道明尼資源 (D) 2016 Q4 法說會逐字稿

Good morning and welcome to the Dominion Resources and Dominion Midstream Partners fourth-quarter earnings conference call.

(Operator Instructions)

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 e-mail alerts and view our year-end earnings documents.

Our website addresses are dom.com and dommidstream.com.

In addition to an earnings release kit, we have included a slide presentation on our website that will follow this morning's discussion.

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 take 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 competed 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 cents per unit payable on February 15th.

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 billion in capital to fund growth, make acquisitions, and repay maturing debt.

Cash flow from operating activities were $4.1 billion for 2016.

We have $5.5 billion of credit facilities and taking into account cash, short-term investments, and commercial paper outstanding, we ended the year with available liquidity of $2.4 billion.

For our planned public debt financings in 2017, please see slide 7. For statements of cash flow and liquidity, please see pages 13 and 24 of the earnings release kit.

As we move into 2017, Dominion will continue to see very strong capital growth, with the final year of construction at Cove Point, ongoing construction of the Greensville County power station, and the start of construction of the Atlantic Coast Pipeline.

However, with the completion of Cove Point and the anticipated asset drop into Dominion Midstream Partners in 2018, the Company's cash flow profile will change dramatically beginning next year, moving from negative to significantly positive.

As we have highlighted in the past, we expect to generate about $7 billion of cash flow as Cove Point is dropped into Dominion Midstream Partners, which we use to reduce debt, increase dividends in excess of 8% per year, invest in new growth projects and repurchase common stock.

As to hedging, you can find our hedge positions on page 26 of the earnings release kit.

We have hedged 85% of our expected 2017 production at Millstone and 100% of first-quarter production.

We also expect to limit our hedging of 2018 production until we see the outcome of pending legislation in the northeast.

Before we move to earnings guidance, let me comment briefly about anticipated federal tax law changes.

Our preliminary analysis shows a wide range of potential outcomes depending on what decisions are made around the actual tax rate, interest deductibility, day one expensing, and normalization.

We have highlighted some of the key issues on slide 8. Remember, different than many of our peers, we have a portfolio of non-regulated and long-term contracted cash flows that will be treated differently than our regulated portfolio.

Based on our asset mix and public information to date, we would expect to be somewhat earnings neutral to any final tax package.

Now to earnings guidance at Dominion, it has been evident for some time that 2017 will be a challenging year for Dominion to achieve its historical earnings growth rate.

Now that we have hedged most of Millstone's 2017 expected output, we estimate a $10 to $12 per megawatt hour reduction in realized energy prices versus last year, impacting 2017 earnings by about $0.15 to $0.20 per share.

Also as we have said on previous calls, we expect to generate about $0.30 per share in solar investment tax credits, a year-over-year reduction of almost $0.20 per share.

As a result, Dominion's operating earnings guidance for 2017 is $3.40 to $3.90 per share.

The midpoint of that range is $0.15 per share, or about 4% below operating earnings of $3.80 per share for 2016.

Operating earnings guidance for the first quarter of 2017 is $0.90 to $1.10 per share.

Moving to 2018, we believe operating earnings will increase by at least 10% over 2017.

Cove Point exports should provide between $0.40 and $0.45 per share of incremental earnings in 2018.

Having one fewer refueling outage at Millstone should add another $0.10 per share to year-over-year results.

Offsetting these growth drivers will be an expected further reduction in solar investment tax credits of $0.15 to $0.20 per share from 2017.

We expect about $0.10 per share contributions from solar ITCs in 2018 and beyond, driven by customer needs in Virginia.

While we are not providing a specific guidance range for 2018 today, you can see that these factors alone can support at least a 10% increase in year-over-year operating earnings.

Looking to 2019 and beyond, we believe our growth opportunities continue to be one of the best in the energy industry.

Some of the growth drivers to focus on are highlighted on slide 11.

All of our business segments are well positioned to support strong growth in 2018 and beyond.

In addition to these organic growth drivers, Dominion will benefit through the use of about $7 billion in cash flow generated by asset contributions to our MLP.

