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

Q2 2014 Earnings Call

July 31, 2014 5:00 pm 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

Jonathan Rose -

Analysts

Brian J. Zarahn - Barclays Capital, Research Division

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

John D. Edwards - Crédit Suisse AG, Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Louis Shamie

Operator

Very good day, ladies and gentlemen. Thank you, all, for joining, and welcome to the Second Quarter 2014 Enbridge Energy Partners L.P. Earnings Conference Call. My name is Lisa, and I'll be your coordinator for today. Today's conference call is being recorded. [Operator Instructions] .

Now I'd like to turn the conference over to Mr. Sanjay Lad, Director of Investor Relations. Please go ahead, sir. Thank you.

Sanjay Lad

Thank you, Lisa. Good afternoon, and welcome to the 2014 Second 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 Investors section of our website at enbridgepartners.com. A replay will be available later today and a transcript will be posted shortly tomorrow morning.

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, President, Liquids Pipelines, Enbridge, Inc.; Mr. Greg Harper, President, Gas Pipelines and Processing, Enbridge, Inc.; Mr. Jonathan Rose, Treasurer; and Ms. Noor Kaissi, Controller.

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 news release and the Partnership's Annual Report on Form 10-K and other SEC filings, and we incorporate those by reference for this call. This presentation also contains certain non-GAAP financial measures. The reconciliation schedule for these non-GAAP measures to comparable GAAP measures can be found in the Investors section of our website.

Please turn to Slide 3. I will now turn the call over to Mr. Mark Maki, President.

Mark Andrew Maki

Thank you, Sanjay. Good afternoon, and welcome everybody. As usual, I'll provide an update on recent developments in addition to discussing the Partnership's strategic outlook before passing it along to Steve to address the second quarter financial highlights.

We are pleased to announced a 2.1% distribution increase over the prior quarter. Our annual cash distribution rate will increase to $2.22 per unit, or $0.555 per unit on a quarterly basis.

The Partnership has several noteworthy highlights to recognize in the second quarter. First, deliveries in our Lakehead system reached a record high averaging close to 2.1 million barrels per day. We expect deliveries in our Lakehead system to progressively increase in the second half of 2014 as refinery expansions ramp up and our market access projects enter service. Our distribution coverage will continue to strengthen with projects entering service, increasing distributable cash flow as we go throughout the year.

June, we announced an equity restructure transaction, whereby our general partner agreed to reduce the Partnership's prospective incentive distribution tier and exchange its existing IDRs for a new class of limited Partnership units.

Next, we will continue to make tangible progress on project execution. We completed a large component of our Eastern Access pipeline program during the second quarter, placing into service approximately $1.5 billion of capital.

Lastly, we finalized our first dropdown sale of an additional ownership interest in our jointly owned natural gas business to Midcoast Energy Partners.

Collectively, these highlights provide the Partnership with strong momentum as we head into the second half of 2014, and position us to deliver on our plan.

Please turn to Slide #4. The equity restructure we recently announced is a very important transaction for Enbridge Partners. Our general partner permanently waived their existing incentive distribution rights, or IDRs, in exchange for Class D units and new incentive distribution units, or IDUs. The new Class D units are limited partner units, and will be entitled to cash distributions equal to those of the Partnership's Class A common units.

After July 1, 2014, the holders of the IDUs will receive a 23% portion of any cash distributions in excess of the quarterly cash distribution rate of $0.5435 per unit. General partner interest of 2% remains unchanged. With the single-tier IDR structure, prospectively, the limited partner unit holders will receive a 75% share of distributions in excess of $0.5435 per unit.

There are some overarching prospective benefits to the Partnership from these changes. The equity restructure will provide EEP's or improve EEP's cost of capital, as the general partners' share of future distribution increases will be lowered. The equity restructuring is expected to enhance the economics of the Partnership's investment projects and increase cash flow available for distribution to public unit holders from existing as well as future growth projects.

The improved cost of capital will enhance the Partnership's acquisition competitiveness. This equity restructuring, again, just demonstrates Enbridge's commitment to the financial success of the Partnership. Enbridge's objective is to reestablish the Partnership as a strong, sponsored investment vehicle, and position EEP as a future dropdown vehicle for liquid pipelines assets.

