Good morning, and welcome to Dominion Resources and Dominion Midstream Partners Fourth Quarter Earnings Conference Call. At this time, each of your lines is in a listen-only mode. At the conclusion of today's presentation, we will open the floor for questions. Instructions would be given as to the procedure to follow if you would like to ask a question. I would now like to turn the call over to Mr. Tom Hamlin, Vice President of Investor Relations and Financial Planning for the Safe Harbor Statement.

Good morning, and welcome to the 2016 year-end earnings conference call for Dominion Resources and Dominion Midstream Partners. During this call, we will refer to certain schedules included in this morning's earnings releases and pages from our Earnings Release Kit. Schedules in the Earnings Release Kit are intended to answer the more detailed questions pertaining to operating statistics and accounting. Investor Relations will be available after the call for any clarification of these schedules. If you have not done so, I encourage you to visit the Investor Relations page on our websites, register for email alerts and view our year-end earnings documents. Our website addresses are dom.com and dommidstream.com. In addition to the Earnings Release Kit, we have included a slide presentation on our website that will follow this morning's discussion. And now for the usual cautionary language. The earnings releases and other matters that will be discussed on the call today may contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q for a discussion of factors that may cause results to differ from management's projections, forecasts, estimates and expectations. Also, on this call, we will discuss some measures of our company's performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures we are able to calculate and report are contained in the Earnings Release Kit and Dominion Midstream's press release. Joining us on the call this morning are our CEO, Tom Farrell; our CFO, Mark McGettrick and other members of our management team. Mark will discuss our earnings results for 2016 and Dominion's earnings guidance. Tom will review our operating and regulatory activities and review the progress we have made on our growth plans. I will now turn the call over to Mark McGettrick.

Good morning. Dominion Resources reported operating earnings of $0.99 per share for the fourth quarter of 2016, finishing in the middle of our guidance range. EBITDA for each of our business segments was in line with their respective guidance ranges. As a result, operating earnings finished at $3.80 per share for the full year 2016, which was 10.5% above operating earnings for 2015. Overall, we are very pleased with the performance of each of our operating segments and our financial results for 2016. GAAP earnings were $0.73 per share for the fourth quarter and $3.44 per share for 2016. The principal difference between GAAP and operating earnings for the quarter and the full year were charges associated with coal ash remediation at several of our closed coal generating plants. A reconciliation of operating earnings to reported earnings can be found on Schedule 2 of the Earnings Release Kit. For the fourth quarter of 2016, Dominion Midstream Partners produced adjusted EBITDA of $45.8 million, 94% higher than the level produced in the fourth quarter of last year. Distributable cash flow increased 63% to $37.7 million. On December 1, Dominion Midstream Partners completed the acquisition of Questar Pipeline from Dominion Resources. The acquisition more than doubled Dominion Midstream's ongoing adjusted EBITDA and is expected to cover our planned 22% distribution growth through mid to late 2018. Finally, on January 25, Dominion Midstream's Board of Directors declared a distribution of $0.2605 per unit payable on February 15. This distribution represents a 5% increase over last quarter's payment and is consistent with our distribution growth plans. Moving to treasury activities and earnings guidance at Dominion, 2016 marked a peak in our capital growth plan, with over $5 billion in growth CapEx and $4.4 billion acquisition of Questar. During the year, we raised over $10…

Good morning. Strong operational and safety performance continued at Dominion – excuse me, in 2016. All of our business units either met or exceeded their safety goals for the year. I'm pleased that our employees set an all-time low, OSHA recordable rate of 0.66 last year. Our nuclear fleet continues to operate well. The net capacity factor of our six units was 93% for the year, the highest since 2013 and the second highest since Millstone joined the fleet 16 years ago. Surry Unit 1 set a fleet record for the shortest refueling outage this fall, surpassing a record set at North Anna in 2015. Our Brunswick County Power Station, which began operating last April, has been honored with a number of industry awards including Best Overall Generation Project of the Year and Excellence in Safety Best Project. Now, for an update on our growth plans. Construction of the 1,588 megawatt Greensville County combined-cycle power station continues on time and on budget. As of year-end 2016, the $1.3 billion project was 19% complete. Greensville is expected to achieve commercial operations in late 2018. Five solar projects were completed in the fourth quarter. The 80 megawatt solar facility on Virginia's Eastern Shore went into service in October. Three other Virginia solar projects totaling 56 megawatts went into service in December, along with the 60 megawatt solar facility in North Carolina. For the full year 2016, 727 megawatts were added to our solar portfolio. We have a number of solar projects under development in the State of Virginia and continue to see demand for renewables from our customers including data centers, military installations and the state government. In November, we announced a major expansion of our solar alliance with Amazon Web Services to add 180 megawatts of new solar generating capacity at…

