Thank you, Maria, and good morning, everyone. Thanks for joining us today for our review of Spectra Energy's and Spectra Energy Partners' 2015 third 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 for 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 is 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 website.

So with that, let me turn things over to Pat.

Well thank you, Julie, and good morning. Thanks for joining us today.

As you've seen in our news releases, both Spectra Energy and Spectra Energy Partners delivered solid EBITDA for the quarter. These results reflect the strength of our diverse portfolio, which is structured to moderate the effects of various business cycles and preserve the upside benefits in the recovery phase.

Spectra Energy Partners' EBITDA for the quarter was $467 million, $66 million higher than the same quarter last year, and ongoing EBITDA at Spectra Energy was $634 million, down $70 million from the prior year quarter. Spectra Energy's ongoing results exclude special items of $26 million, all at DCP, and primarily from the gain on sale of an asset.

Turning to the drivers of our ongoing results by segment, let's start with Spectra Energy Partners, where EBITDA was up approximately 16% quarter over quarter. SEP consists of our U.S.

Transmission and Liquids businesses, and is shown in the upper right-hand corner of slide three. U.S.

Transmission delivered EBITDA of $401 million, up $49 million over last year. These quarterly EBITDA results reflect increased earnings at U.S.

Transmission and are attributable to expansion projects placed into service in the prior year: TEAM 2014 and Team South; as well as those placed into full or partial service in the third quarter of this year: Uniontown to Gas City and OPEN, respectively. Both of these projects came into service earlier than expected building on our lengthening record of excellence in execution.

Our base business continues to perform well, and I'm pleased to report that we have achieved a renewal rate of about 98% of our contracted revenue on the U.S. natural gas pipelines, which is an indication of the value of our underlying base business.

The liquids business reported third quarter EBITDA of $79 million, compared with $60 million in the prior year quarter. The improvement is attributable mainly to higher transportation revenues due to increased tariff rates and volumes on the Express pipeline.

Let's move now to our Canadian business segments, which are shown on the left hand side of the slide. While our three-year plan anticipated a lower Canadian dollar in 2015 compared to 2014, for the quarter the Canadian dollar was 14% weaker than our plan had assumed.

As a result, the FX effect on EBITDA for our Canadian business segments this quarter compared to the same quarter last year was $14 million at Distribution and $24 at Western Canada, or $38 million in total. As a reminder, about two-thirds of our currency exposure is naturally hedged at the net income level on an annual basis.

For the quarter, the reduction in net income from controlling interest related to FX was $18 million. Distribution reported third quarter EBITDA of $70 million, compared with $82 million in 2014.

The decrease quarter-over-quarter was driven by the decline in the value of the Canadian dollar. The base business remains strong and, excluding the effect of FX, Distribution would have reported EBITDA that was higher quarter-over-quarter due to customer growth.

Western Canada reported EBITDA of $117 million, compared with $156 million in the prior year quarter. The decrease quarter-over-quarter is due entirely to the effect of the lower Canadian dollar I mentioned previously combined with lower earnings at Empress.

The risk management program implemented at Empress, including the hedges that we have in place, continues to support our view that Empress will generate cash of $30 million this year. Also, as a reminder, our Western Canadian business, including gathering and processing, is fee-based with no direct commodity exposure or volume risk on existing contracts.

We continue to monitor the current macro environment and producer activity in Western Canada, as there have been slowdowns in some areas. We remain focused on continued prudent cost management to respond to the changing environment in Western Canada.

Moving on to DCP, you'll recall that what we show here as Spectra Energy's EBITDA from Field Services actually represents our 50% share of DCP's earnings before income taxes, plus gains from DP unit issuances. Excluding the effect of special items, DCP's year-to-date EBITDA on a standalone basis is about $500 million, which is an indication of the strength of this business even in the current market environment.

For the quarter, we reported ongoing EBITDA from Field Services of negative $29 million, compared with $63 million last year. The 2015 period excludes special items of $26 million, as previously mentioned.

The 2014 period excludes special items of $12 million, mainly due to a goodwill impairment. The decrease in ongoing earnings was primarily driven by continued lower commodity prices and lower gains on DPM unit issuances.

These decreases were partially offset by asset growth, improved operating efficiencies, and other initiatives. We're pleased with all of the actions that have been taken to strengthen DCP, and Greg will speak more about that in a minute.

So all in all it was a solid quarter for both Spectra Energy and Spectra Energy Partners. Importantly, these results have us ahead of our expectations at this point in the year, and we expect to meet or exceed our full-year plan and deliver on the significant financial commitments we made at the beginning of the year.

Let's take a look at our distributable cash flow schedules, beginning with SEP as shown on our Slide 4. SEP's standalone distributable cash flow for the quarter was $270 million, an increase of $23 million over the prior year quarter.

The higher DCF was attributable to the higher EBITDA I previously mentioned and reflects SEP's significant organic growth, strong fee-based earnings, and virtually no commodity or volume exposure. The quarterly and year-to-date results are consistent with our 2015 plan expectations to achieve full year coverage of 1.1x.

SEP paid general and limited partner distributions to Spectra Energy for the quarter of $61 million and $148 million, respectively. In addition, SEP continued to grow its distribution with its recently announced 32nd consecutive quarterly distribution increase.

Turning to Slide 5. Spectra Energy's distributable cash flow is $223 million for the quarter compared with $236 million last year.

The lower DCF is primarily attributable to receiving no distributions from DCP this quarter versus $43 million last year. Both quarterly and year-to-date results for DCF are consistent with our plan to achieve full-year distribution coverage of 1.2x.

SEP's ATM program continues to attract investor interest and, as a result, we don't anticipate accessing the equity markets through any vehicle other than our ATM program for the remainder of this year. For the year to date, SEP has raised $450 million through its ATM.

