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Executives

David Moneta - Former Vice President of Investor Relations & Communications

Russell K. Girling - Chief Executive Officer, President and Director

Donald R. Marchand - Chief Financial Officer and Executive Vice President

Karl Johannson - President of Natural Gas Pipelines

Alexander J. Pourbaix - President of Energy and Oil Pipelines

Analysts

Paul Lechem - CIBC World Markets Inc., Research Division

Juan Plessis - Canaccord Genuity, Research Division

Linda Ezergailis - TD Securities Equity Research

Carl L. Kirst - BMO Capital Markets U.S.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Robert Kwan - RBC Capital Markets, LLC, Research Division

Andrew M. Kuske - Crédit Suisse AG, Research Division

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Chad Friess - UBS Investment Bank, Research Division

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Dennis P. Coleman - BofA Merrill Lynch, Research Division

TransCanada (TRP) Q4 2012 Earnings Call February 12, 2013 3:00 PM ET

Operator

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2012 Fourth Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr. Moneta.

David Moneta

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2012 Fourth Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Karl Johannson, Executive Vice President and President of 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 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 questions. During the question-and-answer period, we'll take questions from the investment community first followed by the media. [Operator 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 U.S. Securities and Exchange Commission.

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, interest -- sorry, 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 U.S. GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.

And with that, I'll now turn the call over to Russ.

Russell K. Girling

Thanks, David, and good afternoon, everybody, and thank you for joining us for our first quarterly conference call of 2013. Starting with some highlights in 2012 is let's say 2012 was a very positive year for our company as we made significant progress on a number of very important initiatives that I believe will improve the future performance of our existing businesses. As well, we placed into service several strategic capital projects, and we also captured significant new opportunities, which will provide the visible growth for our company for many years to come.

Financially, we performed relatively well in 2012 with comparable earnings of 130 [Audio Gap] or $1.3 billion or $1.89 a share. Unfortunately, earnings in 2012 were impacted by lengthy delays in the start up of the Bruce Units 1 and 2, the unplanned West Shift outage of Unit 4, the loss of Sundance A contributions for the year. In addition, the continued low natural gas and power prices, which did put pressure on those commodity-exposed assets that are affected by commodity prices.

Looking forward, we did receive positive decisions related to both the Sundance A and Ravenswood issues and we placed $3.4 billion of new assets into service and they started operations. We saw the start up of the Bruce Units 1 and 2 late last year. We expect the return to service of Unit 4 this quarter. The Sundance A issue, as I said, was resolved at this year as well and we expect that Unit to return to service in the fall of 2013. All of those events, along with the startup of other key natural gas pipeline Energy projects that I mentioned, are anticipated to have a positive impact on earnings and cash flow in 2013 and, because of their contractual nature, in many years to come.

We did continue to advance our pipeline systems with the start of the Gulf Coast construction, the Gulf Coast Project from Cushing, Oklahoma to the Gulf Coast, and the approval of the new route for the Keystone XL pipeline in Nebraska.

And lastly, and probably one of the most significant accomplishments on the year was 2012 did present us with some unprecedented opportunities for high-quality long-term growth in each of our 3 core businesses.

Since the beginning of 2012, we've secured about $16 billion of new projects, which include the Coastal GasLink project, the Prince Rupert project, the Topolobampo, Mazatlan and Tamazunchale Extension projects in Mexico, the Northern Courier and Grand Rapids oil projects in Alberta, as well as the Hardisty terminal project that goes along with those oil projects in Alberta and the Napanee Generating Station in Ontario. In total, the company now has more than $25 billion in projects to bring onstream over the balance of this decade. Between now and 2015, we expect to complete about $12 billion of those projects, including the Gulf Coast Project, Keystone XL, the Hardisty terminal and the initial stages of the Grand Rapids pipeline, the Tamazunchale Extension, the -- some of the Ontario -- all of the Ontario Solar projects and the ongoing expansions of our Alberta System. As you can see from the slide, all of these projects are highly contracted or their regulated and therefore, we expect each of these projects will generate significant sustained earnings and cash flow for our shareholders for many years to come.

Turning briefly to the fourth quarter results, I would describe them as solid, but not reflective of the underlying earning power of our underlying asset base.

Comparable earnings were $318 million for the quarter or $0.45 a share, and the year-over-year decrease in quarterly earnings was primarily due to the same factors that I just mentioned that impacted the full year results. Which include lower earnings from the Western Power, primarily resulting from the loss of Sundance A contributions for the year; the Bruce Power delays; and certain Natural Gas Pipelines, including not getting a Mainline decision, as well as the Great Lakes and ANR revenues that have been impacted by narrower spreads on our U.S. pipeline transportation business.

Comparable EBITDA for the year was $1.1 billion, with funds generated from operations at $818 million. Today, the Board of Directors declared a quarterly dividend of $0.46 per common share per quarter, for the quarter ending March 31, 2013. On an annual basis, that translates into a 5% increase from $1.76 to $1.84, and that is the 13th consecutive year TransCanada's Board has raised its dividend. Don Marchand will provide more details on those financial results in a few minutes. But before that, I'd like to provide you with some more detail on a number of the advancements that we made in 2012 on our capital projects, primarily in the last quarter of last year.

Certainly, the Gulf Coast Project is -- as you know, decreasing the glut of oil in Cushing and providing American producers with a way of getting their domestic crude oil to market is the focus of the Gulf Coast Project. As many of you might be aware as well, many out-of-state sort of professional, or what we call activists, have done their best to slow down the project and stop our project, primarily in Texas. The 4,000 Americans that are building that project, and I've seen them all on the job site, are pleased that, that hasn't happened, and we look forward to continuing to put them to work in the months ahead. And the off-spin benefits that we have in having them in those communities, spending money in restaurants, hotels and other local community businesses. The demand for that project is clear. U.S. oil production has been growing significantly in states such as Oklahoma, Texas, North Dakota, Montana. But producers don't have sufficient access to pipeline capacity to move this production to market, primarily in the U.S. Gulf Coast. And the Gulf Coast Project will address that constraint and allow U.S. refineries to access lower cost domestic production and avoid paying a premium to foreign producers. We're both 45% through that project and we continue to anticipate it being in service late in 2013.

Moving to Keystone XL. We received some very significant good news last month. The 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. The approved reroute now becomes part of the project's Presidential Permit application with the U.S. Department of State, which was filed on May 4, 2012. This development does move us one step closer to Americans and Canadians receiving the benefits of Keystone XL, which is the connection of Canadian and U.S. production to U.S. markets and the enhanced energy security, and that it will provide thousands of jobs over the construction process.

The need for the project continues to grow as North American oil production increases. And having the right infrastructure in place is critical to meeting the goal of reducing dependence on foreign oil and moving that oil in the most environmentally responsible way.

Keystone XL is the most studied crossover pipeline ever proposed and it remains very much in the American's national interest to approve that pipeline. We expect to obtain regulatory approval in the first half of 2013, and we still anticipate that the pipeline would become operational in late 2014 or early 2015.

Moving back to Alberta, the day prior to our third quarter earnings call, we announced the Grand Rapids project. This $3 billion joint venture with Phoenix Energy will be operated by TransCanada and will transport crude oil and diluent between Northern Alberta and Edmonton. In addition to their 50% equity commitment, Phoenix has also signed a long-term contract to ship crude oil and diluent on the pipeline system. This combination of diluent and oil delivery in Alberta is very unique and I think it positions our company very well to connect new supply for 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 by mid-2015. The entire Grand Rapids project should be completed in the first half of 2017 with the full system having a capacity of up to 900,000 barrels a day of crude oil moving South, and 330,000 barrels a day of diluent moving North.

