TransCanada Corporation (NYSE:TRP)
Q2 2016 Earnings Conference Call
July 28, 2016 11:00 ET
David Moneta - VP, IR
Russ Girling - President & CEO
Don Marchand - EVP, Corporate Development & CFO
Alex Pourbaix - COO
Karl Johannson - EVP & President, Natural Gas Pipelines
Paul Miller - President, Liquids Pipelines
Bill Taylor - President, Energy
Glenn Menuz - VP & Controller
Linda Ezergailis - TD Securities
Robert Hall - Scotiabank
Robert Kwan - RBC Capital Markets
Ted Durbin - Goldman Sachs
Ben Pham - BMO Capital Markets
Andrew Kuske - Credit Suisse
Steven Paget - FirstEnergy
Faisal Khan - Citigroup
Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.
Thanks very much and good morning, everyone. I'd like to welcome you to TransCanada's 2016 second quarter conference call.
With me today are Russ Girling, our President and Chief Executive Officer; Don Marchand, Executive Vice President, Corporate Development and Chief Financial Officer; Alex Pourbaix, Chief Operating Officer; Karl Johannson, Executive Vice President and President of our Natural Gas Pipelines Business; Paul Miller, President of our 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 their prepared remarks, we will turn the call over to the conference coordinator for questions from the investment community. If you are a member of the media, please contact Marc Cooper or James Miller following this call and they would be happy to address your questions.
In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or detailed financial models, Stewart and I would be pleased to discuss some 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 Exchange Commission. And finally, I'd like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest taxes, depreciation and amortization or EBITDA; funds generated from operations; and comparable distributable cash flow. 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. They are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance our operations.
With that, I'll now turn the call over to Russ.
Thanks, David and good morning everyone and thank you for joining us. I am very pleased to announce another solid quarter for all of our base businesses operated safely, reliably and continue to deliver solid financial performance. As was highlighted in our press release, year-over-year earnings were primarily impacted by a pair of events; first, net income and funds generated from operations were down due to the one-time dividend equivalent payments made on subscription or receipts related to the Columbia acquisition and second, comparable earnings were largely impacted by a once in a decade station containment outage at Bruce Power.
With the closing of the Columbia acquisition behind us and the successful completion of the Bruce upgrades, we expect to generate stronger earnings in cash flow going forward. As I said, our three business segments all performed well during the quarter, TransCanada reported net income of $365 million or $0.52 a share. Comparable earnings for the quarter were $366 million or $0.52 a share. Comparable EBITDA was $1.4 billion, funds generated from operations were $831 million after the $109 million dividend, equivalent payments on subscription receipts and comparable distributable cash flow was $698 million or $0.99 per common share.
Earlier today the Board of Directors declared a quarterly dividend of $0.565 per common share for the quarter ending September 30, 2016, equivalent to $2.26 per common share on an annualized basis. In a few minutes Don will provide more detail on our Q2 financial performance and our financial outlook but first I'll highlight some of the key developments over the quarter.
At beginning of this month, as you're well aware we closed the Columbia Pipeline acquisition for $13 billion including the assumption a $2.7 billion of debt. This is a very significant once in a generation opportunity to acquire a competitively positioned growing network of regulated natural gas pipelines and storage assets in the heart of the Marcellus and Utica basins. As you know, this is the fastest growing natural gas supply region in North America with the lowest development and production cost along with the highest growth prospects of any large basin on the continent. The acquisition creates one of North America's largest natural gas pipeline companies. Today TransCanada operates over 90,000 kilometers or 56,000 miles of natural gas pipelines, enough to circle the globe more than twice.
As well, we now North America's largest natural gas storage business with 664 billion cubic feet a day of capacity. In addition to complementing our existing regulated pipeline of storage businesses, our customer base is further diversified and we have improved access to key markets in the U.S. Northeast, Midwest, Mid-Atlantic and Gulf Coast. As well the Columbia Pipeline Group $7.3 billion of modernization and commercially secured projects are now an important part of our $25 billion near term portfolio of growth projects that are expected to deliver significant shareholder value as they begin operating largely in the 2016 to 2018 timeframe.
As was previously announced portfolio management will play an important role in financing the acquisition and sale of our U.S. Northeast merchant power assets and a minority interest in TransCanada Mexican natural gas pipeline business. The funds from those asset sales along with proceeds from the subscription receipts are expected to make up the required funding for the acquisition, well maintaining the company's financial strength and they flexibility to continue to fund our growth projects going forward. The asset sale process is progressing, advisers have been engaged and the initial stages of soliciting interest -- interested parties is well underway and we would expect to be able to write an update by the end of 2016.
