道明尼資源 (D) 2019 Q1 法說會逐字稿

Good morning, and welcome to the Dominion Energy first quarter earnings conference call.

(Operator Instructions) I would now like to turn this call over to Steven Ridge, Vice President of Investor Relations.

Good morning, and welcome to the first quarter 2019 earnings conference call for Dominion Energy.

I encourage you to visit our Investor Relations website to view the earnings press release, a slide presentation that will follow this morning's prepared remarks and additional quarterly disclosures.

Schedules and the earnings release kit are intended to answer detailed questions pertaining to operating statistics and accounting, and the Investor Relations team will be available immediately after the call to answer additional questions.

The earnings release 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.

A reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures which we are able to calculate and report are contained in the earnings release kit.

Joining today's call are Tom Farrell, Chairman, President and Chief Executive Officer; Jim Chapman, Executive Vice President, Chief Financial Officer and Treasurer; and other members of the executive management team.

I will now turn the call over to Jim.

Thanks, Steve.

Good morning.

Dominion Energy reported first quarter 2019 operating earnings of $1.10 per share compared to our guidance range of $1.05 to $1.25 per share.

Otherwise strong performance across our businesses was impacted by unusually mild weather in Virginia and South Carolina, which reduced utility earnings by about $0.06 per share.

As a general indicator, heating degree days were 5% and 19% below normal in Virginia and South Carolina, respectively.

Various initiatives, primarily in Power Delivery and Power Generation, were successful in offsetting some of this headwind, and when adjusted for utility weather of $0.06, operating earnings for the quarter were $1.16 per share, which is above the midpoint of our guidance range.

Operating segment performance for the first quarter is shown on Slide 4. GAAP earnings for the quarter are negative $0.86 per share, which were driven primarily by the expected charges related to SCANA merger commitments and the early retirement of certain cold reserve Virginia utility-generating units.

Slide 5 highlights the pretax drivers of adjustments to reported earnings.

A reconciliation of operating earnings to reported earnings can be found on Schedule 2 of the earnings release kit.

On March 25, we held 2 sessions for investors that provided updates on capital investment, earnings and dividend growth outlook, financing plans, expense control initiatives as well as a first-of-its-kind sustainability and ESG-focused session, highlights of which are shown on Slide 6. It is worth noting that we continue to have full confidence in the earnings growth and other targets we've highlighted during those meetings.

We are very happy with the in-person and online attendance and thank all of those who were able to participate and provided feedback following the event.

Please note that the meeting materials, including the webcast replay, continue to be available on our website, which we encourage all to review thoroughly.

Also during this quarter, we continue to be engaged across a number of important though less public initiatives as follows.

First, as announced at our Investor Day, we are preparing to restructure our reporting segments, a meaningful change to the way we manage our businesses and report their financial performance.

We continue to forecast that this transition will take until late 2019 to complete.

The Alternate Breakdown Structure, or ABS, provides a preliminary view of our future intended reporting segment results and will be posted shortly after this call to our Investor Relations website.

The ABS, which is not reflective of how we currently manage our business, is not intended to replace Dominion Energy's current operating segment disclosures.

Second, progress is being made on our flat O&M and voluntary retirement program initiatives discussed at the end of March.

We're very intentionally combing through each of our segments, all of our assets and every location to identify opportunities to embrace technology, increase efficiency, improve business processes and enhance the customer experience.

Results of the voluntary retirement program discussed at our Investor Day including response rates from eligible employees, an assessment of backfill needs and financial impacts are still being quantified, although I would note that the preliminary response rate was robust.

We expect to be able to quantify these results on the next quarter's call.

Moving now to operating earnings guidance on Slide 7. As usual, our operating earnings guidance ranges assume normal weather, variations from which could cause results to be towards the top or the bottom of these guidance ranges.

For the second quarter, we are initiating guidance of $0.70 to $0.80 per share.

Positive factors as compared to last year include growth from regulated investment across electric and gas utility programs as well as a contribution from the Southeast Energy Group.

Negative factors as compared to last year include Millstone refueling outage timing, the impact of 2018 asset sales, share issuances and a return to normal weather.

We're also affirming our expectation for full year 2019 operating earnings per share between $4.05 and $4.40.

Positive 2019 full year drivers relative to last year include the growth from regulated investment across electric and gas utility programs, contribution from the Southeast Energy Group, a full year of Cove Point Liquefaction operations at run-rate production levels and expense control initiatives.

Negative drivers relative to last year are expected to include the impact of the 2018 noncore asset sales, share issuances and a return to normal weather.

Finally, we also reiterate our long-term EPS growth expectations of approximately 5% per year through 2020 and 5% plus thereafter.

I'll now turn the call over to Tom.

Thank you, Jim, and good morning.

On April 10, we were tragically reminded of the everyday risks our colleagues face when a fellow employee was fatally injured as a result of a gas line rupture caused by an unrelated third-party contractor installing fiber in Durham, North Carolina.

We are deeply saddened by the loss of this dedicated employee.

Our thoughts and prayers continue to go out to all who were impacted, including the family of the store owner, who also perished in the incident.

Turning to business updates.

We've provided a comprehensive update at our recent Investor Day meetings, so my remarks are brief.

First, a reminder that safety is our core value.

It is at the heart of our corporate culture, and we will continue to improve until we achieve the only acceptable safety statistic: 0 injuries.

Turning now to Slide 8. As highlighted at our Investor Day, we operate premium state-regulated utilities that center around 5 key states, which account for 65% to 70% of Dominion Energy's projected operating income.

During the first quarter, we saw a continued development of positive utility fundamentals across each jurisdiction.

In Virginia, we set a company record for new data center connects and had the most total new customer connections in the first quarter since 2012.

In South Carolina, our quarter-over-quarter customer growth was 1.7% for electric operations, which is the highest quarterly growth rate since 2008.

Gas customer growth was 3.1%, which is in line with prerecession levels of growth.

Gas distribution utilities in Utah and North Carolina reported strong customer growth of around 2.5% each.

And in Ohio, we saw 1.3% growth in throughput levels driven in part by the lowest unemployment rate in Ohio in the last 18 years.

These summary metric highlights -- these summary metrics highlight the opportunities we have to deploy capital in regulated programs that allow us to provide best-in-class customer service across our regulated footprint.

I will now review recent developments across the company.

Last month, the Virginia State Corporation Commission approved rider recovery under US-3 application, which represents 240 megawatts of cost-of-service solar with a $410 million capital investment through 2020.

We also announced a partnership with Facebook that includes 6 solar projects totaling 350 megawatts and approximately $600 million of investment also through 2020.

In coming weeks, we will begin construction on the $300 million Coastal Virginia Offshore Wind project, which was approved by the Commission last November.

These developments support the commitment we have made to have 3,000 megawatts of solar or wind resource in operation or under development in the state of Virginia by 2022.

On April 9, we celebrated the 1-year anniversary for commercial service of the Cove Point Liquefaction facility.

In its first year, the plant liquefied over 200 billion cubic feet of natural gas and met over 90% of customer nominations.

That success rate improved to 100% during the first quarter of this year.

In addition to an extra quarter of operation, Cove Point's record of sustained strong operational performance will contribute to our 2019 financial results relative to last year.

With regard to Millstone, 2 weeks ago, we hosted Governor Lamont and his team at the plant to celebrate the 10-year agreement signed on March 15 to provide critical 0-carbon power to the state and region.

We expect regulatory approval of the agreement later this year and the contract to become effective shortly thereafter.

We will resume the practice of providing hedging information for Millstone once the contract is approved and effective.

We are entering our fifth month of integrating the Southeast Energy Group.

Our team members are working diligently across geographies to socialize best practices and introduce common systems where needed.

While these integrations are major undertakings, we are advantaged by lessons learned from our Questar integration.

We remain focused on ensuring that throughout the process, we provide a safe and reliable customer experience.

Turning now to Slide 10.

At our investor meeting in March, we announced that we are permanently retiring several generating units, most of which have been placed into cold reserve.

Many of these units were designed to consume coal, and this step will help us achieve our recently updated company-wide emissions targets shown here.

Our new targets include a 55% and 80% reduction in gross carbon emissions from our electric generation fleet by 2030 and 2050, respectively.