Moving over to the Mainline conversion. We continue to advance our Mainline conversion project, a proposal which is to repurpose the Canadian Mainline from natural gas service in order to transport Western oil to Eastern markets. We have determined that the project is both technically and economically feasible and that we will be able to continue to meet the needs of our natural gas customers. Discussions with potential shippers and other stakeholders are well underway to determine if it is a project that the market wants, and I would say to date, those discussions have been very, very encouraging. Eastern Canadian refineries today import about 600,000 barrels a day. Much of that is higher priced oil from places like Saudi Arabia, Nigeria and Libya. The project would support Eastern refineries with lower-priced Western Canadian oil, as well the jobs that those refineries provide along with allowing Canadians to benefit from oil produced in their own country. Our expectation is that we'll be in a position to advance this project into the next phase, which is an open season to formally secure contractual support for the pipeline in the near future. If successful, that will be followed by regulatory application and we'd expect that to occur later in the year.

Moving over to the gas side. I had the pleasure of traveling to snowy Prince George in early January to officially announce our Prince Rupert Transmission project. We were selected by Progress to design, build and operate the $5 billion pipeline. It's proposed that we transport gas primarily from the North Montney region near Fort St. John to the recently announced Pacific Northwest LNG export facility in Port Edward, which is near Prince Rupert, British Columbia. This project would allow British Columbians and all Canadians to continue to benefit from the responsible development of a growing supply of natural gas resources in the Western Canadian Sedimentary Basin.

As you know, this is the second major natural gas pipeline proposed to Canada's West Coast for TransCanada, following the earlier announcement of our Coastal GasLink pipeline project. If approved, the Prince Rupert Transmission project and the TransCanada proposed Coastal GasLink project to Kitimat, together, would add more than 1,400 kilometers to TransCanada's Western Canadian natural gas transmission system. We expect both the Prince Rupert and Coastal GasLinks to be in service near the end of the decade.

In addition, last month we announced that we were proposing to extend our Alberta natural gas delivery system in Northeast British Columbia with an investment of $1 billion to $1.5 billion. This additional infrastructure would connect both the Prince Rupert Gas Transmission project and to additional North Montney gas supply from Progress and other parties. We expect a significant portion of those extensions to be completed by the end of 2015.

The NOVA Gas transmission system remains the cornerstone of our strategy to capture growing supplies and market in both Alberta and British Columbia. In 2012, we completed and placed in service approximately $650 million in pipeline projects. This included the completion of the $250 million Horn River Project in May of 2012 that extended our system into the Horn River shale basin in Northern British Columbia. The National Energy Board approved $640 million worth of additional expansions in 2012, including the $160 million Leismer Kettle River crossover project which is intended to provide increased capacity to meet growing demand in Northeast Alberta. A further $330 million of projects were still pending, awaiting NEB approval on an application that would extend our natural gas pipeline network further into the Horn River area at the end of 2012. A couple of weeks ago, the NEB approved the $100 million Chinchaga portion of that project but not the Komie North extension. It's a decision that we don't expect to impact that business going forward and we hope to continue to develop that region.

As well as expanding our natural gas infrastructure in Western Canada, we made significant strides in broadening our footprint in Mexico. In November, we were awarded the $1 billion Topolobampo pipeline project. The pipeline project is supported by a 25-year contract with the Mexican state-owned electricity utility, CFE, with the capacity of 670 million cubic feet a day. This project is expected to be operational by mid-2016.

And just a few days after we announced that project, TransCanada was awarded another large project in Mexico, the Mazatlan project. This $400 million dollar pipeline will have a capacity of 200 million cubic feet a day to transport natural gas and will interconnect with the Topolobampo project. This project is also supported by a 25-year contract with CFE and we expect it to be in-service by the end of 2016.

I'll conclude my comments with respect to our natural gas business by saying that the National Energy Board hearing on TransCanada's application to change tolls and conditions of service for the Canadian Mainline wrapped up in December. We continue to expect a decision late in the first quarter or early in the second quarter. I tell you the Canadian Mainline remains a critical piece of an infrastructure for North America, connecting the gas fields of the Western Canadian Sedimentary Basin to markets in Central and Eastern Canada and the United States. In 2012, the pipeline network moved on average 2.35 Bcf a day across the prairies and delivered more than 4.25 Bcf a day to Eastern markets in both Canada and the United States.

Turning to power. Bruce Power completed the refurbishment, as I said, of Units 1 and 2 last October, sending power to the Ontario grid for the first time in 17 years. Both units have operated at reduced output levels since they became operational. Unit 1 was off-line for the month of November for maintenance. Bruce expects both reactors to ramp-up to full power in the coming months. Units 1 and 2 will produce clean, reliable power for the province of Ontario until at least 2043. Bruce Power also continues its strategy of maximizing the operating life of its running reactors. Unit 3 returned to service last June after upgrades were completed. Unit 4 is expected to become operational late in first quarter of 2013, following work that started in August of 2012. And while these outages negatively impacted earnings in 2012 and early 2013, the enhancements are now expected to allow both of these units to continue to produce low-cost electricity until at least 2021.

100% of the power produced at Bruce is sold under contract to the Ontario Power Authority. Bruce is one of the world's largest nuclear facilities capable of generating more than 6,200 megawatts, supplying approximately 25% of Ontario's power needs.

Also in Ontario, in mid-December we signed a 20-year contract with the OPA to develop, own and operate the 900-megawatt natural-gas-fired power facility in Ontario. Located in the town of Greater Napanee in Eastern Ontario, the Napanee Generating Station will replace the facility that was planned for the community of Oakville. TransCanada has been reimbursed for $250 million primarily for the cost of natural gas turbines purchased for the Oakville facility, and those turbines will be used for the Napanee project. And in addition we expect to invest approximately $1 billion in that facility.

Finally, on the power side, the last of 5 wind facilities that are part of the Cartier wind project in Québec was completed in early November of last year. TransCanada is a 62% owner of the Cartier Project, the largest wind farm in Canada. With a total capacity of 590 megawatts, Cartier has the capacity to meet the power needs of more than 100,000 Quebec homes. All of the power produced by this project is sold to Hydro-Québec under a 20-year Power Purchase Agreement.

So as you can tell, in conclusion, TransCanada did make significant progress in 2012, building long-term shareholder value. We commercially secured $16 billion of new projects, bringing our portfolio of commercially-secured projects to $25 billion. Over the next 3 years, we expect to complete $12 billion of these projects that are in the advanced stages of development. Our natural gas footprint continues to expand in British Columbia, Alberta and Mexico. Our generation position has continued to grow in Ontario. And we moved 1 step closer towards a Presidential Permit for Keystone XL with the approved route in Nebraska. Construction of the Gulf Coast Project is now 45% complete, and we have made great strides in expanding our oil footprint infrastructure in Alberta. The long-term growth outlook for natural gas, crude oil and electricity generation presents significant opportunities for TransCanada to continue investing our strong and growing cash flow in all 3 of our core businesses. And we remain confident in our ability to continue to grow earnings, cash flow and dividends as we complete our capital program, benefit from the anticipated recovery in natural gas and power prices and advance our portfolio of growth opportunities.

I'll now turn the call over to Don Marchand, who will provide additional details on our fourth quarter 2012 financial results. Don?

Donald R. Marchand

Thanks, Russ and good afternoon, everyone. As you know, earlier today we released our fourth quarter results and announced a 5% increase in the common share dividend. Before I discuss our fourth quarter in detail, I would like to reiterate a few of Russ' key messages. The majority of TransCanada's diversified portfolio of high-quality energy infrastructure assets performed relatively well in 2012. However, persistently weak natural gas and power prices, planned outages at Bruce Power and the absence of Sundance A did negatively impact earnings. $3.4 billion of new assets were placed into service in 2012, most of which occurred in the fourth quarter and are expected to contribute to earnings and cash flow growth in 2013. The company has commercially secured $16 billion of new projects over the last year in its 3 core businesses. These projects will further diversify the company's portfolio and contribute to sustainable earnings, cash flow and dividend growth in the future. And finally, we remain well-positioned to fund our current capital program, as well as pursue other growth initiatives.

