Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 Second Quarter Results Conference Call. I would now like to turn the call 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 20 16 Q2 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 Johansen, Executive Vice President and President of our Natural Gas Pipelines Business Paul Miller, President of our Liquids Business 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 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 questions from the investment community. If you are a member of the media, please contact Mark Cooper or James Miller following this call and they would be happy to address your questions. In order to provide everyone community 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, Stuart and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U. S.
Securities and Exchange Commission. And finally, I'd 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. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.
With that, I'll now turn the call over to Russ.
Thanks, David, and good morning, everyone, and thank you very much for joining us. I'm very pleased to announce another solid quarter where all of our base businesses operated safely, reliably and continued 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 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 and cash flow going forward. As I said, our 3 business segments all performed well during the quarter. TransCanada reported net income of $365,000,000 or 0 point 5 2 a share. Comparable earnings for the quarter were $366,000,000 or $0.52 a share. Comparable EBITDA was 1,400,000,000 funds generated from operations were $831,000,000 after the $109,000,000 dividend equivalent payments on subscription receipts and comparable distributable cash flow was $698,000,000 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 the beginning of this month, as you're well aware, we closed the Columbia Pipeline acquisition for $13,000,000,000 including the assumption of $2,070,000,000 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 costs 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 encircle the globe more than twice. As well, we now own North America's largest natural gas storage business with 6 64,000,000,000 cubic feet a day of capacity. In addition to complementing our existing regulated pipeline storage businesses, 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's $7,300,000,000 of modernization and commercially secured projects are now an important part of our $25,000,000,000 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 we previously announced, Portfolio Management will play an important role in financing the acquisition through the planned sale of our U. S. Northeast merchant power assets and a minority interest in TransCanada's 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 while maintaining the company's financial strength and flexibility to continue to fund our growth projects going forward. The asset sale process is progressing, advisors have been engaged and the initial stages of soliciting interested parties is well underway and we would expect to be able to provide 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 I Nova, a subsidiary of Sempra Energy, was chosen to build, own and operate the $2,100,000,000 Sur de Texas tuxpan natural gas pipeline in Mexico. TransCanada will own 60% interest in that project and expects to invest US1.3 billion dollars to construct a 42 inches diameter 800 kilometer pipeline.
We anticipate that pipeline to be in service in late 2018. The Sur de Texas tuxpan pipeline the most recent addition to TransCanada's expanding portfolio in Mexico. In the last 8 months, TransCanada was awarded the $500,000,000 Tuxpan Tula and the $600,000,000 U. S. Tula Villa del Rey pipeline.
Construction of those two pipelines is already underway and we expect them to be operational in 2017 2018 respectively. We continue to expect our Topolobambo 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 $5,000,000,000 All of those are underpinned by 25 year agreements with Mexico State Power Company. Here in Canada, our NGTL system, we placed about $450,000,000 of facilities into service in the Q2 of the year. Another $400,000,000 of facilities are approved and currently under construction.
A further $2,900,000,000 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, BC border and then further into our gas transmission system on the West Coast will require construction of about $135,000,000 of new facilities not previously included in our 2018 program. We continue to look at other additional demands for service and are reevaluating all of our facility requirements to meet those needs over the coming months. In addition, some changes in the timing, our spend on the NGTL system will likely occur to match revised and service dates with certain producer facilities. But in total, the capital commitment for NUTL remains at approximately $5,400,000,000 including the North Montney pipeline.
We continue to advance our $45,000,000,000 portfolio of 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 Co Gas have determined that they will need more time prior to making the final investment decision. Coastal GasLink enjoys a strong stakeholder and First Nation 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 for arbitration with the International Center For Settlement of Investment Disputes under the North America Free Trade Agreement. This means a panel of 3 arbitrators will soon be tasked with determining whether TransCanada is treated fairly in the protracted 7 year review. On June 16, the National Energy Board announced it is 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 will include 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 report is due no later than March 16, 2018. Federal government has said it will then take up to an additional 6 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 1st full year of operation, providing increased revenue from predictable, regulated and long term contracted assets.
