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.
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. 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 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 with an equal opportunity to participate, we ask that you limit your questions to two. If you have any additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Lee and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties.
For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, I'd also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation, and amortization or EBITDA, 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. With that, I'll now turn the call over to Russ.
Thanks, David, and good afternoon, everybody, and thank you for joining us for our first quarterly conference call of 2013. I'm starting with some highlights in 2012. As I 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 provide the visible growth for our company for many years to come. Financially, we performed relatively well in 2012 with comparable earnings of CAD 1.33 billion or CAD 1.89 a share.
Unfortunately, earnings in 2012 were impacted by lengthy delays in the startup 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 to 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 CAD 3.4 billion of new assets into service, and they started operations. We saw the startup of the Bruce Units 1 and 2 late last year. We expect a return to service of Unit 4 this quarter. The Sundance A issue, as I said, was resolved 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 on 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. Lastly, and probably one of the most significant accomplishments of the year was 2012 did present us with some unprecedented opportunities for high-quality, long-term growth in each of our three core businesses.
Since the beginning of 2012, we've secured about CAD 16 billion of new projects, which include the Coastal GasLink project, the Prince Rupert Project, the Topolobampo, Mazatlán, 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 CAD 25 billion in projects to bring on stream over the balance of this decade.
Between now and 2015, we expect to complete about CAD 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, 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 they're 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 CAD 318 million for the quarter, or CAD 0.45 a share.
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 Western Power, primarily resulting from the loss of Sundance A stake 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 CAD 1.1 billion, with funds generated from operations at CAD 118 million. Today, the board of directors declared a quarterly dividend of CAD 0.46 per common share per quarter for the quarter ending March 31st, 2013. On an annual basis, that translates into a 5% increase from CAD 1.76 to CAD 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. Starting with the Gulf Coast Project, 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. Many of you might be aware as well, many out-of-state professional, what do 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, the spin-off of 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. Producers don't have sufficient access to pipeline capacity to move this production to market, primarily in the U.S. Gulf Coast. 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 about 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 re-route 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 re-route now becomes part of the project's presidential permit application with the U.S. Department of State, which was filed on May 4th, 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 Americans' 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 will 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 CAD 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 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 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. I would say to date, those discussions have been 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 as the jobs that those refiners provide, along with allowing Canadians to benefit from oil produced in their own country. Our expectation is that we'll be in 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 Gas Transmission project. We were selected by Progress to design, build, and operate the CAD 5 billion pipeline.
It's proposed that it would 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 GasLink 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 CAD 1 billion-CAD 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 CAD 650 million in pipeline projects. This included the completion of the CAD 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 CAD 640 million worth of additional expansions in 2012, including the CAD 160 million Leismer-Kettle River crossover project, which is intended to provide increased capacity to meet growing demand in Northeast Alberta. A further CAD 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 CAD 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 CAD 1 billion Topolobampo pipeline project.
The pipeline project is supported by a 25-year contract with the Mexican state-owned electricity utility, CFE, with a capacity of 670 million cubic feet a day. This project is expected to be operational by mid-2016. Just a few days after we announced that project, TransCanada was awarded another large project in Mexico, the Mazatlán project. This $400 million 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 that the Canadian Mainline remains a critical piece of 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 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 offline for the month of November for maintenance.
Bruce Power 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 the first quarter of 2013, following work that started in August of 2012. 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 Power 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. In Ontario, in mid-December, we signed a 20-year contract with the Ontario Power Authority to develop, own, and operate the 900-megawatt natural gas-fired power facility in Ontario. Located in a 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 CAD 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. In addition, we expect to invest approximately CAD 1 billion in that facility. Finally, on the power side, the last of five 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 MW, Cartier has the capacity to meet the power needs of more than 100,000 Québec homes. All of the power produced by this project is sold to Hydro-Québec under a 20-year power purchase agreement. As you can tell, in conclusion, TransCanada did make significant progress in 2012 building long-term shareholder value. We commercially secured CAD 16 billion of new projects, bringing our portfolio of commercially secured projects to CAD 25 billion. Over the next three years, we expect to complete CAD 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 one 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 three of our core businesses. 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?
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's 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. CAD 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 CAD 16 billion of new projects over the last year in its three core businesses.