A portion of this cash flow will significantly reduce parent level debt and allow for share repurchases, as well as support our growth capital needs.

With the growth we have highlighted, we expect 6% to 8% compound average grow rate in earnings off a 2017 base through 2020.

Not only is this one of the best growth rates in the industry, but coupled with our stated intent to grow our dividend rate at over 8% annually beginning next year, Dominion provides investors with one of the best total return opportunities in the industry.

Let me summarize my financial review.

2016 operating earnings were $3.80 per share.

2017 operating earnings guidance is $3.40 to $3.90 per share.

2018 operating earnings are expected to be at least 10% above 2017.

2017 through 2020 earnings growth rate should be 6% to 8% and we anticipate dividend growth of more than 8% per year beginning in 2018.

I will now turn the call over to Tom Farrell.

Good morning.

Strong operational and safety performance continued at Dominion 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.

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 if 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 a 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 sites in five Virginia counties, all of which should be in service this year.

In total, we have announced close to 300 megawatts that will go into service by year end, bringing our operating portfolio to over 1,400 megawatts of solar generating capacity.

We have been working to secure a combined operating license for a third unit at our North Anna nuclear power station since 2009.

Last month the staff of the Nuclear Regulatory Commission completed its final safety evaluation report, concluding that there are no safety aspects that would preclude issuing the license for construction and operation of the proposed reactor.

Following a mandatory hearing later this year, the Commission will vote on whether to authorize the staff to issue a license.

Company has made no decision to construct North Anna 3, but with the combined operating license will preserve its option to do so should the Virginia State Corporation Commission believe it is in the best interest of our customers.

Company has included new nuclear in its integrated resource plan as one option to meet future customer demand and comply with environmental regulations.

Dominion Virginia Power connected 11 new data centers in 2016, two more than planned and two more than in 2015.

We anticipate a similar number of centers to come online this year and each year through the end of the decade.

In fact, we have already connected one new data center already this year.

In addition, anticipated increased federal spending on defense will provide strong support for the Virginia economy, which is the largest recipient of defense dollars in the nation.

We have a number of electric transmission projects at various stages of regulatory approvals and construction.

$784 million worth of these facilities were completed last year, including our new system operation center.

We plan to invest $800 million in our electric transmission business this year.

Our strategic under grounding program continues at Dominion Virginia Power.

In August of 2016, State Corporation Commission approved phase one in the recovery of $139 million capital investment to convert 412 miles of overhead tap lines to underground.

We will invest $110 million in capital and convert an additional 244 miles of overhead cap lines during phase two.

Progress on our growth plan for Dominion Energy continues as well.

Our Cove Point Liquefaction project is now 84% complete.

Engineering and procurement is essentially done.

All major equipment has been set and steel and pipe installation continues.

We completed pressure testing of the air cooled condenser and commissioning is under way for electrical, compressed air and water treatment.

We expect to achieve completion of 95% or more of structural steel by the end of this quarter.

The project continues on time and on budget to be in service later this year.

We are continuing to work toward the commence machine of construction on the Atlantic Coast Pipeline and the related Supply Header Project.

FERC issued its draft environmental statement in December, in line with their permitting schedule.

The report is favorable and importantly concluded that environmental impacts will be effectively mitigated and there would be no significant public safety impacts.

ACP has essentially completed its design, executed the construction contract, and completed over 80% of materials procurement.

The project's budget has been updated for the construction plan, including the cost to reroute segments impacting US Forest Service lands and we now anticipate total development cost for the project, excluding financing cost, of $5 billion to $5.5 billion.

ACP expects to maintain the returns on the project through a combination of construction contingencies and negotiated rate adjustments as allowed by the existing customer agreements.

We expect completion of the Atlantic Coast Pipeline and the Supply Header in the second half of 2019.

A record six major pipeline expansion projects were placed into service in 2016, adding 1.2 billion cubic feet per day of capacity for our customers.

We have an additional six pipeline growth projects under way, with $700 million of investment to move 900 million cubic feet per day for customers by the end of 2018.

We are seeing continued appetite for new pipeline expansion projects driven by new power, industrial and LDC load throughout our system.

We believe a more open federal policy for infrastructure investments will increase drilling in the basin and increase demand from industrials and other sectors.

Importantly, we'll also expedite approvals of gas infrastructure, which will in turn accelerate investments in needed pipeline expansions.

Based on these drivers, we expect to secure a number of new growth projects this year and significantly more through 2020 throughout our entire footprint, including our traditional Appalachian Basin, our new Western system and our expanding Eastern footprint, which has direct access to the fast growing Mid-Atlantic and Southeast US markets.

To summarize, our business has delivered strong operating and safety performance in 2016.

Construction of the Greensville County project is on time and on budget.

Construction of the Cove Point Liquefaction project is also on time and on budget.

We continue to work toward FERC approval for the Atlantic Coast Pipeline and the Supply Header Project and we look forward to completion of these major projects, which will deliver strong earnings and dividend growth starting next year.

As Mark stated, we expect earnings growth of at least 10% in 2018 and a diverse set of positive drivers will support continued growth in years to come, supporting an earnings-per-share growth rate of 6% to 8% through 2020 off of our 2017 base year.

Finally, because of our unique MLP structure, our superior cash flows will also allow a dividend growth rate at Dominion higher than 8% per year for the foreseeable future.

With that, we will be happy to take your questions.

(Operator Instructions)

Our first question comes from Julien Dumoulin-Smith from UBS.

Good morning.

How are you?

Good morning.

Perhaps just a first quick question on the tax reform scenario you discussed in which 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?

Julien, this is Mark.

We say neutral, we've run a number of different cases.

Some will be positive, some will 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.

The key drivers for us, and remember, our mix is different than 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 in our regulated operations we operate in many, many states and day one expensing.

Taking each one individually, they could have a positive or slightly negative impact, some greater than others, but because 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 pay down targets, buybacks and any tax implications from the drop?

Again, obviously with some moving pieces there, just kind of what you see today as 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 as a material number within that, as best you expect?

We have some tax strategies that we are planning to put in place.

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 that 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.

Morning.

Good morning.

You guys, when you talked about the guidance for 2017 over 2016, very, very clear.

The 2018 over 2017 also very clear 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 based growth forecast.

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 reason to be concerned about that.

Okay.

Are there any other -- over than thinking about whether or not there's a drop in 2017 and recycling of cash flow, are there any other major drivers for thinking about where we are in that 10% plus range?

No, I think the drivers -- Greg, this is Mark.

The drivers are pretty straightforward, 2017 to 2018.

Cove obviously is there, one fewer Millstone outage.

We've tried 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, we talked about it earlier, we've actually talked about it for about a 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 drain of a large capital spend program and we are not going to be in that business any big way in 2018 and beyond.

Great.

You also did not contemplate any change in regulatory scheme in Connecticut or Massachusetts as it pertains to clean energy credits from Millstone, correct?

The only thing we factored into our growth rate and for 2018 is a very modest increase for power prices in the northeast, just because wee think they're extraordinarily low right now.

I was not a reflection of any legislative effort that would be out there but just a normal slow recovery in the northeast on power.

Okay.

You guys raised -- last raised the dividend in December, so when you say that -- 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 would be again next December?

Yes.

We have -- the Board is fully aware of the statements we have been making since the fall that we expect starting in 2018 to have a dividend growth rate higher than 8%.

Our normal policy would be go back later in the year to talk to them about next year's dividend policy, but they're very aware and supportive of a 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.

Good morning, guys.

Good morning.

Hey, just a follow up on Greg's questions.

Can you elaborate a little more on why there's a 6% to 8% growth rate for the next few years instead of the old 7% to 9%?

Why -- you're already starting off a lower base.

I'm just wondering 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 am CP delay, although obviously ACP versus previous estimates will be lower in 2019 as the build out occurs and be stronger, or I guess equivalent, I should say, in 2020.

There's a couple things to think about there.

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 piece of it, which everybody -- there's 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.

That could go up, but we wanted to normalize that in this growth rate.

