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RANGE RESOURCES CORP (RRC)·Q1 2025 Earnings Summary

Executive Summary

  • Q1 2025 was a strong execution quarter: adjusted diluted EPS of $0.96 vs consensus $0.93 and revenue of $0.85B vs consensus $0.78B; GAAP diluted EPS was $0.40 and GAAP total revenues and other income were $690.6M. The beat was driven by higher realized natural gas and NGL prices and disciplined costs, despite a $159M non-cash derivative mark-to-market loss . EPS/revenue consensus from S&P Global showed a beat in both metrics for Q1 2025; values retrieved from S&P Global.*
  • Realized prices after hedges averaged $4.02/mcfe (gas $3.64/mcf; NGL $27.75/bbl; oil $61.72/bbl) with a NGL premium of +$1.05/bbl to Mont Belvieu and an improved gas basis differential of ($0.15)/mcf to NYMEX .
  • Management raised full-year 2025 NGL differential guidance to MB +$0.25 to +$1.25 (from +$0.00 to +$1.25 previously); capital ($650–$690M), production (~2.2 Bcfe/d), and per-unit expense guidance were maintained .
  • Capital allocation remained balanced: $183M free cash flow enabled $68M buybacks (1.83M shares at ~$36.97) and $22M dividends, while net debt fell by ~$42M to $1.36B; CFO reiterated the May 2025 bond maturity will be addressed with cash on hand and a small revolver draw .

What Went Well and What Went Wrong

What Went Well

  • Higher realized pricing and NGL premium: “First quarter 2025 natural gas, NGLs and oil price realizations…averaged $4.02 per mcfe…pre-hedge NGL price…$27.79 per barrel, approximately $1.05 above Mont Belvieu” .
  • Operational efficiency and record drilling: CEO highlighted “new program drilling record by averaging 5,961 feet per day” and consistent completions efficiency with an e-frac fleet, underpinning low capital intensity and repeatable well performance .
  • Shareholder returns while de-leveraging: $68M buybacks, $22M dividends, and net debt reduced by ~$42M in the quarter; free cash flow was $183M supporting both returns and balance sheet strength .

What Went Wrong

  • Derivative headwind: Q1 included a $159M mark-to-market derivative loss due to higher commodity prices, reducing GAAP profitability (GAAP diluted EPS $0.40) .
  • Unit cash costs up modestly YoY: total cash unit costs rose to $2.01/mcfe from $1.96/mcfe (+3%), primarily on transportation/gathering/processing/compression (TGPC) expenses; DD&A also increased slightly .
  • Near-term production dip: management flagged Q2 production “slightly down” due to scheduled processing maintenance before rising in H2 2025, a potential near-term headwind to volumes .

Financial Results

Revenue and EPS vs Prior Periods and Estimates

MetricQ1 2024Q4 2024Q1 2025
Revenue (S&P Global definition, $USD)$602.2M*$680.4M*$851.2M*
Revenue Consensus Mean ($USD)$708.6M*$676.5M*$784.1M*
Adjusted Diluted EPS ($USD)$0.69 $0.68 $0.96
Primary EPS Consensus Mean ($USD)$0.590*$0.602*$0.928*

Values retrieved from S&P Global.*

GAAP P&L and Cash Flow (reported)

MetricQ1 2024Q4 2024Q1 2025
Total Revenues and Other Income ($USD)$645.5M $626.4M $690.6M
Net Income ($USD)$92.1M $94.8M $97.1M
Diluted EPS ($USD)$0.38 $0.39 $0.40
Net Cash Provided by Operating Activities ($USD)$331.9M $217.9M $330.1M
Cash Flow from Ops before WC (non-GAAP, $USD)$307.9M $311.7M $397.4M