Now, moving to our fourth quarter consolidated results.

Comparable earnings in the fourth quarter of $318 million or $0.45 per share decreased by $47 million or $0.07 per share compared to the same period in 2011. Lower contributions from Western Power, Bruce Power, Canadian Mainline, ANR and Great Lakes more than offset increased income from the Alberta System, Eastern Power and U.S. Power. On a per share basis, changes in comparable earnings for the fourth quarter 2012 compared to 2011 are summarized as follows: earnings rose $0.04 from improvements in Eastern Power, U.S. Power and the Alberta System. In Energy, the Sundance A force majeure caused EPS to decline by about $0.06 and planned outages at Bruce Power decreased EPS by an additional $0.01. In Natural Gas Pipelines, lower revenues and higher operating expenses at both ANR and Great Lakes and the absence of incentive earnings on the Canadian Mainline reduced EPS by a combined $0.04. As you know, we are progressing through many of these items that have affected earnings over the past several quarters. I'll provide an update on our progress in each of these areas in a few minutes.

But first, I will 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 $690 million in the fourth quarter of 2012 compared to $716 million for the same period last year. The $26 million net decrease resulted primarily from lower contributions from the Canadian Mainline, ANR and Great Lakes. Partially offsetting that were earnings improvements from expansions on the Alberta System, as well as some GTN and Mexican pipelines. Our 2012 Canadian Mainline results excluded incentive earnings generated in prior years under a 5-year settlement that expired on December 31, 2011, and reflect the last NEB-approved return on equity of 8.08% on deemed common equity of 40%. A lower investment base also reduced earnings for the Canadian Mainline compared to the prior year.

With the conclusion of the hearing on our 2012-2013 tolls application in December, we expect to receive a decision from the NEB within the next couple of months. Any resulting impact on earnings for both years will be recorded in 2013.

As a reminder, in our application, we requested an after-tax weighted average cost of capital of 7%, which equates to a rate of return of 12% on a deemed equity component of 40%.

In fourth quarter 2012, our U.S. Natural Gas Pipelines continued to be affected by lower transportation revenues and higher operating costs at ANR and Great Lakes.

Turning to Oil Pipelines. Keystone generated $180 million of EBITDA in the fourth quarter, which was comparable with 2011. Business development costs increased $8 million compared to the same period last year and reflect heightened levels of development activity, including work on the potential conversion of a portion of our Canadian Mainline from gas to oil service.

In Energy, comparable EBITDA was $222 million in the fourth quarter compared to $254 million for the same period last year. The $32 million year-over-year decrease was the result of a combination of factors.

Western Power EBITDA was lower in fourth quarter 2012, primarily due to the Sundance A PPA force majeure and the impact of the Sundance B arbitration decision. For the 3 months ended December 31, 2012, TransCanada recognized no earnings in the Sundance A PPA compared to $57 million of EBITDA in fourth quarter 2011. 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 will be relieved of the associated capacity payments. TransAlta has indicated that it expects to return the units to service in the fall of 2013.

In addition, in the fourth quarter, Western Power recorded an $11 million reduction to pretax earnings to reflect the amount that will not be recovered as a result of an arbitration decision that stems from the second quarter 2010 unplanned outage on Sundance B Unit 3. A lower contribution from Bruce Power was responsible -- was primarily due to the Bruce A Unit 4 life extension outage, which commenced in August 2012 and is expected to be completed in late first quarter 2013. As a result, the unit did not generate any revenue in the fourth quarter. The planned outage will extend the operating life of Unit 4 to at least 2021 and align it with Unit 3. In June 2012, Bruce Power returned Unit 3 to service after completing the 7-month West Shift Plus life extension outage.

These declines were partially offset by increased contributions from Eastern Power and U.S. Power. Eastern Power EBITDA increased $12 million compared to the same period in 2011, primarily due to incremental Cartier wind earnings, partially offset by lower Bécancour contract earnings.

U.S. Power EBITDA rose USD 16 million in the fourth quarter compared to the same period last year. The increase was primarily due to higher generation volumes and higher realized power and capacity prices in New York, partially offset by lower earnings in U.S. Hydro facilities due to reduced water flow.

Now turning to the other income statement items on Slide 25. Comparable interest expense in the fourth quarter was $246 million compared to $251 million in the same period last year. The $5 million decrease reflects higher capitalized interest for the Keystone XL and Gulf Coast pipelines, partially offset by lower capitalized interest related to the completed Bruce A restart. In the fourth quarter, $76 million of interest was capitalized to assets under construction compared to $71 million for the same period in 2011.

Comparable interest income and other for fourth quarter 2012 increased $12 million from 2011 due to realized gains in 2012 compared to losses in 2011 on derivatives used to manage the company's net exposure to foreign exchange fluctuations on U.S. dollar income. In combination with U.S. dollar-denominated interest expense, this hedging program largely counterbalances the currency impact of translating U.S. dollar pipeline and Energy income reported in the business segments.

Comparable income taxes of $123 million in fourth quarter 2012 were consistent with last year. Despite lower earnings in the quarter, the company's effective tax rate increased primarily due to higher U.S. pretax earnings, which are taxed at a higher rate, partially offset by a decrease in the Canadian statutory tax rate.

Moving on to cash flow and investing activities on Slide 26. Cash flow was again solid in the fourth quarter and is expected to grow as new assets are placed into service. Funds generated from operations totaled $818 million, a decrease of $19 million from the same period last year. For the full year 2012, the company generated $3.3 billion of funds from operations, which was down modestly from 2011 for the same reasons that earnings declined.

Turning to investing activities. Capital expenditures were approximately $1 billion in the fourth quarter, driven primarily by the Gulf Coast and Keystone XL projects, as well as ongoing expansions on the Alberta System.

Equity investments totaled $95 million and relate to our investment in Bruce Power, including the restart of Units 1 and 2, planned activities related to the life extension of Bruce Unit 4 and capitalized interest.

Acquisitions, net of cash acquired, were $214 million and reflect our purchase of the remaining 40% interest in the cross-sell to gas storage facility in mid-December.

In 2012, we invested $3.5 billion on capital projects, equity investments, acquisitions and maintenance capital. This number includes approximately $300 million of capitalized interest.

Now looking at Slide 27. Our liquidity position and access to capital markets remain strong. At the end of the fourth quarter, our consolidated capital structure consisted of 42% common equity, 4% preferred shares, 2% junior subordinated notes and 52% debt net of cash.

At December 31, we had just over $550 million of cash on hand, along with $4 billion of committed and undrawn revolving bank lines with our high-quality bank group. Our 3 commercial paper programs, 1 in the U.S. and 2 in Canada, are well supported and provide a flexible and very attractive sources of short-term funds.

In January, we issued USD 750 million of 3-year senior notes at a coupon of 0.75% with proceeds used to reduce short-term indebtedness and for general corporate purposes.

In 2013, we expect to spend $6.4 billion in our capital program, which is broken down as follows: $4.1 billion in Oil Pipelines; $1.9 billion in Natural Gas Pipelines; and $400 million in Energy, which includes equity investments and the acquisition of Ontario Solar projects. We are well-positioned to finance our current committed capital program through funds generated from operations, new senior debt, as well as subordinated capital as required in the form of preferred shares, hybrid securities and portfolio management, including LP drop downs. We'll remain opportunistic in sourcing required capital given the unprecedented low interest rate environment.