We also have significant liquidity available across the company, totaling $3.4 billion as of September 30. This financial flexibility gives us confidence in our continued capacity to successfully fund our growth projects in an efficient and cost-effective manner.

We know that investors are interested in the credit quality of our customers, so I want to mention that 90% of our revenues are contracted with customers who are investment-grade or are secured by investment-grade equivalents like letters of credit. Overall, our base businesses continued to perform well, generating stable and sustainable earnings and cash flow.

Our financial results are ahead of our expectations, even with commodity and FX headwinds, and we have the financial flexibility to fund our growth projects efficiently while staying on track to meet or exceed our 2015 EBITDA and DCF objectives. As a result, we remain confident in our ability to deliver on the $0.14 annual dividend increase guidance we shared with you earlier this 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.

Well, thanks very much, Pat, and good morning, everybody. As you've just heard we achieved another solid quarter from both a financial and execution perspective.

The results we delivered this quarter continue to underscore the strength and resilience of our portfolio of businesses. SEP has no commodity and virtually no volume exposure and Spectra Energy's exposure to commodity is limited to 1% of our forecasted EBITDA.

In the current environment, this limited commodity and volume exposure coupled with our track record of consistently doing what we say we'll do are important risk differentiators for us versus many others in the midstream space. Our focus continues to be on operating our business safely and reliably and delivering on our growth and dividend promises for investors in both Spectra Energy and Spectra Energy Partners.

You've previously seen this slide outlining our priorities, so let me provide an update on our progress. First, we're very pleased that the recent transactions initiated by Spectra Energy and Phillips 66 to strengthen DCP are complete, with the transactions closing on October 30.

As we have said previously, the contributions made by the owners along with the other initiatives underway at DCP establish a foundation for sustainable cash flows at DCP Midstream over the longer run. DCP quickly adjusted to the rapidly changing industry environment and continues to be extremely diligent in taking actions of its own to ensure its longer-term success.

Over the past year, DCP has engaged in various self-help initiatives, including the sale of $200 million of non-core or underperforming assets, reducing base costs by approximately $70 million and launching the restructuring of its commodity-sensitive contracts which, combined with hedging, will increase fee-based earnings. I'm very pleased with the progress being made on the contract conversion front.

As an example, you may have seen the recent announcement of a 10-year renewal of contract with one of the largest investment-grade independent producers in the Permian. This new contract has been converted at significantly better margins from percent of proceeds to 100% fee-based and covers approximately 1 million dedicated acres.

DCP is on track, if not slightly ahead, of where they need to be to achieve their contract conversion goal of reducing one-third of its commodity-exposed NGL length by the end of 2017. With the support provided by the owners and DCP's own initiatives, it's our view that DCP has the ability to realize breakeven cash flows and make ongoing positive economic contributions to the owners at current commodity prices, while remaining well positioned to further benefit from industry recovery.

This turnaround is significant and a direct reflection of all the actions taken to strengthen this must-run business. Next, completing our secured backlog and doing so on time and on budget continues to be key to our execution advantage.

We also remain diligent in advancing and securing projects in development to ensure we deliver on our growth objectives. Finally, we continue to believe there will be industry consolidation opportunities and that could advance our value creation objectives and complement our business profile.

With that, let me update you on the projects we have in execution. You've seen this slide many times before and it's a great scorecard to track the success that we've had so far in executing on our growth plans.

Not only are we consistently demonstrating that our project development timelines and budgets are reliable, but also that we're able to realize some upside from placing projects into service early. Our Uniontown to Gas City Project began delivering gas to the Midwest on August 1 and was fully in service September 1, two full months ahead of the schedule.

Additionally, the first segment of OPEN was also put into service about six weeks ahead of schedule and the remaining portion of OPEN has a November in-service date. We're very proud of the track record on project execution and pleased with the growth that these projects offer our investors.

Since our last earnings call, we've moved $1.4 billion of expansion projects into service and, by year end, that number will be almost $1.9 billion as we will place the 2015 Dawn Parkway project fully into service, consistent with the originally planned in-service date. In aggregate, the expansion projects that will be placed into service this year, excluding those at DCP, will generate $135 million of EBITDA annually.

These projects are fee based, with no commodity or volume exposure, further adding to the stability of Spectra Energy and Spectra Energy Partners earnings and cash flows. Overall, 2015 will be a successful year for delivering projects into service and demonstrating our project execution advantage.

Looking forward, our project backlog has almost $9 billion of projects still to be placed into service. As a reminder, all of these projects are underpinned by executed customer agreements.

You'll also notice that about 75% of our expansion CapEx in execution is supported by secure contracts with demand pull customers, such as local gas distribution companies, further demonstrating the strength of our current project backlog in this environment. All of our projects in execution are proceeding well and are on track to meet their respective in-service dates.

And here's an indication of the great progress we've been making since our last earnings call. We have filed FERC regulatory applications for several U.S.

projects: Atlantic Bridge, PennEast, Access South, Adair Southwest, and the Lebanon extension. In Western Canada, the Jackfish Lake, RAM, and High Pine projects have either already been filed or will be filed this month with the National Energy Board.

These projects represent about $1 billion of low-risk, cost-of-service pipeline expansions. In addition, construction is underway on AIM, the 2016 Dawn-Parkway project, and the Express Enhancement project, and we are on track to begin construction on Sabal Trail next year.

A significant milestone will be met on NEXUS later this month when the project files its FERC application. Let's take a closer look at NEXUS and the progress we're making on that particular project.

Many of you are familiar with NEXUS, but I want to take this opportunity to remind you of the scope of the project that we are jointly developing with DTE. The NEXUS project is a 250-mile, 1.5 Bcf a day pipeline that will originate at Kensington, Ohio, and connect with DTE Gas in Michigan.

