Start Time: 16:30
End Time: 17:11
Enbridge Energy Partners, L.P. (NYSE:EEP)
Q2 2016 Earnings Conference Call
July 28, 2016, 16:30 PM ET
Mark Maki - President and Principal Executive Officer
Steve Neyland - VP, Finance
Guy Jarvis - President, Liquids Pipelines
Jonathan Rose - Treasurer
Sanjay Lad - Director, IR
Jeremy Tonet - JPMorgan
Sunil Sibal - Seaport Global
Brian Gamble - Simmons & Company
Gabriel Moreen - Bank of America Merrill Lynch
John Edwards - Credit Suisse
Hilary Cauley - Ladenburg Thalmann
Good day, ladies and gentlemen, and welcome to the Second Quarter 2016 Enbridge Energy Partners, L.P. Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions]. As a reminder, this conference call is being recorded.
I would now like to turn the conference over to our host for today, Sanjay Lad, Director of Investor Relations. You may begin.
Thank you, Sonia. Good afternoon, and welcome to the 2016 second quarter earnings conference call for Enbridge Energy Partners. This call is being webcast and a copy of the presentation slides, supplement slides, condensed unaudited financial statements, and news release associated with it can be downloaded from the investor section of our Web site, at enbridgepartners.com. The webcast replay will be available later today and a transcript will be posted to our Web site shortly thereafter. As a reminder, the Partnership's results are also relevant to Enbridge Energy Management or EEQ.
I will be available after the call for any follow-up questions you may have. Our speakers today are Mr. Mark Maki, President; and Mr. Steve Neyland, Vice President, Finance. Available for the Q&A session we also have Mr. Guy Jarvis, Executive Vice President, Liquids Pipelines; Mr. Jonathan Rose, Treasurer; and Ms. Nora Casey, Controller.
Moving forward to Slide 2, our legal notice. This presentation will include forward-looking statements. Any statements made or discussed today that do not constitute or are not historical facts, particularly comments regarding the company's future plans and expected performance, are forward-looking statements. Actual results or outcomes may differ materially from those that may be expressed or implied.
The risks associated with forward-looking statements have been outlined in the press release and the Partnership's 2015 annual report on Form 10-K and subsequently filed quarterly reports on Form 10-Q. This presentation also contains certain non-GAAP financial measures. The comparable GAAP and the reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found in the investor section of the Web site and following the slide presentation.
Please turn to Slide 3. I’ll now turn the conference over to Mr. Mark Maki, President.
Thank you, Sanjay. Good afternoon and welcome. We will be concise with our remarks of today's call, and then we’ll get to your questions. Two top of mind business matters first and then we’ll discuss our crude oil fundamentals.
One point of emphasis before we proceed further is that the Partnership had a very good quarter, despite the impact of the wildfires in northern Alberta, and Steve Neyland will take us through the financials before we go to Q&A.
Please turn to Slide 4. One very important recent business matter is our settlement with the U.S. Department of Justice, or DOJ. Last week we announced we had come to an agreement on a consent decree with the DOJ and the U.S. Environmental Protection Agency.
The consent decree relates to the Line 6B and 6A pipeline incidents in 2010. The settlement is an important milestone that allows us to move forward. Let's first review the principles of the agreement.
The decree has three primary components. The first is a civil penalty of 61 million for the Line 6B incident and $1 million for the Line 6A incident. Next, the decree provides safety measures that quantify and build on continuous improvements that we've implemented since 2010.
These measures are largely related [indiscernible] operations, total inspection practices, spill prevention and our response capabilities. The cost of these measures is estimated at $110 million over four years and is already largely incorporated in the Partnership's operational and capital expense planning.
The final component is pipeline replacement. We replaced the entire 285-mile length of Line 6B in 2014. Also in 2014 we agreed with our customers to fully replace Line 3. We’ll talk more about the progress on this project in just a minute.
Safety is one of our three core values at Enbridge, and our team remains very focused first and foremost on the safety and operational reliability of our systems. We took full responsibility for the Line 6B incident in 2010 and we have fulfilled our commitment to thoroughly clean up and restore the area, and to cover all costs of the spill.
Following the incident, we reflected long and hard about what happened in 2010 and we invested significantly in our people, processes, equipment, and our technology. We are a better company today as a result and we will never be satisfied with anything other than leading safety performance.