Looking at the year ahead, we see several key developments which are anticipated to have an impact on earnings in 2013 and beyond. In Natural Gas Pipelines, these include a decision on our current Mainline Tolls Application, which is expected from the NEB in late first or early second quarter, an ongoing expansion of the Alberta System, partially offset by expectations of continued weakness in certain U.S. pipelines due to lower revenues and higher operating costs. We do, however, expect this business to recover over the longer term as our assets adjust to the changing market conditions and pipeline flows.

In Oil Pipelines, the Keystone system is expected to continue generating predictable and stable EBITDA of approximately $700 million per annum. Our Gulf Coast Project, with the late 2013 completion, is not expected to make a meaningful contribution until 2014.

In Energy, the addition of several new assets is expected to generate incremental earnings and cash flow in 2013. These include the restart at Bruce A Units 1 and 2, which are expected to ramp up to full capacity by the end of the first quarter. Bruce Unit 4 life extension outage, which began in August 2012, is expected to be completed by the end of the first quarter. While it is taking longer than first anticipated, Bruce Power has been able to bring forward and complete some additional work that was planned as part of a future outage.

Partially offsetting increased contributions from the Bruce A units will be higher planned outage days on the Bruce B units. Taking into consideration all of the work going on at Bruce Power, the overall planned availability for 2013 at Bruce A is expected to be approximately 90% and in the high 80% range at Bruce B.

Other factors that will affect our Energy business in 2013 include: Sundance A, which is expected to return to service this fall; the acquisition of several Ontario Solar assets; and our recent move to 100% ownership of CrossAlta; a full year contribution from the last phase of Cartier wind; and a more constructive environment that should see a firming up of capacity prices in New York.

As usual, Alberta and U.S. Northeast power prices and Natural Gas Storage spreads will also impact our results in 2013.

Finally, as I've highlighted in the past, on a fully unhedged basis, a $1 per megawatt hour change in the average Alberta power price impacts EBITDA by about $10 million. A $0.10 change per GJ in Alberta gas storage spreads impacts EBITDA by about $8 million. And a $1 per kilowatt month change in New York capacity prices impacts EBITDA by $26 million.

In closing, 2012 was a successful year despite some of the challenges we faced. TransCanada's diverse, high-quality energy infrastructure assets performed relatively well in the fourth quarter and overall in 2012. The majority of our portfolio continued to generate steady and predictable earnings and cash flow.

In 2012, we placed $3.4 billion of new assets into service, and these are expected to contribute incrementally in 2013. We also continued to advance a number of other initiatives, including commencing construction of the USD 2.3 billion Gulf Coast Project and completing the reroute of the USD 5.3 billion Keystone XL pipeline in Nebraska.

We've invested approximately $3.1 billion to date in projects expected to be placed in service by 2015 and are well-positioned to fund the remainder of this capital program. We also secured $16 billion of new projects over the past year, all of which are underpinned by long-term contracts with strong counterparties or regulated cost of service business models.

Finally, we expect to continue to generate significant cash flow that can be used to invest in new accretive growth opportunities, grow the dividend and further enhance our financial strength and flexibility in the years ahead.

In closing, I would like to mention that we expect to file our 2012 annual report to shareholders tomorrow, which contains the consolidated financial statements and accompanying notes, as well as the related MD&A.

That's the end of my prepared remarks. I'll now turn the call back over to Dave for the Q&A

David Moneta

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

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Paul Lechem with CIBC.

Paul Lechem - CIBC World Markets Inc., Research Division

My question's with regard to the Komie North project that was denied by the NEB. I was just wondering, what was different about this application than others you've made, number one. Number two, what now? Do you go back with a different proposal to get this project complete? And finally, does this potentially impact any of the extensions into the North Montney that you proposed to build out?

Karl Johannson

Let me start with the first part of the question, what was different. I think there's one area here that the Board paid particular attention to that is a little different than our other application and it was really the commercial backstopping of this project. The Board did agree with us that the facilities that we proposed were proper. The Board agreed with us that our stakeholder consultations were proper and correct. And they also agreed with us on the total reserve estimates that we had in that area. What the Board didn't accept was our commercial underpinning for the project. We had one customer on that project and we did -- when we initially did set up that project, we expected more customers to come. But with the Horn River development slowing down, with the low gas prices, they never did materialize. So the Board did come back to us, suggested that we would have to relook at the commercial backstopping on this. They suggested that we either get more volumes on the system, longer-term contracts or more customers just in generally, to backstop the system. So how that plays in the future is that TransCanada's still interested in the Komie North project. We are, right now, in the marketplace. We will be talking to our customer on there. And we'll be, over time, gathering new customers to resubmit that application in due course.

Russell K. Girling

I think just, Paul, just to I guess remind you as well that part of the application was approved, the Chinchaga portion of the application, which had sort of a more traditional underpinning to what we've seen in the past on the NGTL system. So your other question, how does it affect our business going forward. I don't think anything really changes with respect to how we move forward on NGTL. They didn't suggest that there's any issue with our tolling methodology or anything like that.

Paul Lechem - CIBC World Markets Inc., Research Division

Okay. So the projects that you're suggesting, your build out in the North Montney related to the LNG pipe service wouldn't be affected by this decision?

Russell K. Girling

No, I think as Karl pointed out, I mean, there's multiple customers and much larger volumes for those projects. So I fully expect that they will be approved similar to our system that we've operated under in the past.

Operator

The next question is from Juan Plessis with Canaccord Genuity.

Juan Plessis - Canaccord Genuity, Research Division

I noticed that your expectations for the Keystone XL approval has shifted a bit to the first half of 2013 from the first quarter. Can you take us through the process as you see it for the Department of State approval for Keystone XL? And more specifically, do you expect there could be another comment period after the State Department issues its supplemental EIS?

Alexander J. Pourbaix

Sure, Juan. It's Alex. Just in terms of the Keystone XL process, obviously, the first thing we're waiting on now is the issuance of the supplemental EIS, which will be largely focused on the reroute in Nebraska. Certainly, what we've heard, I think, what everyone has heard is that the State Department intends to issue the SEIS quite quickly. I mean whether that's 1 week, 2 weeks, it's hard to say, but they've certainly led us to the view that it is imminent. Once the SEIS has been issued, we are of the view that the State Department is in receipt of absolutely every piece of information they could require to make a decision. There are a number of sort of statutory notice periods in the remaining process. I would expect that we would be in a position anywhere between 2 and 3 months to get a decision from the State Department once that SEIS is issued.

Juan Plessis - Canaccord Genuity, Research Division

And just as a follow-up here, there was mention in the MD&A that the Bruce Units 1 and 2 were expected to operate at lower utilization rates in 2013. Can you talk a bit about your expectation for utilization rates for those units? And does the 90% expected utilization for Bruce A in 2013 take this into account?

Alexander J. Pourbaix

Yes, it does. And it'd probably be helpful just to give a little background on that. When we brought those units into service, really, for the first time in their life, they have a -- first and only time in their life, they have a full load of brand-new fuel, and that results in a very energetic core. And just from a safety perspective, what happens is that the units are slightly derated and then over a period of about 3 months, they ramp-up to full power. So that 90% is a good full year number.

Operator

The next question is from Linda Ezergailis with TD Securities.

Linda Ezergailis - TD Securities Equity Research

I realize it's still somewhat early days in your Mainline Conversion project, but you have had some very encouraging conversations recently. So I'm just wondering if you can give us a sense of what the views are on potential ultimate end markets and how the interest is for various terminus points of the pipeline, whether it be Québec City, Montréal or St. John? And what the customer mix is like in terms of shippers that have expressed interest, whether it be mostly producers versus refineries?