As we have said, this supports and may augment our 8% to 10% expected annual dividend growth rate through 2020. A dedicated team is now focused on realizing the $250,000,000 in annual cost, revenue and financing benefits we forecast would result from the integration of Colombia into TransCanada, and we remain confident that those targets are achievable. We continue to expect savings of approximately $125,000,000 in 2017 and the full $150,000,000 of cost savings by 2018. The remaining $100,000,000 is expected to come primarily from financing benefits. With the US7 $300,000,000 of projects Columbia has underway, our portfolio of no term projects has now increased to CAD25 1,000,000,000 These projects are in all three of our business lines, natural gas, liquids and energy, and they span all three of our geographies, Canada, United States and Mexico.
Essentially, all of these projects are underpinned by regulated business models or long term contracts. Today, more than 90% of our EBITDA is generated by this type of stable business model. And as we divest of our merchant power 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 in a simple and understandable manner that supports our A grade credit rating, ensuring our access to capital to fund our growth. In summary, 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 of 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 $25,000,000,000 of near term projects are expected to support and may augment our dividend growth rate of 8% to 10% through 2020. Through a 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 our shareholders.
That completes my prepared remarks, and I'll turn the call over to Don for some further details on our Q2 results. Don?
Thanks, Russ, and good morning, everyone. As highlighted earlier, we reported net income attributable to common shares in the second quarter $1,000,000 associated with Columbia acquisition costs, dollars 109,000,000 of which related to dividend equivalent payments on the subscription receipts. In addition, we recorded a $10,000,000 after tax restructuring charge related to expected future out of the money lease commitments and $9,000,000 after tax related to Keystone XL maintenance and liquidation costs. Excluding these items, comparable earnings for 2nd quarter 2016 decreased by $31,000,000 to $366,000,000 or $0.52 per share compared to $397,000,000 or 0 point 56 dollars per share for the same period last year. In the quarter, Bruce Power Units 1 through 4 were removed from service for approximately 3 weeks, with a once a decade station containment outage.
Planned maintenance on Units 2, 3 and 8 was also conducted in the 2nd quarter, with some work on Unit 3 continuing into the Q3. As a result, Bruce's availability was reduced to approximately 71% in the period. While some additional plant maintenance is scheduled in Q4 2016, Bruce Power's overall average plant availability for the year is expected to be in the low 80s. Other items contributing to lower comparable earnings in the Q2 were higher interest expense as a result of debt issuances net of maturities and lower capitalized interest. Lower uncontracted 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 a rate regulated projects, increased earnings from ANR due to higher transportation revenues and lower OM and 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 Q2, comparable EBITDA was essentially unchanged from the same period last year. Our Natural Gas Pipelines business generated comparable EBITDA of $880,000,000 in the Q2 compared to $799,000,000 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. And international gas pipelines increased by $46,000,000 for the 3 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 OM and A expenses, higher transportation revenues on Great Lakes and a higher contribution from TC Pipelines LP, 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 earnings from our U. S. And international pipelines. Canadian Gas Pipelines' comparable EBITDA of 5 $81,000,000 was slightly higher than the Q2 of 2015.
For the quarter, net income from the Canadian Mainline decreased by $15,000,000 primarily due to lower incentive earnings and a lower average investment base. Higher incentive earnings were recorded in the Q2 of 2015 as the NEB approval of compliance tolls related to the LDC settlement was received in June 2015, resulting in the full year to date impact being recognized in that period. This resulted in approximately $11,000,000 of incentive earnings related to the Q1 of 2015 being booked in the Q2 of 20 15. In GTL system, net income increased $13,000,000 year over year to $79,000,000 mainly due to a higher average investment base. In liquids, the Keystone Pipeline system generated $279,000,000 of comparable EBITDA in the 2nd quarter, which was a $38,000,000 decline from the same period in 2015.
The decrease was the net effect of lower uncontracted volumes on the Keystone pipeline system and lower volumes on Market Link, partially offset by the positive impact of the stronger U. S. Dollar. Turning to energy, comparable EBITDA of 230 $6,000,000 in the 2nd quarter declined $31,000,000 from the same quarter last year due to the net effect of a lower contribution from Bruce Power, mainly due to higher planned outage days as described earlier, a reduction in earnings from Western Power as a result of lower realized power prices and increased PPA volumes following the termination of the Alberta PPAs and a decline in Eastern Power earnings due to lower contractual earnings at Beckancur. These were partially offset by higher earnings in U.
