Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Maneta, Vice President of Investor Relations. Please go ahead, Mr.
Maneta.
Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2015 Q2 conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Alex Pourbaix, Executive Vice President and President of Development Carl Johansen, President of our Natural Gas Pipelines Business Paul Miller, President Liquids Pipelines Bill Taylor, President of Energy and Glenn Manusz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks.
A copy of the presentation is available on our website at transcanada.com, and can be found in the Investors section under the heading Events and Presentations. Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone 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'd be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U. S.
Securities and Exchange Commission. Finally, I'd also like to point out that during 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 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 our operating performance, liquidity and our ability to generate funds to finance our operations.
With that, I'll turn the call over to Russ. Thank you, David, and good morning, everyone, and thank you for joining us today. We're very pleased to report today's strong financial results for the Q2 of 2015. The results again reflect the resilience and diversity of our 3 core businesses through difficult business cycles. As you're well aware, low commodity prices are and challenging market conditions are impacting our customers and their capital expenditure plans, and we are working closely with our customers to understand those impacts and to adjust our projects to best meet their needs.
During the quarter, we continued to advance a number of our key components of our capital program, including construction activities on our $12,000,000,000 shorter term project portfolio such as the Napanee power plant, the Northern Korea pipeline project, Tablo Bamba and Mazatlan in Mexico and several NGTEL receipt and delivery expansion projects. We advanced our $13,000,000,000 portfolio of projects that support the emerging liquefied natural gas business in British Columbia, and we continue to progress our long distance crude oil pipeline initiatives. In addition, we continue to work on additional strategic opportunities in each of our 3 core businesses such as expansions of the NGTL system, the ANR system, Mexico opportunities and the refurbishment of Bruce Power.
As I said
on a number of occasions, given the highly contracted underpinning of these projects, once complete, they are expected to deliver steady growth in earnings, cash flow and dividends through the end of the decade and beyond. So back to the quarterly numbers. TransCanada reported net income of $429,000,000 or $0.60 per share in the 2nd quarter. Comparable earnings for the quarter were $397,000,000 or $0.56 per share, the 20% increase over the $332,000,000 or $0.47 per share reported in the Q2 of 2014. Cash flow has also continued to grow compared to quarter of last year.
Comparable EBITDA was $1,400,000,000 and funds generated from operations were 1,100,000,000 Earlier today, the Board of Directors declared a quarterly dividend of $0.52 per common share for the quarter ending September 30, 2015. As a result of the company's past performance, along with confidence in our future business plans, our Board of Directors has raised the dividend in each of the last 15 years from $0.80 in 2000 to the current rate of $2.08 per year. Stock appreciation combined with this steady growing dividend, has resulted in a 14% average annual total shareholder return since 2000. Looking forward, continued strong performance from our core businesses and expansions currently underway is expected to provide the foundation to continue to grow our dividend at an annual rate of 8% to 10% through 2017 and to continue to prudently fund our industry leading $46,000,000,000 capital program. Our CFO, Don Marchand, will speak with you shortly and provide more details on our financial performance in the Q2.
But before that, I'd like to speak to you about some key developments over the quarter in advancing our capital program. Starting with our gas pipeline business. As I've mentioned last quarter, with nearly $7,000,000,000 of new supply and demand facilities under development, we are poised to almost double the rate base of our NGTL pipeline system. We continue to advance several of these facility expansions and plan to file additional facility applications with the NEB through the remainder of 2015. In addition, we continue to receive requests for firm receipt service that we anticipate will increase the overall capital spend on NGTL system beyond what we have previously announced.
In service dates for the majority of those initiatives run through 2016, 'seventeen and 'eighteen. The single largest NGTL project that has been approved is our one $700,000,000 North Montney project. In June, the Government of Canada announced a decision to accept the National Energy Board's recommendation to approve the project, which will expand NGTL's reach into the one of the most prolific producing regions in the Western Canadian Sedimentary Basin. It will consist of 2 large sections, the Aitken Creek and Cata sections, totaling just over 300 kilometers in length. This pipeline will connect Montney and other Western Canadian Sedimentary Basin supply to existing and new natural gas markets, including Pacific Northwest LNG Terminal via the Prince Rupert gas transmission project.
We expect to have Aitken Creek operating in late 2016 and Cutta around 2017. Construction of the North Montney project will begin after final investment decision has been made on the proposed Pacific Northwest LNG project and Trans Canada proceeds with construction of the Prince Rupert Gas Transmission project. With respect to Prince Rupert Gas Transmission, we're pleased to see significant developments over the last month. Pacific Northwest LNG reached an important milestone with a positive final investment decision subject to 2 conditions: firstly, approval from the Canadian Environmental Assessment Agency and second, the BC Legislature's ratification of the project development agreement between the province and Pacific Northwest. On the latter condition, the BC Legislature ratified that agreement with Pacific Northwest just over a week ago.
Pacific Northwest is proposing to build a liquefied natural gas facility and export facilities near Prince Rupert. These facilities would receive gas through our 900 kilometer Prince Rupert gas transmission project from the Montney producing region near Fort St. John, British Columbia. PGRT was the beneficiary of further positive news recently receiving 6 of the 11 pipeline and facilities permits from the BC Oil and Gas Commission needed to build and operate the pipeline. We anticipate a decision on the remaining permits in the Q3 of this year.
We remain on target to begin construction of the Prince Rupert project following confirmation of a final investment decision from Pacific Northwest. The in service date of PGRT is expected to be 2020, but we will align that with Pacific Northwest LNG's facility timeline. On our Coastal GasLink project, we announced last month that we had signed project agreements with 6 BC First Nations. These agreements reinforce the strong relationship TransCanada has built with First Nation communities and demonstrate their willingness to participate in the many benefits and opportunities this project will bring to their communities. An estimated 30% of the $4,800,000,000 project spend will be spent locally in British Columbia, creating over 2,000 jobs during construction and $20,000,000 in annual property tax payments.
