道明尼資源 (D) 2019 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 conference over to Mr. Steven Ridge, Vice President, Investor Relations.

Please go ahead, sir.

Good morning, and welcome.

Earnings materials, including today's prepared remarks 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.

I encourage you to visit our Investor Relations website to review the earnings conference call materials, including the earnings release kit.

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

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'll now turn the call over to Jim.

Thank you, Steven, and good morning.

Let me start by saying that we have a lot of ground to cover on today's call, which reflects the exciting progress we are making on our investment program, our financial targets and on our ESG efforts, including the introduction of an enterprise-wide net 0 emissions initiative.

Over the last several years, Dominion Energy has transitioned into a larger, more regulated and more predictable company and this is reflected in our ability to extend our track record of delivering financial performance consistent with our guidance.

I'm pleased to report on Slide 3, that the fourth quarter of 2019 was the 16th consecutive quarter of achieving operating earnings per share that, adjusted for normal weather, met or exceeded the midpoint of our guidance range.

Quarterly operating earnings were $1.18 per share, which includes a benefit from better-than-normal weather of less than $0.01.

Even without adjusting for weather, this was still the 16th consecutive quarter of results that aligned with our guidance range.

2019 full year operating earnings of $4.24 also exceeded the midpoint of our annual guidance range of $4.15 to $4.30 per share.

When adjusted for about $0.02 of help relative to normal weather, these operating earnings for the year met the midpoint of our annual guidance range and represent a 5.5% increase over 2018 weather-normalized operating EPS.

GAAP earnings for the quarter and for the year were $1.32 and $1.73 per share, respectively.

Recall that full year reported results were materially impacted during the first 2 quarters of the year by charges associated with the SCANA merger, including a substantial customer refund as approved by the South Carolina Public Service Commission.

Adjusted for these merger and integration-related costs, our trailing 3-year aggregate GAAP earnings are actually higher than our total operating earnings over the same period.

A summary of adjustments between operating and reported results are included in the appendix with a detailed reconciliation available on Schedule 2 of the earnings release kit.

Turning now to Slide 4. As usual, our operating earnings guidance ranges assume normal weather, variations from which could cause results to be toward the top or the bottom of these ranges.

We are initiating 2020 operating earnings guidance with a range of $4.25 to $4.60 per share.

The midpoint of this range represents a 5% increase over our weather-normalized 2019 results, which aligns with the guidance we provided at our Investor Day last March.

Select drivers in 2020 as compared to 2019 include increased earnings from regulated investment growth across our electric and gas businesses, lower interest expense due to lower average debt balances and a lower rate environment, the full year impact of the Millstone 0 carbon contract and lower depreciation expense associated with an anticipated extension of the useful life assumption for our regulated nuclear plants in Virginia.

Negative drivers include increased minority interest expense associated with the equity recapitalization of Cove Point, share dilution, lower New England capacity prices and a double outage year at Millstone.

Note that the double outage year -- the double outage occurs every third year and will, therefore, be a positive driver in 2021.

We are introducing first quarter consolidated operating earnings guidance of $1.05 to $1.25 per share.

We are also affirming our post-2020 guidance of 5-plus percent annual operating EPS growth as well as our dividend per share growth rate of 2.5% per annum, subject, as is customary, to Board approval.

We have successfully changed the way we manage and report our businesses, as shown on Slide 5, to better reflect the larger and more regulated nature of our operations.

We expect that these realigned segments will also make it easier to model and analyze our company.

On Slide 6, we provide annual operating income guidance at the new segment level.

Let me take a moment and highlight a few points.

First, except for Contracted Generation, which I'll explain in a minute, each of our segments exhibit strong operating earnings growth trends, driven primarily by regulated investment and general cost discipline.

Contracted Generation's earnings trend is negatively impacted by the sale of Manchester and Fairless at the end of 2018 and by the double outage year at Millstone in 2020.

As I mentioned previously, the double outage driver will reverse for 2021.

