TransCanada Corporation (USA) (TRP) Management Discusses Q2 2013 Results - Earnings Call Transcript

TransCanada Corporation (USA) (NYSE:TRP) Q2 2013 Earnings Call July 26, 2013 11:00 AM ET

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
Alexander J. Pourbaix - President of Energy and Oil Pipelines
Karl R. Johannson - Executive Vice-President and President of Natural Gas Pipelines

Analysts

Linda Ezergailis - TD Securities Equity Research
Carl L. Kirst - BMO Capital Markets U.S.
Paul Lechem - CIBC World Markets Inc., Research Division
Robert Kwan - RBC Capital Markets, LLC, Research Division
Matthew Akman - Scotiabank Global Banking and Markets, Research Division
Juan Plessis - Canaccord Genuity, Research Division
Pierre Lacroix - Desjardins Securities Inc., Research Division
Paul Tan - Crédit Suisse AG, Research Division
Steven I. Paget - FirstEnergy Capital Corp., Research Division
David McColl - Morningstar Inc., Research Division
Lin Shen
Chester Dawson

Operator

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2013 Second 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

Great, thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2013 Second 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 our Energy and Oil Pipelines Groups; Karl Johannson, President of the Natural Gas Pipelines business; and Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com, and it can be found in the Investor section under the heading Events and Presentations. Following their prepared remarks, we will turn the call over to the conference coordinator for your questions.

During the question-and-answer period, we'll take questions from the investment community first, followed by the media. [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. And finally, I'd also like to point out that during this presentation, we will refer to measures such as comparable earnings; comparable earnings per share; earnings before interest, taxes, depreciation and amortization or EBITDA; comparable EBITDA; and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are 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.

Russell K. Girling

Thanks, David, and good morning, everyone, and thank you very much for joining us. We're very pleased to report this morning that all 3 of our core businesses generated strong results in the second quarter of 2013. We saw higher power prices in Alberta, an increase in New York capacity prices, the return of an 8 unit site at Bruce Power and a higher Canadian Mainline allowed to return on equity, all of those things contributed to a significant increase in earnings and cash flow compared to the same period last year. In addition, we continued to advance a number of our projects and our expansive $26 billion capital program. Over the next 3 years, we expect to complete $13 billion of projects that are currently in the advanced stages of development. They include the Gulf Coast Project, Keystone XL, the Keystone Hardisty Terminal, the Heartland Pipeline and TC Terminals project, the initial phase of the Grand Rapids Pipeline, the Tamazunchale extension, the acquisition of the remaining 8 solar projects in Ontario and the ongoing expansion of our NGTL System.

From 2016 to the end of the decade, a further $13 billion of projects are expected to become operational. Those include the Coastal GasLink and Prince Rupert Gas Transmission projects that would move natural gas to Canada's West Coast for liquefaction and shipment to Asian markets, the Topolobampo and Mazatlan gas projects in Mexico, completion of the Grand Rapids and the Northern Courier oil projects in Northern Alberta and the Napanee Generating Station in Eastern Ontario. TransCanada shareholders will benefit from the predictable and sustainable earnings and cash flow resulting from these projects, as all of those projects are secured by long-term contracts.

I'll talk a little bit more about the progress on those projects in just a moment, but I'd like to highlight a few of the major accomplishments in our second quarter results. As I said, our third quarter business segments performed well during the quarter, TransCanada reported net income of $365 million or $0.52 per share. Comparable earnings for the quarter were $357 million or $0.51 per share, versus $300 million or $0.43 in Q2 of 2012, a 19% increase on a share basis. Comparable EBITDA was $1.1 billion and funds generated from operations were $955 million. The Board of Directors also declared a quarterly dividend of $0.46 per common share for the quarter ending September 30, 2013.

Don Marchand, our CFO, will provide some more details on our financial results in a few moments. Before that, I'd like to update you on the progress of our many capital projects.

I'll start with the Energy East oil project. We continue to feel very positive about this initiative and we have received significant interest from both producers and refiners. Our [indiscernible] are confident Energy East will garner the binding long-term contracts needed to move that project forward. It'll be the most efficient and safest and economic way to transport crude oil to Eastern Canadian refineries creating jobs, long-term economic benefits across the country and displace foreign imported oil, making Canada more energy independent.

This project is a new and innovative way to transport Western Canadian crude oil to market, pushing out as I said, unstable oil from foreign regimes. It may come as a surprise to many, but Eastern Canada currently imports about 700,000 barrels a day of oil, each and every day, from overseas. Energy East creates the opportunity for Canada to use and refine its own resources, something that we believe will benefit Canadians across this country.

Energy East will complement our planned Keystone XL Pipeline in a number of tangible ways, moving -- safely moving growing Canadian production, not only to Canadian refineries but also to U.S. refineries, as well as to other global markets.

If you look at where the key refining centers are in North America, our long-haul pipelines that we proposed are designed to strategically link those regions with supply. The circles on this chart represent the crude oil refining centers across North America. The size of the circle depicts the volume of crude oil refined. For example, the biggest circle is in the Gulf Coast, which is the largest refining center in North America and probably the largest refining center in the world. It currently refines about 7.5 million barrels a day. The orange parts of those pie charts indicate where the imported oil comes from. Most of it coming from offshore. As you can see in the Gulf Coast, it imports about 4 million barrels a day, as well as you can see in North America, both Canada and the U.S., in total, import about 10 million barrels per day. Energy East and our Keystone systems have the ability to supply those refining markets with growing North American production. The Gulf Coast needs both Canadian heavy and light crude oil from the U.S., and Keystone will supply that need. And Energy East will have the ability to supply refineries in Québec, New Brunswick, and the Eastern United States with light and heavy oil, both pipelines, as I said, displacing foreign imports, ensuring North America has security of supply for decades to come.

Moving to our projects under construction, or under development, firstly, the $2.3 billion Gulf Coast project is nearing completion, construction now is more than 85% complete. Since the start of that project in August 2012, we've created approximately 4,000 high-paying jobs for those who are building the pipeline, those are pipe fitters, welders, electricians, heavy equipment operators and many more. The demand for the project remains very clear. U.S. crude production has been growing significantly in places, such as Oklahoma, Texas, North Dakota and Montana. Producers don't have access to sufficient pipeline capacity to move that production to the large refining markets in the U.S. Gulf Coast. The Gulf Coast Project addresses that constraint, allowing U.S. refiners to access lower-cost domestic production and avoid paying premiums to foreign oil producers. This supports thousands of additional refining jobs in Texas, and the economic benefits of those jobs -- the economic benefits that those jobs provide to that state.

We expect this 700,000 barrel a day pipeline to be operational by the end of the year. In addition, construction of the $300 million Houston Lateral is expected to begin in the coming months. That 76-kilometer project will transport crude oil to the Houston refineries and expect -- is expected to be complete in 2014.

Moving to Keystone XL. Review of the over 1 million comments presented to the U.S. Department of State continues, and we look forward to a Final Environmental Impact Statement being issued once that review is complete. We are now closing in on 1,800 days since the review of Keystone XL began. Our base Keystone Pipeline has now safely delivered over 400 million barrels of oil to refineries in Illinois and Oklahoma since the summer of 2010. The review for that project, which is nearly an identical project to Keystone XL, took only 21 months.

Our view is it's now time to bring this process to a conclusion, to focus on the safe construction and operation and allow Americans to continue to experience the benefits of the one of the largest infrastructure projects on the books in that country right now. Creating 9,000 construction jobs and many more spin-off jobs in manufacturing and other sectors. Once the FEIS is issued, the Department of State will begin the National Interest Determination period for Keystone XL, which will lead to a decision on a Presidential Permit. The $5.3 billion cost estimates that we put up there will increase, depending on the time of that permit. As of June 30, we have invested about $1.9 billion in the project.

