DOMINION-ENERGY Earningcall Transcript Of Q2 of 2024

Steven D. Ridge -- Executive Vice President, Chief Financial Officer

Thank  you,  David,  and  good  morning,  everyone.  I'll  start  with  quarterly  results  on  Slide  3.

Second-quarter operating earnings were $0.65 per share, which included $0.03 of help from better

than normal weather in our utility service areas, whether normal operating EPS was $0.62. Relative

to  Q2  last  year,  positive  factors  for  the  quarter  included  $0.11  from  improved  weather,  $0.10  from

regulated  investment  growth  and  $0.17  related  to  Millstone,  including  $0.13  from  the  absence  of

extended duration outages and $0.04 due to higher realized power prices.

Recall  that  during  the  second  quarter  last  year,  we  experienced  both  planned  and  unplanned

outages  at  Millstone.  The  other  material  factor  for  the  quarter  was  an  $0.08  year-over-year  hurt

associated with the revenue reduction at DEV related to moving certain riders into base rates as a

result of legislation that became effective in July of last year. A summary of all drivers for earnings

relative to the prior year period is included in Schedule 4 of the earnings release kit. Second quarter

GAAP results were also $0.65 per share.

Adjustments  between  operating  and  reported  results  include  the  net  benefit  from  discontinued

operations,  primarily  associated  with  the  sale  of  the  gas  distribution  operations,  as  well  as

unrealized and non-cash market driven changes in the value of nuclear decommissioning trust funds

and  economic  hedging  derivatives.  A  summary  of  all  adjustments  is  included  in  Schedule  2  of  the

earnings release kit. Turning to guidance on Slide 4. We're reaffirming all of the financial guidance

we provided at our March 1st investor meeting.

First,  2024,  we  continue  to  expect  2024  operating  earnings  per  share  to  be  between  $2.62  and

$2.87  with  a  midpoint  of  $2.75.  Year-to-date  operating  earnings  are  consistent  with  the  illustrative

quarterly earnings cadence ranges that we provided on March 1st. Looking ahead, we expect that

better than normal weather during the first half of July, combined with the $0.03 of weather help in

the  second  quarter  will  nearly  offset  the  $0.06  of  weather  hurt  we  experienced  in  the  first  quarter.

During the second half of the year, we expect to see some headwinds from higher than budgeted

short term interest rates and backloaded O&M expense, which puts us on track for the midpoint of

our guidance range.

A  summary  of  the  year-over-year  drivers  and  illustrative  EPS  cadence  for  the  third  and  fourth

quarters  is  replicated  from  our  March  1st  meeting  in  today's  appendix.  Turning  to  2025  through

2029. We are reaffirming our guidance for 2025 operating earnings per share of between $3.25 and

$3.54 inclusive of approximately $0.10 of RNG 45Z credit income with a midpoint of $3.40. We also

continue to forecast an operating earnings annual growth rate range of 5% to 7% through 2029 of a

midpoint of $3.30 which excludes the impact of the RNG 45Z credits.

As a reminder, we continue to expect to see variation within our annual 5% to 7% growth range as a

result of the Millstone refueling cadence, which requires a second planned outage once every third

year.  As  it  relates  to  2025  specifically,  earlier  this  week  PJM  published  the  clearing  prices  in  the

2025-2026 planning year base residual auction. Elevated capacity prices at the RTO and DOM zone

affirm  what  we've  been  saying  for  the  last  several  years,  that  robust  investment  in  an  all  of  the

above  generation  resources  and  new  transmission  infrastructure  is  critical  to  reliably  serve  the

growing needs of our customers in Virginia. As a vertically integrated utility, we have a natural hedge

in that the capacity purchases to serve our load are mostly offset by the capacity revenue, our own

generation receives.

As  a  result,  customers  do  not  have  material  exposure  to  the  outcome  of  the  capacity  market  and

therefore higher prices do not automatically translate into higher customer costs. At the time of our

most recent biennial rate review, net capacity expense represented only about 1% of customer bills.