We also have an ambitious methane reduction goal that calls for a 50% reduction in gross emissions from our gas infrastructure business by 2030.

These represent meaningful progress beyond our company's already impressive achievements over the last decade.

On a related note, we're pleased that earlier this week, the SCC approved all 11 of our proposed demand-side management programs, citing the Grid Transformation & Security Act support for those programs.

As a reminder, these program's costs, including a margin, are recoverable.

Additional ESG information is included in the appendix for your review.

And finally, with regard to Atlantic Coast Pipeline and Supply Header.

As shown on Slide 11, an appeal to the Supreme Court with regard to the Appalachian Trail crossing will be filed before the end of the second quarter.

We believe that the Solicitor General of the United States will join that appeal.

We continue to pursue legislative and administrative options as well.

Oral arguments on the biological opinion case are scheduled for next week with a decision expected within 90 days.

We expect to recommence construction on the project in the third quarter.

There has not been any change to expected time line or costs since our last earnings call or Investor Day meeting.

In summary, we achieved weather-normalized operating earnings per share above the midpoint of our guidance range.

We are affirming our full year operating earnings per share guidance.

We continue to see strong growth fundamentals in our state-regulated utility footprints.

We continue to make progress across our capital investment programs to the benefit of our customers.

We have a strong environmental social and governance story, and we will continue to increase our engagement with customers, shareholders and other stakeholders on those topics.

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

(Operator Instructions) Our first question will come from Greg Gordon, Evercore ISI.

Two questions.

One -- and I appreciate if you're limited in how much you can answer this.

But as it pertains to options for ACP, it's probably as, if not more, frustrating for investors as it is for you to watch this political process delay what is obviously a necessary piece of infrastructure.

But the way that this -- that you're going to phase construction here, is it possible that the portion of the pipeline that's impacted by the biological permit, assuming that that's resolved and you complete construction, could you still become a functioning infrastructure asset by backhauling gas off Transco and still serve your customers should you have an extensive period of uncertainty with regard to resolving the Appalachian Trail issue?

Greg, I'll start the answer.

And Diane can fill in any details.

The Transco backhaul solution is not a solution, does not meet our customers' needs on any kind of long-term basis.

Our customers need infrastructure from a different supply basin.

For example, the state of North Carolina has exactly one pipeline that serves the entire state, Transco.

That's why the policy-makers in North Carolina asked for additional gas infrastructure to be built into North Carolina that is not Transco.

It's in addition to Transco's lines.

We have full confidence in the biological opinion case.

The Forest Service follow the guidelines that were given to them by the court and completed that reissuing of the biological opinion.

And so we'll see what happens, but we believe we'll be under construction in the third quarter.

Diane, you can answer additional points on the timing.

No.

We are talking with the customers, and we have looked at phased-in service and we will -- we're in active negotiations with them.

They have reaffirmed the need for a permanent solution to be able to have the independent infrastructure and supply to meet their needs.

Great.

And just as a follow-up to that, the -- you're very clear in your presentation that, that Supreme Court path is the primary path here to hopefully get a solution.

You continually allude to these other potential administrative options but haven't wanted to "negotiate against yourselves" in public by articulating what they might be.

Is there anything at this point that you can articulate with regard to those solutions?

Or are you still not feeling like that's appropriate to discuss?

Greg, there are several.

But at this point, we think it's better to stand where we are.

Okay.

And then finally, I know it's extremely early in the year, but do you still feel comfortable that the guidance range -- the midpoint of the guidance range reflects a good baseline for the year?

Hey, Greg.

It's Jim.

Yes, we do.

Our next question will come from Chris Turnure, JPMorgan.

Jim, I think you made it very clear that you're working hard on the cost-cutting effort here and that you'll have the quantitative details for us next quarter, but I'm wondering if you can help us understand by segment kind of where those cost cuts might be able to fall through to your bottom line or benefit you, and if there would be a material amount of upfront cash costs that would be excluded from adjusted EPS.

Yes.

Thanks for that.

We do look forward to providing more update on the second quarter, in particular as it relates to our voluntary retirement program, which we announced at our Investor Day on March 25.

But there really are 2 parts of this.

One is a continuation of what we've been talking about since the last call, which is a flat O&M initiative and which is across our business segments.

