Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 Third 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.
Great. Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2017 Q3 conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Karl Johansen, President of Canada and Mexico Natural Gas Pipelines and Energy Stan Chapman, President, U. S.
Natural Gas Pipelines Paul Miller, President, Liquids Pipelines and Glenn Manous, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investors section under the heading Events. Following their prepared remarks, we'll take questions from the investment community.
If you are a member of the media, please contact Mark Cooper or Grady Siemens following this call, and they'd 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 2 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 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 statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by Trans Canada with Canadian Securities Regulators and with the U. S. Securities and Exchange Commission. And finally, I'd also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA, comparable funds generated from operations and comparable distributable cash flow.
These and certain other comparable measures are 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 our 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 very much for joining us today.
As highlighted in our quarterly report to shareholders released earlier today, our portfolio of high quality, low risk energy infrastructure assets continues to perform very, very well. Evidence of this can be seen in our solid Q3 financial results, which continue to support our Board of Directors decision earlier this year to increase our quarterly dividend to $0.625 per share. That equates to $2.50
per share on an annual basis and represents a 10.6% increase over the dividend we paid in 2016. During the quarter, we also continued to advance our $24,000,000,000 near term capital program. This portfolio of commercially secured and rate regulated projects remains largely on time and on budget. To help fund our capital program in the Q3, we raised $1,000,000,000 through the offering of 10 30 year medium term notes on very compelling terms. In addition, in October, we recovered our development costs associated with the Prince Rupert Gas Transmission project and we agreed to sell our Ontario solar assets.
The combined proceeds from those two transactions at approximately $1,100,000,000 will be used to fund a portion of our capital program and for general corporate purposes, thereby reducing the need for external capital, including common equity. Finally, we continue to advance certain other strategic initiatives such as our long term fixed price arrangement that will enhance the predictability and stability of our earnings and cash flow while providing our natural gas pipeline customers with cost effective service to premium markets across North America. I'll touch on each of those developments in the next few slides, beginning with a brief review of our financial results. Excluding certain specific items, comparable earnings for the Q3 of 2017 were $614,000,000 or $0.70 per share, compared to the $622,000,000 or $0.78 per share for the same period last year. Comparable EBITDA was $1,700,000,000 while comparable funds generated from operations was $1,300,000,000 As highlighted in our quarterly report, while our Q3 2017 results are lower than the amounts reported for the same period in 2016, the declines were largely attributable to the impact of issuing 60,000,000 common shares in the Q4 of 2016 and the sale of our U.
S. Northeast power generation assets in the Q2 of 2017. Effectively, in the Q3 of 2016, enjoyed the benefit of having both the Columbia and U. S. Northeast power assets in our portfolio, funded by a low cost bridge facility pending the subsequent permanent financing of the Columbia acquisition in the form of the November 2016 equity issue and the Q2 power generation asset sales.
Overall, the Columbia acquisition has contributed to very strong results over the 1st 9 months of the year and its expansion projects, which largely come into service over the next 12 months, will contribute to growth in cash flow and earnings for many years to come. As highlighted on this slide, on a year to date basis, comparable earnings were $2.27 per share, a 12% increase when compared to the $2.02 per share reported for the same period last year. Year to date comparable EBITDA was also up 15% to approximately $5,500,000,000 while comparable funds generated from operations were $4,200,000,000 an increase of 12% over the same period last year. Don will provide more detail on our financial results in a few moments. But before he does, I'd like to offer a few comments on some recent developments in each of our businesses, beginning with our natural gas pipelines.
First, on the NGTL system, we up from 11,200,000,000 cubic feet a day last year. At the same time, we continue to advance MDTL's $7,100,000,000 capital program with approximately $2,300,000,000 of those facilities expected to enter service by the end of 2017. In addition, we continue to seek regulatory approvals for facilities expected to enter service in 2018 and beyond. They include the North Montney project, which will connect approximately 1,500,000,000 cubic feet a day of new supply under 20 year transportation contracts with producers. Recently, the NEB issued a hearing order indicating that the oral portion of that hearing will begin in mid January with a decision to follow later in 2018.
Turning to the Canadian Mainline, where we received NEB approval for our RFR Dawn long term fixed price service in September. The service, which went into effect November 1, allows us to transport 1.5 PJs or approximately 1.4 Bcf a day from Empress in Alberta to the Dawn hub in Southern Ontario under 10 year contracts at a simplified toll of $0.77 per gigajoule. This service provides our customers with toll certainty and improved market access, enabling them to compete effectively with emerging supplies of natural gas from the Marcellus and Utica basins. We also plan to invest approximately $500,000,000 through 2019 in the portion of the Canadian Mainline referred to as Eastern markets, including New England via our Portland natural gas transmission system. Turning to our U.
S. Natural gas pipelines in Colombia. As I mentioned earlier, we continue to advance our $7,900,000,000 capital program by placing the $400,000,000 U. S. Rain Express project and the $300,000,000 U.
S. Gibraltar project into service in early November. We also expect the $1,600,000,000 Leach XPress project to enter service in early January of 2018. Looking forward with the FERC having regained a quorum, we expect to receive FERC certificates for the WB Express, Mountaineer Express and Gulf Express projects in the Q4 of this year. All three projects are expected to be placed in service in 2018.
The capital cost for the Mountaineer XPress project has increased to approximately $2,600,000,000 due to increased construction estimates. However, as a result of the cost sharing mechanisms we have in place, overall project returns are not anticipated to be materially different than those previously expected. Finally, in the U. S, we also advanced 2 new initiatives, the Buckeye XPress project and the Portland XPress project that will see us further expand our existing Colombia and Portland natural gas transmission systems to meet growing natural gas demand. Finally, in our natural gas pipelines business in Mexico, we continue to advance the Tula Villare project and the Sur de Texas projects that will see us invest approximately $2,500,000,000 in those three projects with approximately $1,600,000,000 having spent to date.
Again, all three of those projects are underpinned by long term contracts with CFE and are expected to be placed in service in 2018. Turning to our liquids business, where the Keystone pipeline continues to produce solid results in the quarter, largely due to contributions from the 545,000 barrels a day of long term take or pay contracts as well as higher contributions from shorter term volumes. We also placed the $900,000,000 Grand Rapids pipeline into service in late August and the $1,000,000,000 Northern Korea project achieved commercial in service in November. Turning to Keystone XL, where we continue to advance the project during the quarter following the presidential permit in March of this year. Earlier this year, we also filed an application with the Nebraska Public Service Commission seeking approval for the pipeline route through the state of Nebraska.
