Enbridge Energy Partners, L.P. (EEP) Q1 2014 Results - Earnings Call Transcript

May. 1.14 | About: Enbridge Energy (EEP)

Enbridge Energy Partners, L.P. (NYSE:EEP)

Q1 2014 Earnings Call

May 01, 2014 11:00 am ET

Executives

Sanjay Lad - Former Director

Mark Andrew Maki - Principal Executive Officer of Enbridge Energy Company Inc, President of Enbridge Energy Company Inc, President of Enbridge Management and Director of Enbridge Energy Company Inc

Stephen J. Neyland - Vice President of Finance of Enbridge Energy Company Inc and Vice President of Finance - Enbridge Management

Guy D. Jarvis - Executive Vice President of Liquids Pipelines and Director

C. Gregory Harper - Director

Analysts

Brian J. Zarahn - Barclays Capital, Research Division

Sunil Sibal - Global Hunter Securities, LLC, Research Division

John D. Edwards - Crédit Suisse AG, Research Division

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Mark L. Reichman - Simmons & Company International, Research Division

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2014 Enbridge Energy Partners, L.P. Earnings Conference Call. My name is Morris, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes.

And now, I'd like to turn the call over to Sanjay Lad, Director, Investor Relations. Please proceed, sir.

Sanjay Lad

Thank you, Morris. Good morning, and welcome to the 2014 first quarter earnings conference call for Enbridge Energy Partners. This call is being webcast and a copy of the presentation slides, supplemental slides, condensed unaudited financial statements and news release associated with it can be downloaded from the Investor section of our website at enbridgepartners.com. A replay will be available later today and a transcript will be posted to our website 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 Guy Jarvis, President, Liquids Pipelines, Enbridge, Inc.; Greg Harper, President, Gas Pipelines and Processing, Enbridge, Inc.; Jonathan Rose, Treasurer; and Noor Kaissi, Controller.

Moving forward to our legal notice. This presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and the partnership's SEC filings and we incorporate those by reference for this call. This presentation also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found in the Investor section of our website.

Please turn to Slide 3. I'll now turn the conference over to Mr. Mark Maki, President.

Mark Andrew Maki

Thank you, Sanjay. Good morning and welcome. Our agenda this morning is to provide a business development update and a project execution update in addition to discussing our plans for Midcoast Energy Partners. Then our call will go to Steve to address this quarter's financial highlights.

We are very pleased with the partnership's performance in the first quarter, particularly with the strong deliveries in our mainline and North Dakota liquids pipeline systems. Deliveries in our Lakehead system reached a record high, averaging 2 million barrels per day. We expect deliveries in the Lakehead system to increase throughout 2014 as refinery expansions come online and as our market access projects enter service. Our distribution coverage will continue to strengthen, with projects entering service, increasing our cash flow and supporting our annual distribution growth target.

On the call today, we're joined by Jonathan Rose, who succeeds Darren Yaworsky as Treasurer of the partnership. After spending the last few years in the liquids pipeline organization in the business development leadership role, we are excited to welcome Jonathan back as Treasurer of the partnership. Jonathan's treasury, corporate finance and business development background will provide strong continuity to the partnership's treasury office.

Please turn to Slide 4. In early March, we announced a Line 3 replacement project together with our general partner, Enbridge Inc. This project will replace the existing Line 3 on the Canadian mainline and the Lakehead system between Hardesty, Alberta and Superior, Wisconsin with the latest in high strength steel pipe and fusion bonded epoxy coating. The United States segment of the project is expected to cost approximately $2.6 billion with the completion in second half of 2017. Our segment of the project extends from Neche, North Dakota to Superior, Wisconsin. The project's costs will be recovered through a toll surcharge using a cost-of-service methodology, which is part of the system-wide rates of the Lakehead system. Recovery of the rate base will happen over 30 years, with the primary term of the arrangement at 15 years. The U.S. portion of the project will be jointly funded by the partnership and Enbridge Inc. A special committee of the independent directors of the partnership is considering a proposal from the general partner to establish the joint funding arrangements.

