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SANDRIDGE ENERGY INC (SD)·Q4 2024 Earnings Summary

Executive Summary

  • Q4 2024 delivered higher volumes and stronger cash generation versus Q3: production averaged 19.1 MBoed (+12% QoQ, +19% YoY) and Adjusted EBITDA rose to $24.1M from $17.7M in Q3; basic EPS was $0.47, down from $0.69 in Q3 on mix and depletion effects .
  • Revenue (oil, gas, NGL) was $38.97M, up 30% QoQ (+$8.9M) and +15% YoY; LOE per Boe held at $6.43, while Adjusted G&A was $1.39/Boe, reflecting continued cost discipline .
  • Board declared a $0.11/share quarterly dividend (Mar 31, 2025 pay date); cash and restricted cash ended 2024 at $99.5M; the company has no debt .
  • 2025 guidance initiates a one‑rig Cherokee Shale plan (8 wells drilled, 6 completed) with total production of 5.9–7.1 MMBoe and $66–$85M capex; management highlighted hedges added to secure cash flows and optionality to lean into oilier Cherokee development as macro improves .

What Went Well and What Went Wrong

What Went Well

  • Production and revenue inflected: Q4 production 1,754 MBoe (19.1 MBoed), revenue $38.97M; realized gas price rose QoQ to $1.47/Mcf and NGLs to $18.19/bbl; Adjusted EBITDA improved to $24.1M .
  • Cost control: LOE held at $6.43/Boe; Adjusted G&A was $2.4M or $1.39/Boe; management emphasized “cost discipline continues to yield results” and an efficient org “just over 100 people” .
  • Strategic progress in Cherokee: initial operated DUCs achieved costs below historical play averages; plan to drill 8 and complete 6 wells in 2025 with low breakevens (~$35 WTI), positioning for oil-weighted growth .

What Went Wrong

  • EPS and net income down sequentially: basic EPS fell to $0.47 from $0.69 in Q3; net income declined by $7.9M QoQ; depletion per Boe rose to $5.25 vs $2.88 in Q4 2023, reflecting asset mix and acquisitions .
  • Free cash flow lower YoY: Q4 FCF was $13.16M vs $25.53M in Q4 2023, given higher investing cadence and acquisition/portfolio transition .
  • Macro sensitivity remains: while hedges were added, management noted backwardation in the 2025 gas curve and the need for stronger, durable prices to expand reactivations and legacy gas-weighted development .

Financial Results

MetricQ4 2023Q3 2024Q4 2024
Oil, Natural Gas & NGL Revenues ($USD Millions)$33.93 $30.06 $38.97
Basic EPS ($)$0.05 $0.69 $0.47
Adjusted EPS ($)$0.35 $0.19 $0.34
Adjusted EBITDA ($USD Millions)$19.46 $17.74 $24.07
Net Cash from Operating Activities ($USD Millions)$26.22 $20.85 $25.99
Free Cash Flow ($USD Millions)$25.53 $10.86 $13.16
LOE per Boe ($)$6.73 $5.82 $6.43
Adjusted G&A per Boe ($)$1.49 $1.02 $1.39

KPIs and price realization

KPIQ4 2023Q3 2024Q4 2024
Production (MBoe)1,473 1,563 1,754
Daily Production (MBoed)16.0 17.0 19.1
Oil % of Production16% 15% 17%
Realized Oil Price ($/bbl)$77.53 $73.07 $71.44
Realized Gas Price ($/Mcf)$1.50 $0.92 $1.47
Realized NGL Price ($/bbl)$21.05 $16.25 $18.19
Realized Price per Boe ($)$23.03 $19.23 $22.22

Vs Estimates

  • Wall Street consensus (S&P Global) was unavailable at time of analysis due to provider limit. We attempted to fetch Q4 2024 EPS and revenue consensus; values could not be retrieved. Estimates will be updated when accessible (S&P Global data unavailable at time of request).

Segment breakdown

  • SD does not report multiple operating segments in the quarter; results are presented for consolidated E&P operations .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Oil (MMBbls)FY 2025N/A1.0–1.4 Initiated
NGLs (MMBbls)FY 2025N/A2.0–2.3 Initiated
Natural Gas (Bcf)FY 2025N/A17.5–20.5 Initiated
Total Production (MMBoe)FY 2025N/A5.9–7.1 Initiated
Drilling & Completions Capex ($M)FY 2025N/A$47–$63 Initiated
Workovers/Optimization/Leasehold Capex ($M)FY 2025N/A$19–$22 Initiated
Total Capex ($M)FY 2025N/A$66–$85 Initiated
LOE ($M)FY 2025N/A$42–$50 Initiated
Adjusted G&A ($M)FY 2025N/A$10–$12 Initiated
Prod & Ad Valorem Taxes (% of Revenue)FY 2025N/A6%–7% Initiated
Differentials (Oil % of WTI)FY 2025N/A97%–98% Initiated
DividendOngoingPrior $0.11/shareDeclared $0.11/share (paid Mar 31, 2025) Maintained

