Enbridge Energy Partners' (EEP) Q3 2014 Results - Earnings Call Transcript

Enbridge Energy Partners, L.P. (NYSE:EEP) Q3 2014 Earnings Conference Call November 3, 2014 10:00 AM ET

Executives

Sanjay Lad - Director of Investor Relations

Mark Maki - President

Steve Neyland - Vice President, Finance

Guy Jarvis - Executive Vice President, Liquids Pipelines

Greg Harper - Executive Vice President, Gas Pipelines and Processing

Analysts

Mark Reichman - Simmons & Company

Brian Zarahn - Barclays

TJ Schultz - RBC

Sunil Sibal - Seaport Global Securities

Faisal Khan - Citigroup

John Edwards - Credit Suisse

Ross Payne - Wells Fargo

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Enbridge Energy Partners, L.P. Earnings Conference Call. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session towards the end of the presentation. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I'd now like to turn the presentation over to your host for today, Sanjay Lad, Director of Investor Relations. Please proceed.

Sanjay Lad

Good morning and welcome to the 2014 third 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 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 Mark Maki, President; and Steve Neyland, Vice President, Finance. Available for the Q&A session, we also have Guy Jarvis, Executive Vice President, Liquids Pipelines; Greg Harper, Executive Vice President, Gas Pipelines and Processing; Jonathan Rose, Treasurer; and Noor Kaissi, Controller.

Let's move 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 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 schedules 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'll now turn the call over to Mr. Mark Maki, President.

Mark Maki

Thank you, Sanjay. Good morning and welcome. On the call today, we'll provide an update on recent developments, discuss the Partnership's strategic outlook and Steve Neyland will address the third quarter financial highlights.

Before we get into presentation, I want to touch on an 80-K that we filed announcing some changes in our Directors in Enbridge Management and at our General Partner. First, we'd like to thank Terry McGill whose leadership of the Partnership during his impactful 10 years as Director on the boards of our General Partner and Enbridge Management. Within new organizational structure, Terry will lead his position on these boards and will focus his efforts as President and Chief Commercial Officer for Midcoast Energy Partners. In addition to serving as Director on the board of Midcoast Energy Partners General Partner.

We also welcome John Whelen, Executive Vice President and CFO at Enbridge Inc. to the boards of our General Partner, Enbridge Management. Finally, Richard Bird who recently announced his upcoming retirement from Enbridge Inc. will remain a Director of EECI and EEM. We will continue to benefit from Richard's great depth and the long history with EEP, which dates back to before its founding in 1991.

Moving on to the noteworthy highlights for the third quarter, deliveries in the Lakehead System reached a record high, averaging close to 2.2 million barrels per day. Deliveries in our North Dakota System also reached record levels during the third quarter. We expect deliveries in both Lakehead and North Dakota to remain strong and continue to increase as our Market Access projects enter service.

We continue to progress very well on our major projects. Collectively, Partnership is placed in service over $2.0 billion or capital in the year. We expect organic projects and our recently announced Alberta Clipper dropdown transaction will deliver highly certain earnings and cash flows, which will increase our DCF and strengthen distribution coverage. In July, we closed the previously announced equity restructure transaction, whereby our General Partner agreed to reduce the Partnership's incentive distribution tier in exchange for a new class of limited partnership units.

Finally, we recently received $900 dropdown proposal from our parent, under which our General Partner will drop its remaining two-thirds interest in the US segment of the Alberta Clipper pipeline to the Partnership. We'll discuss the details of this exciting development shortly. Collectively, these highlights provide the Partnership with strong momentum as we head into the fourth quarter and into 2015 and they position us to deliver on our plan.

Please turn to Slide number 4. In late September, we received a proposal initiated by our parent, under which our General Partner will drop down its remaining two-thirds interest in the US segment of the Alberta Clipper pipeline to the Partnership for an aggregated consideration of approximately $900 million. The proposed transaction or consideration includes cash of approximately $300 million plus approximately $600 million of a new class of limited partner equity units to be issued to our General Partner. The transaction will not require EEP to issue any equity in the public markets and we do not expect the current market conditions to affect the closing of this transaction.

The Board of Directors of Enbridge Management has appointed a special committee comprised of independent directors to review the proposal. The dropdown transaction is targeted to close by the end of 2014. Proposed dropdown value corresponds to an approximate 11 times multiple of expected 2015 EBITDA. The Clipper earns a stable cost of service return, which is not subject to variations in throughput. We expect the proposed dropdown to be immediately accretive to DCF by approximately 3%.