Since  then,  we've  seen  a  variety  of  actual  and  potential  bill  drivers  like  the  elimination  of  the  regi

rider  that  have  the  potential  to  significantly  mitigate  any  net  effect  of  higher  capacity  expense  on

customer  bills.  And  remember  currently  DEV's  rates  are  approximately  22%  below  the  national

average.

We'll have a holistic view of customer bill impacts when we file our next biennial case next March

with rates effective by the end of the year. Until those new rates become effective and as a result of

a  small  short  generation  position,  we  expect  the  impact  from  higher  capacity  prices  in  the  second

half of 2025 relative to our prior assumptions to be about a $0.04 headwind in 2025, which we fully

expect to overcome. That's a temporary impact, but big picture, this is a clear and forceful signal of

the continued need for robust levels and investment in our system for many years to come. Finally,

and for the avoidance of doubt, no changes to any of the financial guidance we provided on March

1st, including earnings, credit and dividend guidance.

Turning now to a status update on our business review debt reduction initiatives as shown on Slide

5.  During  the  review,  we  announced  transactions  that  represent  approximately  $21  billion  of  debt

reduction. With the closings of the Cove Point, East Ohio Gas, Questar Gas and Wexpro sales and

completion of the DEV fuel securitization, we've now achieved 72% of our business review target.

We're  making  excellent  progress  toward  timely  closing  of  the  two  remaining  debt  reduction

initiatives, the sale of public service company in North Carolina to Enbridge and the noncontrolling

equity financing by Stonepeak in the Coastal Virginia offshore wind project.

Let  me  provide  a  little  more  color  about  what  to  expect  here.  As  it  relates  to  PSNC,  all  parties

reached a comprehensive settlement in late May, followed by an evidentiary hearing on June 11th.

On  July  24th,  the  joint  proposed  order  was  filed  with  the  commission  representing  the  final

procedural step. We expect a final commission order during the third quarter with closing to follow

shortly thereafter.

And as it relates to CVOW, we received Affiliates Act approval, representing the first of two required

Virginia approvals from the State Corporation Commission on June 26th. Last week, SEC staff filed

their  comments  on  the  Transfer's  Act  and  financing  partner  petition,  the  second  of  two  required

Virginia  approvals.  No  other  parties  filed  comments,  and  we  consider  the  staff  comments  to  be

constructive. A hearing is scheduled for August 27, and we expect the final order later this year.

In North Carolina, the financing requires affiliates agreement approval. This week, the NCUC public

staff were the only party to file comments and we consider their comments to be constructive. Next

steps will be commissioned hearings, if requested, followed by a commission order. We continue to

expect  the  CVOW  financing  partnership  to  be  completed  by  the  end  of  the  year,  and  we  look

forward to continuing to work with all parties involved.

Turning  to  financing  on  Slide  6.  Since  our  last  call,  we  successfully  issued  $2  billion  in  enhanced

junior subordinated notes. These tax-deductible securities received 50% equity credit from the credit

rating  agencies.  We've  also  issued  approximately  $400  million  of  equity  under  our  ATM  program,

representing 80% of the midpoint of our annual guidance, as well as roughly $100 million under our

DRIP programs.

Consistent with our prior guidance during the remainder of the year, we'll complete ATM and DRIP

issuance, complete a final long-term debt issuance at DEV, and utilized proceeds from the closings

of  the  PSNC  sale  and  the  CVOW  partnership  financing  to  further  reduce  debt  and  lower  interest

expense. In conclusion, I'll reiterate that I am highly confident in our ability to deliver on our financial

plan.  The  post-review  guidance  has  been  built  to  be  appropriately  but  also  not  unreasonably

conservative to weather unforeseen challenges that may come our way. And with that, I'll turn the

call over to Bob.

Robert M. Blue -- Chair, President, and Chief Executive Officer

Thank you, Steven, and good morning. I'll begin my remarks by highlighting our safety performance.

As  shown  on  Slide  7,  our  employee  OSHA  injury  recordable  rate  for  the  first  half  of  the  year  was

0.38, reflecting the continued positive trend from the last two years. This is a good start, but safety is

much more than just a number on a page.