At this time, we will open the floor for questions. Our first question comes from Julien Dumoulin-Smith from UBS.

Good morning. How are you?

Good morning.

Good morning.

So perhaps just a first quick question on the tax reform scenario you discussed in what you'd be, I think you said, neutral. Can you discuss some of the moving pieces that you would think about under that specific scenario, just to give us a little bit more detail?

Hi, Julien, this is Mark. And if we say neutral, we've run a number of different cases, some would be positive, some would be slightly negative. And I guess, we've taken the approach today that no one knows what's going to happen with taxes. And so instead of giving some range out in terms of probabilities, we took a neutral stance. But the key drivers for us, and remember, our mix is different in a lot of truly regulated companies, but the tax rate obviously is a key component on where that lands. Interest deductibility is a very large component for us because of our unregulated fleet, and the amount of current interest that we deduct, normalization, practices and our regulated operations, we operate in many, many states and day-one expensing. So, taking each one individually, they could have a positive or slightly negative impact, some greater than others, but because they – some of these may change or be offset, we think at this point, the best decision for us is to stay neutral until we get some additional clarity out of Congress.

Got it. Excellent. Can you give us your latest expectations for proceeds just through the decade from the MLP drops? And breaking that down, if you can, between debt paydown targets, buybacks and any tax implications from the drop? And again, obviously, with some moving pieces there, just kind of what you see today is your expectation?

I think, today, I would see a breakdown where debt repayment at the parent of between now and 2020 would probably fall in the range of $3 billion to $4 billion, and the remainder of the $7 billion would go to either share repurchases, support growth, dividend support, but that's kind of the breakdown that I look at right now.

Is taxes not a material number within that, as best you espect?

We have some tax strategies that we are planning to put in place. And remember as you think about this, the basis of Cove Point is going to be very high when it drops in. So, it's not like a traditional legacy pipeline asset. But we have factored taxes into our assumptions going forward and we're comfortable with the cash flows we quoted coming back to the parent.

Got it. Excellent. Well, thank you very much, gentlemen.

Thank you.

Our next question comes from Greg Gordon of Evercore.

Good morning.

Good morning. So, you guys, when you talked about the guidance for 2017 over 2016, very, very clear; the 2018 over 2017 also very clear. But – and pointing to at least 10% growth, but how do we think about the other puts and takes. Obviously, Virginia Electric Power you laid out still a reasonably robust capital spending and rate base growth forecast. So, is there any reason I should be concerned or believe that the quantum of net income from VEPCO in 2018 over 2017 wouldn't be higher as well?

No. No reason to be concerned about that.

Okay. And then are there are any other – other than thinking about whether or not there is a drop in 2017 and recycling of cash flow, are there any other like major drivers for thinking about, so where we are in that 10% plus range?

No. I think the drivers Greg, is more – the drivers are pretty straightforward 2017, 2018, Cove obviously is there, one fewer Millstone outage. We try to adjust these growth rates and guidance range to current commodity decks out there on power and also on gas. So I think the growth drivers should be pretty clear. The other thing I'd emphasize, again, and we talked about it earlier. We've actually talked about for about year now. We are purposely stepping down our ITC reliance, so that we get to a very low normal run rate. We've used ITCs for a number of years here to help support earnings during a large capital spend program. And we are not going to be in that business any big way in 2018 and beyond.

Great. And you also did not contemplate any change in regulatory scheme in Connecticut or Massachusetts, as it pertains to clean energy credits for Millstone, correct?