This transaction is the latest in a series of actions and which is taken to strengthen and enhance the composition of EEP's distributable cash flow and reestablish EEP as a strong master limited partnership. Enbridge has reinforced its objectives to utilize dropdown as a source of funding for its own $44 billion growth program, and this initial dropdown paves the way for future dropdowns. Enbridge Inc., as you all know, has a very attractive portfolio of liquids pipeline and assets in the US, representing over $10 billion in book value that can dropped down to the Partnership over the longer term.

And as a reminder, the Partnership has dropdown call options in the Eastern Access and Mainline Expansion series of projects, whereby EEP may increase its ownership participation in these attractive projects by incremental 15 percentage points at cost. The value of this is about $800 million. EEP intends to position for these dropdown transactions or opportunities into 2016 and 2017 timeframe.

The Clipper dropdown transaction together with future dropdown call options in the EA and ME projects provides further momentum for the Partnership's distribution growth potential. And this ought to be clear from our comments in the press release, but management intends to request that the Board of Directors consider approval of an additional 2015 distribution increase following the close of the dropdown transaction, which we expect to occur before the end of the year.

Let's move ahead to Slide number 5. The equity restructure that we recently closed is a very important transaction for EEP. Our General Partner agreed to reduce its incentive distribution tier in exchange for a new class of limited partner units with a single tier IDR structure. Limited partner unitholders will receive a 75% share of distributions in excess of $0.5435 per unit per quarter. There're some overarching prospective benefits to the Partnership from this.

The equity restructure will improve EEP's cost of capital as a General Partner share of future distributions will be lowered. The equity restructuring also enhances the economics of the Partnership's investment projects and will result in a greater proportion of cash flows being available for distribution to the public unitholders from existing capital projects as well future growth projects. In addition, the improved cost of capital enhances the Partnership's acquisition and dropdown positioning.

The positive momentum established by the equity restructure was a key catalyst that paved the way for Enbridge to accelerate its dropdown objectives and initiate the Alberta Clipper dropdown. Cost of funding arbitrage between Enbridge and the Partnership has compressed enough that it's not possible to structure a transaction that's mutually beneficial to both parties. This is again a key step in establishing EEP as a strong master limited partnership.

Please turn to Slide number 6. Turning to project execution, we are keen to make solid strides in project construction and delivery on our growth projects. During the quarter, we completed the remaining 50 miles of 30-inch diameter pipeline between Stockbridge, Michigan and Sarnia, Ontario. We've now expanded this line's capacity from 240,000 to 500,000 barrels per day. This project is a critical component of our Eastern Access program.

Next we placed in the service phase one of our Line 61 expansion whereby we increased our Southern Access pipeline capacity by 160,000 barrels a day between Superior, Wisconsin and Flanagan, Illinois. Partnership has placed into service over 2 billion of liquids pipelines expansion in 2014. Collectively, the long-term low-risk commercial frameworks underpinning our organic growth projects such as cost of service and take-or-pay will provide us a high-level confidence in progressing DCF growth and strengthening distribution coverage.

Let's move ahead to Slide number 7. The Market Access programs that we have underway collectively with Enbridge Inc. are part of the overall strategic initiative to match current North American crude oil supply to domestic demand centers. This slide summarizes all those projects and illustrates on a year-by-year basis 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 markets.

As you can see from the projects listed on the right of the map, Enbridge and the Partnership have successfully executed on our program in 2013 and 2014. And looking ahead to '15, we're on target to deliver the remaining components of our US mainland expansion projects, specifically phase two of the Line 61 and Line 67 expansions and the Line 62 Twin also known as the Chicago Connectivity Project. These expansion projects are expected to progressively increase the utilization of the Partnership's Lakehead System and are facilitated by the downstream pull from the parent's US Gulf Coast and Eastern Access market extensions.

As it relates to Sandpiper pipeline project out of the Bakken, we originally estimated target and service date for the project would be early 2016. We now estimate that in-service date will occur during 2017. The delay is a result of a longer-than-expected permitting process in the state of Minnesota.

Let's turn to Slide 8 and I'll turn the call over to Steve to discuss the financial results.

Steve Neyland

Thank you, Mark. For the third quarter, the Partnership reported adjusted EBITDA of $406.7 million. This represents a 48% increase over the third quarter of 2013. Record Lakehead and North Dakota System deliveries in addition to our organic growth projects entering service in 2013 and through 2014 contributed to solid EBITDA growth.

Third quarter adjusted net income of $117.8 million was $56.8 million higher than the same period of 2013. Increased earnings were attributable to higher transportation rates, increased deliveries and associated revenues from our liquids segment, which were partially offset by lower gross margin in our natural gas segment.