S. Power, mainly due to the addition of the Ironwood Power Plant in Pennsylvania and insurance recoveries related to Ravenswood. Natural gas storage EBITDA was also higher due to improved realized natural gas storage price spreads compared to last year. Now turning to the other income statement items on Slide 18. Comparable interest expense of $405,000,000 in the 2nd quarter increased by 74,000,000 dollars compared to the same period last year.
This was primarily due to higher interest costs as a result of long term debt issuances in 2015 2016, partially offset by Canadian and U. S. Dollar denominated debt maturities a stronger U. S. Dollar and its effect on translated interest on U.
S. Dollar denominated debt and lower capitalized interest on Keystone XL Innovative Projects following the November 6, 2015 denial of a U. S. Presidential permit, partially offset by higher capitalized interest on liquids projects, LNG projects and the Napanee power generating facility. Comparable interest income and other increased by $64,000,000 for the 3 months ended June 30, 2016, compared to the same period in 2015 as a result of realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.
S. Dollar denominated income as well as increased AFUDC related to our rate regulated projects, including Mexico pipelines, NGTL system expansions and the ANR Southeast Mainline. Comparable income tax expense for the Q2 was relatively unchanged from the same period in 2015. Net income attributable to non controlling interest increased by $12,000,000 for the 3 months ended June 30, 2016, compared to the same period in 2015, primarily due to the sale of a 49.9 percent direct interest in PNGTS to TC PipeLines LP on January 1, 2016, as well as the impact of a stronger U. S.
Dollar on the Canadian dollar equivalent earnings from TC PipeLines LP. Preferred share dividends were $28,000,000 for the 3 months ended June 30, 2016 compared to $25,000,000 for the same period last year. Now moving on to cash flow and investing activities on Slide 19. Funds generated from operations in the second quarter declined by $230,000,000 compared to the same quarter in 2015. As mentioned earlier, dollars 113,000,000 of this was related to Columbia acquisition, including the $109,000,000 of dividend equivalent payments on the subscription receipts that were issued in April and that we have not normalized for in FGFO.
Other items impacting FGFO include lower distributions from 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 2nd quarter, $0.99 per common share compared to 861,000,000 dollars or $1.21 per common share in the Q2 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 $269,000,000 in the quarter compared to $194,000,000 for the same period in 2015. The $75,000,000 increase was primarily attributable to repairs related to the Q1 outage at Halton Hills and continued elevated maintenance on the ANR Southeast mainline.
Maintenance capital expenditures on our Canadian regulated natural gas pipelines were $42,000,000 $61,000,000 in Q2 16 and 2015 respectively, which contributed to their respective rate basis and net income. For full year 2016, we expect we continue to expect distributable cash flow coverage of around 2x. Regarding investing activities, capital spending was approximately $1,100,000,000 the second quarter, driven principally by expansions of the NGTL, Canadian Mainline and 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 remain strong.
On April 1, 2016, we issued 96,600,000 subscription receipts at a price of $45.75 each for total proceeds of approximately $4,400,000,000 This was used to partially fund the Columbia acquisition. The gross proceeds from the sale of the subscription receipts less amounts used 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 US6 $900,000,000 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 $13,100,000,000 of gross proceeds from the subscription receipts and bridge loan facilities were recorded as restricted cash on the balance sheet pending next day close of 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 $1,700,000 of non restricted cash on hand after a very active period of time. In June, we issued $300,000,000 of 7 year medium term notes and $700,000,000 of 30 year notes in Canada at interest rates of 3.69% and 4.35%, respectively. In addition, ANR completed a private placement of US $240,000,000 of 10 year senior unsecured notes at a rate of 4.14% in the United States. In April, we completed a public offering of 20,000,000 Series 13 cumulative redeemable first preferred shares at $25 per share, resulting in gross proceeds of $500,000,000 The fixed rate dividend was initially set at 5.5% per annum and will be reset every 5 years going forward.
