道明尼資源 (D) 2019 Q3 法說會逐字稿

Good morning and welcome to the Dominion Energy Third Quarter Earnings Conference Call.

(Operator Instructions)

I would now like to turn the call over to Steven Ridge, Vice President, Investor Relations.

Good morning and welcome.

I encourage you to visit our Investor Relations website to view the earnings release kit, the presentation that accompanies this morning's prepared remarks and additional quarterly disclosures.

The Investor Relations team will be available after today's call to answer any questions regarding this quarter's results.

Earnings materials, including our prepared remarks 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.

This morning, 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 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; as well as other members of the executive management team.

I will now turn the call over to Jim.

Thanks, Steve, and good morning.

Before I walk through the quarterly results, which were above the midpoint of our guidance range, I wanted to highlight Dominion Energy's key investment themes, all of which are consistent with the messaging from our Investor Day in March.

At the highest level, we delivered exceptional value to our customers, our communities, our employees and our shareholders.

We do this by providing affordable, reliable and sustainable energy to our customers.

Approximately 2/3 of our operating income comes from our state-regulated utility operations whose customers center around 5 key states.

Our demand pull utility-centered FERC transmission and storage customers account for most of the rest of our operating income.

Together, these regulated and regulated-like customers comprise approximately 95% of our total operating income.

From 2019 through 2023, we plan to invest $26 billion in growth capital programs that will modernize, strengthen and improve the sustainability of our systems to the benefit of these customers.

Further, we do this by engaging with communities in which we live and work, by being responsible stewards of the environment and by focusing relentlessly on the safety of our nearly 20,000 employees.

Tom will touch on these 3 topics more extensively in his remarks.

Finally, we do this by delivering financial results that are consistently within our guidance for earnings and dividend growth.

As an example, this quarter's results represent the 15th consecutive quarter of delivering weather-normalized operating earnings per share that are at or above the midpoint of our quarterly guidance range and also the 15th consecutive quarter of being in or above the range without weather normalizing.

And today, we are also reaffirming our annual and long-term growth guidance.

Turning now to the quarterly results on Slide 4. Today, we reported third quarter 2019 operating earnings of $1.18 per share compared to our guidance range of $1 to $1.20 per share.

Strong performance across our segments was aided by better-than-normal weather, which increased utility earnings by about $0.05 per share.

Adjusted for normal weather, operating earnings for the quarter were $1.13 per share, which is also above the midpoint of our guidance range.

GAAP earnings for the quarter were $1.17 per share.

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

On Slide 5, we've summarized several milestones achieved since our last call.

First, Millstone began to sell electricity under the 0 carbon power contract with Connecticut utilities on October 1. Under the 10-year contract, Millstone will sell 9 million megawatt hours of electricity per year, representing 55% of the plant's output at a fixed price of $49.99 per megawatt hour.

This contract, the financial impact of which is incorporated into our existing guidance, recognizes the tremendous value of Millstone's environmental and other attributes for the state and the region.

For the plant output not covered by the contract, we will continue to employ a prudent hedging strategy.

Note that the contract does not cover capacity as the entire plant is expected to continue to be compensated via the existing regional capacity program.

We are pleased with this agreement as it ensures the ongoing financial viability of the plant, and we wish to thank the Governor's office, DEEP, PURA and the electric utilities who work in a collaborative and thoughtful fashion to safeguard the state's environment, the economy, employment and energy security.

Next, we continue to achieve constructive results across our various and normal course state-level regulatory proceedings.

In North Carolina, we reached a nearly complete settlement with commission staff for our electric operations in the state with interim rates based on a 9.75% ROE to be effective this month.

In Utah, our gas distribution business has filed its first post-merger base rate proceeding, which we expect will conclude early next year.

Finally, we expect resolution of our Virginia ROE proceeding later this month.

The updated ROE will impact in the near term approximately $4 billion of rate base currently earning rider returns of 9.2%, plus adders of up to 1%.

We estimate that every 50 basis point change in ROE would impact near-term rider earnings by between $0.01 and $0.02 per share per year.

Next, we expect to complete the transition to our newly -- new operating segments by the end of this year.

As a reminder, and as shown on Slide 6, we are reorganizing the way we manage and report our operating segments to more closely align with their customer and regulatory profiles.

During our fourth quarter earnings call early next year, we expect to provide our 2019 full year results and 2020 guidance in conformity with these updated segments.