During the third quarter, the Partnership attributed approximately $22.5 million of earnings to its Series 1 preferred unitholders. 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.

Interest expense increased approximately $52.3 million due to the recognition of non-cash unrealized mark-to-market losses associated with the amendment of the maturity date for our interest rate hedges that were originally set to mature in 2014 and 2016, resulting in hedge ineffectiveness.

Adjusted earnings per unit for the third quarter increased $0.25 compared to $0.09 for the same period of 2013 due to higher adjusted earnings attributable to limited partner interest. Our year-to-date as declared distribution coverage ratio on a cash basis was 1.08 times and was 0.9 times during the inclusion of the paid in kind distribution. For the third quarter, the as declared coverage ratio on a cash basis was 1.14 times and was 0.95 times during the inclusion of the paid in kind distribution. 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 dollar organic growth program into service.

Please turn ahead to Slide 9. The liquids pipeline segment had another strong quarter. Adjusted operating income of $269.7 million for the third quarter was $119.5 million or 80% higher than the same period from 2013 and $38.9 million or 17% higher than the second quarter of 2014.

Third quarter operating revenues over the prior year increased due to an increase in transportation rates and higher deliveries on our Lakehead and North Dakota systems. The Partnership completed a large component of its Eastern Access program, specifically the Line 6B replacement project from Griffith, Indiana to Sarnia, Ontario in two phases during 2014. The 160 mile segment of the Line 6B replacement project from Griffith, Indiana to Stockbridge, Michigan entered service May 1, 2014 and contributed to the increase in revenues during the third quarter. The remaining 50-mile segment of the Line 6B replacement to Sarnia, Ontario entered service September 30, 2014. These phases have collectively brought the full line 6B replacement project into service. Additionally, the first phase of the Line 61 mainline expansion began service on August 1, 2014.

Third quarter 2014 operating revenues decreased $17.7 million as a result of regulatory accounting true-ups related to Lakehead toll revenues. Our updated Lakehead tariff filing, which was effective August1, 2014, placed the update index rate adjustment into effect, eliminated the step two surcharge for Line 14 and added new components to the facility surcharge mechanism in order to recover the remaining Line 14 rate base.

Operating income benefited from lower operating and administrative expenses of $23.2 million over the prior year, primarily due to the higher pipeline integrity cost related to the Line 14 hydrostatic test, which we completed last year.

As you view the chart on the right, you can see the increasing deliveries trend on our Lakehead and North Dakota pipeline systems during the quarter. Deliveries on our Lakehead System reached a record 2.17 million barrels per day during the third quarter, strong deliveries, driven by continued supply growth at our Western Canada, as Enbridge and the Partnership's pipeline expansion projects were entering service. Deliveries on our North Dakota System also reached record levels at approximately 350,000 barrels per day as volumes transitioned back to our pipeline system due to favorable market pricing differentials between the East Coast and Gulf Coast markets.

Collectively, total liquids system deliveries increased approximately 21% over the same period from the prior year. During the quarter, we increased our total cost estimate related to the Line 6B incident by $51.9 million to a total cost of $1.21 billion. The cost increase during the third quarter is primarily related to the finalization of the Michigan Department of Environmental Quality approved scheduled work as we completed the dredge activities near Ceresco and Morrow Lake and updated estimated several penalties under the Clean Water Act of the United States. We're currently working with the Michigan Department of Environmental Quality to transition activities from the EPA.

The cumulative amount collected from insurance recoveries is $547 million. The remaining uncollected liability insurance coverage is $103 million. We believe we will collect these amounts in future periods. Through the end of the third quarter, cumulatively, we spent approximately $989 million on Line 6B remediation and have a remaining estimated liability of approximately $219 million.

Let's move forward to Slide 10. The natural gas segment had an adjusted operating loss of $3.2 million for the third quarter, which was $20 million lower than the same period for 2013 and $9.8 million lower than the second quarter of 2014. The decrease in our third quarter natural gas adjusted operating income over the prior year was primarily due to lower natural gas and NGL volumes on our systems.

Moving to the right-hand side of the slide, you can see wellhead volumes increased approximately 1% in the third quarter versus the second quarter of 2014. We're encouraged by the sequential increase in total system natural gas volumes from the first through the third quarter and expect volumes to continue to progressively ramp up. New production in the Anadarko region is coming on to replace volume losses from the previously announced lost customer. Also, reduced dry gas drilling in the East Texas region is being partially offset by rich gas drilling. Likewise, North Texas is showing steady gains underpinned by richer gas streams.