Let's move on to Slide #5. The equity restructuring transaction will result in a greater proportion of cash flows being available for distribution to public unit holders from the exiting capital projects, as well as from future growth projects. This will provide momentum for the Partnership to accelerate their distribution growth profile in future years. This slide includes our intent to exercise the upsize options that we have with our general partner to bring our interest in the jointly funded Eastern Access and Mainline Expansion projects from 25% to 40% one year after the in-service dates of these projects, which are targeted to begin service by early 2016. These initial dropdowns position the Partnership to deliver the higher end of our 2% to 5% annual distribution growth target.

Please move ahead to Slide #6. Turning to project execution. We continue to make solid strides in project construction and delivering our growth projects. We commenced deliveries in our Line 6B replacement project, specifically the 160-mile, 36-inch diameter pipeline segment between Griffith Indiana and Stockbridge, Michigan on May 1.

This segment represents approximately $1.5 billion of capital going into service, and includes new pumps and terminal upgrades at Griffith, Hartsdale and Stockbridge. The remaining 50-mile, 30-inch diameter pipeline segment, which represents another $600 million of capital, is on track for in-service early fourth quarter of this year. Construction is proceeding on schedule with Mainline pipe welding and pipeline tie-ins underway. Once the remaining 50-mile segment is in place, we'll expand the line's capacity from 240,000 to 500,000 barrels per day into Sarnia, Ontario.

Next, as part of our Mainline Expansion program, our Line 61 southern access pipeline expansion, which increases the line's capacity by 160,000 barrels per day between Superior and Flanagan, Illinois is proceeding on schedule and should enter service in the third quarter.

Looking ahead to 2015. We expect the second phase of our Mainline Expansion projects to enter service, which will effectively expand Enbridge and the Partnership's pipeline quarter from Western Canada to Chicago with additional pump stations on Lines 67 and 61. Collectively, the long-term, low-risk commercial frameworks underpinning our organic growth program, such as cost to service and take-or-pay, provide us with a high level of confidence in progressive, distributable cash flow growth and strengthening distribution coverage.

Let's move ahead to Slide #7. The market access programs collectively underway by Enbridge and the Partnership are part of the strategic initiative to match the growing North American crude oil supply to the respective domestic demand centers. This slide summarizes all those projects 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 are also strengthening our strategic position in all of our markets.

As you can see on the map, the Partnership's Lakehead system is ideally positioned to facilitate Enbridge's market access program, increase light crude oil capacity in the East, increase heavy capacity to the Midwest and serve markets as far south as the U.S. Gulf Coast. As our market access programs enter service, they are expected to progressively increase the utilization of the Partnership's Lakehead system. The downstream pull from the parent's Flanagan South and Line 9B reversal projects is expected to bolster deliveries on Lakehead.

As it relates to Sandpiper, one of our key projects in North Dakota, during the second quarter, the Federal Energy Regulatory Commission, or FERC, granted approval of our petition for a declaratory order regarding the project's tariff structure. Additionally, in early July, the North Dakota Public Utilities Commission, or PUC, provided pipeline and facilities construction in that state -- or approved construction in that state. We are pleased with the regulatory progress to date on Sandpiper, and expect the project to enter service in early 2016.

Moving ahead to Slide 8. We completed our first dropdown sale of additional ownership interest in our jointly owned natural gas business to Midcoast Energy Partners, or MEP, since MEP's IPO. MEP agreed to purchase an additional 12.6% LP interest in Midcoast for $350 million effective on July 1, 2014. EEP's ownership in Midcoast's operating subsequent to transaction is now 48.4%.

We are excited that closing the transaction was in line with our accelerated timeline for 2014, and EEP will optimize the size and timing of future dropdowns to meet the mutual objectives of Enbridge Partners and Midcoast Partners.

The MEP dropdown strategy is an integral component of our financing program as we expect to provide significant funding for EEP's attractive liquids pipelines growth projects, and will substantially satisfy our equity capital requirements.

Let's move ahead to Slide 9. I'll turn the call over to Steve to discuss our financial results.

Stephen J. Neyland

Thank you, Mark. For the second quarter, the Partnership reported adjusted EBITDA of $362.3 million, which represents a 27% increase over the second quarter of 2013.

Record Lakehead and North Dakota system deliveries complemented by the in-service of Phase I of our Eastern access Line 6B replacement project on May 1 contributed to solid EBITDA growth.

