Good morning. My name is Angel, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy and Spectra Energy Partners Second Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

Thank you. Julie Dill, you may begin your conference..

Thank you, Angel, and good morning, everyone. My name is Julie Dill, the Chief Communications Officer for Spectra Energy. Thank you for joining us today for our review of Spectra Energy's and Spectra Energy Partners' 2015 second quarter results.

With me today are Greg Ebel, President and CEO of both Spectra Energy and Spectra Energy Partners; and Pat Reddy, Chief Financial Officer of both companies. Pat will discuss our results for the quarter and then Greg will update you on our growth opportunities and the progress we're making on our Drive to 35.

And as always, we'll leave plenty of time for your questions. Our Safe Harbor statement is contained within our presentation materials and available on our websites. This disclaimer is important and integral to all our remarks, so I would ask that you refer to it as you review our materials.

Also contained in our presentation materials are non-GAAP measures that we reconciled to the most directly comparable GAAP measures, and those reconciliations are also available on our websites. So with that, let me turn things over to Pat..

Thank you and good morning, everyone and thanks for joining us today. As you've seen in our news releases, both Spectra Energy and Spectra Energy Partners delivered very strong ongoing EBITDA for the quarter.

But before I get into the details of those results, I want to discuss some special items we recorded during the quarter, as shown on slide three. There were three special items which lowered reported EBITDA by $217 million or $0.20 per share. As you can see on this slide, only one of these items affected DCF by $11 million.

The first item is $194 million pre-tax non-cash charge or $122 million after-tax, which represents our 50% share of a goodwill impairment at DCP. The second item also is associated with DCP and it's a pre-tax non-cash charge of $12 million, related to our share of a loss on the sale of an asset, during the quarter.

Lastly, Western Canada recorded a pre-tax special item of $11 million, related to employee and overhead reductions. We expect there will be some incremental charges of less than $10 million, related to these efforts that will be recorded in the third and fourth quarters.

Our ongoing EBITDA increased year-over-year, so let's turn to those results, which really tell the story of the strength and resilience of our business model. As noted, we delivered very strong second quarter results, with ongoing EBITDA of $652 million at Spectra Energy and $456 million at Spectra Energy Partners.

Given the current macro environment, it is significant that Spectra Energy's ongoing EBITDA increased 4% quarter-over-quarter. As we consistently demonstrated year-after-year, our portfolio of assets is structured to moderate the effect of various business cycles, and maximize the upside benefits. And with approximately 95% fee-based earnings at U.S.

Transmission, that have no exposure to commodity price or volume fluctuations, SEP is a standout in the MLP space. So, let's take a look at the drivers of our results by segment. I'll start with Spectra Energy Partners, whose EBITDA was up almost 30%. SEP is comprised of our U.S.

Transmission and Liquids businesses and is shown in the upper right-hand corner of slide four. U.S. Transmission delivered EBITDA of $396 million, up $76 million. That is almost 24% higher than the same quarter last year.

Results for the 2015 quarter were driven primarily by increased earnings from expansion projects placed into service, specifically TEAM 2014, TEAM South and the Kingsport project. Our Liquids business reported second quarter EBITDA of $78 million compared with $51 million in 2014.

The increase was primarily driven by higher volumes and tariffs on the Express crude pipeline, as well as higher equity earnings from increased volumes on the Sand Hills natural gas liquids pipeline. As you can see, SEP is performing very well and delivering results ahead of our expectations.

Moving to the table on the left-hand side of the slide, Distribution reported second quarter EBITDA of $98 million, compared with $112 million in 2014. The decrease quarter-over-quarter was due almost entirely to the decline in the value of the Canadian dollar, which was down 13% this quarter compared with 2014.

Western Canada recorded ongoing EBITDA for the quarter of $115 million compared with $111 million last year. Higher earnings at Empress offset the effects of the lower Canadian dollar. With respect to FX, the 13% reduction in the Canadian dollar affected EBITDA for both our Canadian business segments by $26 million quarter-over-quarter.

Fortunately, about two-thirds of that number is naturally hedged on a net income basis. So the change in net income related to FX was only $6 million. Now, a number of you have expressed interest in how the current operating environment in Western Canada might affect our business risk going forward.

So I want to take a moment and speak to the business model of that segment. First, 95% of our Western Canadian business, including gathering and processing, is fee-based with no direct commodity exposure or volume risk on existing contracts.

While the Canadian pipeline model is similar to the model used in the U.S., it's important to remember that the Western Canadian G&P structure is different from the more commodity sensitive model that largely exists across the U.S. G&P business.

Second, as you're aware, we implemented a risk management program at our Empress processing facility to reduce cash flow volatility. At our February Analyst Day, we said that we expected Empress to generate approximately $30 million of cash this year, and we're on track to exceed that forecast for 2015, given the hedges we put in place.

Looking forward to 2016, we've hedged about half of our targeted sales levels at positive margins and we will continue to opportunistically layer in hedges as the year progresses.

It's also important to note that nearly all of our Empress propane and butane sales contracts and our hedging program are linked to Conway and Mont Belvieu pricing, not Edmonton. Moving on to DCP, our 50% share of DCP's ongoing EBITDA was a negative $27 million in the quarter, compared with $54 million last year.

As expected, the decrease is primarily due to significantly lower commodity prices, which are down about 50% from last year's levels. These decreases were partially offset by increased earnings growth or increased earnings from asset growth, improved operating efficiencies and savings from other strategic initiatives.