As discussed previously, we believe that this new reporting structure will make our company more accessible and will highlight the premium nature of each of our businesses.

Turning to Slide 7. On October 21, we announced that as part of our previously communicated intention to establish a permanent capital structure for the Cove Point facility, we reached an agreement with a financial investor affiliated with Brookfield to participate in an equity recapitalization of that asset.

This transaction, the financial impacts of which are already included in our existing earnings and growth -- earnings growth guidance, accomplishes several key objectives, including: highlighting the intrinsic value created through Dominion's 5-year development efforts with an implied enterprise value of nearly $8.25 billion compared to a construction cost at the time of liquefaction completion of just over $4 billion; redeploying capital from the low-growth annuity-type area into our robust regulated growth capital program; preserving full operational control of the facility with no impact on existing customer contracts or employees; and reducing Dominion's annual common equity financing needs in the coming years from the levels described in our March Investor Day.

Immediately upon close, expected later this year, we will use 100% of the proceeds to retire parent-level debt.

This transaction, which attractively addresses the equity portion of the facility's long-term capital structure, is step 1 of 2 as we intend to finalize long-term debt related to the asset in the near future.

Moving quickly to credit.

During 2018, we took major steps to improve our balance sheet while also reducing our business risk profile.

We expect that our full year 2019 credit metrics will be supportive of our existing credit ratings, with debt coverage ratios normalized for merger-related charges in the mid-teens.

Moving now to operating earnings guidance on Slide 8. 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 ranges.

For the fourth quarter, we're initiating guidance of $1.10 to $1.25 per share.

Positive factors as compared to last year include the absence of the Millstone refueling outage, growth from regulated investment across electric and gas utility programs, contribution from the Southeast Energy Group, commencement of the Millstone 0 carbon contract, net capacity expense improvement and the impact of O&M initiatives.

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

This fourth quarter guidance implies a narrowing of our 2019 full year guidance range to $4.15 to $4.30 per share with no change to the midpoint of our original guidance.

Before I turn it over to Tom, let me summarize that today, we reported our 15th consecutive quarter of weather-normalized operating EPS at or above the midpoint of our guidance range.

We are confirming the midpoint and narrowing our guidance range for 2019 full year operating EPS.

And we are reiterating our long-term EPS growth expectation of approximately 5% next year and 5% plus thereafter.

I'll now turn the call over to Tom.

Thank you, Jim, and good morning.

First, a reminder that safety is our first core value.

I'm pleased to report that our year-to-date safety performance is consistent with the record-setting results we have achieved in the last few years.

We are focused on continuing that trend over the last 2 months of 2019.

Turning to Slide 9. I will now address the topics Jim mentioned in his remarks.

First, 3 weeks ago, we released our latest sustainability and corporate responsibility report.

It's our most comprehensive report to date, and it delivers on the company's commitment to complete transparency.

It embraces ESG disclosure best practices.

It includes information on corporate governance and stakeholder engagement, social and workforce metrics and indices that map to standards from the Global Reporting Initiative and the Sustainability Accounting Standards Board as well as the United Nations' Sustainable Development Goals.

Key highlights from the report include: Dominion has reduced carbon dioxide emissions by 52% since 2005.

We have also prevented more than 250,000 metric tons of methane entering the atmosphere from our gas infrastructure assets in the past decade, which is the equivalent of planting more than 100 million trees.

The company has raised its diverse hiring rate from 27% to 42% from 2013 to 2018, and 1 in every 5 new hires is a veteran.

In 2018, Dominion contributed nearly $35 million to social betterment, and employees volunteered more than 126,000 hours in community service.

In August, we announced plans for the largest electric school bus initiative in the nation.

This innovative effort aims to replace 100% of the approximately 13,000 diesel-powered school buses in our Virginia electric utility service territory by 2030, which would be the equivalent in emission reductions of removing 65,000 cars from the road.

The vehicle-to-grid technology allows the bus batteries to store and then release energy out of the grid during periods of high demand when the buses are not in use.

Finally, last week, we announced that we are expanding our 50-50 partnership with Smithfield Foods to become the largest renewable natural gas supplier in the nation.

In total, we are doubling our combined investment over the next 10 years to $0.5 billion, which will allow us to capture RNG that reduces greenhouse gas emissions that are equivalent to taking 500,000 cars off the road or planting 40 million new trees.

We are one of the most sustainable and innovative energy companies in the United States, and we believe that our customers and shareholders will benefit from our efforts.