Second, we've adjusted the CAGR of the Gas Distribution segment to exclude the impact of the addition of PSNC in 2019 to demonstrate the very strong core growth rate at the segment absent merger activity.

Third, we are not showing a 2018 to 2020 CAGR for Dominion Energy South Carolina as the merger with SCANA did not conclude until 2019.

Growth in 2020 is primarily driven by merger cost savings, which we expect to accrue to the benefit of our customers in South Carolina as part of our upcoming electric rate case.

In other words, this growth is good for both customers and shareholders.

Finally, these segment level operating income CAGRs, of course, don't reflect equity issuance at the parent over the period shown, including shares issued in exchange for SCANA stock early last year, and which act to produce a consolidated EPS growth rate that is slightly below the segment level growth numbers shown here.

On Slide 7, we show expected 2020 operating EPS contribution by segment.

This page underscores 2 of the key investment themes we have emphasized.

First, that the strategic progression of our company has resulted in having approximately 95% of our operating earnings derived from regulated and regulated-like operations; and second, that around 70% of our operating earnings come from state-regulated utility operations centered around 5 highly attractive states, including Virginia, North Carolina, South Carolina, Ohio and Utah.

Going forward, we plan to provide this segment level operating guidance annually.

We have also simplified or added to our existing disclosures, including with regards to weather impacts, customer growth, rate base estimates, Millstone hedging, fixed income and other topics.

We hope you find these changes, which are included in our earnings release kit and in the appendix of today's presentation, helpful.

Turning to Slide 8. We've summarized our current capital structure.

We now have distinct and aligned financing entities related to our Dominion Energy Virginia, Dominion Energy South Carolina and Gas Transmission & Storage operating segments.

These financing vehicles are, in addition to our parent level entity, SEC registrants and therefore, will continue to file 10-Ks and 10-Qs.

For the Gas Distribution and the Contracted Generation segments, we show here the aggregate of existing financing balances across the individual opco entities, which, primarily due to their smaller size, are financed in the private market.

Let me now address credit more generally.

I frequently remind our investors that we manage our balance sheet to a target credit rating range and not just to one of the specific credit metrics.

Also that the cash coverage metrics, such as FFO or CFO pre-working capital to debt, represent only a small weighting within the overall rating methodologies employed by our credit rating agencies.

Nonetheless, on Slide 9, we illustrate the meaningful improvement we have achieved in the cash coverage metric over the last 4 years and which we expect will continue to gradually improve over the next several years.

We've included in the appendix additional detail on the calculation of this metric for 2019.

On a related topic, strong performance of our retirement plan assets, combined with an earnings-neutral fourth quarter contribution more than offset a year-on-year reduction in discount rates, resulting in an increase in the overall funded balance of these plans by around 7 percentage points.

This leads me to our 2020 CapEx and financing plan.

Slide 10 provides our 2020 capital investment plan, which are broadly in line though a little higher in aggregate than the forecast we provided at our Investor Day due to a handful of small positive revisions and timing deltas.

And Slide 11 provides an overview of our 2020 external financing plan.

A couple of things to highlight here.

First, consistent with previous guidance, our common equity plans for the year include only around $300 million via our DRIP program.

You may recall that we have previously forecast $300 million to $500 million of ATM issuance in 2020, but subsequently announced that we would use proceeds from the Cove Point equity recapitalization to reduce or eliminate that issuance which is reflected here.

Next, I'll point out that during 2020, we intend to issue up to $1.8 billion of privately placed fixed income securities at Dominion East Ohio, which, as a result of the Dominion Energy Gas Holdings reorganization we completed last November, is currently levered only on an intercompany basis.

We currently expect this issuance in the midyear, and we'll use proceeds to retire current level debt.

Finally, as is the norm, this annual financing plan does not reflect any opportunistic refinancing activities which may arise during the year.

For example, in 2019, we rebalanced the capital structure at Dominion Energy South Carolina via a series of bond repurchases.

In this fourth quarter, we took advantage of an attractive financing environment to replace existing debt with an equity credit preferred security that's priced at an all-time industry low.

We will continue to monitor opportunities to similarly strengthen our balance sheet in an earnings supportive manner.

Turning now to the Atlantic Coast Pipeline, which Tom will address in greater detail in a moment.

Since about a year ago, when we announced the last material increase in our estimated total capital cost for ACP, discussions have been ongoing between the project owners and the anchor shipper customers regarding the equitable sharing of those increases within the contract tariff.

Those negotiations have been productive, and we expect to formalize an agreement in the coming weeks.

As part of those discussions, the major project customers have confirmed their willingness to take on higher project rates given the strategic importance of ACP as an alternative pipeline option to the region.

As a reminder, these are 20-year take-or-pay agreement with regulated utility customers and no commodity exposure.

This customer negotiation process -- progress allows us to provide guidance related to the project's economic contribution after entering commercial service.

As shown on Slide 12, we expect the 2022 earnings contribution to be between $0.20 and $0.25 per share, which includes Supply Header and assumes a full year of commercial in-service.

This estimate also reflects the transition from AFUDC to contract-based cash earnings potential.

We expect this contribution to increase over time as we expand the project via compression and laterals.

There is no change to our expected contribution this year of mid- to high teen cents per share.

In related news, we're announcing today that we have agreed to acquire certain modestly sized gas transmission and storage assets from Southern company, subject to HSR regulatory approval.

The first is Pivotal LNG, which liquefies and delivers LNG as fuel for transportation in the Southeast U.S., primarily from a new LNG production facility located in Jacksonville, Florida.

Tom will discuss how this asset together with Cove Point, support the expansion of our LNG strategy to include maritime transportation.

The second asset being acquired is Southern Company's 5% stake in the Atlantic Coast Pipeline, which upon closing will bring the project ownership to 53% Dominion Energy and 47% Duke Energy.

Note that the governance arrangements for the project company remains such that it will continue to be recognized on an unconsolidated equity method basis in Dominion's financial statements.

Likewise, there is no change to Southern Company's status as one of the anchor customers for the project through its Virginia natural gas local distribution company.

The near-term financial impact of the acquisition of these 2 assets is positive, but relatively small, and the increased ACP ownership is reflected in the earnings contribution estimates I provided previously.

Total cash consideration for these acquisitions is around $175 million.

Turning to Santee Cooper.

Our interest remains limited to a management proposal arrangement designed to cooperatively improve operational efficiency from our nearly colocated utility footprint.

Consistent with our previous messaging on this topic, while the potential financial impact of any such arrangement would not be a material near-term financial driver for Dominion, we are glad to participate if selected by the Department of Administration and the South Carolina General Assembly, especially if the collaborative approach results in cost savings that can be passed on to our and Santee Cooper's customers in the state.

We will provide updates as warranted as that process moves into the next phase.

Finally, let me offer just a brief comment on the recent third quarter related to the PJM capacity market structure, commonly referred to as MOPR-Ex.

We will continue to monitor that situation as it winds towards resolution.

In the meantime, we do not see this as a material financial risk for our company given the even balance of supply and demand at Dominion Energy Virginia.

Further, if we determine it to be in the best interest of our customers, we have the option to make a fixed resource requirement or FRR election.

This would require a notification to PJM and where we'd also notify the Virginia State Corporation Commission and the North Carolina Utilities Commission.

With that, let me conclude my remarks by reiterating the key investment themes that I spoke to on our last quarterly call.

We are highly regulated -- we are highly regulated, with about 95% of our company's operating earnings derived from regulated and regulated-like operations.

70% of our earnings are from utility operations centered around 5 attractive states.

Another 25% of our earnings are from FERC-regulated transmission and storage operations primarily serving utility customers under long-term capacity contracts.

During 2019, we grew our regulated rate base by approximately 6%.

We continue to expect 5-year rate base CAGR of approximately 7%, consistent with our expectations at Investor Day.

We are executing on our previously announced 5-year and $26 billion growth capital plan that will modernize, strengthen and improve the sustainability of the services we offer to our customers.