Second quarter adjusted net income of $107.1 million was $32.4 million higher than the same period in 2013. Higher earnings were attributable to higher transportation rates, increased deliveries and associated revenues from our liquid segment, partially offset by lower gross margin in our natural gas segment due to lower natural gas volumes and NGL production on our natural gas systems. 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 second quarter increased to $0.21 compared to $0.13 for the same period of 2013 due to higher adjusted earnings attributable to the limited partner interest.

We have presented our as-declared coverage ratio both on a cash basis and assuming inclusion of the paid-in-kind distribution, which were 1.05x and 0.88x, 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 multi-billion organic growth program into service.

Please turn to Slide 10. The liquids pipeline segment had another strong performance in the second quarter. Adjusted operating income of $232.8 million for the second quarter was $64.9 million, or 39% higher, than the same period for 2013. And $27.6 million, or 13% higher, than the first quarter of 2014.

Over prior years, second quarter operating revenues increased due to an increase in transportation rates and higher deliveries on our Lakehead and North Dakota systems. Additionally, on May 1, we placed into service a large component of our Eastern Access program, specifically the 160-mile segment of our Line 6B replacement project, which contributed to the increase in revenues during the quarter.

Our second quarter 2014 operating revenues were impacted by a $19 million decrease as a result of our regulatory accounting true-ups related to Lakehead toll revenues. This decrease was largely attributable to an overcollection of revenues related to the system II expansion -- system expansion II surcharge, which expired at the beginning of April. Due to the delayed Lakehead toll filing that I will discuss in detail shortly, we overcollected revenue during the second quarter at the 2013 rates that we collected on the contained provisions that were not applicable under the newly negotiated agreement for Line 14.

The higher revenues during the quarter were partially offset by increased operating and administrative expenses. As you view the chart on the right, you will see the increasing deliveries trend on our Lakehead and North Dakota pipeline systems during the quarter.

Deliveries on our Lakehead system reached a record 2.09 million barrels per day during the second quarter. Strong deliveries were driven by continued supply growth out of Western Canada, Lakehead expansion projects and refinery expansions ramping up.

Deliveries on our North Dakota system improved at 314,000 barrels per day come as volumes transitioned back the -- to our pipeline system due to tightening of crude oil differentials. Collectively, total liquids system deliveries increased approximately 29% over the same period from the prior year.

As discussed last quarter, our April 1 Lakehead system tariff filing was delayed as we were in negotiations with our shippers concerning certain components of the tariff rate structure. Historically, we have made the Lakehead system annual tariff filing adjustment for the Facilities Surcharge Mechanism, or FSM, component of the rate with an effective date of April 1 and the index rate with an effective date of July 1.

On June 27, 2014, we filed for an increase in our Lakehead system rates with an effective date of August 1, 2014. This filing included the following: an increase in rates in compliance with the index rate ceilings allowed by the FERC, which represents a 3.9% increase; annual tariff rate adjustment for the FSM components on our Lakehead systems, which include our projected cost for 2014 and true-ups for the difference between our estimated actual cost for 2013; increase the return on equity allowed for recovery for certain FSM projects; eliminated the System Expansion II, or SEP II surcharge, which had expired and added it to the cost of service FSM to enable the recovery of costs for Line 14, including the recovery of agreed upon legacy integrity and agreed upon future integrity cost; lastly, the increased rates included recovery of cost related to the 2014 Eastern Access and mainline expansion projects, which are currently or will be in service later this year.

During the quarter, we increased our total cost estimate related to the Line 6B incident by $35 million to a total cost of $1.157 billion. The cost increase during the second quarter is primarily related to the finalization of the Michigan Department of Environmental Quality approved schedule of work for the remainder of 2014 and other costs related to the ongoing river restoration activities. Additionally, work from the EPA's submerged oil recovery and assessment plan is being completed as we finish dredging in and around Morrow Lake and its delta.

Through the end of the second quarter, cumulatively, we have spent approximately $926 million on Line 6B remediation, and had a remaining estimated liability of approximately $224 million. The cumulative amount collected from insurance recoveries is currently at $547 million, and we expect to recover the balance of our aggregate liability insurance coverage of $103 million from our insurers in future periods.