While we'd all love to see stronger commodity prices and positive earnings at DCP, I would remind you of counterintuitive effect, DCP's lower earnings have on Spectra Energy's cash flows. Since distributions from DCP can't drop below zero, its negative earnings benefit our DCF by ultimately lowering our cash taxes.

So, overall, Spectra Energy's ongoing EBITDA was up quarter-over-quarter despite both lower commodity prices and a lower Canadian currency. And again, the results at SEP reflect its significant organic growth, strong fee-based earnings and virtually no commodity or volume exposure.

Importantly, these results exceeded our budget expectations for the 2015 quarter. Let's take a look our DCF schedules, beginning with SEP as shown on slide five. SEP's standalone distributable cash flow for the quarter was $321 million, $82 million more than the same quarter last year with distribution coverage of 1.3 times.

This higher DCF was directly attributable to the higher EBITDA I just described. For the full year, we expect SEP's coverage to be at least 1.1 times, consistent with our 2015 forecast. SEP paid general partner and limited partner distributions to Spectra Energy for the quarter of $56 million and $145 million respectively.

And earlier this morning, SEP announced its 31st consecutive quarterly distribution increase of $0.0125 per unit. We continue to see strong interest in our ATM program at SEP. To this point in the year, SEP has raised almost $350 million through this vehicle.

Given the attractiveness of SEP's investor value proposition and the lack of commodity and volume exposure, we expect continued utilization of the ATM program throughout the year and can further expand the program if needed. Let's turn now to Spectra Energy's distributable cash flow as shown on slide six.

At Spectra Energy, distributable cash flow is $274 million for the quarter, in line with last year. Coverage was 1.1 times and DCF per share was $0.41. Year-to-date, we're at 1.7 times coverage and by the end of the year, we expect coverage to be at least 1.2 times, consistent with the forecast we provided at the beginning of the year.

Total available liquidity across the entire Spectra Energy enterprise was $3.5 billion as of June 30. So, while we still have a little less than half a year ago to go, we're feeling very good about how the businesses continue to perform.

We're ahead of where we thought we'd be at this point in time in terms of EBITDA and DCF, despite the current environment. We're very pleased with our performance to date and expect to continue to deliver on the commitments we made for the balance of the year.

So with that, let me turn things over to Greg to talk about our growth opportunities and the progress we're making on our Drive to 35..

Thanks very much, Pat and good morning, everybody. As you just heard, the results we delivered this quarter underscore the stability of our overall earnings and cash generation capabilities.

I think that stability comes from a well-positioned high-performing portfolio of assets that allows us to generate value creating DCF regardless of commodity or market fluctuations. It also reinforces our confidence and our ability to deliver ongoing annual dividend growth of $0.14 per share, while maintaining coverage at or above 1.

Pat mentioned that we realized strong results for the quarter at both Spectra Energy and SEP, that's significant and worth repeating. We believe the strength of our businesses and financial structure are important differentiators, allowing us to deliver consistent and dependable growth.

With everything that's occurring in the energy space, I want to take a minute to share our priorities for driving growth and increasing shareholder returns for both Spectra Energy and SEP investors.

It goes without saying that safe, reliable operations of our assets is a big element of Spectra Energy's success and so we are steadfastly focused on day-to-day operations. That focus ensures that our customers' requirements are met in a safe and responsible manner.

And my confidence in our operating team's ability gives me more time to concentrate on four other major areas. First, ensuring that we successfully execute on the secured project backlog that we already have and that we do so on time and on budget.

Our execution advantage really does differentiate us, especially when you consider that most projects take several years to come into service given the current regulatory process. As you can imagine, this is no small undertaking, but we continue to deliver.

This year we've already put $600 billion of expansion capital into service and this amount will grow to more than $2 billion by yearend. Second, I'm focused on securing contracts for projects that are in development.

While our track record would suggest we're successful in signing up the majority of projects we pursue, we know it's not possible to secure all of them. With that said, we continue to expect that we will secure contracts of at least another $20 billion at attractive returns by the end of the decade.

To-date, this year alone, we've moved more than $1 billion of projects into execution and we expect to add to that in a meaningful way by yearend.

Third, with our partner Phillips 66, we continue to focus on the appropriate structure of DCP to ensure that DCP and DPM are set up in a manner that provides the best opportunity for the owners to realize their value. As we said before, we expect this matter will be resolved in the October timeframe.

As we work our way through the process our ultimate objective remains ensuring that any structuring outcome still allows DCP's enterprise to retain and grow its number one position in NGL production and gas processing, and that it positions DCP to efficiently finance that growth.

Lastly, I'm watching for industry consolidation opportunities that fit our portfolio strategically and add value to our shareholders.

Our current Drive to 35 backlog does not contemplate any M&A activity, but as we've mentioned before, we're constantly looking at opportunities that complement our business portfolio and profile and advance our value creation objectives. So, with that, let me now turn to our projects in execution.

As you've heard Pat mention, Spectra Energy and SEP's second quarter results benefited from new assets we successfully put in the ground last year. But we've also had two projects that moved into service since our last earnings call, totaling about $600 million, so let me begin with those. At U.S.

Transmission, the Uniontown to Gas City project commenced service well ahead of its original November 1 in service date. And DCP placed the Lucerne II processing plant in the DJ Basin into service since our last call along with several smaller gathering projects.

We also have about $1.6 billion in projects that are nearing completion and are on track to go into service later this year. Our OPEN project will bring incremental Marcellus and Utica supply to southern markets beginning in November, if not sooner. Our 2015 Dawn-Parkway project is scheduled to go into service at Union Gas during the fourth quarter.