Recently, the question of Keystone XL's contribution to global GHG emissions has been raised. And in our view, the answer to that question is quite simple. Keystone XL will not result in growth in GHG emissions, period. It is just a pipeline and it's 875 kilometers of pipeline in a North American market that has 180,000 miles of liquids pipelines. Keystone XL will not dictate the growth in supply, nor will it dictate the volume refined in North America. It happens to be just the safest and most efficient means to move that crude oil from supply to refiner, but that commerce will continue, irrespective of the approval of Keystone Pipeline. The fact is, the U.S. needs oil, it needs oil to start 250 million cars each morning, it also -- it needs oil so the Americans can heat their homes, fly in airplanes and manufacture thousands of products they use everyday. Simply put, for now, the U.S. cannot live without oil.

I agree that we need to move to a less carbon-intensive energy future, and that is why TransCanada has invested over $5 billion in emission-free energy, solar, hydro, in the U.S. Northeast, the largest wind farm in Maine, nuclear, we are involved in all of those areas. But the fact remains that the U.S. consumes some 50 million barrels a day of oil and it imports 8 million to 9 million barrels a day of those needs.

Our opponents cannot spin this in any way that makes it look like that's going to change. The U.S. Energy Information Administration and the International Energy Agency, both forecast the United States will need to import millions of barrels a day of oil for decades to come. And again, I'm not sure how our opponents can spin that.

So it's not a case of whether Americans need oil, they will and they do. The only relevant question is, where would Americans like that oil to come from? Should it come from a friendly nation in Canada, an ally that shares American ideals and can supply lower prices, stable crude oil? Or should the oil continue to come from unstable countries like Venezuela and other countries that do not support American values. And again, I think the answer is quite clear, and that's why we remain confident Keystone XL is in the national interest of United States, and it will be approved.

Moving to the rest of our infrastructure, on the pipeline -- or on the oil side, we continue to expand our oil infrastructure network in Alberta, with the announcement May 2 of the Heartland Pipeline and the TC Terminals project, that initiative includes a 200-kilometer oil pipeline, connecting the Edmonton region to facilities in Hardisty. We will build the oil storage terminal in Heartland, which is industrial area just north of Edmonton. The pipeline would transport up to 900,000 barrels a day, and up to 1.9 million barrels of oil could be stored at the terminal. Together, these projects have a combined cost of about $900 million, and are expected to be operational during the second half of 2015. On May 30, we filled a permit application for the terminal, and expect to file an application for the pipeline later in 2013.

Earlier this spring, we filed permit applications for the -- with the provincial regulator for both our Grand Rapids and Northern Courier pipeline projects. We continue to work with the Fort Hills Energy Limited Partnership on the development of that project. The Grand Rapids Pipeline system will be the first pipeline to connect the growing oil sands region West of the Athabasca River to Edmonton, and will be able to carry up to 900,000 barrels a day of crude oil and 330,000 barrels a day of diluent. We expect initial deliveries to begin in 2015 and that project should be complete in 2017.

Moving now to gas. In the spring, the National Energy Board issued its decision on our application to change the business structure in terms and conditions of the Canadian Mainline. The decision significantly altered the regulatory framework that has formed the basis for billions of dollars of regulated pipeline investment over the last 60 years. On May 1, 2013, we filed an application for review and variance of that decision, asking for specific long-haul toll adjustments, a surcharge methodology for the recovery of certain costs and a change in the implementation date of the decision. On June 11, the NEB dismissed our review and variance, and released its reasons for decision on July 22. The regulator did recognize that certain proposed changes by TransCanada to any Mainline tariff should be considered as a separate application, and proceed through an oral hearing that will begin on September 3 of this year. TransCanada is operating under that new decision environment as of July 1, and we've submitted the tariff change application that will manage the process through the oral hearing and wait for the decision on those changes.

Focusing on our -- continuing to focus on gas. Our Western Canadian infrastructure network, we continue to expand the NGTL system, with about $700 million of new facilities becoming operational so far this year. TransCanada has applied and received approval for -- from the NAB for an additional $130 million of new facilities. To date, in 2013, we've applied for additional $145 million of facilities, and are planning regulatory applications for further expansion into British Columbia at an estimated cost of between $1 billion and $1.5 billion to connect and transport new gas supply that will be delivered to the Prince Rupert Gas Transmission Project and other markets served by the NGTL System. NGTL is also developing plans for its upcoming open season to provide delivery service to Vanderhoof, British Columbia, on the Coastal GasLink pipeline. That open season is expected to occur in the second half of 2013.

In early January, TransCanada was selected by PETRONAS, affiliate Progress Energy Canada, to build, own and operate the $5 billion Prince Rupert Gas Transmission Project. That pipeline would transport natural gas primarily from the North Montney gas producing region near Fort St. John to the PETRONAS affiliate, Pacific Northwest LNG's proposed export facility near Prince Rupert, British Columbia. We filed the project description with the British Columbia Environmental Assessment Office and the Canadian Environmental Assessment Agency in May of 2013, First Nations and stakeholder engagement processes continue as we advance through the regulatory process.

Pacific Northwest LNG applied for a National Energy Board permit to export up to 19 million tonnes of LNG per year for 25 years beginning in 2019. Pacific Northwest continues to work to reach a final investment decision in late 2014. Also, in June 2012, TransCanada was selected by Shell and their partners, Mitsubishi, KOGAS and PetroChina to design, build, own and operate the $4 billion Coastal GasLink pipeline project. TransCanada initiated the environmental assessment process in the fall of 2012 through filing of a project description with the British Columbia Environmental Assessment Office and the Canadian environmental assessment agency. The project teams continue to focus on community, landowner, government, Aboriginal and First Nations engagement, as it gathers information and field data to advance the project through the regulatory process and through the preliminary design.

Turning now to power, and Bruce Power specifically. Unit 4 returned to service on April 13 after work was completed to extend its operational life. That work began in August of last year, and now should allow that unit, Unit 4, to operate until at least 2021. With the return of Unit 4 and the restart of Units 1 and 2, Bruce Power is now operating as an 8 unit site for the first time in 2 decades, and has the capability to generate 6,200 megawatts of emissions-free energy. No further maintenance outages are planned for Bruce Power for the remainder of 2013, following planned outages of 2, the Bruce B units, and 1 at the Bruce A units in the second quarter of 2013.

And in addition, earlier this month, we acquired the first 9 Ontario Solar power facilities from the Canadian Solar Solutions company. The combined capacity of the 9 projects is 86 megawatts, and the cost of that portfolio will be approximately $470 million. We anticipate the remaining 8 projects will come into service by the end of '14. They will complement TransCanada's existing operations in Ontario where we have become the largest independent power producer in that province. The renewable energy produced from these projects will be sold to the Ontario Power Authority under a 20-year power purchase agreement. 1/3 of our power now at TransCanada is emission-free, and will provide carbon-free power for the -- North America for decades to come.

So in conclusion, all 3 of our core businesses, as I said, continue to perform strong through the second quarter, higher Alberta power prices, higher New York capacity prices and the return to an 8 unit site at Bruce and a higher Canadian Mainline allowed return on equity, all contributed to a positive quarter. Our unprecedented portfolio of growth opportunities now includes $26 billion worth of commercially secured projects, which we expect to become operational between now and the end of the decade.

As I said earlier, we have significant interest in our Energy East project, which would add to that existing portfolio of commercially secured projects if we decide to move forward. As a result of the contractual nature of all of those projects, we expect them to generate predictable and sustained growth in earnings, cash flow and dividends, growing shareholder value as we have done in the past, for decades yet to come. I'll turn it over to Don Marchand, who will provide some additional details on our second quarter financial results. Don?