It's  our  first  core  value  and  represents  the  well-being  of  our  people.  Our  focus  continues  to  be  on

driving workplace injuries to zero. Moving now to CVOW, the project is proceeding on time and on

budget, consistent with the time lines and estimates previously provided. Let me start by highlighting

the exciting progress we've made on monopile installation.

Thus far, we've taken receipt of 72 monopiles at the Portsmouth Marine terminal, representing 40%

of  the  project  total.  Our  partner,  EEW,  continues  to  make  excellent  progress,  and  we  expect

deliveries  to  continue  steadily  in  coming  weeks.  As  shown  on  Slide  8,  we  began  monopile

installation  using  DEME's  heavy  crane  vessel  the  ORION  on  May  22nd.  As  of  yesterday,  we

successfully installed 42 monopiles.

After  a  start-up  period  during  which  we  successfully  calibrated  our  sound  verification  process  in

accordance  with  our  permits,  we've  been  able  to  ramp  the  installation  rate  markedly  including

achieving two monopile installations in a single day on July 21st and again on July 28th. Last week,

the  project  welcomed  a  second  bubble  curtain  vessel,  an  important  ancillary  installation  vessel.  A

bubble curtain is deployed around the pile driving site during every monopile installation as depicted

on Slide 9. The second vessel will effectively reduce time between installations.

In  summary,  we're  confidently  on  our  way  to  achieving  our  goal  of  70  to  100  monopiles  installed

during  the  first  of  two  planned  installation  seasons.  In  another  important  milestone,  installation  of

scour  protection  for  the  monopiles  began  in  June.  We've  started  work  on  23  monopiles  to  date,

which  is  consistent  with  the  final  project  schedule.  Turning  now  to  Slide  10  for  a  few  additional

updates on permits.

We  have  received  all  federal  permits.  This  is  unchanged.  On  materials  and  equipment,  we're  on

track and making excellent progress. Two of three offshore substation topside structures have been

completed and delivered to Semco and Denmark for outfitting, 33 Transition pieces have been fully

fabricated and 15 have been delivered to the Portsmouth Marine Terminal.

All 161 miles of onshore underground cable has been manufactured and about half of the 600 miles

of offshore cable has been produced. In fact, we expect to begin installing the export cable later this

quarter. Scheduled for the manufacturing of our turbines remains on track. Fabrication of the towers

for our turbines began in June.

It's  worth  noting  that  even  though  we  won't  begin  turbine  installation  until  2025  per  our  schedule.

DMA recently finished supporting a monopile installation campaign for Moore West a project off the

coast  of  Scotland  that  has  now  successfully  installed  the  same  Siemens  Gamesa  wind  turbine

model that CVOW will use. Roughly half of the turbines have been installed and the first turbines are

already producing power. The lessons learned from that project will benefit our project installation in

the future.

Moving  onshore.  Construction  activities  remain  on  track,  including  civil  work  to  support  overhead

lines, horizontal directional drills, and duct bank to support the underground work and boards where

the  export  cables  come  ashore.  On  regulatory,  last  November,  we  made  our  2023  rider  filing,

representing  $486  million  of  annual  revenue  and  the  final  order  was  received  on  July  25th,

approving our revenue request. Turning to Slide 11.

The  project's  expected  LCOE  is  unchanged  at  $73  per  megawatt  hour.  Project  to  date,  we've

invested  approximately  $4.5  billion  and  remain  on  target  to  spend  approximately  $6  billion  by

year-end  2024.  Per  the  quarterly  update  filing  today,  current  unused  contingency  is  $143  million

compared to $284 million last quarter. Use of this contingency is as expected.

I'd just note that the current unused contingency as a percentage of the remaining project costs at

3%  is  equal  to  the  same  percentage  at  the  time  of  the  original  filing  in  November  2021,  despite

being  some  33  months  further  along  with  the  project.  The  current  contingency  level  continues  to

benchmark  competitively  as  a  percentage  of  total  budgeted  costs  when  compared  to  other  large

infrastructure  projects  we've  studied  and  ones  that  we've  completed  in  the  past.  We've  been  very

clear with our team and with our suppliers and partners the delivery of an on-budget project is the

expectation.  Lastly,  the  project  is  currently  33%  complete,  and  we've  highlighted  the  remaining

major milestones on Slide 12.