A public hearing on our application was held in August and the final written submissions were made in September of this year. The Nebraska PSC is reviewing all of the comments and a final decision is expected by the end of November. On the commercial front, given the passage of time since the Keystone XL presidential permit application was previously denied in November of 2015, we are updating our shipping contracts and anticipate core shipper group will be augmented with the introduction of new shippers. As part of the required process of updating our commercial agreements, in July, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on both the Keystone Pipeline System and the Keystone XL project from Hardisty, Alberta to markets in Cushing, Oklahoma and the U. S.
Gulf Coast. That open season closed on October 26, 2017 and we received a broad interest and we are currently in the process of analyzing those results. Overall, we anticipate the support for the project to be substantially similar to that which existed when we first applied for the Keystone pipeline permit. To be clear, production of Canadian heavy oil continues to grow and the need for new pipeline transportation capacity remains high. TransCanada and its shippers continue to believe that the U.
S. Gulf Coast is the largest and most attractive market for growing volumes of Canadian heavy oil. And we also believe that the Keystone XL Pipeline is the safest, most efficient and most environmentally sound way to move that crude oil from Western Canada to the U. S. Gulf Coast.
Finally, in our liquids business, in October, we informed the National Energy Board that we will not be proceeding with the Energy East and Eastern Mainline projects after a careful review of changed circumstances. While this is very disappointing, we continue to progress a number of other medium and longer term organic opportunities in our 3 core businesses, including the Keystone XL project, the Coastal GasLink project and the Bruce Power Life Extension program. Turning now to energy, where approximately 95% of our 6,200 megawatt portfolio of generating capacity is underpinned by long term contracts with solid counterparties. On the project front, we continue to advance construction of our $1,000,000,000 Napanee gas fired generation facility in Ontario. That plant is expected to be completed in 2018 and is underpinned by a 20 year contract with the Ontario Independent Electricity System on continues to progress with work on the continued to progress with work on the asset management program advancing as planned in preparation for the 1st major component replacement, which is scheduled to commence in 2020.
And finally, in energy, in October, we agreed to sell our Ontario solar asset for approximately $540,000,000 This sale allowed us to surface good value for our shareholders for mature assets that represented less than 2% of our generating capacity. As I mentioned, proceeds will be used to fund a portion of our capital program and for general corporate purposes, thereby reducing our need for external capital, including common equity. Our remaining energy assets, which includes approximately 6,200 megawatts of clean burning natural gas fired generation as well as wind, nuclear, continue to be a core component of our overall asset base and are expected to generate approximately $1,000,000,000 of EBITDA in 2020 as we complete the Napanee and advance the Bruce Power refurbishment program. In summary, during the Q3, our high quality portfolio of energy assets continue to produce solid results. We continue to advance our $24,000,000,000 program largely on time and on budget.
In total, we invested approximately $2,500,000,000 during the Q3. This includes amounts related to the expansion of NGTL and Colombia as well as our Mexican natural gas pipeline projects, regional liquids projects in Alberta and the Napanee and Bruce Power projects, bringing the cumulative investment in this $24,000,000,000 program to approximately $10,400,000,000 The remaining $13,500,000,000 required to complete these projects will be largely spent through the end of 2019 and we remain well positioned to fund this capital program. Each of the projects is underpinned by long term contracts or cost of service regulation giving us visibility to growth in earnings and cash flow as they enter service between now and the end of the decade. As a result, we expect to continue to build on our track record of 17 consecutive years of dividend increases by growing the dividend at the upper end of the 8% to 10% range through 2020. Our dividend growth outlook is supported by growth in earnings and cash flow emanating from the commissioning of new facilities, which will allow us to maintain our strong consistent dividend payout coverage ratios.
That concludes my prepared remarks. And now I'll turn the call over to Don for some additional comments on our Q3 results. Don, over to you.
Thanks Russ and good morning everyone. As outlined in our quarterly report to shareholders issued earlier today, we reported net income attributable to common shares in the 3rd quarter of $612,000,000 or $0.70 per share compared to a net loss of $135,000,000 or $0.17 per share for the same period in 2016. Per share amounts reflect the dilutive effect of having issued 60,000,000 common shares in November 2016 plus additional shares through the dividend reinvestment program this year. 3rd quarter results included an additional $12,000,000 after tax net loss on sales of U. S.
Northeast power generation assets related to closing adjustments, an after tax charge of $30,000,000 for integration related costs associated with the acquisition of Columbia and an $8,000,000 after tax charge related to the maintenance of Keystone XL assets. We are now largely complete on integration related charges with respect to the Columbia acquisition. Q3 2016 included a $656,000,000 after tax Ravenswood goodwill impairment charge, an after tax charge of $67,000,000 related to costs associated with the acquisition of Columbia, recognition of $28,000,000 of income tax recoveries resulting from a 3rd party sale of Keystone XL project assets, a $9,000,000 after tax charge related to Keystone XL maintenance and liquidation costs and $3,000,000 of after tax costs related to the sale of our U. S. Northeast power business.
All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings for Q3 2017 declined by $8,000,000 or $0.08 per share to $614,000,000 or $0.70 per share, largely due to the monetization of our U. S. Northeast power generation assets in Q2 2017, as well as the dilutive impact of share issuances last November and through our dividend reinvestment program. As Russ indicated, the asset sales and the issuance of common shares were undertaken to help permanently fund the Columbia acquisition and retain our full ownership in the Mexico Natural Gas Pipeline business, which has contributed to a 12% increase in comparable earnings per share on a year to date basis.
Turning to our business segment results on Slide 17. In the Q3, comparable EBITDA from our 5 business segments was approximately $1,700,000,000 $219,000,000
lower than
in the same period in 2016. The decrease was largely driven by the following factors. Canadian Natural Gas Pipelines comparable EBITDA was largely unchanged from the same period in 2016 as an increase in NGTL resulting from projects entering service was offset by a decrease in the Canadian Mainline, primarily due to depreciation on that system. Net income and comparable EBITDA for our rate regulated Canadian natural gas pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also affect comparable EBITDA, but they do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow through basis.
As outlined in the quarterly report, net income for the NGTL system increased $11,000,000 in the Q3 compared to the same period last year, mainly due to a higher investment base and alumina incentive earnings, partially offset by higher carrying charges on regulatory deferrals in 2017, while net income for the Canadian Mainline decreased $3,000,000 due to a lower average investment base and lower incentive earnings. The U. S. Natural Gas Pipelines comparable EBITDA of $482,000,000 in the quarter decreased by CAD 40,000,000 or CAD 9,000,000 in U. S.