Product Mix and Realized Pricing

MetricQ3 2024Q4 2024Q1 2025
Net Production per Day – Gas (mcf)1,502,106 1,505,140 1,510,705
Net Production per Day – NGL (bbl)111,465 111,199 110,222
Net Production per Day – Oil (bbl)5,594 5,028 4,706
Gas Eq Production (mcfe/d)2,204,460 2,202,500 2,200,276
Realized Price after Hedges – Gas ($/mcf)$2.48 $2.90 $3.64
Realized Price after Hedges – NGL ($/bbl)$26.09 $26.47 $27.75
Realized Price after Hedges – Oil ($/bbl)$69.73 $70.66 $61.72
Gas Eq Realized ($/mcfe)$3.18 $3.48 $4.02
Differentials: Gas to NYMEX ($/mcf)($0.50) ($0.44) ($0.15)
Differentials: NGL vs MB ($/bbl)+$4.10 +$1.96 +$1.05
Differentials: Oil vs WTI ($/bbl)($11.55) ($10.64) ($10.28)

Unit Costs per mcfe

Metric ($/mcfe)Q3 2024Q4 2024Q1 2025
Direct Operating$0.12 $0.12 $0.13
TGPC$1.51 $1.48 $1.55
Taxes other than income$0.03 $0.03 $0.04
G&A$0.16 $0.18 $0.16
Interest$0.14 $0.14 $0.14
Total Cash Unit Costs$1.96 $1.94 $2.01
DD&A$0.45 $0.46 $0.46
Total Unit Costs + DD&A$2.41 $2.40 $2.46

KPIs

KPIQ4 2024Q1 2025
Cash Margin per mcfe ($/mcfe)$1.55 $2.02
Net Debt ($USD)$1.40B $1.36B
Share Repurchases0.65M shares ($32.50 avg) 1.83M shares ($36.97 avg)
Capital Spending ($USD)$124M D&C; $29M other $147M all-in (incl. $130M D&C)
Production (Bcfe/d)2.20 2.20

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Natural Gas Differential to NYMEXFY 2025($0.40) to ($0.48) ($0.40) to ($0.48) Maintained
NGL Differential vs MBFY 2025+$0.00 to +$1.25 +$0.25 to +$1.25 Raised bottom end
Oil/Condensate Differential vs WTIFY 2025($10) to ($15) ($10) to ($15) Maintained
All-in CapitalFY 2025$650M–$690M $650M–$690M Maintained
ProductionFY 2025~2.2 Bcfe/d ~2.2 Bcfe/d; Q2 slightly down on maintenance Maintained; near-term Q2 dip
Liquids MixFY 2025>30% >30% Maintained
Per-Unit Expense GuidanceFY 2025DO $0.12–$0.14; TGPC $1.50–$1.55; Taxes $0.03–$0.04; G&A $0.17–$0.19; Interest $0.12–$0.13; DD&A $0.45–$0.46; Brokered gas $8–$12M Same ranges Maintained
DividendQ1 2025$0.08 per share (implied prior)$0.09 per share (12.5% increase) Raised

Earnings Call Themes & Trends

TopicQ3 2024 (Prev Mentions)Q4 2024 (Prev Mentions)Q1 2025 (Current)Trend
In-basin demand & data centersFocus on premium markets and exports; no specific in-basin data center mention Secured 2026 processing (300 Mmcf/d), gas transport (250 Mmcf/d), and NGL export capacity; 3-year outlook to 2.6 Bcfe/d Collaboration with Liberty Energy/Imperial Land to supply planned power facility in PA; Homer City repurposing; PJM demand could add ~4 Bcf/d by 2030; site proximity reduces infrastructure needs Increasing visibility; near-/mid-term projects
Pricing & hedgingBasis hedge fair value disclosure Differential expectations for 2025 reiterated 2025 ~35% hedged; 2026 ~15% (up to ~25% via swaptions) with >$4 floors; preserve upside Opportunistic with insurance floors
Operations & costsTGPC higher YoY; stable unit costs Maintenance capital improved ~$50M on strong wells and optimization Record drilling efficiency; e-frac fleet contract extended; expect consistent well costs through 2025–26 Efficiency improving; cost stability
Tariffs/macro (LPG)NGL premium strong NGL premium guidance into 2025 LPG tariff risk seen as manageable via diversification; ~80% LPG exported to Europe; East Coast terminal advantage Resilient due to market positioning
Balance sheet & capital returnsNote repurchases of notes/shares Share repurchases and net debt decline $68M buybacks; CFO: May maturity via cash + small revolver; tilt returns toward buybacks on dislocations Strengthening; flexible allocation

