TC PipeLines, LP (NYSE:TCP) Q1 2020 Earnings Conference Call May 6, 2020 11:00 AM ET
Rhonda Amundson - Manager, IR
Nathaniel Brown - President
Janine Watson - VP and GM
William Morris - Principal Financial Officer
Conference Call Participants
Jeremy Tonet - JPMorgan
Matthew Taylor - Tudor Pickering Holt & Company
Michael Lapides - Goldman Sachs
Good morning, ladies and gentlemen, welcome to the TC PipeLines, LP 2020 First Quarter Results Conference Call.
I would now like to turn the meeting over to Ms. Rhonda Amundson. Please go ahead, Ms Amundson.
Thank you, Operator, and good morning, everyone. Welcome to TC PipeLines First Quarter 2020 Conference Call. I'm joined today by our President, Nathan Brown; our VP and General Manager, Janine Watson; and our Principal Financial Officer, Chuck Morris.
Please note that a slide presentation will accompany their remarks and is available on our website at TCPipeLinesLP.com where it can be found in the Investors section under the heading Events and Presentations.
Nathan will begin the call today with a review of TC PipeLines' 2020 first quarter results. Janine will provide a commercial update on the Partnership's assets and our growth program, following which Chuck will provide a review of our financial results for the first quarter. Nathan will return and wrap up our remarks and close with some key takeaways. Following the prepared remarks, I will ask the conference operator to coordinate your questions. Before we begin, I would like to remind you that certain statements made during this conference call will be forward-looking, regarding future events and our future financial performance.
All forward-looking statements are based on our beliefs, as well as assumptions made by and information currently available to us. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions as discussed in detail in our 2019 10-K, as well as our subsequent filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, actual results may differ materially from those described in the forward-looking statements.
Please also note that we use the non-GAAP financial measures EBITDA, adjusted EBITDA and distributable cash flow during our presentation. EBITDA and adjusted EBITDA are approximate measures of our operating cash flow during the current earnings period and reconcile directly to net income. Distributable cash flows provide a measure of cash generated during the period to evaluate our cash distribution capability. As stated in our press release this morning, we've made a definitional change to adjusted EBITDA, and this will be covered later in the call by Chuck. These measures are provided as a supplement to GAAP financial results, and we provide a reconciliation to the most closely related GAAP measures in our SEC filings.
With that I will turn the call over to Nathan.
Thanks Rhonda. Good morning everyone and thank you for joining us today.
Let me begin by saying that we are clearly living in unprecedented times with the COVID-19 pandemic having such a significant impact on people around the world. On behalf of everyone at TC PipeLines, we truly hope that you and your families are healthy and safe during these uncertain times. I'd also like to express our sincere thanks to the front line health care and other essential service workers who are risking their personal safety to ensure the well being of others.
We at TC PipeLines in concert with our sponsor TC Energy are very focused on the health and safety of our employees, contractors and the communities in which we operate. When the World Health Organization declared COVID-19 a global pandemic in early March, our business continuity plans were put in place across our companies, allowing us to continue to safely and effectively operate our assets and execute on our capital programs.
These services we provide are broadly considered essential or critical given the important role our infrastructure plays in delivering energy to people and businesses across the United States. To do this, many of us are working remotely, while those of us that must physically be at work are following rigorous health, hygiene and distancing protocols. These actions ensure the energy that is vital to the daily lives of so many continues to be delivered seamlessly across our country. I'll now turn to our first quarter financial results. As outlined in our news release and looking at
Slide 4, I'm pleased to report TC PipeLines solid quarterly results with our portfolio of pipeline assets continuing to perform as expected. With approximately 90% of our cash flow coming from long-term take-or-pay contracted assets, we're insulated to a great degree from the recent volatility associated with volume throughput and commodity prices that's being experienced by many others in the energy business.