Dollar terms versus the same period in 2016, mainly due to the timing of funding contributions to the Columbia Gas defined benefit pension plan, partially offset by increased revenue from Columbia Gas growth projects and higher ANR transportation revenues, resulting from increased rates that went into effect on August 1, 2016 as part of its rate settlement. As well, a weaker U. S. Dollar had a negative impact on the Canadian dollar equivalent segmented earnings from our U. S.
Operations. Mexico Natural Gas Pipelines' comparable EBITDA of 100 $18,000,000 increased $7,000,000 compared to Q3 2016. In U. S. Dollar terms, EBITDA rose by $11,000,000 primarily due to the incremental earnings from Mazatlan, which entered service commercial service in December 2016 and equity earnings from our investment in the Sur de Texas pipeline, which records AFUDC during construction, partially offset by interest expense on an inter affiliate loan from TransCanada to fund Sur de Texas construction.
In accordance with GAAP, this interest expense in the business segment is offset by equal recognition of the income in interest income and other. Also note that Mexico Natural Gas Pipelines comparable EBITDA was impacted by a Canadian $12,000,000 impairment charge on our 46.5 percent equity investment in Transgas to Occidente in Colombia, which represents our last remaining non North American based asset. Transgas was constructed and operated under a 20 year build own transfer contract that was fulfilled in August 2017, at which time Transgas transferred its pipeline assets to transport to Dora to Gas International SA. The impairment charge represents the write down of the remaining carrying value of the equity investment. Liquids Pipeline's comparable EBITDA rose by $25,000,000 to $303,000,000 primarily as a result of higher volumes on the Keystone pipeline, a higher contribution from liquids marketing activities as well as initial income from the Grand Rapids pipeline, which was placed in service in late August 2017.
Energy comparable EBITDA decreased by $194,000,000 year over year to $224,000,000 principally due to the sale of our U. S. Northeast power generation assets in the second quarter of 2017. Bruce Power continues to perform well with comparable EBITDA increasing $15,000,000 from the same quarter in 2016 due to improved results from contracting activities, partially offset by lower volumes resulting from increased planned outage days. As discussed in Q2 2017, we are winding down our remaining U.
S. Power marketing contracts and will realize their value and associated working capital over time. In the Q3, these operations contributed comparable EBITDA of $29,000,000 Now turning to the other income statement items on Slide 18. Depreciation and amortization of $506,000,000 decreased by $21,000,000 versus Q3 2016, largely due to the sale of our U. S.
Northeast power generation assets, partially offset by the addition of new facilities across our segments. Interest expense included in comparable earnings of $503,000,000 decreased by $13,000,000 compared to the same period in 2016, mainly due to the repayment in June 2017 of the bridge facilities used to partially fund the Columbia acquisition and the impact of a weaker U. S. Dollar in translating U. S.
Dollar denominated interest, partially offset by new long term debt and subordinated notes issuances. AFUDC was $35,000,000 higher year over year, largely driven in Canada by investments made on the NGTL system. The increase in U. S. Dollar denominated AFUDC is primarily due to the continued investment and higher rates on Colombia projects as well as additional investment in Mexico, partially offset by the commercial in service of Topolobambo and completion of Mazatlan.
With respect to the October 5, 2017 termination of Energy East and related projects, we ceased capitalizing AFUDC on the projects effective August 23, 2017, being the date of the NEB's announcement altering the terms of their assessment and expect to record an estimated $1,000,000,000 after tax non cash charge in our 4th quarter results. As previously indicated, due to the inability to reach a regulatory decision, no recoveries of costs are expected from third parties. Interest income and other included in comparable earnings rose $46,000,000 in the 3rd quarter compared to the same period in 2016 due to realized gains in 2017 compared to losses in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U. S. Dollar denominated income, the interest income and foreign exchange impact related to the aforementioned Adder affiliate loan receivable from the Sur de Texas joint venture and $10,000,000 of income recognized on the termination of the PRGT project, mainly related to the recovery of carrying costs.
Regarding our sensitivity to foreign exchange rates, our U. S. Dollar denominated assets, including our interest in Mexico, are predominantly hedged with U. S. Dollar denominated debt and the associated interest expense.
163,000,000 in Q3 2017 decreased by $98,000,000 compared to the same period last year, mainly as a result of lower comparable pretax earnings in 2017 and changes in the proportion of income earned between Canadian and foreign jurisdictions. And finally, preferred share dividends increased by $13,000,000 for the 3 months ended September 30, 2017 versus the same period in 2016 due to the issuance of Series 15 preferred shares in November 2016. Now moving to cash flow and distributable cash flow coverage ratios on Slide 19. Comparable funds generated from operations of approximately $1,300,000,000 in the 3rd quarter decreased by $125,000,000 compared to the same period in 2016, primarily due to the lower comparable to lower comparable EBITDA, largely as a result of the sale of our U. S.
Northeast power generation assets in Q2 2017 and increased funding for our U. S. Employee post retirement benefit plans, partially offset by higher distributions from our equity investments and an increase in interest income and other. For the Q3, comparable distributable cash flow was $769,000,000 or $0.88 per common share compared to $994,000,000 or $1.25 per common share in 2016. The year over year decrease was primarily driven by the decline in comparable funds generated from operations and higher maintenance capital expenditures.
Comparable distributable cash flow per common share for the 3 months ended September 30, 2017 also includes the dilutive effect of issuing 60,000,000 common shares in November 2016 as well as through DRIP participation in 2017. Maintenance capital expenditures of $442,000,000 in the Q3 were $100,000,000 higher than the level of spend last year. This amount includes $181,000,000 related to our Canadian regulated natural gas pipelines, which was $85,000,000 higher than the Q3 2016 and is immediately reflected in the NGTL and Canadian mainline rate basis, which positively impacts net income. As well, maintenance capital of 2 $17,000,000 on our U. S.
Natural gas pipelines was $28,000,000 higher than in the Q3 2016. A reminder that ANR maintenance capital is expected to be at elevated levels through the balance of 2017 2018 and will earn a return of and on capital per last year's rate settlement. Seasonally, maintenance capital is concentrated in lower gas flow months, which tend to occur in the Q3. Overall, our DCF coverage ratios of 1.4 in the 3rd quarter and 1.8 year to date are lower than last year, but trending towards the full year outlook provided in our February business update. Finally, a few words on the notable progress we have made in financing our 24,000,000,000 dollars near term capital program.