As I said earlier, the settlement is an important milestone and it allows us to move forward. So moving to the financial implications with the decree, the prospective costs associated with the decree are manageable. The costs are not expected to significantly affect the longer-term outlook for EEP. For your information, we’ve included a table on our supplemental package that shows the components of this portion of the decree in more detail.
Please turn ahead to Slide 5. Earlier this year, we received written orders from Minnesota Public Utilities Commission for portions of the proposed Sandpiper project and Line 3 replacement projects located in the state. Orders require that a final environmental impact statement, or EIS, for those pipeline projects be completed prior to the commencement of this the certificate of need and route-permit processes.
We expect the Minnesota Public Utilities Commission to rule what is in scope and out of scope for the environmental assessment by the end of this summer. And the approximately 280-day EIS process is expected to commence thereafter. As the regulatory process has been clarified, we are confident in early 2019 in-service dates.
The Sandpiper project is expected to provide access to key lateral markets in the U.S. Mid-Continent and Eastern Canada. We recognize that the supply fundamentals in the Bakken are under some pressure, and we are sharply focused on ensuring that when it comes to this service, we will provide our customers with the benefits that everyone expects, competitive tools and shot netbacks.
The Line 3 replacement is critical to the industry because it ensures our shippers have enhanced reliability and assurance of moving anticipated end of decade throughput levels on our system of 2.85 million barrels per day. Collectively, these products are secured by long-term, low risk commercial structures and are expected to deliver meaningful cash flow growth to the Partnership and our unitholders.
Please turn ahead to Slide 6. Let’s transition now to the strong supply fundamentals supporting our core liquids pipelines business. The Canadian Association of Petroleum Producers or CAPP recently released its updated Western Canadian supply forecast. This was done last month.
Focusing on the heavy oil in particular, as you see on this chart in the left, CAPP is anticipating approximately 660,000 barrels per day of heavy production growth over the next four years out of the region. Despite the low commodity prices, there’s a solid growth expected into the next decade.
This growth is backed by the ramp up of recently completed projects and anticipated in-service dates of projects that are under construction. Given the nature of the projects, this is highly certain growth. Remember, the oil sands projects typically have long-lasting and steady production profiles and the producers typically don't curtail production once a project is operating as it risks the lifecycle economics of the project.
As shown on the chart in the right, CAPP expects the pipeline takeaway capacity from the region will remain constrained in the foreseeable term. On the surface, it appears the basin is expected to be shored about 300,000 barrels per day of pipeline capacity by 2020.
When you peel back the onion, however, and look at the crude slates, the 2020 capacity requirement is likely higher because of room that won’t certainly [ph] be created by expected declines in light volume can’t be utilized by growing heavy barrels on a barrel-per-barrel basis. So you actually need to add about 700,000 barrels per day of capacity to accommodate the heavy oil growth.
We are working with Enbridge and our customers to help address this gap between heavy crude oil supply and pipeline capacity, and we’re always looking for ways to further optimize our system.
One way we’re doing that is by blending volumes to a new crude stream that can move on light lines and free up capacity on our heavy lines. We talked about this idea on our last quarter’s call and we’re working hard to have a new crude stream added to our system late this year.
When this is done, then it’s expected to add an incremental 60,000 to 80,000 barrels per day of heavy capacity to the mainline system. And of course we’re also looking at other cost effective ways to add incremental capacity to the system and we have a list of scalable opportunities that we’re pursuing.
Please turn ahead to Slide 7. The other side of the equation driving system demand is the market reach of our system. Customers on our liquids pipeline system have the premier access to markets in Eastern Canada, U.S. Midwest and the Pad 2 regions of the U.S. Gulf Coast.
Our system provides Western Canadian and Bakken producers with direct and indirect access through third-party pipelines to more than 8.5 million barrels per day of refining capacity. And because we offer access to multiple premium markets, our shippers have flexibility in the event of a market disruption, like a major refinery outage.
Recent Enbridge projects, like the U.S. Gulf Coast market extension, the Line 9B reversal, expansion of the Line to Montreal, the Southern Access Extension to Patoka, all serve to enhance this flexibility and pull volumes to our system. It’s a long list of market access projects added by the parent over the last several years.