The Line 3 replacement project has many benefits to the partnership and its customers. It will provide our customers with enhanced reliability and assurance of moving anticipated end of decade throughput levels on our pipeline system. The replacement also supports our #1 priority of safety and operational reliability, while delivering low risk accretive growth to our unit holders.

Let's move forward to Slide #5. The market access programs collectively underway by Enbridge and the partnership are part of the strategic initiative to match growing North American crude oil supply to respective domestic demand centers. This slide summarizes all those projects, along with the addition of our Line 3 replacement program and illustrates a year-by-year buildup of the expanded market access that our systems will provide. Through a combination of new pipeline construction and the expansion of existing pipelines, we're also strengthening our strategic position in all of our key markets.

As you can see on the map, the partnership's Lakehead system is ideally positioned to facilitate Enbridge's market access program to increase light crude oil capacity to the East, heavy capacity to the Midwest and serve markets as far south as the U.S. Gulf Coast. It is this diversity of premium markets and market optionality offered by the partnership's Lakehead system that differentiates our pipelines from those of other companies.

Please turn to Slide 6. We continue to make solid strides on project construction in delivering our growth projects. The partnership will benefit from a large phase of our Eastern Access project entering service in 2014. We are excited to begin deliveries in our Line 6B replacement project, specifically the 160-mile segment between Griffith, Indiana and Stockbridge, Michigan, which is expected later this month. This segment will bring approximately $1.5 billion of capital into service, which includes new pumps and terminal upgrades at Griffith, Hartsdale and Stockbridge.

The remaining 50-mile segment, which represents approximately $600 million of capital, is on track to be in service in the third quarter of this year. We have secured the required right of way and permitting and construction is set to commence in the near term. Once the remaining 50-mile segment is in place, it will have expanded the line of capacity from 240,000 barrels a day to 500,000 barrels per day into Sarnia, Ontario. We will discuss the capital cost updates in more detail in this section and have refined our cost estimates in a number of projects, some have increased, some have decreased, but on a net overall basis, forecast capital spend is largely unchanged.

Next, as part of our Mainline Expansion program, our Line 61 southern access pipeline expansion will increase the line's capacity by 160,000 barrels per day between Superior and Flanagan, Illinois. And that project is progressing on schedule and should enter service in the third quarter. Once these projects enter service, they'll begin delivering highly certain cash flows for a very long term, given their cost of service contract structure.

Let's move ahead to Slide #7. The substantial organic growth in the liquids side of our business, coupled with our intent to drop down the remaining interest in our gas business to Midcoast Energy Partners over the next 5 years, will shift the partnership's earnings and cash flow profile heavily weighted towards crude oil. This chart presents an unconsolidated view of the partnership's perspective contract and associated cash flow mix. This view also excludes noncontrolling interests.

As depicted on the chart, collectively, these liquids expansion projects are transformative. They will progressively move the partnership to an even lower risk business model. The long-term, low risk commercial frameworks underpinning these projects such as cost of service or take-or-pay, provide us with a high level of confidence in cash flow growth and strengthening distribution coverage.

Let's move ahead to Slide #8. In November 2013, we executed a pivotal component of EEP's funding program which involved a carve out of our natural gas business with the creation of Midcoast Energy Partners, or MEP. EEP intends to drop down additional ownership interest in natural gas business to Midcoast Partners as an additional source of capital to fund our liquids pipelines’ organic growth program. With that plan in mind, EEP is focused on executing our first IPO drop-down to MEP in the middle of 2014. And we currently estimate the range in the drop down to be between $300 million and $400 million.

Over the next few years, we expect that EEP will sell all of its gas business ownership interest to Midcoast. We see the series of drop downs as an important source of equity capital for the partnership. As earnings and cash flows from Midcoast Partners grow, we will also benefit from the perspective growth and the incentive distribution rights that we own as GP of Midcoast.