Donald R. Marchand

Thanks, Russ, and good morning, everyone. I'd like to begin today by highlighting a few key messages. First, all 3 of our business segments generated solid results in the quarter. Second, the positive momentum in earnings is expected to continue in the second half of 2013, with Bruce Power operating as a full 8 unit site. The return of Sundance A, constructive power markets in Alberta, in the U.S. Northeast and a higher Canadian Mainline return on equity. Third, as Russ highlighted earlier, we continue to advance our $26 billion portfolio of high-quality, long life energy infrastructure opportunities, all these projects are underpinned by long-term contracts, and are expected to contribute to significant growth in earnings, cash flow and dividends over the remainder of the decade. And finally, we remain well-positioned to fund our current capital program. Our track record in 2013 to date, which has seen us raise $3.6 billion of capital at very attractive rates, is a clear demonstration of our ability to access varying sources of capital in order to finance our growth plans.

Now moving to our consolidated results, shown on the next slide. Comparable earnings in the second quarter of $357 million or $0.51 per share increased by $57 million or $0.08 per share compared to the same period in 2012. The 19% increase in comparable earnings per share was primarily due to higher power prices in Alberta, higher Bruce A volumes due to the recent restart of Units 1 and 2, combined with the return of Unit 3 after its life extension outage in June 2012, higher realized power prices and capacity prices in U.S. power and a higher allowed return on equity for the Canadian Mainline. These were partially offset by lower contributions from U.S. Natural Gas Pipelines, lower volumes at Bruce B and higher interest expense and income taxes.

I'll now review the business segment results at the EBITDA level. Our Natural Gas Pipelines business segment generated comparable EBITDA of $644 million in the second quarter 2013, compared to $666 million for the same period last year. The $22 million decrease resulted primarily from lower contributions from ANR, Great Lakes and TC PipeLines LP. Canadian gas pipelines EBITDA of $491 million increased $24 million compared to the same period in 2012. The improved results were due to a higher NGTL System average investment base as a result of ongoing expansions and a higher return on equity for the Canadian Mainline as a result of the NEB decision on our Canadian restructuring proposal. Recall that in its decision, the NEB approved, among other things, a return on equity of 11.5% on a deemed equity ratio of 40%, compared to the last approved return on equity of 8.08%. U.S. Natural Gas Pipelines generated $150 million in EBITDA, a decline of $48 million in second quarter 2013 compared to the same period last year. Decreased revenues at Great Lakes due to lower tariff rates and uncontracted capacity, as well as lower revenues and higher costs at ANR, associated with services provided by other pipelines continue to have an impact on our results. Overall weakness in certain U.S. pipelines, due to lower revenues and higher operating costs is expected to continue in the coming quarters.

Turning to Oil Pipelines, Keystone generated the $187 million of EBITDA in the second quarter. The $9 million of incremental EBITDA year-over-year was due to increased revenues as a result of higher contracted volumes and the impact of a positive adjustment to the final fixed tolls on committed pipeline capacity, which came into effect in July 2012. In Energy, comparable EBITDA was $330 million in the second quarter, compared to $170 million for the same period last year. The $160 million year-over-year increase was the result of a combination of positive factors across both our Canadian and U.S. Power businesses. Western Power's EBITDA rose $96 million in second quarter 2013 compared to the same period last year. The significant increase was primarily due to higher realized prices and purchased PPA volumes in Alberta, as well as the $30 million Sundance PPA arbitration decision charge that was recorded in the second quarter of 2012. Average Alberta spot power prices tripled in second quarter 2013 to $123 per megawatt hour, compared to $40 in the same period last year, due to plant outages in the province and increased power demand. While Western Power benefited from these higher prices, results also reflect the mid impact of hedging activity. With respect to Sundance A, TransAlta's most recent update was that it expects to return Unit 1 shortly and Unit 2 in the fall. Until the Sundance A units are returned to service, we will not realize the generation or related revenues we would otherwise be entitled to under the PPA, and will continue to be relieved of the associated capacity payments.

Equity income from Bruce Power increased $28 million in the second quarter compared to the same period in 2012. For the first time in 2 decades, Bruce Power is operating as full 8 unit site, with the return of Unit 4 from its life extension outage on April 13. The work completed on Unit 4 during the prolonged outage will allow it to operate until at least 2021.

Higher equity income from Bruce A, as a result of the restart of Units 1 and 2, along with increased volumes in Unit 3, which was under a 6-month outage to extend its useful life last year, was partially offset by lower revenues and higher operating costs at Bruce B, as a result of increased plant outage days and higher lease expense. With no further maintenance outages planned for the remainder of 2013, Bruce Power is expected to generate significant earnings and cash flow in the second half of the year, now that all 8 units are operational.

U.S. Power EBITDA was $43 million higher in the second quarter compared to the same period last year. The increase was primarily due to higher realized power prices, continued firming of the New York Zone J capacity market and higher net revenues on wholesale industrial and commercial power sales. And finally, Natural Gas Storage results decreased $8 million in the quarter to lower realized storage spreads, partially offset by the acquisition of the remaining 40% interest in CrossAlta in December 2012.

Now turning to the other income statement items on Slide 27. Comparable interest expense in the second quarter was $252 million compared to $239 million in the same period last year. The $13 million increase primarily reflects lower capitalized interest as a result of the restart of Bruce A units 1 and 2, partially offset by increased capitalized interest related to the Gulf Coast Project. In the second quarter, $60 million of interest was capitalized to assets under construction compared to $76 million for the same period in 2012. Comparable interest income and other decreased $20 million -- $21 million year-over-year, primarily due to realized losses in 2013 compared to gains in 2012 on derivatives used to manage the company's net exposure to foreign exchange fluctuations on 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 for second quarter 2013 increased $42 million compared to the same period last year, due to higher pretax earnings and a higher effective tax rate as a result of a change in the proportion of income earned in higher tax jurisdictions.

Moving on to cash flow and investing activities on Slide 28. Cash flow was strong in the quarter, mainly due to higher earnings in the period. Funds generated from operations totaled $955 million in the second quarter, an increase of $226 million from the same period last year. Turning to investing activities, capital expenditures were $1.1 billion in the second quarter, driven primarily by the Gulf Coast Project, ongoing expansion of the NGTL System and construction of our Mexican pipeline projects. Acquisitions of $55 million in the quarter reflect the purchase of our first Ontario Solar project, which closed in late June. The acquisition of the 8 remaining projects is expected to close in 2013 and 2014 as they are satisfactorily completed and brought online.

Now looking at Slide 29, our liquidity and access to capital markets remain strong [ph]. At the end of the second quarter, our consolidated capital structure consisted of 41% common equity, 5% preferred shares, 2% Junior subordinated notes and 52% debt net of cash. At June 30, we had $674 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, one in the U.S. and 2 in Canada, are well supported and provide flexible and very attractive sources of short-term funds. In July, we completed the sale of a 45% interest in each of GTN and Bison for USD 1.05 billion, which included $146 million of GTN-related debt to our master limited partnership, TC PipeLines LP.

TC PipeLines successfully refinanced the transaction through a public offering of common units and a debt placement. Aside from contributing USD 8 million to maintain our GT interest, we did not participate in the equity offering and as such, our ownership interest in the partnership decreased from 33.3% to 28.9%. This asset dropped down as a clear demonstration of one of the many financing options available to us as we continue progressing our unprecedented growth portfolio.