On the permitting front, Coastal GasLink has received the majority of its permits from the BC Oil and Gas Commission, 8 out of 10 are in hand and the remaining 2 permits we expect those to be issued in the Q3 of 2015. The 6 70 kilometer Coastal GasLink pipeline will run from Dawson Creek to the proposed LNG Canada liquefied natural gas export facility near Kitimat, British Columbia. We anticipate construction starting in the latter part of 2016. Moving over to oil and Energy East. We announced in early April that we would not build a marine terminal at Cocoona, Quebec.
We continue to review potential alternative export terminal options with our shippers and stakeholders. There's a possibility that only one export terminal at a facility at St. John, New Brunswick would be built. The other existing delivery points to refineries in Montreal, L'Abie, near Quebec City and St. Jean and the export terminal in St.
Jean are not impacted by that review. We expect that we'll be in a position to offer a further update on the project in the coming weeks. During the past 9 months, the NEB has continued to review our October 14 filing for the project. Amendments to that application are expected to be filed with the NEB in the Q4 of 2015. The result of this change to project scope and further refinement of the project schedule expected to result in an in service date of 2020.
This project will connect directly refineries in Eastern Canada, allowing them to access cheaper Western Canadian crude oil instead of having to rely on 600,000 barrels a day of oil Canada imports from foreign countries today. The benefits from the multibillion dollar project for all Canadians are quite clear. 1,000 of good paying jobs and 1,000,000 more in annual tax revenues to fund healthcare, build roads, schools and fund local communities. We expect the current announced project cost $12,000,000,000 to increase due to adjusting the pipeline's route following feedback from communities, governments and indigenous peoples and higher construction costs. Moving to the Keystone Pipeline System.
We achieved a very important milestone just a couple of weeks ago when we announced the Keystone Pipeline System had safely delivered its 1,000,000,000 barrel of oil of Canadian and U. S. Crude oil refineries in the United States. Since 2010, when we first began transporting oil, the Keystone system has contributed to the U. S.
Energy security and has generated close to $200,000,000 in property taxes and more than 14,000 construction jobs for 11 states and provinces that it crosses. Construction continues on the Houston Lateral Pipeline Tank Terminal, which will extend Keystone to the Houston, Texas refineries. The terminal is expected to have an initial storage capacity of 700,000 barrels of crude oil. The pipeline and terminal are anticipated to be operational in the Q4 of 2015. In addition, we announced a joint development agreement with Magellan Midstream in the spring to connect our Houston crude oil terminal to Magellan's East Houston terminal.
TransCanada will own 50 percent of this still $50,000,000 project, which will enhance connections to the Houston market for our Keystone pipeline customers. We expect that pipeline to be operational in late 2016. On Keystone XL, we continue to wait for recommendations from the U. S. Department of State as to whether the project is in the national interest of the United States.
Our focus at the current time is taking part in hearings held by the South Dakota Public Utilities Commission related to our request to certify Keystone XL's existing permit authority in the state. Those hearings are expected to wrap up next week. We continue to believe Keystone XL is in the national interest of America and meets the President's climate test of not significantly exacerbating global greenhouse gas emissions, something that the U. S. State Department has concluded on numerous occasions in over 17,000 pages of scientific review since 2010.
The need
for the
Keystone XL pipeline remains high as consumers continue to use more and more gasoline refined from barrels of crude oil. The American Energy Information Administration reported earlier this month, oil consumption in the U. S. Is up by nearly 500,000 barrels per day over last year. As a result, refiners are producing more gas for U.
S. Motorists at near record levels. We believe the fundamental choice for Keystone XL remains, firstly, would Americans rather receive this oil that they continue demand from Venezuela or places like Iran or would they rather use American and Canadian oil? And second, is it safer and more environmentally sound to ship that oil in trucks, railcars or barges or in a modern state of the art pipeline buried 4 feet below the ground? We continue to believe the answers to these questions are self evident.
This $8,000,000,000 pipeline remains the safest, least GHG intensive and most secure way to supply the oil the United States needs, and TransCanada and its shippers remain 100% committed to this project. As of June 30, 2015, we had invested $2,400,000,000 in the project, and we've also capitalized $400,000,000 of interest. Moving over to energy. In January, we began building the 900 Megawatt natural gas fired Napanee power plant at Ontario Power Generation's Lennox site in the Eastern Ontario town of the Greater Napanee. The $1,000,000,000 plant is anticipated to begin operating in late 2017 or early 2018.
Power produced at this facility is fully contracted for 20 years with the independent electric system operator in Ontario. So to conclude, our 3 core businesses produced another solid quarter demonstrating resiliency while facing some very challenging market conditions. Comparable earnings and funds generated from operations increased 20% 16%, respectively, compared to the same period last year. This highlights the solid foundation from which we expect to grow the dividend at 8% to 10% through 2017 and fund our industry leading $46,000,000,000 portfolio of new high quality energy projects. These projects are expected to result in significant growth in earnings, cash flow and dividends through the end of the decade and beyond and continue to deliver long term shareholder value.
I'll now turn the call back to Don for more details about our Q2 financial performance. Don?