Let's move on to Slide 9. This slide presents our funding outlook through 2017. The partnership's equity funding requirements, with the addition of the Line 3 replacement program, are in our view very manageable. Our remaining equity interest needs -- or remaining equity needs over the next 4 years is quite modest. We undertook significant equity financing actions in 2013, which are benefiting us in our funding strategy in 2014 and these actions have been fully integrated in our plans.

As discussed in the previous slide, the funds to be released to the drop downs to Midcoast Partners will expand the partnership's ability to undertake a significant participation level in the Line 3 replacement. We are estimating this amount, which is, of course, subject to special committee approval, at around 50%. To that end, the drop down strategy positions the partnership to pursue this solid accretive growth project and fund the incremental capital investment.

We intend to finance the funding net of the Enbridge joint funding through additional term debt issuances. I also want to point out that this slide depicts our intent to participate in the upsize option that we have with our current -- or with our general partner to bring our ownership interest in the Eastern Access and mainline expansion projects from 25% to 40% 1 year after the in-service date of these projects. These upsize options are mutually exclusive.

Let's turn to Slide 10, and I'll turn the call over to Steve to discuss our financial results.

Stephen J. Neyland

Thank you, Mark. For the first quarter, the partnership reported adjusted EBITDA of 33 -- $338.7 million, which represents a 20% interest over first quarter 2013. Strong Lakehead and North Dakota system deliveries, complemented by full quarter contributions from growth projects that entered service in 2013 contributed to solid EBITDA growth.

First quarter adjusted net income of $102.9 million was $7.2 million higher than the same period of 2013. Higher earnings were attributable to higher transportation rates, deliveries and associated revenues from our liquids segment, partially offset by lower gross margin in our natural gas segment, due to lower natural gas volumes and NGL production.

Additionally, the increase in adjusted net income was also partially offset by the inclusion of the deferred distribution of $22.5 million relating to the preferred units issued in the second quarter of 2013 and by higher noncontrolling interest resulting from the Midcoast Energy Partners initial public offering. The main items eliminated from these adjusted results include unrealized noncash mark-to-market net gains and losses and other items noted in our supplemental slides.

Adjusted earnings per unit for the quarter was $0.20 compared to $0.21 for the same period of 2013. Higher adjusted earnings attributable to limited partnership interest were partially offset by the inclusion of the deferred distribution on the preferred units. Additionally, the increased weighted average number of units outstanding in 2014 compared to the first quarter in 2013 resulted in lower earnings per unit when compared to the prior year.

We have presented our as-declared coverage ratio, both on a cash basis and assuming inclusion of the paid-in-kind distribution, which were 1.07x and 0.89x, respectively, on a year-to-date basis. We are pleased by the strengthening of our coverage ratio and expect it will continue to strengthen as we place additional assets from our multibillion dollar organic growth program into service.

Please turn to Slide 11. The liquids pipeline segment had a solid performance for the quarter. Adjusted operating income of $205.2 million for the first quarter was $50.9 million higher than the same period for 2013 and $19.4 million higher than the fourth quarter of 2013. Over prior year, first quarter operating revenues increased due to an increase in transportation rates and higher deliveries on our Lakehead system and North Dakota systems and full quarter contributions from growth projects entering service in 2013, specifically from the Bakken pipeline expansion, Bakken Berthold Rail, Bakken Access and Lakehead system expansion projects. Higher revenues during the quarter were partially offset by increased operating and administrative expenses, higher pipeline integrity costs, increased property tax and workforce costs.

As you view the chart on the right, you can see the increasing deliveries trend on our Lakehead and North Dakota systems during the quarter. Deliveries on our Lakehead system increased to 2 million barrels per day during the first quarter, which was 4.2% higher for the current quarter over the fourth quarter of 2013 due to continued supply growth out of Western Canada, Lakehead expansion projects and refineries emerging for maintenance periods.