DCP is in the final stages of starting up its Zia II processing plant in the Permian. And at our Liquids segment, the Red Lake lateral to expand the reach of Sand Hills to access growing Permian production will go fully into service once Zia II comes online.

Placing projects into service on time or even ahead of schedule is an example of how we've built our track record of delivering on our execution promises, an advantage for both customers and of course investors. We've got a full complement of great projects in execution, which are detailed on this slide.

I'll start by highlighting three new projects that we recently moved into execution. You'll recall that during last quarter, we mentioned open seasons that were underway for projects that would further connect Marcellus and Utica supply to demand markets. Since then, we moved our Lebanon Extension project into execution.

We've secured commercial commitments for the project and are proceeding with the FERC approval process and anticipate a 2017 in-service date. We also moved the High Pine project into execution. High Pine is another project in Western Canada that will further expand the BC Pipeline.

You'll recall that we announced a binding open season for this project during our last earnings call. And we were able to quickly execute our commercial agreement to move the project forward. This $325 million project will have a late 2016 in-service date.

Another project we moved into execution this past quarter is the 2017 Dawn-Parkway project at Union Gas. Commercial contracts underpinning this $620 million project have been executed, and a facilities application has been filed for approval with the Ontario Energy Board.

Other projects in execution are also proceeding well and are on track to meet their respective in-service dates. All of these projects are underpinned by executing customer agreements that are unaffected by commodity market conditions.

In fact, you'll note that about 75% of our expansion CapEx is driven by natural gas demand pull projects rather than supply push. During the quarter, both the AIM and 2016 Dawn-Parkway projects began construction and are on track to be in service in the second half of 2016. NEXUS is on track for its fourth quarter 2017 in service date.

We completed a major milestone in the regulatory process for this project by submitting our FERC resource reports in June and we anticipate filing a formal FERC application later this year. Our execution efforts also continue on two projects in Western Canada to expand our BC Pipeline; the Jackfish Lake and RAM projects.

We expect both of these pipeline expansions to go into service during 2017. As you know, LNG projects on the West Coast of Canada and the U.S. have been delayed, given current market dynamics. However, producers still need to move natural gas.

So this LNG deferment has led to these new opportunities for us in our Western Canadian pipeline, totaling about $1 billion already this year. The pipeline expansion opportunities we're seeing in British Columbia, underscored the benefit of having an expansive and strategic existing footprint in a region.

At a time when the Montney region producers are looking for the lowest cost option to move their product quickly to the Pacific Northwest or Eastern Canada or Alberta markets, having steel in the ground already is clearly a competitive advantage for us.

So, wrapping up the review of projects in execution, we will have brought more than $2 billion of projects into service by yearend, creating additional earnings and cash flow for 2016 and beyond.

We're making great progress on all of our projects in execution, and we continue to further expand our execution backlog by adding about $1 billion of projects over just this last quarter.

You've seen our impressive slate of projects in service and in execution, projects that will deliver the earnings and cash flow we laid out in our three-year plan for you in January and February.

In addition to our backlog of projects in execution, we have a healthy portfolio of opportunities in development that will lead to continued growth and we're working diligently to move those projects forward. Let me take a look at some of our projects that are in development.

Access Northeast, under development with Eversource and National Grid, continues to advance quite nicely. Unlike other projects in the region, which are intended to serve gas LDCs in New England, Access Northeast will serve the electric power market.

Project customers including Eversource, National Grid and Central Maine Power serve more than 80% of the 6.5 million electric customers in the region. The project will expand the Algonquin and Maritimes systems, utilizing their existing footprints.

We expect the customers to file agreements with their respective PUCs soon and we anticipate moving Access Northeast into execution later this year or early 2016, once state regulatory approvals have been received by our customers.

An interesting note for you, we've already seen a record summer-time demand from power generators on our existing Algonquin and Texas Eastern lines this year.

With new number one delivery days of more than 800 million cubic feet a day on each of these lines and daily average deliveries to power generators up 21% over 2014 on Algonquin, and up 33% over 2014 on the Eastern Market Zone 3 of TETCo. Also under development are two Marcellus and Utica expansion projects.

The Greater Philadelphia Expansion and Marcellus to Market projects, which received positive responses to open seasons during the quarter and discussions with potential customers, are underway.

Moving to Western Canada, we kicked-off another binding open season in late July to further expand the T-North section of the BC Pipeline, and we expect the results from that this fall.

As I mentioned earlier, we're extremely pleased with the level of producer interest we're seeing for our BC Pipeline, and we're exploring ways to further serve producers in the Montney region. Customer interest also remained strong in our large-scale crude oil projects and development.

While we continue to expect a late in-the-decade timeframe to secure commitments to advance these projects, in the interim we'll seek smaller scale optimization projects similar to the $135 million Express Enhancement project currently in execution. To summarize, we made significant progress during the quarter on our Drive to 35.

In fact, we're more than halfway to our goal with $8.2 billion in service now and $9.6 billion in execution as I speak. We continue to advance our projects in execution and development to generate incremental cash flow and of course shareholder value. As you've heard today, Spectra Energy delivered solid results for the quarter.

We're disappointed of course that our stock price isn't reflecting the strong performance of our businesses. We're not alone. The energy sector is being painted with a far too broad brush and suffering the consequences of perception that all energy cash flows are correlated to commodity prices.