Thanks, Russ, and good morning, everyone. As highlighted in our release this morning, we again generated strong results in the Q2 with net income attributable to common shares of $429,000,000 or $0.60 per share compared to $416,000,000 or $0.59 per share for the same period in 2014. Excluding a $34,000,000 income tax expense adjustment resulting from the recent increase in the Alberta corporate income tax rate, an $8,000,000 after tax restructuring charge related to changes in our major projects group as well as unrealized gains from various risk management activities, comparable earnings increased $65,000,000 in the 2nd quarter to $397,000,000 or $0.56 per share compared to $332,000,000 or 0.4 $7 in the same period last year. Net income in Q2 2014 included a $99,000,000 after tax gain from the sale of CanCar, a $31,000,000 after tax loss from the termination of a natural gas storage contract, as well as unrealized losses from various risk management activities, each of which were excluded from that period's comparable earnings. The 20% year over year increase in 2nd quarter comparable earnings was primarily due to higher contributions in the Canadian Mainline and GTL system, Keystone, Bruce Power and Eastern Power, partially offset by lower contributions from U.
S. Power due to timing differences on recognizing earnings as well as lower realized power prices and PPA volumes in Western Power. In terms of our business segment results at the EBITDA level, the Natural Gas Pipelines business generated comparable EBITDA of $807,000,000 in the Q2 of 2015 compared to $759,000,000 for the same period last year. Canadian Natural Gas Pipelines' comparable EBITDA of $583,000,000 increased $34,000,000 compared to 2014, primarily due to incentive earnings recorded for the Canadian Mainline and a higher average investment base on NGTL, partially offset by a lower allowed ROE on the Mainline. Canadian mainline earnings increased $9,000,000 in Q2 2015 to 67,000,000 dollars The NEB approved final tolls for the 20 fifteen-twenty 20 tolling agreement in June, allowing us to record incentive earnings in the period of $24,000,000 for the 1st 6 months of the year.
This was partially offset by a lower allowed ROE of 10.1% versus 11.5% last year as well as a lower investment base. Given the strong volume throughput and contracting efforts in the first half of twenty fifteen, the mainline is expected to earn its base ROE of 10.1% throughout the remainder of the year with incremental short term volume movements or additional contracting providing potential upside from this level. NGTL's net income increased by $8,000,000 in the second quarter compared to the same period last year, primarily as a result of its growing investment base and no OM and A incentive losses realized in 2015. U. S.
And International Pipelines comparable EBITDA was up $26,000,000 to $238,000,000 in Q2 2015, primarily as a result of the positive impact of the stronger U. S. Dollar. Business development costs have risen for the 3 6 month periods in natural gas pipelines, mainly due to increased business activity. In liquids, the Keystone Pipeline system generated $320,000,000 of comparable EBITDA in the 2nd quarter, an increase of $64,000,000 from last year.
This was a result of higher uncontracted volume throughput and the favorable impact of a stronger U. S. Dollar. Turning to energy, comparable EBITDA of $272,000,000 in the second quarter represented an increase of $41,000,000 versus
the same period in 2014. Bruce Power equity income increased $42,000,000
as a result of fewer outage days. Strong operating performance in the A units, which achieved 98% availability, was a primary factor in Bruce's strong results. Bruce B conducted its planned 30 day vacuum building outage slightly ahead of schedule and also completed an extended planned outage on Unit 6 during the quarter. An additional scheduled outage on Unit 4 at Bruce A began in mid July and is expected to continue for approximately 90 days. This work on Unit 4 will substantially complete the planned major maintenance events at Bruce for the remainder of the year.
Eastern Power comparable EBITDA was up $21,000,000 year over year due to incremental earnings from solar facilities acquired in the second half of twenty fourteen and increased power generation from Cartier Wind. Western Power comparable EBITDA decreased $12,000,000 due to lower realized prices and lower purchase PPA volumes. We continue to expect Western Power earnings in 2015 to be lower in comparison to last year as the Alberta power market is currently well supplied and demand growth has slowed with weakened economic conditions leading to lower prices. US Power comparable EBITDA of $79,000,000 decreased $17,000,000 in the 2nd quarter compared to 2014, primarily due to the timing of earnings recognition on certain contracts in our power marketing business and lower realized capacity prices in New York, partially offset by a stronger U. S.
Dollar and stronger margins in sales to wholesale customers. Now turning to the other income statement items on Slide 19, comparable interest expense of $331,000,000 in the 2nd quarter increased $34,000,000 compared to the same period last year. This was primarily due to interest charges on recent U. S. Debt issues and higher foreign exchange on interest denominated in U.
S. Dollars, partially offset by Canadian and U. S. Debt maturities and higher capitalized interest. Comparable interest income and other rose $22,000,000 compared to the Q2 of 2014, principally 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 the strength in the 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 a result, we saw minimal effect from the strengthening U. S. Dollar in our Q2 due to our hedging activity. However, going forward, we should see future results positively impacted should these currency levels persist. Comparable income tax expense of $185,000,000 represented an increase of $23,000,000 versus the same period last year due to higher pretax 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 interest increased $9,000,000 compared to the same period in 2014, primarily due to the sale of our remaining 30% interest in GTN to TC PipeLines in April 2015 and Bison in late 2014, along with the foreign currency translation impact of US dollar minority interest in the LP. Now moving on to cash flow and investing activities on Slide 20. Cash flow remained robust with funds generated from operations of approximately $1,100,000,000 in the quarter, representing a 16% increase year over year. Capital spending, which includes projects under development, totaled $1,100,000,000 in the 2nd quarter, driven principally by NGTL system expansions, construction activities on Mexican pipelines, Northern Courier and Napanee, along with ongoing expansion work at ANR to accommodate new contracted shale gas volumes. Equity investments of approximately $100,000,000 reflect activities related to the Grand Rapids pipeline and Bruce Power.
Turning next to Slide 21, our liquidity, financial position and access to capital markets remain strong. At June 30, our consolidated capital structure consisted of 36% common equity, 5% preferred shares, 4% junior subordinated notes and 55 percent debt net of cash. From a liquidity perspective, we had approximately $600,000,000 of cash on hand, $5,000,000,000 of committed non drawn revolving bank lines available with our high quality bank group, as well as 2 well supported commercial paper programs. Being one of a very small group of pipeline or midstream companies in North America with A grade credit, we believe our financial strength and flexibility provides us with a competitive advantage, particularly during stressed market conditions and positions us commercially as a counterparty of choice. Access to capital markets at all point to the economic cycle is imperative to ensure we can execute on our growth plans and act when opportunities arise.
