Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 First Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr.
Moneta.
Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2015 Q1 conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Alex Torbay, Executive Vice President and President, Development Karl Johansen, President of our Natural Gas Pipelines Business Paul Miller, President of Liquids Pipelines Bill Taylor, President of Energy 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 Investors section under the heading Events and Presentations. Following the prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to 2 questions.
If you have additional questions, please reenter 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. And finally, I'd also like to point out that during the 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 turn the call over to Russ. Thank you, David, and good afternoon, everyone, and thank you all very much for joining us late on Friday afternoon.
Delivering results and position for growth is the theme of our 2014 annual report to shareholders and the theme of our address this morning at our Annual General Meeting. And those words very simply describe our strategy. With $64,000,000,000 of high quality assets across North America, we are situated to take advantage of unprecedented opportunities and deal with unprecedented challenges that lie ahead of us. As we advance our industry leading $46,000,000,000 capital program of commercially secured short and long term projects, we will enhance our competitive position in each of our 3 core businesses and continue to deliver significant growth in earnings, cash flow and dividends. Focusing first on Q1 results, comparable earnings were up 10% in Q1 of 2014 to $465,000,000 or $0.66 per share.
Comparable EBITDA was also up by 10% to $1,500,000,000 and funds generated from operations were up 5% to $1,200,000,000 Solid performances in the quarter each of our 3 core businesses contributed to that increase in comparable earnings and funds generated from operations. Strong performance from our Keystone system, Eastern Canadian Power and U. S. Power businesses helped offset lower Alberta power prices. This clearly demonstrates the value of a large and diversified portfolio of assets.
Today, our Board of Directors declared a quarterly dividend of $0.52 per common share for the quarter ending June 30, 2015. This equates to $2.08 per share on an annualized basis. In a moment, Don, Marchand, our CFO, will discuss our financial results in a bit more detail, but I'd like to now give you a brief update on our progress over the quarter on some of our major projects. Starting with our gas pipeline business, we are now post almost double the rate base of the NGTL system with nearly $7,000,000,000 of new supply and demand facilities under development. We also continue to advance several facility expansion projects in the Q1 by filing regulatory applications with the National Energy Board.
That's a process that will continue through 2015 and into 2016. We've also received further requests for firm service that we anticipate will increase the overall capital spend on NGTL system beyond what we had previously announced. In service dates for the majority of those initiatives run through 2016, 2017 2018. North Montney, we received some positive news just a few weeks ago from the National Energy Board recommending approval of that North Montney project. That $1,700,000,000 natural gas pipeline would provide substantial new capacity on the NGTL system to meet the needs of the rapidly expanding Montney supply basin in Northeast British Columbia.
Besides connecting supply to existing natural gas markets, North Montney would connect our proposed connect with our proposed Prince Rupert gas transmission project to supply gas to the proposed Pacific Northwest LNG liquefaction facility and export facility near Prince Rupert, British Columbia. We expect to phase North Montney into operation in 2016 2017. NEB approval is subject to certain conditions, including a positive final investment decision of the Pacific Northwest LNG facility. Further on Prince Rupert, we expect decisions in the Q2 on permits from the BC Oil and Gas Commission. These permits are required to build and operate that pipeline.
As I said previously, we continue to work with Progress Petronas, the project sponsors and our contractors to refine project costs in anticipation of a final investment decision later on this year. Pacific or Prince River Gas Transmission is a 900 kilometer pipeline that would deliver natural gas from the Montney producing region in Airport St. John through an interconnect of the NGTL system to the proposed Pacific Northwest LNG facility near Prince Rupert, British Columbia. Similarly, on our Coastal GasLink project, we anticipate a decision on permits in the Q2 from the Oil and Gas Commission in British Columbia. That 6 70 kilometer pipeline would deliver natural gas from the Montney producing region again to LNG Canada's proposed LNG facility near Kitimat, British Columbia.
The project is also subject to regulatory approvals, and an FID is expected in early 2016. Moving to our oil pipelines. On Energy East, in April, we announced our decision to not build a marine terminal and associated tank terminals at Tucuna. Quebec potential alternative export terminal options in Quebec are being reviewed. The existing delivery points to refineries in Montreal, L'Abie, which is near Quebec City and St.
John and the export terminal in St. John are not impacted by this review. This decision to move away from Cucuna was a result of recommended changes in the status of the beluga whales to an endangered species and ongoing discussions we have had with communities and key stakeholders. We have listened to those conversations and our decision reflects that. Our goal has been to strike a balance between TransCanada's commitment to minimizing environmental impacts and the imperative to build modern infrastructure to safely transport the energy Canadians need and consume every day.