Not only do we offer our customers connectivity to the best markets, we do so at very competitive rates. This gives us great confidence and a continued strong demand for and the high utilization of our liquids pipeline systems. So these are very strong supply and demand fundamentals and it resulted in another good quarter for the Partnership.
Let’s move ahead to Slide 8. I’ll turn the call over to Steve to walk us through the financial results.
Thank you, Mark. The Partnership's financial results for the second quarter are tracking well with our expectations and reflect the reliability of our low-risk business model. Starting with the financial results table on the left side of the slide for the second quarter, the Partnership's reported adjusted EBITDA of 489.3 million and distributable cash flow of 262.7 million. The EBITDA impact from the Alberta wildfires in the second quarter was an unfavorable 20 million and we did not adjust for this amount in our quarterly results. More on this in a moment.
Our as declared distribution coverage ratio for the second quarter was 1.0 times, including inclusion of paid-in-capital distribution and cash coverage of 1.22 times. Let's review our findings results compared to the second quarter of 2015 and then discuss how they compare sequentially over the first quarter of 2016. The Partnership's second quarter adjusted EBITDA and distributable cash flow increased 16% and 13%, respectively, when compared to the comparable period in 2015.
Revenues from our liquids pipeline systems increased due to higher transportation rates attributable to new assets placed into service related to our mainline expansion project. Lakehead system deliveries were higher by more than 230,000 barrels per day over the comparable period in 2015, despite the impact from extreme wildfires in northeastern Alberta during the second quarter of 2016.
Higher segment revenues were partially offset by increased operating and depreciation expense over the same period from the prior year due primarily to higher property taxes related to new assets placed into service. The Partnership's second quarter adjusted EBITDA and distributable cash flow increased 5% and 7%, respectively, when compared to the first quarter of this year. Adjusted EBITDA was 23.1 million higher than the first quarter.
The EBITDA impact from the wildfires in the second quarter was an unfavorable 20 million, the financial impact from the wildfires was more than offset by a combination of positive items when compared to the first quarter. First, liquids segment revenues were higher due to the updated Lakehead system surcharge, effective April 1 by approximately 20 million. Next, assets came into service during the quarter which increased revenues by 10 million. This included operational storage as part of mainline expansion projects and the final phase of the Eastern Access project.
Also, the sequential increase in Ozark system volumes contributed to higher revenues in the second quarter. Complementing the higher revenues were reduced operating costs over the first quarter attributable to lower operating and administrative expenses and lower power of approximately 10 million.
Our debt to EBITDA leverage metric at the end of the second quarter was 4.6 times, which considers 50% equity treatment for hybrid financing instruments we currently have in place. The debt to EBITDA bank covenant metric was 4.2 times as it attributes 100% equity treatment for the hybrid instruments. This puts us comfortably in compliance with our bank covenant requirement.
The main items eliminated from these adjusted results include unrealized non-cash, mark-to-market net gains and losses and other items noted in our supplemental slides. Today, the Board of Directors declared a quarterly cash distribution for the Partnership unitholders of $0.583 per unit or $2.332 per unit on an annualized basis. The approved distribution remains unchanged from the previous quarter.
We are pleased with the Partnership's first half financial performance and expect to carry this positive momentum into the second half. As a reminder for investors, we look at distribution coverage on an annual basis. The most significant reason for this being the seasonality of maintenance activities on our pipeline systems, especially those located in the north. We expect maintenance, capital expenditures, and operating costs will be higher in the second half of 2016 relative to the first half of the year.
Please turn to Slide 9. Turning our discussion of the Partnership's liquids segment volumetric performance, you'll see that second quarter deliveries averaged approximately 3.04 million barrels per day. Deliveries on our Lakehead system for the second quarter averaged 2.44 million barrels per day while the Alberta wildfires affected Lakehead deliveries in May and June by approximately 255,000 barrels per day. Second quarter deliveries were also reduced by upstream and downstream upgrader and refinery turnarounds.
Demand for our liquids pipeline systems remains strong and we expect the Lakehead system deliveries during the third quarter to return to levels anticipated at the outset of the year. Deliveries on the North Dakota system remain strong and were 381,000 barrels per day in the second quarter. While rig activity in the Bakken region has been declining in the low commodity price environment, the basin is significantly short pipeline takeaway capacity.