Alexander J. Pourbaix

Sure, Linda. Happy to do so. With respect to the Eastern conversion project, as Russ said, we have been advancing discussions with potential shippers, and we are quite pleased and optimistic about how those discussions are going. I think there's a great deal of interest in moving towards those markets. From our perspective, when we look at the markets, there's obviously, there's about a 400,000-barrel a day domestic market in Québec. There's about another 400-odd thousand barrels a day refining capacity in the Maritimes, largely underpinned by Irving. We would see that domestic markets would be largely the focus of the pipeline and potentially I guess, down the Eastern Seaboard. I think initially, those would be the lion's share of the markets. We have talked about a number of termination points for the pipeline, and what I would tell you, there are sort of pros and cons from each of them from our perspective, and they go anywhere from points in Québec to going all the way out to the East Coast. And at the end of the day, we're going to listen to our shippers, and so we haven't reached final conclusion on that aspect of the project yet.

Linda Ezergailis - TD Securities Equity Research

Okay. That's very helpful. And in terms of your business development costs, they've moved around in your various business units. Can you maybe just give us a sense of how they might be trending over the next couple of years?

Alexander J. Pourbaix

Sure. I can talk to mine, and maybe Karl can talk to his, if that's of interest. But I would expect, there's obviously been a downward trend in BD costs on the power side. I think that probably we're at a reasonably good run rate for a period of time, maybe a little potential downside. I -- given all of the opportunities we're seeing on the oil side, I would continue to expect to see some reasonably robust BD numbers come out of the oil side, of course subject always to our desire to capitalize them if we think they're leading towards projects that are going to come into service.

Karl Johannson

And I think on the natural gas side, I think similar to the Energy, I think what you see today is a pretty good run rate for BD cost. We have -- we were expecting some more business to come up to Mexico, so we'll be concentrating our resources there and any further LNG-related projects that we have on the Alberta System.

Operator

The next question is from Carl Kirst with BMO Capital Markets.

Carl L. Kirst - BMO Capital Markets U.S.

Just a couple of questions on the -- going back to the Eastern conversion, and I guess with sort of as the project may be focused more on serving domestic markets rather than perhaps heavy oil export, has that given you a sense, a better sense, of what the magnitude of the pipeline that this is honing in on, and specifically, trying to get a better sense of maybe what size line you'd be lifting out of the Canadian Mainline?

Alexander J. Pourbaix

Sure. Depending -- we've said publicly that we have a number of options with what pipes to take out -- to buy out of regulated service, and that would give us a range of between about 500,000 at the smaller end and possibly up pretty close to 1 million at the upper end. Our gut feel is we'll probably be more past the middle of that range than the bottom end. But as I said, we're still waiting to hear back finally from a number of our potential shippers.

Russell K. Girling

Carl, I agree with Alex. It's Russ. I suspect it will be at the larger diameter pipe to give us the optionality going forward of being able to expand in the future. I think we're seeing a minimal interest in at least sort of the 500,000 to 600,000-barrel a day range. But as you sort of look out, that kind of import level that Alex mentioned would lead you to believe that on the whole Eastern seaboard, in total, between Canada and the United States, we're importing something close to 1.5 million or more barrels a day, which suggests that there's a market out there for domestic production to attach to that market.

Carl L. Kirst - BMO Capital Markets U.S.

Is it still -- I mean I think in prior discussions we thought maybe about, depending on the size of that pipe, between a half and a mil, that we'd be looking anywhere from 1 billion to 2 billion buying out from rate base. If we're looking at a larger diameter piece and we are again locked to settle out here, but if it does go that route, is it possible even to say of that overall 2 billion amount, say for instance, how much of that is associated with what you might call the problematic piece of the mainline right now?

Russell K. Girling

I guess my first comment is that I don't think there is problematic piece of the mainline, it's an integrated piece of infrastructure. I think what we're working through right now -- I'm going to let Karl talk in a second, but what we're working through is ensuring that we have sufficient capacity to meet the needs of our gas customers going forward. And as we've said before, it's a needed piece of infrastructure. So depending on what we do, there's varying amounts of work that we'll have to do to ensure that we can continue to meet their needs going forward. And as you pointed out, it's a dynamic sort of changing environment. But I think the key would be -- is ensuring that the facilities that we repurpose to oil, if they impact our ability to deliver gas, that we can meet the needs of those customers that are actually willing to sign up and pay for that capacity. So I'd say it's early days, Carl, on exactly how that's going to work. But the numbers that you pointed out, we haven't changed our views on those numbers at all.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. Great. And then lastly if I could, just with respect to, Russ, your comments I guess on perhaps following this with an open season. I just wanted to make sure I understood that correctly. Would that be sort of market or customers giving you soft indication and then you'd go to an open season to firm everything up? Or would you only go to an open season if there were minimum commitments that you knew it was going forward and the rest you were just trying to kind of get icing on the cake, so to speak?

Alexander J. Pourbaix

Carl, it's Alex. We're out right now seeking commercial support. And I think at the end of that, as a matter of course, we will follow up with an open season. A, it's a requirement that we do so, and we want to make sure we sop up all the potential barrels that are out there. But we're not -- we wouldn't go to an open season unless we're very comfortable of getting a minimum level of commercial support for [Audio Gap].

Karl Johannson

[Audio Gap] to that, Carl. Is that we're all seeking right now some indication of the questions asked earlier, of receipt points and delivery points. Once we have that, then we know where the project needs to go. And then we have to commence stakeholder discussions along the route. We want to engage with those communities that are [Audio Gap] by that route as quickly as possible, we don't want to [ph] sort of get the cart before the horse here. Because I think it's very important to engage with those communities first and those stakeholders first as well as our shippers in determining what an appropriate route would be to the marketplace. So there is that activity in addition to the open season activity that will take place concurrently. And I guess the third activity that you can think of is when we get into that next phase would be the preparation of a regulatory application, which, assuming all things going well, we'd like to be in position to file by the end of the year.

Operator

The next question is from Matthew Akman with Scotiabank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Don, you mentioned $1.9 billion of CapEx on gas pipes in 2013, and I'm just wondering if any significant portion of that at all relates to the LNG pipelines? And then as a follow-up to that, what are the steps that are necessary that we should be following that need to get put in place before you guys can start putting in significant capital into those projects?

Donald R. Marchand

Yes. The $1.9 billion in gas pipes is broken down roughly as, there's about $600 million to go into Mexico, on the 3 projects we have there. Probably around $600 million, $700 million on the Alberta System, which is regular maintenance capital plus some of the expansions we have on the go. And then we will have some development spend on Coastal GasLink and Prince Rupert. Then to top it all off, there would be maintenance capital across the rest of the portfolio. In Alberta, we would expect to file regulatory applications -- and, Karl, jump in if you wish here, for the expansions related to serving Prince Rupert over the course of this year, and then start some spend probably late this year and then more concentrated in '14 and '15.

Karl Johannson

Yes, our goal would be the end of the year for applications.

Donald R. Marchand

So the stage gates on the Alberta System facilities for the LNG would, I guess, be signing agreements with the shippers there and getting through that regulatory process. That's -- it's really separate from the actual approval processes of Prince Rupert.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

How do your contracts work with your counterparties, with, I guess, Shell and PETRONAS, in looking at the significant amounts you might be spending in development over the next year or 2, leading into regulatory approval?

Donald R. Marchand

Yes. The -- we will spend some amount, in the couple of hundreds of millions of dollars, on those projects to get them to that regulatory phase. If the projects don't proceed, we would get reimbursed for those amounts. And if they do proceed, they would form part of the rate base on those projects.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Okay. Just one other question in the area of power, and then I'll get off the call here. In Northeast power, I noticed that you commented in the fourth quarter that low hydrology impacted there. I'm just wondering if you're seeing that bounce back towards normal at the start of the year as we've seen in some of the other Eastern areas, I guess this is for Alex. And part of my question is also, we've seen very, very robust power prices out there, so I'm just wondering, to what extent you're capturing that in the first quarter here?