Also in July, we completed 2 additional debt offerings, raising over $1.25 billion in Canada and U.S., in Canadian and U.S. markets at very attractive rates. Specifically, we issued our first LIBOR-based floating rate notes, raising USD 500 million of 3-year funding at an initial interest rate of 0.95%. And in Canada, we issued $450 million and $300 million of medium term notes for terms of 10 and 30 years, bearing interest at 3.69% and 4.55%, respectively. Proceeds from these offerings will be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund [indiscernible] capital program. Year-to-date, we've now raised $3.6 billion on attractive terms through an array of funding products to a diverse investor base.

Looking forward, we remain well positioned to finance our capital program through funds generated from operations, new senior debt, subordinated capital in the form of additional preferred shares and hybrid securities, as well as portfolio management, which may include further LP drop downs.

In closing, TransCanada produced another strong quarter with comparable earnings per share 19% higher than second quarter 2012. Going forward, the restart of Bruce Power Units 1 and 2, along with completion of the Unit 4 life extension outage in April, the return of Sundance A, affirming our power markets in Alberta and in the U.S. Northeast, incremental Keystone revenues and a higher Canadian Mainline return on equity are all expected to have a positive impact on earnings in 2013. This will be partially offset by lower contributions from U.S. Natural Gas Pipelines and higher interest expense.

Furthermore, we also expect to complete a number of capital projects that will also contribute to earnings and cash flow in 2013 and 2014. They include construction of the Gulf Coast Project, ongoing expansion of the NGTL System, Tamazunchale Pipeline Extension, the Hardisty Terminal and the acquisition of the fully contracted Ontario Solar assets. Finally, we continue to advance the balance of our $26 billion of commercially secured capital projects, which includes a number of large scale energy infrastructure investments that are targeted for completion between 2015 and the end of the decade. They include Keystone XL, 2 Natural Gas Pipelines to Canada's West Coast, 2 gas pipeline projects in Mexico, several oil pipeline projects in Alberta and the Napanee Generating Station in Ontario. Each of these initiatives is underpinned by long-term contracts with strong counterparties. As a result, we expect to generate significant growth in earnings, cash flow and dividends, which are expected to deliver superior risk-adjusted returns for our shareholders in the years ahead.

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

David Moneta

Thanks, Don. Just a reminder before I turn the call over to the conference coordinator, we will take questions from the financial community first. Once we've completed that, we'll then turn it over to the media. And with that, I'll turn it back to the conference coordinator for your questions.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Linda Ezergailis from TD Securities.

Linda Ezergailis - TD Securities Equity Research

Just a quick question on Energy East. When might you expect to finalize or firm up your commercial agreements? And what would you say is the key challenge, if any, in getting to that point?

Alexander J. Pourbaix

Linda, it's Alex. I don't think we really have any challenges really to get to the point where we can be in a position to announce. It's really just kind of working through terms and conditions, credit, so forth. I think from our perspective, look forward to hearing something from us within the next 2 weeks.

Linda Ezergailis - TD Securities Equity Research

Great. And then beyond the large current projects you're working on, Keystone XL, Energy East, Northern Courier, Grand Rapids, and I realize that alone keeps you busy. But are you working on any other major liquids pipelines, either regional in Canada or the U.S. or larger, either as a newbuild or maybe partially re-purposing a natural gas pipeline?

Russell K. Girling

We are. And what I would say, it's kind of all of the above. We're actually seeing some very interesting greenfield opportunities. But we always look very hard at our existing pipeline assets to see if we see opportunities for re-purposing along the lines of Energy East or Keystone, and I think we're pretty optimistic we may be able to execute on some of those opportunities in the future.

Operator

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

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

Just keying off of Linda's question, Energy East, is it possible just kind of given kind of where we are on the process to start giving detail as far as what we think the cost structure, the total investment cost will be, and in particular, the destination? And would this be kind of a phased destination over time or sort of done all at once?

Alexander J. Pourbaix

Carl, it's Alex again. I think that we're, I've said this recently, we were pleasantly surprised by the commercial response to our open season, and particularly with interest going all the way to the East Coast. We have provided our shippers with a number of destination options which will be -- when we announce the project, we'll be able to give a lot more guidance on that and on the capital cost. I think the one thing I would say is that we are working very closely with stakeholders and the communities that we go through to ensure that we are very thoughtful and very responsive to the concerns that various communities and regions may have. And that's one of the other reasons why we're being very careful as we go through this process.

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

No, understood and appreciate the color. A separate question, if I could, and Russ, this is really more of a question on the Mainline and I guess, the market's digestion of the new rate sort of taking into account, July 1. And one of the discussion points prior was, perhaps, don't kind of knee-jerk on the decline in spot volumes because we're seeing increased interest in contracted volumes. I didn't know if there was any way to quantify that to get sort of greater long-term comfort relative to where the spot volumes are today, for instance.

Russell K. Girling

I think I'll let Karl take that one.

Karl R. Johannson

Yes, I could take that, Carl. Yes, and I think it's a matter of public record. So I think I can share this number with you, it's on our website. We have -- since the NEB decision, we have put on the books about 1 Bcf a day of new FT contracts from transportation contracts. So we have seen that -- that's quite a large increase. I guess going into that, we had about 1.1 Bcf a day coming out of the West in contracts so it's about doubled it. So we have seen quite a bit of new contracting on the system.

Operator

The next question is from Paul Lechem from CIBC.

Paul Lechem - CIBC World Markets Inc., Research Division

Still on the Mainline, wanted to try to understand a little bit what the NEB hearing that's -- the oil hearing that's starting in September, what that is related to, what it involves, that hearing would involve? And furthermore, with the filing of an Energy East application, I understand that might trigger a new rate case around the Mainline. What would you expect that to involve as well?

Karl R. Johannson

Yes, it's Karl again. Certainly, the hearing in September really came out of our review on variance with the NEB. We asked for some changes to the contracts, and we'll probably have several of these going forward, quite frankly, with the new pricing environment we're in. We have to change some of our contracts to make them look less like the old world of cost service and more like the new world of merchants, so we have to take things out of the contracts. In particular, in September, we're looking at the renewal options in our existing contracts. Well, the 2 more important issues in September, the renewal options in the contracts that we have right now and the diversion rates for people that buy service on us. We're looking to modify the renewal options and eliminate the diversion rights. As for the -- as for what's going to happen with the Mainline upon the Energy East application, the NEB did make a provision in their decision that when we were to go forward with Energy East, or if we were to go forward with Energy East, they would invite us back to relook at our rates and relook at the -- at how the rates are determined on the system. So I suspect at that time, given that we'd be transferring some capacity to the oil business, we would be back in front of the NEB, looking for the impact of that transfer and looking for different rates.

Paul Lechem - CIBC World Markets Inc., Research Division

Okay. And just one follow up, if I may. On the -- since July 1, given you're operating under the new rate though [ph], the new tolling structure, can you talk a little bit about your short-term and interruptible tolls, how you've been setting them, how that's being received by the market? Any thoughts on, in terms of modification to the short-term tolling that you've put in place?

Karl R. Johannson

Well, sure. I don't want to get into what our actual strategy is because that would -- given the market we're in now, that's somewhat confidential, but I think I can talk in broad ranges. The board has given us, for our kind of short-term and discretionary services, they've given us a broad range of flexibility now. And they haven't really limited us in any way. Our goals, our high-level goals of offering that is to really maximize both throughput and revenue on our system. So it's not just about throughput and it's not just about revenues, it's about both. We look at both of them. But we do look at how much volumes that we are shipping on short-term. We're looking at how much volumes are new contracts we're getting on FT contracts as well. So it's -- we are trying to price accordingly to maximize both the revenue and throughput on the system.

Operator

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

Robert Kwan - RBC Capital Markets, LLC, Research Division

Karl, maybe I'll just continue with the Mainline as the first question here. Just with the way you're aggressively pricing the IT and the STFT and what that's kind of done for migrating some people to contracting on the ST, can you talk about maybe what you've seen behind that in the delivery point? Like are people -- did you see that increase as people are trying to use the cheaper GLGT path into Dawn? And what your expectations are as you've started to use up some of that capacity for future or for additional FT contracts?