That's just not the case, of course, and certainly not the case for Spectra Energy and SEP. The current environment allows investors to differentiate between investment options. So let me take a minute to remind you why Spectra Energy and SEP are best-in-class investment opportunities.

We understand what investors are looking for, and Spectra Energy and SEP offer all those attributes. Specifically, we know that investors prefer strong portfolios. Our unrivaled footprint connects all the major North American supply basins with growing demand markets. You could not replicate our geographic positioning nor reach today.

Our healthy mix of businesses are structured to minimize the effect of multiple and varied market cycles. Next, we know that stable reliable cash flows are important for investors as well.

As we told you back in February, 99% of Spectra Energy's EBITDA for the 2015 to 2017 period will come from our fee-based businesses and our DCF forecast is virtually unexposed to incremental commodity downside. And SEP is barely unique in the MLP space, as 95% of U.S.

Transmission revenue, the largest component of SEP and Spectra Energy for that matter, is reservation based with no commodity nor volume exposure.

The average remaining contract term within our gas pipeline business is about nine years and the Express crude pipeline has an average contract term of 10 years, thanks to the contract restructuring we've done since acquiring this system in 2013.

Investors seek companies with robust growth profile and again we're making great progress on our Drive to 35. By 2020, we'll grow our EBITDA by about $1 billion and approximately $800 million at Spectra Energy and SEP respectively. That the projects that we have in execution are moved into service and begin generating cash.

And with the ongoing growth and the demand for natural gas and natural gas infrastructure, we have tremendous confidence in realizing our projects in development. Healthy financials are also important and we have the financial flexibility to efficiently fund our growth projects and pursuing new opportunities.

We have two solid currencies, strong investment grade balance sheet and disciplined financial management. Investors look for strong track records and proven performance, and you've heard me talk about our execution advantage and that's another feature that sets us apart.

Since 2007, we've delivered more than 70 projects into service for a capital expansion investment of about $9 billion, a record that speaks to our level of accountability and achievement. Lastly and most importantly, investors want to track the returns, and Spectra Energy has done that.

In the past five years, our annual dividend per share has grown from $1 to $1.48 and we're committed to continuing to grow Spectra Energy's dividend by at least $0.14 per share through 2017.

Similarly, SEP has delivered 31 consecutive quarters of distribution growth and we're committed to continuing that track record with an 8% to 9% annual growth rate through 2017.

So those are the attributes that differ Spectra Energy and SEP from other energy companies, and why we believe so strongly that both entities offer a best-in-class investment opportunity today. With that, let me turn things over to Julie, to take your questions on the quarter..

Thank you, Greg. And so now we're going to open up the lines for questions.

Angel, would you please provide instructions on how folks can ask those questions?.

Certainly. Your first question comes from the line of Christine Cho. Your line is open..

Hi everyone. Congrats on a great quarter..

Good morning..

So, some questions on SEP and the strength we're seeing there. You guys talk about in the release how the increase in quarter results were mainly due to three projects. The TEAM projects were put on September and November of last year, I think.

So we've already seen one or two full quarters from these assets, yet the beats in earlier quarters were nothing like they are today.

So did the reservation payments for these assets not all come on day one or are they ramping up through the year? Any color on how we should think about that for these assets and maybe your other pipeline projects that are supposed to come online in the future would be helpful?.

Sure. I'll – you're right, there is some ramp up. So TEAM 2014, TEAM South, the Kingsport project as well didn't have as quick a start up until, ramp up in revenues until the new year and I think a little bit better results on the New Jersey and New York project as well than we expected.

I think through the rest of the year, call it, $5 million, maybe $10 million on the projects that we've brought in early, will be helpful, Christine, for the rest of the year as well..

Okay. And then, I guess kind of going off that, when we look at your SEP guidance, even if we were to keep EBITDA flat from second quarter and third quarter and fourth quarter, you guys would still come in $80 million over guidance.

Given you still have some projects coming online the remainder of this year and we actually still have our winters to go through, would it be fair to say that your guidance is very conservative or am I missing something that may provide some offsets in the second half of this year?.

Well, as you know Christine, we don't change – we come out with our numbers at the start of the year. I think historically, if you looked at the last few years that we've doing DCF, we've typically under-promised and over-delivered.

But you still do have two quarters to go and of course, well, it wouldn't have affected first SEP that much in the first half of the year. The good strong cold winter was also helpful in some regards in terms of additional interruptible revenues.

So I'm not changing the forecast, but I think history would say we do try to under-promise and over-deliver..

Given most of your cash always is fee-based than take-or-pay, how should we think about a distribution increase above guidance or holding it to maybe fund some of your projects?.

Yeah, I think that's the balance. It's interesting, because I know historically you and I have chatted about this. Some people may have had faster growth than us, but I think kind of I'd call it 8% to 10% outlook on distribution growth and frankly on dividend growth in that range is the way to think about it.

And I think you see companies actually when our (30:12) dividend growth and distribution growth has actually moved up, you're seeing actually other companies come down to a number more in line with ours.

So, we look at dividend policy and distribution policy on a regular basis, but really make decisions on an annual basis towards the end of the year..

Okay..

Hey Christine, this is Pat. I think one thing you know is that, you can't levelize things like maintenance CapEx during the year. So for example, we've been averaging about 60% to 70% of our maintenance CapEx in the third and fourth quarters.

So, we're not changing our outlook for maintenance, but we're just saying, remember that there is a ramping up in the last half of the year..