Management Commentary

  • “Range is off to a great start in 2025 with efficient operations, consistent well performance and strong free cash flow.” – CEO Dennis Degner .
  • “During the quarter, Range set a new program drilling record by averaging 5,961 feet per day…while staying 98% within our…landing target window.” – CEO Dennis Degner .
  • “Those capital allocation decisions were made possible by $183 million in free cash flow…we invested $68 million in share repurchases…paid $22 million in dividends and reduced net debt by $42 million.” – CFO Mark Scucchi .
  • “We expect production to be slightly down in the second quarter as we undergo scheduled processing maintenance. Following Q2, we expect production to increase in the second half of the year.” – CEO Dennis Degner .
  • “We are collaborating with Liberty Energy and Imperial Land Corporation to supply natural gas to a planned…power generation facility…a catalyst for attracting data centers.” – Company release .

Q&A Highlights

  • Tariffs/LPG exposure: Management emphasized diversified transport/pricing, East Coast export advantage, and minimal China exposure; ~80% of LPG currently goes to Europe, supporting premium NGL realizations and improved guidance .
  • In-basin demand & basis: Liberty/Homer City projects could consume up to ~90–100 mmcf/d; expectation that growing in-basin demand strengthens basis over time; Constitution pipeline visibility uncertain, but incremental brownfield expansions are positive signs .
  • Hedging outlook: Strategy to insure fixed costs and preserve upside; 2026 hedging ~15–25% with attractive floors; 2025 ~35% hedged .
  • Debt maturity: CFO to address May bond maturity via cash on hand and a small revolver draw; ongoing balance sheet optimization .
  • Capital returns: Greater buybacks during market dislocation; total 28.6M shares retired historically; expect continued tilt toward returns while meeting balance sheet goals .

Estimates Context

MetricQ1 2024Q4 2024Q1 2025
Revenue Actual ($USD)$602.2M*$680.4M*$851.2M*
Revenue Consensus Mean ($USD)$708.6M*$676.5M*$784.1M*
Adjusted EPS Actual ($USD)$0.69 $0.68 $0.96
Primary EPS Consensus Mean ($USD)$0.590*$0.602*$0.928*
  • Q1 2025: revenue and adjusted EPS both beat consensus; prior quarters also show EPS beats (Q4 2024 $0.68 vs $0.60; Q1 2024 $0.69 vs $0.59). Values retrieved from S&P Global.*

Key Takeaways for Investors

  • Pricing tailwinds and basis improvement drove a material beat: realized gas $3.64/mcf and NGL premium +$1.05/bbl underpinned $0.96 adjusted EPS vs $0.93 consensus and $0.85B revenue vs $0.78B ; values retrieved from S&P Global.*
  • Guidance quality improved: NGL differential raised (MB +$0.25 to +$1.25), while capital/production and per-unit cost guidance held; near-term Q2 maintenance dip is transitory with H2 volume recovery .
  • Operational cadence and efficiency are strategic: record drilling rates and e-frac efficiency support low reinvestment and options to modularly add “wedges” of growth into 2026–27 as demand materializes .
  • Capital returns likely continue: opportunistic buybacks on market dislocations, sustained dividend ($0.09/qtr), and strengthened balance sheet (net debt ~$1.36B) create flexibility .
  • Macro set-up constructive: normalized storage, accelerating LNG offtake, and in-basin demand projects (Liberty, Homer City) support tighter markets and favorable basis into 2026–27, benefiting Appalachia cost leaders .
  • Risk monitor: derivative fair value volatility can swing GAAP results; TGPC costs remain a watch item as cash unit costs rose modestly; keep an eye on regulatory timelines for in-basin projects .
  • Trading lens: Near-term catalyst is H2 production ramp and continued NGL premium realization; the maintained capex and improved price guidance plus buyback activity are supportive on pullbacks, while Q2 maintenance-driven volume dip is well telegraphed .