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NORTHERN OIL & GAS, INC. (NOG)·Q3 2025 Earnings Summary

Executive Summary

  • Q3 2025 delivered mixed results: Adjusted EPS of $1.03 beat consensus $0.87 and Adjusted EBITDA of $387.1M was above consensus $356.8M, but revenue was below S&P Global consensus due to commodity mix and definitional differences; GAAP net loss of $129.1M was driven by a non-cash impairment of $318.7M . EPS/EBITDA estimates from S&P Global; see Estimates Context section for details.*
  • Production was 131,054 Boe/d (55% oil), down 2% q/q on expected TIL timing and up 8% y/y; management raised full-year production guidance (132,500–134,000 Boe/d; oil 75,000–76,500 Bbl/d) and tightened capex ($950–$1,025M) .
  • Cost and pricing tailwinds: oil differentials improved to $3.89/bbl vs WTI and LOE/boe eased sequentially; hedges protected cash flows, with $55.4M realized hedge gains in Q3 .
  • Balance sheet actions are a catalyst: issued $725M 2033 notes at 7.875%, retired ~97% of 2028 notes, and extended/cheaper revolver (-60 bps), pushing weighted average maturity to ~6 years and preserving >$1.1B revolver availability .

What Went Well and What Went Wrong

What Went Well

  • Raised FY2025 production guidance and tightened capex; Q3 production outperformed internal expectations across basins, with record Appalachia volumes and rising gas momentum .
  • Improved realized pricing/differentials and operational efficiencies: oil differential improved to $3.89/bbl; normalized AFE costs fell to ~$806 per foot from $841 in Q2; LOE/boe down marginally q/q .
  • Strategic capital and BD execution: $98.3M Uinta royalty/minerals bolt-on increasing effective NRI from ~80% to ~87%; robust ground game (22 transactions, +2,500 net acres, +5.8 net wells) .
  • Quote: “You’d be hard-pressed to find a better hedge company than ours… [hedging] protects our business and allows us to continue to take the offensive through trough periods.” — CEO Nick O’Grady .

What Went Wrong

  • GAAP loss due to non-cash impairment: $318.7M full-cost “ceiling test” impairment tied to lower average oil prices; net loss of $129.1M (−$1.33 diluted EPS) .
  • Sequential oil volume decline and fewer net wells added: oil at 72,348 bbl/d (−6% q/q) and 16.5 net wells added (vs 20.8 in Q2), with Q3 the low point for TILs .
  • Continued expense pressure in parts of the cost stack (workovers), prompting LOE guidance increase; production taxes guidance lowered reflecting mix .

Financial Results

Multi-period comparison (Q1 → Q2 → Q3 2025)

MetricQ1 2025Q2 2025Q3 2025
Oil & Gas Sales ($USD Millions)$576.952 $574.369 $482.243
Total Revenues ($USD Millions)$602.098 $706.809 $556.637
GAAP Diluted EPS ($)$1.39 $1.00 $(1.33)
Adjusted Diluted EPS ($)$1.33 $1.37 $1.03
Adjusted EBITDA ($USD Millions)$434.735 $440.416 $387.131
Free Cash Flow ($USD Millions)$135.693 $126.178 $118.894
Production (Boe/d)134,959 134,094 131,054
Oil Mix (%)58% 57% 55%
Realized Price Incl. Settled Derivatives ($/Boe)$48.49 $45.86 $45.08
LOE ($/Boe)$9.39 $9.95 $9.81

Margins vs prior year and sequential

MetricQ3 2024Q2 2025Q3 2025
EBITDA Margin %123.70%*97.82%*85.80%*
Net Income Margin %59.59%*18.36%*−28.23%*
Values retrieved from S&P Global.*

Q3 2025 YoY detail (selected)