In terms of financing activity,
to date in 2015, we've raised in excess of $4,000,000,000 on attractive terms order to fund our capital program and refinance scheduled debt maturities. Over the past several months, we closed the sale of our remaining interest in GTN to TC PipeLines LP, issued US750 $1,000,000 of 60 year junior subordinated notes that will be accorded attractive equity credit from our rating agencies and placed $750,000,000 of medium term notes in Canada to fund the growing NGTL system rate base. At the end of June, we also reset the rate on our Series 3 preferred shares from 4.0% to 2.15% for the next 5 years. At that time, holders elected to convert 5,500,000 of our 14,000,000 outstanding Series 3 shares into floating rate Series 4 preferred shares, which will pay a floating quarterly dividend for the same 5 year period at a yield of 90 day Canada T bills plus 128 basis points.
The
initial Series 4 rate setting was at 1.95 percent per annum. In closing, the company produced very strong results from its diverse portfolio of critical energy infrastructure assets due to challenging energy market conditions. Comparable earnings per share and funds generated from operations were up 20% 16%, respectively, compared to the same period in 20 14. With a solid foundation in the form of high quality and diversified suite of assets and a sizable portfolio of small to medium sized growth projects under development, we remain committed to continuing to increase the dividend at an annual rate of 8% to 10% in 2017. Our strong internally generated cash flow from our 3 core businesses is expected to provide a significant source of funding for our capital program in addition to underpinning a growing dividend.
Given our financial strength, we remain well positioned to finance our capital needs throughout various market conditions. Finally, we also continue to advance a number of attractive opportunities in addition to our $46,000,000,000 of commercially secured projects 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 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.
Thank you. And the first question is from Paul Leachim from CIBC. Please go ahead.
Thank you. Good morning. Question on commentary in your written materials on your intra Alberta oil pipelines experiencing a slowing pace of growth. So I'm just wondering if you can elaborate on that, what that means in terms of in service dates and costs on Grand Rapids, Heartland and Northern Courier?
Sure, Paul. It's Paul Miller here. We I'll start with Northern Courier. We are proceeding with the construction of Northern Courier and it's proceeding well, targeting a 2017 in service date. On our Heartland pipeline, we continue to enjoy solid commercial support, and we've elected to proceed with the project at a time when the committed volumes require transportation.
We continue to contract up Heartland, but we're aligning the in service date with Heartland when we need to move those volumes to the marketplace. On Grand Rapids, we are proceeding with the in service for Grand Rapids for initial volumes in 2016, and we will follow-up with the full system deliveries in 2017. We do anticipate, however, a slowing growth of throughput and the build out of the Grand Rapids system to align with the slowing pace of growth of oil production that we're seeing in Alberta.
Okay. So is that meaning you that Heartland now has no fixed in service dates is what you're saying?
That's correct. A lot of the commercial underpinning for Heartland is tied to Energy East and Keystone XL. And as we get better visibility to the in service date of those 2 XL greater pipelines, we'll look at the in service date for Heartland or as we contract independent volumes on Heartland.
And if I could just ask a couple of questions on PRGT. You haven't yet given us an updated cost
for that. But the
pipeline from when it was initially announced has increased the route has increased by about 25% in additional kilometers 20%, I guess. Some of that's underwater. So should we be thinking about like on an order of magnitude here, the costs have gone up at least 20% and potentially significantly more. Is that how we should be thinking about it?
Paul, it's Alex.
As Russ mentioned, we are seeing cost pressures on that largely for some of the reasons that you've identified, which is increased scope and some more complexity in the project. And we are our plan, when this project is finally sanctioned, we will give an update. Our customer is fully apprised of where we are, and we don't think it's going to be very much longer before we can give a bit of an update. But I don't think we're going to speculate at this point.
Okay. Thanks. Thanks, Paul.
Thank you. The next question is from Robert Catellier from GMP Securities. Please go ahead.
So just some additional clarity here on the intra Alberta slowing. So this is a question of just moving out the in service dates and there's no deferral or makeup for the impact to TransCanada? It's
Robert, it's Paul Miller here. And just I understand your question, but maybe just back up a bit. So on Grand Rapids, we're proceeding with the construction of Grand Rapids, the Duo pipeline system. We have in place an anchor shipper who requires the Duo system and we're targeting the 17 in service. Beyond the anchor shipper, we would anticipate building out the system through laterals, etcetera, to attach to incremental production.
That build out and the bringing on of additional volumes beyond the anchor shipper will continue, but we believe at a slower pace than initially anticipated.
Okay. And then can I give an update on Bruce Power to see if there's been any advancements in bringing that to a final investment decision?
Sure, Robert. It's Bill Taylor here. The status of discussions with between Bruce Power Management and the IESO on the potential transaction associated with refurbishments of Units 3 through 8 are continuing. I can report that they're progressing well. We haven't reached any definitive agreement at this point, but we are quite encouraged with the progress.
The next question is from Andrei Kalsky from Credit Suisse. Please go ahead.
Thank you. Good morning. I guess the question just relates to a bit of the capital flexibility that you've got. And how are you thinking about just your balance sheet right now and just a bit of the interest rate dynamics across the border where you've got an environment in the U. S.
With rising rates, Canada more compression. And then obviously what also falls into the mix is a little bit of what we've seen in the MLP market in the U. S. Where that's really come back in pretty dramatically where you've seen about a 20% decline in a lot of the names.