In addition to the Columbia acquisition we continue to advance our growth strategy on many other fronts. In Mexico, our joint venture with IEnova, a subsidiary of Sempra Energy was is chosen to build, own and operate the $2.1 billion U.S. Sur de Texas-Tuxpan natural gas pipeline in Mexico. TransCanada alone at 60% interest in that project and expects to invest $1.3 billion U.S. to construct a the 42-inch diameter, 800 kilometer pipeline. We anticipate that pipeline to be in service in late 2018. The Sur de Texas-Tuxpan pipeline is the most recent addition to TransCanada's expanding portfolio in Mexico. In the last eight months, TransCanada was awarded the $500 million Tuxpan-Tula and the $600 million Tula-Villa de Reyes [ph].
Tula-Villa de Reyes pipeline, construction of those two pipelines is already underway and we expect them to be operational in 2017 and 2018 respectively. We continue to expect our Topolobampo and Mazatlan natural gas pipelines in Mexico to be in-service later this year. In total, our footprint of existing assets and projects in development in Mexico is now more than $5 billion. All of those are underpinned by 25-year with Mexico State Power Company. Here in Canada, our NDTL system -- we placed about $450 million of facilities into service in the second quarter of the year, another $400 million of facilities are approved and currently under construction. A further $2.9 billion have yet to be filed with regulators but we'll be doing that in the coming months.
In addition, new long-term contracts signed during the quarter to deliver gas to the Alberta and then further into our Gas Transmission System and on the West Coast will require construction of about $135 million of new facilities not previously included in our 2018 program. We continue to look at it at other additional demands for service and are re-evaluating all of our facility primes [ph] to meet those needs over the coming months. In addition, some changes in the timing of our spend on NDTL system will likely occur to match revise in service dates with certain producer facilities but in total, the capital commitment for NDTL remains at approximately $5.4 billion including the North Montney pipeline.
We continue to advance our $45 billion portfolio of a larger scale long-term projects on July 11, LNG Canada announced that due to challenges in the current global energy market their joint venture participants Shell, PetroChina, Mitsubishi and Kogas have determined that they will need more time prior to making final investment decision. Coastal gas link enjoys strong stakeholder and First Nations support and it has all of its key approvals. We will continue to advance the project consistent with the revised timelines of LNG Canada. On the Prince Rupert Gas Transmission project the team continues to engage with Aboriginal communities and other stakeholders along the route in preparation for final investment decision by Pacific Northwest LNG.
On Keystone XL, in June we filed the official request property for arbitration with the International Center for settlement of investment disputes under the North America Free Trade Agreement. This means the panel of three arbitrators will soon be tasked with determining whether TransCanada is treated fairly in a protracted 7-year review. On June 16, the National Energy Board announced to starting the clock for the review of Energy East and also determined that the project application was complete.
The National Energy Board's review starts on August 8 and while crude opportunities for the general public to provide input and for hearing participants to question the applicants in person. The National Energy Board will have 21 months to carry out its review, once complete the NEB will submit a report to the Minister of Natural Resources recommending whether the project should proceed along with any conditions. This route reported due no later than March 16, 2018. Federal government has said it will then take up to an additional six months to consult further with Canadians and then make a decision.
What I would say is that today our company is better positioned to grow cash flow, earnings and dividends than at any other time in our history. The Columbia acquisition itself is expected to be accretive to earnings per share in the first full year of operation providing increased revenue from predictable, regulated and long-term contracted assets. As we have said, this supports our 8% to 10% expected annual dividend growth rate through 2020. A dedicated team is now focused on realizing that $250 million of annual cost, revenue and financing benefits we forecast would result from the integration of Columbia into TransCanada and we remain confident that those targets are achievable. We continue to expect savings of approximately $125 million in 2017 and $450 million of cost savings by 2018. The remaining $100 million is expected to come primarily from financing benefits.
With the U.S. 7.3 divest of our merchants businesses and optimize our growth portfolio that percentage is expected to increase in the future. Going forward, we will continue to prudently finance our growth with long-term capital and as we marked another solid quarter and we're very excited to have closed the Columbia acquisition. We're confident that this acquisition will lead to both near term and long-term opportunities for our company. TransCanada is one of North America's leading energy infrastructure companies with earnings and cash flow underpinned by regulated cost-to-service businesses and long-term contracted assets. Today we have an enviable well diversified footprint of critical infrastructure assets that deliver stable and growing cash flow.
Our blue-chip asset base along with $25 billion of near term projects are expected to support our dividend growth rate of 8% to 10% through 2020. For the focus on safe operations and disciplined execution of our plans, including the Columbia acquisition, I'm very confident we will achieve our vision of being the leading energy infrastructure company in North America while continuing to generate superior risk-adjusted returns for shareholders.
That completes my prepared remarks and I'll turn the call over to Don for some further details on our second quarter results. Don?
Thanks Russ and good morning everyone. As highlighted earlier, we reported net income attributable to common shares in the second quarter of $365 million or $0.52 per share. Second quarter 2016 included an after-tax charge of $113 million associated with the Columbia acquisition costs, a $109 million of which related to dividend equivalent payments on the subscription receipts.
