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NO

NORTHERN OIL & GAS, INC. (NOG)·Q2 2025 Earnings Summary

Executive Summary

  • Q2 2025 delivered resilient production and strong free cash flow amid lower oil prices: 134,094 Boe/d (+9% YoY), Adjusted EBITDA $440.4M, Free Cash Flow $126.2M; GAAP diluted EPS $1.00 and Adjusted diluted EPS $1.37 .
  • Consensus comparison: Adjusted EPS materially beat S&P Global ($1.37 vs $0.95*) and S&P’s revenue definition slightly exceeded consensus ($542.4M* vs $540.5M*), while company-reported Total Revenues were $706.8M; note definitional differences between S&P “Revenue” and NOG’s “Total Revenues” .
  • Guidance pivot: 2025 CapEx cut by ~$125–$150M; production and oil-volume guidance trimmed; cost/differential assumptions updated, reflecting a returns-based shift toward inorganic opportunities .
  • Catalysts: expected net cash legal settlement of $48.6M in Q3, expanded hedges, and an upsized $200M reopening of 2029 converts paired with a 1.1M-share buyback to bolster liquidity for countercyclical M&A .

What Went Well and What Went Wrong

What Went Well

  • Strong multi-basin execution: Uinta volumes +18.5% QoQ; Appalachian gas volumes set a second straight record, underpinning production resilience at 134,094 Boe/d (+9% YoY) .
  • Robust cash generation and hedging: Free Cash Flow $126.2M; cash from operations $362.1M; realized hedge gains ~$60.9M in Q2; substantial oil/gas hedges in place for H2’25–2026 .
  • Strategic discipline and inorganic pipeline: “Our diverse and scaled platform delivered solid results… with a focus on… backlog of inorganic opportunities” — CEO Nick O’Grady; record Adjusted EBITDA $440.4M (+7% YoY) .

What Went Wrong

  • Cost pressure: LOE rose to $9.95/boe (+6% QoQ) on higher processing and saltwater disposal costs; G&A per boe ticked up to $1.28 .
  • Pricing headwind: Unhedged realized oil price fell to $58.37/bbl (WTI differential $5.31); gas realizations dropped to 82% of Henry Hub on Waha weakness .
  • Non-cash impairment: $115.6M “ceiling test” impairment due to lower average oil prices (no cash-flow impact), and $33.1M legal settlement expense booked in Q2 .

Financial Results

Core P&L and Operating Metrics (Company-reported)

MetricQ4 2024Q1 2025Q2 2025
Total Revenues ($USD Millions)$514.98 $602.10 $706.81
Oil & Gas Sales ($USD Millions)$545.47 $576.95 $574.37
Net Income ($USD Millions)$71.70 $138.98 $99.59
Diluted EPS ($)$0.71 $1.39 $1.00
Adjusted Diluted EPS ($)$1.11 $1.33 $1.37
Adjusted EBITDA ($USD Millions)$406.63 $434.74 $440.42
Avg Daily Production (Boe/d)131,777 134,959 134,094
Oil % of Production59.9% 58% 57%

Price Realizations and Per-Boe Costs

MetricQ2 2024Q1 2025Q2 2025
Unhedged Realized Oil Price ($/bbl)$77.11 $64.92 $58.37
WTI Differential ($/bbl)n/a$5.79 $5.31
Unhedged Realized Gas & NGL ($/Mcf)$2.47 $3.86 $2.89
Production Expenses ($/boe)$8.99 $9.39 $9.95
Production Taxes ($/boe)$4.33 $2.97 $2.92
G&A ($/boe)$1.21 $1.19 $1.28
DD&A ($/boe)$15.73 $16.93 $16.86

Consensus vs Actual (S&P Global definitions and company metrics)

MetricQ2 2024Q2 2025 ConsensusQ2 2025 Actual
EPS (Primary/GAAP, $)$1.36 $0.95*$1.37 (Adjusted Diluted)
Revenue (S&P “Revenue”, $USD Millions)n/a$540.55*$542.37*
Adjusted EBITDA (Company, $USD Millions)$413.07 $361.22*$440.42

Values with an asterisk (*) are retrieved from S&P Global.

Explanation: S&P’s “Revenue” definition differs from NOG’s “Total Revenues” ($706.8M) and “Oil & Gas Sales” ($574.4M). We present both to clarify the apparent beat under S&P’s definition alongside company-reported totals .

Segment/Program Mix (Q2 2025)

AllocationQ2 2025
CapEx by Basin (%)Permian 34%; Williston 25%; Uinta 15%; Appalachian 26%

KPIs (Development & Activity, Q2 2025)

KPIQ1 2025Q2 2025
Net Wells Added (TIL)27.3 20.8
Net Wells in Process (Period-End)38.9 53.2
Net Producing Wells (Period-End)1,133.9 1,151.7
Weighted Avg Gross AFE ($MM)$10.53 $9.61
Normalized AFE ($/ft)$833 $841

