APA Earningcall Transcript Of Q2 of 2024

John J. Christmann -- President and Chief Executive Officer

Good morning, and thank you for joining us. On the call today, I will review APA's second quarter

performance, discuss the Callon integration and review our activity plan and production expectations

for  the  remainder  of  2024.  Our  second  quarter  results  were  strong  across  the  board  with

higher-than-expected  production  in  all  three  operational  areas.  Capex  was  lower  than  expected,

mostly due to timing of spend.

In  the  U.S.,  oil  volumes  of  139,500  barrels  per  day  were  up  67%  from  the  first  quarter  as  we

incorporated  Callon  into  our  operations.  Production  and  costs  were  significantly  better  than

expected  on  a  BOE  basis  after  adjusting  for  asset  sales  and  discretionary  natural  gas  and  NGL

curtailments.  Our  Permian  Basin  continues  to  perform  at  a  high  level,  and  we  marked  our  sixth

quarter in a row of meeting or exceeding U.S. oil production guidance.

On  a  BOE  basis,  oil  now  comprises  46%  of  our  total  U.S.  production  following  the  Callon

transaction. With this increased exposure, APA's cash flow sensitivity to a $5 per barrel change in oil

price is approximately $300 million annually. In Egypt, production also exceeded expectations.

We saw a positive contribution from new wells, improved results from recompletions, and continued

strong base production. Base production is particularly benefiting from the implementation of several

new water injection projects. We are also beginning to see a decrease in off-line oil volumes waiting

on workover as we moderate the drilling rig count to free up workover rig resources. Turning to the

North Sea.

Operations  were  relatively  smooth  in  the  second  quarter  with  better-than-forecast  facility  run  time

driving higher production. Our ongoing focus in the North Sea is rightsizing our cost structure for late

life  operations.  In  Suriname,  our  partner,  Total,  recently  announced  that  it  has  secured  the  FPSO

hole for our first offshore development, and we remain on track for FID before year-end and first oil

in 2028. And in Alaska, we are still working through options for the upcoming winter drilling season

and look forward to returning to exploration activities.

Turning now to the Callon acquisition. Note that in last night's release, we increased our estimate of

annual Callon cost synergies from $225 million to $250 million as we leverage economies of scale of

the combined APA and Callon Permian businesses. Steve will speak in more detail about some of

the  specific  initiatives  driving  these  cost  reductions.  More  importantly,  we  are  just  beginning  to

implement drilling unit design and operational changes that we expect will create substantial value in

the Callon acreage via improved well performance and capital efficiency.

Our  preliminary  estimate  is  that  we  can  drill  a  standardized  two-mile  lateral  for  roughly  $1  million

less  than  Callon  was  spending  in  2023.  We  recently  spud  our  first  APA  designed  drilling  unit  on

Callon  acreage,  the  five-well  Callon  unit  in  the  Midland  Basin  and  should  begin  to  see  initial

flowback results in the fourth quarter. Turning now to our activity plans and outlook for the second

half of 2024. In yesterday's release, we provided guidance for the third and fourth quarters, which

contains some notable positives.

In the U.S., we will average nine to 10 rigs for the remainder of this year, consisting of approximately

five rigs in the Delaware and four rigs in the Midland. We plan to run three to four frac crews and

complete about 90 wells by year-end. This sets the stage for strong oil growth in the second half of

the year. Accordingly, we are increasing fourth quarter U.S.

oil  guidance  to  150,000  barrels  per  day  which  is  up  1,500  barrels  per  day  after  adjusting  for  the

impact  of  asset  sales  closed  in  June.  This  represents  organic  production  growth  of  roughly  8%

compared  to  the  second  quarter.  We  also  expect  an  increase  in  natural  gas  and  NGL  production

driven  primarily  by  fewer  discretionary  curtailments  than  in  the  first  half  of  the  year.  In  Egypt,  we

expect a continuation of the operational progress that we made in our second quarter.

There  will  be  some  volume  impacts  from  the  rig  count  decrease  but  this  should  be  mitigated  by

strong base production performance and increased workover capacity to remediate wells offline. By

year-end,  we  project  the  backlogged  oil  production  will  be  closer  to  more  normalized  operating

levels.  On  our  May  call,  we  said  that  adjusted  production  in  Egypt  would  remain  relatively  flat  in

2024 and while gross oil production would be flat to slightly down through the remainder of the year.

While there are a number of moving parts to the program in Egypt, we see no material variances to

our May outlook.

And therefore, guidance is unchanged. Similarly, our full year production guidance in the North Sea

is unchanged. We though we now expect a bit larger decrease in third quarter volumes associated

with maintenance and turnaround activity at barrel and a slightly larger subsequent rebound in the

fourth quarter. In closing, second quarter was an excellent quarter operationally, and we continue to

execute at a high level in the Permian Basin.

We  are  realizing  greater-than-expected  cost  savings  from  the  Callon  acquisition  and  have  a  clear

pathway  and  plan  to  improving  capital  efficiency  on  those  assets.  Egypt  also  had  a  very  good

quarter and is beginning to deliver significant capital efficiency improvements. Though our drilling rig

count is coming down, continued strength in base production and the return of wells offline will help

sustain volumes in the near term. At current strip pricing, the second half of the year is setting up to

deliver a substantial increase in free cash flow compared to the first half.

