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AR

ANTERO RESOURCES Corp (AR)·Q3 2025 Earnings Summary

Executive Summary

  • Q3 2025 was operationally strong (record lateral length, completions productivity) but financially mixed: revenue was $1.214B, net income $76M (diluted EPS $0.24) and Adjusted EBITDAX $318M, with FCF of $91M .
  • Versus S&P Global consensus, EPS ($0.155 vs $0.247)* and revenue ($1.169B vs $1.180B)* modestly missed, while EBITDA ($333M vs $322M)* beat; EBITDA execution offset lower liquids realizations. Values retrieved from S&P Global.
  • Guidance: Q4 production raised to 3.50–3.525 Bcfe/d; full-year production tracking to the high end of 3.40–3.45 Bcfe/d; 2025 land capex increased to $125–$150M; full-year C3+ NGL premium lowered to $0.75–$1.00/bbl (Q4 premium $1.25–$1.75/bbl) .
  • Strategic actions: ~$260M of bolt-on acquisitions (75–100 MMcfe/d, +10 net locations), a spot rig added for a dry gas proof-of-concept pad (turn-in-line 1Q26), and 1.5M shares repurchased for ~$51M; expanded hedging across Q4-25 to 2027 .

What Went Well and What Went Wrong

What Went Well

  • Operational outperformance: record-long lateral (>22,000 ft), record 349 continuous pumping hours, and 14.5 completion stages/day; 16 wells turned in-line averaged 16,130 ft laterals and early rates of ~30 MMcfe/d per well (60-day sample) .
  • Marketing/realizations resilience: realized gas price premium to benchmark (+$0.05/Mcf) and weighted average realized $3.59/Mcfe pre-hedge (+$0.52/Mcfe vs NYMEX), supporting margins despite softer liquids .
  • Management discipline and positioning: accretive bolt-ons funded with FCF, debt paydown, buybacks; reloaded hedges to lock 2026 base FCF yields while retaining upside; management sees a visible step-change in demand from LNG and data centers .

“Antero’s third quarter results yet again raised the bar for operational performance…we completed several bolt-on acquisitions…increase Antero’s production and inventory and enhance our ability to capitalize on the significant demand increases expected for natural gas.” — CEO Michael Kennedy .

What Went Wrong

  • Estimate optics: GAAP “Primary EPS” and revenue slightly missed S&P Global consensus despite an EBITDA beat (see Estimates Context), driven by weaker liquids pricing q/q and mix . Values retrieved from S&P Global.
  • Liquids headwinds: C3+ NGL realized prices fell sequentially ($36.60/bbl in Q3 vs $37.92/bbl in Q2), and oil prices were lower ($50.65/bbl vs $50.15/bbl Q2) contributing to revenue down q/q ($1.214B vs $1.297B) .
  • Guidance mix shift: Full-year C3+ NGL premium to Mont Belvieu reduced to $0.75–$1.00/bbl (from $1.00–$2.00), reflecting tighter dock premia and macro softness, partly offset by better domestic pricing exposure .

Financial Results

P&L and Cash Flow (oldest → newest)

MetricQ3 2024Q1 2025Q2 2025Q3 2025
Revenue ($USD Billions)$1.056 $1.353 $1.297 $1.214
Diluted EPS ($)$(0.11) $0.66 $0.50 $0.24
Adjusted EBITDAX ($USD Millions)$186.9 $549.4 $379.5 $318.2
Net Cash from Ops ($USD Millions)$166.2 $457.7 $492.4 $310.1
Free Cash Flow ($USD Millions)$(23.2) $235.6 (FCF); $336.6 (FCF ex-WC) $262.4 $90.9

Notes: Where shown, FCF before changes in working capital is provided for context .

Margins (GAAP/Non-GAAP as defined by S&P Global) — for context

MetricQ3 2024Q1 2025Q2 2025Q3 2025
Net Income Margin %-3.43%*14.66%*12.65%*6.52%*
EBITDA Margin %17.07%*32.61%*33.43%*28.48%*
  • Values retrieved from S&P Global.