Customer demand for our service remains strong despite the impact of COVID-19 on the broader North American economy. Aside from the impact of normal maintenance activities, planned regulatory adjustments and seasonal factors, to date we have not seen any meaningful change in the utilization of our assets, which further reinforces the critical nature of our infrastructure. We generated $88 million in net income during the first quarter of 2020, slightly less than the $93 million in the same period in 2019.
EBITDA was at $134 million for the first quarter, and adjusted EBITDA was $138 million compared to $142 million and $152 million respectively generated in 2019 over the same period. The decreases were largely a result of negotiated rate decreases on certain of our pipelines together with lower short term discretionary sales related to the warmer winter we all experienced this year.
The rate decreases we're anticipated coming into 2020 and the seasonally warm winter weather essentially limit our upside compared to the additional marginal revenue we were able to achieve in the colder winter last year. We generated $88 million in distributable cash flow in the first quarter 2020 compared to 2019. Our DCF was $116 million. The decrease is largely the result of lower revenues as already discussed together with higher maintenance and integrity capital expenditures.
Higher maintenance costs, although a drag on distributable cash flow, reflects a positive environment of higher natural gas flows. And these costs will be added to rate base and enjoy return on and of capital through future tolls. We paid out $47 million in distributions to our unit holders during the first quarter, together with $8 million to our Class B units.
The partnership also declared its first quarter distribution of $0.65 per common unit, which is consistent with our quarterly distributions in 2019 and for each quarter in 2018. The stability of our low risk business model, which is underpinned by long-term take-or-pay contracts, and strong demand for our essential energy services provides a basis for our solid financial performance and our ability to maintain the distribution to unit holders, even in periods of economic stress and uncertainty.
Chuck will discuss the financial results in a little more detail later in the call. We also continue to advance our organic growth program, work continuing on both our GTN XPress project and Tuscarora expansion.
Our other PNGTS organic projects are progressing well and will provide for incremental capacity on a PNGTS pipeline system in the Northeast. We anticipate the changes to work practices and other restrictions put in place by government and health authorities in response to the COVID-19 pandemic could have an impact on construction timeline.
We generally believe this will not be material to our operations, but the long-term impact of COVID-19 impact and associated effect is certainly - is uncertain at this time. We continue to develop other projects across our portfolio, including the Iroquois Enhancement by Compression Project and North Baja's XPress project which was discussed in previous calls. Both are low impact compression only projects.
Janine will discuss these and other commercial developments in more detail in a minute or two. During the first quarter, looking at our financial position, our bank leverage ratio was approximately 3.4 times and our distribution coverage also remained very strong at approximately 1.9 times.
While we're proud of our financial performance and returns we have generated for our unit holders, we know our ongoing success depends on our ability to balance profitability with safety, environmental and social responsibility. I want to stress that safety and reliability are critical priorities for us. Our general partner, TC Energy, has a 55-year track record of safe and reliable operations, and we're committed to protecting the environment in all that we do.
Our natural gas assets are critical to the quality of life of communities they serve. We believe our systems will be important contributors in achieving greenhouse gas emission targets to further improve the carbon footprint in North America and beyond.
I'll now turn the call over to Janine Watson, our VP and General Manager for additional color on our assets and our commercial developments, together with the market outlook.
Thanks Nathan, and good morning, everyone.
Moving on to Slide 5. TCPs Assets are highly contracted critical infrastructure as was evidenced in their steady performance this past quarter. As Nathan noted, these pipeline systems have firm take-or-pay contract structures that largely insulate them from volatility associated with fluctuations in markets or throughput.
Despite the slowdown of economic activities due to COVID-19 we saw no meaningful changes in utilization of our assets in Q1 when compared to our expectations and based on prior years' experience, other than those we expect to see as the weather changes during the spring months or that are tied to our maintenance activities. And our assets encountered no material credit issues during this period, nor were there any noteworthy contract expirations or non-renewals.