And  lastly,  I  am  very  proud  of  our  teams  for  delivering  these  results  while  remaining  on  track  to

achieve our safety and environmental goals for the year. For a detailed review of APA's safety and

environmental  performance,  I  encourage  you  to  review  our  recently  published  2024  sustainability

report, which can be accessed via our website. And with that, I will turn the call over to Steve.

Stephen J. Riney -- Executive Vice President, Chief Financial Officer

Thank  you,  John.  For  the  second  quarter,  under  generally  accepted  accounting  principles,  APA

reported  consolidated  net  income  of  $541  million  or  $1.46  per  diluted  common  share.  As  usual,

these  results  include  items  that  are  outside  of  core  earnings,  the  most  significant  of  which  were  a

$216  million  after-tax  gain  on  the  divestiture  and  $98  million  of  after-tax  charges  for  transaction,

reorganization and separation costs, mostly associated with the Callon acquisition. Excluding these

and other smaller items, adjusted net income for the second quarter was $434 million or $1.17 per

share.

During  the  first  half  of  the  year,  we  generated  roughly  $200  million  of  free  cash  flow  and  returned

$311  million  to  shareholders,  nearly  half  of  which  consisted  of  share  repurchases.  That's  a  lot

compared  to  the  $200  million  of  free  cash  flow,  but  we  like  buying  at  those  share  prices,  and  we

anticipate free cash flow will be much higher in the second half of the year. That said, the balance

sheet  remains  an  important  priority,  and  I  will  talk  about  plans  for  further  debt  reduction  in  a  few

minutes. Now let me turn to progress on the Cowen integration.

As John noted, we increased our estimate of annual synergies to $250 million. Since we announced

the Callon acquisition, we have categorized synergies into three buckets: overhead, cost of capital,

and operational. We are now increasing our estimate of expected annual overhead synergies to $90

million.  Most  of  this  was  captured  by  the  end  of  the  second  quarter  on  a  run  rate  basis  and  the

remainder will be done by year-end.

At  this  time,  we  anticipate  that  our  quarterly  core  G&A  run  rate  as  we  enter  next  year  will  be

approximately $110 million. With that, we will have eliminated about 75% of Callon overhead cost.

So  no  material  further  synergies  are  likely.  Our  cost  of  capital  synergy  estimate  assumed  terming

out Callon's $2 billion debt at APA's lower long-term cost of borrowing.

At the closing, we used cash from the revolver and a $1.5 billion three-year term loan to refinance

this debt. Instead of turning this debt out, our current intention is to use asset sales and free cash

flow  to  simply  pay  off  the  loan  before  the  end  of  its  three-year  term.  This  would  represent  a

significant  step  forward  in  the  goal  to  strengthen  the  balance  sheet  and  to  fully  realize  these

synergies.  And  lastly,  we  are  increasing  our  operational  synergies  to  $120  million  annually

approximately 60% of which is associated with capital savings and 40% attributable to LOE.

To reiterate, these cost synergies do not include capital productivity benefits associated with uplifting

type  curves  and  improving  well  economics  through  spacing,  landing  zone  optimization,  and  frac

size.  We  believe  this  will  be  a  source  of  material  long-term  value  accretion.  Turning  to  our  2024

outlook. John has already discussed our activity plans and production guidance, so I will just add a

few items of note.

We now expect that our original full year capital guidance of $2.7 billion may start trending down a

bit.  A  number  of  factors  could  contribute  to  this,  including  further  synergy  capture  from  the  Callon

combination, lower service costs, improving capital efficiency, and potential minor reductions in the

planned activity set, mostly in the U.S. For purposes of third quarter U.S. BOE production guidance,

we are estimating further Permian gas curtailments of 90 million cubic feet per day.

This  would  also  result  in  the  curtailment  of  7,500  barrels  per  day  of  NGLs.  As  most  of  you  are

aware,  our  income  from  third-party  oil  and  gas  purchased  and  sold  can  change  significantly  from

quarter-to-quarter. This is primarily driven by the volatility and differentials between Waha and Gulf

Coast  gas  pricing  regardless  of  the  absolute  pricing  levels.  It's  important  to  note  that  APA's  gas

marketing  and  transportation  activities  are  generally  more  profitable  when  Waha  gas  price

differentials are wider.

For example, the Waha differential was very wide in the second quarter, while Gulf Coast gas prices

averaged around $1.65, Waha gas prices averaged closer to negative $0.34. Because of the nearly

$2  differential  income  from  our  third-party  marketing  and  transportation  activities  was  well  above

expectations.  At  current  strip  gas  pricing,  we  expect  a  similar  dynamic  in  the  third  quarter.

Accordingly, we are raising our full year estimate of income from third-party oil and gas purchased

and sold by $120 million to around $350 million.

Approximately half of the full year estimate is attributable to the Cheniere gas supply contract and

half  is  attributable  to  our  marketing  and  transportation  activities.  Lastly,  APA  is  now  subject  to  the

U.S. alternative minimum tax. And accordingly, we are introducing new guidance for current U.S.

tax accruals of $95 million for the year. And with that, I will turn the call over to the operator for Q&A.

Operator

Questions & Answers: