道明尼資源 (D) 2018 Q4 法說會逐字稿

Ladies and gentlemen, good morning, and welcome to the Dominion Energy Fourth Quarter Earnings Conference Call.

(Operator Instructions) I would now like to turn the call over to Mr. Steven Ridge, Director of Investor Relations for the safe harbor statements.

Good morning, and welcome to the Fourth Quarter 2018 Earnings Conference Call for Dominion Energy.

I encourage you to visit the Investor Relations page on our website to view the earnings press releases and accompanying materials as well as a slide presentation that will follow this morning's prepared remarks.

Schedules in 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 report 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, 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.

Good morning.

Dominion Energy reported operating earnings of $0.89 per share for the fourth quarter of 2018, which is above the midpoint of our guidance range of $0.80 to $0.95 per share.

GAAP earnings for the quarter were $0.97 per share, which includes gains on the sales of noncore assets.

For the full year, we reported operating earnings of $4.05 per share, which is also above the midpoint of our guidance range of $3.95 to $4.10 per share.

Drivers relative to our guidance include lower O&M, income tax and depreciation expense as well as favorable weather, partially offset by a longer commissioning process for the Cove Point Liquefaction process -- projects during the first quarter and higher storm restoration expense in the third and fourth quarters.

We are pleased that despite a challenging year, we achieved annual operating earnings per share growth of 12.5%.

Operating segment performance for the fourth quarter and the full year are shown on Slide 4. GAAP earnings for the year were $3.74 per share.

Differences between operating and reported earnings included gains on sale of noncore assets, unrealized losses on nuclear decommissioning trust funds and onetime rate credits issued to customers under Virginia legislation passed in March.

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

Before we turn the page completely on 2018, we want to briefly highlight some of the important initiatives that we successfully executed during the year and that we believe will position us for success in 2019.

As mentioned, we achieved annual operating earnings per share growth of more than 10% despite a number of headwinds, including the dramatically altered financing plan.

We grew the dividend per share by 10% year-over-year, consistent with the commitment we had previously made to shareholders and slightly lower than annual operating earnings per share growth.

We sold noncore merchant assets at attractive valuation, improving our business risk profile and generating over $2.5 billion of sale proceeds, which we used to retire parent-level debt.

We placed both the Cove Point Liquefaction project and Greensville Power Station into commercial service, collectively representing over $5 billion of invested capital.

I'm pleased to report that Cove Point continues to operate at or above designed capacity and successfully completed the same-day loading of an export cargo and unloading of an import cargo during the fourth quarter, which we believe may be a first for the domestic LNG industry.

Greensville is also operating as designed.

We took meaningful steps to improve our credit profile, including reducing parent-level debt by about $8 billion through proceeds from equity issuance, noncore asset sales and a Cove Point asset level financing.

As a result of these efforts, we achieved our parent-level leverage targets 2 years ahead of schedule.

We also materially improved our cash flow coverage metric as measured by Moody's.

These achievements in combination with the improved business risk profile due to asset sales and the addition of SCANA's high-quality regulated businesses resulted in the affirmation of our existing credit ratings and the lowering of our credit metric thresholds.

In Virginia, we worked with legislators, the Governor, customer groups and other important stakeholders to support the Grid Transformation & Security Act, a bipartisan law that provides a path to a sustainable and reliable energy future in the Commonwealth.

And finally, we obtained all required regulatory approvals and subsequently closed our merger with SCANA, which we expect to provide near-term earnings of approximately $0.10 per share per year.

Tom will talk more about this a little later, but we are pleased that we were able to offer significant value to SCANA customers, protections to SCANA employees and preserve transaction economics that our shareholders and credit providers expected.

Moving now to 2019 earnings guidance.

Operating earnings per share for 2019 are expected to be between $4.05 and $4.40 per share.

This guidance range of $0.35 is narrower than in recent years reflecting the increasingly regulated nature of our operation.

The midpoint of this range represents 5.6% growth relative to 2018's weather-normalized results.

As usual, our guidance assumes normal weather, variations from which could cause results to be toward the top or the bottom of this narrower guidance range.

Positive factors as compared to last year include an additional quarter of commercial operations of the Cove Point Liquefaction project, the addition of the Southeast Energy Group operating segment, which includes all former SCANA operations and growth from regulated investment.

