Slides
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NOG Q2 2026 Earnings Presentation August 6 , 2026
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Q2 2026 Earnings Presentation | 2 Q2 2026 Financial & Operating Highlights Ground Game 145.7Mboe/d Average Daily Production $159.0MM Free Cash Flow1 Adj. EBITDA1 Shareholder Returns ~$97.4MM $401.0MM 1. Free Cash Flow, Adjusted EBITDA and Adjusted ROCE are non-GAAP financial measures. See appendix for calculations and reconciliat ions. 2. Adjusted ROCE is adjusted for impairment and depletion of $971.0 million and $67.4 million respectively, as of June 30, 2026. +9% YoY , -2% QoQ +17% QoQ 26.0% YoY , 423.7% QoQ In dividends and share repurchases $45.0MM 30 deals, 2,366 acres, 6.2 net wells NOG's Areas of Operation Appalachia (PA,OH, WV) ~96K acres Duvernay (Alberta CA) ~78K net acres Permian (TX, NM) ~46K net acres Uinta (UT) ~16K net acres Williston (ND,SD, MT) 178K net acres Adjusted ROCE 1,2 12.7% +35% QoQ Financial and operational outperformance on strength of assets, optionality of NOG model and higher oil prices
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Q2 2026 Earnings Presentation | 3 • ~250 wells evaluated, 16.8 net driven by the Permian and Williston • 100% consent rate, expected IRRs above hurdle rate at flat $55 oil and $2.75 gas price deck • AFE and election activity accelerating, up ~20% relative to trailing twelve month run rate • Lateral lengths continue to lengthen modestly on new elections and normalized AFE costs are down ~5% from the 2025 average Wells in Process Well Completions Q2 2026 Operations Highlights Acceleration in oil-weighted activity coming through Wells In Process and AFEs • 12.7 wells added to production in Q2, with ~3.0 net wells deferred to July driven by Waha pricing • Permian, Williston and Uinta accounting for over 80% of activity • Appalachian set record gas volumes for NOG, driven by strong IPs, a full quarter from the Utica transaction, and culmination of the Appalachian joint development program • Uinta significantly outperformed internal estimates both on legacy production as well as on the 2026 development program • Strong build to the Drilling & Completions list ending the quarter with 51.8 net wells in process • Net wells in process were split approximately 36% Permian, 26% Williston, 16% Appalachia, 19% Uinta, and 3% Duvernay • 19.1 net wells added to the D&C list resulting in a build of 8.07 net wells • SM Energy, OXY , PR, Crescent and Slawson driving activity AFE's
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Q2 2026 Earnings Presentation | 4 First Half 2026 Basin Level Performance Metrics Production Volumes WILLISTON PERMIAN APPALACHIAN UINTA DUVERNAY3 TOTAL Oil (MBbl/d) 27.1 32.5 1.0 9.8 0.5 70.9 Gas (MMcf/d) 80.8 132.6 237.2 5.0 0.8 456.4 Equivalent (Mboe/d) 40.7 54.6 40.5 10.6 0.6 147.0 Total Net Production (MMBoe) 7.4 9.9 7.3 1.9 0.1 26.6 % Oil 67 % 60 % 2 % 92 % 79 % 48 % CMA BENCHMARK PRICING - NYMEX WTI $82.67/Bbl NYMEX HENRY HUB $3.21/MMBtu Per Unit Metrics WILLISTON PERMIAN APPALACHIAN UINTA DUVERNAY TOTAL Unhedged Realized Oil Price ($/Bbl) $77.51 $81.56 $63.76 $67.10 $83.79 $77.79 % of Benchmark — WTI 94 % 99 % 77 % 81 % 101 % 94 % Unhedged Realized Gas Price ($/Mcf) $4.46 $0.50 $3.07 $3.26 $0.96 $2.57 % of Benchmark — Henry Hub 139 % 16 % 96 % 102 % 30 % 80 % Unhedged Realized Price per BOE ($)(1) $60.70 $49.76 $19.53 $63.34 $67.31 $45.51 Production Expenses per Boe ($)(2) $16.78 $9.32 $4.11 $5.59 $3.97 $9.65 Production Tax per Boe ($) $4.64 $4.03 $0.53 $3.28 $0.00 $3.16 Production Tax as a % of Pre-hedge Revenue 7.6 % 8.0 % 2.7 % 5.2 % — % 6.9 % Cash Production Margin per Boe ($) $39.28 $36.41 $14.89 $54.47 $63.34 $32.70 1) Unhedged Realized Price is calculated based on average benchmark prices during period less transportation and basis different ial costs. 2) Production expenses include lease operating expenses, expensed workover costs, and certain facilities costs on a 2 -stream per BOE basis (excluding NGL volumes). 3) Data related to Duvernay reflects partial period, from June 1, 2026 to June 30, 2026