This path will utilize TETCo, DTE Gas, and Vector pipelines, and the project represents tremendous opportunities for customers to access gas from both Utica and Marcellus and move it through markets in Ohio and Michigan to the 150 Bcf a day Dawn storage hub, the second largest physical trading gas hub in North America, and which is owned and operated by our own Union Gas. NEXUS is a key strategic project for us as it will ultimately connect Texas Eastern with the Union Gas system, something we've been envisioning for our customers for many years.

To complete the upstream path of NEXUS, we're advancing the TEAL project, an expansion of TETCo, to offer customers greater supply access and market connectivity by transporting gas on Texas Eastern to Kensington, Ohio. We'll be filing our FERC application for TEAL later this month.

As you know, downstream of NEXUS are the Union Gas's $1.5 billion Dawn to Parkway expansions, which provide customers in Eastern Canada and the Northeast U.S. access to supply directly at the Dawn hub and the capacity to move their gas to downstream markets.

And as I mentioned earlier, the first phase of the Union Gas Dawn-Parkway expansion projects will be completed later this year. NEXUS is moving forward with the support from executed customer agreements with LDCs, so demand pull markets, as well as Marcellus and Utica producers.

We've also recently signed a number of interconnect agreements with industrial facilities and power generators that could connect incremental load across Northern Ohio of up to 1.4 Bcf a day. Importantly this demonstrates strong long-term market support for our route and the project, and we continue to see increased production forecast for the Appalachian region.

We've achieved several milestones in NEXUS this year, including the January approval by FERC to use the prefiling review process, selection of an EPCM contractor and securing pipe for the project, and, as mentioned, NEXUS will file its FERC application later this month, and we would expect FERC to issue its approval to proceed in the second half of 2016, thereby allowing us to achieve our in-service date of late 2017. So we're pleased with the progress we're making on NEXUS, as well as the progress we continue to make on all of our projects in execution.

When this backlog of project is in service, along with the others we'll place into service this year, investors can expect these projects to generate about $1 billion of EBITDA by 2020. Let's now shift our focus to projects in development.

In addition to our backlog of projects in execution, we've got a robust portfolio of opportunities in development that will lead to continued growth in 2018 and beyond, and we're working diligently towards advancing those projects. We continue to make progress on our Access Northeast project, which is an expansion of our Algonquin system to serve the New England power generation markets and address electric reliability concerns during peak periods.

This reliability is becoming a more critical concern each year as additional coal, oil, and nuclear plants announce retirements. Key to Access Northeast is recognizing the importance of being directly connected to 60% of New England's gas-fired electric generators.

Gas deliveries to electric generators can only be guaranteed for those with last-mile firm transportation contracts. Electric generators without last-mile firm transportation contracts have no guarantees of gas deliveries on peak demand days, regardless of firm contracts they may have on other pipelines.

Access Northeast will largely solve this issue. Earlier this week, we filed with FERC to use the pre-filing review process for this project.

At the state level, we are at a positive turning point as support for our approach and for the electric distribution companies to secure capacity continues to build with a series of separate but very consistent actions across the different states. Rhode Island's Affordable Clean Energy Security Act of 2014 authorizes the Division of Public Utilities and Carriers and the Office of Energy Resources to develop and issue open and competitive solicitations for infrastructure projects and clean energy resources.

Last month in Massachusetts, the Department of Public Utilities confirmed its legal authority to review and approve EDC contracts to enhance electrical reliability and reduce energy costs. The Maine PUC's ongoing proceedings has recognized the benefits of examining a regional electric reliability solution for Maine customers.

Connecticut continues to make progress towards their RFP, focused on ensuring electric reliability as outlined in legislation passed this summer. And in New Hampshire, the PUC staff has issued a report supporting the legal authority for EDCs to enter into gas pipeline capacity contracts.

We've made significant progress since the region's governors came together around the reliability challenge they identified in 2013. We're optimistic that before the year is over, some of the electric distribution companies will be filing contracts for state approval.

As a result, with all this positive momentum, we are now even more confident in our ability to move Access Northeast into execution in the first half of 2016. We continue to actively pursue many other projects in development and have ongoing productive discussions with potential customers.

Interest remains strong in many of these projects, particularly those that are demand-pull. Supply-push discussions are proceeding at a slower pace in the current market environment.

However, we remain highly confident that this infrastructure is needed and will ultimately be secured by the end of the decade. We will continue to actively engage with the market as the energy environment evolves and aggressively pursue the other projects in development.

Two years ago, our Drive to 35 originated from our expectation that we had the ability to secure contracts and pursue organic growth projects totaling $35 billion. To date, we've been very successful in our efforts, with almost $10 billion in service, and delivering cash and almost $9 billion remaining in our secured project execution backlog, which will add incremental cash flow beyond the current period.

We will continue to focus our efforts on organic growth, since it's the most economically attractive way to grow, albeit often at a slower pace. We're not dependent on M&A to achieve our Drive to 35; however, the current environment may provide good opportunities to participate in industry consolidation, which could in fact expedite our efforts to achieve that goal.

So we continue to deliver solid results, further proof of the resiliency of our underlying businesses and continued demonstration of our execution advantage. As I mentioned last quarter, not only do we believe that investors are beginning to differentiate between investment options in this environment, but also that Spectra Energy and SEP offer best in class investment opportunities.

Spectra Energy's Partners is one of the lowest-risk MLP investments available, offering investors visible growth. The average remaining contract term within our gas pipeline business is about nine years, and these are reservation-based contracts.

An Express crude pipeline has an average contract term of 10 years. Revenues are reservation-based with no commodity exposure and virtually no volume exposure, allowing us to provide quarterly distribution growth for investors every quarter for the last eight years.

And we're committed to continuing that track record with 8% to 9% annual growth. Simply put, SEP is the most proven, steady large pipeline MLP in existence today.