Okay, great. And then just, in the Western Canadian segment, obviously the producers up there exposed to the Edmonton propane prices must be struggling with netbacks. I've seen data that indicated that the frac spread in Canada is actually not that much different from the U.S.

due to lower AECO prices and natural gasoline prices that are higher in Canada, which surprised me a bit, is that right?.

Yes..

And as we think of – yeah..

Well, I was just going to say, I think that's a fair comment. I would say you don't have as liquid a market up there, A. B, you've got – you did effecting propane prices some infrastructure issues coaching (31:39), et cetera changes. I guess the point I would make is that remember the Empress business is very much a Conway business.

So, wouldn't get – at least as with respect to our business, wouldn't focus too much on Edmonton as opposed to what's going from a Conway perspective..

Well, I was more thinking about the outlook for G&P.

What that would do – what that's doing to the rig activity in Western Canada in reaction to the prices? And also, if you've heard about any solutions that are being talked about for propane in the region? I've heard of some potential LPG exports in Western Canada or off the coast of Washington, do you think either of these could happen, or too much regulatory red tape?.

I actually don't think its regulatory red tape too much. I actually think it's volumes. Remember Western Canada produces about as much liquids as the entire industry, as DCP would produce. So, you need a lot of volume and at depressed NGL prices, I think it's kind of tough from that perspective.

That being said, I think June had the highest production out of Western Canada in a very long time, I think 13 Bcf or 14 Bcf. And while you're right, you're seeing rig counts come off, you are still seeing a lot of gas being produced.

And I think you see that effect hitting our pipeline business, which as you know is a very long-term fee-based contract perspective. And I'm not sure many people would have predicted that Spectra Energy would have added $1 billion dollars in pipeline projects this year into our backlog out of Western Canada.

And I think that you've going to have ebb and flows between G&P and from pipelines, but investors in the E&P business are going to be happy that the producers have pipelines that can take gas down to the Pacific Northwest and Alberta.

So, yeah, lots of solutions being worked out, but I don't see a huge NGL solution in the near-term in Western Canada..

Okay. Great. Thanks for all the color. Last question for me.

Can you remind us how exactly the fee-based G&P model works in Western Canada? It's fee based, but is there exposure to volumes or is there some sort of demand payment that also needs to get paid, is the contract for a certain number of years so is there re-contracting risk? Some detail about that would be helpful..

Sure. So, you should think of it very much as like negotiated pipeline rates in the United States. So, we sign up contracts for processing plants, long-term contracts, I think like the Dawson project that we put in place a couple of years was a 20-year contract, with a set fee that is not volume risked.

In other words, unlike how you often see G&P in the United States, it's not volume risked. Now, at the end of contract life, just like on a pipeline in the United States or Canada, you are exposed to re-contracting. So, that's obviously – that's something you're always looking at.

But I think our average contract life would be three years to five years for the overall whole portfolio and I said projects like Dawson, more like 20 years. So, think of it much more like a negotiated rate pipeline as opposed to just cost of service..

Thank you so much..

Okay. Thank you..

Your next question comes from the line of Darren Horowitz with Raymond James. Your line is open..

Good morning, everybody. Greg, couple of quick questions for you. The first on the two Appalachian expansion projects that you discussed.

Just given the recent shift in basin dynamics and not only the imbalance between supply growth and demand, but a lot of the pipe options out of the region and the impact on regional pricing differentials, maybe shifting economics or at least net back incentives.

I'm just wondering if anything has changed from a customer thought process in your perspective.

Maybe a better way to ask the question is, if you could kind of quantify or give us some color on what a positive response to the open season means? And then, secondly, the one project that wasn't discussed was that Texas Eastern Lebanon expansion project, and I was just wondering, in terms of incremental CapEx to scale that project up, if there could be any opportunity for that..

Well, I think a variety of questions in there, and fortunately Bill Yardley is in the room as well, but really, I would say customers have the same message, get my product to a demand market, very simple, or get me partial (36:17) on the trail.

And so, you've seen us put a variety of projects that not only might take gas and molecules a long-distance, but actually to the next closest liquid point. So, you will see the projects ebb and flow in terms of their size. I don't think there is anything restricting customers from signing up.

Sure, E&P customers are very focused on their cap spend and where they think commodity prices will go but – and I think the Lebanon project, as you'll see on one of the slides that we've put out of the $9 billion, we did put it into execution this quarter, Darren.

And I would say, it's lumped in with the Access South and Adair Southwest Extension, because they really are in many respects, for some different customers achieving similar type goals. So, even in the way we're going to FERC and have those approved, we have lumped them as one project. So you continue to see projects morph.

And I think the underlying facet that's really critical and a real advantage for Spectra, we already have assets in the ground. So, we're going to – and I hear a lot of discussion about reversing flows and stuff, jeez, guys we've been doing that for a number of years now. So, I know other folks are starting to think and get to that.

That's not novel for Spectra or its customers, and I think that's why you're seeing some of the results that you are seeing.

Bill, I don't know if you want to add to that?.

No. No, I think we're still seeing some pretty good interest in both the Marcellus and the Utica regions from producers. That's a little bit longer lead time than perhaps it was a couple of years ago, but we have a lot of faith in these two projects, both Philly and Marcellus to market come to fruition at some point in the not-too-distant future..

Okay..

Yeah. I think the gating issue as well, it's just – I mean, look, to build anything these days is expensive. And I think that as always in any good business relationship, there's a negotiation back and forth and you've got to find the common ground where it makes economic sense for both parties..