The National Energy Board has been advised of our decision with respect to Cocoona. Amendments to the application for Energies are expected to be filed with the NEB in the Q4 of 2015. The result of this change, the project scope and further refinement of the project schedule is expected to result in an in service date of 2020. This 1,100,000 barrel per day pipeline will transport oil from Western Canada, Eastern Canadian refineries, creating jobs, tax revenue and energy security for all Canadians. To Keystone XL, we continue to work through the permitting process being led by the U.
S. Department of State. Our current focus is on preparing for the South Dakota Public Utility Commission hearing on TransCanada's request to certify Keystone XL's existing permit authority in the state. As you're aware, the timing of the ultimate resolution of the decision on the presidential permit for the pipeline project remains uncertain, but I believe that the facts will prevail at the end of the day and we will eventually receive a permit and Keystone XL will be built. Our shippers continue to be 100 percent supportive of the project and despite the dip in oil prices, the need to safely transport new Canadian and U.
S. Crude oil to marketplace remains. Moving over to energy. In January, we began building the 900 Megawatt Napanee Natural Gas Fired Power Plant at Ontario Power Generation's Lennox site in the Eastern Ontario in the town of Greater Napanee. That $1,000,000,000 plant is anticipated to begin operation in late 2017 or early 2018.
Power produced at that facility is fully contracted for 20 years with the independent electric system operator in Ontario. To conclude, despite the current low commodity price environment, I'm very pleased with the performance of our businesses and our assets in the Q1. Looking forward for the remainder of 2015 and beyond, you can expect us to remain focused on our 4 key priorities, specifically to maximize the value of our $64,000,000,000 asset base secondly, is to move our $46,000,000,000 capital program from concept to cash flow and thirdly, to continue to cultivate new opportunities to prudently reinvest our growing cash flow in the years ahead and lastly, to maintain our financial flexibility and discipline to ensure we can continue to fund our growth in all market circumstances and conditions. These are the priorities that have guided us in our growth for about the last 15 years, and I believe continued disciplined execution of those priorities will result in growth in earnings, cash flow and dividends and growing shareholder value for many years yet to come. I'll now turn the call back over to Don for some more details on our financial performance in the Q1.
Don, over to you.
Good afternoon, everyone. As Russ highlighted earlier, net income attributable to common shares in the Q1 was $387,000,000 or 0 point 5 $5 per share compared to $412,000,000 or $0.58 per share for the same period in 2014. Excluding unrealized gains and losses from changes in various risk management activities, comparable earnings in the Q1 of $465,000,000 or $0.66 per share increased $43,000,000 or 0 point 0 $6 per share compared to the same period last year. The 10% rise in comparable EPS was primarily due to increased contributions from the Keystone system, the Temazancholy extension in Mexico, Eastern Canadian Power and U. S.
Power, partially offset by lower power prices in Western Power, weaker spreads in natural gas storage and higher interest expense. In terms of our business for segment results at the EBITDA level, our Natural Gas Pipelines business generated comparable EBITDA of $874,000,000 in Q1 2015 compared to $848,000,000 for the same period last year. Canadian Gas Pipelines comparable EBITDA of $522,000,000 decreased $44,000,000 compared to 2014, primarily due to the Canadian Mainline's long term settlement with shippers, which includes a lower embedded allowed ROE. The 2015 to 2020 tolling agreement, which took effect in January, will create long term commercial stability and uncertainty for the mainline. As part of this agreement, we agreed to a base allowed ROE of 10.1% before our annual $20,000,000 contribution versus an 11.5% allowed ROE last year.
This lower allowed return in combination with a lower investment base, primarily stemming from the positive toll stabilization account balance at the end of 2014, led to the $19,000,000 year over year reduction in net income from the mainline. NGTL's net income increased slightly versus Q1 2014 as a result of growth in its investment base. South of the border, U. S. And international pipelines comparable EBITDA rose $79,000,000 to $370,000,000 in Q1 2015, primarily as a result of higher earnings from the recently completed Timassen Charlie extension, a recovery of third party pipeline damages on ANR and the positive impact of a stronger U.
S. Dollar. In liquids, the Keystone pipeline system generated $314,000,000 of comparable EBITDA in the Q1, an increase of $66,000,000 from last year. This was a result of a full quarter's contribution from the Gulf Coast extension, higher volume throughput and the favorable impact of a stronger U. S.
Dollar. Turning to energy, comparable EBITDA was up $43,000,000 to $388,000,000 in the Q1 due to a combination of factors. Eastern Power comparable EBITDA rose $38,000,000 year over year due to the sale of unused gas transportation capacity, higher contracted Beck and Coeur earnings and the contribution from recently acquired solar facilities. Bruce Power equity income increased $15,000,000 as a result of fewer outage days, partially offset by higher operating expenses. Bruce B is currently in the midst of its planned 30 day vacuum building outage that requires us to take down all 4 units.