Moving down to the system-wide NGL production chart, we have represented a portion of NGL production related to the previously disclosed customer loss on our Anadarko system. As you can see, our system-wide NGL production continues to increase when excluding the production associated with the lost customer. This positive trend in the NGL production indicates that we're benefiting from richer gas developments across our systems.

Please turn to Slide 11. In February, we provided full year 2014 adjusted EBITDA guidance of $1.5 billion to $1.6 billion. We remain confident in delivering our full year financial guidance for 2014. Year-to-date adjusted EBITDA through the third quarter was $1.108 billion. Looking forward to the fourth quarter of 2014, we continue to expect a ramp in adjusted EBITDA predominantly due to successful project completion.

As Mark discussed earlier, in 2014, we completed a large component of our Eastern Access program, notably the Line 6B replacement project and the first phase of our Line 61 mainline expansion. Collectively, full quarter contributions from these recently completed growth projects are expected to fuel sequential growth in EBITDA and cash flows for the Partnership in the fourth quarter. Additionally, our updated Lakehead tariff filing, which became effective August 1, 2014, is expected to provide full quarter benefits in the fourth quarter.

Let's move forward to Slide 12. This slide provides our 2014 capital expenditure forecast, which is estimated to be $1.6 billion and is inclusive of approximately $100 million maintenance capital expenditures. These expenditures are presented net of joint funding. At the end of the third quarter, we had approximately $1.4 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 EEP's liquidity requirements.

On October 6, 2014, we amended the five-year credit facility to extend the maturity date from September 26, 2018, to September 26, 2019, with $175 million of commitments expiring on the original maturity date of September 25, 2018.

Please turn to Slide 13. I'll now turn it the call back over to Mark for his closing comments.

Mark Maki

Thank you, Steve. Just a couple of points and emphasis in closing. First, we are pleased with the strong performance in our liquids pipeline systems so far in 2014. We expect deliveries in both our Lakehead and North Dakota systems to remain strong as we leave the year and enter 2015.

Our 2015 organic growth is on target. We expect our organic growth projects and our recently announced Alberta Clipper dropdown will delivery highly certain earnings and cash flows, which will increase our DCF and strengthen our distribution coverage.

Partnership's expected funding needs are very modest to 2017 as the net dropdowns largely defray our near-term equity requirements. EEP will optimize the size and timing of any future dropdowns to meet the mutual objectives of EEP and Midcoast Partners.

The positive momentum established following our equity restructuring transaction was a key catalyst tha paved the way for Enbridge to accelerate the dropdown objectives and initiate $900 million of Alberta Clipper dropdown. Our parent has reinforced its objectives to utilize dropdowns as a source of unding for Enbridge's own product growth program.

So with that, I'd like to turn the call over for questions please.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question will come from the line of Mark Reichman with Simmons & Company.

Mark Reichman - Simmons & Company

Just a few questions. The liquids segment performed very well and natural gas segment was a little weak. And during your Analyst Day presentation, you had outlined an MEP dropdown schedule through 2017. I was just curious would your preference be to accelerate the sale of your interest in MEP or would you be more apt to extend it to allow MEP to use its financial capacity to fund organic expansions or even third-party acquisitions to diversify its business.

Mark Maki

All those are certainly options we're going to look at for Midcoast. One of the key things I want to emphasize without a question is Midcoast is an important part of EEP's future and we want to take actions that are going to help meet these successful. So if it's throttling up or throttling down on the dropdown schedule in order to accomplish that, that's one thing we could do, especially if as Greg looks at opportunities to step outside the footprint and diversify the Midcoast business, EEP certainly would intent to invest alongside Midcoast anything that happens on the footprint, but also where there is off the footprint and you look at the types of projects that Greg is targeting with his leadership team, those are projects that would fit well in EEP and EEP would then drop it down at a later point. So there is lots of things that we can do. All those options that you outlined are all things that we would consider.

Mark Reichman - Simmons & Company

And then on the 2014 capital expenditure budget, was just wondering how much of the $95 million reduction is attributed to lower cost, deferred spending or changes to the project portfolio and any comment on expectations for '15, or is that generally outlined at your Analyst Day.

Steve Neyland

As it relates to $95 million change, I'm sure you probably already have done the math, about $40 million of that is around Eastern Access. Really it just has to do with really just timing of phase one. It's just the cleanup cost associated with the in-service or the asset as well as some of the decommissioning cost we have around the old Line 6B. So it's really just a function of some timing. And the other big component that's there is on the liquids other expansion capital for about $65 million, which is quite honestly a number of different projects and again timing. So it's really just refinement, if you will, this late in the game process in the year.

And as it relates to future periods, 2015, 2016, really not any additional guidance to provide other than what we've already communicated.