Turning to Slide 10.

We have several important initiatives underway in Virginia.

First, offshore wind.

Last month, we received key approvals from the Bureau of Ocean Energy Management, BOEM, regarding the design, fabrication and installation of our 12-megawatt pilot project, which is under construction and scheduled to enter service late next year.

The knowledge and experience we obtain from the permitting, construction and operations pilot will be invaluable as we embark on our program to develop 2.6 gigawatts of utility-scale offshore wind in support of Governor Northam's recent executive order number 43.

That order provided clear direction to policymakers and agencies regarding the state's sustainable energy future as well as a challenge to Dominion Energy to accelerate the timeline for more renewables on our system, a challenge we embrace.

Our intention is to bring the project, which is located 27 miles off the coast of Virginia Beach, online in 3 phases of 880 megawatts each.

The 3 phases will enter service in 2024, 2025 and 2026, and taken together, will be the largest offshore wind installation in the United States.

The projects will be developed and owned by Dominion Energy Virginia, with regulated cost recovery subject to approval by the Virginia State Corporation Commission.

Our current 5-year capital plan provided at our Investor Day identifies $1.1 billion for offshore wind, inclusive of $300 million for the pilot.

Preliminary cost estimates, which we will work hard to reduce in the interest of customer savings, total an additional $7 billion.

We anticipate capital expenditures to ramp up in the latter part of our current 5-year plan, with the most significant investment to take place in 2024 through 2026.

We look forward to working closely with policymakers, regulators and other stakeholders to establish Virginia as the center of the United States offshore wind industry.

Efforts presently underway include ocean survey work and the development of the construction and operations plan, which is targeted for submittal to BOEM late next year.

We will make additional details available as we continue to make progress.

Offshore wind is just one of the many investment programs that we continue to execute on for the benefit of our customers and in accordance with the Grid Transformation & Security Act.

Four weeks ago, we filed for a second phase of grid transformation investments to complement the cyber and physical security and telecommunication investments already approved by the SEC this past January.

This second phase, which calls for over $500 million of capital investments through 2021, will enhance service to customers through implementation of new technologies and a series of new programs developed with input from stakeholders and customers over the past several months as well as a thorough third-party cost benefit analysis.

That analysis concluded that the planned investments will deliver significant benefit to all customers across a wide range of areas while also driving down -- driving reductions in greenhouse gas emissions, increasing economic growth in the commonwealth and providing savings to electric vehicle owners.

This phase includes the installation of nearly 1 million smart meters as well as a new customer information platform, which allows customers to digitally manage their energy use.

A prudency determination is expected in about 6 months, with a recovery determination thereafter.

Overall, we expect our grid transformation investment programs to total nearly $3 billion over a 10-year period.

Finally, 2 weeks ago, we announced an agreement with the Commonwealth of Virginia that, combined with previously announced contracts, will produce enough renewable power to meet roughly 45% of the state government's annual energy use, which is the largest state renewable energy procurement in the country.

To accomplish this, Dominion will own approximately 345 megawatts of new solar facilities and sell the output to the state under a long-term power purchase agreement.

The balance of the megawatts will come from a third-party-owned wind farm.

With these projects, we are nearly halfway fulfilling the commitment we made to Governor Northam to have 3,000 megawatts of solar and wind resources in service or under development in Virginia by 2022.

Turning to Slide 11.

We have provided a brief summary of capital investment related to the GTSA.

As you can see, we are taking significant steps in successfully implementing programs that have been identified by state policymakers as crucial for our state.

Over the last several months, the SEC has approved approximately $1.6 billion of capital investment with an additional $800 million filed and pending approval.

During the third quarter, the commission approved rider recovery for nearly $300 million of our Rider E request, which was related to environmental upgrades of certain generating units.

Since the last state-wide election that took place 2 years ago, Virginia's policymakers have supported on a bipartisan basis common sense utility legislation that puts the commonwealth firmly on a sustainable and modernized path to continued delivery of low-carbon, affordable and resilient power.

Notable examples include the Grid Transformation & Security Act in 2018 and comprehensive coal ash and rural broadband solutions in 2019.

As we execute on these policy priorities, we remain vigilant of customer bill impacts.

We intend to keep rates reasonable and competitive in the future, just as they are today.

Turning to Slide 12.

We continue to see very strong customer growth across our gas distribution franchise.