Unit 6 on the B side will continue on outage beyond the BBO. All of this work is on track and progressing well. Western Power comparable EBITDA decreased $57,000,000 due to lower realized power prices. Lower demand driven in part by a mild winter along with new supply and strong overall fleet performance have been contributing factors to historically low Alberta spot power prices. While this softness is expected to persist in the near term and result in lower overall earnings in 2015 for Western Power as compared to last year, we don't see current prices as sustainable in the medium to longer term.
U. S. Power comparable EBITDA of $164,000,000 increased $70,000,000 in the Q1 compared to last year. The significant increase was influenced by the timing of recognizing earnings in our power marketing business and a stronger U. S.
Dollar, partially offset by lower realized power prices in New England and New York. In our U. S. Power business, where much of the supply is sourced at flat prices over multiple periods, customer pricing is typically shaped to the market and as such has resulted in higher realized prices in the Q1 to be offset by lower prices throughout the rest of the year. The volatility in natural gas and power prices experienced in the winter of 2014 has caused a more pronounced impact on our 2015 contracts, which in turn magnifies the normal seasonal timing differences of earnings.
The majority of these earnings higher earnings recorded in the Q1 2015 will be offset by lower earnings in the Q2. Natural gas storage comparable EBITDA declined $24,000,000 to $3,000,000 in the first quarter due to lower realized storage spreads and the absence of natural gas pricing volatility that occurred in the Q1 of 2014. Now turning to the other income statement items on Slide 16. Comparable interest expense of $318,000,000 in the Q1 increased $44,000,000 compared to the same period last year. This was primarily due to higher interest charges on recent U.
S. Dollar debt issues, higher foreign exchange on interest denominated in U. S. Dollars and lower capitalized interest, partially offset by Canadian and U. S.
Debt maturities. Comparable interest income and other rose $21,000,000 compared to the Q1 of 2014, primarily due to increased AFUDC related to our rate regulated projects, including Mexican Pipelines and Energy East. Partially offsetting the increase in AFUDC were higher realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U. S. Dollar income and the impact of a strengthening U.
S. Dollar on translating foreign currency denominated working capital balances. Our exposure to U. S. Dollar income was largely offset with U.
S. Dollar denominated interest expense and financial derivatives. As highlighted in the past, the stronger U. S. Dollar is not expected to have a material impact on earnings in 2015, but could benefit comparable results in 2016.
Comparable income tax expense for Q1 2015 increased $23,000,000 versus the same period last year due to higher pre tax earnings and changes in the proportion of income earned in higher tax jurisdictions, partially offset by lower flow through taxes in Canadian regulated pipelines. Net income attributable to non controlling interests increased $5,000,000 compared to the same period in 2014, primarily due to the sale of our remaining 30% interest in Bison to TC PipeLines LP in late 2014 and the foreign currency translation of U. S. Dollar minority interest in the LP. Now moving on to cash flow and investing activities on Slide 17.
Cash flow remains strong with funds generated from operations of approximately $1,200,000,000 in the quarter. Capital spending totaled $1,000,000,000 in the Q1, driven principally by NGTL system expansions, construction activities on Northern Courier, Napanee and our 2 Mexican pipelines and ongoing expansion work at ANR to accommodate new contracted shale gas volumes. Equity investments of $93,000,000 in the quarter reflect activities related to the Grand Rapids pipeline and Bruce Power. Turning next to Slide 18, our liquidity and access to capital markets remained strong. At March 31, our consolidated capital structure consists of 37% common equity, 5% preferred shares, 2% junior subordinated notes and 56% debt net of cash.
We had $1,800,000,000 of cash on hand, along with $5,000,000,000 of committed and undrawn revolving bank lines available with our high quality bank group. Our 2 commercial paper programs, 1 in Canada and 1 in the U. S. Remain well supported and continue to provide flexible and on attractive terms in on attractive terms in order to fund our capital program and refinance scheduled debt maturities. In January 20 15, we issued US750 $1,000,000 of 3 year senior notes in 2 tranches, US500 $1,000,000 of fixed rate notes at 1.875 percent and $250,000,000 of floating rate notes at LIBOR plus 79 basis points with the initial rate setting at 1.045%.
In March, we completed a $250,000,000 preferred share issue in Canada. The Series 11 cumulative redeemable first preferred shares carry an initial dividend rate of 3.8%, which is fixed in November 2020. We also raised US750 $1,000,000 of 30 year maturity senior notes in the Taiwanese market in March, which bear interest at 4.6% and are redeemable at par in March 2020 and annually thereafter. Finally, on April 1, we closed the sale of our remaining 30% interest in GTN to TC PipeLines LP for US446 million dollars comprised of US253 million dollars of cash proceeds, US90 $1,000,000 of assumed debt and US95 $1,000,000 of new Class B units issued to TransCanada. The transaction advances our commitment to drop down the remainder of our U.