Also, the contributions at Hastings, a small processing plant that's is housed within DTI, their contributions are also down from previous expectations based on these same liquids pricing events that are out there.

Again, instead of taking a very bullish recovery in commodities, we've pretty much looked at the strip.

If your outlook is that is conservative based on a recovering economy in E&P and others, then that could well happen.

But those are the two biggest drivers in the 2019 and 2020 time frame than what we would have talked about previously.

Got you.

So you're being conservative and considering the -- when I look at the frac spreads going forward in the Marcellus, there has been improvement over the last six months and I'm just wondering if you're seeing any more interest from your customers.

There's has been I'm improvements, certainly in the basins two between South Point and Henry.

We've seen a little bit of 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.

We put out growth, anticipated growth, a couple 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.

Got you.

In terms of Connecticut legislation, is there a possibility for Massachusetts legislation to support nuclear as well?

Is that something you're hearing?

Good morning.

What we've heard is more through the regulatory process in Massachusetts, but yes.

What form would that take?

Similar, as we understand it.

All of this is in development.

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 as subsidies.

I'll leave that to others to discuss.

Connecticut is clearly not a subsidy.

It is an opportunity for us to bid 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 it this year than we got last year, it's been under some pressure, but we're hopeful that things will improve there.

All right.

Thank you.

Our next question comes from Steve Fleishman of Wolfe Research.

Hi.

Good morning.

A couple quickly.

Just on the 10% plus for 2018, you guys give pretty wide ranges when you do years, so is the 10% the low end of that wide range or is that being too specific?

The way I look at it, Steve, is if you look -- typically what most folks have done, they way we look at it, if you look at the midpoint of our range, we see it -- 2017, I should say, we would see at least 10% growth off the midpoint of 2017.

You are right, we do give fairly wide ranges.

That is mainly because we have been so weather sensitive the last five year that it can move an awful lot based in weather in Virginia and of Ohio for us.

That's how I would do the math, midpoint to midpoint.

That makes sense.

One clarification of something you've already said.

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.

I guess I wasn't exactly clear which is the answer to that.

Let me see if I can help you a little.

We looked 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 lift in power price.

Again, we don't know if it will 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 at what's out there and we've just taken a very conservative upside to that.

Last question is Tom mentioned kind of more opportunities for growth off of pipeline network, both the east and the west.

When we think about your 6% to 8% growth rate, is that would 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 there's been a lot of interest 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 Appalachian Basin area and now this more southeastern situation with what we have in South Carolina, for example.

They will start layering in.

New projects will start layering in, in 2019,2020 and 2021, so they're going to be spaced out.

There will be some in 2018.

There will be some in 2019, 2020, and 2021.

It depends how quickly we sign them up.

Some will be longer and more capital and some will be shorter and less capital.

They will come out.

They will -- as you've traditionally seen, we announce them as we sign them.

We will have projects that will come in 2018.

We already talked about those today.

We'll have more in 2019, more in 2020, more in 2021, more in 2022.

By expanding our gas infrastructure footprint, we've expanded the opportunities.

Okay.

Thank you.

Our next question comes from Angie Storozynski of Macquarie.

Thank you.

Just a follow-up question to Steve's question.

Again, did you incorporate those pipeline growth projects or any midstream growth projects in that 6% to 8% earnings growth for 2020?

A modest amount.

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 an estimate or even a probability at this point whether there will be success in Connecticut.

We would hope there would be, but we don't have a number today at all.

Okay.

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 pay down 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?

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 did between supporting organic growth, share repurchase and dividends, but on the dividend side, the math is fairly straightforward.

It will be a modest amount but it will be the amount that allows us to grow our dividend at a level that doesn't burden our regulated entities beyond a 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.

Again, it will be a split between that and as we get closer to the period we'll go ahead and give clarity.

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.

The drop-value that you guys talk about, $7 billion, has that already been negotiated with the complex committee?

It has not.

Okay.

What is the -- how are you going to drop this thing out?

Are you going to stagger it over a few years or will it happen all at once?

Right now we're anticipating staggering it over a few years.

A lot of that will depend, I think, on a couple 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 it 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.