Deliveries on our North Dakota system improved to 245,000 barrels per day or 22% higher than the fourth quarter of 2013 as volumes transition back to our pipeline system due to tightening of crude oil differentials. Deliveries on our Ozark system increased over the fourth quarter to 211,000 barrels per day. One item of note I'd like -- within our liquids segment is our normal April 1 Terra filing adjustment will be combined with our index filing adjustment, which is typically done in June.

During the quarter, there were no changes to our total cost estimate related to the 6B -- Line 6B incident of $1.12 billion. The cumulative amount collected from the insurance recoveries is currently $547 million, and we expect to recover the balance of our aggregate liability insurance coverage of $103 million from our insurers in future periods. Cumulatively, we have spent approximately $902 million on Line 6B remediation through the end of the first quarter and have a remaining estimated liability of approximately $217 million.

Let's move forward to Slide 12. Before discussing the results, I wanted to note that during the first quarter of 2014, we revised our reporting segments. The marketing segment was combined with the natural gas segment to form one new segment called natural gas. As such, the adjusted operating income results presented on this slide have been adjusted for this change in segment reporting.

Adjusted operating income of $8.8 million for the first quarter was $18 million lower than the same period for 2013 and $4.4 million higher than the fourth quarter of 2013. The decrease in our first quarter natural gas adjusted operating income over the prior year was primarily due to lower natural gas and NGL volumes on our systems and other operating factors that I will discuss.

Lower natural gas throughput on our East Texas system was due to reduced dry gas drilling in our operating region, coupled with natural gas wells drilled but not completed. Additionally, within our Anadarko and North Texas systems, volumes were impacted by freeze-offs due to extreme weather conditions unfavorably impacting this segment by $3 million. As well, we were impacted by the previously disclosed and planned loss of a major customer on our Anadarko system. This customer loss on Anadarko system also weighed on sequential volumes.

Moving to the system-wide NGL production chart on the bottom right quadrant, here we have represented a portion of NGL production related to the recent customer loss. The key point to note is that our base NGL production continues to increase. Our natural gas marketing business benefited from strong seasonal demand and optimization opportunities for natural gas.

Please turn to Slide 13. This slide provides our 2014 capital expenditure forecast, which is estimated to be $1.7 billion and is inclusive of approximately $110 million for core maintenance. These expenditures are presented net of joint funding. We've refined our cost estimates on a number of projects. Some have increased, some have decreased, but on a net basis, our overall capital spending forecast is unchanged. As a result of more detailed engineering estimates, coupled with issues related to ground terrain conditions, the expected capital cost of the Eastern Access Line 6B replacement project increased. However, this was largely offset by a decrease in estimated costs associated with the mainline expansion projects.

At the end of the first quarter, we had approximately $2.4 billion of available liquidity. The partnership now has $3.175 billion of credit facility capacity to provide enhanced financing flexibility as we execute on our organic growth program. We continue to be committed to maintaining our strong investment-grade credit rating.

Please turn to Slide 14. I'll now turn the call back over to Mark for his closing remarks.

Mark Andrew Maki

Okay, thank you, Steve. Just a few points of emphasis in closing. First, we're very pleased with the strong performance for our liquids pipeline systems this quarter. We expect the results for our liquids segment to continue to strengthen as Lakehead system deliveries increase throughout 2014 and refinery expansions come online and Enbridge and the partnership's market access projects enter service. The partnership's distribution coverage is improving, increasing distributable cash flow and provide momentum to achieving our 2% to 5% annual distribution growth target. To complement our funding needs, we expect EEP to execute a further drop down of ownership interest in our natural gas business to Midcoast Partners by mid-2014.

Management remains very strong in its view that the long-term outlook for the partnership remains secure, especially if we adhere to our and execute our strategic plan. We believe this will result in visible long-term, low risk accretive cash flow growth to our unit holders.

Now I'll turn the call over to the operator for Q&A. So Morris, if you could please open the lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] We do have your first question and that comes from the line of Brian Zarahn with Barclays.