Pending under our rider investment programs, including pipeline replacement, is tracking in line with the 5-year, approximately $2 billion CapEx plan highlighted at our Investor Day.

Last week, we received approval from the Utah Public Service Commission to proceed with our investment in a regulated, reliability-driven LNG peaking facility.

And in West Virginia, regulators recently approved a plan that will allow us to double our annual investment in replacing infrastructure by 2023.

In South Carolina, our integration efforts and focus on operational excellence continue to proceed successfully.

In early September, as Hurricane Dorian swept up the East Coast, nearly 300,000 of our South Carolina electric customers as well as over 170,000 of our North Carolina and Virginia customers experienced service disruptions.

Our crews worked around the clock in hazardous conditions to quickly and safely restore power.

In fact, in all 3 states, including South Carolina where nearly 40% of our customers lost power, service was restored in less than 3 days.

As part of our commitment to relief efforts across Virginia, North and South Carolina, we also donated $250,000 to the American Red Cross to support the purchase supplies and food as well as shelter for those in need.

Turning next to the Atlantic Coast Pipeline on Slide 13.

Consistent with our expectations, the United States Supreme Court granted our appeal of the Fourth Circuit's Cowpasture decision, which relates to ACP's crossing underneath the Appalachian trail.

We expect that the Supreme Court will schedule arguments to occur late winter or early spring of next year with a final decision no later than June 2020.

We are confident in our legal position and believe that the Fourth Circuit's ruling will be overturned.

Our focus remains on the Supreme Court appeal, but all other options remain available.

Let me also address 2 other points.

Regarding the project's biological opinion, I will reiterate our commentary from last quarter that there is nothing in the court's opinion on the 4 species that we expect would prevent the biological opinion from being reissued during this winter's tree felling window.

However, even if the timing of the BO reissuance prevents us for taking full advantage of the window, including through the end of the first half of next year, we do not expect the existing project cost estimate of $7.3 billion to $7.8 billion to change.

This cost range, which we provided early this year, incorporated a variety of potential permit resolution and construction recommencement time lines, including a successful AT Supreme Court appeal.

We continue to expect project construction to be completed by the end of 2021, with full commissioning to conclude in early 2022.

This past Tuesday, the Fourth Circuit heard arguments regarding an appeal of our Buckingham Compressor Station minor source air permit.

We remain confident that the extraordinary protections undertaken at the site as adapted to address -- and as adapted to address community input more than satisfy both the process and substance required by applicable law.

The permit provides for the most stringent controls for any compressor station in the United States.

We have demonstrated that emissions measured at and beyond the station's fence line will meet the highest public health standards as applied to even the most sensitive populations and environments.

We expect the court to issue a ruling within the next 3 months.

We expect the project will be able to deliver significant volumes to customers under our current timeline, even if the permit needs more time to be resolved.

I will also note that since the last quarterly call, we have continued to advance discussions with Atlantic Coast Pipeline customers regarding the equitable resolution of project cost increases.

We expect to reach an agreement in principle by the end of this year, and we are confident that the result will satisfactorily balance customer rates with project returns.

Our customers' demand for this critical and common sense energy infrastructure is unwavering.

Turning to Slide 14.

Early last month, we announced several leadership changes to better reflect the new financial and operating reporting structure that will take effect later this year.

Bob Blue, currently CEO of the Power Delivery Group, will assume responsibility for Dominion Energy Virginia and Dominion Energy Contracted Generation.

Diane Leopold, currently CEO of the Gas Infrastructure Group, will assume responsibility for Dominion Energy South Carolina, Gas Transmission and Storage and Gas Distribution.

In addition, Bob and Diane will each assume the title of Co-Chief Operating Officer.

Carter Reid, currently Chief Administrative and Compliance Officer, will become the Chief of Staff for Dominion Energy and President of Dominion Energy Services.

Bob, Diane, Carter and Jim Chapman, as Chief Financial Officer and Treasurer, will continue to report directly to me.

These leaders are exceptionally well qualified to play important roles in the execution of our long-term strategy, and I congratulate them.

I also want to thank Paul Koonce who will retire in the coming months for his many years of dedicated service to our company.

His contributions will be missed, and we wish him all the very best in his future endeavors.

With that, I will summarize today's release as follows: We are on track to achieve full year safety results that are consistent with the record-setting performance of recent years.

We continue to take industry-leading innovative steps to demonstrate our leadership on environmental, social and governance matters.

We achieved weather-normalized operating earnings that exceeded the midpoint of our guidance range for the 15th consecutive quarter.

We are narrowing our full year 2019 operating earnings per share guidance and affirming our original midpoint.

We are reiterating our long-term EPS growth expectations of approximately 5% next year and 5% plus thereafter.

And we are making significant progress across our capital investment programs to the benefit of our customers.

We will now be happy to answer your questions.

(Operator Instructions) We will take our first question, and that is from Shar Pourreza with Guggenheim Partners.

So Tom, you obviously highlighted -- a couple of questions here.

You obviously highlighted the huge opportunity you said you guys have with offshore wind, right?

And we know the development cycle could be kind of long.

We've seen it with Vineyard.

I'm curious if you could talk a little bit around how you're thinking about contingencies around permitting, construction and contract terms.

And then as the projects starts to go through construction, maybe just a little bit on financing.

I mean should we think about the first tranche of the projects self-funding future projects with the cash flow they're generating?

So maybe how we should think about sort of the financing of what could be a very large capital outlay.

Thanks.

I'll start, and then I'll turn it over to Paul Koonce who's spent an enormous amount of time working on this development.

The -- and Jim Chapman can answer any further questions on the financing.

I would mention we are expecting rider recovery, and we'll seek rider approval for all 3 phases.

We've been working on this project for 6 years.

We bought the right lease option, the lease rights, in a 2013 auction that was run by BOEM.

And ever since that time, we've been working with a variety of stakeholders to make sure we had the right plan and we had the right folks to help us do the pilot.

We got approval from the State Corporation Commission.

It's been through BOEM.

We had the permits from BOEM.

One of the things to keep in mind that differentiates us from the New England situation is we own the entire lease for the entire coastal region of Virginia.

And it's 26 miles offshore.

It is not in fishing grounds, and it is not visible from the shore.

So it's very significant differentiating aspects of what's going on here in Virginia and what you've seen happen in New England but -- from the macro level.

And now I'll turn it over to Paul to answer the balance of your question.

Thanks, Tom.

Shar, as Tom mentioned, we've been at this for quite some time.

We expect, as Tom mentioned in his prepared remarks, to file the construction and operating permit about this time next year.

We've got ample time to get the BOEM permit in place in order to meet the first phase construction.

We will be starting the work now, the ocean mapping, the geotech work, the environmental studies, and that will take place over the course of 2020.

And having -- as Tom mentioned, having just gone through it on the CVOW project, while that was a research area permit and this is a commercial and operating permit, the process is identical.

So we know the stakeholders, we know the process, and we feel really pretty good about it.

I'll ask Jim to comment on financing.

Yes.

Two things, Shar.

One, as Tom mentioned in his prepared remarks, in our existing plan that we walked through in some detail back in March, we highlighted $1.1 billion of spending in offshore wind in our plan from 2019 through '23.

So obviously, recent announcements are much larger dollars than that, but the vast majority of the increase is going to come in those years of completion, '24, '25, '26.

So the majority of the spending to come in our current planning horizon is already in our plans that we walked through.

And the rest, we'll update over time as time comes closer.

But given what Tom and Paul just described, this is all in a regulatory construct to be financed at VEPCO.

It's certainly achievable, but the details will come in the next period.

Got it.

That's helpful.

And then just around the VRP, the retirement plan, is there any status?

And then I know your past comments is it's supportive of your growth.

Maybe just a little bit of a sense on how that program is going, how it's shaping the O&M profile.

And sort of bigger picture is VRP, offshore wind, the rate plans you have in Virginia, is there a point in time when you can change the way you guide to growth, i.e., moving from 5% plus more of a range, especially as we're trying to model what the incremental accretion is from offshore wind?

Because it just seems like between Cove Point, your plan is becoming much more visible.

So is there a point in time when you can start to layer in more of a definitive growth range versus 5% plus?

Shar, you linked quite a few things into one question there, good job.

Yes.

Look, the offshore wind, what that does to our guidance, I mean, it's beyond our 5-year planning horizon.

So the spending and then the associated earnings, as I just walked through, the $1.1 billion, including the pilot, I mean, that's in our plan.

It's in our earnings guidance.

There are no changes for now on that front.

On the VRP, you're right, that's kind of done and dusted earlier this year.

We talked about that as being a savings of, call it $0.05 to $0.06 this year, maybe double that on a full run rate next year and diminishing over time as it's given back to customers.