These projects will further diversify the company's portfolio and contribute to sustainable earnings, cash flow, and dividend growth in the future. 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 CAD 318 million, or CAD 0.45 per share, decreased by CAD 47 million or CAD 0.07 per share compared to the same period in 2011. Lower contributions from Western Power, Bruce Power, the Canadian Mainline, ANR, and Great Lakes more than offset increased income from the Alberta system, Eastern Power, and US Power. On a per-share basis, changes in comparable earnings for fourth quarter 2012 compared to 2011 are summarized as follows. Earnings rose CAD 0.04 from improvements in Eastern Power, US Power, and the Alberta system.
In energy, the Sundance A force majeure caused EPS to decline by about CAD 0.06, and planned outages at Bruce Power decreased EPS by an additional CAD 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 CAD 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. 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 CAD 690 million in the fourth quarter of 2012, compared to CAD 716 million for the same period last year.
The CAD 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 from GTN and Mexican pipelines. Our 2012 Canadian Mainline results excluded incentive earnings generated in prior years under a five-year settlement that expired on December 31st, 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 a 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 CAD 180 million of EBITDA in the fourth quarter, which was comparable with 2011. Business development costs increased CAD 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 CAD 222 million in the fourth quarter compared to CAD 254 million for the same period last year. The CAD 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 a Sundance B arbitration decision. For the three months ended December 31st, 2012, TransCanada recognized no earnings from the Sundance A PPA compared to CAD 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 it expects to return the units to service in the fall of 2013.
In addition, in the fourth quarter, Western Power recorded a CAD 11 million reduction to pre-tax 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 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 seven-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 CAD 12 million compared to the same period in 2011, primarily due to incremental Part II wind earnings, partially offset by lower BIC and core contract earnings. U.S. Power EBITDA rose $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 from 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 CAD 246 million, compared to CAD 251 million in the same period last year. The CAD 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, CAD 76 million of interest was capitalized to assets under construction, compared to CAD 71 million for the same period in 2011. Comparable interest income and other for fourth quarter 2012 increased CAD 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 CAD 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. pre-tax 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 CAD 818 million, a decrease of CAD 19 million from the same period last year. For the full year 2012, the company generated CAD 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 CAD 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 CAD 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 CAD 214 million and reflect our purchase of the remaining 40% interest in the CrossAlta Gas Storage Facility in mid-December. In 2012, we invested CAD 3.5 billion on capital projects, equity investments, acquisitions, and maintenance capital. This number includes approximately CAD 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 CAD 550 million of cash on hand, along with CAD 4 billion of committed and undrawn revolving bank lines with our high-quality bank group. Our three commercial paper programs, one in the U.S. and two in Canada, are well supported and provide a flexible and very attractive sources of short-term funds.
In January, we issued $750 million of three-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 CAD 6.4 billion in our capital program, which is broken down as follows, CAD 4.1 billion in oil pipelines, CAD 1.9 billion in natural gas pipelines, and CAD 400 million in energy, which includes equity investments in 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 will 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, and 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 restarted Bruce A units 1 and 2, which are expected to ramp up to full capacity by the end of the first quarter. The Bruce unit four 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 plant 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 CAD 1 per megawatt-hour change in the average Alberta power price impacts EBITDA by about CAD 10 million. A 10-cent change per GJ in Alberta gas storage spreads impacts EBITDA by about CAD 8 million. A CAD 1 per kilowatt-month change in New York capacity prices impacts EBITDA by CAD 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 CAD 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 $2.3 billion Gulf Coast project and completing the reroute of the $5.3 billion Keystone XL pipeline in Nebraska. We've invested approximately CAD 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 CAD 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 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.
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.
Thank you, Mr. Moneta. Questions will now be taken from the telephone lines. If you wish to ask a question at this time, please press *1 on your telephone keypad. If you are using a speakerphone, please ensure that you lift your handset before you make any selections. If you wish to cancel your question, you may do so at any time by pressing the pound sign. Please press *1 at this time if you have any questions. There will be a brief pause while participants register. Thank you for your patience.
The first question is from Paul Lechem with CIBC. Please go ahead.
Thank you. Good afternoon. My questions are 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? Finally, does this potentially impact any of the extensions into the North Montney that you proposed to build out?
Let me start with the first part of the question, what was different. I think there was 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. 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 when we initially did set up that project, we expected more customers to come. With the Horn River development slowing down with the low gas prices, they never did materialize.
The board did come back to us, suggested that we would have to re-look 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 general to backstop the system. How that plays in the future is that TransCanada is still interested in the Komie North project. We are right now in the marketplace. We'll be talking to our customer on there, and we'll be, over time, gathering new customers to resubmit that application in due course.