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Q2 2026 Earnings Presentation | 5 • M&A landscape remains robust with an increase in diversity. Larger oil assets returning to market • NOG’s capital and solutions remain sought-after • Variety of structures (Non- Op packages, Joint Development, Co-Bids) • Wide range of partners and basins Ground Game Investment Activity Update Diverse and scaled non-op model provides a vast total addressable market in both M&A and Ground Game opportunities relative to peers • Closed Duvernay Joint Development Acquisition adding 20 years of inventory with average breakevens below $50 WTI for less than $0.6 million per net location • First full quarter of Utica acquisition, proceeding according to plan • Culminated Appalachian joint development, well results outperforming internal estimates • Increased deal sourcing, evaluated approximately 250 ground game opportunities in Q2 26 • Completed 30 ground game deals in Q2, focusing on both near term development and inventory duration • Ground Game activity across all basins • Added 6.2 Net Wells and over 2,300 Net Acres in Q2 Bolt-On & JVOpportunity Set
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Q2 2026 Earnings Presentation | 6 Light-Oil Duvernay: Strategic TAM Expansion into Canada 25% non-operated stake | ~$262MM purchase price | Operated by Parallax Energy, L.P. |Closed June 1,2026 Why the Duvernay? Why Now? • Strategic TAM expansion into one of North America's premier light oil resources — 40–50° API gravity crude, directly comparable in quality to the best Lower 48 basins. • Self-funding acquisition — leverage neutral, accretive to key financial metrics over a multi-year period. • 100% jointly owned gathering and gas processing infrastructure — leading cash costs <$7.50/Boe, with ample egress and no takeaway constraints. • Early-stage play with ~20 years of inventory at average WTI breakevens <$50 — NOG enters before the market fully values it. • Area-of-Mutual-Interest (AMI) in place — line of sight to additional bolt-on opportunities. ~$262MM Purchase Price (US$) <3.0x NTM EBITDA ~78,000 Net Acres ~500 gross locations ~4K Boe/d 2027E Net Production* 2-stream | ~80% light oil <$7.50 Cash Costs per Boe (2-stream) Leading North American netbacks <$50 WTI Average Breakeven High-quality, resilient inventory ~20 Yrs Inventory Runway Decades of development potential
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Q2 2026 Earnings Presentation | 7 Activity and Cap Ex Spend by Basin For the Quarter and Year-to-Date 1) Data related to Duvernay reflects partial quarter, from June 1, 2026 to June 30, 2026. 2) Cap Ex excluding non-budgeted acquisitions and other, in millions. Cap Ex in the Quarter and YTD2 WILLISTON PERMIAN APPALACHIAN UINTA DUVERNAY1 TOTAL Cap Ex in the Quarter2 $64.8 $71.6 $27.7 $28.5 $3.2 $195.8 Cap Ex Year to Date2 $129.5 $156.0 $101.7 $75.5 $3.2 $465.9 Activity Year to Date WILLISTON PERMIAN APPALACHIAN UINTA DUVERNAY1 TOTAL Net Drills (net wells) 10.6 14.8 2.6 5.7 0.0 33.7 Net TILS (net wells) 8.2 11.4 5.7 4.5 0.0 29.8 Activity in Quarter WILLISTON PERMIAN APPALACHIAN UINTA DUVERNAY1 TOTAL Net Drills (net wells) 5.8 8.8 1.6 2.9 0.0 19.1 Net TILS (net wells) 4.3 4.7 2.3 1.4 0.0 12.7 Drilling activity outperforming expectations. Operators pulling forward activity in Permian and Williston.