Alexander J. Pourbaix

Yes. Thanks, Matthew. I don't have the volumes in front of me. My recollection was that the volumes have -- or certainly are forecast for the full year, is that we're going to bounce off those very, very low hydro volumes that we saw last year. That was kind of a sort of a 1 in a 30 or 40 year event in terms of volumes. In terms of pricing, we are, certainly with the prevailing relatively low prices, we are much less hedged than we typically would be at this time of year. So whenever we see those robust prices, you can imagine that we're going to be capturing a fair chunk of it right now.

Operator

The next question is from Robert Kwan with RBC Capital Markets.

Robert Kwan - RBC Capital Markets, LLC, Research Division

I'll just come back to the Mainline conversion. I'm just wondering if you can give us some sense as to the various timelines as you move forward here, as you move to the open season and how long do you think you'd leave that open for and then be able to finalize the commercial terms? How long do you think political/stakeholder discussions would be. And then last 2 would be regulatory and construction.

Alexander J. Pourbaix

Sure. Happy to do that, Robert. I think you heard Russ say that we would be -- hope to be in a position that we would be filing our various regulatory applications late this year. And if -- you can kind of count backwards from that, if we're hoping to do that by the end of the year, that means we have a significant amount of stakeholder work in preparation of that -- preparation of those applications. I probably -- you would see an open season somewhere between 30 and 60 days. And we're probably going to need a little time here to get through the engagement and the discussion with shippers that Russ had talked about. So probably, you would see an open season, assuming that we're successful in those discussions with stakeholders and shippers, I'm kind of thinking about something towards the end -- near -- in the latter part of Q2, maybe a little earlier.

Robert Kwan - RBC Capital Markets, LLC, Research Division

And then, regulatory you expect to run for a year?

Alexander J. Pourbaix

I think the -- because of the implications of the new bill that was brought into force, the NEB application, once complete, would be 18 months. I'm kind of -- 18 months to 24 months to get through the regulatory process. And then probably think about another 2 years for construction. So looking like 2017 in service.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And just -- the 18 to 24 months in regulatory, that includes both the facilities application and the removal from rate base?

Alexander J. Pourbaix

Yes. That would be our hope.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. Just a last question as it relates to the Mainline, just the toll rate case. I know it's pretty tough to speak of the future ahead of the upcoming decision. But given it only relates through 2013, what are you thinking with respect to a 2014 and beyond process? Are you going to just allow the 2013 to fall and try to use that as a framework? Or is there something greater with some of the developments that we've seen that you'll be pushing for?

Karl Johannson

Well, I think first of all, we're going to wait until we get the '12 and '13 decision here near the end of quarter, early next quarter, and then we'll make a decision from there where we'll go. Clearly, we have to start, we have to turn our mind to 2014-and-on rates, which we're doing right now. But we really can't address that early until we see the guidance and the decision from the board later this quarter.

Operator

The next question is from Andrew Kuske with Credit Suisse.

Andrew M. Kuske - Crédit Suisse AG, Research Division

I guess just a point of clarity on, I guess, the last answer on the potential conversion project. Will you be filing specifically a first application on the Mainline conversion on just withdrawing from rate base and then there's a second application for the actual reversal and any other equipment or new pipe that's needed?

Alexander J. Pourbaix

Yes. There are -- I mean in the past when we did this on base Keystone, there were 2 separate hearings. We are still taking a look at that, and we're thinking there's probably some opportunity to streamline that process from when we went through it the first time. But as we know more, we'll let the market now.

Russell K. Girling

We're in early days, Andrew, of our conversations with stakeholders. As we mentioned, there's a lot of conversation that yet has to occur between -- amongst regulators and amongst federal and provincial jurisdictions in a pipeline that traverses Canada. So we have to do our work as to exactly how we want to make this application, and we're in those discussions as we speak, and those will become more pronounced as -- over the coming months. So we'll have an answer here by the time we get to making a filing. But it will be premature to say exactly what roadmap we're going to use at this point in time. There's a lot of other people that have to provide us with input before we make those decisions.

Andrew M. Kuske - Crédit Suisse AG, Research Division

That's helpful. And then, Alex, just on the U.S. Power, how much outperformance do you think you had relative to your plan on U.S. Power? And how much of that was really related to the storm and the impact of Sandy when some facilities went out, both transmission and generation? Because the quarter looked very good for the U.S. Power versus what we've seen in the past.

Alexander J. Pourbaix

Yes. I think you know it's funny. My take on it was, obviously you don't want to profit from something as problematic as Sandy. But I would say that the -- that we were obviously a very big part of keeping the lights on in New York City and sort of other features. But a lot of units during and around that storm were kind of running on a must-run basis. But the market price actually wasn't representing what it otherwise would've been. In other words, I'm saying prices were quite low given the magnitude of impact on power supply. I think when you look at the quarter, you're seeing a few things. You're seeing the impact of some improvement on capacity markets. We did get some benefit from the extreme weather conditions. But I don't think there was any real overperformance involved there.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Really just the volume itself is on a per megawatt basis, just on some simple calcs, your per meg numbers were actually down versus a year ago, but your volume is up dramatically. So is it really just the volume and being one of the sole generators that was still operating during that period?

Alexander J. Pourbaix

Yes. There's no doubt that all of our assets were running pretty much full-out during that period.

Andrew M. Kuske - Crédit Suisse AG, Research Division

Okay. And then just if I can, one final question on the Bruce. What kind of tilt do you think you're going to have on your operating levels? I know the MD&A talked about 90% on the As through the year. Is that your 90% at the end of Q1 for the rest of the year? Or do you have a little bit of a tilt going through the first quarter?

Alexander J. Pourbaix

Yes. I think you can think about that kind of tilting upward, like hitting an overall average of 90% and getting there by, in the second half of the year, having availabilities higher than 90%.

Operator

The next question is from Steven Paget with FirstEnergy Capital.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Just first question. What's the average price for the Western megawatts you've contracted in 2013 and 2014?

Alexander J. Pourbaix

I always get a little uncomfortable with this, Steven. I'm stepping back a little bit about giving sort of guidance on what we've actually sold for. But what I would say is that forwards in 2013 are kind of in sort of higher 50s. 2014 right now we're probably still pretty low, around 50%. And our hedging activities would be significantly north of both of those prices for those years, or some degree north of that.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

North of both of those prices. Second question, if the Mainline was converted, some shippers could see a benefit from lower gas tolls, while other shippers aren't really so worried about those same tolls. Is there any discussions between the 2 groups of shippers and the allocation of economic benefits?

Karl Johannson

It's a little premature to be having that discussion. Right now, we're really still in the process of getting commercial confirmation of our project. When we do get -- if we do move to the next step, I'm quite certain the discussion will be around how much rate base goes out, which facilities go out. I don't anticipate, at least initially, a discussion on giving up the pie so to speak, I'm expecting we will talk asset-specific.

Russell K. Girling

Yes, Steven, historically that hasn't been the nature of the process for our regulated assets. The criteria is public interest, the overall public interest. And they make their determination based on what is the greatest good for the greatest number, and they look at the overall number, and they opine based on that. As opposed to sort of sorting out the winners and losers in a process. It's the overall public interest which is the guiding factor. And that's what I suspect, again, why we're encouraged that obviously from a Canadian interest perspective, there's tremendous benefits from the repurposing. I think folks have seen the impact of the curtailment of -- or the lack of capacity leaving the Western Sedimentary Basin, the impact on netbacks for producers, which impact royalties, which impact taxes and impact the Canadian economy to a great degree. So those are, I think, the overriding factors driving folks to say that this is something that Canada -- is in Canada's interest and we should take a pretty hard look at it. As you just point out, there'll be individuals within that process or within that context that win or lose to a greater degree. But I think the board, the National Energy Board's primary decision criteria is in the overall public interest.