We believe our funding needs remain manageable and will be met through predictable and growing internally generated cash flow as well as a variety of financing levers available to us across the capital spectrum. We generated $1,300,000,000 of comparable funds generated from operations in the 3rd quarter and $4,200,000,000 on a year to date basis. We also completed additional external financing in the quarter on compelling terms and exited the period with approximately $1,400,000,000 of cash on hand. In September, we issued $1,000,000,000 of medium term notes in Canada comprised of $300,000,000 maturing in 20.28 at an interest rate of 3.39 percent $700,000,000 maturing in 20.47 at an interest rate of 4.33%. Today, our debt is long duration and predominantly fixed rate in nature with an average coupon of 5.3% and an average term of 20 years, including the hybrid securities to final maturity.
The average term of our debt, including the hybrids to first call is 13 years. Our dividend reinvestment plan also continues to provide incremental subordinated capital in support of our growth and credit metrics. Approximately 35% of common share dividends declared July 28, 2017 were designated to be reinvested under the DRIP. Year to date in 2017, the participation rate amongst common shareholders has been approximately 36%, representing $594,000,000 of common equity. In June, we established an at the market or ATM program that allows us to issue up to $1,000,000,000 in common shares from time to time over a 20 5 month period at our discretion at the prevailing market price when sold in Canada or the United States.
The use of the ATM will be shaped by our spend profile as well as the availability and relative cost of other funding mechanisms. We have not issued any shares through the ATM to date. In October, we received approximately $600,000,000 from Progress Energy and reimbursement of costs, including carrying costs including carrying charges incurred to develop the Prince Rupert gas transmission pipeline following the cancellation of the Pacific Northwest LNG project. We are also now receiving quarterly cash payments related to carrying charges on Coastal GasLink. The pending sale of our Ontario solar portfolio will also contribute approximately $500,000,000 that we will use to fund a portion of our growth program.
As Russ mentioned, the sale of Ontario solar was not a reflection on the role that renewable energy has in our strategy, but instead represented an opportunity to recycle capital on attractive terms. We expect to book an after tax gain on the sale of this portfolio of approximately $100,000,000 upon closing, which is anticipated before year end. Looking forward, we expect to continue to access the senior debt hybrid and preferred share markets in a manner that is consistent with achieving targeted A grade credit metrics in 2018, while maintaining a strong focus on share count and per share metrics. So in summary, while external funding needs are sizable, they are eminently achievable in the context of multiple financing levers available and the clear, accretive and credit supportive use of proceeds. With the dividend reinvestment plan, access to preferred share in hybrid security markets, portfolio management including potential dropdowns to TC PipeLines LP, project cost recoveries and the select use of the ATM as appropriate, we do not foresee a need for additional discrete equity to finance our current 24,000,000,000 portfolio of near term growth projects.
Turning now to Slide 21. In closing, I would offer the following comments. Our financial and operational performance in the Q3 continues to highlight the diversified low risk business strategy. The addition of the Buckeye Express and Portland Express projects demonstrates the organic growth opportunities that continue to emanate from our broad strategically located asset base. Today, we are advancing a $24,000,000,000 near term capital program and have 5 distinct platforms for future growth in Canadian, U.
S. And Mexico natural gas pipelines, liquids pipelines and energy. Our overall financial position remains strong supported by our A grade credit ratings and a straightforward corporate structure. We remain well positioned to fund our near term capital program through resilient and growing internally generated cash flow and strong access to capital markets on compelling terms. Our suite of critical energy infrastructure projects is poised to generate significant growth in high quality earnings and cash flow for our shareholders.
That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook through 2020 beyond. That's the end of my prepared remarks. I'll now turn the call back over to David for Q and A.
Thanks, Don. Just a reminder before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to 2 questions. And if you have any additional questions, we'd ask that you please reenter the queue. With that, I'll turn it back to the conference coordinator.
Thank you. We will now take questions from the telephone Our first question is from Linda Ezergailis with TD. Please go ahead.
Thank you. I have a question about the Mainline. I don't know if this will be maybe addressed at your upcoming Investor Day. But I'm just curious to know if you have any preliminary thoughts on how your long term fixed price service is going? Is it unfolding as expected?
And how might this influence in any way perhaps a resetting of tools for 2018 or post 2020 as contemplated potentially a couple of years back might be required?
Lid, it's Karl. I can address the LTFP right now. As of November 1, it started. We have not all contracts started this year. Some will start next year and the year after.
So we had a little less than 1.3 Bcf a day scheduled into our system for the start this year. If things went well, I see that if you check day over day from October 31 to November 1, we saw an incremental about $700,000,000 on our system. But the full $1,300,000,000 moved because other contracts have fallen off and not had and had not been renewed. So I consider it to be a full incremental 1.3 on our system. I think that it is well, it has cleared a large surplus of our system, which I think has been good for the mainline.
The mainline right now today is operating full. We have capacity on that mainline of about 3 point 8 Bcf a day and 3.8 Bcf a day is moving long haul out of that system. So the Western system is full. Total contracts on the system still remain about 8 Bcf a day when you take into account all the shorter contracts and delivery contracts in Eastern Triangle contracts. So the main line is operating quite well.
What impact will it have on setting of new tools? Well, we have to go to the Board for 2018 to 2020 tools. We're right now just finishing up some discussions with our shippers to to see if we can get a settlement. But we are preparing ourselves to file those tolls before the end the year. So any tolls that we do file will be adjudicated early next year.
I think on a very high level, I can't go into specific details, but we have accumulated over the last 3 years quite a surplus in our long term adjustment account, but $1,100,000,000 right now sits in that account. So it is clear that as we go forward with our new rates, there'll be some reductions in those rates going forward, both because of the past over collections and because when we brought the extra revenue from the long term fixed price, we never anticipated that in our original filings back in 2015. So we will have a filing for those rates before the end of the year and then you can expect some adjustment to those rates.
And just as a follow-up, if your system is running effectively full, do you see maybe the possibility of some sort of expansion, whether it be related to just adding back some of the compression over the next little while? And what might that entail?
Well, yes, well, certainly so the system isn't fully contracted for a long period of time. As other contracts fall off and don't get picked up, there'll be capacity that comes back on the system. So there will be opportunity for people to buy more capacity if they want to just this not for a couple of months here as the beginning of the winter starts. But I guess one part of the comment on that is that, yes, if you take a look at our entire infrastructure coming out of WCSB from NGTL to the mainline and the volatility of prices on NGTL, which says to me when the prices are volatile that people should have to should find more export markets out of the WCSB. We will be looking at potential expansions of the mainline.