Let's move forward to Slide 11. Adjusted operating income of $7.7 million for the second quarter was $8 million lower than the same period from 2013 and $1.1 million lower than the first quarter of 2014. The decrease in our second quarter natural gas adjusted operating income of a prior year was primarily due to lower natural gas and NGL volumes on our systems and other operating factors. Lower natural gas throughput on our East Texas system was due to reduced dry gas drilling activity in our operating region coupled with delayed well completions. Additionally, our Anadarko region experienced reduced drilling activity. Anadarko was also impacted by the previously disclosed customer loss, which weighed on sequential volumes.

Moving to the system-wide NGL production chart on the bottom right quadrant. The key point to note is that after accounting for the recent customer loss, our base NGL production continues to increase.

While volumes in the second quarter of 2014 were lower than the comparable period in 2013, management believes that volumes have stabilized, as volumes increased month-over-month in the second quarter of 2014. Management expects this trend to continue through the balance of 2014.

Please turn to Slide 12. In February, we provided full year 2014 adjusted EBITDA guidance of $1.5 billion to $1.6 billion. We remain confident in achieving our guidance for 2014. First half 2014 adjusted EBITDA was $701 million. Looking forward to the second half of 2014, we expect a ramp in adjusted EBITDA as compared to the first half of 2014, which is the result of projects placed into service, as well as continued increase in volumes.

As Mark discussed earlier, we placed into service a large component of our Eastern Access Line 6B replacement project on May 1, and are on track to place the remaining section of the Line 6B replacement project in service early in the fourth quarter. Additionally, as part of the Mainline expansion program, our Line 61 southern access pipeline expansion is expected to enter service during the third quarter.

Collectively, these projects are expected to provide significant growth in EBITDA and cash flows for the Partnership in the second half of the year.

We expect deliveries on our Lakehead system to progressively increase in the second half of 2014 as Enbridge and the Partnership's market access projects enter service, specifically the second phase of our Line 6B replacement, the line 9 reversal to Montréal and the Flanagan South pipeline.

In addition to the expected volume increase on our Lakehead system, our rates will be higher as a result of the Lakehead tariff filing that will be effective on August 1. For example, this tariff filing increased the transportation rate for heavy crude oil movements from the Canadian border to Chicago, Illinois by approximately $0.32 per barrel to approximately $2.49 per barrel. We expect operating and administrative expenses related to our Liquids business to increase in the second half of 2014 over the first half due to the seasonality of repairs and maintenance and integrity cost.

Let's move forward 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 of maintenance capital expenditures. These expenditures are presented net of joint funding. At the end of the second quarter, we had approximately $2.1 billion of available liquidity.

On July 3, 2014, we amended our 364-day credit facility to extend the termination date to July 3, 2015 and to decrease the aggregate commitments under the facility by $550 million. This adjustment is an effective rightsizing of the EEP liquidity requirements. Additionally, we continue to be committed to maintaining our strong investment grade credit rating.

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

Mark Andrew Maki

Thank you, Steve. Just a few points and emphasis in closing. First, we are pleased with the strong performance of our liquids pipeline systems during the first half of 2014. We expect deliveries in our Lakehead system to further increase and deliveries in our North Dakota system to remain strong in the second half of 2014. As well, we are pleased to see volume stabilization in our jointly owned natural gas business. Distribution coverage will continue to strengthen as our liquids projects enter service and deliver highly certain stable cash flows over the long term.

The partnership's expected equity funding needs are modest through 2017 as the MEP dropdown strategy largely defrays our near-term equity requirements. EEP will optimize the size and timing of future dropdowns to meet the mutual objectives of EEP and Midcoast Partners.

Finally, the equity restructuring transaction is another example of how Enbridge is strategically aligned and invests with and in the Partnership. Improving EEP's prospective cost of capital provides a catalyst to enhance the accretion from our liquids pipeline investment projects, and positions the Partnership to deliver the higher end of our 2% to 5% annual distribution growth target in the 2017 timeframe.

Reestablishing the Partnership as a strong, sponsored investment vehicle as a key objective of Enbridge, and will generate momentum for Enbridge to use EEP as a dropdown vehicle over the long term.

I'll now turn it over to the operator for Q&A. Lisa, can you please open the lines for questions?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Brian Zarahn of Barclays.