I think, 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'd seen in the past on the NGTL System. Your other question, how does this 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 was any issue with our tolling methodology or anything like that.
Okay. The projects that you're suggesting you build out in the North Montney related to the LNG pipes, those wouldn't be affected by this decision?
No, I think as Carl pointed out, there's multiple customers and much larger volumes for those projects. I fully expect that they'll be approved similar to our system that we've operated under in the past.
Okay. Thank you very much.
Thanks, Paul.
Thank you. The next question is from Juan Plessis with Canaccord Genuity. Please go ahead.
Thanks very much. 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 U.S. Department of State approval for Keystone XL? More specifically, do you expect there could be another comment period after the State Department issues its supplemental EIS?
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. Whether that's one week, two 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.
Great. Thanks very much for that. 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.
Mm-hmm.
Can you talk a bit about your expectation for utilization rates for those units? Does the 90% expected utilization for Bruce A in 2013 take this into account?
Yeah, it does. 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 full load of brand-new fuel, and that results in a very energetic core. Just from a safety perspective, what happens is that the units are slightly derated, and then over a period of about three months, they ramp up to full power. That 90% is a good full-year number.
Okay. Thank you very much.
No problem.
Thank you. The next question is from Linda Ezergailis with TD Securities. Please go ahead.
Thank you. I realize it's still somewhat early days in your mainline conversion project, but you have had some very encouraging conversations recently. 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 Quebec City, Montreal, or St. John. What the customer mix is like in terms of shippers that have expressed interest, whether it be mostly producers versus refiners.
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 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.
What I would tell you, there's 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. At the end of the day, we're going to listen to our shippers. We haven't reached a final conclusion on that aspect of the project yet.
Okay. That's very helpful. 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?
Sure. I can talk to mine and maybe Carl can talk to his, if that's of interest. 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. 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, subject always to our desire to capitalize them if we think they're leading towards projects that are going to come into service.
I think on the natural gas side, I think what you see today is a pretty good run rate for BD costs. We're expecting some more business to come up in Mexico, so we'll be concentrating our resources there and any further LNG-related projects that we have on the Alberta system.
Great. Thank you.
Thanks, Linda.
Thank you. The next question is from Carl Kirst with BMO Capital Markets. Your line is now open. Please go ahead.
Thanks. Good afternoon, everybody. Just a couple of questions on 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 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?
Sure. We've said publicly that we have a number of options with what pipes 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 it will 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.
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 what we're seeing, minimal interest in at least sort of the 500,000-600,000 barrel a day range. As you sort of look out, the kinds of import levels that Alex mentioned would lead you to believe that on the whole Eastern Seaboard, in total between Canada and 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.
I think in prior discussions, we thought maybe about, depending on the size of that pipe between the half and the mil, that we'd be looking anywhere from CAD 1 billion-CAD 2 billion of buying out from rate base. If we're looking at a larger diameter piece, and we are, again, a lot to settle out here, but if it does go that route, is it possible even to say of that overall CAD 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?
No. I guess my first comment is that I don't think there is a 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. As we've said before, it's a needed piece of infrastructure. Depending on what we do, there's varying amounts of work that we will have to do to ensure that we can continue to meet their needs going forward. As you point out, it's a dynamic, sort of, changing environment.
I think the key would be 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, Karl, on exactly how that's going to work. The numbers that you pointed out, that we haven't changed our views on those numbers at all.
Okay, great. 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 get icing on the cake, so to speak?
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. 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. We wouldn't go to an open season unless we are very comfortable of getting a minimum level of commercial support for the project.
May I just add to that, Carl, is that we're out seeking, right now, some indication of, the question was asked earlier, of receipt points and delivery points on the system. 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 going to be impacted by that route as quickly as we possibly can. We don't want to sort of get the cart before the horse here, as 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. There's that activity in addition to the open season activity that'll take place concurrently.
I guess the third activity that you can think of is, when we get into that next phase, 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.
Great. Appreciate all the color, guys.
Thanks, Carl.
Thank you. The next question is from Matthew Akman with Scotiabank. Please go ahead.
Thanks very much. Don, you mentioned the CAD 1.9 billion of CapEx on gas pipes in 2013. I'm just wondering if any significant portion of that at all relates to the LNG pipelines. 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?