The only thing we've factored into our growth rate and for 2018 is a very modest increase in power prices in the Northeast just because we think they're extraordinarily low right now. It was not a reflection of any legislative effort that would be out there, but just a – on a normal slow recovery in the Northeast on power.

Okay. And you guys raised – last raised the dividend in December. So when you say that you're – when you articulated the dividend growth target today, should I presume that the normal cadence of going to the board with a – to have a conversation on the dividend will be again next December?

Yes. We have – the board is fully aware of these statements we have been making since the fall that we expect to – starting in 2018, to have a dividend growth rate higher than 8%. So we would – our normal policy would be go back later in the year to talk to them about next year's dividend policy, but they are very aware and supportive of dividend growth rate higher than 8% starting next year.

Okay. Thanks, gents.

Thank you, Greg.

Our next question comes from Michael Weinstein of Credit Suisse. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Hey, good morning, guys.

Good morning. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Hey, just a follow-up on Greg's questions. Can you elaborate a little more on why – why there is a 6% to 8% growth rate for the next two years instead of the old 7% to 9%, like why – you are already starting at a lower base. I'm just wondering what – what's the driver in 2019 and 2020 that forces you to reduce that by 1%? Is it the ACP delay or is it something else?

Michael, this is Mark. No, it's not really the ACP delay, although obviously ACP versus previous estimates were being lower 2019 as the build out occurs and be stronger or I guess equivalent, I should say, in 2020. But there's a couple of things to think about there. And when I referenced to Greg earlier, that we kind of reset the commodity deck here, that is a reference to really two parts of our business, obviously the power vis-à-vis which everybody – there is real clarity on that. But the second is gas and oil prices that might impact our business, in particular at Blue Racer. Blue Racer's contribution versus previous estimates are going to be down significantly based on current oil and gas outlook; that can change, it could go up, but we wanted to normalize that in this growth rate. Also the contributions at Hastings, our small processing plant that is housed within DTI, their contributions are also down from previous expectations based on the same liquids pricing events that are out there. So, again to set up, taking a very bullish recovery in commodities, we pretty much looked at the strip, and if your outlook is that – that is conservative based on the recovery of economy, and E&P and others, that could well happen. But those are the two biggest drivers in the 2019 and 2020 timeframe than what we would have talked about previously. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Got you. So you're being conservative and considering there – I mean, when I look at the frac spreads going forward in Marcellus, that – I mean, there has been improvement over the last six months, and I'm just wondering if you're seeing any more interest from your – from your customers?

There has been improvements, certainly in the basin two between South Point and Henry, but we've seen a little bit of an incremental activity in Blue Racer. But it's going to be a slow recovery there, I think, to a more normal rate than we thought two years or so ago in the Southern Utica. So we put out a growth – anticipated growth a couple of years ago for Blue Racer. I'd reference you to those numbers, but it's going to be significantly less than that based on what we're seeing currently over the next two or three years. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Got you. And in terms of Connecticut legislation, and is there a possibility for Massachusetts legislation to support nuclear as well, is that something you're hearing?

There is a – good morning. What we've heard is more through the regulatory process in Massachusetts, but yes. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): So, what – how – what form will that take?

Similar, as we understand it, I mean, all of this is in development, but it's similar – it would be a similar approach to what Connecticut is considering, which unlike some of the other states is not a – some people are describing the other states and subsidies, I'll leave that to others to discuss, but Connecticut is clearly not, it's up to the – it is a opportunity for us to fit into their clean energy program, and compete with other clean energy sources. Connecticut – Millstone Power Station provides over half of Connecticut's power and it has – you can obviously see for the 20% lower prices we're getting for this year than we got last year, it's been under some pressure. And – but we're hopeful that things will improve there. Michael Weinstein - Credit Suisse Securities (USA) LLC (Broker): Okay. All right. Thank you.

Our next question comes from Steve Fleishman of Wolfe Research.

Yeah. Hi, good morning. A couple quickly. The – just on the 10%-plus for 2018. I mean you guys give pretty wide ranges when you do the years. So, is the 10% like the low-end of that wide range or is that being too specific?

