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Vital Energy, Inc. (VTLE)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 2024: Vital delivered record volumes (147.8 MBOE/d; oil 69.8 MBO/d) and outperformed guidance on production and LOE; GAAP results were negatively impacted by a non‑cash $481.3mm impairment, driving a net loss of $359.4mm (diluted EPS $(9.59)); non‑GAAP Adjusted Net Income was $86.5mm (adjusted diluted EPS $2.30) and Consolidated EBITDAX was $383.5mm .
  • Q4 actuals vs guidance: production beat the high end (147.8 vs 137.0–143.0 MBOE/d), LOE beat ($8.89/BOE vs $9.35 guide), while capex was higher ($226mm vs $175–$200mm), largely due to higher working interest/carry and activity pull‑ins .
  • 2025 outlook tightened/updated: capex $825–$925mm (≈3% below earlier projections), oil production 62.5–66.5 MBO/d (slightly lower vs earlier projections) with ~75% 2025 oil hedged at ~$75/bbl; aiming for ~$330mm Adjusted FCF at $70 WTI and ~$350mm total debt reduction by YE25 .
  • Management highlighted Point Energy integration outperformance and inventory depth (>11 years; ~925 locations, ~400 sub‑$50 WTI), while acknowledging underperformance on a specific Upton County pad and operational delays that shift some 2025 volumes to later in the year—key catalysts remain execution on cost, production cadence recovery, and accelerated deleveraging .

What Went Well and What Went Wrong

  • What Went Well

    • Production and cost execution: “We outperformed our LOE guidance by 5%, delivering at cost of $8.89 per BOE,” and total/oil production exceeded the high end of guidance, driven by better‑than‑expected performance from recently acquired Point Energy assets .
    • Free cash flow and EBITDAX: Generated Consolidated EBITDAX of $383.5mm and Adjusted FCF of $110.8mm for the quarter, reflecting strong operations and hedging support .
    • Inventory quality/scale: Inventory expanded to 925 oil‑weighted locations (>11 years), with longer laterals and delineation of deeper horizons (Wolfcamp C/D, Barnett); management cited improved breakevens ($53 avg WTI), horseshoe wells/J‑shaped designs, and an 8‑mile project with ~$40 WTI breakevens .

  • What Went Wrong

    • GAAP earnings driven by impairment: A non‑cash pre‑tax impairment of $481.3mm led to a Q4 net loss of $359.4mm (diluted $(9.59)), overshadowing otherwise solid operating metrics .
    • Specific underperformance and timing: A seven‑well Upton County package underperformed expectations and operational delays shifted completions/turn‑in‑line timing, modestly lowering 2025 oil production vs earlier projections .
    • Capex above plan: Q4 capex was $226mm vs $175–$200mm guidance, due to higher working interest/carry ($17mm) and activity acceleration ($5mm) .

Financial Results

Income Statement Snapshot (GAAP/Non-GAAP)

MetricQ4 2023Q3 2024Q4 2024
Total Revenues ($mm)$444.5 $459.2 $534.4
Net Income (Loss) ($mm)$281.4 $215.3 $(359.4)
Diluted EPS (GAAP)$9.44 $5.73 $(9.59)
Adjusted Net Income ($mm)——$86.5
Adjusted Diluted EPS——$2.30
Consolidated EBITDAX ($mm)——$383.5

Notes: Q3/Q4 2024 Adjusted EPS only disclosed for Q4; Vital emphasizes Consolidated EBITDAX as a non‑GAAP operating metric .

Q4 Actuals vs Company Guidance (Q4 2024)

MetricGuidanceActualResult
Total Production (MBOE/d)137.0 – 143.0 147.8 Beat (above high end)
Oil Production (MBO/d)66.5 – 69.5 69.8 Beat (above high end)
LOE ($/BOE)$9.35 $8.89 Beat (lower than guide)
Capital Investments ($mm)$175 – $200 $226.1 Miss (higher than guide)

Operating KPIs

KPIQ4 2023Q3 2024Q4 2024
Avg Daily Production (BOE/d)113,747 133,339 147,819
Avg Daily Oil (Bbl/d)53,070 59,198 69,827
Realized Oil Price ($/Bbl, ex-deriv.)$79.37 $76.51 $70.80
LOE ($/BOE)$8.33 $8.78 $8.89
DD&A ($/BOE)$14.58 $15.25 $15.77
Capital Investments ($mm)—~$242 $226.1

Segment Reporting

SegmentNote
Exploration & Production (single operating segment)Company reports one operating segment .