Karl R. Johannson

I guess what I can say is we've seen -- as I talked about a little earlier, I think, we saw about 1 Bcf, a little over 1 Bcf a day of new contracts since the NEB decision. About 40% of that came after July 1, so we've been very busy since July 1. A lot of those contracts since July 1 have been kind of the Empress to Emerson, to Great Lakes or in that area of contracts. So yes, I do think we've seen some extra contracting that's destined ultimately for Great Lakes. The rest of the contracts really are all through our system. So there's -- we've seen contracting right across the board for all of our delivery points.

Russell K. Girling

And just to add to that, Robert, just to hear your comment on aggressively pricing that. I guess that wouldn't be the way we would characterize it. Is it -- our tolling structure changed as of July 1, and what we're trying to do is understand what value people derive it for different segments in different parts of our systems over different periods of time, and make sure that we price accordingly to capture the value that the people see in our pipeline. I think as we've always said, the Mainline has tremendous value to the North American gas infrastructure. And part of what we're doing is learning how that works and trying to price accordingly to meet customer needs.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And just the second question I have. You talked about how you've used TCP and looking at it in the future as part of your financing options. I'm just wondering though, with some of the U.S. valuations and the bumps we've seen for the general partners, i.e. the C corps, just wondering if you have any thoughts on a more aggressive use of TCP from a strategic valuation perspective.

Karl R. Johannson

It's -- go ahead, Russ.

Russell K. Girling

I was going to say, maybe start from a high level, and maybe Don can jump in on this, too, Robert. As obviously, we've always said that the TC PipeLines is a strategic financing vehicle for us when we have capital needs. Obviously, as you look at our portfolio of $26 billion and growing, we have significant capital needs. So the strategic financing position for TCP is growing inside of our company. We are watching what others have done with respect to dropping down larger portions of their portfolio and the valuations. I guess what we always look at is truly long-term value. And to the extent that, that creates value for shareholders in both TC PipeLines and for TransCanada, obviously, we'd look at that. But usually, not that swayed, at least today, we haven't been swayed by sort of what I call sort of short-term market valuations for certain assets that aren't underpinned by fundamental economics. That said, it's obvious that we have a big financing need which is probably driving us more to using TC PipeLines in the future than we have in the past. Don?

Donald R. Marchand

Yes, I'd agree with that. And it's driven by use of proceeds. And what we look for is to extract cash rather than pieces of paper from it. If you just vend assets and then create governance between the cash flows and where we need them, that's something we bear in mind. But we'll weigh it against preferred shares, hybrid securities and the like in terms of cost size, currency, equity credit and the like. And you've seen us go down the path on all these in the past, and I'd expect us to do the same in the future.

Operator

The next question is from Matthew Akman from Scotiabank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Don, a question for you on financing plans. With bond yields having lifted in the last couple of months, I'm just wondering how you're thinking about your debt issuances. There were some issuance last week. And also your hedging program on forward cost-to-debt.

Donald R. Marchand

Yes. I'll just speak broadly about what the quantum is over the next couple of years here. So if we look between now and the end of 2015, and we'll just put Keystone XL aside for now until we have visibility on timing of that, total CapEx is in the $11 billion area. Roughly broken down, about $4 billion on oil, includes Gulf Coast and the Alberta regional pipes and terminals. But $4 billion in gas, which is NGTL, Mexico and some pre-spend on the LNG projects to get them to permitting. And about $3 billion of other, which includes the solar acquisitions, some spend on Napanee, maintenance capital and other. So we gave out $11 billion. Internally generated cash will cover about $7 billion of that. That leaves us about $4 billion of new capital and about $3 billion of maturities. So we would see a need of $7 billion, $7.5 billion over the next few years. Now that will go up as we get clarity on XL, and that could also go up as we start progressing NGTL spend on Prince Rupert. So from a quantum perspective, that's what we're looking at. Talk about some of the levers that are available. Senior debt will be the first place we look to, being the cheapest form of capital within the constraints of the A credit metrics. And then as I walk through some of the other options there, we're not active hedgers of forward issuance. We're a continuous issuer in the marketplace. The cushions we have against rising interest rates are predictable and growing cash flow. We have a long-term debt portfolio that the average term of our debt is in excess of 11 years, where we're over 90% fixed-rate financed at this point in time. We do have cost pass-through ability, certainly, on our Canadian regulated pipes and on certain prospects such as the LNG projects. And we would expect ROEs, albeit with a lag effect, to increase in a rising interest rate environment as well. If it's accompanied by inflation, we do have CPI adjustment factors on Bruce as well. We expect commodity prices to rise as well. So we're not lying awake at night, worrying about rising interest rates. Obviously, it has a valuation impact, but those are some of the things we look at and the quantum of needs that we have clear visibility to right now.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Okay, great. Just one more question, it relates to the Mainline tolls. And I'm just wondering, the process, we've touched on this for re-establishing tolls in the event of successful open season at Energy East. Would that process go along the same timelines as the regulatory approval process for Energy East? What timelines, roughly, would the gas pipeline re-tolling hearing run on?

Russell K. Girling

Matthew, that's actually a good question. We've been talking a lot about that in our shop. We really have 2 options. We can file a revised mainline application at the same time as Energy East or we could wait till closer to the time that we take these assets out of service on Energy East. And at this point, we haven't really determined what's -- which way we're going to go, but I guess it's not necessary to file it at the exact same time because it is going to take a couple of years to get the capacity out of service once we file our application. So we do have some flexibility there. But we haven't made a final decision on when we'll be filing that.

Russell K. Girling

And Matthew, obviously, the 2 things are tied together. The reason for a revised toll application is because we're going to adjust the rate base because of the transfer to oil service. So they are linked. And so we're just working through what is the most efficient way to file that one when the time comes. And part of that, obviously, will be dependent upon our discussions and negotiations with the shippers on both sides. And we're active in those discussions right now, and we're trying to find the place that works best for both parties.

Operator

The next question is from Juan Plessis from Canaccord Genuity.

Juan Plessis - Canaccord Genuity, Research Division

You've mentioned in your MD&A that the indicative timeframe for a Keystone XL in-service date is 2 years after receipt of a Presidential Permit. And previously, you had indicated 18 to 24 months, depending on the timing of the approval. Has anything changed with respect to the construction schedule or is it just that you think you'll receive a Presidential Permit at a time in the construction cycle that will require 24 months?

Alexander J. Pourbaix

Juan, it's Alex. I don't think -- there really hasn't been any change in our thought on that. And really, I think we've just sort of used that 24 months as a bit of shorthand. I think as you noted, we need the better part of 2 construction seasons. But depending on the date we get the approval, all months really aren't equal. So we've just kind of, just for simplicity's sake, we're kind of using 24 months. But it doesn't indicate any sort of differing thought on construction timing or anything like that.

Juan Plessis - Canaccord Genuity, Research Division

Okay. So it's 24 months at the outside?

Alexander J. Pourbaix

Yes, I think we need -- we basically -- I think that's a fair way to describe it.

Juan Plessis - Canaccord Genuity, Research Division

Okay. And my second question, Karl, you didn't get the interest in the Portland Natural Gas Transmission System open season, but you continue to look for market opportunities to develop growth. Can you talk about some of these potential market opportunities as it relates to PNGTS?