And finally, this customer-focused approach also benefits our shareholders as demonstrated by our growing track record of meeting and affirming our financial guidance, including a 16th consecutive quarter of meeting or exceeding our guidance midpoint.

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.

On Slide 14, we have recast our historic safety results to incorporate our mergers with Questar and SCANA.

As you can see, the overall trend reflects a continuous focus on employee health and welfare.

Pro forma for past mergers, our company-wide OSHA recordable incident rate decreased in 2019 for an 11th time over the last 13 years.

Turning now to our consistent national leadership as it relates to environmental, social and governance matters.

Over the course of the last year, we have intensified our efforts to reduce emissions of all types.

As shown on Slide 15, we have already reduced carbon emissions by around 50% since 2005, which is nearly twice as much as the most recently reported industry average.

We have followed a similar path for methane emissions, which have fallen by around 25% since 2010, a significant reduction driven by industry-leading efforts.

Further, as shown on the next slide, we have reduced coal-fired generation's contribution to company-wide electricity production by 80% from 52% in 2005 to 12% in 2019.

And we estimate that coal-fired generation today accounts for less than 8% of our total regulated investment base.

Turning to Slide 17.

I'm pleased to announce a new commitment to achieve net 0 emissions by 2050.

The goal includes both carbon dioxide and methane emissions and covers all of our businesses, including electricity generation and gas infrastructure.

This represents a significant expansion from the company's previous greenhouse gas emission reduction goals, which included a commitment to cut methane emissions from our natural gas operations by 50% between 2010 and 2030 and carbon emissions from our power generating facilities by 80% between 2005 and 2050.

Reducing emissions as fast as possible and achieving net 0 emissions company-wide requires immediate and direct action.

That is why the company continues to make meaningful steps to extend licenses for its 0 carbon nuclear generation fleet, promote customer energy efficiency programs, invest heavily in wind and solar power, reduce the amount of coal-fired generation on our system, enhance gas infrastructure leak detection, systematically replace legacy gas distribution lines and harvest agricultural methane emissions to be repurposed as renewable natural gas.

All of these initiatives are included in our capital investment plan guidance through 2023 and will extend well beyond that.

Over the long term, achieving these goals will require supportive legislative and regulatory policies and broader investments across the economy.

This includes support for the testing and deployment of technologies, such as large-scale energy storage and carbon capture, which, though still early stage, have the potential to reduce greenhouse gas emissions significantly when deployed in conjunction with carbon-free generation.

And we will never lose sight of our fundamental responsibility to customers: provision of safe, reliable and affordable energy.

We have issued a press release this morning that addresses the topic in additional detail.

And you should expect to hear more about our plans, including in upcoming climate and corporate and social responsibility reports.

Though certain approaches will undoubtedly evolve over the coming decades to reflect the most up-to-date assumptions, our commitment to net 0 emissions will not change.

I'm pleased to report that our work on reducing emissions and enhancing our ESG disclosures was recognized with a leadership rating by CDP, an influential nonprofit that monitors and measures environmental impact.

These ratings put Dominion Energy in the upper echelon of not just U.S. utility companies but all companies of all industries globally.

In addition, Just Capital, an organization that promotes corporate responsibility in partnership with Forbes, has ranked Dominion among America's top 100 corporate citizens.

It is, of course, nice to receive accolades like these, but we are not declaring victory.

In addition to minimizing our own operational environmental footprint in line with the carbon and methane goals I just described, we are also embracing the notion of Beyond Dominion Energy as it relates to our ability to transform the emissions profiles of our customers and energy end users, as shown on Slide 19, in the transportation sector, which accounts for 29% of U.S. greenhouse gas emissions.

We are leading the way in the development of the largest electric school bus program in the nation.

We are enhancing the resiliency and flexibility of our electric grid to enable the more rapid deployment of electric vehicle charging infrastructure as enabled in Virginia by the Grid Transformation & Security Act, and we are developing infrastructure that will make liquefied natural gas, compressed renewable natural gas and potentially hydrogen fuels more available and more affordable for use in transportation applications, including maritime shipping vessels.