In Q2 2016, Bruce Power issued recapitalization bonds and borrowed 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 from Bruce Power of $725,000,000 On June 30, we also announced the reinstatement of the issuance of common shares from treasury at a 2% discount under TransCanada's dividend reinvestment plan, commencing with the dividends declared on July 27, 2016. In addition to drawing $6,900,000,000 under bridge facilities to fund a portion of the Columbia acquisition, year to date, we have raised approximately $8,300,000,000 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 $25,000,000,000 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 our master limited partnership holdings. We expect to be in a position to communicate the determination regarding the future of TC Pipelines LP and Columbia Pipeline Partners LP later in 2016. Now turning to Slide 23. In closing, during the Q2 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 positioned to finance our $25,000,000,000 portfolio of near term growth projects through strong internally generated 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. 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
the call over to the conference
Thank you. We'll now take questions from the telephone line. The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. Appreciate the detail around the expected synergy levels the Columbia Pipe acquisition in 2017 2018. I'm just wondering maybe more in the near term, do you expect any synergies in 2016 and would those be back end 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, Whit. It's Don here. I'll start with the synergies. We are working through them 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 us get up to the $125,000,000 level of costs achieved in that year and then $150,000,000 in 2018 full run rate in that timeframe. With respect to the funding program, I'll just walk you through our capital requirements and how we view things here over the next couple of years. Looking at 2016 2017 including Colombia, we're probably looking at capital including maintenance in the $7,000,000,000 ish area for this year and north of $10,000,000,000 next year. That will be funded as we go.
So we're not looking at any large element of prefunding here. It's very much an ongoing spend here. So, it's not huge spikes in the firm, 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 the market, through market access and across the capital spectrum here. As noted in my remarks, we've done about $8,300,000,000 of funding year to date aside from the bridge loan facilities.
As we look forward, just 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. And we would expect the DRIP to recapture 30% to 35% of the cash dividends based on a 2% discount. That's our historical experience on that. So that's pretty much the standard you should see us employ here over the next while.
We'll watch the cadence and the shaping of the spend here. We remain comfortable with the $25,000,000,000 of growth will be expanded in this primarily in the 2016, 2017, 2018 timeframe. But we do see some stuff shift around like we'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 a 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 your growth projects need to be in service?
Or how might you think of timing of that augmentation?
Lynn, it's Don again here. I would say line of sight and this is 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 $7,300,000,000 in comfort level around that amount, which we do have pursuant to our due diligence. But as we get the organization integrated, we'll relook at our payouts and the like. I wouldn't look for us to make any major change in terms of payout ratios and the like.
Any change in the dividend trajectory would be underpinned by real cash flow and not using leverage and the like. So it's early days here. We've only had these organizations together for about 3 or 4 weeks right now. But as our comfort level grows on the ability to deliver, we'll have a look at the capital allocation again.
The next question is from Rob Hope from Scotiabank. Please go ahead.
Good morning and thank you for taking my question. Now that you have Columbia in hand, can you speak to the potential commercial synergies of integrating these asset bases as I know that the $250,000,000 that you do reference is largely on the cost and financing side?
Yes, Roel. It's Karl. Yes, the $250,000,000 that we have talked about has been mostly cost 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 before we 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, that moves on Colombia. And we are going to start working on those synergies right away. For example, we can move some gas from Colombia onto some of our other systems and maybe get the gas from Colombia up into the mainline and maybe even to the into Northeast to support the natural gas transmission system. So there are some shorter term synergies that we can probably capture. But for the most part, I think we're if we're going for ongoing long term synergies, we're going to have to start 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 Colombia was announced. Have you given any thought to potentially augmenting your financing plan for Colombia with other sources of financing rather than in the asset sales?
Yes, it's Don here. No, the asset sales remain the principal source of retiring the bridge loan. We're dedicated to going forward with that process. And to date, we're comfortable with the quality of the parties that are at the table on that. As we look at the markets today, our philosophy is not to push things to the last minute here.
We do have much of our 2016 financing completed, but we won't hesitate to start 2017 given the $10,000,000,000 capital program next year ahead of us here in the coming months. So, no change to the approach to asset sales.
Thank you. I'll jump back in the queue.