In addition, we recorded a $10 million after-tax restructuring charge related to expected feature, out of the money lease commitments and $9 million after-tax related to Keystone XL maintenance and liquidation costs. Excluding these items comparable earnings for second quarter 2016 decreased by $31 million to $366 million or $0.52 per share compared to $397 million or $0.56 per share for the same period last year. In the quarter Bruce Power units 1 through 4 were removed from service for approximately three weeks. It's been a once a decade station containment outage. Plant maintenance on units 2, 3 and 8 was also conducted in the second quarter with some work on unit 3 continuing into the third quarter. As a result Bruce's availability was reduced to approximately 71% in the period. While some additional plant maintenance is scheduled in fourth quarter 2016, Bruce Power's overall average plant availability for the year is expected to be in the low 80's.
Other items contributing to lower comparable earnings in the second quarter were higher interest expense as a result of debt issuances, net of maturities and lower capitalized interest, lower and contracted volumes on Keystone and market link, lower earnings from Western Power and lower mainline incentive earnings; these were partially offset by realized gains in 2016 versus realized losses in 2015 on derivatives used to manage our foreign exchange exposure. Higher AFUDC on regulated projects increased earnings from ANR due to higher transportation revenues and lower -- or M&A expense and higher earnings from U.S. Power mainly due to an incremental contribution from Ironwood.
In terms of our business segment results at the EBITDA level, in the second quarter comparable EBITDA was essentially unchanged from the same period last year. Our natural gas pipelines business generated comparable EBITDA of $880 million in the second quarter compared to $799 million last year. The increase was largely driven by a higher contribution from our U.S. and international pipeline. When measured in U.S. dollars, comparable EBITDA for U.S. an international gas pipelines increased by $46 million for the three months ended June 30, 2016, compared to the same period in 2015. This was largely due to higher ANR Southeast mainline transportation revenues and lower OMNA expenses, higher transportation revenues on Great Lakes and a higher contribution from TC Pipelines LPE; partially offset by lower contracted revenue on Mexican pipelines.
In addition, a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent in earnings from our U.S. and international pipelines. Canadian gas pipelines comparable EBITDA $581 million with slightly higher than the second quarter of 2015. For the quarter net income from the Canadian mainline decreased by $15 million, primarily due to lower incentive earnings and a lower average investment base. Higher incentive earnings were recorded in the second quarter of 2015 as the NEB approval of compliance tools related to the LDC settlement which was received in June 2015 resulting in the full year-to-date impact being recognized in that period. This resulted in approximately $11 million of incentive earnings related to the first quarter of 2015 being booked in the second quarter of 2015.
NGTL System net income increased $13 million year-over-year to $79 million mainly due to a higher average investment base. In Liquids, the Keystone pipeline system generated $279 million of comparable EBITDA in the second quarter which was a $38 million decline from the same period in 2015. The decrease was the net effect of lower and contracted volumes on the Keystone pipeline system and lower volumes in market link, partially offset by the positive impact of the stronger U.S. dollar. Turning to energy, comparable EBITDA of $236 million in the second quarter declined $31 million from the same quarter last year due to the net effect of a lower contribution from Bruce Power mainly due to higher planned out that was also higher due to improved realized natural gas storage price as compared to last year.
Now turning to the other income statement items on Slide 18; comparable interest expense of $405 million compared to the same period last year. This was primarily due to higher interest cost as a result of long-term debt issuances in 2015 and 2016, partially offset by Canadian and U.S. dollar denominated debt maturities, a strong U.S. dollar and its effect on translated interest on U.S. dollar denominated debt and lower capitalized interest on Keystone XL related projects following the November 6, 2015 $230 million compared to the same period/quarter in 2015. As mentioned earlier, $113 million of this was related to the Columbia acquisition including the $109 million of dividend equivalent payments on the subscription receipts that were issued in April and that we have not normalized for an FGFO. Other items impacting FGFO include lower distributions, some equity investments, primarily related to the Bruce plant maintenance described earlier and higher comparable interest expense including lower capitalized interest associated with Keystone XL.
For the second quarter comparable distributable cash flow was $698 million or $0.99 per common share compared to $861 million or $1.21 per common share in the second quarter of 2015. The decrease in comparable DCF was largely driven by higher maintenance capital expenditures and items impacting FGFO as previously discussed with the exception of the dividend equivalent payments. Maintenance capital expenditures were $269 million in the quarter compared to $194 million for the same period in 2015. The $75 million increase was primarily attributable to repairs related to the first quarter outage at Holton Hills and continued elevated maintenance on the ANR Southeast mainline. Maintenance capital expenditures on our Canadian regulated natural gas pipelines was $42 million and $61 million in second quarter 2016 and 2015 respectively which contributed to the respective rate basis and net income.