MetricQ3 2024Q3 2025Change
Production (Boe/d)121,815 131,054 +8%
Oil (Bbl/d)70,913 72,348 +2%
Gas (Mcf/d)305,413 352,250 +15%
Realized Price incl. derivatives ($/Boe)$48.47 $45.08 −7%

Segment/KPI highlights (Q3 2025)

KPIQ3 2025
Permian Capex Allocation (%)49%
Williston Capex Allocation (%)25%
Appalachian Capex Allocation (%)21%
Uinta Capex Allocation (%)5%
Net wells added to production16.5
Liquidity (cash + revolver availability)$1.2B (>$1.1B RCF + $31.6M cash)
Realized hedge gains (Q3)$55.390M
Commodity derivatives gain (net)$70.769M
Non-cash impairment$318.674M

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Annual Production (Boe/d)FY2025130,000–133,000 132,500–134,000 Raised
Annual Oil Production (Bbl/d)FY202574,000–76,000 75,000–76,500 Raised
Total Capex ($MM)FY2025$925–$1,050 $950–$1,025 Tightened/Higher mid
Net Oil Wells TILFY202573.0–76.0 71.0–74.0 Lowered
Net Total Wells TILFY202583.0–85.0 80.0–83.0 Lowered
Net Wells SpudFY202575.0–85.0 75.0–85.0 Maintained
Production Expenses ($/Boe)FY2025$9.25–$9.60 $9.40–$9.75 Raised
Production Taxes (% of Oil & Gas Sales)FY20257.5%–8.5% 7.0%–8.0% Lowered
Avg Differential to WTI ($/Bbl)FY2025($5.25)–($5.75) ($5.25)–($5.75) Maintained
Gas Realization vs Henry Hub (%)FY202585%–90% 85%–90% Maintained
DD&A ($/Boe)FY2025$16.00–$17.00 $16.00–$17.00 Maintained
G&A Non-Cash ($/Boe)FY2025$0.25–$0.30 $0.25–$0.30 Maintained
G&A Cash ($/Boe)FY2025$0.85–$0.90 $0.85–$0.90 Maintained
Quarterly Dividend/ShareQ3–Q4 2025$0.45 (paid Q3) $0.45 (declared for Dec 30; payable Jan 30) Maintained

Earnings Call Themes & Trends

TopicPrevious Mentions (Q2 2025)Previous Mentions (Q1 2025)Current Period (Q3 2025)Trend
Capital discipline & returnsReduced 2025 capex range; focus on returns vs growth Reaffirmed guidance; flexible allocation per commodity backdrop Emphasized return-driven allocation; cautious drilling; preserve inventory Consistent discipline
Hedging strategyStrong hedge gains; portfolio expanded Robust hedge book insulating cash flows Active hedge management; “best hedge company”; realized gains $55.4M Strengthening
Gas rampRecord Appalachia; gas momentum Record Appalachia; gas realizations 100% HH Record gas volumes; expect material gas growth in 2026 Accelerating
Operational efficiency (AFEs, lateral length)Normalized AFE ~$841/ft; service cost pressures Per-foot normalized AFEs down; D&C list efficiencies AFEs ~$806/ft; longer laterals across basins; vendor consolidation may reduce costs Improving
Balance sheet & liquidityRe-opened converts; >$1.1B liquidity Liquidity >$0.9B $725M 2033 notes; 2028s retired; RBL to 2030, −60 bps; ~6-year WAM Strengthened
M&A/ground game22 transactions; Upton County deal 7 ground game deals Uinta minerals/royalty; 22 transactions; screening $8B+ pipeline; flexible deal structures Robust pipeline
Regulatory/legal (DAPL risk disclosure)DAPL dispute referenced in risk section DAPL risk in risk section Risk factors reiterated in release Ongoing disclosure

Management Commentary

  • Strategy and capital: “Our portfolio and strategy remain resilient… we seek and evaluate value-creating, accretive transactions… our existing assets are delivering better than expected, capital efficient performance.” — CEO Nick O’Grady .
  • Risk management: “You’d be hard-pressed to find a better hedge company than ours. This actively managed hedge program allows us to better navigate the typical commodity cycle.” — CEO Nick O’Grady .
  • Operations: “Assets continue to outperform… increased annual production guidance while tightening CapEx… longer laterals and downward pressure on service costs have been encouraging.” — President Adam Dirlam .
  • Financials: “Adjusted EBITDA was $387.1M… we increased annual production guidance… amended RCF reduced pricing by 60 bps; extended tenor to 2030… no major maturities until 2029.” — CFO Chad Allen .