Brian J. Zarahn - Barclays Capital, Research Division

Appreciate your view on how you see the new safety regulations on rail in Canada. We'll see some new regulations in the U.S., and obviously of the recent derailment in Virginia. How do you think the landscape impacts your pipeline system, Lakehead and Bakken, specifically?

Mark Andrew Maki

Let's start with Guy Jarvis on that one. So maybe Guy, you want to field that question?

Guy D. Jarvis

Sure. Thanks. I think I'll attack it from 2 points of view. The first point of view would be in terms of the North Dakota system and our mainline system, we're already seeing improved and strong performance on those where some of the barrels that, throughout last year were leaving the system, are finding their way back. So to me, that's a combination of a number of things. It's the improvement in the differentials which is a clear fundamental driver. I think the impact as it comes to rail regulation is we're sensing that we're seeing some volumes come back to our system, particularly in North Dakota, so that shippers can preserve the historical nominating rights. And we think that is in part driven by some of the uncertainty as to what this new regulation is going to mean for the rail industry. So we continue to expect to see that get better and better on our existing system as we later in the year bring in the full Eastern Access and the Line 9B reversal, which is providing access to more and better light crude oil markets. In terms of the Canadian ruling and the impacts on that, the sense that I have is that the Canadian crudes that are moving by rail, I think, are not finding their way into that same packing group that the Bakken would. So I think the regulations that have been announced here in Canada in terms of movements of Canadian crude by rail, I haven't got the sense that it's going to be a dramatic impact.

Brian J. Zarahn - Barclays Capital, Research Division

Okay, I appreciate the color. I'm sure also the delay in the Keystone XL doesn't hurt your Lakehead system either. I guess any update to your guidance for 2014, either from operating income or distribution coverage, or is it similar to your previous guidance?

Mark Andrew Maki

Yes, Brian, it's Mark. There's no change to our guidance.

Operator

And your next question comes from Sunil Sibal with Global Hunter Securities.

Sunil Sibal - Global Hunter Securities, LLC, Research Division

Couple of questions related with the MEP drop downs. So just wanted to confirm the timeline is still completing the drop downs through 2017. Is that correct?

Mark Andrew Maki

We would like to -- the number of years, we'll spread it out over is probably 4 to 5 years. It really depends upon the EEP capital needs. Greg's got lots of things he's going to be doing with Midcoast and -- so trying to manage that as well. But certainly, we expect -- the first drop down is targeted, as we said in the call here, for the middle of this year. And that's the first gate to hit.

Sunil Sibal - Global Hunter Securities, LLC, Research Division

Okay. And then that $2.6 billion funding number that you have from the MEP drop downs, was wondering if you could just talk a little about what are some of the variables which kind of move that number up or down as you execute these drop downs.

Mark Andrew Maki

Sure. I mean, obviously, the multiple at which the drop down would happen would be one, what's the -- how does the underlying business look over time as the drop downs happen. So in other words, the shaping of the cash flows and the underlying business. Those are kind of -- some of the critical things. And then if you want to peel the onion a little further, what's happening with commodity price, as Greg develops the business out, is it around the existing footprint or is it off the existing footprint, that kind of thing.

Sunil Sibal - Global Hunter Securities, LLC, Research Division

Sure, that's helpful. And then if I just wanted to kind of quantify that a little bit in terms of the range, would you say $2.6 billion plus/minus 10% is what you would be targeting if you just want to bracket it a little bit better?

Mark Andrew Maki

We're pretty -- there's a range around that number, and I hate to put a plus or minus 10% on it. Just I think there's enough. There could be reasons we want to accelerate it, there could be reasons you want to slow it down. So just it's hard to say with a great degree of precision. We're fine with the $2.6 billion as kind of a number to lever around, but I hate to put an upper cap and a lower cap on it.

Sunil Sibal - Global Hunter Securities, LLC, Research Division

Okay. That's fair. And then on the -- lastly on the 14 -- Line 14 hydro test expenditure, I think you guys talked about that in the last couple of calls. And I was kind of curious how should we think about that going forward? Are there still kind of benefits from the project? Or is it kind of built into a rate base going forward?