Mark Reichman - Simmons & Company

Could you just provide an update on efforts to optimize the permitted cross-border capacity on Line 67 and Line 3? What your expectations are in terms of the timing on ramping up capacity and your expectations to receiving permit amendment?

Guy Jarvis

In terms of the cross-border Line 3 maintenance and our flexibility program that we had talked about implementing at the border, that is now in service. It's been in service since second half of September. And as we've previously indicated, that and some other things that we've doing have allowed us to realize the incremental capacity of up to 570,000 barrels a day that we're expecting versus the prior limitation of 450,000 barrels a day. So that's in service. We've got the capability to add the additional 120,000 barrels a day.

In terms of then the next stage of the Clipper expansion to 800,000 barrels a day, we have got all of the state and Army Corp. permits that are required to build those stations, and we're going to be commencing that construction shortly. It is expected, they will be in service by the middle part of next year. And we're still confident based on the insight that we have through our major projects group that we can get the Presidential permit amendment in place by that time.

Operator

Our next question will come from the line of Brian Zarahn with Barclays.

Brian Zarahn - Barclays

On the planned distribution increase from the Alberta Clipper dropdown, is that going to be just part of your regular quarterly distribution?

Mark Maki

Brian, that would be the intent, yes.

Brian Zarahn - Barclays

How should we think about your distribution growth guidance range, given you have tailwinds obviously from the dropdowns in the organic projects entering service, but headwinds from lower NGL prices? So how should we think about these cross-currents?

Mark Maki

You've hit on a couple of them, the headwinds and tailwinds. We're sticking for the time being any way in the 2% to 5% over time, but certainly we would look distribution outlook based on what we've already talked about for 2015 is better than, say, what it was this year. And given the dropdown from the parent, plus we come back to an normal distribution cycle at the middle of the year and see how things are looking. But certainly 2% to 5%, Brian, we're going to stick with that for the time being and monitor the headwinds and tailwinds and see if there is any adjustment required to 2% to 5%. But it's a broad range. It covers lots of different conditions in the market and we consider that. We're establishing what our outlook is for distribution growth.

Brian Zarahn - Barclays

Mark, in your comments you mentioned expected growing liquids volumes. I'm just curious on your North Dakota System, since the crude price decline really accelerated in October, any impact on the North Dakota System that you're seeing on volumes?

Mark Maki

Not yet, Brian. I think certainly the decisions the producers are making in North Dakota, a lot of us see different market fundamentals and you'll get short-term blips and aberrations in the market and you're seeing some of that in pricing now. But we've seen volume come back to our system away from [ph] rails as differentials have come in and I think the fundamentals really line up for it longer term. So right now, again we feel very, very good about the outlook for North Dakota and long term we feel great about the outlook for North Dakota.

Brian Zarahn - Barclays

Last line from me related to Sandpiper, any change in your cost estimates due to the permitting delay and any additional color on when in 2017 do you think the project will enter service?

Mark Maki

I'll take the top level of that and look to Guy to add any additional color. Basically the year 2017 is going to be somewhat dependent upon when we receive all the different decisions we need from the state of Minnesota. You've got to first off a Certificate of Need and you've got the route decision. Depending on the route that eventually is chosen, then certainly we think the one that we put forward is the right one, but if there're some alterations or deviations that would likely add cost to the project. So till we know that, it's really hard for us to say the numbers. Certainly delay will likely add some marginal dollars to the cost. Again, it's hard to say what that is until we have a chance to look more definitively what the schedule is, when do we receive the go ahead, where do we have the routes at. And then we can look at what we can do to manage the construction to get it done in maybe an accelerated timeframe, looking at winter construction and other alternatives.

So there is a lot of variables we don't know the answer to that make it hard to answer the cost question.

Guy Jarvis

No, nothing to add to that, Mark. I think you highlighted it on briefly. But one of the real issues that we face is that winter construction period and areas that do need work in winter, depending when we get our permits, you can't just say, well, it's two months or three months behind what we expected, so the in-service date is delayed two or three months if we get into construction window problem, two or three months delay on the permitting side, could have the potential to result in larger delays. But as Mark said, at this point in time, we don't have enough information to have anything more definitive.

Operator

Our next question comes from the line of TJ Schultz with RBC.

TJ Schultz - RBC

As you previously thought there was $2.6 billion I think was the number of value to drop to MEP, just how has that view or dollar value changed, given the year-to-date results in the gas business generally?

Mark Maki

The $2.6 billion was before the first drop. So again factor that down. But then thereafter, TJ, the value that we expect here out of the dropdown of strategy for Midcoast is going to be dependent upon when it takes place, what the commodity cycle looks like at the time the drops take place and other activities that happen on the system and off the system and how EEP invests alongside Midcoast along the way. So again lots of variables in that.