For full year 2016 we expect -- we continue to be expect distributable cash flow coverage of around two times. Regarding investing activities, capital spending was approximately $1.1 billion in the second quarter, driven principally by expansions of the NGTL Canadian Mainline in ANR systems and construction activities on Mexico pipelines, Northern Courier and Napanee. Contributions to equity investments in the quarter relate to our investments in Grand Rapids and Bruce Power.
Now Turning to Slide 21, our liquidity and access to capital markets remained strong. On April 1, 2016 we issued $96.6 million subscription receipts at a price of $45.75 each for total proceeds of approximately $4.4 billion. This was used to partially fund the Columbia acquisition. The gross proceeds from the sale of the subscription receipts less amount to use for dividend equivalent payments were held in escrow until the acquisition closed on July 1, 2016. Following the closing of the acquisition, the subscription receipts were automatically exchanged for TransCanada common shares in accordance with the terms of the subscription receipt agreement and were delisted from the TSX.
At the end of June, we drew $6.9 billion under our bridge loan facilities to finance the balance of the Columbia acquisition. Proceeds from planned asset sales will be used to repay these facilities. As of June 30, 2016 the $13.1 billion of gross proceeds from the subscription receipts and bridged loan facilities were recorded as restricted cash on the balance sheet pending next to close the acquisition. The process of selling our U.S. Northeast Power assets and a minority interest in our Mexican gas pipeline business is proceeding as planned. We are in the initial stages of receiving preliminary expressions of interest. We expect to provide further updates related to the outcome of the process by the end of 2016.
Now Turning to Slide 22, at quarter end we had $1.7 billion of non-restricted cash on-hand and after a very active period [ph]. In June we issued $300 million of 7-year medium-term notes and $700 million of 30-year notes in Canada and interest rates of 3.69% and 4.35% respectively. In addition, ANR completed a private placement of $240 million of 10-year senior unsecured notes at a rate of 4.14% in the United States. In April we completed a public offering of $20 million Series 13 cumulative group redeemable first preferred shares at $25 per share resulting in gross previous proceeds of $500 million. The fixed rate dividend was initially set at 5.5% per annum and will be reset every five years going forward.
In second quarter 2016 Bruce Power issued recapitalization bonds and board under committed bank credit under a committed bank credit facility as part of its financing program to fund its capital needs and make distributions to the partners. During the quarter we received financing related distributions in Bruce Power of $725 million. On June 30, we also announced the reinstatement of the issuance of common shares from Treasury at 2% discount under TransCanada's dividend reinvestment plan commencing with the dividends declared on July 27, 2016.
In addition to drawing $6.9 billion under bridged facilities to fund a portion of the Columbia acquisition, year-to-date we have raised approximately $8.3 billion dollars across the capital spectrum on compelling terms. As a result we have made a significant dent in our 2016 consolidated funding requirements. Going forward multiple attractive funding options are available to us to finance our $25 billion of secured near term growth, including predictable and growing internally generated cash flow, senior debt, preferred shares, hybrid securities, portfolio management and equity principally through our dividend reinvestment plan. On July 1, TransCanada announced that we retained a financial advisor to assist in a review of strategic alternatives for a master limited partnerships holdings. We expect to be in a position to communicate the determination regarding the future of TC 5.5P [ph] and Columbia Pipeline Partners LP later in 2016.
Now turning to Slide 23, in closing during the second quarter of 2016, our diverse portfolio of high quality long life assets generated steady results. The completion of the Columbia acquisition was truly a transformational event for TransCanada and we are very excited about the opportunities this additional platform for growth will provide. Our overall financing position remains strong supported by our A-Grade credit ratings. We remain well position to finance our $25 billion portfolio of near term growth projects through strong and internally generate cash flow and access to capital consistent with our enduring financial strength.
Our industry leading suite of critical energy infrastructure projects is expected to generate significant growth in earnings and cash flow for our shareholders. The Columbia acquisition supports and may augment our expected 8% to 10% annual dividend growth through 2020.
That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.
Thanks, Don. Just a reminder, before I turn the call over to the conference coordinator for questions from the investment communities, we ask that you limit yourself to questions, if you have any additional questions please re-enter the queue.
Thank you. [Operator Instructions] The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I appreciate the detail around the expected synergy levels from the Columbia Pipe acquisition in 2017 and 2018. I'm just wondering maybe more in the near term do you expect any synergies in 2016 and with those be backend loaded and do you have a sense of the magnitude at this point? And I'm also wondering -- also looking over the next year in terms of financing, both the Columbia Pipe and other projects. How you might think of putting in permanent financing? Would you do it as you go or would you maybe be more inclined to wait until once the projects are in service and contributing?