Turning to our largest asset, effective January 1 GTN implemented the 6.6% recourse rate step down agreed to in its 2018 settlement with its shippers. Mild weather conditions experienced in the Pacific Northwest this spring and the absence of major disruptions on other neighboring systems meant that our marketing team did not have as many opportunities to make short-term sales, as was the case in Q1 of 2019.
Nonetheless GTN's large portfolio of long-term take-or-pay contracts, together with the incremental flows coming down to Kingsgate as a result of TC Energy's ongoing debottlenecking projects upstream, enabled GTN to be a solid performer for TCP.
Looking forward, we anticipate about 250,000 dekatherms a day of additional upstream capacity will become available for transportation to GTN in the second half of 2020. As discussed in past calls, these volume increases will bring the upstream systems capacity up to parity with GTN's current maximum capacity. Northern Border's equity earnings for Q1 were slightly elevated when compared to the same time frame last year as Northern Border's team successfully marketed its operational capacity in the final months of winter.
And, in more recent developments, on May 1 Northern Border filed a tariff amendment with the FERC to establish a 111,000 Btu - an 11,000 Btu heat content safe harbor provision for the natural gas it receives into many receipt points across the system. This step was taken in response to the increased production and higher BTU supply coming out of the Williston Basin, which has resulted in the BTU levels above 1,100 being present at many Bakken receipt points onto Northern Border. By proposing a Safe Harbor BTU level of 1,100 as opposed to a maximum BTU level or a hard cap, Northern Border can continue to receive natural gas in excess of this level, but only as long as it is able to blend the overall system content to a level of no higher than 1,100 BTU.
The changes being proposed are designed to ensure the continued safe and reliable transportation of natural gas through Northern Border's system and to downstream markets. And we remain committed to working towards an economical expansion project to provide incremental takeaway capacity out of the Bakken, a potential project that could include reversing the direction of flow on our Bison Pipeline.
Now the impact of recent global events on the development of this project cannot be fully assessed at this point, but we may experience a slowdown of our development activities compared to the pace we were expecting at the beginning of this year and potentially a push back of the project in service date by perhaps 6 to 12 months into the second half of 2023.
Moving on, Great Lakes continues to be a steady performer with equity earnings roughly on par with Q1 of 2019. And in light of current market uncertainties, we find it significant that Great Lakes was recently able to hold a successful open season for firm capacity this April, marketing a total of about 570,000 dekatherms a day via multiple contracts with various parties for an average term of just over 18 months.
About half of these arrangements are set to commence in November of this year, though some have start dates in 2021 and 2022. We believe this is a positive indicator of the ongoing value of our asset base, even during the times as challenging as the current COVID-19 crisis.
Quarterly results on the remainder of our transmission system were all roughly comparable to Q1 of 2019. These assets are highly contracted on a firm basis, and each has the opportunity to make incremental short-term sales, though mild weather meant that not many incremental sales opportunities arose this past quarter versus quarter - Q1 of last year. And finally, all of our assets operated at high levels of availability, with no significant safety or operational issue.
Turning now to Slide 6, we introduced this chart last quarter, and it illustrates our CapEx outlook for our major projects over the 2020 to 2023 period. It is largely unchanged from what we presented in February. We continue to advance the projects that make up TC PipeLines significant platform for growth with business continuity plans in place across our footprint, allowing our operator to continue to effectively operate our assets and execute on our capital program. To date we have experienced no slowdown of our permitting, pre-construction or construction activities nor any material changes to our planned capital expenditures.
However, it is too early to determine whether the pandemic will have any long-term impacts on our capital program. We continue to monitor the impact that the COVID- related safety protocols will have on productivity as we execute on our projects. The bars on the graph represent TC PipeLines proportionate share of estimated CapEx based on our ownership levels. North Baja and Iroquois projects are, of course, still subject to a few extra layers of further approval, but we have included them given their advanced stages of development.