Mark Andrew Maki

The way we've recovered the costs of the Line 14 hydro test -- largely, it's been recovered through the toll filing last year. It's still effectively in the toll that Lakehead is charging today. So there will be some kind of true-up of that when we do our -- probably our next filing. So it is the cost -- has been included in rates or recovered through rates, and it should be -- as it relates to Line 14 or other lines, our hydro system is not our preferred method of testing integrity lines. We prefer to use internal inspection tools, Hydro testing, though, has its place. Maybe we let Guy expand on the answer a little further if he wants to. But that's -- costs have been recovered. Wouldn't expect that to be a recurring kind of event on the system. We use in-line inspections as kind of our primary means of testing the integrity of pipelines. Maybe Guy, anything else you want to add?

Guy D. Jarvis

No, nothing -- no, I've got nothing to add to that, Mark, other than to just reinforce that the pressure restrictions were lifted and we're back operating at the levels that we had anticipated.

Sunil Sibal - Global Hunter Securities, LLC, Research Division

Okay, then. That's helpful. Then just lastly, in terms of the operating and administrative costs on the liquids segment, how should we think about that going forward? Of course, you had some variability there in the last few quarters from the Line 14 work. Now going forward, is what you've reported in the first quarter, is that a good kind of a base rate for the rest of the year or do you sense some variabilities there continuing?

Stephen J. Neyland

Yes. Hey, Sunil, this is Steve Neyland. So a couple of things there. One, you're right. As you look back over the last couple of quarters, the hydro tests costs have been in there. When you look at Q4 or Q3 of last year, we had approximately $56 million, $57 million of costs running through our numbers that we called out as unusual, and then we get that through our tolls, so some timing differences there. So we don't expect that. Within our numbers for the current quarter, they're higher because we brought more assets into service. Our operating costs are typically lumpy. One thing to call out within our numbers be in our 10-Q disclosures, we had a issue at Griffith where we had a terminal leak. Oil's been picked up there or substantially picked up, and that's about $4.4 million unfavorable within our numbers. So that's -- would be considered kind of a one-time event that's within our operating costs, as well as you put these projects into service, one of the things that comes along with that is higher property taxes. And so that's something that is a variable in our numbers. We record large elements of that within our toll structure, but it does create some variability in the costs. So again, more assets in service, new costs are going to go up associated with that and then just a few one-time events to call out in there are going to be the hydro test -- not this quarter but prior quarters, and then the Griffith terminal issue for $4.4 million.

Operator

[Operator Instructions] And your next question comes from John Edwards with Crédit Suisse.

John D. Edwards - Crédit Suisse AG, Research Division

Just a minor one here. Just on the allowance for funds you used during construction, what's a reasonable assumption to think about kind of going forward?

Mark Andrew Maki

Well, that one, John, you may have stumped us. I'll have to get back to you as first running, but as you spend more money or you put capital, we've got -- as capital goes in the ground, not necessarily in service, you'd apply the cost of equity and cost of debt weighted basically against that capital that's -- you're not, not productive yet. But as far as the trend to that, we would have to beg that one off for the time being.

Guy D. Jarvis

And John, just to clarify on your question, you're looking for run rate kind of...

John D. Edwards - Crédit Suisse AG, Research Division

Yes, just thinking kind of a -- yes, just kind of a run rate there to try to navigate.

Guy D. Jarvis

Yes, more assets going into service. Many of these will have an AEDC element associated with them. So it would be increasing in future periods likely.

John D. Edwards - Crédit Suisse AG, Research Division

I can follow-up on that. That's all I had.

Operator

And your next question comes from Sharon Lui with Wells Fargo.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

I just want -- Slide 13 shows, I guess, the shift in CapEx spending, but maybe if you can go over, I guess, the material changes in total costs for your major liquids projects and if that has any impact on, I guess, the expected returns?