Hi Linda, it's Don here, I'll start with the synergies. We are working through the math as we go here, we would expect some modest amount here in 2016, there will be costs associated with those synergies as well but I would say the inflection point here is probably in 2017 to see as get up to the 125 level of costs achieved in that year and 150 in 2018 for run rate in that timeframe. With respect to the funding program, I'll just walk us through our capital requirements and how we view things here over the next couple years. Looking at 2016 and 2017 including Columbia, we're probably looking at capital including maintenance in $7 billion-ish area for this year and north of $10 billion next year. That will be funded as we go -- real estate not looking to any large element pre-funding here, it's very much an ongoing spend here so it's not a huge spike but literally month-by-month kind of a profile on these things. So watch for us to just continue to chip away at that through market access and across the capital spectrum here.
As noted in my remarks, we've done about $8.3 billion of funding year-to-date aside from the bridge loan facilities. As we look forward, the philosophy is the same as always; senior debt within the constraints of an A-Grade credit rating, hybrid securities and preferred shares will form a healthy component here of the funding and then we've got the drip turned on. Now we would expect the drip to recapture 30% or 35% of the cash dividends based on the 2% discount, that's our historical experience on that. So that's pretty much the standard that you should see us employ over the next while we watch the cadence and the shaping of the spend here, we remain comfortable with the $25 billion of growth will be expanded in this -- primarily in the 2016. 2017, 2018 timeframe but we do see some stuff shift around like you've seen with NGTL this quarter. And we'll shape our funding accordingly as well.
Thank you. And just as my second question, with respect to capital allocation on the dividend part of the equation, augment is very intriguing word -- just what sort of factors might need to be in place to revisit your appropriate dividend growth level? Do you need to actually have realized the synergies or have a line in sight to that and do their growth projects need to be in service or how might you think of timing out of that augmentation?
It's Don again here. I would say line of sight and this was a fairly sizable transaction and a fairly sizable organization to integrate into TransCanada. So as we get a comfort level on the achievement of the synergies and the timing of the $7.3 billion and comfort level around that amount which we do have pursued hard due diligence but as we get the organization integrated. Where we look at our payouts are like -- I wouldn't look for us to make any major change in terms of payout ratios like any change in the dividend trajectory would be underpinned by real cash flow and not using leverage. So it's early days, here we've only have these organizations together for about three or four weeks right now but as our comfort level grows on the ability to deliver that we'll have a look at the capital allocation again.
Great, thanks for the context.
Thank you. The next question is from It's from Rob Hall from Scotiabank. Please go ahead.
Good morning and thank you for taking my question. Now that you have Colombia in hand, can you speak to the potential commercial synergies of integrating these assets basis as I know that the 250 that you do reference is largely on the cost and financing side.
Yes Rob, it's Karl. The 250 that we have talked about is mostly costs and financing. I see some significant revenue synergies but they're going to probably take couple of years to materialize, we're going to have to interconnect these systems a little bit. Before we can see large synergies what we're finding right now is that when we do some activities on some parts of our system we can still access I guess and that moves on Columbia and we are going to start working on those synergies right away. For example, we can move some gas from Colombia on to some of our other systems and maybe get the gas from Colombia up into the mainline and maybe even into northeast natural gas transmission system. So there are some shorter term series that we can probably capture but for the most part I think we're -- if we're going to for ongoing long-term synergies, we're going have to start out interconnecting some of these systems together physically.
All right, that's helpful. And then just maybe on your financing plan, the equity and debt markets look significantly different than when Columbia was announced. Have you given any thought to potentially augmenting your financing plan for Columbia with other sources of financing rather than in the asset sales?
It's Don here. No, the asset sales remain the principal source of retiring the bridge loan, we're dedicated to going forward that process and to date we're comfortable with the quality of the parties that are better at the table on that. As we look at the markets today, our philosophy is not to push things for the last minute, here we do have much of our 2016 financing completed but we won't hesitate to start 2017 given the $10 billion capital program next year ahead of us here in the coming months. So no change to the approached asset sales.
Thank you. I'll jump back in the queue.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Just turning back to asset sales here and Don you mentioned you're kind of in the preliminary expression of interest stage but just wondering as relates to Mexico, what exactly are you putting out there as the base package with respect to the operating pipes -- is it that plus what's coming to service shortly and then the new projects? And also have you specified to the potential bidders what percentage interest you are looking for them to bid on or is this just more of make us an offer and you'll kind of sip through that?
So what's being marketed is the six projects in operation in construction or approaching construction timeframe right now, it excludes the new Sur de Texas pipeline. So the package is excluding that one. So six pipes that will effectively all be in service by 2018. We are looking to sell up to 49.9% of that package, we haven't specified minimums on that but that's what's being marketed to the investment community right now. And I won't comment any further in terms of any other considerations we might take with respect to the future.
Fair enough. And just a last question, is there any update on turning on the mainline tolls? Any update on negotiations with respect to looking at a reduced firm transportation toll for longer term and also specifically any kind of thoughts on the potential timeline to either go or no go on this?