Permit acquisition work on both these projects has continued as anticipated in Q1. PNGTS' projects also continue to proceed as anticipated. Phase 3 of Portland XPress is currently under construction with the contractor having put COVID-19 safety protocols into effect, and the project remains on schedule to be in service on November 1 of this year.
We continue to proceed with the Westbrook XPress project at PNGTS with the FERC section 7C permit for Phases II and III anticipated to be filed in about July of this year. These two phases require certain capacity enhancement work to be completed upstream of PNGTS to achieve their planned in service dates of November of 2021 and 2022.
Engineering and permit acquisition efforts continue to be on track for GTN XPress, and we are progressing our Tuscarora XPress project as per normal course. We continue to plan to self-fund the capital during this period through a combination of debt at the asset levels and contributions from TC PipeLines, the latter funded with cash from operations, together with our revolving credit facility, if required.
Though a small portion of our planned maintenance activities in Q1 have been shifted to subsequent quarters this year as a result of our business continuity planning in response to COVID-19, our proportionate share of maintenance CapEx is still expected to be about $113 million in 2020, again self-funded. As always, this CapEx is expected to be added to our pipeline system's respective basis and - respective rate basis and recovered through fixed negotiated rate contracts or recourse rates over time.
I will now turn the call over to Chuck Morris, our Principal Financial Officer, to discuss our first quarter in more detail.
Thanks, Janine, and good morning, everyone.
Moving on to Slide 7, I'll now review the partnership's first quarter 2020 financial results. Net income attributable to controlling interests in the first quarter was $88 million or $1.21 per unit compared to $93 million or $1.28 per unit in the first quarter of 2019. This represents a 5% decrease year-over-year and primarily reflective of the scheduled rate reductions on certain of our pipelines, together with warmer winter weather this year that offered fewer opportunities to benefit from short-term sales.
These decreases were partially offset by additional revenue from our new contracts at PNGTS that came into service in late 2019. EBITDA was $134 million in Q1 of 2020 versus $142 million for the previous year, or 6% lower, primarily as a result of the lower revenues from our consolidated pipelines that I just noted.
I'd also like to highlight that we've made a change in how we calculate adjusted EBITDA. In the past, we have included this measure and adjusted for non-recurring items that were significant, but not reflective of our underlying operations. Going forward, we would also adjust EBITDA to remove earnings generated from our equity investments and add cash distributions received from those equity investments.
We have recast the results from our quarter ended March 31, 2019 to conform to this new presentation. We believe that this revised measure more closely aligns with similar non-GAAP measures presented by our peers and provides a better representation of our operating performance. With that enhancement, our adjusted EBITDA for the first quarter of 2020 was $138 million compared to $152 million in 2019, approximately 9% lower.
The decrease was a result of the lower revenues, together with the lower distributions from our equity investment in Iroquois. Iroquois had been making quarterly payments to its owners of surplus cash on its balance sheet from the date of our investment in Iroquois, and the Q4 2019 payment marked the final installment associated with that obligation.
The Partnership paid distributions of $47 million to common unit holders in the first quarter, the same amount that was paid in Q1 of 2019. We also paid $8 million to our Class B units in 2020, $5 million lower than that was paid in 2019. The reduction year-over-year resulted from higher maintenance CapEx at GTN which reduced distributable cash flows generated.
As Nathan mentioned earlier, we declared our first quarter 2020 distribution of $0.65 per common unit. This is consistent with that declared in previous quarters in 2019 and for each quarter in 2018. And distributable cash flows were $88 million in the first quarter of 2020, $28 million lower year-over-year.
The primary drivers for the decrease were our lower earnings and adjusted EBITDA, together with higher maintenance and integrity capital expenditures at GTN resulting from higher system utilization. The higher maintenance costs, although a drag on distributable cash flow, reflect the positive environment of higher natural gas flows. And these costs will be added to rate base and will attract a return on and of capital through future tolls. Partially offsetting these factors was a $3 million reduction in interest expense attributable to our $68 million lower average debt balance in the first quarter of 2020 compared to the same period in 2019.