Stephen J. Neyland

Hey Sharon, this is Steve. I'll take a shot at that. So -- and what will be helpful, I think, is when we file, there'll be even more detail in our quarterly financial statements and we've got full project costs in there. And so you can line those up against -- in our K. And what you'll see in there -- effectively, there's -- the increase is Eastern Access, so we're seeing approximately $300 million increase in our Eastern Access Phase 1 and Phase 2 projects, and then as it relates to our U.S. mainline expansions and some of the additional Eastern Access projects, we're seeing reductions of approximately $150 million. So net-net, we're up about $150 million from one period to the other, and again, that's over a significant capital base. And again, those are at 100% from project costs and both Eastern Access and U.S. mainline expansion are 25% owned by EEP. So you have to take that $150 million and then multiply it by the 25%, so you're around about $40 million impact directly to EEP.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay, so no -- but no change in Sandpiper or in the other projects?

Stephen J. Neyland

That's correct. The Line 3 Sandpiper which are significant project construction items, there's no change to those.

Mark Andrew Maki

You had one other subpart to your question we'll try and get, but we can't get real specific with numbers, but you got a little bit of additional capital in the EA. That effectively could get additional return on -- some of that, EEP has to share with the customers, but the rate base effectively eats earning -- got a little bigger, but your effective return would go modestly down because some of the capital would not be -- would be shared effectively with the customer. And on the other expansions, again, you're going to get basically the same return on a little bit different capital base.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And I guess based on the Q1 performance, what are the current thoughts in terms of resuming distribution growth this year?

Mark Andrew Maki

Nothing inconsistent with what we said at Enbridge days that we would be certainly desirous of us to resume distribution growth this year. We don't necessarily have to back at one. To do that, it's really a function of how we see the long term for the business. So it would be disappointed if we went out this year without doing that, but it's a decision we'll make later on in the year.

Operator

Your next question comes from Mark Reichman with Simmons Company.

Mark L. Reichman - Simmons & Company International, Research Division

Just really 2 questions, just update. First on the Line 67, the delays in securing the amendment to the Presidential border crossing permit, I wonder if you can just discuss that a little bit. I mean what you see as kind of the challenges surrounding that and whether you think that 3Q 2015 date is still good for the expansion to go into service? And then second, a real nice rebound in volumes on the North Dakota system this quarter, and I was just wondering if you could kind of talk a little bit about the dynamics there and whether that has translated or followed on to commitments to the Sandpiper projects, if anything's changed there?

Mark Andrew Maki

Guy, you got all those parts, but certainly on the AEDC [ph].

Guy D. Jarvis

Yes, let me start with the Line 67 and the Department of State process. So obviously, all of these regulatory processes are taking longer today than they have historically and this one has surprised us in terms of the length of time that it's taken to get us to the point in time where we're at. But where we're at right now is that we see that process moving and when we -- when our major projects guys map out the timelines and associated steps that are required by the Department of State kind of from where we're at today to where we think we need to be, we can still see that, that process will deliver the permit by Q3 of next year. And we're remaining fully engaged in trying to provide the information and support that they need to make that type of determination. So at this stage of the game, we still are confident given a look at that timeline that it'll be there, and we're proceeding as if it will be. In terms of the North Dakota dynamic, I think it's -- as I mentioned earlier, it's a combination of better differentials, concern about what the implications of further rail regulation will mean, and then a desire to preserve their historical nominating rights on the system. So it's kind of that combination that's really brought the volumes back strongly. In terms of the longer-term impact on Sandpiper, we haven't really seen that. We've got our anchor customer. We've picked up a bit more through a subsequent open season. We're very confident in terms of the underpinnings of that project and more confident now that the incremental capacity that will be available on a spot basis on that system is likely to be utilized.

Operator

And your next question comes from Ross Payne with Wells Fargo.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

I was wondering if you could give us a little bit more color on what was driving the $300 million Eastern Access cost increase.