And that really relates to a large number of small improvements across, as I mentioned in my prepared remarks, every segment, every location, every asset: leaning in on technology opportunities, finding better business processes, et cetera.

That flat O&M is on a normalized basis.

And by that, I mean that some of the savings will fall to the bottom line.

And some of that, in particular as it relates to rider O&M, for example, accretes to the benefit of the customer.

But we do expect flat O&M to be a driver for the foreseeable future on a bottom line basis for our earnings per share growth.

For the voluntary retirement plan, there are a lot of moving parts there.

As I mentioned, we had a robust response from our employees to the option we provided them.

I mentioned at Analyst Day that in the last iteration of this kind of program at Dominion, which was long ago, 2010, we had roughly a 10% acceptance rate from all of our employees.

So what we've done this time is we've offered the same type of program to union and nonunion employees where they have the ability to retire and receive their accrued retirement benefits, whatever they may be, in addition to severance which is in line with policy, which could be, in various cases, up to 12 months of severance.

So the way that will work is the severance payment will likely be treated as a onetime item, but the resulting savings in lower O&M cost from the VRP will begin to be recognized in our operating earnings starting soon after the second quarter.

Okay.

Great.

And is it fair to say that even though you've had kind of preliminary positive indications on acceptance and the success rate here, this is all kind of in line with the plan that you laid out just a month ago now?

Yes.

The VRP, which we started to talk about in public a month ago or so, that is additive to the flat O&M initiative.

But it is within our earnings guidance and stands ready to overcome any unexpected headwinds or things like $0.06 of weather that we incurred in the first quarter.

It is a positive, but it's within the guidance range for the year.

Our next question will come from Michael Weinstein, Crédit Suisse.

A quick question on the solar.

For the solar -- for the contracted solar that you get the ITC for, are you planning to safe harbor anything this year for that program?

Would you benefit from safe harboring the ITC at a 30% level going forward?

Michael, I don't believe that safe harboring really applies in our case.

I mean we're pretty quick to transact on these construction projects in Virginia as they arise.

So safe harboring is not really a factor in our case in Virginia.

Do those benefits get passed to the customer -- to your customers?

Or you do get to keep them in effect?

Or does it -- are the contracts basically earning the same ROE regardless?

Yes.

Michael, this is Paul Koonce.

The earnings impact, I mean when we think about safe harbor, as Jim said, I mean we're bringing these contracts to market.

We're not really sort of in a position to build a backlog of contracts because the need is immediate.

Tom announced the Facebook transaction.

We have a number of others that are in the pipeline.

And as soon as we can get those contracts finalized, then we'll be announcing and bringing those contracts to service.

And Michael, just to reiterate, what we outlined at the Analyst Day was a run rate ITC recognition of about up 10% to 15% -- $0.10 to $0.15, I'm sorry, per year, which is not really a significant increase from where we were last year.

And really 100% of that is related to what Paul just discussed.

This kind of investment on behalf nonjurisdictional customers in Virginia, that PPA structure, that helps us in part achieve the 3,000-megawatt commitment we've made in Virginia by 2022.

All right.

Got you.

It's a very limited program.

It's very structured, so doesn't really pay I guess to try to get ahead of the market with the safe harbored ITC.

I agree.

Our next question will come from Shar Pourreza, Guggenheim Partners.

Just a real quick update or just to follow up on ACP.

And obviously, fully understand why you don't want to negotiate with yourself as far as administrative or legislative.

But as investors are sort of thinking about the timing, are you sort of waiting for a SCOTUS affirmation that they would take on the case before coming out with something -- before disclosing what the administrative fix is?

Or are they -- so I guess how are we thinking about the timing and versus what SCOTUS' decision is?

It's a very perceptive question.

I think we need to just stand pat with what we've said about Atlantic Coast Pipeline and Supply Header for now.

We're working through the process.

As Greg Gordon mentioned a few minutes ago, it's been a very frustrating process, but we are winding our way through it.

Calendar is flipping, and we're making progress.

We believe that the Solicitor General will join us in this appeal, no guarantee of that.

We believe that he will.

That has a very high percentage of acceptance by the Supreme Court when that occurs.

And that'll take some additional time.