Turning to Slide 8, revenues from our consolidated pipelines of $101 million for the first quarter of 2020 were lower than that at the same quarter last year by $12 million. This is primarily a result of the scheduled rate reduction of 6.6% on GTN effective of January 1 of this year and a 10.8% decrease on Tuscarora effective August 1 of 2019, together with lower discretionary services sold by GTN, PNGTS and North Baja during the period.
These decreases were partially offset by the new revenues from PNGTS' growth projects that went into service on November 1 of 2019. Equity earnings in the first quarter of 2020 were $1 million higher than ended the same quarter in 2019. Operating, maintenance and administrative expenses during the first quarter were $2 million lower than in the same quarter of 2019 as a result of lower property taxes on Bison and PNGTS, and an overall decrease in allocated employee costs.
Depreciation expense was unchanged from the first quarter of 2019, and financial charges were $3 million or 14% lower in the first quarter of 2020 versus the same period in 2019. The ongoing reductions in our outstanding debt balance, which was $68 million lower at March 31, 2020 compared to the previous year.
Moving on to our financial position on Slide 9, our healthy financial position is reflective of the proactive measures that we have taken over the past two years. Our balance sheet is strong with a solid capital structure underpinned by our high-quality energy infrastructure pipeline assets. Our investment grade credit ratings, including our one-notch upgrade by S&P from BBB-minus - BBB flat last year provide us with the financial flexibility as we look to organically grow the portfolio in the future. And we believe the ratings reflect our solid financial condition and outlook.
A significant portion of our long-term contracted revenues with investment grade counterparties. We have not experienced any collection issues on our receivables to date. We'll execute our suite of organic growth projects on a self-funding basis without the need to access the equity capital markets.
Capital market conditions in 2020 have been significantly impacted by the COVID-19 pandemic and the oil price decline resulting in periods of heightened volatility and reduced liquidity. Despite this, our liquidity position remains strong. Underpinned by our stable cash flow from operations, cash on hand and full access to our $500 million revolving credit facility.
Additionally, we expect to refinance GTN's $100 million senior notes due June of 2020 and Tuscarora's $23 million unsecured term loan due in August of 2020, together with additional funding that will be used to finance a portion of GTN XPress and Tuscarora XPress. Consistent with our self-funding model, in order to build capacity for future organic growth, we have reduced our overall average debt balance, resulting in a bank leverage ratio of approximately 3.4 times.
As we've noted on previous earnings calls, the bank leverage ratio is expected to migrate to the high threes to low four times area due to the impact of previous toll settlements and the de-contracting of Bison. We maintained our quarterly distribution at $0.65 per common unit, resulting in a solid distribution coverage ratio of 1.9 times for the quarter ended March 31, 2020.
As Nathan and Janine outlined earlier, we continue to execute on an organic growth program, including GTN Xpress, Tuscarora Xpress and PNGTS' projects with both PXP and Westbrook XPress proceeding on time and on budget. And we continue to use our steel in the ground advantage across our pipeline system to explore additional growth opportunities.
That concludes my remarks on the first quarter financial results. I'll now turn the call back over to Nathan.
I'll now refer to Slide 10. As I mentioned at the outset, we had a very good quarter this year and our assets continue to perform well, proving out their resilience and strong low risk business model. Going forward, our cash flow will continue to be derived from our portfolio of critical natural gas pipeline infrastructure assets underpinned by long-term take -or-pay contracts of credit-worthy shippers.
In aggregate, our systems are approximately 90% contracted on a long-term take-or-pay basis. We continue to prudently manage our financial position and believe our actions have resulted in a strong balance sheet. Our bank leverage ratio is currently 3.4 times and our distribution coverage this quarter is a very healthy 1.9 times. These healthy metrics are enabling us to self-fund our organic growth as we outlined earlier on each of our GTN, Tuscarora and PNGTS projects.