I would say in the $2.6 billion, using that old number, there was certainly cushion as to how much we expected to get from the dropdown strategy. We have certainly the ability to pick a lesser number and still be fine as far as our equity funding requirements are at EEP. We had JR in the treasury books that made sure we've got room. So the number to me is maybe less. No one is particularly concerned with that at this end at this particular point in time.

TJ Schultz - RBC

I understand it's kind of variable as you look to grow the Midcoast operating business to grow the size of that pie to allow for dropdowns. But maybe that means acquiring something outside the footprint, but maybe if you could just expand on that gas business, what you see for the investible opportunities, what dollar value of Midcoast growth organic CapEx is maybe achievable next year and then just kind of the types and returns on the projects there.

Mark Maki

Well, Greg touched on this in the call for Midcoast and he could certainly add additional color here. But a couple of hundred million dollar kind of range organic in $200 million to $300 million organic in and around the footprint and I'll Greg speak here in just a moment, but (inaudible) opportunities, there is certainly other opportunities in North Texas footprint, organic on system activity. In addition, one of the things Greg highlighted as a key strategy, once you came in and looked at our business, is we need to get assets that enhance the value chain, change some of the contract mix that's in that existing business, look at other basins.

So we're got more exposure to other sales and activity areas in the US. And so all those are places we could see Midcoast invest in EEP. I think we'll be very happy to invest alongside Midcoast.

Greg Harper

Mark, I think you, this is Greg, did quite well answering that. I'd say you've got input footprint strategy in East Texas. It's getting [ph] Becko online and fully operational and getting the gas stream richened to an optimum level is going to be key for East Texas. North Texas, as Mark say, continuing on what we're doing. We actually have a pretty good year on North Texas and adding new business and new richer volumes in that stream. Anadarko has been a disappointment for sure, but that's a key focus here. And I think fourth quarter will straight the renewed the focus on Anadarko for us and some things we are doing there to bring more gas into that system and get it processed and then move down to Texas Express.

So that's the end footprint. Dave Weathers and his team, Mark addressed this earlier in his comments, is looking for new opportunities outside the footprint within the gathering and processing world. And to be more proactive in those approaches as opposed to reactive to RPs, and we're hope we'll be successful. Again, you can't make people dance with you, but we'll be kissing a lot of frogs out there on that end.

TJ Schultz - RBC

Going back to the distribution growth kind of guidance range, in the past you've highlighted that organic projects provide some of the momentum maybe to accelerate to the high end of that 2% to 5% range by 2017. So if you could just frame the ability to accelerate distribution growth kind of in the context of Sandpiper getting delayed, do you consider that project at crux to accelerate growth or now do you think the call options on EA mainline provides some flexibility, just kind of how are you thinking about the need or ability to accelerate that growth to the higher end of your range?

Mark Maki

If you look at the old guidance, if you will, on that particular subject matter, the acceleration to the higher end of the range was a confluence call options together with Sandpiper getting done in '16 and then the Line 3 project in '17. So what you have now as you got Sandpiper and Line 3 still lined up in the '17 timeframe, which you saw the call options in '16. And so as you think about the ability to accelerate, we'll be carrying some capital, no question, with respect to Sandpiper through '16. So we probably don't quite have the same cross-over, if you will, to that particular point in time, but we'll get there with the projects that we've got lined up.

And I think one of the nice things, if you think about what has been done of late with respect to EEP, the IDR restructuring was a critical component. You see that with the Alberta Clipper transaction. So the ability of EEP now to be in a position to take dropdowns from the parent is substantially better than it was when that prior guidance was given. So I think we've done a lot of work to strengthen each positioning to be in a position to take dropdowns in the parent. And that I think would probably be one of the things I'd look at as being as a catalyst to drive us to the higher end sooner or to maintain the old look that we had before.

Operator

Our next question comes from the line of Sunil Sibal with Seaport Global Securities.

Sunil Sibal - Seaport Global Securities

One quick question, if I may, regarding your operating and administrative expenses, especially the way they are broken down between the liquids and the gas business. Looking at the total operating and administrative expense, seems like gas business is picking a much bigger share of that expense, especially as a percentage of gross margins across the two businesses. I think Greg alluded a little bit to that on the MEP call. I was wondering if you could talk about how are you thinking about that going forward.