Q&A Highlights

  • 2026 outlook and activity: Management sees stable activity entering 2026; material gas growth expected; return-driven capital plans could flex with commodity changes .
  • Q4 TIL timing and ramp: 23–25 net wells expected in Q4; many late-Q3 tills drive Q4 volumes; sequential growth implied in annual guide .
  • M&A funding approach: Broad multi-basin opportunity set ($100M–$1B+ deals); financing only if beneficial; abundant liquidity at advantaged cost plus multiple avenues .
  • Lateral length/capital efficiency: Across basins, longer laterals (14–15k ft in Williston) lowering normalized AFE $/ft and flattening declines; cautious on decline assumptions until more data .
  • Cost trajectory and vendor strategy: Cost relief likely via vendor consolidation and contract renewals; broader inflation still present; LOE pressures from workovers .
  • Wells-in-process dynamics: Stable gross activity; net levels can vary with working interest; completion timing drives near-term production .

Estimates Context

How results compared to Wall Street consensus (S&P Global):

MetricConsensus (Q3 2025)Actual (Q3 2025)Surprise
Primary EPS ($)0.871*1.03*+0.16*
Revenue ($USD Millions)524.19*457.18*−67.01*
EBITDA ($USD Millions)356.78*392.26*+35.48*
Target Price (USD)33.50*33.50*—*
Values retrieved from S&P Global.*

Notes:

  • Company-reported Adjusted EBITDA was $387.1M vs S&P Global “EBITDA actual” 392.3M, reflecting differing definitions (adjusted vs unadjusted) .
  • Company-reported total revenues were $556.6M and oil & gas sales $482.2M; S&P Global “Revenue actual” differs due to classification/derivative treatment. Consensus comparisons anchored to S&P Global convention .*

Where estimates may need to adjust:

  • Raised production guidance and improved differentials likely support upward revisions to Q4 volumes/EBITDA; LOE guidance raised and oil mix lower could temper margin expectations .
  • Non-cash impairment has no cash impact; should not alter forward EPS/FCF trajectories, but highlights sensitivity to average prices under full-cost accounting .

Key Takeaways for Investors

  • Adjusted EPS beat and Adjusted EBITDA outperformed consensus, driven by strong multi-basin operations and robust hedge gains; GAAP loss was non-cash impairment-related and not reflective of ongoing cash generation .
  • Narrative shift to gas: record Appalachia volumes and guidance imply stronger gas contribution into 2026; watch gas price dynamics and realizations vs Henry Hub .
  • Cost and efficiency trajectory favorable: longer laterals and vendor consolidation should continue to lower normalized AFE $/ft; LOE pressures from workovers persist but trend is manageable .
  • Balance sheet optionality enhanced: terming out debt, retiring 2028s, and cheaper RCF broaden capacity to pursue countercyclical M&A without near-term maturity risk .
  • Ground game and minerals strategy add durable, low-break-even inventory; Uinta royalty/minerals deal increases effective NRI and lowers basin break-evens .
  • Near-term trading lens: focus on Q4 TIL cadence (23–25 net wells) and exit-rate momentum; production mix/differentials and hedge book should stabilize EBITDA/FCF through year-end .
  • Medium-term thesis: diversified non-op model, disciplined capital allocation, and active hedging support resilient FCF across cycles; multi-basin M&A pipeline is a lever for accretive growth .