Earnings Call Themes & Trends

TopicQ-2 (Q2 2024)Q-1 (Q3 2024)Current Period (Q4 2024)Trend
Capital allocation & reinvestmentDefensive stance amid low gas prices; focus on optimization, small M&A; dividend maintained Acquisition of Cherokee assets; September production up; EBITDA support from oily PDP One‑rig Cherokee program; target reinvestment 55–80% in 2025, ~50%+ in 2026; maintain capital returns Pivot from defensive to measured development; oil-weighted growth rising
Cost discipline (LOE/G&A)LOE $6.41/Boe; Adjusted G&A $1.85/Boe; organization efficiency emphasized LOE $5.82/Boe; Adjusted G&A $1.02/Boe LOE $6.43/Boe; Adjusted G&A $1.39/Boe; reiterated cost discipline Sustained low overhead; LOE stable despite higher activity
Commodity hedging & macroMinimal hedges; upside exposure retained Macro updates; more liquids, acquisition-driven mix Added gas/ethane hedges (e.g., gas collars $4/$8.20); ~60% of PDP gas hedged; upside preserved Introduced risk-managed hedging as spend increases
Cherokee play executionPSA announced; DSU framework in Ellis/Roger Mills; plan to initiate drilling Closed acquisition; DUC completions underway; initial IP ~1,000 Boe/d (~70% oil) Operated DUCs below historical costs; plan 8 drilled, 6 completed; low breakevens (~$35 WTI) Execution advancing; oilier, higher-productivity trajectory
ESG & infrastructureNo routine flaring; 95% water by pipeline ESG reiterated; infrastructure scale No routine flaring; >90% water by pipeline; SCADA & operations center highlighted Consistent ESG narrative supporting operating efficiency

Management Commentary

  • “Despite headwinds from natural gas prices last year, the company generated adjusted EBITDA of $24 million in the fourth quarter and $69 million for the year… cash at year‑end was just under $100 million… we paid $72 million in dividends in 2024” (CFO) .
  • “We successfully completed and initiated production from the company’s first operated wells in the Cherokee Play… DUCs achieving costs below historical industry average… we anticipate growing oilier production volumes further” (CEO) .
  • “We plan to drill 8 operated Cherokee wells… complete 6… gross well costs $9–$11 million… breakevens in high‑graded areas down to ~$35 WTI” (COO) .
  • “Our substantial owned and integrated infrastructure helps derisk individual well profitability… down to roughly $40 WTI and $2 Henry Hub” (CEO) .

Q&A Highlights

  • Path to high end of guidance: management would like to see gas stabilize near $5 for ~18 months and WTI solidly >$70; upside from better‑than‑expected results and quick‑to‑deploy reactivations (inventory ready) .
  • Infrastructure and potential direct energy deals: SD sells to large purchasers with access to markets; direct tailgate-to-engine use is impractical given processing needs; indirect benefits possible via counterparties .
  • Capex step-up: 2025 midpoint capex ~3x 2024 due to acquired high-graded undeveloped projects with low breakevens; reinvestment targeted at 55–80% in 2025 and 50%+ in 2026, while maintaining dividends .
  • 2026 production trajectory: two 2025 completions carry into 2026, providing early-year volume without new drilling; growth contingent on returns, not “growth for growth’s sake” .
  • Hedging update: added collars with $4 floor/$8.20 ceiling; just under ~60% of PDP gas volume hedged; no hedging against anticipated production from yet‑to‑be drilled wells .

Estimates Context

  • Analyst consensus for Q4 2024 EPS and revenue via S&P Global was unavailable at the time of analysis due to provider limits; we attempted retrieval but could not access the data. As a result, we cannot quantify beats/misses versus Street for Q4. We will update when S&P Global consensus becomes accessible.

Where estimates may need to adjust:

  • Cherokee development and improved realized gas/NGL pricing versus Q3 suggest upward bias to oil‑weighted volume/mix and cash flows as wells come online in H2 2025; hedges secure a portion of cash flows and reduce downside estimate risk .

Key Takeaways for Investors

  • Volume inflection with disciplined costs: sequential production and revenue growth with LOE and Adjusted G&A well‑controlled; Adjusted EBITDA up QoQ to $24.1M .
  • Oil‑weighted growth optionality: Cherokee drilling program (8/6) at ~$35 WTI breakevens improves portfolio mix; most production impact in H2 2025 and early 2026 .
  • Balance sheet strength and capital returns: $99.5M cash, no debt, dividend maintained at $0.11/share; NOLs ($1.6B gross) shield cash flows from federal taxes, enhancing FCF durability .
  • Hedging prudence: newly added gas and ethane hedges secure cash flows (~60% PDP gas), balancing upside exposure with risk management as development spend rises .
  • Macro leverage: higher Henry Hub and constructive WTI would catalyze reactivations and potentially legacy development; backwardation post‑2025 tempers gas enthusiasm near term .
  • Watch cost trends and depletion: rising depletion per Boe reflects asset mix/acquisitions; monitor Q1–Q2 WELL costs ($9–$11M gross) and realized pricing impacts on margins .
  • Near‑term trading implications: catalysts include initial operated Cherokee well results, hedging disclosures, and confirmation of H2 2025 ramp; any sign of sustained $5 gas/$70+ oil likely supports guidance upside and sentiment .