Spectra Energy offers an unrivaled footprint that connects all of the major North American supply basins with demand markets, a first- and last-mile advantage. With more than half its EBITDA coming from SEP stable and reliable earnings, 99% of Spectra Energy's EBITDA for 2015 to 2017 period will come from our fee-based businesses.

And there is virtually no further commodity downside to our DCF forecast if commodity prices move lower. As such, we remain committed to growing Spectra Energy's annual dividend by $0.14 per share through 2017.

We have the financial flexibility to efficiently fund our impressive backlog of secured growth projects and pursue new opportunities. We've got two strong currencies through Spectra Energy shares and Spectra Energy Partners.

Both companies have investment-grade balance sheets which we're committed to, and we are disciplined in our financial management. So those are the attributes we believe differentiate Spectra Energy and Spectra Energy Partners from other energy companies and why we believe so strongly that both our companies offer best-in-class, low-risk investment opportunities today.

With that, let me turn things over to Julie so that we can take your questions.

Thank you, Greg. So, Maria, we're ready to take questions.

If you would open up the lines, we'd appreciate that.

Morning, guys. Two quick questions from me to start.

First, Greg, if I could on Access Northeast, and I realize a lot of this is going to hinge on the level of state approvals for the EDCs that ultimately transpire, but at this point do you have an estimate of where you think the incremental EDC capacity commitments could land based on the level of support that you guys have? And also has there been any change to your thoughts on timing?

I don't think any change on timing. Bill, do you want to speak to the level of commitments?

Bill Yardley's actually here with me, who I think most of you know runs our U.S. pipeline operations and business.

Hey, Darren. We haven't deviated from the 900,000 Bcf that we feel (a) that we feel that the region needs and that is needed specifically on Algonquin in particular.

We feel pretty good that we're in the running for that entire volume.

Okay. And then, Bill, if I could switch for a second over to NEXUS, including those interconnect agreements with the industrial and power-gen customers, what's the total level of commitments relative to that 1.5 Bcf a day of capacity now?

So at the 1.5 Bcf, we are at about 60%, 65% firm contracts all wrapped up there. The interconnects represent about 1.4 Bcf of potential market along the pipeline route.

And it's kind of why we picked this route; we picked a bit of a northerly route to make sure that we had these options and alternatives, and that's looking very attractive to producers as they assess when to jump back into the capacity game. I will add to that, too, we have four other generators – when you think about the power in this region and potential coal conversions and coal retirements, we have four generators we're talking to that are – they total about 3,000 megawatts, and that would be another 0.5 Bcf on top of that, so really good load there.

Yes, just to add to that, Darren, I think just like in the Northeast projects, when we lay out these pipeline routes, obviously we look for and are close to industrials and power plants. So those interconnects, I think – remember, that's done at their request.

So that's very much, I think, underlines just the demand factor for these pipelines. Again, we've seen that in the Northeast and we're seeing it again here.

You get the base commitment and then others come along and see really the power of having natural gas available to them.

I appreciate it. Thanks, guys.

Thanks.

Good morning, gentlemen. Julie.

Good morning, Brandon.

Good morning.

Greg, following on the participating in industry consolidation bullet, can you describe what you see as the M&A landscape today and how it may change over the next 6 months to 12 months?

Well, there's no doubt it's going to change over the next 6 months to 12 months. I think what you're seeing is, starting to see some real differentiation.

I just look at SEP equity, for example. In the last 12 months SEP equity, I don't think it should have, but it backed up the yield maybe 100 basis points, 125 basis points.

But you see a lot of others moving 200 basis points, 300 basis points, 400 basis points, 500 basis points, even 600 basis points on their yield. I think that's going to make it very tough for some of those people to be able to execute on some of their plans and so I think that could create some opportunity for us.

Obviously I think part of our interest is on the liquids side. We're always open to gas, that's our base business.

So I don't think the delta between the bid and ask has come down entirely yet, but again as each quarter goes on and people see the strength of those people with pipeline assets like we have that have very steady, reliable and have committed to 8%, 9% type growth, that's going to be rewarded versus some folks who have maybe much loftier suggestions that people are going to realize in this environment is not possible. So I think you're going to see strength go to people of size and strength go to people of low volatility.

And I think that's advantage for both Spectra and Spectra Energy Partners.

Great. Very useful color.

I appreciate that. And then just, circling back to Access Northeast, obviously some very nice regulatory tailwinds.

I guess a question, when you are talking with regulators, is there any conversation about competing projects and maybe a cost advantage that you have relative to those projects?

Well, I'll let Bill add to that. But I would say that, yes, and I'd also say one of the critical components is greenfield versus brownfield, and obviously that leads to disruption and cost differentiators.

And I think Access Northeast has a huge advantage there. I would say it's not just regulators, also politicians, local communities.

As you know, Algonquin is the backbone through New England and I think both Grid and Eversource have recognized that as partners. Bill, I think you were up there talking to folks last week.

Any color?

Yeah. One thing I'd add to that, I think you summed it up well.

The discussions we do have – these electric distribution companies in the region as a whole are looking at making a significant investment and so they want to make sure that the capacity that they're getting is going to the actual power plants that need it the most. and that's probably the extent of any type of conversation we have in the competitive landscape.

They just know that we can get the gas exactly to where it's needed.

Yeah, Brandon. One thing that I think why we're so optimistic now of being able to move into execution is, remember, typically this is a project that you'd already see in execution, good partners, good contracts kind of thing.

But there are some unique regulatory aspects to it. But probably the biggest one that we first had to get over was the fact of the legality, if you will, of EDC's whole pipeline capacity.

I think in the last several months that's largely been put to bed. And so that was a critical component and now the other one we'll just turn around getting contracts filed with regulators, which, as I think we made in opening comments, we'd expect to see some of those folks do that before the end of the year.

Great. That's it for me.

Thanks, Greg and Bill.