Karl R. Johannson

Well, yes, I think that's a fair characterization. We never got the market interest that we wanted. I think that was because there's still a lot of uncertainty over our tolls and how much capacity we're going to have for long-haul, what's the price of long-haul, what's the price for incremental capacity on our lines. So there's still some uncertainty around the Mainline, and I personally attribute that to be the main reason we didn't get as much interest as we wanted. We are, as Russ said, we are in talks with all of our shippers right now to try and reduce that uncertainty, to try and determine how incremental capacity will be put into the system under this new world that we're in. And I am optimistic that we will come to some arrangement in the future, and I think we'll be able to take out that uncertainty in the Mainline and we will go back with another open season at that time with PNGTS. So I don't think it's over, there are open seasons on that line. By any stretch of imagination, I think it's still a pretty useful piece of assets, so I think it goes into pretty -- a market that needs the capacity. So we're just going to work on reducing some of the uncertainty over some of the Mainline part of that, and I think we'll be back at it.

Operator

The next question is from Pierre Lecroix from Desjardins Capital Markets.

Pierre Lacroix - Desjardins Securities Inc., Research Division

First, Russ, I just wanted to have an update on the Keystone XL as the decision is taking more and more time and the startup is slipping toward 2016. Just wanted to have a refresh on what are the main contracts or deadline that you have with your shippers or your customers there for your contractual arrangements, depending on the date of the startup.

Russell K. Girling

I'll let Alex take that.

Alexander J. Pourbaix

Sure. We do have some sunset dates in those provisions. What I can say is that we have been in close contact with all of our shippers and we do not anticipate that any of those sunset dates are going to be a problem with the project date. I think basically, how our shippers look at it is we are the most economic route to the Gulf Coast. We're the furthest advanced. The project is really kind of sitting on the 5-yard line. And I think everybody is fully committed, all of our shippers, behind getting this project over the line. So we don't anticipate any significant concerns on that regard.

Pierre Lacroix - Desjardins Securities Inc., Research Division

Okay. And further on this, the Gulf Coast Project, can you remind me the return profile? I know that it's tied to volume in the meantime that Keystone XL comes in at some point. With the tightening of the differentials, do you see the initiation of the Gulf Coast Project with -- at the lower end of the return profile range? And can you give us some kind of a refresh on this side as well?

Alexander J. Pourbaix

Sure. I think we're -- we've always said that the contribution from the Gulf Coast Project is probably kind of in the range to $200 million to $300 million of EBITDA, and that range probably -- kind of looks like a 7% to 9% type of project. And we think that we're -- the majority of the volume moving under that pipeline is going to be under contract. There is some amount of spot, but we still think that guidance is pretty good guidance.

Pierre Lacroix - Desjardins Securities Inc., Research Division

Okay. And one other, maybe for Russ. What is the company's appetite at this point to look at major or significant corporate strategic moves? When we saw earlier this week, some of your comparables in U.S. doing some and some, also, IPO going on in the power space. Where do you stand on that front, Russ?

Russell K. Girling

Right. I think that our strategy is pretty much laid out in front of us. We have, I think, a diversified large portfolio of energy infrastructure. All 3 of those businesses create new platforms for growth. That's turned into a number that looks like about $26 billion. So that's what our focus is on, is execution of that $26 billion of opportunity. And from both a human resource perspective and capital perspective, most of our time is spent on ensuring that we have those resources to be able to execute on that plan. If it comes to fruition, and we're fortunate that all of those projects receive sanction and move forward, they'll add tremendous value for our shareholders. So our focus isn't on other sort of corporate transactions right now, but we do keep an eye to the market as things arise and we'll adjust if there's opportunities. But I'd say that, that's not in our core sort of focus right now. We've got lots to do with our existing platform.

Pierre Lacroix - Desjardins Securities Inc., Research Division

Okay. One final for Don. You mentioned that CapEx over the next couple of years of $11 billion. What is the breakdown between 2013 and 2014 in terms of the CapEx plan?

Donald R. Marchand

Yes. Just looking at it here, probably about $4.5 billion this year, 5-ish this year then, $3 billion and $3 billion.

Pierre Lacroix - Desjardins Securities Inc., Research Division

$3 billion in 2014, $3 billion in 2015?

Donald R. Marchand

Yes.

Operator

The next question is from Paul Tan from Credit Suisse.

Paul Tan - Crédit Suisse AG, Research Division

With regards to your Mexican assets, with the energy reforms in Mexico, there's expectations that there will be a number of pipeline projects to be assigned by the government in the future. How do you see your position in Mexico and where would you like to be?

Karl R. Johannson

Yes, I can take that. It's Karl. I think our position in Mexico is excellent. I think we have a very good base position right now. We've got, essentially, 3 projects under construction, 2 in the very early stages and 1 in the middle of construction. And a good presence in Mexico City with all the key stakeholders. So if the reforms do pan out and some of the existing infrastructure is available, I think that TransCanada will take a very serious look at it.

Paul Tan - Crédit Suisse AG, Research Division

And a follow up for that one would be, would you guys be considering possible partnerships with local companies specifically, INOVA, to further increase your presence or market share in the country?

Karl R. Johannson

I guess I can start on that comment. We have been looking at several ways of executing these projects and new projects, going forward, in Mexico. And partnerships, local partnerships, I notice some of our competitors even went and incorporated their own companies in Mexico. So there's various options that we can look at there if we do choose to bring in outside money into these projects. So I wouldn't take anything off the table, but right now I think we can -- we're comfortable we can fully fund everything we have there, yes.

Russell K. Girling

Our focus, primarily, is to get the projects secured from a contractual perspective, move them through construction, remove those risks and then, look at the most beneficial way to finance those for our shareholders as bringing partners too early, obviously, would detract potentially from the shareholder value that we create. That said, in certain cases, partnerships will make sense. But our -- I'd say that our mode of operation has been secure the projects first, take away risk that we are good at mitigating and then, bring in partners and hopefully, if you bring in partners, you can bring them in at a level that creates more shareholder value than bringing them in upfront.

Operator

The next question is from Steven Paget from FirstEnergy.

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

Just my first question, what factors might potentially go into the rate case for Great Lakes being filed later this year? And what factors might create upside and downside to current EBITDA levels on Great Lakes?

Karl R. Johannson

Well, the Great Lakes rate case, November 1 is our filing date for that. And if we get -- if we can't come to a settlement, which we are actually progressing, we think we're progressing quite well towards the settlement. So it's -- we're still in settlement negotiations and we still are talking about. But really, the Great Lakes rate case will center around increasing the revenue from our shippers on our default rates. And so we've talked about several options on that rate case. We've talked about just increasing the rates that are existing rates and we've talked about postage-stamping it. But the -- going into that rate case is going to be simple. Our volumes have fallen so our rates have got to go up. This settlement, we are in a FERC-mediated settlement discussions right now. And I think I'm quite optimistic that we might be able to do something there but we do have to file by November 1 if we don't get any progress on that.

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

And what are the -- and factors are driving toward progress as you see it? Or -- and do you think it likely to be done before November 1?

Russell K. Girling

As it stands right now, I'm optimistic. But we're just a few months away from November 1 right now and if we don't see some movement right now -- it's always difficult when you have your volumes fall this much and you have to put that big of a rate increase on the remaining shippers. So it's -- there are fairly serious conversations right now with our shippers on that. But I think we've -- and I'm quite optimistic we'll get there. But if we don't, we have the filing ready and we'll be ready to file on November 1.

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

Don, just a quick follow-up. When you gave your 2013, '14, '15 CapEx split, that was x XL?

Donald R. Marchand

That's correct. And that also excludes any significant NGTL spend related to Prince Rupert, as mentioned in his remarks, probably $1 billion to $1.5 billion there may come at some point.

Operator

The next question is from David McColl from Morningstar.

David McColl - Morningstar Inc., Research Division

Just to move back to the Gulf Coast connector. I'm just wondering if you can give any commentary on when the line fill might be starting there? We've kind of heard late October, early November.