Negative factors as compared to last year include the loss of earnings from 2018 asset sales, higher share count, higher pension expense and a return to normal weather.

The midpoint of our 2019 guidance range assumes that ACP construction recommences during the third quarter of this year, which Tom will address momentarily.

It excludes any contribution associated with the Blue Racer earnout, which could be 0, as well as any contribution associated with the resolution of the outstanding zero carbon energy procurement process in Connecticut, which Tom will also address.

Our operating earnings guidance for the first quarter of this year is $1.05 to $1.25 per share compared to $1.14 per share in the first quarter of 2018.

Positive factors relative to Q1 2018 include the contribution from the Cove Point Liquefaction project and the addition of the Southeast Energy Group.

Negative factors include timing of contributions from farmout, the loss of earnings from asset sales and a higher share count.

While we are not providing formal 2020 operating earnings guidance on today's call, we do expect approximately 5% growth from 2019 to 2020, which aligns with achieving our most recent guidance regarding our 2017 to 2020, 6% to 8% compounded annual growth rate.

This 2020 expectation also excludes impact of any Blue Racer earnout and the contribution from a resolution in Connecticut.

Finally, we expect dividend per share growth in 2019 of 10%.

Please note that all dividend declarations are subject to board approval.

Major elements of our 2019 financing plan are included on Slide 8. In addition to a fairly standard debt financing program, we intend to replace and possibly increase the size of the mandatory convertible security that was issued to 3 years ago and which converts in the third quarter.

Despite affirmed ratings and lower credit metric downgrade thresholds, we will continue to take steps to support our credit profile.

Turning to Dominion Energy Midstream Partners.

The merger of DM into Dominion Energy was completed earlier this week.

We issued approximately 22 million shares in exchange for all outstanding Dominion Midstream common and preferred units.

The merged assets now reside at subsidiaries of our parent company, though we intend for certain assets to migrate to Dominion Energy Gas Holdings during the year.

Finally, we plan to make 2 distinct presentations for investors on March 25.

The first presentation targeting the general investor community will include a number of informational updates, such as asset profiles -- asset profile updates, including for the newly added Southeast Energy Group, capital investment programs, opportunities under the Grid Transformation & Security Act in Virginia, O&M initiatives and long-term dividend growth and capital structure objectives.

We believe that this brief presentation will provide reference information and insights that will help investors to better understand Dominion Energy's expanded operational footprint as well as drivers behind our expectation for 5%-plus growth in operating earnings per share beyond 2020.

We're pleased to announce that in a second and separate presentation on that day, we will provide an update that will focus exclusively on our accomplishments and efforts on environmental, social and governance matters and how those efforts underpin our long-term strategy and position us to be -- to become an industry leader in sustainability.

To our knowledge, this is the first instance of a major company from the energy infrastructure industry or otherwise to host an investor session dedicated exclusively to these matters.

The target audience for this second presentation is members of the financial community with special focus on ESG topics.

Both of these presentations will be webcast live on our Investor Relations website with an opportunity to submit questions electronically so that, in the event of capacity constraints at our New York City venue, all investors will be able to participate.

We'll be providing additional information regarding these investor updates in the near future.

I will now turn the call over to Tom.

Thank you, Jim, and good morning.

For the second straight year, we have set a company record for the lowest OSHA recordable incident rate in our history, 0.55, which is an 8% improvement over what was a record-setting performance in 2017.

This achievement is equally impressive when compared to a peer average that is nearly twice as high.

Safety does not just happen.

These results represent years of focus on making sure that every employee returns home in the same condition in which they arrived at work that day.

We're going to get to continue to improve until we achieve the only acceptable safety statistic, 0 injuries.

Now to our business updates.

I will begin by addressing our merger with SCANA, which closed at the beginning of this year.

Our new operating segment, the Southeast Energy Group, comprises all of the former SCANA operations.

Rodney Blevins, one of our most experienced utility operators now leads the segment.

He is working among the over 5,000 able and dedicated colleagues that now comprise the Southeast Energy Group.

The group's high-quality businesses and our colleagues who operate them enhance Dominion's best-in-class portfolio of state-regulated utility operations.

For example, customer growth at SEG's electric and gas utilities were 1.7% and 2.8% respectively, during 2018.

North and South Carolina, despite the challenges related to new nuclear development in the latter, are considered to be among the most constructive regulatory jurisdictions in the country.

In 2020, we will file a rate case in South Carolina that, subject to commission approval, will reflect recovery of traditional electric utility capital investment that is not currently being recovered in rates.

Those new rates, subject to approval, will become effective on January 1, 2021.

Over the coming months, we will continue to build trust with customers, employees, regulators and policymakers by keeping our commitments and being a transparent and responsible corporate citizen.

We look forward to discussing the Southeast Energy Group in greater detail in our investor meeting in March.

Next, I'll turn to updates related to the Grid Transformation & Security Act adopted last year in Virginia.

In less than a year, we have filed for and received Virginia State Corporation Commission approval for projects representing over $1 billion of capital investment.

We expect that number to grow significantly over the next several years as we continue to invest to make our system increasingly sustainable and reliable for our customers.

First, we received approval from the SCC for approximately $300 million offshore wind projects, which will be completed under a fixed cost construction agreement.

This pilot has the support of Governor Northam and Virginia's General Assembly, and will provide important early learning that we believe will lay the foundation for commercial-scale offshore wind for Virginia's clean energy future.

Construction of the project is expected to begin this second quarter with a commercial in-service date in late 2020.

Second, we received approval from the SCC for phases 2 and 3 of our strategic undergrounding program representing a capital investment of about $240 million.

This effort improves the reliability of our system and substantially reduces the duration of restoration times following severe weather events.

Third, we received an order granting our certificate of public necessity and convenience for our U.S. 3 utility-scale solar farms, representing 240 megawatts at a capital cost of around $410 million.

We remain committed to advancing our goal of having 3,000 megawatts of additional renewable generating capacity in-service or under development by 2022, and we expect to make regular filings under the GTSA with the commission for additional projects in the future.

Next, we received partial approval from the SCC for our initial grid transformation application.

The commission approved nearly $100 million of capital over 3 years associated with important physical and cybersecurity investments.

The commission asked for more information to support capital investment associated with other aspects of our grid mod strategy, including smart meters, intelligent grid devices and an enhanced customer information platform that allows more sophisticated and convenient customer experience.

We will provide that data when we refile our application later this summer.

A decision on the refiled application would be expected 6 months after.

I want to offer a few remarks related to recently proposed legislation supported by Governor Northam and bipartisan legislative leadership that establishes a path for addressing our coal ash empanelments.

We support the policymakers' desire to resolve this issue permanently through annual rider recovery.

The legislation would provide for full cost recovery of operating expense and capital investment associated with the recycling of coal ash for beneficial use and the construction of on-site lined landfills for disposal of the residual coal ash.

We believe that, that legislation provides a fair balance between Dominion Energy's customers and its shareholders, and allocates the cost of this program equitably among large and small users of electricity.

I'll now address Millstone and the Atlantic Coast Pipeline.

With regard to Millstone, it's important to recognize the extent of the progress that has been made to date on ensuring the long-term viability of this critically important resource to Connecticut.

We began engaging in the legislative process 3 years ago.

We have diligently followed the law and the requirements established by both DEEP and PURA, and each agency has determined Millstone is an at-risk resource.

Former Governor Malloy made an announcement in late December awarding Millstone a 10-year agreement for 9 million megawatt hours per year.

The awarded price for the first 3 years of the contract is approximately equal to the New England wholesale power price.

That is not an acceptable result for the company and our 1,500 Millstone colleagues who work safely every day to provide half of the power and 90% of zero carbon power to the State of Connecticut.

In order to ensure the plant's viability, we must have pricing that recognizes energy security, environmental and economic benefits.

We have and will continue to engage constructively with Governor Lamont's team in seeking a solution work for the state, the region, our company and our employees.

We are confident that these issues will be resolved in a manner that provides the long-term financial assurance required for Millstone's continued operation.

As to the Atlantic Coast Pipeline and Supply Header projects, we remain highly confident in the successful and timely resolution of all outstanding permit issues as well as the ultimate completion of the entire project for the following reasons.

First, our customers critically need this project to heat and electrify homes, businesses and industries; assist in the transition away from coal-fired power generation; support economic and renewable energy development; and reduce reliance on a single source of gas delivery.

Our customers, state regulatory commissions and FERC have all attested independently to the need for this project.

Second, we have followed the established rules with regard to permitting environmental protections.