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.

That's how we're thinking about it now but that could change based on opportunity out there.

Okay.

The value of the drop, $7 billion versus sort of, let's say, the book value after it's all said and done will be $4 billion, so 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, 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.

We would expect only the minimum amount to anticipate any tax issues that may occur out there in terms of units back.

Okay.

What happens with the preferred equity in 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 exchanged for common equity in Cove Point?

I think realistically once all Cove Point's dropped in, there's no preferred value to it at all, so it probably becomes common, but we haven't really talked about that.

Until it's all dropped in, differentiation is probably important, but after it's all in I'm not sure there's a need for that.

Okay.

You guys discussed the commissioning is under way.

Are you going to produce any commissioning cargoes this quarter, in the first quarter?

No.

Okay.

When would you envision producing the commissioning cargoes?

Assuming you sell those in the market, would that be used as a debit against your be PP&E.

Just to back up, we expect the unit to come online, be ready for commercial operations late this year.

The capacity and output is all entirely -- is owned by the shippers.

We have capacity contracts, take-or-pay contracts, on those.

So once it's operational, we will be receiving our payments for capacity and that will be up to the shippers to take the cargoes.

Sure.

I understand that, but I thought that -- and the commissioning stage will produce cargoes to test the facility, was my understanding, and then those commissioning cargoes sort of belong to you.

That's true.

At least, that's my understanding.

That will be late in the year.

Okay, last question from me.

Our next question comes from Jeremy Tonet of JPMorgan.

Good morning.

Good morning.

I just wanted to follow up on Atlantic Coast Pipeline a bit more.

If you could just comment on how the progress there and any thoughts as far as where FERC stands right now or the new administration.

Any updated thoughts on the regulatory environment would be helpful.

Doing quite well with the Atlantic Coast Pipeline.

The draft environmental impact statement came out as scheduled under the scheduling order.

It was 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.

We were -- FERC had done a very thorough analysis, but we had done a lot of very thorough work before filing everything.

Any major reroutes were already all scoped out before the draft environmental impact statement came out.

Comment period is under way.

Public hearings will be heard starting at the end of this month.

That 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 going down to two FERC commissioners here in 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 summertime to be on our schedule.

I'm highly confident that the President will appoint folks by them.

They'll be confirmed by the Senate and seated.

We think it's going extremely well.

We've signed our construction contract, all taking into account all the changes that were necessary as part of the rerouting through the mountains and the forest, the National Forest.

So all in all, ACP is going extremely well.

Great.

That's all from me.

That's helpful.

Thank you.

Our last question comes from Paul Patterson of Glenrock Associates.

Good morning, guys.

Good morning, Paul.

Just following l back on -- I'm sorry if I missed this.

The solar ITCs for 2018, it sounds like that will be kind of the baseline 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-out outlook for farm-outs?

How 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 we would have -- I think the number was about $450 million over a five-year period.

We've done about 3/5 of that already.

We have a lot of interest.

We're not in any hurry.

We'll do plenty of farm-outs over that period but we're going to get the right price for them.

So we're being patient but we have plenty of interest.

Okay.

On the nuke life extension, sounded like there might be considerable rate base opportunity there 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 through the legislature associated with that and I'm just wondering when -- assuming that, that goes -- what your outlook for that is and when it quantitatively might start showing up in rate base.

I'll answer part of that question.

I'll turn it over to Paul Koonce.

Your reference is to, I think, is there's legislation progressing through the Virginia General Assembly the 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 quickly 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 the last few years, North Anna 3, is there as a possibility, an option 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.

I'll turn over the timing to Paul Koonce.

Good morning, Paul.

Yes, we -- North Anna and Surry have operated terrifically over its life.

We see the opportunity to spend probably in the order of $3 billion to $3.5 billion in just equipment upgrades.

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 time frame and out into the decade.

One of the things that we'll have to look at is our traditional refueling outages.

Do we change the number of days to get more work done?

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 time frame.

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.

Yes, Paul, you notice we took a $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.

I would expect over time as we get those solid waste permits, we might need to make revisions.

But again, on 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 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.