Yeah. I think that makes sense. Last question from me is just on Access Northeast and I realize, it's still under development and a little bit of a moving target.

But when you think about the ultimate scale and scope of that $3 billion project and then you reconcile that with a lot of the proposed consolidation in the area, and maybe again a bit of a shift in terms of scale and scope of some competitors' pipes.

To your point and I fully agree with you, I mean, obviously, following Algonquin and M&N gives you, just from a footprint perspective and a right-of-way perspective, a bit of an advance, but a little bit of a timing shift here obviously, from a regulatory perspective and certainly that's not getting any easier.

But I'm wondering just with some of the different proposed consolidation dynamics, economies of scale and what could come out of that area over the next possibly 12 months to 18 months.

How could that impact Access Northeast, either in ultimate scale, scope from a timing perspective or from a further growth opportunity standpoint?.

Yeah. Again, I don't think that'll change the timing. I mean, as I noted, just volume increase we're seeing in terms of our deliveries to generators, I think – and remember this is the summer, where the challenge is really in the winter, and we're already seeing 20%, 30% increases up there.

I don't think there is that time if they want to keep the lights on. And I think the Eversources and National Grids of the world, which represent what's 5.5 million of the 6.5 million customers up there, Bill, I think they recognize it. So, I don't see big changes there.

I would also say that doesn't take away from any projects that are also needed out there. Remember, our AIM, our Atlantic Bridge projects are about LDCs. That's already in execution – well in execution. The other projects about the Access Northeast is about electric. Other folks' major projects being pitched are LDC-related projects.

So, I think the dynamics don't allow for changes. I think the dynamics that we're seeing are more like additional projects will becoming forth over the following years.

So, if you think that we've got – we have 16, 17, 18 projects coming in service, if you look at gas demand in North America going from 75, call it, Bcf a day to 100 Bcf, 110 Bcf a day, in the next 10 years, despite what any brilliant policy might be coming out of various government officials, that will happen.

And those, most of that's going to happen in the Northeast and that's advantage pipeline. That's got to happen unless people are willing to let lights go out, get colder; at this time of year, get awful hot and sticky in the Northeast..

Thanks, Greg..

Your next question comes from the line of Brandon Blossman. Your line is open..

Good morning, everyone..

Good morning..

I guess real quick, just following on Darren's question.

Access Northeast, the PUC process that is kicking off, what insight do you guys have into that, and/or how do you handicap it as far as an outcome here?.

Bill?.

Yeah. Sure. So, hey Brandon, it's Bill Yardley. We're really interested in all six New England states is that, as an overarching statement, I'd say that, we've got pretty clear authority in one state, Rhode Island and the other four states are going through some sort of process. We expect those processes to be very clear by year's end.

At the same time, we'll be preparing the contracts for the seven utilities that we have – that we're negotiating with, we'll be submitting those with each respective state. And then of course, entering the pre-filing process, and then looking for those state approvals, as Greg mentioned, probably early next year..

Okay. Good. That's appreciated. Sticking with the Northeast, Uniontown to Gas City, online three months early.

I guess the question is what was the driver for that accelerated pace? And is there any read-throughs to the OPEN project or anything else that's happening in the Northeast?.

Well, I think depending on where you're working obviously, and I'll give our project execution team full credit. I mean we think this is an advantage we have, very keen on local game as opposed to state or national games in terms of getting stuff approved and the delivery was there. On OPEN, obviously our timeframe is still the 1st of November.

And I'm hopeful that we'll be able to do that early as well. Obviously, every day we can get that pipe in earlier, that has benefits from a safety perspective, from an operational perspective, and obviously from an economic perspective in many cases, not always the contracts ramp up early.

But I will tell you, the customers that have got the projects that are – they like it coming in earlier. Back to the point I was making that any time we can get their project the heck away from supply area to demand area, they'll take it all day long. So we're pushing as hard as we can. We obviously have a very systematic approach to doing projects.

This is not a new area for us. We're talking half a century of building stuff there and we're going to take advantage of that..

Okay, good. Thanks for that. And then just real quick bigger picture question. Montney customers you mentioned I think Greg in your prepared comments that there is an interest in finding a outlet that's not LNG for obvious reasons. My question is, is that a permanent solution bringing gas to the U.S.

instead of LNG or is this just a temporary outlet from the Montney customer perspective?.

Well, no. Well, I would say a bit of both obviously. We're saying, we have the long-term contracts cost of service based. I think it's a combination of both a longer-term solution.

Look, I will be surprised to see any on LNG on the West Coast of North America, definitely not going to happen before 2020 at this point in time, even if you saw approvals happen instantly just the amount of the work that has to get done.

So whether you think a six-year to 10-year solution is a long term or not, but I think you're talking about a while before those projects kick in. And remember, once as demand grows across North America, the Pacific Northwest Alberta production is often – has been declining, so Western Canada is not a single market.

And you're still seeing activity going on from a demand perspective in the oil sands of which much of the fuel they need to use is natural gas. So yeah, I mean there's no doubt the opportunity is being created by LNG deferment, but the amount of gas we're talking about is nowhere near the amount of gas that would be needed for LNG.

So, one is not going to replace the other, the LNG would just be incremental to that..

Okay. Perfect. Thank you for that..

Thank you..

Your next question comes from the line of Earl Lee. Your line is open..

Good morning, Earl..

Good morning. Hi, everyone. Just had a question.

If Congress passes the two-year extension of bonus deprecations, could you guys talk a little bit about how that would impact Spectra's distributable cash flow?.