Mark Andrew Maki

Sure, I'll take a crack at that, but the construction encountered certainly, conditions that were much more challenging than expected. Obviously, this corridor we're very, very familiar with. We operate a pipe in it already, but it was the -- a lot of rain and basically dewatering the trenches, having to shore the trenches up where the construction was underway. It just added a lot to the challenge. There were some workarounds that had to take place. And then finally, it's just as you kind of did the work on the first part -- refining engineering estimates on the work that needed to be done on the rest. So -- but that would be kind of the typical stuff you might run into, just challenges on the construction side that were not anticipated. Conditions on the ground basically were [indiscernible].

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Okay. And then on the natural gas side, do you guys see any kind of turnaround there? Are you seeing any rigs going back to work? And in North Texas, I always think about that as being a bit more liquid focused. I assume that drop-off was due to the loss of the customer?

C. Gregory Harper

Yes. Hey, this is Greg, how are you doing? Hey, Ross. So one thing we track to -- and yes, we're seeing rigs increase a little bit, more so on the well completions, on wells that already been drilled but have been kind of in inventory for the producers. And now with gas prices, even on the prompt month jumping in favorable territory, you'll see some of those get completed quicker. But we also filed permits and in each of our areas, we have seen an uptick over the last 4 months, increasing trend on permitting activity. So that's what we like to see as well. The other thing is in some of the areas that a producer may have moved wells out of an area or has been less active in, some of those areas have been sold to other producers and we're starting to get the drilling plans from the new producer that bought it. So yes, as I said on the call yesterday, we see the deal in the first quarter being kind of the bottom relative to that episode, and again, not saying the prices drop to $2. You'll see some bad stuff happen, but I think where the gas prices are today and the current forward look, we feel pretty confident that [indiscernible] an increase. I was going to say on your North Texas point that you're spot on. The issue with the North Texas is that all volumes aren't created equal. So we were seeing less gas volume but higher liquid content. So that's also a little bit of an issue that we saw and you see in our numbers on the third, fourth and first quarter as you see the trend on the volumes actually decreasing but the liquids production kind of staying level to increase a tad bit.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Okay. And Greg, can you give us any color on what drove the loss of that one customer that probably had some pretty big volumetric issues for you guys?

C. Gregory Harper

Yes, yes. I know this was disclosed during their S1 period and the roadshow stuff, but Ross, you'll hear me talk and the employees here have already heard me talk me about controlling the first mile and the last mile. I think I said that at MEP day as well -- M-E-P day. This particular customer was attached -- their own gathering lines to our control points, which made us kind of susceptible to being picked off, so we were picked off. And so I'd like to do more gathering to the wellhead, it's kind of our mission in life going forward.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Okay. All right. And then switching over to the Bakken real quick, people were wanting to preserve their nominations. Is that kind of a onetime event in your view or do you think this goes on for several quarters and we can expect volumes to stay close to where they are today?

Mark Andrew Maki

Guy, you want to field that, please?

Guy D. Jarvis

Sure, I think as it relates specifically to the nominating history, you do have to continue nominating month after month after month to continue to preserve your history. So to the extent that volumes are coming back to the system to preserve their nominating history, we would expect them to stay. Beyond that, it's really one of looking forward to later in the year where we're providing expanded access to these stronger priced light oil markets where we think that's going to also provide strength for the volume staying on the system.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Okay. And one final question, just so I'm clear, what project or projects require presidential permit at this point?

Mark Andrew Maki

The only presidential permit-ish matter that we have that's been managed is the expansion of Line 67 from 450,000 barrels up to 800,000 barrels a day. We have an existing presidential permit that is volume limited at 400 -- the initial volume limited at 450,000. So we need an amendment to raise the volume on that.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Okay, all right. And that's the timeline you were discussing earlier that you thought you would get, right?

Mark Andrew Maki

Correct.

Operator

I would now like to turn the call over to Sanjay Lad for closing remarks.

Sanjay Lad

Great. Well, we appreciate everyone joining our call this morning. I would like to remind you that I will be available for any follow-up questions you may have throughout the day. Thank you, and have a great day.

Operator

Thank you. This concludes your presentation. You may now disconnect, and good day.

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