Robert, it's Karl. As you know we have been in discussion with some producers in WCSB for a long-term -- little attraction rate I will call it. The discount to loan attraction rate from Empress to Dawn [ph], we are in discussions with many producers right now as you probably see from some of the media and some of the other -- some of the reports on this, it's getting quite a lot of attention here in Alberta and we are in discussions with several parties. We have not signed any agreements with anybody right now but we are quite confident as there is significant interest for us. So we're continuing to pursue with various different kind of parties.
And is there a sense as to a potential timing?
Well, if we were to be successful in getting some contracts on this particular offering, we would need some regulatory approvals. So I would suspect the actual physical movement would not start about November 2017, it would be my guess. In order to have that kind of target physical movement, we probably want to have any contracts signed up by this early this fall so to give us a year to get the regulatory approvals for it.
That's great. Thanks very much.
Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.
Thanks. Just following up on the last question, can you give us a sense of the amount of volumes you like to see contracted up under long-term rates with producers, just a volumes and then some sort of magnitude of production that you'd be willing to give -- I think you came up on a producer call that maybe even 50% would be a number, just some sense on this?
Sure Ted, it's Karl again. We've offered our couple packages, we have offered a long-term loan attraction of 12 to 10 with brigades of Canadian for a billion cubic feet a day. And then we've done a sliding scale down to about $0.85 per gigajoule for $2 billion cubic feet. So we spend so much volume but we do get on the system. It's just get like more than less obviously, but we're willing to be little bit flexible on the volume. We're willing for individual producers to come in and tender any part of that volume from that that they want, we don't have necessarily a minimum that individual producer has to bring although we do have a minimum that we want in aggregate before we would go to the board for that.
And thanks for that Karl. And then how do you think about that relative to just call the earnings power the mainline and maybe Great Lakes as the regulators will look at those versus some of the existing contracts you have with the LDCs on the Eastern Triangle and others across the prairies.
We're serving -- there is really -- I think two questions embedded in that, first of all is, are we in anyway shape or form in pairing our ability to earn our return by doing this and what happens to other shippers that are on the system that aren't necessarily using this. So maybe I'll start with the latter first. On this particular product that we're offering, it has to be -- in our view it has to be a new supply source that wouldn't otherwise -- that we believe would not otherwise flow on the system if we did not allow for this rate.
So, it's pretty critical for us that the shippers can prove to us that this gas would not otherwise flow to our normal markets on it. And that's how we can justify a load attraction rate because that means the gas moving on it will be incremental. And that means that if we can move incremental gas at a discounted rate, everybody on our system will benefit because we will be able to use that contribution margin, so to speak, from the movement to spread across our entire system. So, it is important that we do attract volumes that wouldn't have otherwise moved.
Now, what else we are doing in order to make sure of that is we are only offering a single path, that's Empress to Dawn. We are not offering any services around that path so you cannot divert and you cannot use alternative receipt points, so, that this capacity will not go and cannibalize other markets that we might have on the system. Those are some of the conditions that we have on the movement.
And if we are able to successfully negotiate these types of contracts and get this incremental volume, I believe it will be a win/win for the entire system. We will get extra revenue on the system, extra contribution margin and that should go through when we do our tolling applications for the Board. That should go through to lower overall tolls for everybody on the system.
And then if I could just get one more in on the financing, Don maybe. Can you just remind us the metrics you are actually solving for in terms of leverage metrics, et cetera, relative to what the agencies want you to see? And how much time do you have to get to where they want you to be to keep the A grade rating? Just walk us through that, please.
Sure. There's three key metrics. And they all calculate them slightly differently, but, fundamentally, 15% FFO to debt minimum, although one agency has a higher target there. But we are comfortable as we complete our construction program here and finance it the way we plan to finance it we will achieve that metric exiting 2018. The second metric is 3 times FFO to interest. We feel comfortable tracking there. And then 5 times debt to EBITDA is the other metric.
In terms of timeframe, as I mentioned, as we complete our build program and finance it the way we intend to finance it, we should achieve all these metrics exiting 2018 which is when the bulk of the build program is behind us. We have had conversations with the agencies. They are fully apprised of developments within the Company continuously. And I think we have a long track record of delivering on what we say we are going to deliver. So, we are comfortable that we can maintain these ratings and achieve what they are looking for us to achieve exiting 2018.
The next question is from Ben Pham from BMO. Please go ahead.
I wanted to go back to the Canadian Mainline. There is some commentary in the Q2 about the NEB decision in 2014 through 2020. I recall there was a general agreement in there, too, to revisit the tolls anyways coming to 2018. And I am wondering, with this new offering, the 2 BCF a day, is that going to be separate from the existing shipper renegotiation? It's just the time looks pretty similar on both fronts.
Yes, Ben, it is Karl again. We have an obligation to go back to the Board midway throughout our LDC settlement and rest the tolls. The settlement had limited variables that you could look at to reset the tolls. It was billing determinants and costs and things like that for resetting the tolls. If we were successful to bring load attraction rate volumes on the system and a material amount of load transfer rate volumes on the system, I am sure the NEB would look at that, as well. I can't imagine they wouldn't take a look at it if we were successful in bringing a large volume of load attraction rates.