Donald R. Marchand

I think you heard Russ say we're north of 85% complete and moving quite quickly. So I think that kind of October, November time period is probably a pretty, pretty good estimate.

Operator

The next question is from Lin Shen from HITE Hedge.

Lin Shen

Just one question under TC PipeLines Partners. If you plan to do another drop-down for the MLP, what kind of asset you think should be the ideal job item [ph] for the next one?

Russell K. Girling

I think that what we've said in the past is that we want to put high quality assets into that portfolio. If you look at our U.S. pipeline portfolio, I think they all kind of fit that bill. So we have recently dropped down pieces of Bison and GTN. Again, there's more of those assets left that we could sell into that portfolio, obviously, Great Lakes and our Iroquois, Portland are all good quality pipelines that we've put in. But I think our focus on our MLP has been to ensure that we're putting high-quality long life assets into the portfolio. And we do have a long list of things that would fit that.

Lin Shen

Yes. I mean, more specifically, do you think it makes sense to drop down some crude pipelines to make the MLP more diversified?

Russell K. Girling

I don't think that our objective, as I've said, is about diversifying the portfolio. Our drop-downs to our MLP are driven off financing needs and use of proceeds at the corporate TransCanada level. To the extent that down the road, we see the opportunity to drop down mature oil pipeline assets for example, into the TC PipeLines, there is aversion to doing that. But at the current time, those assets are in, what I would call, sort of the development phase and probably aren't suitable for an LP. You take Keystone XL for example, and we're working through the permitting process and then through a construction process. Those kinds of assets aren't conducive to a cash flowing vehicle like TC PipeLine's LP. So down the road, we're building more options to be able to do that. But the driver, really, is on us assuring that those assets are, sort of, in what I call the cash flowing phase of their life.

Operator

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

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

Just a couple of quick follow-ups, and one, was really on ANR and I mean, we knew it was going to be weak. But first quarter, it actually relatively hung in year-over-year, second quarter, much more of a decline. And so when we talk about it, for instance, continuing to see some weakness, basically, at what point here do you see it sort of basing out, if you will, on kind of a year-over-year comparison?

Karl R. Johannson

Well, let me just talk a little bit about the weakness that we have seen it. The actual transport spreads on -- and are -- have actually hung in pretty good. It's not been a weakness of transport, so to speak, of the spreads that are available. It's really been the storage now. What we've seen come this last quarter, the storage spreads have been very, very weak and their costs have increased. Their costs mostly -- some costs on the action [ph], everyday costs which we have to do, but mostly, the costs have increased through the transportation by other contracts they have on other pipelines. They use other pipelines to access their storage facility. So they have -- so it has been a quarter where it was being dominated, I think, by the storage spreads. And storage spreads are like gas or commodity, they'll get better and worse. So I don't see anything structural there. ANR does have some work to do, maybe on its costs and on these transportation by other arrangements that they have. And that's what we are pursuing right now, is work on those areas.

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

Maybe Don, just a quick follow-up and then, I appreciate all the budget clarity. If we were to throw XL into the mix, kind of knock on wood here, is this something where you still think through, call it, 2015 between, pref LP drops that, that can be managed? Or are we looking at that point of perhaps evaluating a DRIP, for instance?

Donald R. Marchand

Well, there's -- yes, we exhaust the hybrids, the prefs, first then we'd look at the portfolio that could be dropped into the LP and weigh that against the cost of a DRIP. The DRIP -- at some point, if we're fortunate enough to get much of this portfolio moving forward into construction, a DRIP may make sense at some point because it lines up quite nicely with a spend profile on these multi-year construction projects. So it would be on the list and certainly, well ahead of a discrete equity issue by a long stretch.

Operator

There are no further questions from the financial community. We will now proceed to questions from the media. [Operator Instructions] We have a question from Kelly Cryderman from Globe and Mail.

Kelly Cryderman

I'm just wondering, as you look towards the Energy East project, whether the derailment and explosion in Québec earlier this month -- whether you think that has changed anything in terms of the climate for transporting oil in that province as you look to new projects there?

Russell K. Girling

Here's what I'd say, is that obviously, it's a tragic event, tragic event for the people of Lac-Mégantic, and a tragic event for our country and for our industry. And we all have to step back and understand what occurred. We don't know that yet. And make sure that we implement whatever remediations are required in the transport of oil hydrocarbons. What we know is, is that we need to continue to use oil to fuel our daily lives. What we want to do is ensure the public that we can move it as safely as humanly possible. And that is the focus of our company and what we've been focused on. With all of our pipelines, including Energy East, is make sure that we are using the latest technology, the best equipment and again, from a response perspective, the best response capabilities available to respond to any kind of situation that we have along our pipelines.

Kelly Cryderman

And if -- talking about -- switching to Keystone, you talked about, again, about increasing costs due to the delays. Do you have a better handle on what those increased costs are?

Russell K. Girling

I think we have a pretty good handle on them. Obviously, that's a conversation between ourselves and our shippers. As you know, our shippers take up a portion of those costs. But until we have a better understanding of when our actual construction is going to start, we have not put out a new estimate publicly. But certainly, internally, we're working through that. Obviously, in terms of the kinds of things that influence that cost increase would be the cost of money, obviously, we have almost $2 billion invested in this that we have the carrying costs on. The cost of maintaining pipe and equipment and maintaining our contracts through this period. We have thousands of tons of steel pipes sitting on the ground that needs to be maintained, and numerous pumps in warehouses, for example, that need to be maintained on an ongoing basis. So all of those contribute to a cost increase. But again, until we actually have a better understanding of when we can actually start construction, we are not going to issue a new number publicly.

Kelly Cryderman

And is there any change to the timeline that you -- you mentioned, again, last week late 2015, there was a mentioned just on this conference call, pushing into 2016. Is that something you're preparing for at this time?

Russell K. Girling

I think what we are preparing for at this time, as Alex said, is somewhere around 24 months, plus or minus a few months, depending on when we receive the permit. So what we -- rather than me predicting where this is going to land, we are just sort of putting out to the media and in the marketplace the facts, which are when we think we're going to get this permit, which we hope to be somewhere between now and year-end. And from that point, it's going to take us some 24 months to construct, so that sort of puts in the time frames that we've been talking about.

Operator

The next question is from Jeff Lewis from Financial Post.

Jeff Lewis

A couple of follow-ups on Energy East. Are the contracts that you're looking to sign with shippers, are those binding shipping commitments? Or are you looking for financial commitments to get you through the engineering and regulatory phases of the project?

Russell K. Girling

They'll be binding shipping agreements. But as well, there are -- as part of those shipping agreements, there will be some cost sharing of both development cost and development cost risk, if you will, and capital cost risk sharing once we are into the construction phases of the project.

Jeff Lewis

Okay. And how has the ongoing uncertainty over Mainline tolls and sort of the disagreements with gas distributors in Ontario and Québec impacted discussions with prospective oil shippers on that project?

Russell K. Girling

The 2 haven't been related, and in a lot of cases, the oil shippers are gas shippers. I think the noise that people have been hearing with respect to gas capacity versus oil capacity in the East has been raised by shippers that have been concerned about the decision that the main -- that the National Energy Board made on our Mainline, which confuses how we can service those customers and how we can add capital to the system in the future. I think what we've tried to do is be as clear as possible in that confusion as we can by stating that we will have capacity to meet the needs of all of our customers. What we need to do is, whether it be oil or gas, we need to understand what those needs are. And once we understand what those needs are, we can determine what kind of facilities we need to put in place and what kind of capital we need to spend. And that's an ongoing discussion that we have going on right now with both customers. We have a pretty good understanding of what our oil customers are going to need. But given that the change in nature of the contracting structure on the gas pipeline side of things and in our tolling, it's going to take us some time to understand exactly what the needs of our gas customers are, both now and into the future. And what we said is we are committed to meeting those needs, of those customers.