Revenue Mix and Key KPIs

Item (Q3)20242025
Natural Gas Sales ($MM)$425.8 $630.9
NGL Sales ($MM)$504.2 $470.4
Oil Sales ($MM)$52.7 $31.4
Total Revenue ($MM)$1,055.9 $1,214.0
Combined Production (Bcfe)313 315
Daily Combined (MMcfe/d)3,406 3,429
Realized Gas Price ($/Mcf, pre-hedge)$2.13 $3.12
Realized C3+ NGL ($/bbl, pre-hedge)$41.30 $36.60
All-in Cash Expense ($/Mcfe)$2.42 $2.44
Net Marketing Expense ($/Mcfe)$0.05 $0.05

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Net Daily Production (Bcfe/d)Q4 2025—3.50 – 3.525 New
C3+ NGL Premium vs Mont Belvieu ($/bbl)Q4 2025—$1.25 – $1.75 New
Land Capital ($MM)Q4 2025—$25 – $50 New
Production (Bcfe/d)FY 20253.40 – 3.45 (raised in Q2) High end of 3.40 – 3.45 targeted Maintained at high end
C3+ NGL Premium vs Mont Belvieu ($/bbl)FY 2025$1.00 – $2.00 $0.75 – $1.00 Lowered
Land Capital ($MM)FY 2025$75 – $100 (implied prior; new is +$50) $125 – $150 Raised

Note: Q2 2025 also reduced FY25 D&C capex to $650–$675M; Q3 stated any items not discussed remain unchanged .

Earnings Call Themes & Trends

TopicPrevious Mentions (Q1 & Q2 2025)Current Period (Q3 2025)Trend
LNG & Gulf Coast basisQ1: FT to LNG corridor drove premium realizations; LPG dock premia contracted for 2025 . Q2: Demand to grow >25% by 2030 with LNG and AI data centers .Plaquemines ramp driving TGP 500L premium (~$0.80 winter); next wave (Golden Pass, Corpus 3, CP2) adds ~10 Bcf/d over 4 months; AR sells 75% along LNG fairway .Strengthening demand pull and basis premiums
AI/data centers & regional powerQ2: AI data centers cited as a demand driver by decade-end .Proof-of-concept dry gas pad in Harrison County to serve local demand; ability to quickly scale ~1,000 gross dry gas locations .From narrative to execution (proof-of-concept)
Hedging & FCF stabilityQ1: Locked LPG premia; 2026 collars added . Q2: 2026 wide collars (floor $3.14, ceiling $6.31) .Added 4Q25, 2026–27 swaps; 2026 collars re-struck (floor $3.22, ceiling $5.83); hedges target 6–9% base FCF yield at $2–$3 gas .More downside protection, preserved upside
Leasing/bolt-onsQ1 & Q2: Ongoing organic leasing and opportunistic buybacks/debt reduction .~$260M bolt-ons (75–100 MMcfe/d; +10 locations); +79 locations YTD organically; land capex +$50M .Accelerating inventory depth in core
Liquids macroQ1: Firm LPG export pricing; premium to Mont Belvieu .Expect C3+ supply growth to slow; export capacity debottlenecking aids Mont Belvieu pricing in 2026 .Constructive medium-term setup

Management Commentary

  • Strategic positioning: “We are entering an exciting time…visible step change in demand…increasing US LNG exports combined with a surge in natural gas power generation accelerating from new data centers” — CEO Michael Kennedy .
  • Hedging philosophy: “Hedges have locked in base level free cash flow yields of 6% to 9% at natural gas prices between $2 and $3, while…maintain significant exposure to rising…prices” — CFO Brendan Krueger .
  • Dry gas growth optionality: “We are excited to return to our dry gas acreage…we spud a pad during the fourth quarter of 2025…proof of concept…approximately 1,000 gross dry gas locations…held-by-production” — CEO Michael Kennedy .
  • Capital allocation: “Portfolio approach…debt reduction, share repurchases, and accretive acquisitions…funded entirely with our free cash flow in 2025” — CFO Brendan Krueger .

Q&A Highlights

  • Why start dry gas in Harrison County now? Proof-of-concept for local demand/data centers and to demonstrate deliverability and ramp speed; expected ~50% uplift in productivity vs decade-old wells (toward ~2 Bcf/1,000 ft type) as modern completions are applied .
  • 2026 program and maintenance capital: Targeting maintenance volumes (~3.5 Bcfe/d exit) with potential ~3% maintenance capex uplift due to higher production base; drilling JV remains TBD .
  • Hedging posture: Mix of swaps/collars seen as “prudent,” protecting downside FCF and retaining upside to potentially 20% FCF yields in a stronger tape .
  • M&A and Ohio asset market check: Bolt-ons remain opportunistic/accretive; Ohio process ongoing with high bar; potential proceeds could repay callable debt and/or fund repurchases if valuation arb is attractive .
  • Basis and LNG fairway: AR has ~2.1 Bcf/d southbound FT; end-user demand pull increasing; patience emphasized before locking long-term deals .