Longer term, we're targeting to maintain our bank leverage ratio in the high three to low four times area and our distribution coverage ratio of roughly 1.3 to 1.4 times. We reiterate that we do not need to access the equity capital markets to fund our current growth program.
As Chuck noted, consistent with our self-funding model, and in order to build capacity for organic growth, we've continued to pay down debt levels and execute on our delevering program. Our focus remains on provision of the essential energy services together with the optimization of our asset portfolio.
And we'll continue organic growth over time. We are very excited to be pursuing approximately $700 million of growth projects across our suite of assets. These include our current GTN, Tuscarora and PNGTS XPress projects, together with our North Baja and Iroquois development opportunities.
We continue to conservatively manage our financial position, self fund our ongoing capital expenditures and maintain our debt at prudent levels and believe we are well positioned to fund our obligation through a long period of disruption, should it occur. Based on all available information known to us today, we expect to deliver consistent financial performance going forward in our business - and our business to support our currently quarterly distribution level of $0.65 per common unit.
I'll now turn the call back over to Rhonda. Thanks.
Thank you, Nathan. I'd now like to open the call up for questions. Operator, go ahead.
[Operator Instructions] The first question is from Jeremy Tonet from JPMorgan. Please go ahead, your line is open.
I just want to start off with a question on a couple of development projects here. Just hoping to get a little bit more details on the latest for Baja and Iroquois and more specifically, I guess what exact approvals are you guys waiting for both of those projects and any other milestones we should be watching for and how you think the timeline is progressing at this point?
Yes, thanks for the question, Jeremy. So starting with Baja, waiting on approvals there, still subject to final FID by Sempra on their Costa Azul facility. So that's going to run its course. And certainly they have a number of things that they're working through to get to that FID, But things continue on pace for that hopefully within the next quarter or so. Certainly as things develop there, if there are any changes, we'll communicate them through. But for that one on that time frame, we're looking for the next quarter and really listening for Sempra's next step in their decision making.
Within Iroquois and the ExC project up there, things are progressing through the permitting and regulatory process in due course as certainly every stage has its hearings and an ability for interveners to ask questions. And it's going through normal course on that too, so no extraordinary interventions, there no extraordinary push back from the regulators that we've seen. Everything seems fairly normal course.
We're certainly taking a very measured approach as is probably advisable at this time and in that jurisdiction. I think the management team at Iroquois is very focused on getting that done the right way. So that's proceeding, no real timeline changes on that either. So we're watching that, and we'll communicate any changes as they develop.
And then, I just want to pivot to Northern Border for a minute here if I could with regards to the new 1,100 limit that I think that you were talking about there. Just wondering, it seems like it's a dynamic situation right now with regards to Bakken production slowing down a bit here. And then you have kind of similar dynamic in Canada. So wondering how do you see that mix shift kind of changing here as those two streams change a bit. And are you kind of at that limit right now, and where do you see that I guess progressing over time? Could there be a scenario where you would reject Williston Gas because it's too hot or would that just force extraction? Just trying to better understand that dynamic there. Thanks.
Well you kind of put your finger on it there. It's pretty volatile and pretty dynamic, certainly one of the - only one of the inputs to that equation is the heat limit content that we talked about it. Really this has been a developing situation that we've been talking to all interested parties up and down Northern Border for a while to make sure that end users have the gas that they can actually use and then the marketers and producers are able to find the outlet for the gas they have.
So with the limit introduced, it's more of a mechanism to make sure that we don't get offsides of that. Is it possible that there should be - there could be some gas rejected? Yes, but it's more of a tool and a milestone and a signpost to point you to make sure everyone's on the same page is what we can do operationally.
As far as blending goes and the dynamics of Western Canadian gas blending and with the Bakken. As said, it's a volatile situation, and the users of the pipe will work to optimize where the volumes are needed, where the net-backs are good for them. And fundamentally, I think we keep pointing back to the very economical commercial situation that Northern Border represents for folks whether they coming out of Western Canada or they're flowing out of the Bakken. It's a fundamentally advantaged pipe with a depreciated rate base, very, very economical tools for them to find an outlet for their products.