Thank you.

Hi. Good morning.

Good morning, Faisel.

I just have a couple simple questions. Just looking at your TEAM 2014 and your TEAM South expansions, I just want to get a little bit of a gauge in terms of how those backhaul, those commitments to move gas south, what the utilization of those systems look like now that things are up and running.

Yeah, they're maxed I think from pretty well day one. As usual in that neck of the woods, Faisel, I wish we'd built more.

And so I think they contributed probably close to $20 million just for the quarter between those two projects. So they're full capacity.

Okay, got you. And then just on some of these smaller projects that we look at, whether it's a partial conversion of your gas line to a products line or if it's an enhancement to Express Pipeline, the $135 million of capital you're putting there.

How are these sort of brownfield projects where you're talking about more of a liquids component versus gas, which we can look at the FERC documents and figure out those increased tariffs and what they mean for the returns on those capital, what are those sort of returns look like on these conversions to liquid lines or expansion of liquid lines?

Well, in both cases you're talking about double-digit type returns, obviously with far less capital being put to work. Think about it like adding compression to a gas pipeline.

Obviously, it's cheaper than providing pipe. So you're seeing the same thing on the enhancement side, relatively small increments.

I think the Express Enhancement adds about 20,000 barrels, so it's not huge. But obviously people will pay a lot to move product anywhere at this point in time and you're obviously attracting that full rate for a relatively small incremental capital.

So typically the small projects, while they are by definition small, provide very good returns relative to large brownfields or obviously greenfield projects, which are high-single digit type projects.

Okay. The last question from me.

On this procurement of pipeline and steel and those sort of things, what are you seeing right now in the market? How much are costs coming down and where are we in the cycle?

Are those costs being passed through in lower steel and HRC costs?

Well, it's obviously a competitive world out there obviously, so any pipeline savings we get, they may help you on one project but by the next project everybody's got the same competitive makeup, so it quickly dissipates. But that being said, we're taking advantage where we can on that front and we are seeing some benefits on the steel front, I'd even say on turbines and things like that.

But important to remember is that the breakdown is about 70/30 for capital in terms of 30% is hard assets, if you will. 70% is labor and regulatory and land.

And, Faisel, we're not seeing any pullback in costs on those fronts. People are building projects in highly concentrated areas.

As we all know, regulatory processes don't get any easier. Land issues, labor is tight in those locations.

You can move steel from one part of the continent to the opposite side but you can't move people that way, right. So I think the savings because of a relatively weak energy environment are not really showing up in full pipeline construction.

You're getting some benefits on hard product, but again most of the costs are on the other side. So we feel good about our estimates, but I don't see us seeing big cost savings in this environment.

Okay. Got it.

Thanks for the time.

Okay. Thank you.

Good morning, Ted.

Good morning. Thanks.

First question from me, is DCP fixed? And what I mean by that is if we sit here where the strip is where it is, where maybe volumes and activity levels are unchanged, is there any need to do anything else there?

Do you need to put more capital in, more assets in, et cetera? Or can we kind of go forward as we are?

Look, I think we've done, again, with the self-help, with the support of the parent or the parents, we're in a good position, as I said in my comments, where at these types of prices DCP can be a cash-positive business. So yes, I believe we're in a sustainable position.

Maybe just interesting for people to understand from a volatility perspective at DCP, a year ago 50% of DCP's margins came from PoP and keep-whole. Today, that's less than 30%.

And the biggest chunk of margin comes from gas and NGL fee margins, and that's a substantial change in a year. And we've even seen about a 20% increase in the margins realized on gas processing on a fee basis.

So I think between – and we're still early days of the contract discussions, but I think as Wouter [Van Kempen] outlined for investors in February at our conference, that was something we got on very early. And so, yeah, I think we've created a sustainable environment there for investors that won't require additional support from the parents.

Great. Good to hear.

And then you mentioned a little bit about the volumes in western Canada and just noticing the processing numbers are down 12% year-over-year. What's the outlook there?

Do we feel like we're stabilized with where the activity levels are there? Or is there any down side?

And then maybe can you just remind us the contract duration that you've got there, if you have any recontracting risk around those assets.

Yes. So, remember, two types of business there, right.

Call it one-third, 35% pipeline business. So there's no contracting risk on the pipeline side of things, cost of service.

And that's where we're adding additional capital. On the G&P side, contract life's run average two to three years.

And you always have some IT. I think IT runs about 10% from a revenue perspective, so obviously you've got some down side risk there.

As we go through and get our plans wrapped up for next year, that's exactly the kind of stuff that we're looking at. And contract renewals usually come up, Ted, in the April time period.

So that will give us a view next April on how things are going to look from a longer-term perspective. Still, production of natural gas is going on.

And most of our assets are in British Columbia, as you know. And I think you do see, obviously, important infrastructure investments on the pipeline side, saying that people still want to get their product out of Western Canada.

So, yeah, sure, a challenging environment, and we'll just have to watch to see how things go over the next year or so from a commodity price perspective.

Sure. And then the last one from me.

You've taken on some partners on some of these projects, JVs and whatnot. Is that still the MO as you move forward and move some more of these projects that are in development into execution?

Or would you like to keep whether it's operational control or full ownership of some of the projects you've got ahead of you?

Well, we will always keep operational control. That's the modus operandi number one.

And I would argue even strategic control. But the partnerships are really critical.

I think the partners that we've taken on, and we have a long history of doing this, whether it's ExxonMobil or Maritimes & Northeast 10 years ago. Or whether it's Sabal with our friends at NextEra and Duke, or whether it's in the Northeast with Grid and Eversource or DTE, they all have really important insights as to what's going on locally.

And that's where our competitive advantage comes. So would I like 100% of everything?

Absolutely. But, you know, pigs get fat; hogs get slaughtered.

