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Berry Corp (bry) (BRY)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 2024 delivered stronger operations and cash generation: Adjusted EBITDA rose to $82M (+22% QoQ), Free Cash Flow was $24M, and production increased to 26.1 MBoe/d (+5% QoQ), while GAAP EPS was a loss of $0.02 due to derivative and debt retirement impacts .
  • Utah horizontal program is a visible near-term catalyst: two farm-in wells reached peak rates of ~1,900–2,000 Boe/d, first operated horizontal well has reached TD, and management sees ~200 potential horizontal locations with ~20% per-foot cost advantage vs peers .
  • Capital structure strengthened via the December refinancing: $450M term loan, $95M RBL, liquidity $110M, leverage 1.49x; 2025 capital $110–120M with 40% to Utah, 60% California; fixed dividend $0.03 this quarter maintained .
  • Risk management tightened: ~75% of 2025 oil volumes hedged at ~$74.24 Brent and ~70% of 2025 gas purchases hedged at ~$4.25/MMBtu; heavy hedging is mandated under loan covenants and supports funding the 2025 program from operating cash flows .
  • Stock reaction catalysts: further Utah well results from the 2025 operated pad, potential JV to accelerate Utah development, ongoing California sidetrack outperformance (>100% returns), and evidence of sustained production at the upper end of guidance .

What Went Well and What Went Wrong

What Went Well

  • Production and cash generation improved: Q4 production 26.1 MBoe/d (+5% QoQ), Adjusted EBITDA $82M (+22% QoQ), and FCF $24M, underscoring operational execution .
  • Utah horizontal performance: two recent farm-in wells delivered ~1,900–2,000 Boe/d peak rates; first operated horizontal well reached TD with 93% of the lateral in zone, reinforcing basin potential and cost advantages .
  • California thermal diatomite sidetracks: 28 sidetracks in 2024 achieved >100% returns and unlocked ~115 additional opportunities (plus ~110 elsewhere), sustaining production and inventory depth despite permitting constraints .

What Went Wrong

  • GAAP earnings impacted by derivatives and financing items: Q4 GAAP net loss of $1.8M and diluted EPS of $(0.02) driven by derivative losses and a $7.1M loss on debt retirement; quarter also showed realized losses on gas purchase hedges .
  • YoY revenue declines: “Oil, natural gas & NGL revenues” fell to $158M (vs $172M in Q4 2023), and total revenues and other declined to $188M (vs $300M in Q4 2023), reflecting lower prices and negative derivative marks .
  • Well servicing segment softness: management noted lower margins and market disruption for abandonment services in recent quarters; Q3 guidance reset Well Servicing & Abandonment segment Adjusted EBITDA to $6–8M .

Financial Results

MetricQ4 2023Q3 2024Q4 2024
Oil, natural gas & NGL revenues ($USD Millions)$172 $154 $158
Total revenues and other ($USD Millions)$300.3 $259.8 $187.8
Diluted EPS ($USD)$0.81 $0.91 $(0.02)
Adjusted diluted EPS ($USD)$0.13 $0.14 $0.21
Net (loss) income ($USD Millions)$62.6 $69.9 $(1.8)
Adjusted Net Income ($USD Millions)$10.4 $10.8 $16.5
Adjusted EBITDA ($USD Millions)$70.0 $67.1 $81.8
Cash Flow from Operations ($USD Millions)$79.0 $70.7 $41.4
Capital expenditures ($USD Millions)$17.0 $25.9 $17.2
Free Cash Flow ($USD Millions)$62.0 $44.8 $24.1
Production (MBoe/d)25.9 24.8 26.1

Segment breakdown (annual):

Metric ($USD Thousands)FY 2023FY 2024
E&P Revenues (ex-hedge)$684,900 $671,984
Well Servicing & Abandonment Revenues$185,767 $132,452
Corporate/Eliminations$(7,213) $(20,595)
Consolidated Revenues (ex-hedge)$863,454 $783,841
E&P Capital Expenditures$64,844 $97,331