In the agricultural sector, which accounts for 9% of U.S. greenhouse gas emissions, we are partnering with the nation's largest hog and dairy producers to capture methane from farm operations.

These partnerships have already committed $700 million of shared investment to capture methane emissions and use RNG to serve homes, businesses and vehicle fleets.

These are large and ambitious, multi-decade plans that are consistent with the spirit of Dominion Energy and its nearly 20,000 employees.

Many of these efforts are well underway, including our solar, offshore wind, nuclear relicensing and energy efficiency programs.

Others are in more nascent stages, including our electric school bus, RNG and marine LNG programs.

Over the coming months and years, you should expect to hear more on these strategies as we work diligently to reduce the emissions profiles of our company and our customer.

I will address several of these now.

Turning to Slide 20.

Late last year, we announced plans to install over 2.6 gigawatts of wind generation capacity, approximately 27 miles off the coast of Virginia, a major milestone for a project we began developing in 2013.

Since that announcement, we have achieved several additional milestones, including selecting Siemens Gamesa as our preferred turbine supplier and entering into an agreement with 3 prominent trade unions to support the onshore electric interconnection work.

We will begin ocean survey work in April, which will help to support the submission of the construction and operations plan at the end of this year.

We expect to commence construction in 2024, upon timely completion of the BOEM permitting process, with full in-service by the end of 2026.

We will continue to work to refine the preliminary capital cost estimate of approximately $8 billion, the vast majority of which will occur in the '24 to '26 time frame as major components are fabricated and installed.

Cost reductions as well as any tax benefits that we achieve will accrue directly to the benefit of our customers.

Dominion Energy Virginia will be the sole equity owner of this regulated asset.

We will seek recovery via a rider from the Virginia State Corporation Commission.

While the existing GTSA provides a strong framework for regulated cost recovery for offshore wind investments, a legislation, which was supported by the governor's office in recent legislative committee meetings, is working its way through the current Virginia General Assembly session that, if enacted, would provide additional regulatory clarity.

Our related 12-megawatt pilot project will begin turbine installation in May and is expected to achieve commercial operation in late summer of this year.

The lessons learned on this project will be invaluable to the successful completion of our full-scale deployment.

The pilot is the first and only offshore wind project in Federal waters to have completed the BOEM permitting process, which included a cumulative impact analysis.

We expect to leverage the right-of-way and other work already performed under the pilot project to facilitate routing the export cable to shore and connecting it to the onshore electric transmission system.

Also in Virginia, our weather-normalized sales increased 1.4% year-over-year, driven primarily by increased data center and residential demand.

We connected nearly 34,000 new accounts, about 10% more than last year, including 26 data centers, which set another annual record.

Earlier this year, PJM revised upwards their peak load assumptions for our service territory to reflect, among other things, continued strong data center growth.

PJM's DOM zone summer peak load growth is now expected to be 1.2% per year over the next 10 years and 1% annually over the next 15.

These rates are double the PJM system-wide growth rates and rank our zone as one of the fastest-growing regions among the 13 states that comprise PJM.

Turning to Slide 21.

Last month, the State Corporation Commission approved our U.S. forward solar CPCN application, the second such approval in the last 12 months.

We expect subsequent rider approval in April.

Overall, we have now achieved 57% of our commitment to Virginians to have 3,000 megawatts of solar in development or in operation by the end of 2021.

To date and inclusive of around $800 million of spending in 2019 alone, Dominion Energy's enterprise-wide total solar investment now stands at approximately $4 billion with an additional nearly $3 billion expected through 2023.

We anticipate continued solar investment for years to come, which is why we expect to improve our current ranking of fourth among the largest utility owners of solar in the country.

Phase 2 of our grid modernization program is before the commission.

Representing around $500 million of Capex, the request includes deployment of automated metering, a new customer information platform and investments in grid resiliency and telecommunications that are essential to delivering the products and services that our customers desire and which provides for a system more capable of withstanding climate-related risks.

We are optimistic that we will receive approval next month.