Yeah. Excuse me. The CAD 1.9 billion in gas pipes is broken down roughly as about CAD 600 million to go into Mexico on the three projects we have there. Probably around CAD 600 million-CAD 700 million on the Alberta system, which is regular maintenance capital plus some of the expansions we have on the go. We will have some development spend on Coastal GasLink and Prince Rupert. To top it all off 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. Start some spend probably late this year and then more concentrated in 2014 and 2015.
Yeah. Our goal would be the end of the year for-
Yeah
applications.
Yeah. The stage gates on the Alberta system facilities for the LNG would, I guess, be signing agreements with the shippers there and then getting through that regulatory process. It's really separate from the actual approval processes of Prince Rupert.
How do your contracts work with your counterparties, with, I guess, Shell and Petronas, and looking at the significant amounts you might be spending in development over the next year or two, leading into regulatory approval?
We will spend some amount in a couple hundred million dollars on those projects to get them to that regulatory phase. If the projects don't proceed, we would get reimbursed for those amounts. If they do proceed, they would form part of the rate base on those projects.
Okay, thanks for that. Just one other question in the area of power, and then I'll get off the call here. In Eastern 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.
Yeah.
that part of my question is also, we've seen very, very robust power prices out there. I'm just wondering to what extent you're capturing that in the first quarter here.
Yeah. Thanks, Matthew. I don't have the-
I don't have the volumes in front of me. My recollection was that the volumes have improved, or certainly our 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 sort of a one in a 30- or 40-year event in terms of volumes. In terms of pricing, certainly, with the prevailing relatively low prices, we are much less hedged than we typically would be at this time of year. Whenever we see those robust prices, you can imagine that we're going to be capturing a fair chunk of it right now.
Okay. Thanks a lot, guys. Those are my questions.
Thanks.
Thank you.
Thank you. The next question is from Robert Kwan with RBC Capital Markets. Please go ahead.
Thank you. 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. 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? Lastly, it would be regulatory and construction.
Sure. Happy to do that, Robert. I think you heard Russ say that we would hope to be in a position that we would be filing our various regulatory applications late this year. 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 and preparation of those applications. 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. 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 of or in the latter part of Q2, maybe a little earlier.
Okay. Regulatory, you expect to run for a year?
I think 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. Then probably think about another 2 years for construction. Looking like 2017 in service.
Okay. Just the 18-24 months in regulatory, that includes both the facilities application and the removal from rate base?
Yeah, that would be our hope.
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?
Well, I think, first of all, we're going to wait till we get the 2012 and 2013 decision here near the end of the quarter or early next quarter, and then we'll make a decision from there, where we will go. Clearly, we have to turn our mind to 2014 and on rates, which we're doing right now, but we really can't address that thoroughly until we see what the guidance and the decision from the board is later this quarter.
Okay. That's great. Thanks, Alex. Thanks, Russ.
Thank you.
Thank you. The next question is from Andrew Kuske with Credit Suisse. Please go ahead.
Thank you. Good afternoon. I guess just a point of clarity on, I guess, the last answer on the potential conversion project. Will you be filing specifically 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?
Yeah. In the past, when we did this on the Keystone, there were two separate hearings. We're 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. As we know more, we'll let the market know.
Yeah. We're in early days, Andrew, of our conversations with stakeholders. As I mentioned, there's a lot of conversation that yet has to occur among regulators, among federal and provincial jurisdictions in a pipeline that traverses Canada. 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 over the coming months. We'll have an answer here by the time we get to making a filing, but it'd 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.
Okay, that's helpful. 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 to both transmission and generation? Because the quarter looked very good for the U.S. Power versus what we've seen in the past.
Yeah. I think 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 we were obviously a very big part of keeping the lights on in New York City and other areas. 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. I don't think there was any real over-performance involved there.
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. Is it really just the volume and being one of the sole generators that was still operating during that period?
Yeah. There's no doubt that all of our assets were running pretty much full out during that period.
Okay. 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 A's through the year. Is that 90% at the end of Q1 for the rest of the year? Do we have a little bit of a tilt going through the first quarter?
Yeah, 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%.
Okay. That's great. Thank you.
Okay.
Thank you. The next question is from Steven Paget with FirstEnergy Capital. Please go ahead.
Thank you. Just first question, what's the average price for the Western megawatts you've contracted in 2013 and 2014?
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 the 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.
North of both of those prices. Thank you, Alex.
You're welcome.