KPIs and unit economics (quarterly trajectory):

KPIQ2 2024Q3 2024Q4 2024
Production (MBoe/d)25.3 24.8 26.1
Realized oil price ($/bbl, w/o hedges)$78.18 $72.40 $69.08
Lease operating expenses ($/boe, unhedged)$23.47 $24.02 $23.48
Adjusted G&A – E&P & Corp ($/boe)$6.34 $6.19 $5.96
Energy LOE – hedged ($/boe)N/A$14.00 $13.07

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Average Daily Production (boe/d)FY 2025N/A24,800–26,000 New
% Oil ProductionFY 2025N/A91–95% New
Non-energy LOE ($/boe)FY 2025N/A$13.00–$15.00 New
Energy LOE (unhedged) ($/boe)FY 2025N/A$12.70–$14.50 New
Natural Gas Purchase Hedge Settlements ($/boe)FY 2025N/A$1.00–$1.60 New
Taxes, other than income taxes ($/boe)FY 2025N/A$5.50–$6.50 New
Adjusted G&A – E&P & Corp ($/boe)FY 2025N/A$6.35–$6.75 New
Capital Expenditures ($USD Millions)FY 2025N/A$110–$120 New
DividendQ4 2024/FY 2025 policy$0.03/share in Q3 2024 $0.03/share declared; fixed dividend policy maintained Maintained
Adjusted G&A – E&P & Corp ($/boe)FY 2024 (update made in Q3)Prior lower range$6.30–$6.50 (raised due to inflation) Raised
Well Servicing & Abandonment Segment Adjusted EBITDAFY 2024 (update made in Q3)Prior higher range$6–$8M (reduced on market disruption) Lowered

Earnings Call Themes & Trends

TopicPrevious Mentions (Q-2 and Q-1)Current Period (Q4 2024)Trend
Utah horizontal developmentQ2: Acquired WI in 4 Uteland Butte horizontals; above pre-drill estimates; positioned to develop ~100k acres . Q3: Executed 2nd farm-in, marketing JV to accelerate 2025 pads .Two farm-in wells at ~1,900–2,000 Boe/d peak; ~200 potential locations; first operated well TD with 93% in-zone; considering JV but disciplined .Strengthening execution; near-term well flow catalysts
California permitting/EIRQ3: Permits in-hand for sidetracks/workovers; production sustainability not dependent on EIR .Only ~5% of CA PUDs in constrained areas; expect EIR alternatives timing ~2026; continuing sidetracks/workovers .Manageable regulatory overhang
Cost structure/LOE & G&AQ2: LOE/boe down 11% QoQ; adjusted G&A trending down . Q3: Lower hedged LOE; steady CFO; improved FCF .Q4: Adjusted EBITDA +22% QoQ; LOE (hedged) and G&A/boe improved; sustained production .Improving unit economics
Hedging & risk managementQ2: Active oil and NWPL gas hedges . Q3: Maintained heavy hedging .~75% of 2025 oil at ~$74.24 Brent; ~70% 2025 gas at ~$4.25; covenant-driven minimums .Strong risk mitigation
Capital structureQ3: $545M term loan to redeem 2026 notes and refinance RBL; move to fixed dividend .YE 2024: $450M term loan; $95M RBL; 1.49x leverage; optional par takeout in first 2 years .Improved flexibility and liquidity
ESG/methaneQ2: 60% completion toward methane reduction target; zero incidents .>80% methane reduction vs 2022; expected ~10% Scope 1 reduction; new detection and LDAR initiatives; potential CCUS partnerships .Advancing ESG goals
C&J Well Services/P&AN/A earlier.CA legislation increases P&A obligations; demand should rise; consolidation likely before pricing/activity inflection; BRY insulated .Emerging opportunity