Thanks, Rob.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Good morning. Just on 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 it relates to Mexico, what exactly you're putting out there as the base package with respect to, is it the operating pipes? Is it that plus what's coming into 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 just kind of sift through that?
Yes. We've so what's being marketed is the 6 projects in operation, in construction or in approaching kind of construction timeframe right now excludes the new Sur de Texas pipeline. So it's the package excluding that one. So, 6 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 bells or whistles or considerations we might take with respect to the future.
Fair enough. Okay. And just the 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, but for longer term and also specifically any kind of thoughts on the potential timeline to either go or no go on this?
Yes, Robert, it's Carl. Yes, as you know, we have been in discussion with some producers in WCSB for a long term load attraction rate, I will call it, the discounted load attraction rate from Empress to Dawn. We are in discussions with many actually producers right now. As you'd probably see from some of the media and 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 that there's significant interest in the market for it.
So we're continuing to pursue it with various different counterparties.
And is there a sense as to 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 to about November 2017 would be my guess. In order to have that kind of target physical movement, we'd 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. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.
Thanks. Just following up on the last question, please. Can you give us a sense of the amount of volumes you'd like to see contracted up under long term rates with producers, just volume sense? And then some sort of magnitude of reduction 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 those items?
Sure, Ted. It's Karl again. We have offered out a couple of packages. We have offered a long term load attraction rate of CAD1.10 per gigajoule for 1,000,000,000 cubic feet a day. And then we've done a sliding scale down to about $0.85 per gigajoule for 2,000,000,000 cubic feet per day.
So it depends how much volume that we do get on the system. At TransCanada, we'd like more than less, obviously, but we're willing to be a little bit flexible in volume. We're willing for individual producers to come in and tender any part of that volume that they want. We don't have necessarily a minimum that an 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 it the earnings power of the mainline and maybe even Great Lakes as the regulators will look at those tariffs versus some of the existing contracts you have with the LDCs on the Eastern Triangle and others across the prairies?
Well, certainly, there's really kind of I think 2 questions embedded in that. First of all is, are we in any way shape or form impairing 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 is 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 offer 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'll 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 else we're doing in order to make sure of that is we're only offering a single path that's Empress to Don. We're not offering any services around that path.
So you cannot divert and you cannot use our furnace receipt points. So that this capacity will not go and cannibalize other markets that we might have on the system. So that's how those are some of the conditions that we have on the movement. And if we're able to successfully negotiate these types of contracts and get this incremental volume, I believe it will be a win win for the entire We will get extra revenue on 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.
Understood. Super helpful. And then if I could just get one more in on the financing. Don, maybe can you just remind us the metrics you're actually solving for in terms of leverage metrics, etcetera, relative to what the agencies want you to Just kind of walk us through that, please. Sure.
There's 3 key metrics.
Just kind of walk us through that, please.
Sure. There's 3 key metrics and they all calculate them slightly differently. But fundamentally, 15% FFO to that minimum, although one agency has a higher target there. But we're comfortable as we that we will achieve that metric in exiting 2018. The second metric is 3x FFO to interest.
We feel comfortable tracking there. And then 5x debt to EBITDA is the metric. In terms of timeframe, as I mentioned, as we complete our build program and finance 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've had conversations with the agencies. They're fully apprised of developments within the company continuously.
And I think we have a long track record of delivering on what we say we're going to deliver. So we're comfortable that we can maintain these ratings and achieve what they're looking for us to achieve exiting 2018.
Perfect. That's it for me. Thank you.
Thanks, Ted.
Thank you. The next question is from Ben Pham from BMO. Please go ahead.
Okay. Thanks. Good morning. I wanted to go back to the Canadian mainline. There's some commentary in the Q2 about the NEB decision in 2014 through 2020.
I recall there's a general sort of agreement in there to revisit the tolls anyways coming to 2018. And then I'm wondering with this new offering to 2 Bcf a day, is that going to be separate from the existing shipper renegotiation or it's just a time that looks pretty similar on both fronts?
Yes, Ben, this is Karl again. Yes, we have an obligation to go back to the board kind of midway through our LDC settlement and reset the tolls. There's quite a the settlement had a 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 low traction rate volumes on the system and material amount of low traction rate volumes on the system.