Right now, as you're aware, we have some latent capacity in the mainline that all that what we have to do is we have to finish the maintenance, we have to do the pressure maintenance, in line inspections, do the digs and we can bring that capacity back on the mainline. And that's something we're looking at right now an option for our NGTL shippers who want to find extra export capacity out of the WCSB. So the short answer to your question is yes, we're taking a look at that right now.
Thank you.
Thanks, Linda.
Thank you. Our next question is from Robert Kwan with RBC Capital Markets. Please go ahead.
Good morning. Maybe I'll just continue first with the mainline. Just given the high level of contracting that you're at for 2018, are you able to give a bit of a sense as to the ability for discretionary pricing revenues and where you might expect the achieved ROE and where the LTA might move through year end?
It seems I guess I got a couple of comments on that. The number 1, the discretionary pricing revenues, we never actually really got a lot of revenues from discretionary pricing from the actual pricing of surplus services itself. Discretionary pricing acted, I think, as an incentive for our customers to buy Feet contracts. And it was from the additional purchase of those Feet contracts that we were able to overperform our revenue requirement and earn that status in the last couple of years, as you're probably aware, we've earned up to 11.5%, which is the maximum that we can earn on the mainline. My expectation going into next year, don't forget, we're going to reset all of our numbers, all of our billing terms are reset.
And then these higher revenues will come into our incentive setting mechanism. So is it going to be really easy to earn that 11.5 percent? Probably no. I suspect as we go through the hearing and we reset all of our billing determinants, we'll have a new target set for earning those discretionary revenues. So we'll be debating with that with our customers and potentially the regulator here coming in the year as to what that new the new billings term is that we have to exceed in order and incentives will be.
So I think we've had a couple of are those incentives. We've had a lot of value to the mainline. And it's my hope that when we come out of the hearing that we'll have a reasonable incentive program back in place so that we can continue to be assented to over perform on the system.
Got it. If I can then maybe turn to KXL. So on one hand, you're still analyzing the open season results. But on the other hand, you've said that you anticipate commercial support to be substantially similar to the initial project. So is it fair to say based on what you're seeing in terms of the submissions that you pretty much have the volumes that you need, but that obviously, there's some conditions and other things that you need to work through?
Robert, it's Paul Miller here. Your comment is accurate. We do have various conditions attached to the interest. So we are working through those to fully understand what they mean. That will take us till the end of the month, but we're quite encouraged by the results we have seen.
Okay. But just in terms of conditions are generally none of which seem to be onerous to you?
I believe the conditions are manageable, yes.
Okay, that's great.
Thank you. Thanks, Robert.
Thank you. Our next question is from Jeremy Tonet with JPMorgan. Please go ahead.
Good morning. Congratulations on the KXL results as you described them there. Was just want to turn over the wind down of the U. S. Power contracts and was wondering if you might be able to share a bit more color with regards to the duration and ratability of kind of the cash flow there?
Or should we just kind of expect volatility in results until those expire?
So it's Karl. I guess I could talk a little bit about kind of how we're winding down what remains of the U. S. Northeast. We still have a book there.
When I look at kind of earnings that we're expecting out of the book and all the credit that we've put for those earnings into the book, we're looking at about $200,000,000 I think over that will come back to us probably substantially all of it, 95% of it within the next 3 years, of course, weighted to the front end as we wind down that book. We are still in discussions trying to sell what remains in that book. So maybe we can get it 1 down a little early. To date, we have not concluded anything, but we still are in discussions. So it might come a little earlier than that if we're able to sell all of that or pieces of it.
But I would say about 95% of it, we'll see before 2020.
That's helpful. Thank you. And then pivoting over to the financing side and listed a number of options that you guys have there as far as how you approach it. It seems like with this most recent asset sale, you were able to kind of get quite a nice price tag there. So just wondering what other opportunities like that?
And if you could just help prioritize for us how you think about the different mechanisms? Because if I look at TCP, I don't think they could afford that type of evaluation in assets. Maybe you could just help me think through how these things stack up.
Yes, it's Don here. In terms of further asset sales, we're it's pretty high quality portfolio that we have left here, but we're open minded in terms of further portfolio management here. The way we look at this, a couple criteria, hold versus market value, strategic positioning and tax consequences is a big thing as well. If we sell something and pay a big cash tax bill, it makes it certainly less compelling to us. As we look at the stack here, top to bottom, senior debt within the A grade credit metrics that we're targeting here, Probably room for another hybrid issue in the next 12 to 18 months here of some size to bring us to 14%, 15% of capital structure on a sustained basis there.
The DRIP plan will continue running through this, and we'll use the ATM as necessary to balance off the credit metric targets for at the same time being cognizant of growing share count here. Pipe LP is business as usual. There's been no fundamental change in how we view that vehicle. It remains a key financing alternative for us going forward. It does have to compete with our alternate capital sources, including asset sales here.
So it will be fluid depending how ebbs and flows of everything from LP market conditions to business results, capital plans and the like. But what you've seen this year is probably a preview of how we're going to do things going forward. We've done year to date about $1,500,000,000 of senior debt, dollars 3,500,000,000 of hybrids. We did an LP drop. We had some recoveries on PRGT.
We had $800,000,000 from the DRIP and just north of $5,000,000,000 of asset sales. So long way to way of saying it's at all of the above strategy here, but everything's in play.
That's all helpful. Thank you very much.
Thanks, Jeremy.
Thank you. Our next question is from Ben Pham with BMO. Please go ahead.
Thanks, Ed. Good morning. I wanted to go back to the Keystone XL and you mentioned open season taking a month to analyze the bids and then Nebraska approval process around the same timeframe. And there's some questions about timing post that in terms of what you need to do. And I just wanted to check-in end of November, is there anything left there on the XL side of things for you to make an FID decision?
Ben, it's Paul Miller here. So we still have a lot of work to do on both events. We are still working through the bid conditions, and that will take some time. We anticipate the Nebraska PSC approval here by the end of the month, and it will take us some time to review the decision by the PSC. So I think we let those two events play out, and that will give us greater visibility into our investment final investment decision.
Maybe I can just add, Ben, is that there is certainly urgency on the part of our shippers to come to conclusion sooner rather than later. But as Paul said, there's still some data that we don't have in yet that will go into our decision making. But the push is currently from our shipper group to move sooner rather than later.