Brian J. Zarahn - Barclays Capital, Research Division

So you had a good volume growth, obviously, in your liquids business. What's your outlook for your North Dakota volumes for the remainder of the year?

Mark Andrew Maki

I'm turn that to Guy Jarvis, since he's sitting across the table from us, and let Guy comment on that.

Guy D. Jarvis

Thanks, Mark. Actually, we think they're going to continue to be strong. What we've seen on our system in North Dakota is that the nomination practice there is based on historical throughputs and volumes. And as shippers and producers in the region have become a little bit more concerned about the emerging issues around rail transportation, we've seen them come back to the pipe quite strongly to ensure that they are preserving their historical nomination rights and their rights to access capacity going forward. So we expect to see the strength that we saw in Q2 extend through the balance of the year.

Brian J. Zarahn - Barclays Capital, Research Division

Staying in the Bakken, what are your thoughts about recently announced competing Bakken pipeline project? And any implications for Sandpiper?

Guy D. Jarvis

We don't really have a -- see too many implications for that, as it relates to Sandpiper. You'll recall Sandpiper's got a very large anchor shipper, who has also become a partner in the project with us. So we've got a lot of stability in terms of the contracts and the revenues there. In addition, when we look at our programs taking barrels East into Patoka and farther out to Line 9 with our Line 9 reversal, we view that the markets we offer represent the most attractive netbacks to the North Dakota producers. So we think we're going to be in very good shape there.

Mark Andrew Maki

Probably another comment maybe to add on to that, Brian, is just there's still a lot of rail to be displaced. And so that may be one of the things that the other 2 proponents are targeting.

Brian J. Zarahn - Barclays Capital, Research Division

Fair enough. I guess you have, again, obviously, good visibility with your projects coming online for the ramp-up in EBITDA. How do you view distribution coverage perhaps going into next year?

Mark Andrew Maki

We expect that -- we've commented on this before that we will have a little bit of a transitional period. Really, the largest component of our capital begins to come into service in 2016. And so we're perfectly fine with bouncing around the 0.9, 0.95, 1 kind of coverage ratio over the next little while. And -- but then, we expect after that, our coverage ratio would improve significantly. So that would be as much detail as I want to provide on that now, Brian.

Brian J. Zarahn - Barclays Capital, Research Division

Okay. And last one for me, can you repeat what Steve said what the Line 6B cost is? Was that $1.1 billion now? Or what's the total?

Mark Andrew Maki

$1.157 billion is the total cost. And I believe...

Stephen J. Neyland

A $35 million increase from what was there last quarter, Brian.

Brian J. Zarahn - Barclays Capital, Research Division

$1.157 billion.

Operator

Our next question is from the line of more Mark Reichman of Simmons.

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

Just a couple of questions. First, I wanted to talk a little bit about some of the regulatory developments. And some of this may kind of straddle EMB and also EEP, but recently, there was the filing with the FERC that was seeking an order to allow Enbridge to establish a new receipt point on the Lakehead system at Flanagan. And then, I think there was also a mention in there about the possibility of an affiliate of Enbridge building a rail unloading terminal. And I was just wondering if you could maybe just discuss that filing a little bit, what the customer implications and/or reactions have been to that filing and what your expectations are for a decision. I think that the request was by the end of August.

Mark Andrew Maki

Guy, take it.

Guy D. Jarvis

Yes, so the request -- both of those are, obviously, linked to the Flanagan South pipeline that is under construction, and will be coming into service here in the fourth quarter. So the interconnection is obviously to facilitate deliveries off the Lakehead system into Flanagan South. In terms of the rail facility, one of the things we're looking at is -- and that's -- the rail facility is really in relation to the situation in Western Canada, where there is growing crude oil volumes and not enough pipeline capacity to get it out of Alberta for a 2 or 3 year period. So one of the things we're looking at doing is constructing a rail unloading facility that would allow Western Canadian crudes to go by rail to Flanagan, be offloaded and then flow down the Flanagan South pipeline further into seaway and to the Gulf.

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

Okay. And the new receipt point, that would just be for periods when the upstream pipeline is in apportionment, right?

Guy D. Jarvis

That would be the ideal intent, yes.

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

What's been the reaction for customers?