Years of painstaking surveying, data collection and scientific analysis stand behind all of our permit applications.

In fact, most of our permits are setting new national standards in minimizing environmental impact.

Without speaking for the permitting agencies, these professionals have followed the letter in the spirit of the rules, regulations and established precedents that guide their action on our permit applications.

Third, we are actively pursuing multiple paths to resolve all outstanding permit issues, including judicial, legislative and administrative avenues.

We are not alone in these positions.

We have the support of the agencies, our customers and varied industry interests.

Our current expectation is that full construction could restart in the third quarter.

This reflects our belief that the biological opinion issue and any impediments with the crossing the Appalachian Trail should be resolved no later than this fall.

Based on this schedule, key segments of the project, including from Buckingham County located in Central Virginia to the presently planned terminus in Hampton Roads in Eastern Virginia, and in Lumberton in Southeastern North Carolina would enter commercial service by the end of 2020 with the balance of the project being delivered in early 2021.

The cost of the project based on this schedule is expected to be $7 billion to $7.5 billion, excluding financing costs, an increase of approximately $500 million since the update we provided in November.

Similarly, we expect that the Supply Header project would enter commercial service in late 2020, with a project cost of $650 million to $700 million.

While we believe that the Appalachian Trial crossing issue should be resolved in time to recommence construction along the entire route during the third quarter, we intended to continue to build key segments that will deliver partial service to our customers by the end of 2020.

The completion of the remaining section, which could involve an appeal in Supreme Court would complement the first phase of service by the end of 2021.

Under this alternative, total project cost would increase an additional $250 million, resulting in total project cost of $7.25 billion to $7.75 billion, excluding financing costs.

In either case, we're currently working with customers to set rates that balance customer needs with preserving a fair project return.

It's important to understand that the average basis differential over the last 5 years has been $1.79 per dekatherm, which significantly exceeds the rate of this project.

And of course, cost is not the only factor driving our customers' demand.

Additional and diversified supply is critical, given that they are forced to turn away new customers due to the lack of infrastructure.

When extreme weather occurs, such as the existing polar vortex in the Midwest or the bitter cold that affected the Mid-Atlantic in both 2016 and 2018, the concept of reliable and redundant energy supply assumes a new and much more serious meaning.

Policymakers understand the gravity of the situation.

Disruptions to the region's limited supply of existing gas delivery infrastructure and weather-driven demand spikes have and will continue to result in higher prices, forced curtailments and lower reliability for customers until the project is complete.

To be clear, we believe that there are multiple paths that will allow us to complete the entire 600-mile project.

As was the case regarding the challenges we faced in the development of the Cove Point Liquefaction project and the closing of our merger with SCANA, large projects require transparency and determination.

We have an abundance of both.

We will continue to accrue AFUDC equity earnings and expect ACP to contribute to our operating earnings in 2019, 2020 and for decades to come.

In summary, during 2018, we set a new company record for safety performance for the second consecutive year.

We delivered 2018 operating earnings per share that exceeded the midpoint of our guidance range and initiated 2019 guidance that implies over 5% annual growth to 2018 weather-normalized results.

Our 2019 dividends per share are expected to grow 10% subject to board approval.

We successfully executed several major initiatives, including merchant asset sales, $8 billion of parent-level debt reduction, the buy-in of Dominion Energy Midstream Partners and the commercial in-service of the Cove Point Liquefaction project and Greensville Power station that support our earnings and credit objectives and position the business to continue to deliver visible, diversified and regulated growth in the future.

We completed the SCANA merger, adding exciting new businesses to our best-in-class regulated portfolio.

We continued progress towards successful resolution for both Millstone and ACP.

And we advanced capital programs that will help to support 5%-plus earnings growth into the next decade.

With that, we're happy to take your questions.

(Operator Instructions) Our first question comes from Shahriar Pourreza with Guggenheim Partners.

Couple of questions here.

First on sort of Millstone.

You obviously are excluding the zero carbon procurement in your outlook.

Is this a pricing issue given what's currently proposed, i.e., it's not very accretive to your growth?

Or are you kind of implying that a closure is still in the mix, if you get the pricing as currently proposed?

So just trying to figure out why it's been excluded.

Shahriar, it's Jim.

Good questions.