Let  me  now  provide  a  few  updates  on  Charybdis.  Since  May,  we've  installed  the  main  crane

structures  and  the  Helideck  structure  as  shown  on  Slide  13.  And  the  upper  leg  construction

continues on track. We've commenced the main engine load testing, which is on track.

In  the  coming  weeks,  we  will  perform  main  crane  load  testing.  Turning  to  Slide  14.  The  vessel  is

currently  89%  complete,  up  from  85%  as  of  our  last  update.  There's  no  change  to  the  expected

delivery time frame of late 2024 or early 2025, which will be marked by the successful completion of

sea  trials,  after  which  the  vessel  will  return  to  port  for  additional  work  that  will  allow  it  to  hold  the

turbine towers, blades and the cells.

There's  no  change  to  the  vessel's  expected  availability  to  support  the  current  CVOW  construction

schedule,  which  we  anticipate  will  start  in  the  third  quarter  next  year.  As  reflected  in  today's

materials,  we've  updated  the  project's  current  estimated  costs,  including  financing  costs  to  $715

million, compared to $625 million last quarter. The drivers for the increased costs are modifications

to accommodate project-specific turbine loads based on final certified weights and dimensions of the

equipment  and  additional  financing  costs.  The  modifications  will  enable  Charybdis  to  handle  the

latest technology turbine design.

Charybdis is vital not only to CVOW, but also to the growth of the offshore wind industry along the

U.S. East Coast and is key to the continued development of a domestic supply chain by providing a

homegrown solution for the installation of offshore wind turbines. We continue to see strong interest

in use of the vessel after the CVOW commercial project is complete. Let's turn to South Carolina on

Slide 15.

On  July  12th,  we,  along  with  the  office  of  regulatory  staff  and  other  interveners  submitted  a

comprehensive  settlement  agreement  in  our  pending  electric  rate  case  for  approval  by  the  Public

Service  Commission  of  South  Carolina.  The  settlement  includes  all  parties  signing  on  or  not

opposing and reflects the strong collaboration throughout the process. The settlement is premised

on a 9.94% allowed ROE and a 52.51% equity capital structure, compared to rates at the time of our

original  request  in  March  and  offset  by  the  fuel  reduction  and  other  factors,  the  settlement's  rate

request would represent a net 1% increase for residential customers' electric rate. If approved, new

rates will go into effect September 1st.

We  look  forward  to  further  collaboration  with  stakeholders  in  South  Carolina.  Moving  now  to  data

centers  on  Slide  16.  As  I've  said  before,  we're  ramping  into  the  very  substantial  and  growing

multi-decade utility investment required to address resiliency and decarbonization public policy goals

plus the very robust demand growth we're observing in real time across our system. This growth has

been recognized by third parties.

As  just  one  example,  Virginia  was  recently  named  America's  top  state  for  business  in  2024.  This

was Virginia's record sixth time at the top of CNBC's rankings and its third win in five years, a record

unmatched  by  any  other  state  since  the  study  began  in  2007.  For  full-year  2024,  we  expect  DEV

sales  growth  to  be  between  4.5%  to  5.5%,  driven  by  economic  growth,  electrification  and

accelerating data center expansion. It's worth noting that in July, we registered six new all-time peak

demand records and just as we expect, our customers likely had no idea of these demanding load

conditions given the high-quality operational performance delivered by our colleagues.

The  data  center  industry  continues  to  grow  in  Virginia.  We've  connected  nine  new  data  centers

year-to-date  through  July,  consistent  with  our  expectations  to  connect  15  data  centers  in  2024.

Since  2013,  we've  averaged  around  15  data  center  connections  per  year.  However,  growth  is

accelerating in orders of magnitude, driven by the number of requests, the size of each facility and

the acceleration of each facility's ramp schedule to reach full capacity.