In terms of the balance sheet strength, it really doesn't vary at any point of the cycle here. It's a solid grade credit and allows us to act on whatever might arise. In terms of interest rate exposure here, we're predominantly fixed rate finance. So, terms of a rising U. S.
Rate environment, shouldn't have any significant impact on us. In general, we have about average turnover debt is 16 years and we're over 90% fixed rate funded. In a rising interest rate environment as well, we have a significant cost pass through ability on several of our projects and assets. So we're the things we can control on the interest rate front, we think we're in pretty good shape there. We'll see what the FX dynamic here is if you do see rate diversion in Canada and the United States.
Just from an FX perspective, for every $0.10 move in the currency, yes, every $0.10 move in the currency, it's about $0.10 impact on earnings. We do hedge on a rolling 1 year forward basis here. So not seeing much impact from this fairly sizable shift in the currency over the past 12 months coming through yet, but we should start seeing that come through in future quarters years here. In terms of the overall environment, looking at assets and the like, we're always being who we are, we see pretty much everything that transacts in North America. So we're, as always, interested observers.
If anything comes loose that there might be of interest and fits our criteria. But really no change at this point of cycle from any other point of cycle other than we'll see what if anything does arise.
That's helpful. And then maybe just a follow-up, moving away from just the interest rate movements themselves, maybe on spreads, are you seeing less movement with the A credits like yourself versus the BBB and BBB kind of credits that are in the marketplace right
now?
Yes, it's
pretty broad spectrum of credits out there, but generally it's when you do see stress market conditions where the A diverges from the lower rated credits more dramatically. That's the environment we appear to be headed into. So the benefits of the AR are probably more pronounced in these choppy market conditions than when things are robust across the complex.
Okay, that's very helpful. Thank you.
Thanks, Andrew.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go
ahead. Good morning. If I can just start with Keystone. Just wondering if you're part of the better results as well. Are you seeing a trend to any shippers bypassing Steel City and setting more crude into the Gulf Coast?
Robert, it's Paul Miller here. The Gulf Coast market has seen increased activity on Keystone or Keystone's seen increased activity down to the Gulf Coast, largely sourced at Cushing. The Cushing market from Hardisty based barrels continues to be the market of choice, it seems. We saw the spreads pretty strong here between Hardisty and Cushion in the Q1. They collapsed into the first part of the Q2, but they've seemed to have rebounded a bit here.
So we're seeing good flows into the Cushing market and then from the Cushing market down to the Gulf Coast.
Okay. And so there is though a financial benefit to you just with the way you're picking up volumes on the southern part of the system?
There is. We're flowing about 450,000 barrels per day on the southern part of the system. That's up from about 400,000 barrels a day late last year into the Q1. On Keystone, we've seen our flows increase into about the 5 50,000 barrel per day range, and that's been fairly sustained over the course of 2015.
Okay. If I can just look at around more capital allocation in the dividend and you've got 2 kind of upside options here, one around the value of all the projects you've got and then also around doing something on the dividend. I recognize you don't want to do anything to jeopardize the value of the projects by painting yourself into a corner on funding. I guess though when you look at the delays in Alberta and look at how Energy East has been pushed back and Keystone XL has been pushed back, it kind of feels like if that's to come together regardless, it's just going to be a size that you can't finance out of your cash flow. So is there an ability to move the payout ratio up a little bit just to get that dividend growth that you have at 8% to 10% to something north of 10% to be a little more competitive with the North American peers?
Yes, we're it's Don here. The capital program is still in that $6,000,000,000 range for the next couple of years here as well. So it's not entirely hinged on the large projects. There's quite a sizable portfolio of the small to midsize stuff that we continue to finance. So we expect to add to that portfolio here over time.
So it's a balancing act in terms of prudency and we recognize fully the value that our shareholders place on the dividend. And the growth in that dividend, we think earnings do matter. So that is the metric that factors into it. But yes, this 8% to 10% range is our comfort level right now based on what we have in front of us and with the A grade credit and the like and we continue to revisit that as we see our portfolio develop returns here. Maybe just
to add to that, Robert, it's Russ, is I mean, as we've said before, is the 8% to 10% predicated on our projects that we've got underway to get us into that range of into a higher range. We'd be greater confidence around the future of those capital projects. So as we see greater visibility of those actually coming to fruition, whether that be our West Coast LNG projects or the long haul oil projects or even some of the other projects that we're working on in our portfolio right now that are substantial. If we see the direct line of sight to that long term earnings and cash flow growth, we don't have a major issue with increasing our payout ratio in the short run. But as we said, kind of to get above that 8% to 10% level, we want to have some greater visibility around those longer term projects.
And certainly, that's what we're working on.
Yes. We're not going to hold back dividend growth to store up capital for these large projects. And the magnitude of them aside, they are all heavily or fully contracted for decades. So we're pretty comfortable in the fancibility of those projects. We view it as a high grade problem if we did have to get out in the marketplace and finance them.
But that's the dynamic we're looking at right now. We're not going to hold back dividend growth and we may augment it if we have greater clarity on earnings and cash flow growth going forward.
Okay. So any step up in dividend growth really is tied to larger projects. Is there anything else that you might be considering that could develop that would cause you to want to move the payout ratio up?
Well, I think as we said, I mean, the long term projects are one greater visibility of growth in our base business. As we said, there's several organic projects on our horizon, greater visibility of build outs of the NGTL system, the ANR system bringing Marcellus gas moving south and the expansions of those kinds of systems. As we see our base business continue to grow as well, that gives us greater confidence. I think as Don said, earnings do matter to us, but sort of visibility of the growth in that and that the payout ratio in the short run isn't a major sort of factor. It's where we think things are going over the long term.