And there are other avenues that we just feel it's better not to talk about right at the moment.

So just to follow up there, was -- is MVP sort of a read-through on the timing for ACP?

And are you collaborating, working with sort of the NPC owners when you think about an administrative fix?

I don't think MVP's a read-through to ACP.

Got it.

Okay.

And then just lastly around the coal impairments and how we should sort of think about the upcoming rate review in Virginia.

You mean are they -- will the expense of that write-off be included and counted against earnings, is that the question?

Yes.

Perfect.

Yes.

The answer is yes.

Our next question will come from Michael Lapides, Goldman Sachs.

Hey, guys.

Just curious, a handful of things.

First of all, when you think about kind of the next 3 or 4 years, roughly how much incremental solar capacity, can you remind me of this, do you expect to own in Virginia versus having PPA-ed?

Yes.

Michael, this is Paul Koonce.

We committed to the Governor last year to develop 3,000 megawatts, to have that either in service or in development by 2022.

The Grid Transformation & Security Act also calls on us to purchase 25% of that amount from third parties.

So the way we think about it, 75% of the 3,000 megawatts that we've committed will be Dominion-owned.

Now that will be a combination of both rate-based solar like US-3 that was just approved by the Commission, and it will include bilateral agreements with customers such as Facebook or others.

So it'll be a combination of those 2. I would expect that you would see somewhere on the order of 250 to 500 megawatts a year for the developed, and that will allow us to achieve our commitment to the Governor.

How should we think about the economics of the different types, meaning the type that kind of go traditionally in the rate base versus the type that are PPA?

Does one have a very different economic impact on Virginia Power's earnings relative to the other?

Well, they do.

Those that are in the rate base obviously have an earnings profile over the life of the agreement.

So in that regard, I think it's good for our customers, and it's good for our shareholders.

The bilateral agreements that we enter into, as you know, bring with it ITC income, which tends to kind of weight the income to the early part of the period, so different earnings profile, different customer needs.

But we are engaged, doing both.

Our next question will come from Angie Storozynski, Macquarie.

I wanted to ask about coal ash.

So North Carolina seems to be mimicking what Virginia has proposed as far as remediation of coal ash ponds.

Duke is pushing really hard against it.

You guys seem to be okay with what Virginia has decided.

So talk us through why that is and why you don't actually have an issue with spending this CapEx.

Angie, this is Paul Koonce.

We worked collaboratively with all the local communities as well as the legislative and executive leadership on the solution.

Cap and close in place was something that did not seem to be -- while it was federally approved by the Obama administration, it was not something that our local communities wanted.

So the solution that we came up with was on-site landfilling.

Now one reason we think it is probably more supported in Virginia than North Carolina is Dominion relatively has a small coal ash issue to deal with.

Our 27 million metric tons is small compared to Duke and small compared to others.

So we believe that we have a good solution for the local communities.

It's something that is supported by the legislation and supported by the executive branch.

So we look forward to getting that work started as soon as the bill takes effect on July 1. We already have the land, so it'll be a matter of basically moving the ash into a landfill on the existing site.

Paul, if I could add.

Angie, it's Jim.

You mentioned in your question the CapEx, which this program primarily is O&M expense, very little of it is actually capital costs, so it's not a major earnings driver for us.

And most of the activity in the accounting space related to this new legislation is just in the balance sheet, not impacting the income statement, recognition of an ARO and a regulatory asset.

Okay.

And just one follow-up on ACP.

So again, I understand that there are few comparisons between MVP and ACP.

But MVP seems to be suggesting that rerouting the pipe through private lands was a potential alternative, and so could you comment if that's a possibility for ACP, like last resort?

And if it is, why didn't you consider that to start with?

I'm talking about the crossing of the Appalachian Trail.

No, I understand.

There are a lot of possibilities, Angie.

That is one.

And what we may or may not have considered some years ago, I'll just -- I'll leave for after we have finished our court arguments for -- after we finish with the courts on all these issues and/or get our solutions, we'll be happy to talk through with folks all the process we went through over these last few years.

There -- as I've said, there are lots of alternatives.

And we just don't think it's useful at this time to talk about them.

I appreciate the frustration level.

Believe me.