S. Natural gas pipeline assets over the coming years as a means to help fund our capital program. In closing, the company produced solid results from its diverse suite of blue chip assets and what are challenging energy market conditions. Comparable earnings per share and funds generated from operations were up 10% 5%, respectively, compared to the same period in 2014. We remain well positioned to finance the remainder of our $12,000,000,000 of small to medium sized projects through various funding sources, which include predictable and growing internally generated cash flow from our 3 core businesses, LP drop downs and senior debt consistent with our A grade credit rating.
In addition, subordinated capital in the form of preferred shares and hybrid securities are also expected to form part of our financing strategy. Beyond our $12,000,000,000 of shorter term projects, we continue to advance a broad portfolio of attractive growth initiatives, including $34,000,000,000 of commercially secured projects. While the timing around the $34,000,000,000 of larger scale projects remain subject to regulatory processes and customer final investment decisions, they are all underpinned by substantial long term contractual support, underscoring the need for new infrastructure to bring supply to market. In the meantime, we are confident that our current asset footprint will allow us to capture incremental investment opportunities that will lead to sustained growth in earnings, cash flow and dividends for our shareholders over the remainder of the decade. That's the end of my prepared remarks.
I'll now turn the call back over to David for the Q and A.
Thanks, Don. Just a reminder before I turn it back over to the conference coordinator, we'll take questions from the financial community first. And once we've completed that, we'll then turn it over to the media. With that, I'll turn it back to the conference coordinator for your questions.
Thank you. We'll now take questions from the telephone lines. First from the The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I have a question with respect to the pent up demand for the NGTL system expansions. Can you maybe provide some color around the nature of that additional demand? What might be the timing and certainty of firming it up? What would be the potential associated capital expenditures of that?
And specifically, how much might be dependent on LNG exports going ahead?
Yes, Len, it's Karl. I can deal with that. So Yes, the demand right now is we would be looking at it for in service for 2018. I don't have a definite number of new receipt services being requested. We are just negotiating that with our customers right now.
But we're basically undertaking our projects the projects that we announced last year, which is the $2,700,000,000 expansion. We've already filed $1,900,000,000 of that in front of the regulator and we are working on the rest of it as we speak and we are getting new receipt service applications right now as well. I can't speak of the volume because we haven't concluded the contract yet.
Okay. That's helpful. And maybe just getting to some of your even bigger pipes. For your West Coast LNG pipelines, can you maybe talk about the bookends of possible FID, specifically for your PETRONAS FID, the wording is around potentially being later this year. And I'm wondering if that might include the middle of this year?
Or is that flip to maybe Q4?
Hey Linda, it's Alex. I think from what we're seeing from our customer, I'm kind of guessing that a midyear FID decision, I think is probably kind of the highest probability and that of course would be subject to both Petronas progress and TransCanada receiving their remaining outstanding permits.
Okay. Thank you. And on the shelf side, what would be the earliest? Would it be 2016 with some risk of slippage?
Yes. I think you can I think probably a fair kind of Thank
you?
Thank you. The next question is from Carl Kurz from BMO Capital Markets. Please go ahead. Thank you. Good afternoon, everybody.
Maybe just a first start on PRGT is as that finishes sort of through the refined cost process, is that shifted at all from, I guess, the last amount of updated dollars? Karl, it's Alex. I think that last estimate we gave for PRGT if I go back is probably about 2.5 years old. So it's pretty dated and there have been pretty significant scope increases in terms of kilometers added to the project and other scope. So I mean, I think there's going to be there's definitely going to be some upwards pressure on that and that's about as far as we can go now.
The one thing I would remind everybody is the way that our deal on both those BC projects works is we deliver a and I would say all of the capital that we're talking about all of it has been fully shared with our customers. And what we do is just prior to FID, we give an updated capital costs for the project and that is the target we go forward with. Alex, then from a timing standpoint, should we from an investment standpoint get those updated costs at FID? Or does that come out once for instance final permitting is gotten from BC? Or about when would we be able to see those updated numbers?
Yes. I mean, I think you will see those numbers no later than the FID decision. Okay. Fair enough. And then maybe last question if I could.
I'm not sure if this is for Russ or whomever, but just looking at Energy East and going to the amended filing expected here in the Q4. Is there any sense at this point over what type of additional timeframe then the NEB would need to take to know or declare the application complete? I mean, is this something where this is going to materially change enough that we're kind of starting over from square 1? Or is it just we maybe only need another 6, 8 weeks before the application is declared complete? Is there any way to give any more color on that?