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 two groups of shippers and the allocation of economic benefits?
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. 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 divvying up the pie, so to speak. I'm expecting we'll talk asset specific.
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 apply 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. That's what I suspect, again, why we're encouraged. I think 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 net backs for producers, which impacts royalties, which impact taxes and impact the Canadian economy to a great degree.
Those are, I think, the overriding factors driving folks to say that this is something that is in Canada's interest, and we should take a pretty hard look at it. As you point out, there'll be individuals within that process or within that context that win or lose to a greater degree. I think the National Energy Board's primary decision criteria is in the overall public interest.
Okay, gentlemen. Thank you. Those are my questions.
Thank you. The next question is from Chad Friess with UBS. Please go ahead.
Hello. Hopefully, my mainline question is the last. I was wondering, what do you view as the primary threat to your mainline conversion project? I know there's a lot of railing going into Eastern markets, which is cost flexible and fairly expensive. 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 to those sorts of solutions as well as unit train railing.
Well, I certainly think, given the experience we've had on Keystone XL and my observations, that I think the U.S. getting its head around exporting crude oil when they are so focused on energy independence, 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 the 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 three times the GHG that a barrel moved by pipe does, and is an order of magnitude at least more likely to have a spill.
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.
Chad, I guess I'd just add to Alex's comments that 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. 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.
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. Based on that encouragement, that's what we're moving forward with here, is that they're saying they've looked 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.
Great. Thanks for that.
Thanks, Chad.
Thank you. The next question is from Ted Durbin with Goldman Sachs. Please go ahead.
Thank you. 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 you're thinking about there, and we've been thinking about GTN in Northern California. Maybe just talk about any strategies there.
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. Obviously, we have a lot of time and effort tied up in this Eastern conversion project that we've been talking about. I wouldn't have anyone think that while we're looking at that, we aren't considering other options. 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. Right now, the most advanced of those ideas is the Eastern conversion project.
Got it. Thanks. Another quick one for me is, we bumped the dividend here again. We're at CAD 1.84. We just had CAD 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.
Yeah. Dividend growth will follow earnings growth. We've talked about some of the anomalies of 2012. We do have a lot of projects coming on stream. We also still have a lot of capital that's tied up in projects that aren't generating any revenue yet. 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, certainly in the first quarter of this year. As these things come on stream, they're 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%-80% earnings payout range. We expect to gravitate back there over time. That equates to about a third of cash flow.
That's kind of where I'd point you in that direction.
Okay. Thanks, Don. That's it for me. Thanks, guys.
Thanks, Ted.
Thank you. The next question is from Dennis Coleman with Bank of America Merrill Lynch. Please go ahead.
Yes. Good afternoon. Thanks for taking the question. I have a question with regard to the elections coming up in B.C. 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. I guess what I would say is that our projects going west are two 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.
The key there is then it's oil versus gas? Is that-
I'd say that, we're not building oil projects into British Columbia. 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.
Thanks very much.
Thank you. Questions will now be taken from the media. Please press *1 on your telephone keypad if you have any questions. There will be a brief pause while participants register. Thank you for your patience. First question is from Rebecca Penty from Bloomberg News. Please go ahead.
Hi there. I have a couple 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 timeline for in-service, and maybe if someone can elaborate, if that's the case, on what's going on there and why?
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. We're also planning on putting in place a 20-inch diluent line, bringing diluent up north in the opposite direction. The original plan was that we would have that combined project in place in 2017. We saw the opportunity to actually get that 20-inch pipeline, the diluent line, in service earlier, but moving blended bitumen south. 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'll be mid-2015.
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. At that time, we'll reverse the diluent line to be bringing about 300,000-330,000 barrels of diluent north total.
Rebecca, essentially what it does is it allows the production to start ramping on early and grow into its ultimate production. 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.
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 and your debt on that approval?
No, we wouldn't. Our credit spreads 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. In and of itself, no, we wouldn't expect a major reaction in the bond market.
Thanks.
Thank you. The next question is from Jeff Jones with Reuters. Please go ahead.
Yes, thanks. 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, Saint 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.
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. 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 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 could go on existing right of way or via existing pipe.
Okay, and then secondly, maybe on a slightly lighter note, although Mainline Conversion is a good name, do you have a more permanent name for this project yet?
We've got our thinking caps on. We have a few ideas that we'll wait and see when we're 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.
Thank you very much.
Thanks.