We expect volumes moving on rail to be unfavorably affected while our system is expected to remain heavily utilized. Mid-Continent system volumes were 216,000 barrels per day during the second quarter returning to more typical levels following the completion of refinery turnarounds that we saw in the first quarter.
Please turn to Slide 10. This slide provides our forecasted 2016 capital and investment expenditures. We have continued to prudently manage this area and expect capital expenditures to be approximately 885 million, which includes 65 million of maintenance capital. These expenditures are presented net of joint funding.
During the second quarter, the Partnership completed the final phase of the Eastern Access Expansion at a cost of 320 million, adding an incremental 70,000 barrels per day of capacity to the Lakehead system between Griffith, Indiana and Stockbridge, Michigan. With the final phase of the Eastern Access project now complete, the Partnership has up to one year to exercise its book value call option to increase its economic interest in the Eastern Access series of projects from Enbridge. The cost of the book value call option or dropdown is approximately 360 million and is included in our financing plans for 2016.
Next, the Line 3 replacement participation and joint funding level with Enbridge is under consideration by an independent committee with the Board of Directors and no decision has yet been reached. We have presented a credit of 350 million to reflect one possible scenario to represent the approximate dollars that would be remitted to EEP by Enbridge. This would represent the capital contribution by Enbridge for an economic interest in the jointly funded project.
Shifting to the Partnership's liquidity position, as presented on the chart to the right, on July 26, 2016, we entered into a $750 million unsecured revolving 364-day credit agreement with Enbridge U.S. Inc. On a pro forma basis, the Partnership has over 1.2 billion of available liquidity and the Partnership has adequate liquidity to fund its base capital and investment program this year.
Please turn to Slide 11. Our low-risk business model is underpinned by contract structures that deliver reliable cash flows. The liquids pipeline business is expected to deliver more than 90% of the Partnership's 2016 cash flows backed primarily by long-term low risk contract structures like cost of service and ship or pay.
In fact, as you see in the pie chart on the left, less than 5% of the Partnership's cash flows are subject to direct commodity price exposure before hedging. The benefits of our low-risk business model are particularly evident in a period like the second quarter when volumes were disrupted by the wildfires. Despite the impact to Lakehead deliveries, the financial impact was mitigated by these contract structures.
Cash flows are further protected by the high credit quality of our counterparties. Customers have strong credit ratings and balance sheets to navigate the current low commodity price cycle. As you can see on the pie chart on the right, more than 90% of the Partnership's credit exposure is to investment-grade counterparties. The remaining noninvestment grade customers are closely monitored and we take appropriate measures to mitigate the credit risk. The resiliency of the Partnership's business model underpins our investment proposition.
Please turn to Slide 12 and I’ll turn it back over to Mark to wrap it up.
Thanks, Steve. The key points for the quarter are highlighted in this slide and there’s just two important things I want to say before I go to Q&A. During the quarter, one of the three rating agencies that rate the Partnership’s stat placed us on negative outlook. To be clear, as we’ve said many times in the past, the Partnership’s investment-grade credit rating is very central to our investment proposition and maintaining investment grade remains a very top priority for the management group.
Together with our sponsor Enbridge, Inc., we are evaluating actions that we can take to strengthen EEP and to that end, we announced a strategic evaluation of the Partnership's investments in its natural gas business through Midcoast Operating to Midcoast Energy Partners. We are progressing on that strategic evaluation and expect to complete the evaluation by the end of the year.
I’ll turn the call over to the operator for a Q&A.
Thank you. [Operator Instructions]. Our first question comes from Jeremy Tonet from JPMorgan. Your line is now open.
Good afternoon, Jeremy.
Congratulations on the strong quarter there coming in ahead of our numbers. I was just curious as far as the results in the quarter, were there any one-time benefits that you guys had there or given that your operations are fairly stable, especially on the liquids business, could we kind of extrapolate forward this quarterly EBITDA run rate or maybe something a little bit less, O&M’s a little bit higher? Is this close to kind of a regular run rate for you guys?
I’ve always said for many years I’ve been doing this for a long time for this business, one thing you have to realize is there is some seasonality on maintenance, which Steve touched on in his comments. In a lot of the areas a lot of the work gets done in the summer season. And we are expecting a little heavier quarter on maintenance in Q3 and maybe with that kind of just a general comment here and we’ll give a little more color if there’s any one timer’s on the positive side, I think by and large. Steve, you want to take it from here.