So that -- we talked about that as being available savings to offset unforeseen headwinds, and that's still the case.

But as an update, this year, as you know, the vast majority of our business, 95% of our business, is not commodity exposed in any way, the 5% that's not regulated or regulated-like is.

And within that 5% of our operating earnings, there's a couple things.

One is, obviously, the gas commodity environment is weak, and our business is largely immune to that.

We have a little bit of exposure mostly around our single remaining processing plant, which is in West Virginia, and that's a little bit of a headwind as those businesses go from like very small to even smaller this year.

So that's a little bit of a headwind.

More materially, though, this farm-out program, that has been very successful.

As you know, Shar, this is monetizing acreage and mineral resources below our storage field.

We announced that program in early 2015, and we gave guidance to the end of the decade of $450 million to $500 million of pretax earnings, and we've been ticking along that kind of like clockwork.

We're 75% through that guidance.

But given the pricing, given the commodity environment and the pricing that's available to us today, we're choosing not to transact on a farm-out this year.

And we're going to hold that acreage and that value for farm-out transactions in future periods when there's an improvement in the commodity pricing environment.

So what that means is, obviously, we've just reiterated our guidance, same midpoint.

So that means we've overcome any unforeseen headwind, previously unforeseen, relating to our decision not to transact on a farm-out this year.

So that's basically the VRP savings, which we're using it pretty much as we described we would, VRP savings and other initiatives to overcome that decision.

So no change to our guidance.

Those are the (inaudible) parts.

We will take our next question from Steve Fleishman with Wolfe Research.

So the -- your offshore wind is obviously different from really any other so far, in that it's going to be done -- planned to be done in the regulated business.

How do you know that, that structure of it will be approved?

Or could there be people that want to try to bid for it, et cetera?

Could you talk about that?

Sure.

Well, we're the only one that owns the offshore lease.

We own 100% of the offshore lease.

We paid for it in the auction.

Nobody else can build a wind farm off of Virginia.

Governor Northam, a few -- I guess a couple months ago now, called for the construction of this wind farm because it's his intention to help Virginia develop into the center of the offshore wind industry along the East Coast, and that's a challenge that we embrace.

And he specifically said that he recognized that there may be some who want to push back on that, on whether it was necessary, required or a good thing for Virginia that he was going to work very hard to ensure that the public policy and regulatory support was in place to carry out this plan.

And it was only after those statements that we went ahead with our announcement to full deployment, although we had been working obviously because we filed for the PGM -- PJM interconnection agreement.

So there's obviously a process in front of us.

We are highly confident that it will be carried out to fruition.

There is a lot of public support from this -- for this project, including from political leaders on both sides of the political fence, both Democrats and Republicans, that want to see this thing happen.

So we have -- obviously, there are -- a long way to go on it, but we have high confidence level in it going forward.

It'll be the only offshore wind farm in federal waters.

It will not be visible from the shore line.

So we don't have any of these visual impacts that concern people.

The environmental community is very supportive of the project going forward.

The economic development people in Tidewater, Virginia, are very supportive of this going forward.

So obviously, we don't have any guarantees of that, Steve, but we have a very high confidence level in the outcome.

We will take our next question from Julien Dumoulin-Smith with Bank of America.

Congratulations to all those receiving promotions here.

I know there's a number.

Perhaps just to pile on, on this offshore wind question and perhaps to complement that, you talked about potentially finding ways to mitigate cost to consumers.

Can you talk a little bit more precisely about the game plan, first, for qualifying on the tax credit front just given the longevity of the plan, but obviously, if you're starting it today, in theory you should qualify at least some of it?

And then separately, when you'll come out with some more definitive plans and filings, except maybe following the last question here, to actually pursue this at the SEC level?

Well, first, let me just give you a macro answer, Julien.

And the folks who got the promotions are in the room, they heard your congratulations.

On a macro basis, and I'll turn it over to Paul Koonce.

We are very concerned here about customer rates.

It's something we focus on all the time.

And because our goal is to ensure that our customer rates stay very competitive, well below national averages, below the regional averages, as they are now.

And we intend for them to stay that way, including with the construction of this wind farm.

So we will be working very hard with the fabricators, developers, installers.

We will be the operators to ensure that we get the costs down as low as we can as we go ahead, which will be important for everybody involved helping us with the project.

So with that, I'll turn it over to Paul.

Thanks, Tom.