I'm sure the NEB would look at that as well. I can't imagine the NEB wouldn't take a look at it if we were successful in bringing a large volume of low traction rates. Now as I said earlier, we will have to go to the NEB to get approval to do a low traction rate. So it will probably be about the same. We'll be in front of the NEB with that low traction rate just before we go for a new rate reset in 2018.
So I think it'd be reasonable to guess that the Board will take a look at our little traction rate volumes along with all the other billing determinants that they will look at in 2018 to determine our tolls from 2018 to 2020.
Okay. I think, Carl, you mentioned about if that addition to B. C. F. A.
Is a sign on the mainline that you don't expect it to impact the other pipelines. But I'm wondering though, I mean, 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?
Most of the Columbia volumes, there is the CSA system that these various volumes are competing with each other. The Columbia volumes, the lines that we have on our system with the recent acquisition of Columbia generally are going into the Columbia Pico Pool system or they're going into the Gulf Coast system. If we move 2 Bcf a day to Dawn, what is the impact of those systems? Well, there is some Appalachian area natural gas that is planning on going to Don. And will we be backing that out?
It's hard to tell right now. There's a greater demand at Don than 2 BCF, obviously. But if we do back if we do tend to back gas out, I believe we'll 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 some if we back out other volumes that would have gone to Don and those volumes are looking for home and they might go on the Columbia system to golf, for example, or we might actually be able to facilitate them on the mainline still and just move them to Northeast either down through Airflow or down through PNGTS.
So this is a dynamic competitive situation, but I do believe there's room for more gas at Dawn. There's certainly our main lines 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 can make some provisions for it to move into the US Northeast. So it kind of comes from the U. S, goes through our mainline system and goes back into the U. S.
Northeast.
Okay, great. Thanks, Karl. Thanks, everybody.
Okay. Thanks, Ben.
Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Thank you. Good morning. I guess the question is for Don and it's 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?
Keystone, and it was largely attributable to partially attributable to the supply disruption and partially attributable to continued low differentials between Alberta and the markets that we serve. So we moved 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 or EBITDA on Keystone is relatively flat. Sorry, I was just going to say, where we did see a reduction was on our Market Link system, where we saw lower spot volumes quarter over quarter. And so when you see the reduction in our cash flow quarter over quarter, it's largely attributable to bales moving from Cushing down to the U.
S. Gulf Coast.
And Andrew, it's Bill Taylor. I'll 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 only.
Okay. That's very helpful. Maybe just on the and this one is really directly to Don on the goodwill that you've posted up to the $10,000,000,000 How should we think about that on a go forward basis just within the accounting on 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're driving your dividend payouts and all of those things off of?
Yes. The goodwill, the reason we spoke about magnitude is we record the deferred regulated assets essentially at the the book value. Standard practice is something we've also followed in past acquisitions like ANR and the like. So
Sorry, can you hear me, Andrew? I just hear a very busy tone. Okay. Sorry, folks, just bear with us. I'm not sure what's happened.
Sorry, can you hear me now, Andrew?
I can.
Maybe just bear with us for a second. I just want to make sure that everyone else can. Operator? Okay. Sorry, it appears everything is okay.
We apologize for whatever that interruption was. So sorry.
So I'll just start over there, Andrew. And I can assure you I didn't hit any Yes. So the goodwill is we've actually fair value the regulated assets at the regulated value and that's again U. S. GAAP standard and then something we've done in the past here.
So what falls out of that is CAD10 1,000,000,000 of goodwill. There isn't any intent to amortize that into income over time, given the uncertain, but uncertain length of the longevity of the asset, but we our assumption is it will be in service for a very, very long time. So it's difficult to come up with an appropriate amortization period for that. So I'll turn it over to Glenn here for
Yes. 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, you will.
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'll recognize it at the time. But as Don says, it's a long term asset with a good growth profile.
So we're 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? Yes. Okay. That's perfect.
Thank you.
Okay. Thanks. Thanks, Andrew.
Thank you. The next question is from Stephen Paget from FirstEnergy Capital. Please go ahead.