Yes, I think there’s probably elements of both in the numbers and when you look at Slide 8, you kind of extrapolate some of that. Certainly the tolls are something that’s going to continue in the new projects as it relates to the cost that Mark wanted to highlight that. We expect not only operating costs but also maintenance capital to probably be at a higher clip than what we’ve seen in the first half. And so some positive and negative both gradually we look forward. But Jeremy as you noted at the beginning we’re certainly pleased with the quarterly results and the strength of the Partnership this quarter.
Great, thanks for that. And then just with regards to the strategic review, I’m just wondering could this involve other asset exchanges between EEP and ENB as part of the solution for MEP?
We are not really precluding anything off the table but certainly we’re being very focused on both the MEP and MOLP business to start with as we’re trying to strengthen the position that EEP has. But kind of what you’re looking to is something that certainly could happen at some point or be one of the fastest [indiscernible] down the road.
Great, thanks for that.
Thank you. Our next question comes from Sunil Sibal from Seaport Global Securities. Your line is now open.
Hi. Good afternoon, guys, and congratulations on a really good quarter.
So a couple of questions for me. I think you guys touched upon some higher costs in the second half of the year. I was just wondering in terms of the guidance that you gave at the start of the year, from here onwards what are some of the other factors which could steer you towards the lower end versus the higher end of the guidance, and specifically with regard to the timing on the Eastern Access call option?
Sure, I’ll take that. So as it relates to our guidance that we provided at the beginning of the year, we’re still comfortable with the guidance range that we provided. As noted, we had the headwind this quarter of the Alberta fires. We’ve seen substantial comeback in volumes associated with that but there is some of that, a little bit of a recovery of that that will occur in the next quarter. And so that along with the costs that were just mentioned, it’s really just timing that’s natural within our business and third quarter usually is a little bit higher than most. It relates to some of that catch up. So with that we feel comfortable with guidance and where we sit. And then as it relates to the call option that we have on the 15% step up, so our intent within our forecast to have that occur and so that’s a positive as you roll into the second half of the year, that would be helpful.
Okay. And then the call option, the timing on that, would that coincide with your decision on Line 3 participation by the parent?
We would anticipate that those two things will be very closely aligned, again, with the eye towards mitigating capital needs for Enbridge Energy Partners and as stated before, we don’t have an intent to raise equity in 2016.
Okay, got it. And then on the interest expense, it seems like your interest expense was down quarter-over-quarter quite a bit versus Q1 '16. I was wondering was there anything driving that lower interest expense?
We’ll have to probably get back to you on that one.
Just the quarter-over-quarter interest expense.
I’m sorry, Q1 to Q2 or versus last year?
No, Q1 to Q2.
Yes, we’ll have to look at it. This thing goes through my head is whether that’s net of AIDC or not.
Capitalized interest tends to – as we had projects we brought onto service here recently, they would have been higher end of your spend during the second quarter, like the total dollars respectively built up that should be capitalizing interest, like one of the factors and maybe some others as well. But that one will probably be showing up in the numbers. We’ll dig for that while we’re going through the rest of the call.
I’ll just go ahead and confirm that. Mark’s comments were right on as it relates to the AIDC timing, it’s really a source from a – it’s one of the primary drivers.
Thank you. Our next question comes from Brian Gamble from Simmons & Company. Your line is now open.
Good afternoon, guys.
Good afternoon, Brian.
Hi. I wanted to touch on just the optimization that you mentioned on Slide 6 and we had briefly talked about it last quarter, because we’re evaluating it. Are we pretty comfortable with these numbers now and if we’re going out to I guess all the parties will be involved and comfortable that we can get some I guess contracts renegotiated to take different spec products through the line, or is this something that is still a possibility but still kind of working through it?
Brian, it’s Guy Jarvis. I’ll take a crack at answering that. We’re quite pleased with the progress we’re making on this regard. We foresaw the potential for the weakening lights. It has taken our customers a while to warm up to it but now that they’re seeing the heavier portion and all our systems start to creep back up again, I can tell you the interest in it has ramped back up. As a common carrier we do not need to go out and deal with any contracts. People will be able to nominate volumes on a month-by-month basis. So where we’re at is we have pretty much finalized running all of our internal traps in terms of operating issues, integrity issues and whatnot that we all have to go through. It’s a pretty rigorous change management process we need to go through. I believe there’s some investment across the system that’s in the neighborhood of less than $10 million that has been underway for most of the year and it’s going to be complete here towards the end of the summer. So our expectation is quite strong right now that we’re going to manage to make this work in the fall.