Sure. Karl, it's Alex again. Mike, I think it's important to understand that really what we're talking about is replacing the Cocoona terminal with other terminal facilities on the project. So if you think about it from that perspective, probably 80% or 90% of the original filing would remain relevant and the NEB continues to progress that. If you think about us filing towards the end of next year, I certainly think we I would hope we're not talking about much more than hopefully something less than a 6 month period for the NEB to determine the completeness of the application.
Great. Appreciate the color. Thanks guys.
All right, Carl. Just to be clear, the target is filing for the end of this year.
The end of this year. No, I got you. Okay.
Thank you. The next question is from Rob Hope from Macquarie. Please go ahead. Thank you
for taking my questions. Maybe just one more question about the Pacific Gas Connector. Just wondering of the route, what percentage of the land has now been covered with agreements with First Nations? We have right now executed about 4 right now about 4. We are actively involved with the vast majority of the other First Nations.
I don't have a number for you, but it's certainly our expectation is by the time that we get to an FID decision later this year that we will have a very significant number of those First Nation bands signed up. Thank you for that. Maybe switching over to Ontario. Just with the potential for cap and trade there, would your existing gas plants be covered under a change of law scenario? Or could you get incremental costs for CO2 compliance?
Rob, it's Bill Taylor responding. We're waiting to understand the specific details of how Ontario will roll out their pronounced desire to head in the direction of a cap and trade program for the GHD. So the short answer is that it really varies depending on the details of that as to how it will impact our operations. So it's really speculative at this point to get into that until we see the details of what they finally put out. All right.
Thank you.
Thanks, Rob.
Thank you. The next question is from Paul Lejuez from CIBC. Please go ahead.
Thanks. Good afternoon. First on the drop down to TC Pipe to GTM drop down. Just wondering what the rationale was for taking back some of these Class B units from TC pipelines. It's something you haven't done before.
Just wondering why not cash? Why the structure? And what that implies for future dropdowns if you're going to use that structure again?
Yes. Paul, it's Don here. These were effectively a synthetic high split that was specific to this asset dropdown. And it was designed to be beneficial to both the LP and TransCanada in the sense that it shaped the cash and earnings to TransCanada to our cash requirements for CapEx. And from the LPs perspective, we did receive 100% equity credit for the credit rating agencies on these B units, which reduced the equity it had to issue to 3rd parties and also builds in growth into the LP year 5 and onward.
So it helped shape their earnings growth portfolio going forward. So this I wouldn't consider this a template necessarily for every deal going forward, but we'll look at it using this type of a structure on a bespoke basis as we drop down other assets based on the specific situation of the LP and TransCanada at that point in time.
Okay. Good. Thanks. Also separately on the Alberta oil pipelines you're building the Grand Rapids, Northern Korea and Heartland, just wondered if we can get an update. Has there been any change to any of those projects in terms of time frames or anything else given the downturn in the oil price?
Hi, Paul. It's Paul Miller here. There hasn't been any change on Northern Courier. We're still targeting a 2017 in service. We're about 1 third of the way through construction.
We had a good construction season meeting or hitting our performance targets. On Grand Rapids, we're moving forward with the 20 inches line first that we hope to have in service in the next year followed by the 36 inches the year later. We may see a slowing in production to fill up these pipes. But at this point, we're getting strong indications from the shippers to continue.
Okay. And Heartland is still on track?
Yes. Heartland is be a year later. It's in the 2017 timeframe.
Thanks for that.
Thank you. The next question is from Robert Catellier from JMP Securities. Please go ahead.
I'd like to have your comments on the proposed LNG benefits package for the First Nations. There is some comment in there about incentives from pipeline companies. So can you address that at all? And presumably that's all going to be recovered in your total structure?
Yes. Again, we can't comment on what others have put out in the market in terms of their payments. With respect to ours, the answer is, yes. Our contractual obligations to First Nations will be covered in both. Some of it will be covered in the capital costs and some of it will be covered in the operating costs, but all of it will be paid in the tolls to our customers.
Okay. Then just on the cap and trade again, do you think if Ontario goes down this road, there are any implications for the Bruce refurbishment with the thinking being obviously an emissionless source would be harder to abandon in that case? And just a general update on the refurbishment discussions.
Sure, Paul. It's Bill here. I guess I would say that the Ontario government's move on the cap and trade and defining how they're going to approach GHG is quite consistent with the previously stated support for emission free or GHG emission free sources of power and their commitment to the Bruce site and the commitment to engage with Bruce Power in discussions about the continued refurbishment. I can report that those discussions are still ongoing and we are working alongside Bruce Power and with our partner to try to bring those discussions to a successful close.