Mark Maki

I think one as when you're comparing the two businesses and their cost structure is the comparability is a little bit tough from the standpoint that Lakehead or the liquids segment, I should say, is predominantly, not exclusively, but predominantly, mainline type whereas the gathering and processing system there's more people and equipment top rate. The processing plants and treating plants that we have to accommodate the margin, so just by its nature, the gather and processing business is going to carry higher cost structure than would mainline or interstate type pipelines. That said, we did talk about on the call within EEP that we believe there's opportunities to optimize that cost structure and make it more effective.

Operator

Our next question will come from the line of Faisal Khan with Citigroup.

Faisal Khan - Citigroup

Just wanted to go back to a question you answered earlier. So the Line 67, Line 3 sort of optimization plan, you said that now you're capable of running 570,000 versus 450,000 barrels a day. But are you running at full capacity across the board?

Guy Jarvis

Yes, we have. We've been apportioned on our system throughout most of the year, particularly on the heavy side of things. So while we remain apportioned, that capacity has been utilized quite, well, just about every day.

Faisal Khan - Citigroup

As you guys look at the volumes on Lakehead, can you just clarify exactly moving from the 1.83 a day to 2.17 a day, is that a combination of light and sweet or mostly heavy crude? You side Western Canadian is all heavy crude in terms of incremental barrel from last year to this year.

Guy Jarvis

First answer is it's both. I think if we looked at what we've seen manifest this year versus our projection coming into the year, while the heavy has grown, it maybe hasn't grown as strong as we had anticipated, and part of that is based on earlier in the year having less heavy market attached to our system, which has improved throughout the year. But on the light side of things, particularly light originating in Western Canada, we've seen those volumes coming in stronger than we had anticipated.

Faisal Khan - Citigroup

But do you attribute the lower heavy volumes, anticipated to more connection issues for the upstream? Is that a fair statement?

Guy Jarvis

Actually I don't think it was so much upstream as it was throughout this year, for example, BP Whiting has been ramping up their major program to consume more heavy. So earlier in the year, they weren't fully up and our ability to deliver to heavy markets was decreased, whereas now, particularly throughout the summer, BP and all of the other refineries on our system had quite a stable quarter. So our access to more market is better.

Faisal Khan - Citigroup

Line 61 superior to Flanagan, you said that's up and running and running at full capacity. Is that what's going on right now?

Guy Jarvis

I don't have the answer to that. We'd have to get back to you on that. I know it's in service, that's capable of that. How that's operating on any particular day, I don't have that information.

Faisal Khan - Citigroup

On the dropdown of the rest of Alberta Clipper and the accretion dilution, just curious, in terms of the decision to issue Class E units versus common units, what was sort of the logic behind that or strategy behind that? Is there a tax issue or a timing issue or was it an issue of you don't want to come to market with that much equity?

Mark Maki

That has quite a few reasons. Tax isn't one of them, though I would say that it's a relatively brand new asset, so you don't have something that had its basis ground down a ton. We've done a lot of work to try and mitigate the amount of equity needs that EEP has. Now parent is again another example of how supporting Enbridge has been to EEP and this is an example of it is they're prepared to step in and take equity in EEP's activity.

So I think it really is again just a sign that parent wants EEP to be successful. It's a very loud and clear demonstration of that. Besides a reasonable drop, it's got a nice accretion. They're taking equity and equity disproportionate to what the investment would normally require. You think of all the pipeline investment with the cost to serve the structure. To fund it with two-third equity is certainly strong. So I think again it's a strong statement that Enbridge Inc is supportive of EEP.

Faisal Khan - Citigroup

From here on now, assuming that Presidential permit is issued in mid-'15, would all the incremental volumes, I guess, on the US side of the border be associated with upside to EEP and how much of that is in your planning assumptions for distribution growth?

Mark Maki

Keep in mind the projects, this relates to largely our cost to service projects. So you're going to get a specified rate of return regardless of whether the volume actually moves or not. So we've already effectively dialed that into our distribution outlook and there may be some modest upsides that come from index volume that move in the system. But by and large, it's already been factored in.

Faisal Khan - Citigroup

But the customer commitments are there, the revenues are there only of the project that's up and running, right?

Mark Maki

Project has to be up and running and in service. And as Guy pointed out, it's pump stations in the US and those will be up, ready and available for service.

Faisal Khan - Citigroup

On the interest rate hedges, the ineffectiveness, I guess that was all non-cash. But can you just talk about was that a result of the hedges that actually didn't work at all, so there is a loss somewhere on the accounting and financial side, or is it just something else? Is it just an accounting issue and it doesn't matter?