One thing Greg said about how he thinks the investor community is as frustrated as we are, I'm not sure that that's a possibility.

Our next question will come from Abe Azar, Deutsche Bank.

Is there any update on your 2019 financing plans and specifically on the size and timing of the convert refinancing?

And then relatedly, when do you expect to put permanent financing on for Cove Point?

Might you take on a minority partner there?

Got it.

Abe, it's Jim.

Sorry for the interruption.

Yes, there's no material change to our plans for our financing for the year.

As we mentioned on our fourth quarter call, we do plan to replace the maturing -- converting existing $1.4 billion mandatory convertible that we issued in 2016.

Those plans are on track for the year, and we're going to be opportunistic based on market conditions kind of through the summer period, based on not only the exact timing of that but also the exact size.

What we've said is around the size of the one that's converting which is $1.4 billion, which is still is our expectation, again, depending on market conditions.

On Cove, we have lots of time there.

So as you know, late last year, we put in place $3 billion of basically pretty vanilla nonrecourse bank debt.

So the cost of that is attractive.

It's below 4% right now.

It's nonamortizing.

It's prepayable at any time, and there are 2.5 years roughly left on the tenor.

So we have lots of options on how to refinance that, but we also have lots of time.

So no specific guidance on that activity but plenty of flexibility based on what we did late last year.

Our next question will come from Andrew Weisel from Scotia Howard.

Just wanted to clarify.

You've affirmed the 2019 guidance.

But on the drivers slide, it looks like you added expense control initiatives as a positive driver and removed pension expense as a negative.

Can you just give a little more detail as to what caused those changes?

And is that the same stuff you talked about at the Analyst Day?

Or does this maybe suggest you're leaning toward the higher end of the range?

Maybe just some thoughts on that tweak.

Yes, let me address that.

This is Jim.

Let me address that and then more generally, the sculpting of our expected earnings through the year.

We do expect some positive impacts -- again, we haven't baked the numbers yet on the VRP element but some positive impact this year to our operating earnings from our O&M initiatives including our voluntary retirement program.

The pension headwind was really something we highlighted as a short-term change between basically [EEI] and the first of the year.

But that modest impact which was about $0.04 change based on market activity in that short time period, that has been baked into our expectations for the year and is unchanged.

Those pension assumptions that drive the accounting are revisited, as you know, basically every December 31.

So no change before the clock turns at the end of this year.

But let me give a little more guidance on -- a little more granular detail on the sculpting of our earnings through the year, and I gave Greg a somewhat [curt] response that we do still target and expect the midpoint of our range for the year.

But admittedly, our earnings profile is back-end dated.

And that's not something new to us.

I know we've just released our second quarter earnings guidance this morning, but this is as we expected other than the impact of the $0.06 of the weather headwind in the first quarter.

So just to walk you through that, it's a little more than you asked.

But Q1, $1.10.

The midpoint of our Q2 guidance range, $0.70 to $0.80, is $0.75, so $1.85.

Add in $0.06 of weather, you get to $1.91.

So comparing it to last year, $1.91 is $0.09 less than $2, which is where we were during the first 2 quarters of last year.

So clearly, the earnings growth for this year, even aside from the weather headwind, is in the second half, and there are a few reasons for that.

Actually, there a number of reasons for that this year.

One is the timing of the Millstone outage, which last year was in 3Q, this year's in 2Q.

That's one thing that kind of pushes up our second half contribution this year versus last.

There's a full year of Cove Point contribution at run rate production levels, which means without some of the ramp-up costs that last year we had budgeted and experienced in the last 3 quarters.

There's still some improvement that this year versus last, not only the first quarter.

As I mentioned in my prepared remarks, there's growth in regulated investment across electric and gas utilities through the year, which accretes.

There some timing of ITC and farm-outs through the year, this year versus last.

And then last thing is -- there's more to come, and we'll provide some more guidance on the second quarter call, is what you mentioned, the operating expense initiatives: the continuation of flat O&M but also the impact to operating earnings of our voluntary retirement program.

So overall, we're on track but certainly heavier in the second half of this year versus the first half in particular as compared to 2018.

Ladies and gentlemen, at this time, this does conclude this morning's conference call.

You may disconnect your lines, and enjoy your day.

Thank you.