Operator

The next question is from Chad Friess with UBS.

Chad Friess - UBS Investment Bank, Research Division

Hopefully my Mainline question is the last. I was wondering, what do you view as the primary threat to your Mainline conversion project? I mean, I know there's a lot of railing going into Eastern markets, which is cost flexible and fairly expensive. But it seems like there's also the potential to cheaply move oil from the U.S. Gulf to Eastern markets through tankers. I know there's regulatory hurdles there, but I wonder if you could speak to how your potential project compares on tolls for those sorts of solutions as well as unit train railing?

Alexander J. Pourbaix

Well, I think, I certainly think, given the experience we've had on Keystone XL and my observations, that I think getting -- the U.S. getting its head around exporting crude oil when they are so focused on energy independence is -- that's probably a long shot of Marine transits coming out of the Gulf into the Canadian markets. With respect to rail, we obviously are seeing some increased rail movements. I think, fundamentally, looking at kind of the toll that we think we can do out towards East Coast, rail is at least twice as expensive as the pipeline option. And I would argue that if there is a concern about the environment, every barrel you move by rail emits 3x the GHG that a barrel moved by pipe does. And it's in order of magnitude at least more likely to have a spill. So I just think on sort of all of the bases, ultimately, if we're going to be moving the kind of volumes of oil that we're talking about here, and our customers are talking about, then I really think ultimately, everyone wants to get to a pipeline solution.

Russell K. Girling

Chad, I guess just add to Alex comments. What we'll do is we'll let the market decide. There are many alternatives, as you point out, to move the crude. The drivers here are growing production in both Canada and the United States needing to get to markets. The primary markets that they need to get to are those places where we import oil into North America, primarily that's the Gulf Coast, the East Coast of the United States and the Eastern coast of Canada. So right now, there are other alternatives being employed to get that crude to market. Ultimately, the market will decide which alternatives they're going to choose, and we've always been a market-driven company, and I think what I said earlier is our conversations with both producers and refiners to date would indicate that the Eastern Mainline conversion places very high in terms of how they would view that relative to their other alternatives. And based on that encouragement, that's what we're moving forward with here is that they're saying they've look at those other alternative means and for the safety and economic reasons that Alex has mentioned, we believe that we're going to get a very favorable response to our proposal.

Operator

The next question is from Ted Durbin with Goldman Sachs.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

If you can just give us an update on how you're thinking about potentially other conversions of your gas pipeline assets, whether it's regional oil sands or maybe even some of the U.S. pipes that are seeing lower volumes? Is there anything that you're thinking about there? I'm even thinking about GTN and Northern California, maybe just talk about any strategy there?

Alexander J. Pourbaix

I guess what I would say, Ted, is we are constantly looking at our suite of assets to make sure that they're in their highest and most valuable use. And I -- obviously we have a lot of time and effort tied up in this Eastern conversion project that we've been talking about. But I wouldn't have anyone think that while we're looking at that, we aren't considering other options. And to the extent that we see spare capacity that isn't otherwise being utilized, we're going to take a really hard look at it. But right now, the most advanced of those ideas is the Eastern conversion project.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Got it. And then another quick one for me is we've bumped the dividend here again, we're at $1.84. We just had $1.89 of EPS. Obviously pretty high payout ratio on a trailing basis. I guess I'm just wondering how you're thinking about the payout ratio going forward and how we should think about dividend growth going forward?

Donald R. Marchand

Dividend growth will follow earnings growth. We've talked about some of the anomalies of 2012. We do have a lot of projects coming onstream. We also still have a lot of capital that's tied up in projects that aren't generating any revenue yet. So if you look at things like Gulf Coast, Keystone XL, even Bruce, where we did bring $2.4 billion into service in the fourth quarter, but we won't see a normalized run rate for -- certainly in the first quarter of this year. As these things come onstream, there are very predictable earnings streams, and we're quite comfortable that we'll grow our way back into more of a normalized payout ratio, which historically we've been in that 70% to 80% earnings payout range. We expect to gravitate back there over time. That equates to about 1/3 of cash flow. So that's kind of where -- I'd point you in that direction.

Operator

The next question is from Dennis Coleman with Bank of America Merrill Lynch.

Dennis P. Coleman - BofA Merrill Lynch, Research Division

I have a question with regard to the elections coming up in BC, I guess there's been some rhetoric there that would seem to complicate the regulatory process even further. I wonder if you might just comment on the outlook there and potential outcomes and how that impacts some of your projects going west?

Russell K. Girling

Guess what I would say is that our projects going west are 2 natural gas pipeline projects to move primarily natural gas out of Northeast British Columbia. From what we've seen to date, both at a provincial level but also at a local community level from a political perspective, those developments, the value chain of those developments are significant economic generators, significant job generators, and therefore, appear to have the support of local communities as well as the provincial government. And all of the parties that I'm aware of at the provincial level have all endorsed the movement of British Columbia produced natural gas to West Coast LNG export terminals.

Dennis P. Coleman - BofA Merrill Lynch, Research Division

So the key there is then its oil versus gas, is that...

Russell K. Girling

I'd say that we're not building oil projects into British Columbia, but our -- so I can only speak to our experience on the gas projects. And so far, so good. We engaged immediately with communities along the right of way. And so far, we have had a positive reception in all of those communities.

Operator

Questions will now be taken from the media. [Operator Instructions] First question is from Rebecca Penty with Bloomberg News.

Rebecca Penty

I have a couple of questions actually. I'll ask the first one now. I'm wondering if someone can elaborate on I think there was a point about splitting up the Grand Rapids pipeline and splitting up construction or the time line for in-service. Maybe if someone can elaborate if that's the case on what's going on there and why?

Alexander J. Pourbaix

Sure, Rebecca. It's Alex Pourbaix. I'm happy to talk about that. When we announced Grand Rapids, we were anticipating we're building a 36-inch line to deliver from the Grand Rapids region down to the terminus of the pipeline. But we're also planning on putting in place a 20-inch diluent line bringing diluent up north, the opposite direction. The original plan was that we would have that combined project in place in 2017. And we saw the opportunity to actually get that 20-inch pipeline, the diluent line, in-service earlier, but moving blended bitumen south. So what we're going to do, we can have that 20-inch line in-service in 2015, and that probably about 100,000 barrels a day, and then that will be mid-2015. And then by early 2017, we'll be able to bring the 36-inch larger line in-service and be able to move the full 900,000 barrels a day of blend from Fort McMurray down into Edmonton. And at that time, we'll reverse the diluent line to be bringing about 300,000, 330,000 barrels of diluent north, total.

Russell K. Girling

Rebecca, essentially what it does is it allows the production to start ramping on early and grow into its ultimate production. But we can start moving that crude via pipeline earlier by putting the 20-inch line in-service and allowing for that ramp-up to occur.

Rebecca Penty

Okay, great. I just have one follow-up question and this is from a colleague who's writing about TransCanada's debt. Wondering if the Keystone XL decision, if TransCanada gets an approval from the U.S., do you expect to see any reaction in the bond market on your debt on that approval?

Donald R. Marchand

No, we wouldn't -- our credit spreads are -- have been pretty consistent here. We wouldn't expect any rating reaction. It would be a credit positive for the company to move that capital that we've expended into revenue, and it's a great diversifier for the portfolio and a great contractual structure. But in and of itself, no, we wouldn't expect a major reaction in the bond market.

Operator

The next question is from Jeff Jones with Reuters.

Jeffrey Jones

I have a couple of questions. First of all, with regard to the Mainline conversion project, does it make any sense at all to take the line when it gets from the end of the current Mainline to say St. John by going through the United States? Or does that sort of defeat its purpose from a regulatory standpoint, because the route is shorter that way?