So there's obviously those shorter term organic projects, greater efficiencies that we can gain in our base businesses, along with those greater visibility to future opportunities will be the things that drive our dividend decisions over the coming quarters and years.
That's great. Thank you very much.
Thanks, Robert.
Thank you. The next question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I'm wondering on your NGTL project, what is the scale of possibilities in terms of further requests? And I'm assuming it's somewhat constrained by your ability to develop in that region. So can you talk about if this is more of an backend loaded this decade or if there's some potential in some way to accelerate some of your expansions there?
For the NGTL system, it's Karl, Linda. Yes, right now, as you know, we're undergoing about a $2,700,000,000 expansion of that system. We have our regulatory applications in for about $2,000,000,000 of that, and we're working on the rest right now. We're seeing very little slowdown in that expansion. Our customers are asking that we proceed on it.
And we although we may see some of it extend into 2018, we're expecting the vast majority of it to be completed in 20 17. Aside from that, we have closed the queue recently on NGTL. We have more receipt service requests for firm transportation on NGTL right now in front of us. We are just going through the system design for that request and we will hopefully in the next couple of months be able to determine what type of expansion that will be. Probably won't be as big as a 2,700,000,000 expansion that we're undertaking right now, but there is a reasonable amount of receipt service requests in front of us right now for that people are asking for.
So we will have some expansion coming over 2018 and beyond.
Thank you. And just as a follow-up, Carl, your some of the pressure restrictions you're seeing right now, do you see that being on schedule to get resolved with the NEB?
Yes. We're expecting the NEB issues, the derates from the NEB, we expect we're still expecting kind of September, maybe late September to have them all lifted. The pressure restrictions you are seeing right now is clearly on the western side versus some kind of Western Alberta and Northeast BC are both from our integrity work, both our normal integrity work and the integrity work we requested from the NEB and our regular maintenance process right now. This part of our system is extremely full and we have been cutting interruptible transportation quite significantly over the last few months. And hopefully by the end of Q3, we'll have most of the maintenance integrity done and we will have some more interruptible transportation for our customers.
But really the most of the cuts that we have done have been the interruptible transmission. We have seen some firm service cuts, but they generally be nicely in a short duration. But we do hope by the end of Q3 that we'll have reestablished that interruptible capacity for our customers back again.
Great. Thank you. And just as a follow-up on your Alberta power hedging philosophies and approach. I realize there's some competitive dynamics and sensitivities. But can you comment on how much you've been dispatching your PPA contracts?
And to the extent that, that has maybe come down in expectations as well for the next year or 2, is there, I guess, a bias towards less to no contracting to ensure you're not long power during these lower price times? Or can you comment on how you're approaching your Alberta fleet?
Yes. You're correct Linda that we don't typically like to discuss the approach we're taking to the Alberta market in any detail for competitive reasons. But I can tell you that we approach it cautiously as it relates to you saw some of the activity in late May and into June that impacted the quarter as it related to some outages in the Alberta market. So we approach our program pretty carefully as it relates to ensuring that well positioned to not only capitalize on those kinds of opportunities, but also to ensure that we don't find ourselves on the wrong side of events like that. So I mean, in terms of going forward, I think that the market, as Don mentioned in his opening remarks, is at present pretty well supplied.
We've seen some reductions in overall demands with the general economic climate in Alberta at the moment. And so we're cautiously optimistic that there may still be some opportunities in the latter half of the year. Prices have obviously been quite low other than the adjustments that occurred in June due to some outages. So I mean that's about all I guess I can say on that.
Okay. Thank you.
Thank you. Thanks, Linda.
The next question is from Rob Hope from Macquarie. Please go ahead.
Thank you and good morning everyone.
Good morning Rob.
Most of my questions have been answered, but maybe just a few clarifications. On the Grand Rapids, can you maybe comment on how much anchor volumes you have on the system and what an expected ramp in returns would be
on there?
Bob, it's Paul Miller here. We haven't released the anchor volume commitments. The Grand Rapids has the capability of moving 900,000 barrels per day of blend southbound and then Neely went northbound. The anchor shipper in itself provides us with the threshold volumes to proceed and with a suitable return. We'll probably start the capacity of Grand Rapids out of the gate at a lower amount in that 500,000 to 600000 barrel range and then add power as we go.
But we haven't disclosed the shipper's commitment and it's inappropriate for us to do so, but it is enough to proceed with the project and then attract additional barrels as the production grows.
All right. Thanks for that. And then maybe just shifting east, I just noticed that the Eastern Mainline and service date shifted to 2019 from 2017 in your disclosure versus Q1. Is that just to line it up in terms with the Energies oil project?
Yes. Rob, it's Karl. Yes, that's just we're just lining it up with the Energies project.
All right. Good to hear. Thank you.
Thank you. The next question is from Matthew Hackman from Scotiabank. Please go ahead.
Thanks. Good morning. Good morning, Matt. Couple of questions just around the triggers for construction on Pac Northwest LNG. And obviously, the permitting is going very well at the provincial level.
And on the other hand, some of the First Nation stuff is a little more choppy. So I'm just wondering, let's say we get an FID, would TransCanada begin construction on the pipeline even if some of the First Nations' legal challenges persist?
Hey, Matthew, it's Alex. I think we've always said with this project, I mean, we seek to reach agreements with all of the affected First Nations. And I think if you've seen our disclosure over the last couple of months, you've seen that we've been making a significant amount of progress in signing project agreements with a number of the bands on both
of the
projects. From our perspective, we believe that we will, by the time this project is ultimately sanctioned, reach agreement with the vast majority of affected First Nations and it has never been a criteria for us that we reach that we get 100% of those. That's obviously what we strive for, but we think we're well on the way of getting a significant base of support for this project to proceed.
Can you just please confirm, Alex, that any risk related to any legal challenges or tolling issues on North Montney on the project are the risk of Petronas and not TransCanada?