Julien, again just to follow up on Tom's comments about costs, I think that's one of the key reasons why we broke the project up in 3 phases so that we could continue to let the supply chain mature, let the costs continue to come down so that the impact to rates are minimized.

Just in terms of ITC and safe harboring, of course, as you know, in order to qualify for ITC, a treatment for an offshore wind farm, you have to begin construction this year.

We're looking at that.

We don't have anything to comment about that, but we're aware of that timing.

There may be some things that we can do to safe harbor certain of those costs.

So we're exploring that, more to come on that in 2020.

In terms of plans and filings, we're not -- as Tom said, we're going to file for the BOEM application this time next year.

We're not prepared to say exactly when we're going to file for the SEC application, but I can tell you that we will be conducting many public meetings over the course of 2020 as we make the environmental assessment.

Obviously, marine life, plant and birds, we'll be doing ocean mapping, and we'll be doing geotech analysis or subsurface analysis.

So you will begin to see all that sort of play out in 2020, and I think that will be a good way to sort of pace when we might expect to make an SEC filing.

Got it.

But just to clarify the last question, too.

How much of this is in the 5-year window, as you see it, perhaps Phase 1, if you will?

Julien, we're -- as mentioned, we've got $1.1 billion in total in our 5-year plan as we walked through in March.

And for now, that's the number.

The $7 billion is additive to that.

That's right.

Everything else comes in '24, 25, '26.

Okay.

All right.

Fair enough.

Excellent.

And then just to clarify the prior one on the order.

Does that change the criteria that the SEC is going to be applying in that process?

The -- Julien, this is Paul.

The GTSA finds that offshore wind is in the public interest.

Now the SEC process is well known, whether they and how they conduct a market test.

Anytime we build generation for the benefit of our rate payers, there's a certain process that we follow, and that's a process we know well and we'll just step through that when that time comes.

We will take our next question from Greg Gordon with Evercore.

Shar's question was like the question from back-to-school, 1 question but in 27 parts, right?

On ACP, when I first read the release, I felt like it was kind of -- my first reaction was, oh, this is kind of negative.

It looks like there could be slippage in the biological permit.

But now that I'm hearing your commentary on it, I feel less -- I guess we should feel less concerned because you feel like even if the permit comes in after the turn of the year, you've scrubbed your construction cost forecast and you still feel like you can move the schedule around and come in on budget.

Thanks, Greg.

I'll turn it over to Diane Leopold who spent a lot of her life working on the Atlantic Coast Pipeline.

Go ahead.

Yes.

When we looked at it, I think you have it exactly right.

We -- when we gave guidance earlier this year, we looked at a lot of different scenarios and a lot of different contingencies to try to capture a variety of outcomes, including going to the Supreme Court, including when we would restart construction.

And so just given -- looking at the different segments of the pipeline, we feel comfortable with -- that we are well within what we've incorporated for both cost and schedule at this point.

And can you give us some sense of why the permit may have slipped a few more months?

Is it just that they're being extra careful to make sure that they comply with all the nuances of the remand and don't get another stay?

Or is there something else going on?

Greg, I don't think we're trying to imply that we think the permit has slipped.

What we're trying to say is even if it does, we're still on the schedule and cost.

[We're not implying that] we think it's going to slip.

Okay.

Sorry if I misconstrued that.

The last part of my question.

You talked to negotiations with the off-takers on the pipe who are mainly utilities.

This is a demand-driven pipe.

They need the gas, which is why you're building it.

It's not a supply push situation.

I think investors are concerned that with the cost overruns, this winds up being a pipe that doesn't earn its cost of capital.

But you seem to be positioning it in such a way that you should be able to potentially share the burden of those unexpected cost increases with the utilities who are taking the capacity.

So can you talk through like how much of that you're -- you think you'll be able to share given the unforeseen delays in the pipe and what type of return we should expect on the pipe if you're successful?

Yes.

This is Diane Leopold again.

I won't get into the actual expected project returns.

I will tell you, as Tom said in the actual script, the customers very much need this pipeline for regional security, for their own customers' needs.

This is clearly a demand-driven pipeline.

And we are in very constructive negotiations with the customer for fair rates to their customers as well as fair returns for us, and we're comfortable with the returns that we'll get for the pipeline.

We will take our next question from Christopher Turnure with JP Morgan.

Tom, I think you spent a lot of time in your prepared remarks on the political environment in Virginia and kind of how you guys are thinking about that and the legislation from last year.