Yeah. There sure seems to be a very growing momentum in Congress for least one, and it seems increasingly a two-year extension of bonus depreciation. So, as you may recall, we've lined out in our three-year forecast, we see about $300 million in cash taxes in 2016 and 2017. You could take about $0.75 billion off that cash taxes in 2016 and 2017.

So, rough numbers that makes your coverage 20% above your dividend, so call it 1.2 range. And so, that's obviously – out of everything folks are looking at, that's probably the most impactful change and probably the one that's on a pretty good momentum.

I don't have control over that, but I think the reality is that infrastructure builds in this country are critical. And I think Congress on a bipartisan basis obviously recognizes that and sees the benefits that have been out there. So yeah, we'll be watching that closely as we go through the rest of the year..

Okay. Thanks a lot, Greg..

Thanks, Earl..

Your next question comes from the line of Ted Durbin. Your line is open..

Good Morning..

Morning, Ted..

Morning.

Can we just talk about NEXUS a little bit? How much of the volumes – I think you're looking for 1.5 billion there – how much of the volumes you have contracted? What kind of tariff are you looking out there? And what kind of return are you going to – do you think you will get on those volumes that you have contracted?.

Well, if we – I think we're about 70% contracted, as you know, a big element that – an important element in that is the LDCs that are – I think account for about 40% of the volumes. They are going through their regulatory processes now. Those contracts have been filed for approval. I think the project – it's in that 8% to 10% range.

Obviously, if we don't have the full volumes there on start up, it's going to be more at the low end of that range, and I think the volumes actually are about 1.2 billion, Ted, in terms of what we're targeting on NEXUS. Could be up to a 1.5 billion, but I think our base economics are on 1.2 billion. And remember that's an unlevered after-tax IRR..

Perfect. Thank you. The next one from me is just, no commentary I think even – I must have missed in the prepared remarks around DCP.

You've sort of told folks that you've come up with some sort of I think solution around some of the leverage issues that are happening up at the LLC along with your partner PSX, any commentary you can give us there?.

Well, not much other then, yeah, I mean it's very much in line for that October timeframe. As you know, there has been a lot of self help there. I don't know if we've fully disclosed this, but there a couple of hundred million dollars worth of asset sales have already happened at DCP this year. That's helpful, about $70 million of cost effort.

So the management team is doing a very good job to manage that. The liquidity is in place to take us to the end of the year or into that October timeframe. We're well within that October timeframe. So, stay tuned, Ted. We continue to work on that and believe that given the partner's relationship, ongoing cooperation, we're going to get there..

Okay. We'll wait and see on that one. And then, last one for me. You did open the door on the M&A, I think in some of your comments.

So, kind of – and I'd love if you can just expand a little bit about what you're seeing in terms of the types of assets on the market, maybe bid/ask spreads fit with your system et cetera?.

Yeah. I'd be a little bit careful on that. Obviously, there's a whole range of stuff Ted, obviously from lot of asset sales out there are private equity, all that kind of stuff, so, it depends.

I will say, from a selling perspective, we've been very pleased what we've seen, very healthy multiples on what we've sold out of DCP, which were assets that weren't really key for us.

So, I'd say, maybe the best way to say is, look, the key is to expand the footprint where we can find synergies and to the extent we can use tax synergies, which a lot of other folks have already played that card, we have not. So, we'll be looking at that.

I mean, I guess my fundamental belief is obviously as we've doubled the size of the company in the last five years, doubling the size in the next five years is critical.

And could you leapfrog elements of that with some transactions that may come to floor, but obviously, it's a bit of a – it's not something you can plan on, it's not in our three-year plan. We don't need to have that happen to hit our targets. But, there is probably some people under stress and we aren't..

Got it. I'll leave it that. Thank you..

Thanks, Ted..

Your next question comes from the line Becca Followill. Your line is open..

Good morning, Becca..

Hi, guys..

Good morning, Becca..

Just following up on some of the questions that have already been asked.

On the industry consolidation, is there a limit on size for you guys?.

No. But there is only so many big players, I wouldn't say a limit on size. I think as my bottom-line would be size – size is an important element longer term, but I wouldn't say there is a limit on size. We've done everything.

If you look at the history from, call it, the $8 billion, $10 billion deals with Westcoast, which was – that's 10, 12 years ago to, call it $1.5 billion on a little pipeline.

So I'd say anywhere in the mix that moves the ball forward, but I wouldn't – I don't – size is not the determinant, it's far more the economic, strategic and footprint expansion that we're looking for..

Would you look at something as large as Williams?.

Well, I would – I guess, what I would say is that every transaction seems to come across our table, but I wouldn't go any further than that. I don't think there's any transaction out there regardless in any company that we don't look at, whether or not they are in play or not..

Okay. Thank you. And then, on Access Northeast, I thought I remembered you guys targeting definitive agreements by June 30.

And with Kinder going ahead and putting their project into their backlog even though it's not fully contracted, and realizing that you target a different customer base, is your project a go regardless of Kinder, assuming...?.

Yeah, the Kinder project is not a determinant on our project. We're fine with the customer agreements. The issue is to get them approved by the PUC, that's the gating issue for us.

I think it's fair to say Becca, that historically we would have put a project of this nature already in execution, but because of the unique element of an electric distribution company seeking approval for gas transmission capacity, which has not been done in that neck of the woods, that makes us a little bit more cautious.

But I think you even saw comments out of Kinder Morgan in recent days that in fact it's not one or the other, both projects are needed and that's where we've been for quite some time as well..