Sorry, on the North Montney 1st off, on
the Pac Northwest ONG, if there's any risk related to legal challenges following construction commencement, whose responsibility is that TransCanada or Petronas? Well,
it's Karl. I can talk about the North Montney and that's an NGTL project. So we would be so that would be the risk of building that infrastructure would be part of the NGTL infrastructure. So I guess if we had any delay or whatnot, that would be between NGTL and our customers there.
With respect to PGRT, I mean, the way that it's constructed, Matthew, is that we're building this on behalf of our customer. And for the most part, all of the risks pass through to that customer. I mean, you're it's a hypothetical question that you're asking that's got myriad of potential outcomes, which I wouldn't want to speculate at this point in time. As Alex said, I mean, our intent is to get as many First Nation agreements as we can. And we believe that our agreements will protect our shareholders.
But I mean, I don't think I can share with you much more than that as at this point in time.
Thank you. The next question is from Steven Paget from FirstEnergy Capital. Please go ahead.
Well, thank you and good morning.
Carl, could
you please update us on progress at Clearwater and what we can expect in the remainder of the third quarter at that
station? For the I mean, the outage
that we have there? Units 15, yes.
Yes, yes. So So we are making good progress. We are expecting it to be able to reestablish our firm service here before the end of Q3. So that's all I can say right now. It's quite a recent issue that we've had, but it's we are working on getting it back up.
Thank you. Second question, the Magellan announcement looks like it gives some optionality to the Houston delivery and the Keystone XL. Is there an opportunity to add similar connectivity to the Port Arthur end? Or is that pretty much got all the connectivity it needs?
Hi, Stephen. It's Paul Miller here. So you're accurate on the Magellan opportunity. We're excited about being able to team up with Magellan and allow us to essentially access the 2,000,000 barrels per day plus refining capacity in the Houston, Texas City marketplace. And that's a business model we like where we can team up with folks downstream of us to encourage flows on the Keystone system.
So we'll continue to look for similar opportunities in all the markets we serve, including the Port Arthur marketplace. And I do think there's opportunities in Port Arthur.
Opportunities there. Final question, if I might. Are we looking at any further dropdowns to TC PipeLines LP in the remainder of the year?
It's Don here. Yes, we're can't give you a specific timing, but we're still on a path to bend the rest of our U. S. Gas pipes into that vehicle on a systematic basis. So there's been no change to our thinking.
Well, thank you. Those are my questions.
Thanks, Stephen.
Thank you. We'll now take questions from the media. And the first question is from Ashok Datta from Platts. Please go ahead. Mr.
Duffy, your line is open.
Hi, good morning. Two very quick questions if I may please. When or at what stage will you take a call on the single export terminal at Energy East?
Hi Ashok, it's Alex Pourbaix. As Russ said in his prepared remarks, we are well advanced in the process of determining the ultimate configuration for Energy East. We've stated that our plan is to file an amendment with the National Energy Board prior to the end of the year. I think we're still on that path and we are relatively close to making that decision.
Okay. And the second question, in that case, in case there is only one terminal, how would refineries in Quebec be served?
Even in the event that we were to proceed without a marine terminal in Quebec, all options that we are considering would continue to have the pipeline direct connected to the Quebec refineries. So, under any scenario, Energist will be able to serve the overwhelming need of those refineries in Quebec.
Okay, lovely. Thanks.
You're welcome.
Thank you. The next question is from Julien Arcono from La Festa.
Regarding the possibility of another terminal in Quebec, how has been the evaluation towns and regarding this possibility? Some towns regarding this possibility?
Thanks for the question, Julian. Once again, Alex, Pourbaix here. We have undergone a really comprehensive review of all of our options and those go from looking at alternative sites along the St. Lawrence within Quebec to, as we mentioned, potentially just going with 1 marine terminal in New Brunswick. And in all of those cases, we have engaged with stakeholders and we'll make an informed decision based on all of those discussions and the information we gathered from that.
Okay. And second question, I wanted to get your thoughts TransCanada. For the last month and a half, the tone of the Prime Minister of Quebec seems to have changed regarding energy. He now says that the financial impact are not sufficient enough in Quebec to for the government to give us approval to the project. What do you make of that change of tone from the last 1.5 months?
I'm not sure there's been a significant change in tone. I think from the very early days, both the Quebec government and the Ontario government have indicated that their conditions for support include looking at the economic benefits of the project to their respective provinces. And one of the I think something that is often lost in this discussion is whether or not you talk about a marine terminal, there is already an extraordinary economic benefit for those provinces. I think that my recollection is that just through the construction period and operation period in Quebec alone, we and our consultants are estimating GDP impact in excess of $6,000,000,000 We're going to employ 4,000 people alone, full time equivalents through the development and construction stage. But on top of that, we really do take seriously that these projects have to provide long term benefits in the provinces in which they're situated.
You might have seen several months ago, we announced in Peterborough with GE that as a result of Energy's proceeding, GE has been able to make a commitment to move their large industrial motor production Global Center of Excellence to Peterborough, that's totally based on the Energies project proceeding. And I would just suggest that everybody should stay tuned because over the next several months, as we give more clarity on Energies, on the scope and the alignment of the project, we also intend to roll out a lot more positive information about the benefits of this project to the provinces. We're not at all concerned at the end of the day that this project will pass that criteria of providing economic benefit for the provinces.
Okay. Was that Mr. Porbet who answered my question, not sure of the voice?
Yes, it was Alex Pourbaix.
Okay, thanks.
Thank you.
Thank you. The next question is from Lauren Krogl from the Canadian Press. Please go ahead. Good morning. I'm just looking at the capital program chart and the figures for the cost estimates and how much have been spent.