Management Commentary

  • CEO (Fernando Araujo): “Our thermal diatomite asset continues to deliver value enhancing results… we successfully drilled 28 sidetracks with exceptional results and a rate of return exceeding 100%… unlocked the potential to drill an additional 115 more sidetracks… and expanded development of our 100,000 net acre position in the Uinta Basin” .
  • President (Danielle Hunter): “Berry’s ability to sustain production over the next few years is not dependent on the EIR… only 5% of California PUD reserves are in areas where new drill permits are currently constrained” .
  • CFO (Jeff Magids): “Fourth quarter oil and gas sales were $158M, excluding derivatives, with a realized oil price of 93% of Brent… adjusted EBITDA was $82M… year-end total debt $450M, liquidity $110M, leverage 1.5x… 2025 capital guidance $110–$120M, with 40% to Utah” .
  • CEO (Fernando Araujo): “We have already started to execute on value-enhancing opportunities in both California and the Uinta Basin, where we believe we have significant upside value… an exciting time to be at Berry” .

Q&A Highlights

  • Utah wells and operated pad: Management detailed lateral lengths (3-mile laterals delivering ~2,000 Boe/d peaks vs earlier pad with two 2-mile laterals at ~1,100 Boe/d), emphasizing uniform reservoir quality and strong early results; high expectations for operated pad .
  • Potential JV in Utah: Active discussions to mitigate capital needs and accelerate activity, but will only transact on accretive terms; comfortable advancing the first pad alone .
  • California bolt-ons: Ongoing conversations with private operators in Kern County; opportunities exist to execute under the right structure, meaningful for production even if not large-scale .
  • C&J Well Services and P&A legislation: CA regulation increases P&A obligations for operators; demand likely to rise after regulatory implementation and sector consolidation; BRY would be insulated .
  • Permitting and EIR alternatives: Sidetracks/workovers continue with permits; conditional use/multi-basin permits timing similar to EIR, potentially 2026 .
  • Utah long-term potential: Theoretically grow from ~5,000 Boe/d to ~40,000 Boe/d over ~10 years with multi-rig program; watch 2025 pad results as signposts .

Estimates Context

  • S&P Global consensus data for Q4 2024 EPS, revenue, and EBITDA was unavailable at the time of this analysis due to access limits. As a result, we cannot quantify beat/miss vs Wall Street consensus here; we recommend cross-checking updated SPGI estimates post-call to assess potential revisions and the magnitude of any surprises.

Key Takeaways for Investors

  • Utah is the near-term swing factor: first operated horizontal pad is underway, with prior farm-in wells delivering ~2,000 Boe/d peaks; ~200 potential locations and cost advantages (~20% lower per foot) point to scalable growth if pad results hold .
  • California sidetracks underpin stability: >100% returns in thermal diatomite and >200 identified sidetrack opportunities across assets support sustained production despite permitting uncertainty .
  • Heavy hedging supports 2025 program funding: ~75% of 2025 oil at ~$74.24 Brent and ~70% of expected 2025 gas purchases hedged reduce cash flow volatility and align with loan covenants .
  • Balance sheet flexibility post-refinancing: $450M term loan with optional par takeout in first two years, $95M RBL, 1.49x leverage, and $110M liquidity give capacity to pursue bolt-ons or JV structures without equity dilution .
  • Unit economics trending better: LOE/boe and G&A/boe improved; Adjusted EBITDA rose to $82M in Q4 (+22% QoQ), highlighting operating leverage even with lower realized oil prices QoQ .
  • Watch catalysts: operated Utah pad IPs and decline profiles, potential JV, additional CA bolt-ons, and any update on EIR/permit pathways; these could drive estimate revisions and multiple expansion .
  • Dividend policy is sustainable but modest: fixed $0.03/share quarterly maintained; within a debt-prioritizing capital framework, upside to returns likely tied to FCF expansion via Utah execution .