So the way we think about that is that if you look at the table right now, as you know, within this 10-year contract, for the first 3 three years, it's basically roughly equivalent to market pricing, so no need for us to have a contract for that.

So we're hopeful that there will be a contract for that period, the value of these other attributes we've talked about for Millstone.

So if that comes into place, the contribution from such a contract for the relevant period would be an adder to our guidance -- earnings guidance.

Doesn't necessarily mean it would change our growth rate, but it will be an adder to the existing guidance.

So that's what we mean by that, that's excluded.

There will be a potential for an adder for the time period in which a federal contract comes into place.

Okay.

Is it palatable for you as currently proposed?

Or is there -- or is sort of a shutdown still something that's in -- a potential given what's in store there?

Shahriar, we have a new administration in place.

We've been working very constructively with them.

So I'm not going to -- we're not here to do any saber rattling today.

Our position hasn't changed.

We have to have a clear financial path for Millstone.

That proposal from Governor Malloy's outgoing proposal does not meet that standard.

Got it.

Okay.

Good.

And then Tom, let me just ask you, and you touched on it very -- you touched on it in your prepared remarks around the economics of, sort of, the pipe Atlantic Coast, especially with this sort of second delay and cost increase.

Can you just be a little bit more specific on how the conversations are going?

But more importantly, what sort of the impact this sort of legislation, I think it's Bill No.

1718, that's advancing to the general assembly.

Do you -- is there a viability to this thing?

And so just what are your thoughts there?

Well.

So that's -- I think that's 2 different questions in that.

So as I understand, the first one is about -- are you talking about conversation with customers?

Correct.

Okay.

Diane -- I'll let Diane answer that question in just a second, Diane Leopold.

With respect to the legislation, I would just say, I think the simplest answer is to say that legislation has a long way to go in the general assembly.

This is Diane Leopold.

With respect to the contract, there are provisions in the contract to discuss both rates and terms.

And as Tom discussed, given the latest schedule and costs that we talked about today, we're already working with customers to set these rates and terms, partial and service options, the actual rates for the service, et cetera.

And we're confident we're going to be able to balance the customer needs and provide them with their critical need for this project in both cost and noncost items, while preserving a fair return for the project, but we really don't want to go into any more detail than that.

Let me add just one thought also on the legislation.

I think it's also fair to say that in its present form -- it's not likely to come through the general assembly process in its present form.

Our next question comes from Steve Fleishman with Wolfe Research.

So just to follow up on the ACP contracts.

Tom, you mentioned the $1.79 dekatherm last 5 year.

Just could you give us a sense of where the contract pricing of ACP is now versus that?

No, Steve, we can't.

That's all through confidential agreements with the customers, but I can tell you that this -- it's significantly lower than $1.79.

Yes.

Okay.

And then what is pricing now -- like, more like now as opposed to the last 5 years.

Is it in that ballpark, too?

Yes.

I mean, the last few days, when it was cold, it wasn't as cold on the East Coast, obviously, as it was on the Midwest.

But I believe it was somewhere $5, $6 versus the Henry Hub.

It certainly has value there.

But that 5-year average actually is summer and wintertime.

It is averaged through the entire year, not just the price spikes of the winter.

So it continues to show value and increase that you see in these cold times.

Okay.

And then just in terms of going back to -- there was a question -- I just want to clarify the comments on the convert.

So that your intention is to issue a new convert when that one's done or just remarket that debt?

Yes, good question.

We are required, based on the terms of the existing unit, to remarket the debt.

That doesn't represent an increase in debt, it's just remarketing, which will be this year.

But this is our last outstanding mandatory convertible security.

So the equity converts into common equity, the equity's [gone] in August.

And we view that as an attractive security to us, and we think there is demand for it in the capital markets', our perception.

So we do plan to replace it.

Will it be exactly the same as the securities we've issued in the past?

Could be slightly different.

But some form of that hybrid capital or mandatory convertible or otherwise, we plan to use to replace the $1.4 billion that effectively goes away in the middle of this year, in August.

And then one last question, just back to ACP.

So I think there's been some concern that it's often hard to get an en banc hearing.

But obviously, this is, obviously, a pretty important case.

So just maybe you could give some color on why this -- it might be different this time and your ability to get that hearing.

Well, Steve, this is Tom.

You're quite right, en banc proceedings are -- they don't happen every day of the week, they don't happen every month.