And I see about $700,000,000 on for Energy East. I'm just wondering at this stage in the process what that figure would have been spent on given that it is so early on.
Well, it's I think the first thing you have to look at is, first of all, this is a 4,500 kilometer project. It has 75 pump stations. This project has very, very significant scale and scope. And where the regulatory process has gone, in order to make a regulatory filing, a very significant amount of field work, environmental studies, technical studies, engineering reports needs to be prepared along with preliminary engineering. All of this is required just to inform the application.
On top of that, there is a real significant obligation and something that TransCanada would do in any event, but to work with stakeholders in the regions. And to give you an idea, we have held in excess I think it's somewhere in the range of 120 open houses. We've worked with the better part of 8000 or 9000 individuals in terms of our stakeholder outreach. The last I saw, we have already held 1600 meetings with affected First Nations along the route. And as you can imagine, all of that work has costs associated with it.
The one thing I would say is that at where we are right now in terms of cost for the project, there's very little incremental cost required to get us to the regulatory hearing stage. So a lot of that number that you saw is we don't expect that number to get significantly larger prior to the hearing. The other issue that I should also mention is in order to make the application, we also have to satisfy our regulator that the pipe the existing gas pipe that we are proposing will be converted to oil usage. We have to do a significant amount of integrity work on those pipes and that work has been done once again to inform our application and give comfort to the regulator.
Okay. Thanks for the clarity on that. And that sounded like Alex answering the question? Yes.
Sorry, Alex again.
Okay, great. Thanks so much.
Okay.
Thank you. The next question is from Rebecca Penney from Bloomberg News. Please go ahead.
Thanks for taking my question. It's about Keystone XL. As you guys are well aware, there's been lots out recently regarding the potential for Obama to reject Keystone XL in August when the Senate leaves. I'm just wondering in terms of the possibility of a NAFTA challenge and an investor state dispute settlement, as it's called, I'm wondering how TransCanada is looking at event that Obama does protect the line?
I think as we've said before, Rebecca, I mean, TransCanada will employ whatever means necessary to protect its shareholders and its shareholder value, But that's not our focus at the current time. As I said, our focus is on the regulatory proceedings, as you know, in South Dakota and working through those issues, working through the outstanding Supreme Court issues in Nebraska and getting ourselves in a position so that we can construct this facility upon a positive decision by the Department of State. With respect to rumors and things like that. We've been at this for 7 years now and there's been lots of rumors about lots of different things. And we continue to just sort of focus on the things that we're good at, which is trying to get a safe and reliable pipeline built.
I don't want to speculate on what happens sort of post any kind of scenarios or outcomes. At this point in time, it's not our focus.
Would you comment at all on how you see the like whether it could be successful, any kind of naphtha challenge?
As I said, it's not at this point in time. That's not a focus that we have. No decisions have been made. So it premature to speculate on anything like that.
The next question is from Claudia Catania from the National Post. Please go ahead.
Actually, I'd just like to follow-up on the last one. I know that your focus is not on what other options you might have on Keystone XL, but if it does get rejected, would you just refile a new application under a new administration? And would a re filing basically involve like can you use some of the work that you've already done or it would have to be a complete refiling of an application for Keystone XL?
Claudio, as I said, no decision has been made. It's difficult
to speculate on that. I guess what I can tell you is that the demand for the project is greater than it was when we made the application. I think as you've heard me say before, production is up in Canada. We're moving more barrels by rail. Production is up in the U.
S. Coming out of the Bakken. They're moving that production by rail. Demand is up in the U. S.
So the need for the pipeline remains. All of our shippers remain 100% supportive even through the declining commodity price here that we've seen. We've gone back to all of our shippers. As I said, we continually work with them on all of our projects to understand what changes in commodity prices will have on their future needs. They've reiterated their need for Keystone Pipeline and their commitment to their contracts.
So it would be our intent to continue to press to build that pipeline because the demand doesn't change. So obviously, that would be our intent under end scenario is to continue to press for the approval of building this pipeline. What that would require in the event that you outlined, we can't speculate on that what that is because we don't know what that looks like at the current time. But certainly, we don't see there's any rationale at the current time for a negative decision. As I said, we've in my prepared remarks, the greenhouse gas emissions question has been answered several times by the Department of State in its environmental review.
The question of safety has been answered. And at the current time, we see no rationale for anything but a positive decision. So that's when we continue to press and provide information to the Department of State that help them augment the current record and drive us towards making a positive decision.
If I may, just a follow-up. You highlighted in a recent letter to the State Department the fact that Alberta has implemented more stringent climate change regulations. Have you heard any response at all about that?
No, we haven't. We filed that information as we do on a continuous basis with the Department of State, any material updates. And given that the greenhouse gas emissions question has gathered so much attention, we wanted to ensure that the record was as full as possible and had indicated, A, that the decision the conclusion had already been come to that the pipeline won't have an impact on greenhouse gas emissions. The EPA had indicated on several occasions that Canada could be doing more. So we updated the Department of State with, as you pointed out, the most recent changes in Alberta emission regulations, which increased the stringency on a per barrel basis in terms of reduction emission targets and increase the penalties, if you will, if emissions are above those levels.
That's a significant incentive for the industry to continue to reduce greenhouse gas emissions. They continue that. At the same time, we updated the Department of State on Canada's commitment to greenhouse gas reductions. They had made certain statements with respect to their position going into Paris, the 30% reduction by 2,030, their 2,050 reduction targets and the 2,100 reduction targets as well. So in terms of the greenhouse gas emissions questions, what our intent there was, was to ensure that the record was up to date as much as possible.
And I guess, again, to indicate that the Canadian production continues to be a leader and Canadian jurisdictions continue to be a leader in greenhouse gas emissions reduction standards relative to either producing countries around the world.
There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. 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.
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.