But could you give us an update to both the South Carolina and North Carolina -- or pardon me, South Carolina and Virginia regulatory environments right now and political environments and also just the latest on your South Carolina regulatory strategy for next year?

Sure.

The -- we announced the South Carolina -- the SCANA merger, I guess late in, I guess it was '17 and then spent the year '18 going through the process.

And it was a relatively hot political climate in South Carolina over -- because of SCANA and Santee Cooper's cancellation of the expansion of the Summer nuclear plants.

We went through that whole process, very transparently answered all the questions, went to all the meetings.

And then as we closed the transaction, we said to policymakers that our intention was to stay out of the headlines, do our blocking and tackling, provide reliable service, both gas and electric at reasonable and much reduced electric rates, and just be part of the community.

That was our goal, and that's exactly what's happened in the state of South Carolina.

Things are very -- moving along very well there, progressing well.

We're out of the headlines except when we do things in the communities we serve, including the extraordinarily prompt restoration of the loss of electricity for 40% of our customers, got all our lights back on in 3 days.

All that helps a community understand their new neighbor.

We will be filing a rate case next year.

We are under earning in South Carolina.

It's well known to everybody.

And we're formulating and completing that regulatory strategy now, but we will be filing in, I think -- when is it, Rodney, May?

Going to have to file before May 1.

Before May 1, 2020.

I'm sorry, in North Carolina, we have a great case going in North Carolina.

We've settled all but 1 or 2. We consider them to be relatively small issues, got agreed on 9.75% ROE, very constructive regulatory environment and economic development environment in North Carolina.

And just in Virginia, if the legislature stays Republican, would that change some of the plans that you've been talking about today or kind of shift your capital spending at all in a different direction?

No.

We have a long history of working with whatever party is in the majority in whatever of the 2 houses, with Democratic governors, Republican governors, Democratic leaders and Republican leaders.

So don't expect any changes to our plan.

Okay.

And then my second question is just on equity needs going forward.

I think you partially addressed this in your prepared remarks, but will the sale of the stake in Cove Point mean that you will not need any equity, internal or external for the next several years?

Yes.

Going back to our -- it's Jim.

Going back to our guidance from our Analyst Day back in March, we had shown a projection through '21 that had equity component to support our regulated capital spending of $300 million of DRIP as on and $300 million to $500 million per year of ATM, so all done under our programs.

With the Cove financing, we are using 100% of those proceeds by year-end, $2 billion, to pay down parent-level debt, as I mentioned.

But we will effectively offset the ATM portion of that prior guidance in '20 and '21.

So taking a midpoint of that $300 million to $500 million range, $400 million, so that goes to 0. But -- and the DRIP is just always on, so that will be the only remaining program that's active for equity in those years.

We will take our next question from Michael Weinstein with Crédit Suisse.

On Cove Point, is there any interest in selling an additional stake in Cove Point at this point?

Or is this now -- you're now at the minimum desired level of ownership?

Thank you for that question.

We -- there's no interest in that.

We're in our desired outcome.

Okay.

And in the discussions with the ACP customers, I just wanted to be clear that the talks are overall cost increases above the, what is it, I think $6.25 billion that's currently in the agreement, embedded in current agreements?

Yes.

It's -- I won't disclose anything in the contract, but it's basically negotiating cost increases up to the current anticipated level.

And is there anything you can say about what those contracts obligate each party at on the face of it at this point before negotiations?

No.

No.

We don't want to disclose that.

Thanks.

Okay.

And just 1 last question I had is about the renewable tariff.

I think you had some major C&I customers in Virginia looking to -- for alternative suppliers.

And have you guys -- has Virginia -- has the Virginia Utility received permission to have its own renewable tariff at this point so that they can compete against these renewable suppliers?

I'll ask Bob Blue to answer that question.

Yes, Michael, it's Bob.

We have pending an application for a 100% renewable energy tariff.

As you know, in Virginia law, customers can seek service from a competitive service provider unless the utility has a 100% renewable tariff.

We filed for one earlier this year.

We'll have hearing on that in November.

The State Corporation Commission staff filed their testament yesterday and did not raise significant objections to our proposal.

And the one that we have filed is modeled closely on one that was approved earlier by the commission.

So we feel very good about where that will go.

Thank you.

This does conclude this morning's conference call.

You may now disconnect your lines, and enjoy your day.