Steve Neyland

What we've done is as the timing of our projects has moved out, our need to issue debt and the timing of those debt issuances has moved to later periods. And so we've rolled those hedges into future periods. And when we did that roll, the underlying or the initial amount has moved, then it's deemed ineffective from accounting US GAAP perspective and it will apply to recognize that loss or that change at that time. So again, it is non-cash and it really ties to the fact that we've rolled those hedges to future periods to accommodate and line up with the change in the capital spend profile.

Operator

Our next question comes from the line of John Edwards with Credit Suisse.

John Edwards - Credit Suisse

One of the things I was thinking about, earlier in the year, you indicated you've identified $10 billion of projects for dropdown from ENB to EEP. And in light of the distribution growth outlook, the 2% to 5%, why not accelerate some of those dropdowns so that you're at the top end of your range pretty consistently? I mean you can enlighten us on the potential drop process there.

Mark Maki

Well, I think, John, you're certainly seeing the Clipper drop. And if you think about the various actions that are taken by the parent to help EEP, whether it's the IDR restructuring and now the Alberta Clipper transaction, we've got the call options and debt in existing projects and clearly the need at parental level is there is $44 billion in growth projects either secured or projects that are going to be coming in the near future. There's definitely need for that. I think we're positioning EEP to be capable of taking the dropdowns from the parent. We have not laid out a schedule, a specified time, so forth. EEP still has to finance, though, its organic projects. And we think we've got that well in hand, want to make sure that that continues to be the case. And as continue to perform as we have of late, we got to be able to be in a position to take more dropdowns from the parent. Works for both parties as the Clipper transition is done.

So this is an important one to watch. We'll see how it goes and expect it go very, very well. And we've got our call options and then to add something on top of the call options, I'm sure as a parent we'll be thinking about that when the time comes.

John Edwards - Credit Suisse

Have you taken on more insurance coverage in light of this rising liability, if you will, from the Michigan incident a few years ago? I think you had about $600 million or so before. Have you taken that up to, say, over $1 billion in the wake of that incident, or maybe you can talk about process there?

Mark Maki

Yeah, we've had very modest increases in the amount of liability coverage that we have, John. It's just not top off mind. I think it's $700 million of liability. It's very, very expensive beyond that particular point. If you go back over our history, the Marshall incident was without question really a confluence of a number of very, very difficult and bad events in terms of what it cost ultimately. So we just don't see a lot of value in ensuring for another Marshall, especially if you consider what the company has done in terms of the response, the capabilities that company has, the additional investment we've made in terms of new pipelines, replaced Line 6B, going to replace Line 3, the integrity program we've announced on our Line 10.

We've done a tremendous amount and we've got more work to do, as Al often highlights, at the Enbridge Inc level. So I think this is an example we're adequately insured against the risk and it is insurance. It's not mention every conceivable potential incident. It covers off what we think to be the likely incidents and then some.

Steve Neyland

And just to confirm that number, that is $700 million in the aggregate insurance liability for environmental for Enbridge Inc.

John Edwards - Credit Suisse

So basically what you're saying is to cover more than that from a rate perspective, it's not cost effective to take that on?

Mark Maki

For the company of the size of EEP and the ability to handle, I don't see any point to ensuring at $1 billion or $1.2 billion or whatever you all look that.

Operator

Our next question comes from the line of Ross Payne with Wells Fargo.

Ross Payne - Wells Fargo

What kind of cash flow impact do you think this additional Griffith to Sarnia segment might give you in the future quarters? Getting back to some of these dropdowns with ENB, any other near-term targets you would have in terms of projects that could be dropped?

Mark Maki

With respect to other drops from the parent that we target, certainly other interest in Eastern Access, I mean not expansion, beyond what we have is call option would be of interest to EEP. That would be probably number one. Anything on the existing mainline would be certainly ideal initial candidate. After that, you start talking about projects like Flanagan South or Enbridge's interest in, say, the Seaway system. There's also Toledo pipeline, Chicap, Mustang, would be a couple of others that are ancillary to the mainline system also could be looked at. The Line 3 project is going to be jointly funded, again which will be another key project. So all those are laid out in some detail in EEP's Analyst Day from last year.

Steve Neyland

It kind of speaks a little bit of what on Slide 11 is we have full quarter participation of Eastern Access and mainline expansion Line 61, also to get a higher run rate for the fourth quarter. And we'd expect that the Eastern Access contribution of that is somewhere in the $20 million to $25 million incrementally Q3 to Q4, probably at the higher end of that range. You get piece of it in each of the quarter.

Operator

Ladies and gentlemen, this concludes the question-and-answer portion of today's call. I will now turn the call back over to Sanjay Lad for closing comments.

Sanjay Lad

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 participation in today's conference. This concludes your presentation. You may all disconnect. Good day, everyone.