Guy D. Jarvis

Well, the reaction on the producing side is favorable because they're looking at all avenues to get their barrels out of market. The reaction has been favorable from both firm and potential spot shippers on the Flanagan south pipeline, again, because it provides them access to the barrels. So we haven't had -- we've had no negative feedback that I'm aware of from any corners at this point.

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

I see. Okay. And then, on the guidance. The guidance was relatively unchanged from last quarter. It looked like things are on a positive trajectory, certainly very good volumes on the Lakehead and North Dakota system. Just looking, I mean, just looking at the guidance, it seems like that at this point, you're pretty much well on your way and you do have these projects, which I would guess you would have pretty good certainty on what the initial volumes would be. Do you think there's some upside to your guidance relative to hinging on kind of the Lakehead volume growth? Or at this point, do you still feel like the guidance is pretty reasonable?

Mark Andrew Maki

The guidance, to us, feels pretty reasonable, Mark. We're now going to talk the guidance up.

Operator

[Operator Instructions] Our next question is from the line of John Edwards of Crédit Suisse.

John D. Edwards - Crédit Suisse AG, Research Division

I was just curious on the Line 6B that you've just placed into service. What the volumes there are now? And then, I guess you got a second phase on that, so then -- what kind of ramp-up you're expecting on that system here with Phase 1 and Phase 2?

Guy D. Jarvis

Phase 2, which is going to come on into service here later this year, will take it up to 500,000 barrels a day. I think what we did here more recently has got us in about the 260,000-barrel-a-day range.

Mark Andrew Maki

And really, probably, John, what's most important on -- as it relates to the ramp-up associated with that project is the tariff effectiveness on August 1, which picks up a good chunk of the capital that we just deployed. So we got some benefits from volumes, yes, in the first -- or sorry, in the second quarter. But you'll see a bigger benefit. That's one of the reasons you got a stair step in the numbers this year as you start to see the full effect of the tariff increase later in the year.

John D. Edwards - Crédit Suisse AG, Research Division

Okay. Now that's helpful. And then, I was having a little bit of trouble following the discussion on the tariff filing. I guess there was a small delay. So I was curious I guess why was there a delay in the tariff filing? And then, I mean, did it cost you anything in that regard? And if so, how much?

Mark Andrew Maki

Well, with respect to the delay, there was a component of the existing tolls that were in effect last year that relates to an expansion we did that back in the late 90s, called System Expansion Program II, SEP II. SEP -- this was building a new line through Wisconsin. And that agreement has a 15-year life associated with it. It expired at the end of March, 2014. And so when that came up, it was time to renew. The asset still has unrecovered book value and so forth. So we began the process with the CAPP to renegotiate how that would roll over. And so that process took a little bit longer, a little more complicated, a little more involved, because we also worked in some other elements of negotiation as well, including how we're going to handle integrity capital and other things. So that stretched out a little longer than probably we had anticipated or hoped. Did it cost us anything? I don't think so on the grand scheme of things because you got an agreement that was mutually acceptable to both of us and to the customers. So it's just later going to effect for us. There were adjustments provided for in the tariff filing to ensure we basically were whole. We're not changing our guidance because of that. So on balance, John, I don't see it as a negative at all. In fact, we were able to roll over the -- and continue recovery of capital for Line 14 expansion. I think that's good. So really, there's nothing negative, really, John, I can point to in the agreement.

John D. Edwards - Crédit Suisse AG, Research Division

Okay, great. That's helpful. And then, my last question was just -- it was on your Slide 10, and it just showed the volumes with respect to Mid-Continent. They were up slightly year-over-year, a little bit down sequentially. I mean is that just a seasonal issue? Or is there something else going on there?

Mark Andrew Maki

Probably seasonal as much as anything, John. If you think about what's been going on in the marketplace right now with the line fill of TransCanada's line to the South, and just push of volume south. It's really a little bit of that going on. So a little bit less activity on the Mid-Continent going North, but we expect that to change in due time.

Operator

Next question is from the line of TJ Schultz of RBC.

TJ Schultz - RBC Capital Markets, LLC, Research Division

My question really relates to Slide 8, I think. The comment that dropdown proceeds mitigate the equity funding requirements at EEP. I think previous guidance and then taking into account the latest dropdown, you have a split now of about plus or minus $2 billion of dropdown proceeds and $600 million of EEP equity for funding requirements. Is that still the expectation for the split to get you there?