Our other investment programs shown on Slide 22, such as electric transmission, nuclear relicensing, distribution undergrounding, pump storage, renewable-enabling quick-start generation and rural broadband, are tracking in line with our expectations.

Virginia General Assembly has been in session for about 5 weeks and is scheduled to conclude in less than a month.

There are 2 proposals currently pending that I believe warrant highlighting.

One is related to offshore wind, which I previously addressed.

The other relates to our nation-leading initiative to replace diesel with electric school buses.

We have already selected a vendor and worked with local school districts in our service territory to allocate an initial delivery of 50 school buses by year-end.

Pending legislation calls for replacing an additional 1,500 buses by 2025, representing an estimated Dominion capital investment of approximately $400 million which will be eligible for cost recovery subject to commission approval.

Ultimately, we would place all 13,000 diesel school buses in our Virginia service territory.

Not only will this effort dramatically improve the air quality for our students and their communities, it will provide valuable real-world experience with vehicle-to-grid battery technology as the first 1,500 buses, while idle, represent up to 60 megawatts of effective battery storage.

We are monitoring other active pieces of legislation, all of which we expect to represent a reasonable and balanced approach to statewide energy policy priorities.

Turning now to South Carolina on Slide 23.

We are pleased with the work done by our team members to provide for a smooth integration while maintaining their historically excellent levels of reliability and customer service.

Around midyear, we plan to file an electric rate case as stipulated in the merger agreement.

Our most recent earned return was around 7.5% and our current authorized return is 10.25%.

The most significant driver of the under earnings is related to normal course, safety, customer growth and reliability utility investment over the last 8 years.

This is not currently captured in rates.

We believe the case will conclude by year-end with an outcome that appropriately balances the interest of customers and shareholders.

Turning to Gas Distribution.

Recently, we have begun to hear of investor concern that, at least in some states, municipal level ordinances could limit overall demand growth for natural gas utility service.

While that may be true elsewhere, we simply do not see any evidence of slowing customer or investment growth in the states in which we operate gas utilities: Utah, Idaho, Wyoming, Ohio, West Virginia, North Carolina and South Carolina.

Compounded annual customer growth across this segment was 1.5% over the last 3 years and as high as 2.6% and in Utah and North Carolina, with no signs of abating anytime soon.

For many of our customers, the alternative to natural gas for home heating is fuel oil or even wood, which have significantly higher carbon signatures.

And in certain communities within reach of our system, a lack of energy infrastructure is constraining growth and impacting everyday quality of life.

Further, we are an industry leader in minimizing the emissions footprint of natural gas utility operations, including through promoting energy efficiency, utilizing innovative technologies and increasing access for our customers to renewable natural gas.

We also continue to invest hundreds of millions of dollars every year in modernizing our distribution infrastructure, which improves safety, reduces emissions and is recoverable in the form of riders or trackers that will continue over the course of at least the next decade.

Regulators continue to approve new investments like our on-system peaking storage facility in Utah that will improve system reliability for decades to come.

Our Gas Distribution segment is focused on being part of the solution to a sustainable future.

Finally, let me now discuss our Gas Transmission & Storage business.

First, RNG.

We are the largest agricultural waste-to-energy investor in the United States, with investments of $700 million across our partnerships over the next 10 years.

These investments will grow as the offtake market matures.

Through these efforts, we capture otherwise fugitive methane from livestock and convert it to pipeline quality natural gas for use in homes, businesses and vehicle fleets.

Every captured unit of methane is the equivalent of eliminating 25 units of carbon dioxide.

Dominion is uniquely positioned to lead the industry in this effort, given the geography of our assets.

At Investor Day last year, we identified marine LNG as one of the many innovative ideas we were working to advance.

By way of background, crews and cargo vessels primarily consume diesel or fuel oil, each of which is a major contributor of greenhouse gas and other emissions.

The maritime industry is taking steps encouraged by recent global regulation to reduce its emissions footprint, which is expected to result in a material shift to LNG.

This expected growth in LNG as a fuel source allows Dominion attractive opportunity to provide natural gas liquefaction and LNG distribution services to a growing list of maritime customers.