So on the whole, still like the Northern Border's position for this. As far as can how - where specifically the gas is going to be sourced out of, that's definitely going to change with the evolving market conditions, but long term, definitely like the position.
But as of right now the pipe still flowing full right? I mean there is still flaring to be captured to keep it full even if there is curtailments or shut ins?
I don't have kind of up-to-the-minute or up-to-the-week flow data from which basin it's coming in, and they're seasonal fluctuations on Border in any case, but the flows are not anything out of the ordinary.
Next question, Matthew Taylor from Tudor Pickering Holt & Company. Please go ahead. Your line is open.
Just a follow-up there to Jeremy's questions on Northern Border. Is there a financial impact from this new tariff for those that want to continue pushing hotter gas? And then more context on blending, if you don't mind, are customers paying a premium for you to blend it down or do they need to make those arrangements on their own?
Yes, we don't do any blending ourselves, so we had to accept the spec of gas we can get. But we're limited by what our end users can accept too. So we're trying to work really across the value chain here to make sure that everything is workable for the different specs that folks may have, whether it's on our interstate transmission system, the gathering systems that feed into us or our end-users.
And so it's a less than direct sort of line of sight into what is strictly spec, but we're working toward more definition around that. And that's what the tariff filing has done. When we talk about blending in this case, really what we're talking about is blending the gas streams that we do receive on Northern Border's normal course. The processing that's done for our Western Canadian gas lends itself to being drier upon receipt at Manchee for Northern Border than the gas that comes in the Bakken.
So for - historically the gas never had a heat content issue that anyone had to worry about. And we're just starting to add some definition around that to make sure everyone has the mechanisms to get that back onto spec. So to the extent that there is blending from additional streams, we've got a little definition around that in the tariff.
So that if there is relatively drier gas coming out of the Bakken from points, you can blend that in with the growth of the wetter gas and still get that 1,100 number. Or if we've got a greater proportion coming out of Western Canada, it may not be an issue on any kind of given day and point. But it's a dynamic issue, we really look at this as a tool to be able to manage that. And we'll be employing it as necessary, but I don't see it as a big operational shift. It's more representative of the way we operate the pipeline on a regular day, but making it more transparent.
Is there any tariff discrimination there if you do want to flow in excess of the 1,100 or is this just a definitional change?
Definitely wouldn't look at it as discrimination. It gives us the ability if we approach the 1,100 to potentially turn some back, but it's not on a discriminatory basis.
And just to be crystal clear, there is no change in the actual dollar amount of the tariff?
No, this doesn't have any impact on rate.
And then on counterparty risk, I know you mentioned that you haven't seen any collection issues to date. It looks like your partnership profile mentioned about 70% of your customer base is investment grade. Have you seen that number shift at all given all the recent downgrades? And I'm just curious if you could maybe just highlight pipes that might have the most exposure to non-investment grade counterparties and potentially could see collection issues?
Yes, sure, there has certainly been some downgrades across the space, none significant to get us into non-investment grade territory. The other thing that - it's hard to say because we've got a fair amount of customers who are not rated publicly that we would sort of internally call to be investment grade ourselves, sitting in that same space.
So the 70% number that you referenced is the publicly-rated folks, and we've got another 20% or so that we would put in the same category if they were publicly rated. So that puts us in the 90% range of investment grade-ish counterparties that we deal with. And that seems to be persisting even through the current commodity price environment.
So that's to say we don't have large exposure to the folks that are really feeling the particular pinch at the moment. The large counterparties, apart from our affiliates on the TC Energy side of the house, are large marketing and trading operations and also other, to the extent we have upstream customers that are directly contracting on the pipes, they're very strong and doing relatively well in the space and have a strong gas focus that's less reliant upon liquids prices to support them.