This case, I don't know if you've had a chance to read the brief that was filed on behalf of ACP last week, but I think it sets the story out pretty well.

There are 50 pipelines that go underneath the Appalachian Trail today, about 50, that are now all in question.

We have significant support from a variety of folks.

I think you'll see 10 or more friends of the court file brief -- a brief or briefs sometime late next week.

The Department of Justice will weigh in before February 11 on the importance of this.

But that's -- we'll see what happens.

There is other avenues, as I've mentioned.

There -- you can always appeal to Supreme Court, obviously.

And there is legislative efforts underway, and there are other potential administrative avenues we're looking at that we haven't been able to pursue very thoroughly because of the government shutdown.

So the en banc is an important milestone, but it's not by any stretch the only avenue to make sure we finish this pipe, in which we are highly confident.

Our next question comes from Rose-Lynn Armstrong with UBS.

You talked about discussing long-term dividend growth.

I'm sorry.

Is that -- I'm sorry, was that a question?

I'm sorry, I didn't hear the whole thing.

I'm sorry.

It looks like she accidentally disconnected her line.

We'll go to our next questioner, Greg Gordon with Evercore ISI.

Thanks for the updated guidance range.

I know that you had given sort of an interim guidance update in early January and the illustrative guidance range at the time for 2020 was $4.35 to $4.47.

Now if I did take the current guidance for '19 and I just extrapolate 5% growth around, should I be extrapolating 5% growth from the low and the high ends to come up with what you guys believe your current 2020 implied guidance range should be, to get the low end and the high end?

I just want to be clear on that.

Yes, Greg, thanks.

It's Jim.

We're not really talking about a guidance range for 2020 yet.

We've given this indicative 5%.

So we think about it more in terms of midpoints.

So midpoint 2019 to '20, that's where our minds are right now.

We'll get more granular with the guidance range as we go through time.

Okay, I just wanted to make sure that I was translating that 2020 statement properly.

Appreciate it.

In terms of other questions, I think most of mine have been answered, so I'll give you back the time.

Our next question comes from Christopher Turnure with JPMorgan.

Tom, you mentioned the alternative plan for ACP and the slightly higher cost estimate and longer time frame for that.

Could you just expand upon the exact permit scenario that would underpin that plan?

It all has -- we have all of our permits.

So let's -- we didn't mention in the script.

For example, we did get our last real permit, significant permit, which is the air permit for the Buckingham Compressor Station.

So what now is in front of us is these court challenges on a variety of pieces.

For example there's no challenge for what's between Buckingham County and Lumberton, North Carolina.

That has to do with these issues in the mountains and the national parks, et cetera.

So all those different time frames and the different amounts are based on different scenarios on when we finish the court challenges.

Okay, so there is not one particular path there.

So the alternative is not, if you fail the en banc, then you do that?

Correct.

There are other -- there are multiple paths here.

And I know people are focused understandably and justifiably on the en banc, but that's not the only path here.

There are -- there is -- technically, if we don't get the en banc or we lose the en banc, there is the -- you have the judicial path to Supreme Court.

There is a legislative path that we're working on quite vigorously.

And there are, as I mentioned, administrative paths that we have identified, but haven't been able to fully pursue because of the government shutdown.

But the primary focus right now for us is our en banc proceeding.

We think that decision is erroneous and upends almost 50 years of agency precedent.

Okay.

And then just following up on the strategy here with ACP.

The biological opinion is, I guess, technically what's caused the temporary stop in construction right now.

What I'm wondering, given the gravity of the Forest Service opinion and the en banc process, were you to not succeed on the Forest Service side, call it, in the second quarter or midyear, does it make sense to continue construction at that time or hold off on construction until you get more clarity there?

I think last time I checked, you had drawn around $1 billion of the project-level debt, so far you spent a good amount, but you're not maybe fully committed at this point in terms of spending, in my opinion.

Well, I'll let Jim give you the numbers on what has been spent.

I just -- there are so many variables in that question, I just think it's hard for us to -- really to answer it.

We'd have to see -- I think we're going to win on the biological opinion issue quite -- I have high confidence in that.

They've -- this is the second time around.

They followed the dictates of the court and what the court was interested in and reissued it.

So we would have to see -- we assume it's going to get affirmed, and if it's not, we'll have to see what the court said, then we'll have to make a decision around that.