As Jim mentioned, we are acquiring an interest in existing Florida-based operation that currently services marine vessels with an onshore liquefier coupled with marine fuel delivery infrastructure.

Customer contracts in this business are typically long term take-or-pay with no commodity exposure.

This initial acquisition will support a broader marine LNG strategy that would include Cove Point, where we're partnering with an existing export customer to redirect a portion of their liquefied natural gas inventory to provide LNG to constrained markets along the East Coast and to provide fuel for marine vessels under 0 commodity risk take-or-pay contracts.

Importantly, this arrangement does not and will not alter the existing 20-year take-or-pay export contract revenues or terms.

While modest initially, this market has the potential to support the significant decarbonization of the country's marine industry in addition to radically reducing pollution at our nation's ports.

Overall, inclusive of the acquisition from Southern Company, we expect to deploy approximately $200 million on this strategy over the next 5 years.

This is an innovative element of our long-term Beyond Dominion Energy effort to help our customers, new and old, meet their emissions reduction targets.

Turning now to an update on activities related to the Atlantic Coast Pipeline, as shown on Slide 24.

2 weeks from yesterday, the Supreme Court will hear oral arguments related to the Appalachian Trail crossing aspect of our U.S. Forest Service permit.

We remain optimistic that the court will issue an order reversing the Fourth Circuit in the May or June time frame.

We continue to work with the U.S. Fish and Wildlife Service on a reissued biological opinion and are pleased that FERC reinitiated formal consultation yesterday.

We applaud the service for taking the time to consider thoroughly the feedback provided by the court during the prior judicial proceedings and we believe an updated biological opinion will be issued during the first half of this year.

Upon receipt of the updated biological opinion, we intend to notify FERC and anticipate thereafter, the recommencement of construction across major portions of the pipeline.

We're also pleased with the progress related to projects' Nationwide 12 Permit, which was issued by and subsequently voluntarily remanded to the U.S. Army Corps of Engineers.

Last month, the Corps adopted repromulgated regulations that would allow for ACP to seek reissuance of the permit.

As it relates to the Buckingham County compressor station air permit, which was vacated late last year, I repeat my message from our last earnings call.

We can deliver a very material amount of contracted volumes to customers on our existing schedule, even if permit resolution delays the in-service date of the project's third compression station.

We are working on a number of solutions, which we expect will resolve the issue during the second half of this year.

We believe that the options we are evaluating will satisfy the court's concerns, which centered on process not the substance of the permit itself.

Based on our expectation of the biological opinion being reissued during the first half of the year, we are confirming our project time line that calls for construction completion by the end of next year and commissioning to be completed shortly thereafter.

Project costs of approximately $8 billion are in line with the high end of the judicial option range we provided about a year ago.

This estimate incorporates the various potential approaches to permitting issues and construction plans and timing, including as it relates to the Buckingham Compressor Station, which are being contemplated in the customer discussions that Jim described.

Also as noted, we have agreed to acquire the 5% ownership in the project from Southern Company, further underscoring our confidence in the successful completion of the project.

With that, I will summarize today's call as follows: our first value is safety, and we achieved another year of record safety performance.

We introduced a net 0 emissions by 2050 target that accounts for carbon and methane emissions across both electric and gas operations.

We achieved weather-normalized operating earnings that exceeded the midpoint of our guidance range for the 16th consecutive quarter.

We further improved our credit metrics and successfully completed the restructuring of our operating segments.

We introduced 2020 earnings guidance that represents a 5% year-over-year increase, consistent with previous messaging.

We confirmed our earnings per share growth expectations of 5-plus percent post-2020, 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) Our first question comes from Shar Pourreza with Guggenheim Partners.

So thanks for the additional disclosures on the ACP slides.

With the AFUDC rate versus returns once gas is flowing, can you just elaborate if you're expecting any sort of step down there in your assumptions?

I guess what returns are you kind of assuming in your $0.20 to $0.25 per share contribution once the pipe's in service, post these contract negotiations?

And curious if these negotiations built in any potential further cost increases?