Mark Andrew Maki

There is usually a plus-minus I guess on that amount of proceeds from the Midcoast transaction, as I recall the slide. But certainly, that amount might be somewhat different than that. And the number that had been disclosed previously will be smaller by the $350 million that we just, of course, just would have closed here on July 1. And typically, TJ, we'll need a lot of cushion, if you will, in any kind of numbers like that. So we have a little bit of lagniappe, if you want to call it that, with respect to the amount of equity that we've got to issue. So if, for some reason, the amount of Midcoast proceeds is modestly lower, does that automatically result in a dollar-for-dollar increase in equity? No. And so there's some play in between those numbers.

Stephen J. Neyland

And maybe if I can just add, so the waterfall slide that we've had, historically, T.J., where we've shown the debt and equity that's required, effectively it's really just updated by the $350 million drop that has occurred. And you can think that the -- you could refresh that by hand pretty quick. We chose not to include it in the slide deck just because we had to have some -- had to cut the slide deck somewhere as far as size.

Operator

Next question is from the line of Sharon Lui of Wells Fargo.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Just following up on John's question about the tariff filing. Was the magnitude of the increase incorporated in your original guidance?

Mark Andrew Maki

Yes, but the timing would have been sooner in the, probably, the original guidance, where an initial assumption would have been, as I recall, would have been in April effective date. Normally, we did our tariff filings in 2 buckets. There would have been an index increase on July 1 and there would have been adjustments to our cost to service tolls effective April 1. So those both got lumped together effective August 1.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And I guess based on Slide 13, it looks like your total CapEx guidance hasn't changed, but the spending for I guess the different projects shifted a bit. So for example, I guess liquids, integrity and other growth CapEx increased while the spending for Eastern Access and the Mainline Expansions went down. Can you maybe just provide some commentary there?

Stephen J. Neyland

Yes, Sharon, this is Steve. The -- I think the changes were, if I recall, $30 million to $40 million type changes between these different categories. It's really just a function of timing of the spend profile as to when projects are getting done, and not necessarily an overall cost change to Eastern Access or U.S. Mainline programs or the other growth enhancements, just refining of the numbers, if you will. So not really any significant driver behind them.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And then, my last question is just on the recently proposed standards for rail cars that may impact, I guess, operations in the Bakken. Just wondering if you have any commentary how that might impact your business. It looks like the timeline or the proposed timeline is about 2 years. It seems tight, given that the backlog for railcars is pretty high.

Guy D. Jarvis

Well, I think, in terms of thinking about it from our pipeline business point of view, I think there's no doubt while we can't -- I don't have a number for you in terms of what we think is going to happen to the cost of rail transportation. We think between the higher standards around the cars and some of the other limitations that they're talking about, in terms of track maintenance and integrity and speeds of trains and whatnot, we see the cost of crude oil by rail going up. So we think that while we're already very competitive into the markets that we serve directly with pipelines, that competitive advantage into those markets is likely only to get stronger.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

But at this juncture, has this changed I guess your perspective in terms of pursuing additional rail-focused investments at both EEP or ENB?

Mark Andrew Maki

There's still a role for rail, especially in terms of -- it is relatively quick to deploy, so if you got a -- like Guy described earlier, you have a couple-year situation or maybe you've got constraints in the main line, rail provides you a way to kind of work around that. There's -- rail has a place. And then, there are certain markets that are not going to get to with pipe probably any time in the near future, West Coast or others. So rail still has a place, Sharon. It's just where you've got pipeline-rail competition, pipe should beat rail all day, which we've been seeing for a long time.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And I guess in terms of the cars, Enbridge just leases and not own. Is that correct?

Mark Andrew Maki

Yes, as it relates to EEP, we have very, very few railcars. Most of the rail cars at EEP has are the high-pressure cars because we used to haul have Y -- X grade or Y grade -- X grade, I guess, LPGs or specification NGLs. At the Enbridge, Inc. level, yes, there are railcars that are leased, and I can't comment on those.

Operator

Next question is from the line of Louis Shamie of Zimmer Partners.