Guidance Changes

MetricPeriodPrevious Guidance/OutlookCurrent GuidanceChange
Capital Investments ($mm)FY 2025~“around $900” (early outlook) $825 – $925 Lower midpoint (~3%)
Oil Production (MBO/d)FY 2025~Hold around 66.5 (flat to prior 4Q midpoint) 62.5 – 66.5 Slightly lower range
Total Production (MBOE/d)FY 2025—134.0 – 140.0 New disclosure
Adjusted FCF ($mm) @ $70 WTIFY 2025—~ $330 New disclosure
Debt Reduction Target ($mm)FY 2025—~ $350 by YE25 New disclosure
LOE trajectory ($/BOE)Exit 2025“Back into high‑8s” (Q3 view) Avg Q4’24–Q1’25 ≈$9.20; < $9 by YE25 Maintained/improving path
Q1 2025 Total (MBOE/d)Q1 2025—135.0 – 141.0 New disclosure
Q1 2025 Oil (MBO/d)Q1 2025—62.0 – 66.0 New disclosure
Q1 2025 Capex ($mm)Q1 2025—$230 – $260 New disclosure
Q1 2025 LOE ($mm)Q1 2025—$115 – $120 New disclosure

Drivers: lowered oil outlook and timing on completions tied to Upton County underperformance and operational delays; capex lowered on efficiencies with similar lateral footage planned .

Earnings Call Themes & Trends

TopicPrevious Mentions (Q2’24 and Q3’24)Current Period (Q4’24)Trend
Inventory expansion (horseshoe/J‑shaped, deeper targets)Horseshoe wells extended inventory; testing Barnett/Wolfcamp C; added >300 locations; targeting $50 breakevens ~925 locations (>11 yrs), avg breakeven ~$53; +140 deeper‑zone adds; move to J‑shaped 15k’ laterals; 8‑mile Midland project at ~$40 breakeven Positive, deeper and longer laterals supporting lower breakevens
Cost structure (LOE, D&C/ft)Delaware D&C cost path to ~$925/ft; LOE improvements; exit ’25 LOE high‑8s targeted Q4 LOE $8.89 vs $9.35 guide; avg Q4+Q1 ≈$9.20 aiming < $9 by YE25; ~25% lower D&C/ft vs entry Improving; ahead of plan on Q4 LOE
Hedging/FCF/debt reduction2025 hedges near $75; plan to use FCF to reduce debt; ~>$400mm adj FCF over next 5 quarters (as of Q3) ~75% of 2025 oil hedged at ~$75; ~$330mm 2025 adj FCF at $70 WTI; target ~$350mm debt paydown by YE25 Strong hedge book supports deleveraging
A&D posturePause large M&A; focus on operational excellence/FCF “Deemphasize potential large‑scale acquisitions” in 2025; prioritize debt reduction Consistent with pivot to organic execution
Regional performance (Upton/Midland/Delaware)Wider‑spacing outperformance in S. Delaware; Barnett tests positive; LOE optimization Upton County seven‑well package underperformed; shifting rigs; Point asset outperforming; capital leaning to Point/Delaware Mixed: Delaware strong; specific Upton tests weak
Tariffs/supply chainContracting and service market softening aiding costs OCTG largely secured through ’25; limited tariff exposure near‑term Managed; risk if tariffs persist beyond ’25

Management Commentary

  • Strategic focus: “In 2025, our primary goals are reducing costs, maximizing Adjusted Free Cash Flow generation, absolute debt reduction, and extending and enhancing our existing inventory.” – CEO Jason Pigott .
  • Debt/FCF cadence: “January net debt was already down $50 million below year-end levels, and we expect total 1Q debt paydown to be approximately $100 million.” – CEO remarks .
  • Inventory quality: “We now have approximately 925 oil-weighted locations… average breakeven oil price ~ $53 WTI… added deeper horizons (Wolfcamp C/D, Barnett) and longer laterals.” – CEO .
  • Design innovation: “~120 Horseshoe-shaped wells… now drilling J-shaped wells converting 3×10,000′ into 2×15,000′ laterals, reducing breakevens by ~$10/bbl.” – CEO .
  • 2025 capital and production: “Capex $825–$925mm… slightly lower oil production vs earlier projections due to Upton underperformance and delays; still ~same net lateral feet as 2024.” – CEO .