Next question is from Michael Lapides from Goldman Sachs. Please go ahead, your line is open.
Thank you for taking my question, and congrats on a good start to the year. I actually have three. One is, Nathan, when do you think about or when do you think the company will be positioned to reinstate distribution growth for shareholders? That's the first one. The second is, can you remind us what state permits or state approvals are needed for the Iroquois project? And then third, is there any update on kind of re-contracting or ROPER on Northern Border?
Yes, thanks for the question, Michael. First one on distribution growth, really what we're focusing on right now is the execution of the growth project portfolio we've got in front of us. Obviously you've got a fair amount of estimation going into these things prior to them being executed. And once we get there and we get clear line of sight on precisely what the expenditure is going to be, when they're going to come and when the cash flow is going to start coming back positive out of these projects, then we can model out the full financial picture and have a line of sight into the potential distribution growth in the future.
But we're taking a very measured approach to that, making sure we keep our flexibility open, make sure we keep our balance sheet healthy to be able to execute on these projects and absorb even more growth in the near term as we see it potentially coming to pass.
So really it's not a time frame thing, it's more of a project execution thing. Once we get to a level of comfort with all of these and the cash flow timing, then we'll be able to kind of turn our focus into the next phase. But really this phase is an organic growth, internally funded type of case for us.
And we think that's going to be the best way to build that stability and build that value to be able to distribute out to the unit holders out in the future. On your Iroquois projects - your Iroquois project question, I think Janine, do you mind to take a shot at what the last round of regulatory stuff that's gone through on that one?
Iroquois obviously working through its FERC process right now, and I can say that they are at the EA-stage. And that appears to be going in the ordinary course. An unusual or different feature of their application is that they are seeing a three-year construction window for this project that allows us to go through the FERC process and fully determine the types of equipment we are going to need to have to meet that regulatory process ahead of actually ordering long-lead-time equipment. So I think that's an important feature that we're using to handle some of the regulatory risk in that territory.
Once they get their - or assuming they do get their FERC permit which we anticipate in Q1 of next year, we would then need to get air permits at each of the compressor sites. So that's the New York DEC permit as well as one from equivalent in Connecticut, as well as some storm water discharge type permits and various sundry other state level permits. So we're working closely with all those agencies, and things seem to be progressing well there. But of course, as Nathan mentioned, because of the geography and the times, we are trying to be very prudent in how we step forward.
Got it. And then on the last question about Northern Border and the right of FERC refusal some of the customers have and kind of re-contracting for the early 2020?
Yes. So that dynamic continues as it has. I think Northern Border has shown great value and has been running chock full for about a decade now. The fundamental value there of the path of the pipe is very, very strong. I think what we've seen over the past two, three years is the increasing pressure of supply push for associated gas coming out of the Bakken. And while that may slack off for a period of months here, that doesn't change the underlying strength of the pipe for Western Canadian gas coming out. So we still think that production needs to find a market, and it's going to do it on a very economic path. So that's what Northern Border's got going for it.
For Northern Border's ROPER provision within its tariff, again that drives a large portion of what you see if you look at, a simplified look at our contract tenure that we've got out there. That's going to drive down what it looks like we've got for long-term contracting simply because we have these large incumbent positions that can go uncontested and renew what they have on only a five-year bid. So as those come up for rebid, we've got strong positions.
And when the - when your customers and when they exercise the ROPER, is that just exercising on the capacity or does it also maintain the same tariff?
Well, the recourse rate contracts. So to the extent we have recourse rate change, they'll go with that. So those are done on the same terms.
Thank you, ladies and gentlemen, this concludes the question-and-answer session. If there are any future questions, please contact Investor Relations at TC PipeLines, LP. I will now turn the call over to Rhonda Amundson.
Great, thank you everyone for your participation today. We appreciate your interest in TC PipeLines, and we sincerely hope you and your families are staying healthy, bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time and we thank you for your participation.