So from my perspective, let's – we like that MO where we've got big sophisticated partners, and we'll continue to do that.

Great. I'll leave it at that.

Thank you.

Thanks, Ted.

Good morning, Paul.

Good morning. Just maybe following on the questions on Western Canada, I think Pat mentioned that Empress is on track to achieve $30 million cash in 2015.

Can you talk a little bit about the duration of the contracts on Empress and what the early view to 2016 might be?

Yeah, remember, things like ethane and stuff, sure, are long-term contracts through 2019, 2020, so that's quite different from the United States, where ethane is not done on a cost-of-service basis, so that's a positive. On the other side for the other commodities, really, when you think about propane and butane, we did put in some hedging last year, and I think we're about 50% hedged for 2016, Paul.

So again, as we go through the year and put the plan out, you can only go out about 12 months from that perspective. I would say that's an element of exposure there, but feel pretty good to be 50% hedged for next year as well.

Volumes through Empress have been better than what we expected for the year. So that's pleasant.

Margin is lower, volume is higher, which is why we've kind of been focused on this $30 million of cash generation there a year.

Got you. And despite the caution around the outlook in Western Canada, I saw a couple of the projects there actually got a big larger.

I think the RAM project and High Pine ...

Yeah.

...went up a little bit. Can you just talk about what's the driver behind the increased CapEx?

Well, pure demand really. I think just as we got through to the filings and confirmed what customers really needed and the way in which we structured the projects, that just grew the size a little bit.

Remember from a cost-of-service perspective, that's the important element there. So as they go into the NEB filing, you obviously want to make sure that you've got your costs locked down.

I'd say the other thing with Western Canada, Paul, to think about is, while the LNG projects, as you know, I don't think anybody's had it in our models – if they have, it's out past towards the end of the decade – but you are seeing some small LNG projects being approved, wood fibre, et cetera. Those actually, as we look forward, could be quite helpful.

Early days still, but quite helpful to tease out a component of West Coast system, et cetera, so beyond the dollars we've put in to help out Western Canada, in terms of the projects this year, call it almost $1 billion, I think some of these small LNG projects could lead to additional pipeline opportunities, again, on a cost-of-service basis.

Yeah. Those would be helpful.

Last question, in your Drive to 35 slide on the development side, you continue to have exports to Mexico in there.

Yeah.

CFE has a number of RFPs underway currently for pipelines in the northern part of Mexico there. Are you part of that process?

What are you plans? Where are you in the Mexican exports?

Well, Paul, obviously I can only – I have to follow whatever the requirements are from a legal perspective of confidentiality, but as you know our pipeline goes to the border and we have some stations just over the border. And we have expressed interest in the past to participate.

And so I will leave it at that other than to say the judgment there is simply a risk and reward. We have a lot of things going on in this part of – in the United States, a lot of things in Canada.

If the risk and reward are similar in Mexico, you can expect us to be aggressive to look at those opportunities as well.

Okay. Thanks very much.

Thanks, Paul.

Good morning, Christine.

Morning. Can you guys provide us an update on the tax situation for 2016 and 2017?

I don't think we're going to put out 2016, 2017 here. I guess I can – the only thing I would say is that, as you know, we were at 1.2 coverage at the FC (45:20) level, and that was with a low cash tax in 2015.

And we did not assume that in 2016, 2017. We'll get a good view here in the next month from the federal government.

I believe, and I could get this wrong, but I believe both separate committees in the Senate and the House have passed bills that would see the extension of bonus depreciation, one, I think in the case of two years and one on a permanent basis. So obviously that would have a very significant impact for us in a positive basis with respect to 2016.

When we laid out the plans last year, we did not assume that, and that probably runs $200 million plus in terms of a benefit, Christine. So obviously we're watching that closely and are optimistic that that in fact could be the case.

Okay. And then for Access Northeast, you know you guys talk about getting Massachusetts approval, and I think that's the biggest customer base.

What's number two and number three? And do you have any regulatory updates in those states?

And is the PUC approval the biggest roadblock?

Yeah, you know, it's Bill Yardley. I would say Massachusetts and Connecticut – Connecticut is probably second in terms of sheer volume and then you get to Rhode Island, Maine, New Hampshire, and lastly Vermont.

Our opinion is that these are moving really nicely, as we've said, and that – I would say that Connecticut probably has – sorry. Connecticut probably has the process that might take the longest because they're going through a statewide process, but they've shown the ability to really speed that up, so they could be finished by early next year.

Okay. Thanks.

Lastly, this is just kind of a macro question, not necessarily about your assets but maybe just Marcellus build out in general. We're seeing some massive dry Utica wells, and if this continues, I would think natural gas prices stay lower for longer, possibly pricing out some producers who might not have that exposure?

So maybe it becomes less producers each with more market share now. I would think some of the producers are not going to make it, especially given leverage and balance sheet issues.

At what point should we be worried about some of the counter parties on all the pipelines that are currently being developed to get out of the region? I understand a lot of your buildout is underpinned by utilities, but there is an element of supply-push out of the region.

So I would be curious as to your thoughts, and maybe some insight into the landscape out there? Are there outs for some of these producers if the pipeline hasn't broken ground yet?

Well, not on our pipelines. So if we've signed contracts, they are typically only subject to our board approvals and the stuff we have in execution has those board approvals, so there aren't those outs.

I'd say as a macro perspective, and maybe I'm just parroting – maybe even want to see some out of some of that credit analyst, the fixed income analysts, Christine. I think next spring is a pretty interesting time period for a lot of producers as hedges come off and credit facilities come due and the banks figure out what they're going to do.

I guess I feel okay about that. Again, as you point out, 75% of our projects in execution are demand-pull, and low prices – producers don't like it, but the demand side sure loves it, so that's a positive side of things.

And as Pat said, 90% of our customers are investment-grade or secured. I think if you looked at the U.S.

side of things, the top 10 customers, which are investment-grade except for one, would account for 50% of the revenue that we have, and in Canada the same type of thing in all of those top 10 which account for 50% of revenue would be investment grade. So I feel pretty good where we are.

But I think next spring is the time to kind of watch things, but I would also say, just like we see at DCP and other places and you've seen with a variety of producers talking about it this week and last week, boy, they're ripping out costs right, left, and center and so you're seeing some pretty dramatic drops and what you wouldn't have thought was possible a year ago is, so never underestimate the ability of necessity being the motherhood of invention here.

But I guess just to follow-up on that, let's say a pipeline is primarily supply-push. Could it be possible that if some of the producers are having difficulties, that that project might not go?

Well, I guess that's a possibility. I'd think the issue would be – so let's look at one realistically since it's already in service, which in retrospect I think may be a good look.

So let's look at New Jersey and New York. So you're talking about probably the pipeline that's delivering to, until recently, the most expensive place to get gas – now that's New England.

And, too, the big backers of that pipeline, Statoil and Chesapeake, but – so you could say, okay, well, Statoil, very solid; Chesapeake's not investment-grade today, but where they are delivering that gas is absolutely the – probably the most profitable piece of capacity that they own. So I think you can't look at it just who's the backing but where is it going.

And if you do not have first-mile and last-mile advantage, even if you've got contracts, I think you can have some challenges with your supply push producers. If you've got that last-mile advantage, that's going to be the most important project and/or capacity that they will hold.

So I don't think you can look at it just solely on who's backing the project. Where is it going and, where it is going, is that demand market a premium demand market.

That's the real value that supply push players will look for, even in a down market.

And, Christine, this is Pat. One other thing we've already seen and perhaps could see more of if prices stay where they are is that producers that have credit issues sell assets from basins to raise cash.

And in many cases, you see a stronger producer come in and acquire those assets. So we've actually seen already some upgrade in our counterparty profile in the basins you talked about.

And I think there's potential for more of that. So that's maybe an unintended consequence, but in some cases we get a counterparty credit upgrade as a result.

Okay, great. Now given your presence, your insights are valuable.

Thank you.

Thank you.

Good morning, Chris.

Hey. Good morning, Greg.

How are you?

Good. How are you doing?

I'm great. Thanks for the color this morning.

I guess my questions are more for Pat I think. I'm just curious about the impact of lost cash flows, given the asset maturity DCP of Sand Hills and Southern Hills and the unit cancellation in (52:37).

Just wondering how we think about that impact on SEP's leverage, on SE's leverage and then in terms of your reiterated longer-term dividend guidance, the distribution payment loss from the MLP. I'm just wondering how you'd instruct us to think about those things.

Are you going to lean a little bit more heavily on the ATM perhaps next year at the SEP level? And then how do we think about the leverage targets in general?

Well, maybe starting with SEP, the way the math works is SEP is really indifferent to the removal or unaffected by it because we've surrendered LP units. We have a limited-term give back of our GP interest.

And so as we look pro forma on the effect at SEP, it's neutral. And of course that had to be the case to get the special committee to sign off on it.

So don't see any pressure at all on SEP. If anything, it's perhaps slightly positive as we modeled it.

So I don't think it changes at all the credit profile at SEP or how we'll fund growth there for the U.S. portion of our CapEx.

At SE, in consolidation, there is a small reduction, obviously, from the surrender of units and the GP giveback. But given where we are in the IDRs, it's not the full amount of the EBITDA that was transferred to DCP.

And ironically, given the strong benefit to DCP of what we did and what our partner did matching with cash, I believe we'll be in a situation to see cash distributions resume at DCP much earlier than they might have otherwise, in which case we'll get half back, if you think about it that way, of the contribution that we made. So net-net for a company up top that has $3 billion of EBITDA, a very small impact and no effect on SE's outlook for capital or credit.

I think the other thing, Chris, is that as the year's gone on from what we laid out to people and I think you saw it in our press release, we were looking at 1.0 coverage for SEP next couple of years. I think as we said in our press release, we could see it in that range of 1.05 to 1.15, which I think tells you that, again, while plans are still being put together, SEP has added incremental projects and, therefore, results for EBITDA going forward.

Obviously that comes to SE as well, so that's obviously a positive from a credit perspective. Interest expense is staying lower longer.

That's obviously positive. And frankly, we've done better from a maintenance capital perspective moving some stuff into 2015, and that's obviously going to help us because maintenance programs typically be multi-year projects in many respects.

And so moving some stuff into 2015, given the results we have, actually are helpful in 2016, 2017 that, too, is also credit enhancing. So we like the investment-grade, obviously committed to the investment-grade and I think we're doing things consistent with that.

Yeah, I think our debt to EBITDA at SEP is only 3.4 times and we're targeting to be at 4 or below, so in very good shape there, consistent with our investment-grade rating and don't see that changing. We're still out looking 1.1 coverage at the end of the year, but not changing that forecast, but I think it's possible we could do a little bit better than that at year-end.

I guess that was the element of the metric, Pat, I was targeting was more the debt to EBITDA, the fact. I get it from a distributable cash flow perspective and what the distributions were forecast to be previously and then with the unit cancellation what the savings will be for SEP.

I get the make-whole on that regard. I guess what I was targeting is, if I think about it from a debt to EBITDA perspective, there was no change in the debt load, but there was a change in the EBITDA associated with those pipelines, so that was really what I was targeting.

I realize you're well below your target. So are we just to think that that's going to be, from an equity perspective, a similar process as what you're thinking before, and maybe we drift a touch higher?

Yeah, it's pretty de minimis at...

The other thing at SEP that sometimes people don't think about is that there was growth CapEx associated with those investments, new pump stations and things like that that we're not going to be funding. So while EBITDA comes down a tad, so does the need to finance growth.