Louis Shamie

My question was primarily with regards to the distribution increase and understanding the thinking around that. As I see it, coverage probably gets reestablished and starts growing past 1 maybe during 2016. You've got a pretty big build program, you had to give up some portion of your projects, some temporarily, some permanently because of liquidity constraints. And then, on the other hand, you fixed that a bit getting support from Enbridge, Inc. and the GP restructuring and things like that. How do you balance kind of the need for liquidity and the cost of capital against kind of the visibility to eventually covering the distribution and deciding to increase today and increase your quarterly cash payout?

Mark Andrew Maki

We might tag team on that one between Jonathan Rose, Treasurer, and me. And I think maybe the place to start would be -- Louis, I guess we're certainly balancing off -- one thing we certainly get, as management, we get lots of good advice from folks. And -- but the view here is that people investing in MLPs are looking for distribution growth and, frankly, at the end of the day, why we’re doing it is we've got a high degree of confidence in executing on our plan, and that we're going to be able to continue to grow the distribution in the future. The sub 1 coverage is really transitory as a function of the fact we got a lot of capital deployed at the current point in time. And we're sitting here today, it is not of service but we had to issue the equity and the debt for it to finance the project. So we're carrying that without necessarily having cash flow coming in. But given the nature of the projects we've got behind, that capital, we're very confident raising the distribution, albeit at the lower end of our range in a period of time like this. So we're balancing off some coverage improvement. We're going to see substantial coverage improvement from last year to this year, and still, at the same time, being able to bump the distribution, albeit modestly. And then, we expect to continue to improve that picture if you go out the next couple of years. And as you note, or you posited in your question, eventually you get across the 1, and then you got more scope to raise the distribution further.

Jonathan Rose

I guess what I'd add to that is that -- this is Jonathan Rose -- is that through the equity restructuring event and through the high visibility of cash flow that we see coming at us, we can -- we understand that, as we move through our capital program, we're going to be in a position to monetize dropdown opportunities from the parent. And to do that, you need a healthy and viable equity currency, and we've taken advice from many folks about how you maintain an equity currency. And this market rewards and wants cash flow growth, and we can see that and we're working towards that.

Louis Shamie

I see. Okay. So it's about positioning the equity to better be able to access the capital markets for funding.

Jonathan Rose

Well, Enbridge is a long -- Enbridge is a group of companies with a long-term focus, and we have a long-term view on our strategy. So that -- part and parcel of that is the way that we look at our cost of capital.

Louis Shamie

Got it. And then, my second question is, I guess, somewhat straddles EEP and Midcoast, which is -- looking at Midcoast's debt capacity, I understand that your leverage metric is on the consolidated EBITDA and not on the pro rata share of EBITDA. But even so, it looks to me like you're kind of the high -- maybe between 3.5x and 4x. And I guess you ramped EBITDA there a little bit, that improves the metric. But you don't really have much room to issue debt at MEP to fund the future dropdown. So should we expect those to be like 90% equity funded? Or is there some other way of handling that?

Jonathan Rose

I think you'd expect that they would be funded with a mix of debt and equity that would be appropriate to maintain the credit metrics. But there are cash flow dynamics in there and there are -- the amount of interest that's going to be purchased. So I don't think you could say out of the gate that's it's going to be 9% or 10%. It's going to be specific to the circumstance.

Louis Shamie

But if you, say, look at couple of years out or look at EBITDA of around $250 million consolidated times 4, if you want to stay at 4x debt-to-EBITDA, that's $1 billion of debt capacity. You've got over $800 million today and there's probably, say, $1.3 billion, $1.5 billion of future drops. I'm just -- and those drops don't increase your consolidated EBITDA, only MEP's portion of it. So that's where I'm kind of wondering what [indiscernible].

Jonathan Rose

I think the assumption you're making in there is that the consolidated EBITDA doesn't grow.

Operator

As we have no further questions in the queue, I'd now like to hand back to Mr. Sanjay Lad for closing remarks.

Sanjay Lad

Great. We thank you for participating in our earnings conference call today. We have nothing further to add at this time. However, I would like to remind you that I will be available for any follow-up questions you may have. Thank you, and have a great day.

Operator

Thank you for participating, ladies and gentlemen. That concludes today's conference call. You may now disconnect your lines. Have a great day. Thank you.

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Source: Enbridge Energy Partners, L.P. (EEP) Q2 2014 Results - Earnings Call Transcript
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