While recognizing they're still ongoing, I mean, is there any material progress that's been made? Or have they been tied up trying to figure out what they're going to do on cap and trade first and then at this point maybe more substantive discussions can take place?
I guess I would say that the cap and trade initiatives in Ontario are not really impacting our discussions. We're pursuing those with good due diligence and working as I said alongside our partners to try to move that along as just as quickly as we can.
Okay. Thanks for taking my questions.
Thanks, Rob.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Good afternoon. Recognizing we're only 4 months into the year, but we do have the winter volume season behind us. Just wondering if there's any comments on Main
performance? Yes. It's Karl, Robert. The mainline performance this winter was good. We had another good cold winter out east.
So we shipped some pretty good volumes. Just to give you an idea right now, our firm long haul volumes is just a little under 3 Bcf a day, about 2.7 Bcf a day. We got about a little over 7 Bcf a day of total firm contracts on the system. So we're still gathering about in the mid-ninety percent -ish of our revenue coming off firm total. So the mainline had another good winter season.
And just is there any commentary or anything you can give in terms of where you are versus the budgeted revenue requirement?
Well, we have a we had to do a compliance filing here at the end of March. And that was a filing to set our final tolls as of January 1. And the Board has enrolled on that. So it's hard for me to comment on where we're going to vis a vis our revenue requirement because I don't know what the Board is going to set for final tolls. But I will say that we had a good quarter if it is filed as we expected.
I do expect some incentive revenue to come into the income statement. We will be the process for adjudicating the compliance filing looks like it will take most of this quarter. So we'll get a decision either late this quarter on our final tolls or maybe early next quarter. But we it's hard for me to tell you definitively because the Board hasn't approved our final tools yet. Fair enough.
And then just the other question, if you've got some commentary about being more positive on the over to power market longer term. And I'm just wondering, given your portfolio is relatively short duration, how are you thinking about positioning or taking advantage of that view in the market? And as well, if you can comment on how you think the environmental regulations on carbon may or may not be unfolding and how that might change how you think about the Alberta power market?
Well, Robert, it's Bill. I guess our optimism longer term is really driven by the repeating the comment that Don made earlier that really these prices are not sustainable from the perspective that as you understand, I'm sure there's a fleet turnover need that is underway, which I guess goes to your comment or your question I should say regarding where Alberta may ultimately be going with the GHGs. There is obviously some going to be some changes in that regard which are currently being considered by government. And we're engaged as are all other stakeholders in some consultation that is happening in that regard with government. And it's really aimed at turning over the fleet away from coal, which is a long term goal, I guess.
And so these prices do need to improve in order to have that happen and our company is well positioned I think to with our business both in renewables and in gas fire generation to participate in that once the pricing signals show us that those can be reasonable investments.
Okay. So you want to see the price signals first before or instead of you think you're going to get there and you want to be out in front of them?
We're going to be cautious I guess I would say on that and ensure that we can see the runway to some continued prosperity in that before we would make those investments.
Yeah. That's great. Thank you very much. Thanks, Robert.
Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Thank you. Good afternoon. I guess the question spans multiple business groups, but probably starts with Carl. And it's just in relation to the North Montney line. As you start to expand into that basin, what other opportunities do you see beyond natural gas pipes?
Are you seeing other opportunities to be involved in say the G and P space and dedicated liquids lines?
Yes. It's Karl. So let me just talk a little bit about what we view. So number 1, of course, the gas pipelines is just feeding with that business right now. The North Montney is a very prolific part of that shale play.
And it's something that we're working diligently on to try and get a bigger more infrastructure in that area. What else we'll see in that area? I suspect as LNG goes forward, we will see more NGL infrastructure. Every LNG project has its different heat content of its gas. And I don't know if it's I don't know if we can say right now where they're going to keep the stripping plants and the processing plants for managing the gas, but I suspect there'll be some opportunity in that region too for maybe stripping plants or some sort of NGL infrastructure as well.
So certainly, we keep looking at that. We'll see as FIDs get move forward and as we see the plans for the companies, we would expect some NGL infrastructure as well in that region.
So just on that, it seems like there's a bit of a multiplier that could happen on your current capital expectations just in the Montney region alone given the richness of the gas there?
Well, certainly for if they need transportation of liquids, we would welcome the opportunity to work with them on that as well. So yes, you could say there might be some upside to our business out there if we can convince our partners to go with us for that type of infrastructure as well. Yes.
And then if I may just as a follow-up, I mean we've seen progress has really accelerated the drilling activity on a year over year basis. What should we really take away from that as we run into potential FID decision in June or July?