Jeff Lewis

Okay. And do you anticipate, I mean, this could be -- I mean, are you anticipating a protracted sort of regulatory process as you move forward with both the Mainline oil application and the revised tolling structure for that service?

Russell K. Girling

No, I don't believe that there will be a protracted regulatory time frame. I think it's in the Canadian national interest that we get through these regulatory processes in a timely and efficient manner. That's not to say that we want to short-circuit any of the review process, be it environmental or commercial. But we need to set time frames on these processes that are reasonable. We've seen new legislation introduced that will allow for those kinds of accountabilities on time frames. My view is that by working with all parties in a cooperative way, we will come to a resolution, as I said, to meet the needs of all parties and there is no reason for a protracted regulatory process.

Operator

The next question is from Rebecca Penty from Bloomberg News.

Rebecca Penty

I know you've addressed this question before in the past, but I hope you can address it again, as people in the States keep talking about this idea that Keystone XL could be for export of refined petroleum products from the States as more refining goes on in the Gulf Coast. I'm wondering if anyone can address that question. And if you -- the ultimate purpose for Keystone XL and whether some diesel, for example, could be exported from the oil on the line?

Russell K. Girling

I guess what I'd start with is, we're in the oil transportation business and so I can tell you what I know, is that we have 20-year contracts with our shippers to move crude oil from Western Canada and from the northwest United States to refineries in the Gulf Coast. What we know is that those refiners want to refine Canadian and U.S. oil. I think as you've heard me say before, and I said in my opening remarks, the U.S. Gulf Coast consumes some 7 million barrels a day of oil -- refines 7 million barrels a day of oil and imports 4 million of those. With the introduction of Keystone, what will happen is we will displace approximately 800,000 barrels a day of foreign crude oil with crude oil from Canada and from the United States. So there is -- none of this oil will actually be leaving. Now the question of whether or not some of those refined products get exported, that commerce occurs today and it will continue to occur, sort of, post-Keystone. But Keystone won't have any impact on the volumes that are -- of refined products that are either imported or exported. Today, there is some diesel exports and some refined product imports in order to balance the needs of the United States, both from a product slate perspective, as well, from a supply-demand perspective, through the recession, as demand has decreased in the United States, the United States has exported more product. But I would expect that as demand returns to more normal pre-recession levels, United States will export less. But that flexibility is built into the refineries, has nothing to do with the Keystone XL pipeline. The amount of oil, heavy oil that's refined in the Gulf Coast will stay the same, whether you build Keystone or not. So this link between somehow, that Keystone is going to change the nature of U.S. exports, is patently false. First of all, there will be no crude oil exported from Keystone XL shippers through to export points. We don't have any port access along the pipeline. With respect to refined products, I mean, that's a question better directed to the refineries as to what their plans are going forward. But what I can tell you is, incrementally, Keystone won't change that equation, it just replaces the source of crude oil. And as I've said before, it's -- do you want heavy oil from Canada and light oil from the Bakken region of the United States? Or do you want to import oil from Venezuela and from other OPEC nations to feed those refineries?

Operator

The next question is from Chester Dawson from Wall Street Journal.

Chester Dawson

I just have a question about the pipeline projects that would potentially cut the shale gas fields with the West Coast to Canada. Obviously, that's dependent on whether these projects of LNG refining are -- or processing terminals go through. But I'm just curious, are you at all considering integration? Are you talking with other companies? I know you're involved with both PETRONAS and Shell. Is there any talk about combining those? It seems, I think there's 4 planned pipelines and that doesn't seem to make a lot of sense rationally. Can you tell us about that and also, where does that stand with the 2 that you're involved in, in terms of actually mapping the routes out, getting cost estimates, all that good stuff?

Russell K. Girling

Lots of questions in there. The -- I think I'd start with the number of projects. There are a number of projects that are proposed to move natural gas to the West Coast for the purpose of conversion to LNG, and their moving to export markets. I would agree, it's not likely that all can move forward. In our view, the probability of a project moving forward is dependent on, at least, 4 things. Primarily, is it supported by the marketplace? Does it have some agreement with the market to move that LNG to it, and that -- those are usually long term in nature. Secondly, does it have supply and the ability to continue to drill up the properties required to meet that long-term market need? And then, thirdly, does it have the -- does that group have the technical wherewithal in order to build the project? And fourthly, does it have the financial capability to actually pull it off? And these are large projects when you look at the value chain from well head to the re-gas facilities. We're talking about value chains that look like, for each project, a $20 billion or $25 billion, $30 billion kind of value chain. So it does lend itself to the larger players. So as we look forward as to what projects have those 4 key elements, we would say that the PETRONAS and Shell projects are well advanced in that regard, having supply and market, technical capability and financial wherewithal. There are others that are seeking to do the same. And to the extent, I think, that there are synergies amongst supply and market and an ability to find operating synergies and scale synergies on some of these facilities, I think that there is opening for continued discussion. That wouldn't be a role that we would have in bringing those parties together. I think that really is both at the supply end and at the liquefaction and market end. And to the extent that those parties want to come together and combine their volumes, we can modify the designs of our pipelines as they have been proposed today to accommodate more volumes and more receipt points. But the way we're structured today, there's 1 set of delivery points to Prince Rupert, and 1 set of delivery points to Kitimat. We are participating in 1 project in each of those directions. And to the extent that others want to join those projects, as I've said, that would be a decision that will be made by those project proponents. And I think as long as there's value added in those partnerships, I think that they remain open to those kinds of conversations. That's what we've been told to date.

Chester Dawson

Okay. But are you doing any work on the ground today or are you just waiting for them to give the...

Russell K. Girling

We are very active in our review process in both of those projects. We are well underway with filing our project descriptions to the environmental assessment agencies. We've engaged in stakeholder consultation [ph]. We are busy doing our engineering and route design. And what we would hope to be is in a position to receive regulatory approval of those projects by the time that these projects reach their sanctioning point. I would expect that we will spend as TransCanada, over the next, say, 24 months on each of those projects, somewhere in the neighborhood of $200 million to $300 million preparing for those regulatory processes in obtaining of those regulatory approvals. So we are active and moving, actually, as fast as we possibly can towards regulatory approval.

Chester Dawson

Just to clarify, that's $200 million to $300 million each, right, for the 2?

Russell K. Girling

Correct.

Operator

The next question is Patrick Badgley from Platts.

Patrick Badgley

Just had a couple of quick follow-ups on the Mainline. So when you were discussing the extra Bcf per day of firm capacity since the NEB decision, can you give an idea of, kind of, the length of most of those firm contracts?

Donald R. Marchand

Yes. There -- we have contracts between 1 year and 3 years that have come in the door.

Patrick Badgley

Okay. And then, is it possible, still, that -- is TCPL considering legal appeal of the NEB decision?

Russell K. Girling

I didn't quite catch that, can you say that again?

Patrick Badgley

I'm sorry. Is TCPL still considering legal appeal or appealing in the courts of the March 27 decision?

Russell K. Girling

I'd say at this time, we are not. I think none of our costs have been denied at this point in time. As we've said before, our objective is to try to work within the framework of the regulatory decision as it has been laid out. I think as Karl pointed out in his remarks, we have another process in September that we're going to work through, where we've requested certain tariff changes, which will allow us to transform ourselves to be able to offer the services under this new regime. And from that point, we will continue to assess our legal and regulatory strategy going forward. But at the current time, there isn't a plan on the legal front. And our strategy is to try to work within this framework as it's been outlined to us.

Operator

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

David Moneta

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

Operator

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