Shar, it's Jim.

Thanks for that.

Yes, there has been, as we said in our prepared remarks, quite the substantial discussions with the anchor customers, the anchor shippers.

And those discussions don't really revolve around ROE, it revolves around a rate.

So what the guidance we've given is, is for the first full year of operation at that rate.

And that will, of course, imply an ROE, which folks can do the math on, but it's reflective of the expected rate for the anchor shippers.

Now when you do calculate that ROE that's implied by that math, you'll get to a number that is reflective of the first full year of operation only, meaning, over time, as that project expands through laterals or compression or whatever, that's not reflected in that year 1 ROE, but the -- that will all flow from the input, which is a agreed upon customer rate and cost.

Got it.

And then is there a point in time, Jim, that you can sort of update us on laterals and compression?

Is there -- and then where is sort of your intentions are there at that point?

No.

What we can say is that we are optimistic that there will be expansions over time.

Sorry, this is Diane Leopold.

But we're right now focused on getting the base project in.

Our next question comes from Greg Gordon with Evercore ISI.

Tom, I may have -- you covered a lot, and you've made a ton of progress.

So congratulations.

I don't recall if you mentioned whether you think there'll be any substantial legislative activity in Virginia this year?

And if so, what we should be monitoring?

Thanks, Greg.

We mentioned 2 things in particular, the legislation that would allow for up to 1,500 diesel school buses to be converted to electric between now and 2025.

And there are bills in both the House and Senate that are working their way through.

Today is what we call Crossover Day in Virginia, where each of the Houses has to finish work on its own bills.

So the House has to finish work on all House bills, and then everything goes over to the Senate, and they can no longer work on House bills after tonight.

And the same is true for the Senate.

So there are bills on the electric school bus in both houses.

And there are bills related to providing even further regulatory clarity around our 2.6 gigawatt offshore wind farm.

Other than that, Greg, there's been a large amount of legislative activity, some bills are no longer viable, others are.

And we just are monitoring all those, working on them.

Until they work their way through the legislative process, it's really -- it's premature to comment on them.

Great.

And what would be -- what's your expected -- how do we reword this, what would be the outcome that you would expect coming from the legislation with regard to offshore wind, if it does pass, and what type of regulatory framework would that entail?

Well, again, Greg, I just -- the bills are there pending, and I think they speak for themselves.

They have language in them that increase regulatory clarity.

Our next question comes from Michael Weinstein with Crédit Suisse.

What impact does the FERC MOPR have on Virginia, the offshore wind projects?

And what is your -- I guess, your decision process at VEPCO versus an FRR tariff?

Michael, it's Jim.

Let me start there.

We -- as we mentioned, look, we don't expect that, that MOPR, as proposed, will have really any financial impact on Dominion.

As you know, our capacity and load in Virginia, Dominion Energy Virginia, is pretty well balanced.

So no near-term impact.

And if we foresaw that some change with MOPR and PJM rules would mean that we would not be potentially receiving capacity payments on new build generation, we could very easily, in the interest of our customer -- customers in Virginia, just elect that FRR option, which we think is pretty straightforward.

It already exists for another utility in the Virginia regulatory framework.

So we just don't see FRR -- the MOPR in general being an impact to our business one way or the other.

Okay.

So for now, I mean, I guess, later on, you might make that election, if it does impact the ability to bid into the auction for the offshore wind, correct?

Correct.

One other question.

The $8 billion for ACP is a little higher, I guess, you're at the high end of the range now.

What are some of the factors that are pushing that up towards the high end of the range?

Is it the Buckingham issue or something else?

This is Diane Leopold again.

So we run a lot of scenarios, incorporating where we are with permitting issues, and based on the timing of that, construction scenarios, certainly including Buckingham Compressor Station options.

And all of those have been taken into account in the customer negotiations that are factoring into revised rates.

But really, that's what took us to the $8 billion, which is in line or just above the high end of that judicial option range.

This does conclude this morning's conference call.

You may disconnect your lines, and enjoy your day.

Thank you.