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Annual Production (Boe/d)FY 2025130,000–135,000 130,000–133,000 Lowered
Annual Oil Production (bbl/d)FY 202575,000–79,000 74,000–76,000 Lowered
Total CapEx ($MM)FY 2025$1,050–$1,200 $925–$1,050 Lowered
Net Oil Wells TILFY 202587.0–91.0 73.0–76.0 Lowered
Net Total Wells TILFY 202597.0–99.0 83.0–85.0 Lowered
Net Wells SpudFY 2025106.0–110.0 75.0–85.0 Lowered
Production Expenses ($/boe)FY 2025$9.15–$9.40 $9.25–$9.60 Raised
Production Taxes (% of O&G Sales)FY 20258.5%–9.0% 7.5%–8.5% Lowered
Avg WTI Differential ($/bbl)FY 2025($4.75)–($5.50) ($5.25)–($5.75) Widened
Henry Hub Realization (%)FY 202585%–90% 85%–90% Maintained
DD&A ($/boe)FY 2025$16.50–$17.50 $16.00–$17.00 Lowered
Cash G&A ($/boe)FY 2025$0.85–$0.90 $0.85–$0.90 Maintained

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4’24 and Q1’25)Current Period (Q2’25)Trend
Capital allocation discipline2025 plan set to drive growth, diversified model and SPUD momentum Pivot to lower organic CapEx, prioritizing inorganic opportunities with better risk-adjusted returns Shift toward M&A/ground game
Production cadence/TIL timingQ1: strong TILs; diversified basins support resilience Q3 dip expected from lower Q2 completions; Q4 volumes similar to Q2, elevated wells-in-process Near-term moderation, rebuild into Q4
Cost structureQ4 LOE $9.62/boe; Q1 LOE $9.39/boe Q2 LOE $9.95/boe; SWD/processing drove increase; watching frac spread dynamics Cost pressure; potential relief if frac spreads contract
Hedging strategyExpanded oil/gas collars/swaps; ground game hedges Added hedges; realized gains ~$58–63M; strong coverage H2’25–2026 Enhanced downside protection
Legal/regulatoryDAPL risk noted; SEC “full cost” accounting $81.7M settlement booked in O&G sales; $48.6M net cash expected in Q3 One-time cash inflow in Q3
AI/data center power demandNot highlightedPotential regional power builds could narrow gas differential bands over time; too early to impact markets Early-stage optionality

Management Commentary

  • “NOG’s diverse and scaled platform delivered solid results, with strong free cash flow… incremental growth being focused on the strong backlog of inorganic opportunities” — Nick O’Grady, CEO .
  • “We generated over $126 million in free cash flow this quarter, plus… nearly $50 million pending from a recent legal settlement… our business… continues to shine while production has remained resilient” — Nick O’Grady, CEO .
  • “Given our outlook… we are reducing our 2025 CapEx guidance to $925–$1,050 million… pivoted into discretionary acquisitions from ground game to bolt-ons… maintained over $1.1 billion in liquidity” — Chad Allen, CFO .
  • “In the second quarter… we spud 4.8 net wells in Uinta… wells in process totaled 53.2 net wells at quarter end… election percentage remained elevated at 95%+” — Adam Dirlam, President .

Q&A Highlights

  • Cadence and maintenance mode: Management expects a modest Q3 decline (mid-single digits), with Q4 similar to Q2; 2026 activity will be return-driven, with maintenance possible depending on price environment .
  • Organic vs inorganic mix: Preference to shift growth capital to acquisitions given better multi-year resilience versus single-period drilling returns in a volatile strip .
  • Settlement cash use: ~$48.6M expected in Q3 treated through working capital; applied via normal capital allocation (revolver sweep, opportunities) .
  • Costs/outlook: LOE elevated by fixed cost absorption and SWD; further reductions would likely require frac spread count contraction; accruals reflect cautious “show me” posture .
  • M&A market: >10 ongoing processes with combined value >$8B; seeing large traditional non-op packages and gas-weighted opportunities; disciplined underwriting and hurdle rates .

Estimates Context

  • EPS vs consensus: Adjusted diluted EPS $1.37 materially exceeded S&P Global Primary EPS consensus of ~$0.95* for Q2 2025; NOG also reported GAAP diluted EPS of $1.00 .
  • Revenue vs consensus: Under S&P’s “Revenue” definition, Q2 2025 actual was ~$542.4M* vs ~$540.5M* consensus; company-reported Total Revenues were $706.8M (includes derivative gains) .
  • EBITDA vs consensus: Company-reported Adjusted EBITDA was $440.4M; S&P Global EBITDA consensus was ~$361.2M*; definition differences likely explain variance .

Values with an asterisk (*) are retrieved from S&P Global.

Key Takeaways for Investors

  • Returns over growth: The 2025 guidance cut (CapEx, wells, volumes) signals a disciplined, returns-first pivot toward inorganic opportunities amid a tenuous oil strip .
  • Near-term cadence: Expect a modest production dip in Q3 from lower Q2 completions, with Q4 volumes similar to Q2 and wells-in-process elevated, supporting a stronger exit rate .
  • Cash flow durability: 22 consecutive quarters of positive FCF and enhanced hedge coverage underpin balance sheet strength and flexibility through cycles .
  • Cost vigilance: LOE and SWD/processing cost inflation remains a watch item; meaningful relief likely tied to frac spread contraction and broader service cost dynamics .
  • Legal settlement: $48.6M net cash expected in Q3 provides incremental dry powder for revolver reduction, buybacks, or accretive acquisitions .
  • Liquidity/M&A optionality: $1.1B+ liquidity and the upsized 2029 converts reopen position NOG to act countercyclically across a robust >$8B opportunity set .
  • Hedge-insulated cash flows: Strong realized hedge gains and layered collars/swaps across oil/gas mitigate commodity volatility; monitor Waha and basin differentials .

Values with an asterisk (*) are retrieved from S&P Global.