We're  taking  the  steps  necessary  to  ensure  our  system  remains  resilient  and  reliable.  We  had

accelerated plans for new 500kv transmission lines and other infrastructure in Northern Virginia, and

that remains on track. We were awarded over 150 electric transmission projects totaling $2.5 billion

during the PJM open window last December. PJM's latest open window, which commenced on July

15th is anticipated to be equal to or greater in investment needs as the RTO looks to accommodate

data center growth both in Northern Virginia and beyond with additional transmission upgrades.

We're working expeditiously with PJM, the SCC, local officials and other stakeholders to fast-track

critical  projects.  We're  committed  to  pursuing  solutions  that  support  our  customers  and  the

continued growth of the region. This includes assessing dispatchable generation needs, especially

during winter and on-site backup fuel storage. To that end, in June, we filed a petition with the SEC

to  construct  and  operate  a  backup  fuel  source  for  Brunswick  and  Greensville  power  stations  to

support operations and improve system reliability.

Additionally, in July, we announced the acquisition of an additional offshore wind leasehold in North

Carolina  from  Avangrid,  which  we  view  as  an  attractive  option  for  future  regulated  offshore  wind

development,  as  well  as  a  request  for  proposals  to  evaluate  feasibility  of  development  of  small

modular reactors at our North Anna site. These projects reflect an all-of-the-above approach to meet

growing  demand.  When  we  consider  this  demand  growth,  we  think  about  the  full  value  chain,

transmission, distribution and generation infrastructure investment that has and will continue to drive

utility rate base growth. Given these drivers, we continue to believe there may be opportunities for

incremental regulated capital investment toward the back end of our plan and beyond.

As I've said before, we will look at incremental capital through the lenses of customer affordability,

system reliability, balance sheet conservatism, and our low-risk profile. Looking forward, we'll file a

new IRP in October. Last year's IRP factored in significant load growth and investment in generation

and  transmission  over  the  next  15  years  to  meet  that  load  growth,  while  keeping  the  cumulative

average  annual  growth  in  the  customer  bill  below  3%.  The  most  recent  PJM  DOM  zone  load

projections as shown on Slide 17, which were only modestly different than last year's, along with our

work to optimize the best ways to meet this load will be factored into our planning for this year's IRP.

Before I summarize our remarks, let me touch on data center cost allocation on Slide 18, which has

been a topic of investor interest. We routinely examine cost allocations and the corresponding rate

designs to ensure they're fair and reasonable. Distribution and generation rates are reviewed by the

SEC  every  two  years  and  with  our  next  biennial  review  in  2025.  Transmission  rates  on  the  other

hand are reviewed by the SEC every year during our rider T1 proceeding.

In  both  proceedings,  if  the  cost  of  serving  one  or  more  customer  classes  has  changed  over  time,

then  costs  are  reallocated  to  ensure  each  customer  class  is  paying  their  fair  share.  If  the  cost  of

serving one customer class has increased, for example, then their cost allocation will increase and

the cost allocation for all other customers will decrease. The most important example in recent years

has  been  the  significant  reallocation  of  transmission  costs  from  residential  customers  on  to  larger

energy  users  such  as  data  centers.  Since  2020,  residential  customers'  allocation  of  transmission

cost has declined by 10%.

While GS4, our largest energy usage customer class has increased by 9%. This reflects the growing

share  of  our  system  that  is  made  up  of  data  centers,  along  with  a  shift  in  how  we  allocate

transmission costs among the classes. We've also adopted other rate mechanisms in recent years

that combined with regular and routine assessment of cost allocation and rate design ensure costs

are shared equitably across rate classes. We have a long and exciting history of working with data

center customers, and we look forward to supporting all of our customers going forward.

With  that,  let  me  summarize  our  remarks  on  Slide  19.  Our  safety  performance  this  quarter  was

outstanding,  but  there's  more  work  to  do  to  drive  injuries  to  zero.  We  reaffirmed  our  financial

guidance. Our offshore wind project is on time and on budget.

We continue to make the necessary investments to provide the reliable, affordable, and increasingly

clean  energy  that  powers  our  customers  every  day.  And  we  are  100%  focused  on  execution.  We

know we must deliver, and we will. With that, we're ready to take your questions.

Operator

Questions & Answers: