are recoverable if they don't go forward. And then CAD3 billion of other stuff including solar, the ramp-up of spend on Napanee and the like and maintenance capital.

That gets you to about CAD11 billion between now and the end of 2015. There's probably another CAD1 billion to CAD1.5 billion on NGTL that we haven't filed for yet in terms of connecting gas for Prince Rupert. You're getting into that CAD12 billion to CAD13 billion range without Keystone XL. So the plate's not empty but in our view certainly manageable.

Okay. Sorry. In that CAD4 billion, Don, that's without Keystone XL. Does that include at least in the back end of that anything for Energy East?

No.

Okay.

We've got CAD200 million to development work upfront but nothing beyond that. You're kind of in that CAD12 billion range now through 2015 without XL and without any material post filing spend on Energy East.

That's great. Thank you.

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

I guess just a point of clarification on the Mainline accounting for the quarter. You did book the 11.5 ROE. I guess the question really is what portion of that was cash? Was it all cash? In a sense that you received it or what portion wound up with accruals or deferrals?

It's Glen here. Under the direction of the Mainline decision, obviously we had an increase from our 8.08% return that we were recording last year up to 11.5% retroactive to January 1st.

We are not allowed to go back and re-invoice shippers from 2012 and as directed in the decision, that increase forms part of a long-term deferral that Karl was referring to earlier that was already in existence. So that income if you would will be recovered over time with also a regulated return on top of it.

So is it fair to say just really in the quarter if you looked at it on a true cash basis you were probably given the decision timing was about March 27th you were really 8.08% through the quarter? And then the differential is really in this long-term deferral?

I think the other thing to factor in there is that we're also under interim tolls right now and as a result in the winter season we are collecting that. And that will be addressed and dealt with in the future. Karl, anything more to add on that?

No, I don't have anything more to add on that. Our collections in the first quarter under these interim tolls were probably greater than our costs.

They were.

The way it works is we collect more of our cost of service in the winter in the peak months and then less in the shoulder months. I don't know the exact number. But I don't think it's a fair statement to say we didn't collect it.

No, the amount that we've -- as Karl would say overcollected or what I would say the excess of our collection unearned from tolls versus our underlying revenue requirement was a little over CAD100 million, about CAD140 million in the first quarter.

Okay. That's very helpful. I guess just a bigger, broader question but still on the pipeline space and it's probably to Russ. Could you give us any color and comments and just general thoughts on representative Terry's proposal, the legislative proposal, to really avoid the need for presidential permit for Keystone XL?

Can you say that one more time?

The energy subcommittee, we've gone through the process of representative Lee Terry with his proposal to introduce legislation eventually that eliminates the need to have a presidential permit.

Well, I guess what I'd say is obviously we appreciate the sentiments of that kind of proposal, anything that accelerates the decision making. We have been at this review for 67 months and there's not much left to say so let's get on with the decision making.

That said, our focus isn't on legislation. Our focus is on answering any additional questions that arise through the regulatory process. That's what we're focused on right now.

We just got through the comment period on the draft environmental impact statement. Our next focus will be on answering any questions that arise through the national interest determination.

Realistically a time line just excluding the legislative kind of option, you're thinking late summer for an actual presidential permit to be granted?

I guess what I'd say is it appears that we're through the comment period now. The last time that they received comments on a draft environmental impact statement it took them something greater than 60 days to get to a final environmental impact statement.

The Department of State said that it will get to a final -- it will issue a final environmental impact statement. They've got a lot of comments. So 60 plus-ish days is what we were kind of thinking around that process.

Then the national interest determination last time they specified a time frame of 90 days. We would argue that the time frame could be shorter than that given that 79 days had passed through that period last time. That said, they have to specify that time and they haven't specified that time frame yet.

That's what kind of leads you to those kind of time frames that Alex mentioned. But that's the amount of certainty or clarity that we have in the process today and we continue to work a way to make sure that we're ready to start construction when it comes to a conclusion. It's just difficult to put a pin in when that's actually going to occur.

We would hope as I said in that sort of summer to fall time frame that we would see a decision. But as I said, we've been at this for 67 months now and the process I think will take however long the process takes and our objective is to work with everyone in a cooperative way to ensure that they have full information to make a decision.

Okay. That's very helpful. Thank you.

We will now take questions from the media.

(Operator Instructions)

Sorry, operator, can I just confirm that you don't have any other questions from the financial community?

We have one more. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Thanks a lot. Just want to talk about the Mainline conversion or I guess Energy East. You talked about marketing the 850,000 a day.

How much in terms of volumes would you actually need to go forward? I'm assuming it's somewhere less south of 850,000 and can you give us a sense at all of what kind of tariff you'll be marketing to get to different points on the Energy East Pipeline?

So I would say that the project is sort of at the upper end would be about 850,000 barrels. We would be able to go forward commercially with significantly less than the 850,000 barrels. And I'll probably be a little coy on that for the time being and we're talking about a toll to get to kind of Quebec and potentially out to Eastern Canada.

You're talking about the range. It's sort of in the CAD5 to CAD7 range. Depending on, once again, depending on size of the project and how far we go.

Okay. Presumably though that would vary somewhat light versus heavy.

Yes.

Got it. Okay. Then can you talk about just shifting over to the Mainline and I guess the ROE there, the 11.5%, is there any read-through we should have on that into, say the NGTL system? Or maybe even some of the LNG projects might you be looking for a little bit better return than what you've historically gotten on the Canadian pipes on an ROE basis.

I think it's a fair comment to say that the regulatory framework has changed with the decision on the Mainline and that this will be -- this should in our opinion apply to the NGTL system as well. We're in the middle of settlement discussions right now. I don't think I'll talk about specifics of our discussions but it's not lost on us that there has been some change in the regulatory framework and that we would be looking for -- we would be looking for changes for all of our NEB regulated pipelines, yes.

Okay. Is that true for the LNG projects as well?

I'd say that the LNG projects are already contractually set in terms of the return on equity. What I'd tell you about the return on equity it's more in the range of the recent decision and past decisions. Certainly we always thought that the return on equity on the Canadian Mainline and other Canadian regulated businesses are too low and that obviously influenced our negotiating position in securing those new projects. They're already in that neighborhood.

That's very helpful. If I could just do one more just on Keystone XL and the delay here on the in service date. Could you talk about how the contracts look as the time frame continues to go out and if we do bleed past the summer for the permit and potentially into 2016 for the start up, how does that impact the contracts you have in place?

I think the most important thing is that we at this point still enjoy the very strong support of our shippers for this project. I think they see Keystone XL as continuing to be a very attractive route to get their oil to market. So I think that's a first point.

And under the second point, under any of the scenarios that we're looking at we think we are -- we're quite confident that we'll be able to get the pipeline in service without putting at risk significant shipper commitment.

Okay. Thank you very much.

The next question is from Juan Plessis from Canaccord Genuity. Please go ahead.

Thanks very much. Bruce Power, Alex, how much forced outage expectations of Units 1 and 2 is baked into the expectation of a mid-80s% availability at Bruce A?

I don't have that right in front of me. Glen, do you have -- ?

As far as the units being a little or ramping up in filings, the ramp up, that's supposed to end quite soon.

Okay. So the forced outage expectation is baked into that mid-80s%?

The forced outage is already buried into there. As they ramp up it would be consistent with other units.

I think the number that I saw most recently was somewhere in the neighborhood of 3% which would be above. And that's what's baked in and that is above what we would normally see as a forced outage rate, closer to one-ish or so.

Sorry. I didn't quite get the question. That was my recollection. I think it's somewhere around 3% and particularly seeing those as new units we would expect to see that go down relatively significantly after the first year.

Okay. Great. Thanks. And Don, how much of the CAD40 million of business interruption insurance recovery at Bruce related to 2012 and how much was related to 2013?

Juan, it's Alex. I'll just give a quick explanation and then that might be helpful. When we were bringing Unit 2 back from the refurbishment, you'll probably recall we had a generator failure on the unit which slowed down, obviously slowed down bringing Unit 2 into service.

But in order to sort of maximize the value of the site, what we did is we took some generator parts out of the Unit 4 generator which worked because we were putting the Unit 4 generator on one of these life extension outages. And as a result of that, we have attributed some portion of that insurance recovery to 2012 and to 2013 because it had a knock on impact on bringing Unit 4 back later than would have normally occurred.

It's Glen here. After you take into account insurance waiting periods under business interruption and then factor in the full time period, it does span from 2012 into 2013. And without getting into the specifics, a little over half of it would be due to 2013.

Okay. Great. Thank you very much.

We will now take questions from the media.

(Operator Instructions)

The first question is from Chester Dawson from Wall Street Journal. Please go ahead.

I'm sorry to make you repeat something if you explained quite a bit today. Could you go in a little bit deeper on the decision of the catalyst for your new timing on when you think Keystone XL could be up and going provided you get a permit? And is it -- how likely it is that it would go even beyond that into 2016, 2017? Are you absolutely confident it would be late 2015 now or is there an increasing likelihood it would go beyond that?

Secondly, with all of the debate over that and the northern gateway, are you looking into other potential opportunities? For example, going up north through the Northwest Territories, for an arctic means of transmission or what are your thoughts on that as a viable reality for a pipeline?

I'll take a shot at it. It's Russ.

I think the first question on in service timing. In service timing is directly related to when we get a permit. At the current time, as we said, that process continues to be delayed. We're in a position now where the comment period has closed.

The Department of State has to sort out those comments. That's a 60-day process and then potentially a 90-day process on top of that for a national interest determination which gets you through the summer. Hopefully we'd see a decision in that kind of time frame.

But if that time frame continues to get delayed, then our project continues to get delayed and that's just sort of the reality. I can't really sort of nail down what impact a specific period of time would have at this point in time on the back end of that. We still expecting a late -- latter half of 2015 as an in service date.

With respect to other alternatives. I think that we spent some time today and over the last you few months explaining what we think is one exceedingly viable alternative, not really alternative but something that's going to be necessary anyway is the conversion of some of our Mainline gas capacity to move oil from Western Canada through to Eastern Canada delivery points. And to date, we have had considerable positive interest in that and I'm very confident that at the end of our open season we'll have sufficient shipper underpinning to move forward with that project. It can move about 850,000 barrels a day from west to east.

With respect to going north, the marketplace is innovative and it continues to look at all kinds of alternatives. What we know is what drives the production of oil and of any commodity for that matter is economics. And there is considerable economics in producing the Western Canadian reserves, the oil sands reserves is the third largest reserve in the world. And the folks that are investing in it are folks from all around the globe and they will figure out a way to get their product to market.

And Keystone XL is one route to get product to market but what we know is the world needs oil and there's oil available there and the marketplace will figure out how to get it from A to B. I'm 100% confident that that is what is occurring and that's what will continue to occur.

Thank you.

(Operator Instructions)

There are no further questions registered at this time.

Thanks very much and thanks to all of you for participating today. We very much appreciate your interest in TransCanada. 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. We thank you for your participation.