Thank you and good morning. My first question is for Bill Taylor. Bill, for the Bruce Power life extension, now less than 3.5 years away, what do you need to do before the 1st 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're very pleased with the Board selection of Mike Rinchek 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 Areeva 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, now to the first part of your question about what work is underway now, it I would say that there very close coordination going on between Bruce Power and OPG, respecting the work that's 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-twenty 18.
So the team that is already in place at Bruce Power is working diligently towards that goal. And with Mike Rinchek coming in, I would expect his priorities to be very focused on that in the near term.
Thank you, Bill. Russ, my next question is for you. You've been CEO for 6 years and looking back, what major company strategies and practices have you changed and what's drove you to make those changes and what's been the result?
We've become very focused and disciplined around how we allocate capital and the types of businesses that we've approached. As you see, I guess I would think that not just the last 6 years, but say the last 15 years that I've been involved in this VADGI process here, we've refocused the company on North America, 3 geographies and in the 3 businesses that we know and understand very well. And I think that disciplined focus around what we do well and then financing in a way that is prudent with a continuous view of the long term, we would be probably the most significant components. It's our strategy has proven itself out that if you stay disciplined to your assets operate them well and contract them well, they'll generate steady cash flow. If you reinvest that cash flow in those core businesses in the same way, you will grow earnings and cash flow and thus dividends.
And I could see you can see now, as we move from where we were, say, 3 or 4 years ago, where we were generating dividend growth rate of the 4% to 5% kind of rate moving up in the last couple of years to 6%, 7% percent to where we are now, sort of predicting an 8% to 10% dividend growth rate. I think that's attributable to disciplined execution of those types of strategies. So that's what I would say is a number of years before that a number of years before that as a result with the team in driving that strategy forward. It's a big ship. Takes a long time to sort of turn it in the right direction.
And I think that we're seeing the fruits of that turning it in that direction now.
Well, thank you, Russ, and goodbye, everyone.
Thanks, Stephen.
Thank you. The next question is from Faisal Khan from Citigroup. Please go ahead.
Thanks. Good morning. Faisal from Citigroup. I just wanted to see if I understood some of your comments around the current cash position you have the company, the $1,700,000,000 in cash. Is that already being allocated towards the purchase price of CPGX?
Or have you basically raised more capital than you really need? And so I'm just trying to understand how that cash is going to be used over the course of the year.
Yes. It's Don here. We color coded what the cash on the balance sheet at June 30, dollars 13,100,000,000 dollars was for the closing of the acquisition of CPGX. The $1,700,000,000 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's no amount of pre funding to that.
We're not adjusting time funder. We hit the markets when they're capable to our securities and that's really a function of the $8 plus 1,000,000,000 we funded in the first half.
Okay. So I just want to make sure
I understand. So mean, could
you could use that cash to also, I guess, repay the bridge loan, so that would that reduce the amount of assets you have to sell into the market? I'm just trying to understand asset sale program versus also the cash on the balance sheet.
Yes, they're fungible, but we can repay the asset bridge out of whatever funds we generate. But right now, we're color coding the asset sales to repay $6,900,000,000 that we've drawn on that. So yes, cash is fungible, but the way we're mentally looking at this is that that 1.7 $1,000,000,000 is there to fund our capital program, which is north of $7,000,000,000 for the year.
Okay. And then the third of Texas pipeline, I think you mentioned Don that that actually is not part of the package that of assets you're just laying in Mexico. So you're seeing 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 correctly?
That's correct.
And I think, Basil, I mean, that's
at the current time, the way we structured that transaction is as it were 60% partner with Eyenova. But we did retain the right to include it as part of a portion of that as part of the sale package. We have the ability to sell down and 20% of our 20 of the 60 can be sold to a third party without being involved in the Sempra partnership. So it can be included. We've retained the flexibility, but at the current time, we haven't included it.
Okay. Because I was just trying to understand the Mexico business, I thought was more of a franchise that, because we saw minority interest in the franchise, it's this business that grows over time. But if there's assets that are carved off, I'm just not sure if that impacts the sale process or the valuation on the sale of the minority interest or not?
No. No.
Okay, thanks. Thanks Faiza.
Thank you. This concludes today's question and answer session. I would like to turn the call 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 thank you for your participation.