It's hey, Andrew, it's Alex. I think what I would say is until they make their FID decision, I guess there's always the ability for the project to go both ways. But I think by their actions up in the resource base and by the effort that they're going into with us and their other stakeholders. I think you certainly we look at it and view it as all of that as positive.
Okay. That's very helpful. Thank you.
Thanks, Andrew.
The next question is from Stephen Paget from FirstEnergy Capital.
You had a strong EBITDA out of U. S. Power and it looks like it was driven by purchasing power for resale. Can we expect this purchase resale to continue?
It's Bill. Stephen, the Q1 was indeed impacted as Don mentioned in his opening remarks by some not only growth in volume in our direct sales business in the Northeast, but also driven by the dramatic delta in price that we've seen in Q1 2015 versus what we would have seen in the same quarter last year. The anticipated higher winter prices on the fuel side in New England were driving our retail prices higher and that's what really drove that. As Don mentioned, we do expect in the second quarter to see essentially the opposite effect because we've while we do have very strong positive margin expectations from our overall business, there is this timing element where we really saw high revenue in the Q1, which will be declining in the latter quarters, in particular in Q2.
Thanks, Phil. I'm not sure who this is, who will take this next question. But what was the contribution of spot capacity sales to Keystone's EBITDA results? And the second part is could TransCanada buy oil for its own account, ship it on spot capacity market and then resell it at the other end of Keystone?
Stephen, it's Paul Miller here. Would you mind repeating the first question?
What was the EBITDA contribution of spot capacity sales to Keystone?
Okay. In the Q1. The contribution of that $68,000,000 increase quarter over quarter, about half of that was attributable to increased volume over Q1 last year. And of that sort of, let's call it, mid-thirty million dollars range, About half of that was attributable to spot and the other half is attributable to the full quarter contribution from the Gulf Coast extension. In regard to the second half of the question, we don't give into the buying and selling of crude for our pipelines.
We're seeing good demand on Keystone now. We saw the strong contango market going into Cushing, which contributed to this increased spot on Keystone. So at this point, the market's taken up all that demand all that capacity.
Thank you, Paul.
You're welcome.
Thank you. Thank you. The next question is from Carl Kurz from BMO Capital Markets. Please go ahead.
Hey, thanks everybody. Just a couple of cleanup questions if I could. And the first just really looking at Eastern Canada because the EBITDA came out a little bit higher than we were expecting as well even with the Becking core reset. And I noticed there was some sale in the numbers of unused gas transportation and was just curious how much that was? And perhaps maybe said another way, is there anything seasonally that Eastern Canada number in the Q1 that we'll see perhaps a rollback on as we get to Q2?
It's Bill, Karl. Yes, the transportation in question is transportation that we've taken out in advance of the Napanee project, which as Russ highlighted in his remarks is under construction. So that capacity, which we will be holding for use at Napanee down the road, It has some winter value and so we were able to take some earnings in as a result from the resale of that capacity. You won't see that in Q2 or Q3, but you may see a little bit of it in Q4 again. Can you give us sort of the zip code of what that number was as far as what we should see come out of the second quarter?
About $0.02 on an EPS basis. Okay. Thank you. And then last question, maybe for Karl. It was just really a quick question on the North Montney expansion.
I guess I didn't quite understand some of the commentary around the potential toll structure. It seems like we may be going from rolled in to perhaps negotiated rates in the future. And I just wanted to better understand what was going on there.
Yes. No, that's a good question. The decision came down for the North Montney. And really I guess at a very high level, the Board came back and told us they weren't satisfied with cost causation principles on the current rolling methodology that we had. Had.
They have tried to distinguish between expansions on our system and extensions of our system with extension being leaving the boundaries of our existing system and expansions being within existing boundaries. What they have done is they have approved the project, which is good. And they have invited us to come back later after a transition period they've called after the project has started up. And we and they've invited us to come back with 1 of 2 options. We can either come back with a new methodology that would conceivably include roll in that more closely aligns with our cost causation principles.
So I and that's quite frankly the path we will probably take. We will deal with our customers and we will come up with a new tolling methodology for NGTL that will better incorporate cost causation principles for these extension projects. Or alternatively, they invited us come back with a standalone tolling, which would be what you just talked about. It's some sort of a standalone for the project maybe even negotiated tolling with the customer. But I would expect and we're a couple of years away from actually doing anything with the Board on this, but I would expect that NGTL and our shippers would prefer to come back with the new tolling methodology that would include roll in and more closely aligned with what the Board is looking for in cost causation.
Okay. Because ultimately where I was trying to kind of better understand was if we're seeing additional demand coming on the NGTL system was this issue of rolled into negotiated basically shifting the competitive structure a little bit to open the door to others to come in, but it doesn't sound like that's giving you pause?