Now, as I said earlier, we will have to go to the NEB to get approval to do a load attraction rate, so it will probably be about the same. We will be in front of the NEB with that load attraction rate just before we go up for a new rate reset in 2018. So, I think it would be reasonable to guess that the Board will take a look at our load attraction rate volumes, along with all the other billing determinants that they look at in 2018 to determine our tolls from 2018 to 2020.
Okay. Karl, you mentioned if that addition [indiscernible] is a sign on the mainline you don't expected it to impact the other pipelines. But I'm wondering, though, if those lines were to move east, doesn't that impact your Columbia recontracting side of things and maybe some of the potential projects that Columbia is building out there?
No, most of the Columbia volumes -- this is a system that these various volumes are competing with each other. The Columbia line, the lines that we have on our system with the recent acquisition of Columbia, generally are going into the Columbia Tikal pool system or they're going into the Gulf Coast system. If we moved 2 BCF a day to Dawn, what is the impact of those systems? There is some, the Appalachian area natural gas, that is planning on going to Dawn. And will we be backing that out? It's hard to tell right now. There is a greater demand at Dawn than 2 BCF, obviously.
But if we did tend to back gas out, I believe we will back gas out on competing pipelines going into Dawn which Columbia does not have one of them right now. And it may actually be good for the Columbia system. We may actually be -- if we back out other volumes that would have gone to Dawn, then those volumes are looking for a home and they might go on the Columbia systems to the Gulf, for example. Or we might actually be able to facilitate them on the mainline still and just move them to the Northeast, either down through Iroquois or down through PNGTS.
This is a dynamic competitive situation but I do believe there is room for more gas at Dawn. Certainly our mainline is in a good position to actually take more gas at Dawn for the local eastern Canadian market or they could take that gas at Dawn and we could make some provisions for it to move into the U.S. Northeast. It comes from the U.S., goes through our mainline system and goes back into the U.S. Northeast.
The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
The question is for Don and it is just on the act of God of the Alberta wildfires. To what extent did that financially impact your liquids business just with the curtailed volumes over the period of time that the wildfires were raging?
Andrew, it is Paul Miller here. Maybe I can handle that question. We did see lower spot on Keystone and it was partially attributable to the supply disruption and partially attributable to continued low differentials between Alberta and the markets that we serve. We had lower volumes this quarter than last year but we had higher contracted volumes, so lower spot, higher contracted volumes. So, year over year our cash flow, our EBITDA on Keystone was relatively flat.
Where we did see a reduction was on our Marketlink system where we saw lower spot volumes quarter over quarter. So, when you see the reduction in our cash flow quarter over quarter, it is largely attributable to barrels moving from Cushing down to the U.S. Gulf Coast.
Andrew, it is Bill Taylor. I will just augment Paul's answer by adding that we did have a minor impact to one of our power facilities in that area that was impacted and shut down during the fire events. And there was some delay in getting that back up due to our customer at that site having some continuing issues after the fires had moved through the area. But at this time that matter is sorted out and the facility is back online.
Okay, that is very helpful. Maybe this one is really directed to Don on the goodwill that you posted up at the CAD10 billion. How should we think about that on a go forward basis just within the accounting? Is this going to be a 40-year amortization of the goodwill under U.S. GAAP? How should we think about it for adjusted earnings and things that you are driving your dividend payouts and all of those things off of?
The goodwill, the reason it goes to that magnitude is we record the first regulated assets essentially at book to value. Standard practice and something we have also followed in past acquisitions like ANR and the like. Can you hear me Andrew?
Sorry, folks, just bear with us, I am not sure what has happened. Sorry, it appears everything is okay, we apologize for whatever that interruption was.
I will start over there Andrew. I can assure you I didn't hit any buttons. The goodwill, we basically fair value the regulated assets at the regulated book value. And that's again, U.S. GAAP standard and something we have done in the past here. So what falls out of that is CAD10 billion of goodwill.
There isn't any intent to amortize that into income over time given the uncertain longevity of the asset, but our assumption is it will be in service for a very long time so it's difficult to come up with an appropriate amortization period for that. I will turn it over to Glenn here.
Andrew, just to add a little more color, under U.S. GAAP we can't, quote/unquote, amortize, like you would a fixed asset. You cannot amortize goodwill. We will, under U.S. GAAP, revisit the valuation on this each and every year. And to the extent there ever is an impairment, we will recognize it at the time. But, as Don says, it's a long-term assets, with a good growth profile, so we are not concerned about that right now. But we cannot amortize it over a fixed period or something like that.
Okay so just the standard impairment test will apply.
The next question is from Steven Paget from FirstEnergy Capital. Please go ahead.