But we think all of that is taken into account in these different time frames we've given you because we can proceed from Buckingham, which is sort of almost middle of the pipeline all the way down to Lumberton and up into Hampton Roads.

Chris, let me just add.

You mentioned correctly that back in October when we published our third quarter Q, we noted that the amount of capital drawn on that project-level construction facility was a little over $1 billion, $1.15 billion, I think it was, on 100% basis.

And so that number as of 12/31 is about $1.4 billion, not drastically different.

That's on a 100% basis, so that would imply total spend.

That's of course, 50% of the cash capital is represented in draws on the project-level facility.

So double it to get, on 100% basis, the total amount spent, which would be about -- approaching $2.8 billion as of 12/31.

And those numbers will be, of course, in the K.

Our next question comes from Rose-Lynn Armstrong with UBS.

There you are, Rose-Lynn.

I'll try again.

I think you got cut off in the middle of the question, I'm sorry.

I did.

I apologize.

So getting to the indication earlier that you would discuss long-term dividend growth at the analyst meeting, can you just give us a little preview of that today?

I believe, previous comments regarding 2020 were that the policy was predicated on the MLP market and now, of course, with the rollout, how are you thinking about dividend policy going forward?

Thanks, Rose-Lynn.

So let me just refresh everybody on the background here.

So we announced the expected dividend policy.

Of course, they are all subject, as you all know, each quarter to board approval.

But we said in 2017 that looking forward, we had a very robust MLP market.

We had Cove Point expectations coming online, et cetera.

But because of the unique nature of the take-or-pay contracts at Cove Point, the very significant cash flows flowing out of that, the recapture of the capital costs that we would see through drops into the MLP that we would grow the dividend 10% a year in '18, '19 and '20.

And then when we got to '21, we'd have to see what the landscape looked like at that time.

After the FERC ruling in March of last year that destroyed the viability of the MLP market over time, we said not too long after that day, I don't remember the exact date, Rose-Lynn, we said something along the lines of we're going to keep 10% in '18, we expect to keep 10% in '19.

And depending upon what happens, we are going to ask FERC to reconsider, we didn't know what exactly was going to happen, that it could go from 6% to 10% depending upon what happened with MLPs.

I think we have since said that the expectation -- obviously, the MLP market is no longer there, so you start already at the bottom of that.

But we recognize that it's not going to be 10% in '20, highly unlikely.

And that over time, we will bring the dividend growth rate, not going to be a cut in our dividend, that's not even in contemplation, but the notion is we will bring our growth rate of our dividends more in line with our peers after this year.

So starting in 2020, some -- we'll talk more about that in March, but there will be some effort to bring them more in line with our peer group.

I don't know if that answers your question, I hope it does.

Okay.

And you think -- what's your -- I guess, if we look at it from a payout ratio perspective, can you talk about where you'd hope to see the payout ratio over time?

Rose-Lynn, it's Jim.

We will talk about that at the end of March.

But we'll be setting the dividend growth rate to reach a target payout ratio that's more in line with peers, as Tom said.

Our last question will come from Jonathan Arnold with Deutsche Bank.

Okay.

I think you just answered one of our questions, which Jim, it's the payout that you'd bring in line with peers, not the growth rate.

I just wanted to be clear that we're understanding you correctly on that.

That's exactly right.

That's exactly right.

Okay.

And peers, you'll also share with us what you view as the right peer group to be in the March meeting, presumably?

Exactly.

Okay.

And then just on ACP.

When you guys are talking about customers, are you -- does that include the anchor utility customers, your affiliate customers?

And does whatever you kind of negotiate with them need to be approved by the state regulatory bodies?

I'm just curious on that.

The discussions are with -- sorry, this is Diane Leopold.

The discussions are with all of the customers, and every customer has something different with respect to what they will need to finalize the deal, but we are in active discussions with all of the customers now.

And then to the question of, is it subject to SCC approval, if it is outside of normal?

You're talking about -- when you say SCC, you're referring to -- in Virginia?

Yes.

In Virginia, it's just a matter of -- it's like any other part of our fuel costs.

So that will -- it'll be part of the fuel cost case and whenever 2021 or 2022, along with all the other ins and outs of our fuel costs.

Thank you.

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

You may disconnect your lines, and enjoy your day.

Thank you.