Guy, the additional projects – additional dollars could add to that 60,000 to 80,000 a day number or is that kind of I guess the best swag added in the short term and maybe revisit again longer term. I guess the question for you is there any other near-term benefits that you could recognize there?
Yes, I think the way I would characterize it is it’s a little bit more than a swag in terms of what we think we can do. But when you start thinking about pushing that volume higher, we’re very confident that the heavy barrels seem to be there. But again we’re mixing them with a decline in light. So we’re a little bit cautious about just how much more we think that industry may have factored to do.
Great. And then Steve to your comments about I guess moving pieces, Q1 versus Q2 and then looking at Q3, I just want to make sure I got it cleared up. Your expectation for wildfire impact in Q3 is minimal to none because we’re back to or headed back towards lows that we were already trending towards before the fires. And then also there aren’t any additional I guess add-ons from a new asset standpoint that we should be notable right now, like the Eastern Access was for the quarter or like the surcharges were at the beginning of the quarter. Any one-off like that that we need to be thinking about?
Yes, so a couple things there. So as it relates to wildfires, the month of July we’re still seeing those volumes coming back, so we’re still transitioning in the month of July. And then we should be quite comfortable back to normal run rates. So we’re feeling good about that. So that’s one smaller transitional item that we have coming up. The other piece as it relates to our Eastern Access Phase 3 project, we talked about some of the benefits of that. That came into service this quarter but I think you’ll see in our Q that we referenced that as coming into service in kind of the late May timeframe. So we’ll see a longer – the full quarter impact of that when we get to the third quarter. So those were a couple of things on the positive side that will be helpful as we move forward.
Great. I appreciate that.
Thank you. Our next question comes from Gabe Moreen from Bank of America Merrill Lynch. Your line is now open.
Hi. Good afternoon. Nice quarter. Just had a question on maintaining IGs specifically at Moody’s. Just was wondering in terms of signpost, they sort of may have given you in timing in terms of resolving that negative outlook and how to get off of it? And then also I think when they came out with their release, they kind of have Enbridge family I guess write-up, so to speak. So I’m just wondering to what extent you think this is more of EEP doing stuff on its own balance sheet versus I guess the entire Enbridge family trying to get off the negative outlook?
Gabe, it’s Jonathan Rose. I think it’s more of Enbridge family commentary and I think I’d reserve comment for the Enbridge call that’s coming. I think that it’s fairly evident that EEP itself is working towards a number of different objectives to maintain our investment grade rating ourselves. But there is an uplift that exists with the current EEP rating that comes from the strong GP support and the recent action itself I think has been something that’s more attributed to Enbridge, Inc. as a whole.
Thanks, Jonathan. And if I can just also maybe follow up on that in terms of how the agencies viewed the Midcoast to the MOLP debt versus consolidating versus deconsolidating it? Is there a certain ownership interest level that they might have provided where EEP could actually deconsolidate MOLP from an agency standpoint?
I think the agencies proportionally consolidate that debt, specifically I believe Moody’s does and I’d have to run through the numbers with respect to exact ownership but I believe it’s wronged. Sanjay, do you know what our respective economic interest is in MOLP?
I think it can be calculated through but about 75% of that debt.
Got it, okay. Thanks. And then just one more on Sandpiper and Line 3, just can you give you kind of the next sort of regulatory signpost I guess we should be looking for in terms of the MPUC timeline, what the exact next steps are? Sorry if I missed that on earlier comments.
It’s Guy Jarvis again. What’s going on right now is they are developing the scope of the EIS that is going to be undertaken. That scope gets developed and it gets put forth to the Minnesota Public Utilities Commission who will then approve the scope and initiate the process. That work is well underway and we’re hopeful that the recommendation of the scope of that EIS will be put forth in August.
Got it. Thanks, everyone.
Thank you. Our next question comes from John Edwards from Credit Suisse. Your line is now open.