Q&A Highlights

  • Point asset integration: Early results “better-than-expected,” with lower downtime, stronger new wells, and LOE reductions carrying into 2025 (Katie Hill) .
  • Upton County underperformance: Weak Wolfcamp A/Lower Spraberry tests on the eastern edge; rigs shifting away; inventory counts adjusted accordingly (Mikell/Jason) .
  • Capital allocation: 2025 weighted to Delaware/Point; minimal appraisal spend in ’25; upside 250 locations to be delineated over multiple years (Katie Hill) .
  • Tariff exposure: OCTG largely secured for ’25; limited near‑term impact if steel tariffs persist (Katie Hill) .
  • Capital efficiency: Emphasis on lateral length extensions and shaped laterals to reduce breakevens; opportunistic mini‑bolt‑ons like the 8‑mile Midland project at ~$40 breakeven (Mikell) .

Estimates Context

  • Wall Street consensus from S&P Global (EPS, revenue, EBITDA) for Q4 2024 was unavailable at the time of this analysis due to data access limits; therefore, we cannot quantify beats/misses vs Street. Management did state they “beat expectations” on financial performance (EBITDAX/FCF) and exceeded production guidance, while capex ran above plan in Q4 .
  • Going forward, Street models may need to reflect: slightly lower 2025 oil production range vs earlier projections, lower capex midpoint on efficiencies, and the strong hedge coverage near ~$75/bbl supporting ~$330mm 2025 Adjusted FCF at $70 WTI .

Key Takeaways for Investors

  • Underlying operations strong despite GAAP loss: Record volumes, LOE beat, robust EBITDAX/FCF; the GAAP loss was driven by a non‑cash $481.3mm impairment .
  • Q4 execution vs guidance was net positive: production and LOE beat, capex miss explained by higher WI/carry and activity pull‑in—watch 2025 cost/ft and LOE trajectory (<$9/BOE by YE25) .
  • 2025 set up: ~$330mm Adjusted FCF at $70 oil, ~75% oil hedged at ~$75, and targeted ~$350mm debt reduction—de‑risking deleveraging plan .
  • Inventory quality/depth improving: ~925 locations, longer laterals, deeper horizons, design innovations (horseshoe/J‑shaped) lowering breakevens; significant optionality to extend drilling runway .
  • Watch production cadence: Early‑year dip from Upton underperformance and timing delays implies a V‑shaped 2025 production profile with a stronger exit rate (management commentary) .
  • Capital allocation discipline: De‑emphasis of large M&A; opportunistic small bolt‑ons where breakevens are compelling (e.g., ~$40 projects) .
  • Trading lens: Near‑term catalysts include confirmation of Q1 debt paydown (~$100mm), delivery on Q1 production/LOE guide, and visibility on 2H’25 completions cadence; risks center on well performance variability and service/tariff costs .
All figures and statements are sourced from Vital Energy’s Q4 2024 8‑K/press release and earnings materials unless noted: **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:0]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:1]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:2]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:5]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:7]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:9]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:10]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:11]** **[1528129_0001528129-25-000031_a21925vitalenergyreportsfo.htm:12]** **[1528129_1847487:6]** **[1528129_1847487:9]** **[1528129_1847487:10]** **[1528129_1847487:11]**. Prior quarter references use Q3 2024 10‑Q and Q2/Q3 2024 call transcripts: **[1528129_0001528129-24-000195_vtle-20240930.htm:8]** **[1528129_0001528129-24-000195_vtle-20240930.htm:30]** **[1528129_0001528129-24-000195_vtle-20240930.htm:33]** **[1528129_VTLE_3406752_2]** **[1528129_VTLE_3397830_1]** **[1528129_VTLE_3397830_2]** **[1528129_VTLE_3406752_3]** **[1528129_VTLE_3406752_4]** **[1528129_VTLE_3397830_12]**.