No I – the way I look at it, Steve is if you look typically, what those folks have done. The way, we look at it, if you look at the midpoint of our range. We see it of – 2017 I should say, we would see at least 10% growth of the midpoint of 2017. And you are right, we do give fairly wide ranges and that is mainly because we have been so weather sensitive the last five years that it can move in off a lot based on weather in Virginia and Ohio for us, but – but that's how I would do the math, midpoint-to-midpoint.

Okay. That makes sense. One clarification on something you've already said so, you talked about kind of updating to kind of roughly the current forwards but then also on the power side, and then also talked about, though, expecting, anticipating some recovery in the numbers. So I guess, I wasn't exactly clear, which is the answer to that?

Let me see, if I can help you a little bit on that. We look at the strip and we have a very small amount of growth annually off the current strip that's out there in the Northeast. So it's not material to our estimates, it's a few percent a year, the lift in power price. Again, we don't know if it would be more than that or less than that. But we've gone through this for two years now and power prices have not recovered to a level that were in expectations, and we were able to cover those other ways. What we've tried to do here is to say, we've taken a market look of what's out there and we've just taken a very conservative upside to that.

Okay. And then last question is, Tom, mentioned more opportunities for growth off of the pipeline network both the East and the West. When we think about your 6% to 8% growth rate, is that something that would be kind of included there toward the end of the period or is that beyond the period when those new projects would hit? How should we think about that?

Steve, some of them, I think actually has been – a lot of interests starting really this – at the end of last year and this year throughout. We really think of it as three different areas. The West and our traditional Mid-Atlantic. I mean, Mid – Appalachian Basin area. And now it is more Southeastern situation with what we have in North – in South Carolina for example. They will start layering in – for new projects we'll start layering in 1919, 1920 and 1921. So they're going to be spaced out. There will be some in 1918. There will be some in 1919, 1920 and 1921. It depends on what – how quickly we sign them up. Some will be longer, and more capital and some will be shorter and less capital. So I would – they will come out – they will – as you would traditionally see, we announced them as we sign them. And we will have projects that will come in in 2018, we already talked about those today, we have more in 2019, more in 2020, more in 2021, more in 2022. And by expanding our gas infrastructure footprint, we have expanded the opportunities.

Okay. Thank you.

Our next question comes from Angie Storozynski of Macquarie. Angie Storozynski - Macquarie Capital (USA), Inc.: Thank you. Just a follow up question to Steve's question. So, again did you incorporate those pipeline growth projects, or any midstream growth projects in that 6% to 8% earnings growth through 2020?

A modest amount. Angie Storozynski - Macquarie Capital (USA), Inc.: Okay. On Connecticut or New England, in general, I mean, can you give us any sense roughly what would be the benefit to earnings from this legislation, are we talking, I don't know, $0.05, are we talking $0.20, I mean, just a rough estimate?

Angie, this is Mark. We have no estimate to give you, the legislation is not even out of committee. And the exact structure is still evolving, I think, so we don't have any estimate or even a probability at this point whether there'll be success in Connecticut. We would hope there would be, but we don't have a number today at all. Angie Storozynski - Macquarie Capital (USA), Inc.: Okay. And my last question, so you said, out of the $7 billion of cash that's going to be coming from Cove Point. $3 billion to $4 billion will be used for debt paydown, and then the rest split between buybacks, dividends and then growth. Can you give us a little bit more of a sense, I mean, you are giving us EPS growth target. So, just roughly what is the number embedded for buybacks, so that we actually can get a share count, and is there a way for instance you could shift some of the money to make, I don't know, accretive acquisitions that could boost that growth trajectory?

We haven't specifically allocated in 2018, 2019 or 2020, which is when we think Cove Point will be dropped over the three-year period. The exact amount that would go between supporting organic growth, share repurchase and dividends. But, on the dividend side, the math is fairly straightforward. There will be a modest amount, but it'll be the amount that allows us to grow our dividend at a level that doesn't burden our regulated entities beyond the 65% to 70% payout ratio. So, that's a few hundred million dollars. Beyond that, we'll have to see what the opportunities are, Angie, before I can tell you specifically how much the share repurchase versus organic. But, again, it will be a split between that, and as we get closer to the period, we'll go ahead and give clarity. Angie Storozynski - Macquarie Capital (USA), Inc.: Okay. Thank you.

Our next question comes from Faisel Khan of Citigroup.

Hi. Good morning, guys. I have a few questions on Dominion Midstream related to the drop of Cove Point. So, the dropdown value that you guys talked about $7 billion, is that already been negotiated with the Conflicts Committee?

It has not.

Okay. And then, what is the – I mean how are you going to drop this thing, are we going to stagger it over a few years or will it happen all at once?

Right now, we're anticipating staggering in over a few years. And, a lot of that will depend I think on a couple of things. One is there a need for cash at the parent in a particular period that might change that. Second, how are the other assets in DM performing, which we expect to perform quite well, could move that around a little bit. But what I would do for your modeling purposes is I would take the exact amount of EBITDA necessary to grow 22% in 2018, 2019, 2020 off the existing EBITDA stream that's currently there, and back into how the split will occur. And I think what you'll find is that we don't need but a very small drop in 2018 and probably an equal level between 2019 and 2020. So that's how we're thinking about it now, but that could change based on opportunity out there.

Okay. And then just the value of the drop $7 billion versus sort of, let's say, the book value after this is all said and done will be $4 billion. So I mean, is it fair to say that you'll take back a lot of units when you do this drop; simply because you want to mitigate the tax impact of that sort of gain on the book value of the asset?

We will certainly take back some units as part of the drop. A lot of that will be determined by tax planning and market access but based on our last drop or I should say or – I guess our first drop of Questar Pipeline, we can access the market at a very high level and it looks like a very favorable rate. So we would expect only the minimum amount to anticipate any tax issues that may occur out there in terms of units back.

Okay. And what happens with the preferred equity at – in the Dominion Midstream from – in Cove Point, because that was related to the liquefaction asset. So, obviously you can't have two forms of equity in the partnership, would that just get sort of wiped out or sort of exchange for common equity in Cove Point?

Okay. I think realistically, once all Cove Point is dropped in, it's – there is no preferred value to it at all. So probably, it becomes common, but we haven't really talked about that. Until it's all dropped in, a differentiation is probably important, but and after it's all in, I'm not sure there is a need for that.

Okay. And then did you guys discuss that commissioning is under way, so are you going to produce any commissioning cargos this quarter, in the first quarter?

No.

Okay. When would you – when would you envision producing the commissioning cargos, and assuming you sell those in the market, would that be used as a debit against your PP&E?

No. Just to backup, we're – we expect the units to come online, be ready for commercial operations late this year. The capacity and outlook is all entirely – is owned by the shippers. We have capacity contracts, take-or-pay contracts on those. So once its operational, we will be receiving our payments for capacity, and that will be up to the shippers to – to take the cargos.

Sure. No, I understand that. But I thought that in the commissioning stage, you'll produce cargos to test the facility, was my understanding. And then those commissioning cargos sort of belong to you...

That's...

That's my understanding.

That will be later – late in the year.

Okay. The last question....

Our next question comes from Jeremy Tonet of JP Morgan.

Good morning.

Good morning.

Good morning.

I just want to follow-up on Atlantic Coast Pipeline a bit more. And if you could just comment on how the progress there and any thoughts as far as, where the FERC stands right now, or the new administration, any updated thoughts on the regulatory environment would be helpful?

We're doing quite well with Atlantic Coast Pipeline. The draft environmental impact statement came out as scheduled under the scheduling order. It's quite positive, as I mentioned earlier. And it's obviously there for anybody to see. It had about 85 potential conditions in it, number like that, which I think is fewer than we had at Cove Point actually, for a much longer pipeline. So, we were – FERC had done a very thorough analysis, but we had done a lot of – we had done a lot of very thorough work before filing everything, that any major reroutes were already all scoped out before the draft environmental impact statement came out. Comment period is underway. Public hearings will be heard starting at the end of this month. It will all be wrapped up in early March. So we don't see any hurdles to getting our final EIS out in June as it's scheduled. There's an issue, I know, people may have with the going down the two FERC commissioners here over the next I guess about a week or a few days. We don't – need to have a full complement or a quorum at FERC until summer time to be on our schedule. So I'm highly confident that the president will appoint folks by then, they will confirmed by the Senate and seated. So, we think, it's going extremely well, we've signed our construction contract. It's all taken into account all the changes that were necessary as a part of the rerouting through the mountains and the forests, the National Forest. So all in all, ACP is going extremely well.

Great. That's – that's all from me. That's helpful. Thank you.

Thank you.

And our last question comes from Paul Patterson of Glenrock Associates.

Good morning, guys.

Good morning, Paul.

Just following back – and I'm sorry, if I miss this. The solar ITCs for 2018, it sounds like that will be kind of the base line that you guys are looking for. Could you quantify what the total solar ITCs for 2018 are expected to be, roughly speaking?

Paul, right now, we're looking at kind of a normal customer driven run rate of about $0.10 a share from ITCs starting in 2018.

Okay. Has there been any change in the farm outlook performance?

We have – how are you doing, Paul? Good morning.

Hi.

We had – continue to have significant amount of interest in the farm-outs. Just to refresh you, I think we're about 3/5 of the way through the program. When we announced it in the beginning of 2015, we said that we would have – I think the number was about $450 million over a five-year period. We have done about 3/5 of it already. We have a lot of interests. We're not in any hurry to do. We have – we'll do plenty of farm-outs over that period, we're going to get the right price for them. So we're being patient, but we have plenty of interest.

Okay. And then, on the nuke life extension, it sounded like there might be a considerable rate base opportunity there, from a – and also from a risk reward or from a risk perspective, a lower risk than new build. I'm just wondering, the bill seems to be moving to a legislature associated with that. And I'm just wondering when, assuming that that go, what's your outlook for that is and when it quantitatively might start showing up in rate base

I'll answer that part of that question and I will turn it over to Paul Koonce. So your reference is to, I think is the – there's a legislation progressing through the Virginia General Assembly that makes it clear that life extensions of our Surry and North Anna Power Stations, these additional life extensions – license extensions would be subject to rider treatment. It's progressing particularly through the General Assembly. General Assembly adjourns for the year at the end of this month. And all it's doing is ensuring rider treatment for all those capital expenditures. With respect to new build, I think we said pretty consistently last few years, North Anna 3 is there as a possibility, an auction for us for Dominion, when and if, it becomes appropriate and is in the best interest of our customers to do so. I think it's quite clear that risk is less in doing life extensions than building new nuclear reactors as we've seen. But, I'll turn over the timing to Paul Koonce.

Good morning, Paul. Yeah, we – North Anna and Surry have operated terrifically over its life and we see the opportunity to spend probably in the order of $3 billion to $3.5 billion in just equipment upgrade. Right now, when we take an outage we perform a lot of maintenance. If we get the second license extension support then we might start replacing, not performing maintenance. So I think what you'll see is that beginning to take place in the 2018, 2019, 2020 and 2021 timeframe and even out into the decade. One of the things we'll have to look at is our traditional refueling outages, do we change the number of days to get more work done. So we're really looking at all of that now, but you should start to see that, provided the legislation, you should start to see that in our earnings in the 2019, 2020, 2021 timeframe.

Okay. And then just finally on the coal ash, are we pretty much finished with the impact of that given the last quarter, and is there any potential for recovery of these coal ash expenses?

Hey, Paul, I'm going to let Paul Koonce answer that one as well.

Yeah, Paul, you noticed we took $122 million after-tax charge in the fourth quarter to revise our estimates, and really those estimate revisions were due to just additional water treatment at Bremo and Possum Point. Recall we have four sites that we are in the process of remediating Possum Point, Bremo, Chesterfield and Chesapeake. We are in the process of getting the solid waste permits, which will govern the final closure plan and the 30-year water monitoring requirements. So I would expect, over time, as we get those solid waste permits, we buy – need to make revisions. But again, in a relative basis, our coal ash mitigation is pretty small relative to others.

Okay, but we don't expect any recovery of these expenses?

Well, we do have a rider recovery for active coal plants, and Chesterfield Power Station is an active coal plant, so we do expect the coal ash mitigation associated with Chesterfield will be recoverable.

Okay. Thank you.

Thank you. This does conclude this morning's conference call. You may disconnect your lines, and enjoy your day.