Thanks. Congrats on a nice quarter. Just coming back to the negative rating, just can you tell us what prompted the negative outlook? And then just to be clear on kind of following up Gabe’s question, what are they requiring from you to resolve it?
John, again, I’m going to defer to the Enbridge, Inc. call and because it is much more of an Enbridge, Inc. view on that. I don’t think anything specifically has changed with the Moody’s view on EEP but it’s a result of change of outlook on the parent. So I think most of that question should be directed at the parent.
Okay, all right, fair enough. And then are there any – with respect to the noninvestment grade counterparties, you had the slide with the pie chart, was 90-10. Are there any issues we should be aware of on the noninvestment grade counterparties?
Nothing of particular note, John, and just to kind of put an exclamation point on the liquids system, I think in the entire history of the liquids, Lakehead, that one in particular, there’s been two credit events in the entire history of the system. People pay their bills and it’s critical to getting product to market. We’ve had North Dakota since the mid-90s. I don’t recall anything significant there. Our gas business has little things every now and again. But the bulk of what our exposures are that this isn’t an issue for us.
Okay, thanks for that. And then just you were talking about I guess just kind of coming back here to Slide 6 and following up a little bit on some of the earlier questions on that. I think you had mentioned there was some scalable opportunities that you’re looking at there and you didn’t mention anything on the way of – or at least if you did I missed it, on the way of capital spend or what that investment opportunity might be if you might talk about that?
I think we’ll ask Guy for additional color on it, John, but there’s a whole list of projects we’ve shown in prior – in a little more detailed presentations that have gone through the different opportunities that are there. It basically starts in Western Canada and works all the way down to the Gulf Coast. So expansions of existing systems, additional horsepower, a little more capital intensive but still relative to some of Guy’s ideas. Guy’s mentioned earlier about more crude streams and other tweaks he can make to the line. But still relatively light-sized, incremental layers of capacity that we can add over time and maybe Guy can provide a little color on that.
Yes, I think really what we’re focused on is opportunities that aren’t so capital intensive, a, because obviously we can squeeze out cheaper capacity and we’ve got across the system a known toll, they’ll be more profitable. Also because we’re looking to try and find ways to add capacity in manners that minimize the amount of permitting that’s required. And again, generally those projects are going to be smaller scale to eke out capacity in the corners of our system. We’re working on a lot of them and we’re working on a lot of them in parallel and just trying to sort out as the continuing outlook manifest and we understand better the difference between the heavies and the lights, which of these solutions we should be moving forward first. So we haven’t quite landed on that, but probably as the year goes on towards the end of the year, we hope to have a better definition on which ones we would be pursuing on what timelines and more clarity on cost and whatnot.
All right, that’s helpful. Okay, that’s it for me. Thank you.
Thank you. [Operator Instructions]. Our next question comes from Richard Verdi from Ladenburg Thalmann. Your line is now open.
Hi, guys. This is actually Hilary on for Rich and I just had two quick questions for you. The first would be with the Sandpiper on Line 3 with the cut in near-term costs, does that just push back due to the regulatory timeline or more of a permanent cost out there?
Due to CapEx timing for those projects and associated with the related per [ph] cost.
Okay, great. And I know you just kind of hit on the growth out of Western Canada, but the fires in Alberta kind of changed how you’re viewing the growth there and maybe some incremental volumes you can pick up due to the change in the landscape there, or any change in how we can view that growth there?
It’s Guy Jarvis again. I don’t think we draw any particular conclusions from the fire in a negative perspective. And I guess potentially you could draw it a bit more in terms of a positive perspective in that heading into the fire situation, a heavy apportionment on our system I think had shrunk down to as low as 5% in a couple of months. We’ve announced publicly that the heavy apportionment in August is back up at 15%. So that’s an indicator that the heavy volume growth is continuing to be strong. I can’t draw an exact conclusion that it’s stronger than we thought, but I think it certainly supports the viewpoint that we’ve had for the last few years.
Okay, great. Thank you. That’s all for me.
Thank you. This does conclude our question-and-answer session. I would now like to turn the call back over to Sanjay Lad for any further remarks.
Thank you. We appreciate your interest in Enbridge Partners and thank you for participating on today's conference call. I would like to remind you that my team and I will be available for any follow-up questions you may have. Thank you and have a great evening.
Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.
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