No, it's not giving me pause. I'm quite convinced our shippers want to continue with Rolled In. Our shippers want this volume. The volumes coming from LNG projects, the production from that they wanted on NGTL. It contributes to the breadth and depth of the market and the pricing the net pricing mechanism on NGTL.
So I'm pretty certain that's the route that we're going to go. And until told otherwise, I'm pretty certain that that's the route that we're going go.
Great. Appreciate the color. Thank you.
Thank you. This concludes the portion of the Q and A for analysts. We'll now take questions from the media. The next question is from Ashok Dutta from Platts. Please go ahead.
Thank you very much. Good afternoon. I have 2 sets of questions. The first one is about the Prince Rupert gas transmission. How do you think you would be able to overcome this cost overrun issue?
It's Alex Pourbaix. I'm not sure what are you referring to when you say cost overrun.
Last month at the CAP Conference, the guy from Progress said that this project is facing a 40% cost overrun because of its necessary because of a necessity of rerouting or going through offshore areas, the last 150 kilometers and that would result in a 40% cost overrun. So I'm just wondering how will that be overcome?
Well, first off, as I said earlier in my comments, we've announced there has been some upward pressure on that estimate. It was a pretty dated estimate. And in fact, we have added a lot of kilometers to the project and we have we do have a marine component to the project. All that being said, I think our customer at the end of the day will consider that in the context of the overall economics of their liquefaction project. And I think as I said, if you look at their actions over the past year or 2, they certainly seem to be a company that considers this to be a compelling opportunity.
And at the end of the day, the capital or the tolls associated with the capital on the pipeline portion of this project, although important, really are relatively modest portion of their overall cost of delivering gas, liquefying it and getting to their customers.
Okay. And what's the latest with the Upland pipeline? Has the regulatory application been filed as yet? And who has it been filed to?
Yes. Ashok, this is Paul Miller. The regulatory application was filed earlier this week and it's filed with the U. S. State Department.
And we will follow-up with a filing for the Canadian side with the National Energy Board later on this year.
Okay. Thank you, Paul.
That's all that I had.
Thank you.
Thank you. The next question is from Elliot Taheroom from Bloomberg. Please go ahead.
Hi. My question is, I heard your guidance that shipper interest is still strong for Keystone XL even with oil prices where they are. My question is whether the low oil price environment, which some see continuing for a couple of years, has had any impact on any liquids pipeline project yet or if you see it as possible in the near term and what that would be? I'll start maybe turn it over to Paul. But I think along with those long haul pipelines where you started your question around Keystone XL and things like Energies.
Those are projects that are tied to people's long term views of what their production is going to be and what the pricing is going to be out in 2020 through 2,050. And from what we see today, production has grown quite considerably since we announced both Keystone and even Energies. But from the time we applied for Keystone, production is up in Canada, probably about 1,000,000 barrels a day and we're probably up 3,000,000 barrels a day in the U. S. Pipeline capacity hasn't kept up with that current increase in production.
So we're kind of behind already in terms of building long haul infrastructure to move oil to market. And as a result, you've seen rail oil by rail move up quite considerably almost from like 0 to like 1,500,000 barrels a day. So there depends on demand still for long haul infrastructure and that's where Keystone XL fit and the demand is still there and that's why our shippers remain 100% supportive. If I look upstream, I mean, currently there's a lot of projects that are still under construction and moving forward, which means that production in Canada will continue to increase over 2015, 2016, 2017 and likely into 2018, which means that they need new infrastructure upstream. Maybe I'll turn it to Paul for some specifics, if you have any.
No. Thanks, Russ. I think you've covered anyway.
Can I ask
you a quick follow-up, which would be, I think that the maybe Grand Rapids and Northern Courier had been pushed at some point on the timing? Was it at all related to that? Or was it just project logistical stuff?
Yes. Elliot, it's Paul Miller here. On Northern Courier, we've aligned the construction of Northern Courier to coincide with the customers' requirements for the pipe based on the anticipated production date and that's where we landed on the 2017. Grand Rapids, we're building it in 2 phases, starting with the smaller pipe first to bring down some initial volumes in 2016. Now we pushed that out a year.
We were initially targeting this year, but there was a delay in getting our permits from the Alberta regulator. As I said earlier, we've got direction from the shipper to proceed. We do anticipate there will be a slowing in production and attracting volumes onto Grand Rapids. But the need for Grand Rapids remains as it did when we first sanctioned the project.
Thanks very much.
You're welcome.
Thank you. There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Moneta.
Great. Thanks very much and thanks to all of you for participating this afternoon. We recognize it's been a long day with our annual meeting earlier today in our conference call this afternoon. But once again, 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 has now ended.