Estimates Context

Metric (Q3 2025)ConsensusActualSurprise
Primary EPS ($)0.247*0.155*Miss
Revenue ($USD Billions)1.180*1.169*Miss (≈1%)
EBITDA ($USD Millions)322.4*332.8*Beat (≈3%)

Interpretation: EBITDA outperformance reflects solid gas realizations/premia and cost control, while GAAP EPS lagged on lower liquids pricing and mix vs Q2 and standard below-the-line items (tax/interest/DA), yielding a headline EPS miss despite healthy operating results .

  • Values retrieved from S&P Global.

Why the Beats/Misses

  • EBITDA beat: Realized gas premia (+$0.05/Mcf) and weighted average $3.59/Mcfe pre-hedge (+$0.52/Mcfe vs NYMEX), plus stable all-in cash expense ($2.44/Mcfe), supported operating profitability .
  • EPS/revenue miss: Sequential revenue decline ($1.297B → $1.214B) and lower C3+ prices ($37.92 → $36.60/bbl) weighed on net income per share despite operational execution .

Guidance Sensitivities and Implications

  • Production: Q4 step-up to 3.50–3.525 Bcfe/d incorporates acquisitions and sets a higher maintenance baseline; implies modestly higher maintenance capex (+~3%) per management .
  • Liquids: FY C3+ premium reduced to $0.75–$1.00/bbl; however, AR expects 2026 C3+ fundamentals to improve as supply growth slows and export capacity debottlenecks .
  • Hedging: 2026 swaps/collars and 2027 swaps reduce cash flow volatility, backstopping buybacks/bolt-ons even in $2–$3 gas scenarios .

Key Takeaways for Investors

  • Execution remains best-in-class operationally, with multiple company records and continued capital efficiency, underpinning competitive full-cycle returns .
  • The quarter’s headline EPS miss versus consensus came alongside an EBITDA beat; narrative likely improves into Q4 with higher volumes and protected cash flows via hedges .
  • Accretive bolt-ons and organic leasing deepen core inventory; land capex increase is targeted to expand the core fairway where well performance continues to strengthen .
  • Strategic optionality: re-entry into dry gas provides a lever to monetize regional data center/power demand and LNG fairway opportunities as basis strengthens .
  • Capital return: low absolute leverage, hedged base FCF, and ~$915M of remaining buyback capacity enable counter-cyclical repurchases alongside selective M&A .
  • Watch catalysts: Q4 volume step-up execution, realized price premia into winter, data center/power contracting developments, potential Ohio asset process outcomes, and 2026 capital program color .

Appendix: Additional Detail

Hedging Adds and Levels (as of Oct 29, 2025):

  • 4Q25 swaps: 646 BBtu/d @ $3.70; 2026 swaps: 600 BBtu/d @ $3.82; 2027 swaps: 100 BBtu/d @ $3.93; 2026 collars: 500 BBtu/d floor $3.22, ceiling $5.83 .

Share Repurchases and Capacity:

  • Q3 buybacks: 1.5M shares for ~$51M; YTD: ~4.7M shares for ~$163M; remaining authorization ≈$915M .

Acquisitions:

  • ~$260M bolt-ons (West Virginia core) closed end of Q3; included 75–100 MMcfe/d and +10 net undeveloped locations; minimal Q3 impact .

Production and Realizations (Q3 2025) Highlights:

  • Net production: 3.4 Bcfe/d with liquids 206 MBbl/d; gas 2.195 Bcf/d; realized gas $3.12/Mcf (+$0.05 vs index), C3+ $36.60/bbl (+$0.84 vs index) .

All data points from company filings and earnings materials are cited in-line with [document_id:chunk_idx]. S&P Global consensus/realized estimate comparisons and margin metrics are marked with an asterisk and noted as “Values retrieved from S&P Global.”