And my follow-up on that, you've mentioned some of the conditions imposed by shippers you think could be manageable. Are you able to share those conditions, are they mainly driven by external events that shippers have to manage? Or is it more negotiation with how the structure of the contracts or the toll is being discussed at the moment?
Yes. So the way the open season works is we provide the contract and the terms and conditions of the contract to the marketplace, and that's what the ship has bid into. So there's no movement or negotiations around that. It's just unique situations for different shippers that they have to navigate and they work with us to help navigate that. So it really is a lot of it mechanical, logistical, but all very unique to each shipper.
Okay. All right. Thanks a lot. Thanks, everybody.
Thanks, Ben.
Thank you. Our next question is from Paul Tan with Credit Suisse. Please go ahead.
Hi, good morning. Regarding the sale of your Canadian solar asset, how do you think about sort of the positioning of the Canadian business, power business relative to other opportunities in your portfolio?
Paul, this is Karl. Maybe I'll speak to that. We still have actually a pretty high quality power portfolio within TransCanada. So I see the sale of the solar as an opportunity to recycle some capital, which doesn't mean we're not going to recycle capital elsewhere. We've done it both with our natural gas pipelines through the LP and we've done it through selling parts of the power business.
But certainly, we have a big long term commitment to the Bruce Power to refurbish that with our partners. And we have a very large plant, dollars 1,000,000,000 plus plant under construction right now at Dampines. So I would say that we look at our Canadian power business as a key and core aspect of our business going forward. Doesn't mean to say we won't we will recycle some other assets in it over time, but I do believe it is a it's still a pretty high quality business that we intend to hold on to and to grow over time.
And I just
augment to Karl's response. The power business remains a very important part of our portfolio. What we sold here in the last few months is 2% of our portfolio. 76 megawatts wasn't a large component of our portfolio. We retained 6,200 megawatts of operating assets with the addition of Napanee here coming into 2018.
That business will still be generating $1,000,000,000 of EBITDA for us. Looking forward, we believe that 1,000,000,000 of dollars of new investment is required in the energy business or the power business going forward to both convert the system from a higher carbon intensity to a lower carbon intensity. That means more natural gas, more renewables and in our case, potentially more nuclear in places like Ontario. But as well with transmission distribution, as we need to be built out to accommodate those new resources and to replace an aging infrastructure system. So we literally see 1,000,000,000 of dollars of opportunities ahead and those opportunities will compete for capital in the future from our growing cash flow from our asset base.
So it remains important to us, remain in the business, as Karl said. As we've done with all of our businesses, will look to surface value where possible, recycle that capital to higher returns if possible. The lens of which we look at all of things is through a per share return basis for our shareholders, and that's the way that we'll continue to move forward. It's been a solid component of our portfolio for 20 plus years and will continue to be for the future.
Great. Thank you very much.
Thanks, Paul.
Thank you. Our next question is from Ted Durbin with Goldman Sachs. Please go ahead.
Thanks. Just on Keystone XL, we recently had an announcement that the owners of Capline are planning to reverse that in a few years. I wonder if that's changed the nature of the conversation around the competition and the ability to get heavy crude down to the Gulf Coast?
Ted, it's Paul Miller here. It has not Capline, Reverso is near the marketplace. They're looking for nonbinding interested accesses at different markets. So it really hasn't had any impact on our activities around Keystone XL or any of our operating activities.
Okay. And then if I can just on the quarter itself, if we look at the liquids results, you were up year over year, but actually looks like it ticked down a little bit versus Q2. We would have thought you would have maybe taken advantage of some of the widening in WTI Brent to move more on Market Link. Maybe can you just talk about the dynamics there and the ability to drive more revenue on Market Link given that widening spread?
Sure. So we saw the spread widening here really into October more than September. And so we saw reduced activity on particularly on marketing business in the Q3 and slightly reduced flows on MarketLink relative to the 2nd quarter. In the 4th quarter, however, we've seen market activity pick up considerably, and we see flows probably in the 500,000 barrel per day range on Market Link. We have launched an open season on Market Link with the higher differentials.
Parties have approached us with the goal to maybe terminate out some space on MarketLink. So we've launched that open season. I think it runs for about a month, and I would anticipate seeing higher activity in Q4.
Okay, that's helpful. Thank you.
You're welcome. Thanks, Doug.
Thank you. Our next question is from Robert Catelli with CIBC Capital Markets. Please go ahead.
Hi, good morning. I wanted you to address the AECO price situation for a minute. As you know, there's been periods of very low AECO prices in recent months. So in your opinion, what does the industry have to do to mitigate this risk over time? And in your answer, can you please address the various stakeholder groups, including infrastructure companies, shippers as well as regulators?
Yes, Robert, it's Karl. So maybe that's a very big question. So I'll try and answer it in a reasonable amount of time here. And let me start by talking about kind of TransCanada's or my view kind of the dynamics that are going on here and how our infrastructure relates to those dynamics. I think it's important to recognize that NGTL and TransCanada, NGTL specifically in TransCanada generally
are partners
with the producers in the WCSB. We have on Angie TL, we have about at the end of this year, we'll have about $8,500,000,000 invested, net invested into this asset. We have a $7,100,000,000 construction program right now. And in that construction program this November 1st, we put 30 odd, 30 different projects into service to both create new receipt capacity on NGTL and to create more delivery capacity on NGTL. What we just to be plain spoken here, what we're saying on this system right now and this is the net system AECO, whatever you want to call it, as we see more supply staying in net or AECO than we see market.
And that is causing supply on supply competition for the sales. And that is causing extreme amount of volatility. Now I know a lot of people are out there complaining about kind of our maintenance cuts, our cuts for installing new capacity, our use of cutting IT before Feet. But I think when you actually step back for a second and you take a look at it, it all comes down that there is more local supply than local demand. And this is causing gas on gas competition, which is causing extreme volatility as people are fighting for those internal markets.
What you will find right now with this is that, that volatility will moderate somewhat with the cold weather and that start of the new gas here. We see our industrial load in our system is average over 6 Bcf all week. And you've probably seen, if you take a look at the daily price, which I haven't looked at for a day now, but if you look at the daily price, it's probably stabilized in good measure because there is more demand in our system to take up these extra gigajoules. But the fact is that it's fundamentally more gas fighting for a limited market is what's causing this volatility. Now let me take a couple of just couple of comments about kind of what people are feeling about kind of some of our operating practices, and then I'll talk about what I think the solution is.
First of all, maintenance on the system. Maintenance is not new for the NGTL system. What people are seeing right now is that it's more noticeable because 85% of our gas is concentrated in the one area of our system. That's kind of the Northwest Alberta Northeast BC system up by Mohave and Duvernay. So what happens when we do the maintenance, there's not the system isn't as robust as it used to be with the wind gases distributed throughout our entire system and they're seeing it.
One thing I will say with our maintenance and our integrity work is the cuts generally are pretty small and they're episodic, depends where you are on the system. And they're getting better. We're seeing about 1 third less cuts this year than we saw last year, for example. One of the big issues that we have had is, if you recall over the last couple of years watching as this transformation system took place, first of all, we had people, they were upset that we're cutting so much IT, so they bought Feet. And now they're upset that we're cutting more IT in our lead Feet flow.
I can tell you the methodology that we're using when we do do cuts is that we're trying to respect and we've been asked by our producers to our shippers to respect that Feet cuts come last. Any IT that can be cut before Feet is being cut. And that is a model that we've been by our shippers to follow. And that is something that we're trying to do as best as we can to follow the fact that the sanctity of the Feet contract. That has caused some grief for people who believe that some IT should have some ability to vote.
And it's just caused some angst for people depending upon what type of IT we cut. For example, if we cut delivery market IT, it can create even more competition for the market. But we do have to respect the fact that when somebody buys an Feet contract, we have to make sure that all IT that can be cut is cut before that Feet contract gets cut to make way for maintenance. But I would just reiterate again that our maintenance cuts, the system, every time I put those 30 projects in and the 30 projects next year in, those maintenance cuts gets less and less and people notice them less and less. So what is the solution to this?
Well, I have talked about this before, and I've talked about it with our shippers. And quite frankly, a lot of our shippers have followed this through their own marketing efforts. But the solution is to not only own Feet receipt contracts, firm receipt contracts to get your gas on, but to own Feet firm transportation contracts to get your gas out of the system into export markets. The FTD, we call it, Feet delivery contracts. So there are customers that have owned those that have been completely isolated from any volatility as much.
As a matter of fact, the volatility might have worked in their favor. But they are now in Dawn or they're in California or they're in Chicago or they're in the Midwest or New England or New York, depending upon where they bought the transportation contracts to. Those are the people that have not been harmed, that have not felt this volatility or managed to benefit from it because they have owned capacity to get their surplus gas schedules out of the WCSB where the price is depressed and more and into higher value markets. If I can have advice for any of our customers is to take a look at moving air gas out of the market. We are working very hard to get more capacity out.
The LTFP was one step in that. We will find more capacity on the mainline where Stan and his group in the U. S. Are finding or right now looking at more capacity on GTN to get to California and so forth. As for your contract on what is the infrastructure companies and regulators, I do think that the solution to this, the price volatility is to build more takeaway capacity.
The regulators will have a role in that and that we got to be able to build that capacity before too much economic damage occurs, so to speak, with volatile prices. So obviously, the regulators will have a role as us and other infrastructure companies come along to find solutions to it. And but because I do believe the answer is to transport your gas right to market now and not sit around on an over supplied market that is currently net. So I hope that answered your question.
Yes. Thank you for that very fulsome answer. I do have one more question for Don. You've articulated very clearly your financing strategy for existing projects, the current slate. If you're successful with Keystone XL, is there 1 or 2 items in the immediate slate of financing options that's more attractive to fund that project?
Yes. A couple of comments should KXL proceed. We do have much of the long lead time items in inventory already. So that's just one thing to bear in mind here. Much of the steel is already in house here.
By the time we would marshal up and get construction going here, the bulk of the spend on KXL would be in the 2019 2020 time frame, which actually dovetails quite nicely with much of our $24,000,000,000 near term program being completed and those assets starting to cash flow. So this is probably more of a 2019, 2020 financing story with that asterisk that cash flow would be ramping considerably in that time frame.
Okay. Thank you. Thanks, Rob.
Thank you. Our next question is from Rob Hope with Scotiabank. Please go ahead.
Yes. Good morning. Just keeping on the Ketone XL theme, just want to get a sense of what volume commitments you were targeting and then whether or not the return on the project would be including existing capital or would it just be on new capital there?
Rob, it's Paul Miller here. We when we had launched Keystone XL previously, we had contracts of about 500,000 barrels per day, and we'd be looking to target something similar. And these would be long term 20 year contracts. And consistent with all of our large projects, we look to underpin Keystone XL with these 20 year contracts and would look to target appropriate returns on our total capital.
All right. That is helpful. Excellent. And then just finally getting back on to the NGTL system. You have announced projects year to date, but we still do need some capital to connect in some coal to gas conversions as well as some other expansions.
Just want to get a sense of behind the scenes or what do you think a run rate level of investment at the NGTL would be for the next couple of years?
That's a good question. So let me answer it this way. We need 2 investments to happen on the NGTL. Number 1 is we still have a queue of customers wanting to get on the system for receipt services. And that queue is sitting at and it's been a long time since I've looked at it, so I'll just talk kind of approximately here.
But it's approximately 1,000,000,000 cubic feet of gas that is sitting in the queue right now waiting for us to come and propose new pipelines. I also am mindful of the conversation that I just had with Robert on on kind of what is the solution to the oversupply in the net system. And we are looking right now and we will probably be holding some sort of open season or some sort of expression interest for the delivery capacity to go along with that such that we will we can not only bring on 1,000,000,000 cubic feet of new receipt, but tie in some of our delivery service. Delivery service on the NGTL to get to the East Gate, for example, is about 4,800,000,000 feet a day. When you take a look at the math right now, it is fully utilized.
We are between going into the mainline, which is right now at 3.8 and going down Mancia Northern Border, which is about 1.3. We are fully utilized. As a matter of fact, we're using storage to make up the difference on that. So we need to do both. So now what does that come down to for a dollar amount?
I hate to come out and give a number of dollars because it really depends where it is and what we're doing. I could be orders of magnitude to that. But maybe what I will just say is that we have a queue of Bcf a day, new receipts on it. And I would argue that we are here. Actually, I wouldn't argue.
I can tell you we are here looking to find a Bcf to 2 Bcf a day of more delivery capacity and more capacity downstream, let's say, on GTN and or the mainline. So I'll give you the volume numbers that we're kind of looking at. And then we can well, we'll talk about capital as I get contractual support for it and I get better engineering on what that looks like.
Okay. That's helpful. Thank you.
Thanks, Rob.
Thank you. Our next question is from Tom Adkins with Morgan Stanley. Please go ahead.
Thank you and thank you for your patience for hanging in there with us today. So look at Slide 17, you call out some principal variances for the different segments. Just wanted to ask a couple kind of questions on those. First is in pipelines. How the size of the Columbia Gas pension plan item and if that's always going to be a Q3 item or if it's something that you trued up in particular this year to minimize charges in the future?
Yes. It's Glenn here. Normally, we would just expect the pension costs as everybody does. In the case of Columbia, they have a unique aspect of their last approved rate that says they will only expense pension costs as they're funded. And this is our normal funding for the year.
We just didn't have any funding in that last year as part of the as it was transitioning in. So it's a one time thing that you're seeing and we'll continue with normal funding going forward on this.
Yes. No order of magnitude probably a penny, penny and a half this quarter.
Okay. And question 1b is on the entry liquids pipelines of the Grand Rapids entering service. What was the magnitude of that? And I'm assuming since it was mid August, at least more than maybe at least doubles in the 4th quarter, what would be the ramp beyond that?
Tom, it's Paul Miller here. Grand Rapids contributed about $0.05 in Q3, and I would anticipate probably $0.01.5 in Q4.
Great. And then question 2 is the Mountaineer and Leach Express cost increases $700,000,000 between the 2 of them, it's pretty big. I know you get it back in the future, but it's just a lot of capital. What happened there? Can you elaborate?
And why would it why are you confident that that's not going to continue to happen?
Yes. This is Stan. Thanks for the opportunity to opine on that. Cost estimates for Mountaineer in particular have been revised due to increased construction costs, mainly tied to the high demand for resources in the region in 2018. So just as an example, across the Appalachian region, across all the projects that are being built, there's going to be over 100 pipeline spreads, which is an all time peak high for the region.
And that demand for resources is what's driving the increased costs as we lock in our costs with our contractors. I should point out, however, that we do have a cost sharing mechanism with our customers whereby 50% of the costs are shared equally between us and the customers up to a predefined cap, which will minimize the impact to our project returns overall. So we've incorporated the lessons learned from our Leach XPress project, which we've been constructing for past summer and are comfortable that the $600,000,000 represents a large part, if not all of the cost increases with respect to the Mountaineer XPress project.
Great. I appreciate it guys. Thanks a lot.
Thanks Tom.
Thank you. Our next question is from Fazel Khan with Citigroup. Please go ahead.
Thank you. Thanks for taking my question here. I just want to figure out how you guys are thinking about your revenue requirement and or your tariffs, how they might change in U. S. Pipelines under a lower corporate tax rate?
And if you could just remind us also sort of what happened with the revenue requirement in Canada for some of your regulated pipes 10 years ago when the corporate tax rate came down? Just to help us understand how things could change or may not change at all.
Fazlo, this is Stan. I'll start and others can jump into the extent necessary. With respect to rate cases, we do not have any immediate rate case obligations. The first two would be Colombia and ANR in 2019 2020. So absent the FERC absent, 1, the tax plan being finalized as currently is and then 2, absent FERC requiring pipelines to come in and some sort of a special proceeding to address rate reductions, those tax changes would just be incorporated into future rate cases.
Yes. It's Don here. On the Canadian side, income taxes are flow through on a cash basis and that's always been the case. So any interest rates sorry, any tax rate increases or decreases would be reflected in rates effectively immediately.
Okay, got you. And then just on current rate cases, on the GLGT rate case, is there a time when you have to go in for your next rate case? And it's done also on the Northern Border side. Can you talk about the settlement that's being offered there?
Yes. With respect to Great Lakes, there is a 5 year comeback provision. However, there is not a moratorium on filing a rate case sooner should we need to do so. In the aggregate, Great Lakes represents about a 27% rate reduction, but that will largely be offset by increased revenues associated with the long term fixed price deal, as well as removal of the revenue sharing cap. So net net on Great Lakes, we don't see material change in cash flows.
The northern border rate case is not yet public. We're actually drafting that right now. The rate reduction there is much more smaller. You could think of that in terms of a upper single digit rate reduction. But again, given some other parts to settlement, we do not see material impacts to cash flows or revenues in that proceeding either.
Great. Thanks for the time guys. Appreciate it.
Thanks, Ross.
Thank you. Our next question is from Joe Gemino with Morningstar. Please go ahead.
Great. Thank you. Looking at maintenance capital for the quarter, can you explain why it went up from the previous quarter? And is this kind of the run rate to look at going forward?
Yes. It's Don here. I'll start and my colleagues want to jump in as well. There is a seasonality aspect to maintenance capital, as I mentioned in my remarks. It is concentrated, particularly in the U.
S. In months where gas flows are lower. So that's a that will be a recurring phenomenon there. But effectively, there's 2 major trends here. 1, maintenance capital has been trending upward as the gas system gets tighter and tighter and more money is required for reliability.
The second trend, this is actually positive for us because maintenance capital has always been the case in Canada, but increasingly so in the United States is recoverable. It's de facto growth capital that we will earn a return on. So yes, I'll give a little more granularity at Investor Day in terms of that, but those are the 2 major trends right now.
Great. Thank you.
Thanks very much, Charles.
Thank you. Thank you. Our next question is a follow-up question from Jeremy Tonet with JPMorgan. Please go ahead.
Thanks. Just wanted to be real quick here. And you guys were quite successful in scooping up Colombia what appeared to be just the right time in the U. S. Market.
And it seems like the MLP market is quite a level of distress for some players out there. So just wondering if you could provide any high level thoughts as far as opportunities to further expand your position in the U. S. Given the need of some players there to kind of migrate their balance sheet towards metrics more similar to yours? Thanks.
I think, Jeremy, as we've always said, I mean, we're chockablock full right now with things to do and places to allocate our capital. That said, there are certain assets and positions in the marketplace that we covet and we continue to watch them. And if there's opportunity to act, we'll do that. As Don mentioned, we have several levers. One of the reasons for maintaining our strong financial position and financial flexibility is to be able to act when opportunities do arise.
But usually what we're hunting is the crown jewels of these portfolios and they're usually the last things to be sold out of those. So sort of roundabout answer to your question is we're always interested. We have the capacity to act, but it's very rare that these opportunities arise. But if they do, we'll be prepared to act upon them.
Sounds good. See you at Analyst Day.
Thanks. Thanks, Jeremy.
Thank you. There are no further questions registered at this time. I would like to turn the meeting back over to you, Mr. Moneta.
Thanks very much and thanks to all of you for participating this morning. We very much appreciate your interest in TransCanada. We look forward to seeing many of you again later in the month as part of our Investor Day. Again, thanks very much and have a great day. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time and we thank you for your participation.