Thank you. The next question is from Nathan VanderKlippe with The Globe and Mail. Please go ahead.
Yes, hi. Thanks for taking my question. 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?
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. Definitely, we're seeing interest at this point from both sides.
I think, Nathan, similar to the Keystone and 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. It's early to tell, but I think based on what, similar to what Alex said to you, is that there'll be interest from both sides as to who actually is the title holder of the transportation, will be the subject of some of their supply and market agreements.
I wanted to ask too, as far as getting into New Brunswick, if that is the option that you choose, would then have to be new build beyond Montreal? Or are there existing gas pipes or other sorts of pipes you could actually use to get there?
Beyond Montreal, 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. If the project were to go north of Québec, then that would be a greenfield construction for that element of it.
Just one last question and perhaps more of a general question, but, Russ, how closely do you look to something like a State of the Union Address tonight for indications on Keystone XL?
As I think I've said before, 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.
Thank you.
Thanks, Nathan.
Thank you. The next question is from Elsie Ross with the Daily Oil Bulletin. Please go ahead.
Hi. Just a quick question here. Are you talking about heavy oil or light oil or a combination on the mainline conversion?
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. 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.
Okay. The other question is, on the LNG side, what sort of expansions are you looking at in Alberta to connect up into BC?
Well, right now our two projects both originate from the Montney area in Northeast BC, and one I would call North Montney, and the other is right at our Groundbirch pipeline. We are talking to not only the company that we've contracted with, Progress, but we're talking with other companies in the North Montney area to expand our NOVA system north, up in the North Montney. We are really staying right now in the footprint of the Montney area and just expanding the existing infrastructure there.
Thank you.
Elsie, it is 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. 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 till toward the end of the decade. Between that period of time, that new production's going to look for a home and obviously being connected to Alberta and its downstream markets will be very beneficial to those producers.
Okay. Thank you.
Thank you. The next question is from John Spears with the Toronto Star. Please go ahead.
Hello. I have a question about the figure of CAD 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 CAD 250 million is offset by lower payments that you will receive during the course of the contract, and they put a value of about CAD 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 CAD 250 million will be offset by the CAD 210 million over the course of the contract?
Yeah, 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.
The equipment still will be used in the Napanee facility.
Yeah, it's used in the Napanee facility.
Right. Okay. The CAD 250 million payment that you're receiving is offset over the course by that CAD 210 million.
Yeah.
Of the lower net revenue requirement.
Yeah, there is definitely a lower net revenue requirement that would be largely driven by the transfer of that equipment.
Okay. Thank you.
Okay.
Thank you. The next question is from Tonya Zielinski with Upstream. Please go ahead.
Hi, there. Thank you so much for taking my call. I'm gonna change direction here, and I'm wondering, has there been any updates or changes with regards to the Alaska Pipeline project?
I think that the latest in Alaska, that we updated folks on, was that we had suspended the work on the option 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. It's a study that's being done jointly by ourselves, by the three major producers in the region, ConocoPhillips, BP, and Exxon, and the state of Alaska as our partner under the AGIA license. I would say that we would expect, I think the governor of Alaska said that he expects that project will come to conclusion by the middle of February. 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.
Therefore, from that point, I would expect a conversation to ensue as to delivery points again, where and how. 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? By fiscal regime, I'm talking about the royalty rate that will apply to that production, both in terms of quantum and over what timeframe that royalty rate is applied. If they can come to conclusion on that between the producers and the state, there's opportunity to advance an LNG project in Alaska.
Well, are you optimistic given that there are proposed changes to the current tax structure and royalties?
Well, I think that what you're 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. I think the gas royalty discussion is somewhat separate from that.
Thank you.
Thank you. The next question is from Geoff Bird with allnovascotia.com. Please go ahead.
Hi there. Sorry if I missed this earlier. I was just looking for a capital cost for the mainline conversion project.
We haven't put out an actual capital cost number yet, and it will be dependent upon the volume which will then drive the line that we need to take out of service. Then what are the receipt points? What are the delivery points? We haven't announced a capital number yet, but I think that our view would be is that you could 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 it's 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.
Great. Thanks.
Thank you. There are no further questions registered at this time. I'd now like to turn the meeting back over to Mr. Moneta.
Thanks very much, and thanks to all of you for participating today. We very much appreciate your interest in TransCanada, and we look forward to speaking to you again soon. Bye for now.
Thank you. The conference call has now ended. Please disconnect your lines at this time.