Understand. Thank you. And then the last on DCP, just wanted to clarify that your stance hasn't changed, that you would not put equity into DCP, and that you would not have a reduction in your ownership stake, not be willing to do that..

Well, yeah. I don't see the solution as us putting equity in, Spectra Energy equity, whether it changes our ownership, that's always something that I have put on the table, historically, we like the business. The issue is one of value, Becca.

And I think with any of our assets, we're portfolio managers, and so if the value is greater to not hold it than hold it, then we'd do the right thing from that perspective. Historically, we've never found that's been the case..

Great. Thank you, guys..

Thanks, Becca..

Your next question comes from the line of Elvira Scotto. Your line is open..

Hi. Good morning. Just a couple of quick ones for me. Looking at the Atlantic Bridge project, it looks like the estimated CapEx has gone down to about $500 million from $650 million before.

Is that a change in scope or is that just refining costs or can you provide a little detail on that?.

Bit of both. The scope declined a little bit from our perspective, so therefore that brought down the size. And obviously, we wanted to build for our customers and the customers that signed up. when we got the critical mass in terms of contracts, we said go.

So originally, we might have seen some more contracts on that, however, Elvira, when some of those customers couldn't make up their mind, we said go because we wanted to deliver for the folks that we already had in hand..

Okay, great.

And the return expectations would be in line with what your project returns typically are?.

Yeah, absolutely..

Okay, perfect. And then just going back to the consolidation question, are you looking across – would you look across hydrocarbons? That's number one.

And number two, would you look at any anything that would increase commodity price exposure at the SE level?.

No. Look, I mean, I think we've been very clear – well, first of all, let's remind everybody that if you look at our three-year plan, our DCF has virtually no incremental exposure to commodity prices. And we think that's a real value differentiator and I think you see that in the quarter.

So obviously, we're very focused on anything we do to be largely and the vast majority fee-based. Depending on an asset that we might buy, if it had some small element which may not stay in the portfolio from a long-term perspective of commodity, that's not going to stop me from looking at it.

The issue is what do you do with it from a long-term perspective. I'll give you a good example, it really isn't commodity, but sometimes you do things that maybe it's not a perfect fit, but turn out to be quite well.

When we bought Westcoast, Union Gas, which is still in our portfolio and with well in excess of a couple of billion dollars of expansion projects for a utility you wouldn't expect on pipelines, that may not have fit perfectly, but it's been a good generator. Meanwhile, other utilities that we held when we bought Westcoast, we had sold those assets.

So, I think it's – but none of that would have stopped the big prize (57:31) of what we looked at on Westcoast, which was really the pipeline operations that we liked in Canada, but the focus is definitely from a fee-based perspective..

Okay, great.

And then, just going back to DCP, the October timeframe, is that a timeframe where we'll get an indication of what the resolution will be or is that when a resolution will be implemented by? And is there anything special about October?.

Well, nothing really special about October, although I would expect you'd have both a combination of a completion and more than an idea, the actual firm plan of what we plan to do in that timeframe. Whether it's all fully implemented, we'll just have to clarify that when we announce something, Elvira..

Okay, great. Thank you very much..

Okay..

Your final question comes from the line of Shneur Gershuni. Your line is open..

Hi. Good morning, guys..

Good morning, Shneur..

Most of my questions have definitely been asked and answered, but I was wondering if we can just do two little follow-up questions related to DCP. I realize you're not providing an update on the strategy at this stage right now. But you've been very resolute in the past in saying that money goes one way.

Has that changed at all, just given how bad the NGL market has been? Or can we still continue to assume that SE will not be injecting any capital into DCP?.

Look, I think we've been clear that we don't plan to put SE equity into it. We have supported it in a variety of ways historically and today. So, I don't want to split hairs here but Shneur, as you know, over the next three years, we have foregone our right to take distributions that are available for us to take.

So, I don't want to – it would be hard to say that's not us leaving cash, not taking cash out. I guess we could have brought it home and given it back, A. So I think we do put cash in from time to time. The point is we're putting SE equity in it, A. And B, we've also bought assets and that's worked out well, as they're fee-based.

We own a third of those NGL pipelines, which are really great assets. So, I think I'd look at it that way, but yeah, I would say that's no change in the position we have had historically..

Okay. Cool. That's what I thought and wanted to confirm and I realize it was just splitting hairs there. But yeah, specifically, SE equity is not going in. And then, the second question Pat, you had sort of talked about the perverse tax benefit as a result.

And so, basically the more DCP loses, effectively the better it is for you on a cash flow basis, at least in the near term until you max out the tax benefit.

But if there is any change in Spectra's ownership of the GP, let's say, one of the solutions is somebody injects capital, you find a partner and your ownership is diluted, let's say down to 20% or 25%.

Would that change your ability to continue to have that tax benefit, or you would still continue to have equity method accounting and it would still flow through?.

It's the latter. Shneur, we'd still follow the equity method accounting. We pick up our share of any EBITDA loss and then that would generate current cash tax savings. So, to your point, it would just be proportionately less than it otherwise would have been..

Perfect. All right. Thank you very much, guys..

Thank you..

Okay. There are no further....

Sorry, Angel..

I'm sorry. I was going to say there are no further questions..

Great. Thanks. Thank you very much. I appreciate everyone joining us on the call today. Of course, if you have any additional questions, feel free to call Roni Cappadonna or me. And hope you all have a good and safe day. Thanks very much..

This concludes today's conference call. You may now disconnect..