My first question is for Bill Taylor. Bill, for the Bruce Power life extension, now less than three-and-half years away, what do you need to do before the first reactor shutdown? Is there anything you might be able to use from the Darlington refurbishment such as training facilities? And was Mike Rencheck chosen as the new head of Bruce with the major component MCR program in mind?
Let me start, Steve, with the back half of your question and say that, yes, indeed, we are very pleased with the Board selection of Mike Rencheck as the incoming CEO for Bruce Power. Mike comes to that job with a significant amount of experience in large-scale nuclear project delivery in his former positions at AREVA, as well as having an excellent background in plant operations which will be very useful going forward as the plant has the operating element alongside the large projects element.
So, with that, to the first part of your question about what work is underway now, I would say that there is very close coordination going on between Bruce Power and OPG respecting the work that is happening already at Darlington. You can expect that that would continue as we are embarking on our program of planning and commercial structure for the contracting and what have you that will support the work that will begin on the first unit at Bruce Power in 2020.
Our obligation under our agreement is to provide our final estimate of that work to government in mid-2018. So the team that is already in place at Bruce Power is working diligently towards that goal. And with Mike Rencheck coming in, I would expect his priorities to be very focused on that effort in the near term.
Russ, my next question is for you. You have been CEO for six years. And looking back, what major Company strategies and practices have you changed and what has drove you to make those changes and what has been the result?
We've become very focused and disciplined around how we allocate capital and the types of businesses that we've approached. I would think that, not just the last six years but, say, the last 15 years that I've been involved in the strategy process here, we have refocused the Company on North America, three geographies and in three businesses that we know and understand very well. I think that disciplined focus around what we do well and then financing it in a way that is prudent with a continuous view of the long term, would be probably the most significant components.
Our strategy has proven itself out, that if you stay disciplined to your assets, operate them well, contract them well, they will generate steady cash flow. If you re-invest that cash flow in those core businesses, in the same [indiscernible], you will grow earnings and cash flow and, thus, dividends.
You can see now, as we move from where we were, say, three or four years ago, we were generating dividend growth rate of the 4% to 5% rate, moving up in the last couple of years to 6% to 7% to where we are now, predicting an 8% to 10% dividend growth rate. I think that is attributable to disciplined execution of those types of strategies. So, that's what I would say has been my major focus, not just for the last six years but for a number of years before that as I was involved with the team in driving that strategy forward. It's a big ship. It takes a long time to turn it in the right direction. And I think that we are seeing the fruits of that turning it in that direction now.
[Operator Instructions]. The next question is from Faisal Khan from Citigroup. Please go ahead.
It's Faisal from Citigroup. I just wanted to see if I understood some of your comments around the current cash position you have. The CAD1.7 billion in cash, is that already being allocated towards the purchase price of CPGX or have you basically raised more capital than you really need? I'm just trying to understand how that cash is going to be used over the course of the year.
It's Don here. We color-code where the cash on the balance sheet at June 30. CAD13.1 billion was for the closing of the acquisition of CPGX. The CAD1.7 billion of cash and cash equivalents, that is effectively there to fund operations and the capital program here in the second half of the year. So, there is an element of pre-funding to that. We're not a just-in-time funder. We hit the markets when they're available to our securities. And that is really a function of the CAD8 billion-plus we funded in the first half.
Okay. I just wanted to make sure I understand. So, you could use that cash to also repay the bridge loan. Would that reduce the amount of assets you have to sell into the markets? I'm just trying to understand the asset sale program versus also the cash on the balance sheet.
They are fungible. We can repay the asset bridge out of whatever funds we generate. But right now we are color coding the asset sales to repay the CAD6.9 billion that we have drawn on that. So, yes, cash is fungible but the way we are mentally looking at this is that that CAD1.7 billion is there to fund our capital program which is north of CAD7 billion for the year, including Columbia.
Okay. And then the Sur de Texas pipeline, I think you mentioned, Don, that that actually is not part of the package of the assets you're seeing in Mexico. You're selling a minority interest in your position in Mexico but it sounds like that pipeline is not part of that package. Did I hear that commentary crackly?
That is correct.
At the current time, the way we structured that transaction, is, as it were, 60% partner with IEnova. But we did retain the right, a portion of that, as part of the sale package we are have the ability to sell down. 20% of the 60% can be sold to a third party without being involved in the Sempra partnership. So, it can be included, we retain the flexibility, but at the current time we have not included it.
Okay, because I was just trying to understand. The Mexico business I thought was more of a franchise. So, if you sell a minority interest in the franchise it's a business that grows over time. But if there's assets that are carved off, I am just not sure if that impacts the sale process or the evaluation on the sale of the minority interest or not.
Thank you. This concludes today's question-and-answer session. I would like to turn back over to Mr. Moneta.
Thanks very much. We very much appreciate your interest in TransCanada and the time you've taken this morning to participate. We look forward to speaking with you again soon. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time. And we thank you for your participation.
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