And so debt to EBITDA, it really doesn't move the needle.

Okay. That's great.

I just wanted to confirm that. And then as you think about some of the project inventory backlog, a bit different take on Christine's question.

If you think about counter parties in certain regions that maybe were part of the discussion, are you seeing as pressure maybe builds on them, any change in appetite or any mix shift in terms of who's interested in some of the projects that are still in the development phase?

I think, Chris, as I mentioned, obviously conversations on the demand-pull side are very rapid and of great interest. Conversations on the supply-push side are slower and more cautious, perhaps less so on the gas side today, definitely on the oil side.

That's a very difficult discussion to have right now as people are just not certain where prices are going. We didn't have a whole lot, in fact very little, in the way of oil projects until the end of the decade, and that infrastructure is still going to be needed.

So yeah, you see it on the supply side, on the gas side, but more so on the oil side, but again I'd go to where they're going to put their dollars when they have to for capacity is going to be with people like Spectra Energy and Spectra Energy Partners who can get their product to the demand market. So, again, and you've heard us talk about this for years.

First-mile, last-mile advantage is critical. Lots of people seem to have a first-mile advantage from a supply perspective but not having the last-mile advantage, you're going to have a tough time filling up your pipes and if you did contracts with short-term, 10 years or less, that's the folks I'd be watching at.

That's not what we did and those are going to be tougher positions to find yourself in if you do not go to that last market. I think the supply push the producers are going to be looking for, those type of contracts and saying it's not really taking me to a premium market.

Do I need to re-up or do I need to even continue forward with that type of contract?

Okay. Thanks a lot for the call.

Okay. Thank you.

Good morning, Shneur.

Good morning. How are you guys?

Good.

Just a couple of quick follow-ups. There's been a lot of questions that have been asked that I was interested in, but you've put together a string of a couple of good quarters where you've exceeded expectations.

I was wondering if we can sort of talk about OpEx costs a little bit. With you adding projects, hard to parse the trends but we've seen some others where we've seen some OpEx cost come in.

Is that an opportunity for SEP and SE on a go-forward basis? Could you see yourselves stripping out $80 million to $100 million worth of costs as you look forward over the next year?

Well, we're always looking at that. I would say when you're adding $10 billion to your projects or to your overall base, it's going to be hard to see that number go down, but it doesn't go proportionally up.

And in some parts of our business, you've seen us take out costs in Western Canada, obviously, we've taken out costs in DCP. But I would say I wouldn't look for a big reduction on the SEP side of things, or, say, Union Gas where you're seeing big builds.

So now it doesn't proportionally rise but, Shneur, it's hard for me to imagine – we're always careful, you know, you're always careful on wages and stuff and making sure that they stick with inflation but we've gotten about $100 million of costs out of DCP and Western Canada given the environment there but I don't see that happening on the U.S. side of things.

We're building stuff (a); (b), we're very focused on reliability. It's a license to build and operate.

What I can assure you is wherever we can take out costs and where we're looking at things, things like procurement, obviously a big issue – that's going to pay the biggest dividends to investors. You know everything we can to get a dollar off the price of steel or construction, that's forever return for Spectra Energy and Spectra Energy Partners.

So again, always looking at costs. If we can – whatever we can take out, we can.

Our cost increases from an O&M perspective stay well below the rate of inflation.

Cool. And just to follow up on that, I think that you had mentioned to Faisel in his earlier questions on the capital side that you're not seeing much of an improvement there.

When we sort of think about the cost of steel, which has been down a lot, versus the cost of constructing, is it fair to assume that that is really a small portion of the costs and it's really more about trying to get through some of these highly dense neighborhoods?

Yeah. Exactly.

So Sabal's a great example. I don't have the numbers right at my fingertips, but we definitely are doing better on the steel costs.

We locked in the steel costs around Sabal, but I wouldn't say we're changing the project costs because to your point re-routes, land issues, construction, big spreads, the amount of construction being done in the industry in 2016, 2017, 2018 don't lend to what is 70% of so of the costs, i.e., engineering, design, construction.

Okay. And just two quick follow-ups, Empress benefiting from hedges.

How does it look going forward when we think about 2016 and 2017?

So obviously prices are a little lower, about 50% hedged for next year. And I think we're probably 15% or 20% hedged for the following year.

So we've got some work to do there, but as you know we've made that a much smaller element so we're still very much focused on kind of $30 million in cash being generated there. So feel good about that; of course, just to put that in context, that's 1% of the overall company, right.

Yep. No, absolutely.

And then finally M&A, you really sort of chat about it with a lot more fervor last quarter. Is the interest still at that high level?

And is there any areas of interest that you're targeting?

Well, again, I'm not sure my interest's any different than it was a quarter ago. Maybe the market's actually showing some things that could be of interest to us.

No, I wouldn't say it's any different and I'd reiterate we don't need to do anything. That's the positive side.

But you would expect us as a good management team to be watching for opportunities where folks have some particular weakness that we think is temporal and we can take advantage of where we are. But again, the base case is steady as she goes, put the projects into service like we've been doing.

$10 billion of projects, keep adding to the dividend, steady, steady SEP, SE. That I think will be rewarded by investors; in fact, I know it will be rewarded by investors.

And that is the prime focus. But as you've seen throughout our history, when there's some restructuring or M&A that's going to make a whole lot of sense, then that's something we'll obviously look at.

And I would say don't look for us to do anything outside the norm. If we ever did anything, we're a pipeline player and we're a North American player.

And so I wouldn't look for us to do anything different than that.

Great. Thank you very much, guys.

Really appreciate it.

Okay. Thank you.

Thank you, Maria. And thanks to everyone for joining us this morning.

As always, Roni Cappadonna and myself are available for questions. So have a good and safe day, and we'll look forward to seeing many of you soon.

Thank you.