Alexander J. Pourbaix

Yes. But I think, number one, if you were to do that, there would be a regulatory process in the U.S. that would be incremental to the Canadian process that we're already committed to go through. So I think the idea of streamlining the regulatory process by just dealing with Canadian regulators, obviously, has some attractiveness. The other comment I would say is that a good -- TransCanada has significant existing assets and right-of-way in Eastern Canada. And by going on the Canadian route, we would be able to maximize the distance that the project would go on, on existing right-of-way or via existing pipe.

Jeffrey Jones

Okay. And then secondly, maybe on a slightly larger note, although Mainline conversion is a good name, do you have a more permanent name for this project?

Alexander J. Pourbaix

We've got our thinking caps on. We have a few ideas that a -- we'll wait and see when we are able to announce that we have shipper and stakeholder support, and I'm sure we can come out with something a little more interesting for everybody.

Operator

The next question is from Nathan VanderKlippe with The Globe and Mail.

Nathan VanderKlippe

Just -- I wanted to actually re-ask a question that was asked before, I don't think there was an answer given. But can you give us any sense of the breakdown between shippers and refiners as far as the interest in holding capacity on this Mainline conversion?

Alexander J. Pourbaix

I did, and it wasn't on purpose. I just neglected to answer that. Nathan, we're seeing interest on both sides. But until we get the final commitments in, it's hard to know where it's going to fall out. But definitely, we are seeing interest at this point from both sides.

Russell K. Girling

I think, Nathan, similar to the Keystone XL experience, what we found was that producers and refiners talk to each other on a continuous basis. There'll likely be some contracting between producers and refiners, and then between them, they'll decide which party takes the transportation capacity, and some of that conversation is going on. So it's sort of early to tell, but I think what -- based on -- similar to what Alex said to you is that there'll be interest from both sides. Who actually is the title holder of the transportation will be the subject of some of their supply and market agreements.

Nathan VanderKlippe

And I wanted to ask too, as far as getting into New Brunswick,, if that is the option that you choose, would that have to be new-build sort of beyond Montréal? Or are there existing gas pipes or other sorts of pipes you could actually use to get there?

Alexander J. Pourbaix

Beyond Montréal, there are really no existing pipes that I think would be suitable. There is existing right-of-way that could potentially be utilized to Québec. And if the project were to go north of Québec, then that would be a greenfield construction for that element of it.

Nathan VanderKlippe

And just one last question, and perhaps more of a general question, but Russ, how closely do you look to something like the state of the union address tonight for indications on Keystone XL?

Russell K. Girling

As I think I've said before is that the regulatory process is what I look to. As Alex said, the next major step to occur is the issuance of the SEIS, and that's where we'll take our cue from, as to what the next steps in the process are and how long they'll take.

Operator

The next question is from Elsie Ross with the Daily Royal Bulletin

Elsie Ross

Just a fast question here. Are you talking about heavy oil or light oil or a combination on the Mainline conversion?

Alexander J. Pourbaix

I think our view is that, especially initially, we would think that much of the oil moving on this project would be light oil. And that would either be from sort of the Saskatchewan or synthetic crude from Alberta. Most of the refineries in Ontario, Québec, Eastern Canada, are more configured to run light oils right now. And I think initially, that would be most of what would be transported.

Russell K. Girling

We'll find out, Elsie, obviously what the market tells us in terms of what it wants to ship and to where it wants to ship it to.

Elsie Ross

Okay. And the other question is, on the LNG side, what sort of expansions are you looking at in Alberta to connect up into BC?

Karl Johannson

Right now, our 2 projects both originate from the Montney area, in Northeast BC. And one is what I would call North Montney and the other is right at the Groundbirch pipeline. We are talking to not only the company that we've contracted with, Progress. But we're talking with the other companies in the North Montney area to expand our NOVA system north up in the North Montney. So we are really staying in, and we're right now in the footprint of, the Montney area and just expanding the existing infrastructure there.

Russell K. Girling

Elsie, the NGTL system will be connected as a delivery point to both of our proposed projects that move to the West Coast. But as well, all of that production, if you will, in Northeast British Columbia will be connected to the NGTL system, and it will have access to all the markets that NGTL can access. So that's one of the flexibility benefits that the TransCanada brings to the table in its NGTL system, is the ability to bring on that production over the next 3, 4, 5 years. We don't see moving the gas to the West Coast until towards the end of the decade. So in between that period of time, that new production is going to look for a home and obviously being connected to Alberta and its downstream markets will be very beneficial to those producers.

Operator

The next question is from John Spears with the Toronto Star.

John Spears

I have a question about the figure of $250 million that you say is the compensation that you've received from the Ontario government because of the cancellation of the Oakville power plant and moving it to Napanee. They say that, that $250 million is offset by lower payments that you will receive during the course of the contract. And they put a value of about $210 million on those lower payments that you'll receive, because it's a lower net revenue requirement. Do you agree with that figure, that the $250 million will be offset by the $210 million over the course of the contract?

Alexander J. Pourbaix

Yes. In essence, there is a reduction in the net revenue requirement, which was largely created by us transferring that equipment from TransCanada to the OPA.

Russell K. Girling

The equipment still will be used in the Napanee facility.

Alexander J. Pourbaix

Yes, it's used in the Napanee facility.

John Spears

Right, okay. But the $250 million payment that you're receiving is offset over the course by that $210 million?

Alexander J. Pourbaix

Yes.

John Spears

Of the lower net revenue requirement.

Alexander J. Pourbaix

Yes, there is definitely a lower net revenue requirement that would be largely driven by the transfer of that equipment.

Operator

The next question is from Tonya Zelinsky with Upstream.

Tonya Zelinsky

I'm going to change direction here. I'm wondering, has there been any updates or changes with regards to the Alaska Pipeline Project?

Alexander J. Pourbaix

The latest in Alaska that we updated folks on was that we had suspended the work on the auction to come to the lower 48 with a pipeline. And have redirected our work if you will to a feasibility study with respect to LNG off the West Coast. That's ongoing. And it's a study that's being done jointly by ourselves -- by the 3 major producers in the region, ConocoPhillips, BP and then Exxon and the State of Alaska as our partner under the AGIA license. And I would say that we would expect -- I think the governor of Alaska has said that he expects that, that project will come to conclusion by the middle of February. And based on that, we'll determine our next step forward. My view would be is that West Coast LNG off the coast of Alaska is likely economic. And therefore, from that point, I would expect a conversation to ensue as to delivery points again, where and how. And then the issue that always arises in any discussions about the development of gas in Alaska, is what will the fiscal regime look like going forward for those producers. And by fiscal regime, I'm talking about the royalty rate that will apply to that production, both in terms of quantum and over what time frame that royalty rate is applied. And if they can come to a conclusion on that between the producers and the state, there's opportunity to advance an LNG project in Alaska.

Tonya Zelinsky

Are you optimistic given that there are proposed changes to the current tax structure and royalties?

Alexander J. Pourbaix

I think what you were referring to likely would be the tax and royalty structure around crude oil production, which I think has some ancillary benefits to the discussion on gas royalties. But I think the gas royalty discussion is somewhat separate from that.

Operator

The next question is from Geoff Bird with allnovascotia.com.

Geoff Bird

Sorry if I missed this earlier. I was just looking for a capital cost for the Mainline conversion project?

Alexander J. Pourbaix

We haven't put out an actual capital cost number yet. And it will be dependent upon the volume, which will then drive both the line that we need to take out of service, and then what are the receipt points, what are the delivery points. And so we haven't announced a capital number yet. But I think that our view would be is it -- you can think of it as being a number that's comparable to some of the numbers that the people have used for getting a pipeline to the West Coast. Given that its existing pipe in the ground, existing right of way, we think that we can get to Eastern markets for a comparable toll, if you will, to what you can move oil to the West Coast for.

Operator

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

David Moneta

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

Operator

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

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