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Q2 2026 Earnings Presentation | 8 Liquidity Position 1) Revolver outstanding balance and capacity as of 6/30/2026 2) Annualized Q2 Interest Cost / Period End Debt Ample liquidity to support business plan $1.02B AVAILABLE LIQUIDITY 6/30/2026 2029 NEXT DEBT MATURITY ~5.5 yrs WTD AVG DEBT MATURITY 6.0% AVG COST OF BORROWINGS2 DEBT MATURITY PROFILE1 $ in millions, as of 6/30/2026 3.625% Conv. Notes Revolver Drawn 8.750% Sr. Notes 7.875% Sr. Notes REVOLVER CAPACITY & LIQUIDITY $ in millions, as of 6/30/2026 Elected Commitment $1,800 Less: Revolver Drawn (825) Undrawn Capacity 975 Plus: Cash & Acq. Deposits 48 Total Available Liquidity $1,023 $1,975 Borrowing Base $1,800 Elected Commitment DRAWN UNDRAWN +$175 UNELECTED
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Q2 2026 Earnings Presentation | 9 Strategic Risk Management — Hedge Position1 1) Additional hedge details available in the appendix and in Company filings. 2) Percentage hedged based on midpoint of production guidance. REMAINING H2 2026 (JUL-DEC 2026) - OPEN POSITIONS AS OF JULY 31, 2026 H2 2026 Swaps & Collars H2 2026 Basis Swaps Notes: Reflects open commodity derivative positions with settlement during 2026 Oil hedges are NYMEX WTI swaps and collars (floors = long puts, ceilings = short calls); gas hedges are NYMEX Henry Hub swaps and collars. Basis swaps excluded from swaps & collars volumes. % Hedged = Swaps + in-the-money floor or ceiling volume / 2H26 net production at implied guidance midpoint. Gas volumes shown in MMBtu vs. mcf production 60% HEDGED 66% HEDGED OIL VOLUMES ~8,174 MBBls hedged2 Weighted-avg price: $64.97/Bbl (floors & swaps) $69.99/Bbl (ceilings & swaps) GAS VOLUMES ~50,664 BBtu hedged2 Weighted-avg price: $3.75/MMBtu (floors & swaps) $4.57/MMBtu (ceilings & swaps) Oil Volumes (MBbls) Price ($/Bbl) WTI Midland-Cushing Basis 5,045 $0.94 Gas Volumes (BBtu) Price ($/MMBtu) TETCO M2 Basis 12,240 $(1.15) Waha Basis 7,650 $(0.84) REX Zone 3 Basis 6,885 $(0.26)
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Q2 2026 Earnings Presentation | 10 Updated 2026 Guidance and Capital Budget - Previous Guidance (May 26,2026) Revised Guidance (August 6,2026) Annual Production (2-stream, Boe/day) 143,000 - 148,000 143,000 - 148,000 Annual Oil Production (Bbl/day) 71,500 - 73,500 71,500 - 73,500 Net Wells Turned-in-Line (TILs) 74.0 - 76.0 74.0 - 76.0 Total Budgeted Capital Expenditures ($MM) $850 - $900 $850 - $900 LOE/Production Expenses (per Boe) $9.70 - $9.90 $9.70 - $9.80 Cash G&A (ex-transaction costs) (per Boe) $0.83 - $0.86 $0.83 - $0.86 Non-Cash G&A (per Boe) $0.25 - $0.30 $0.25 - $0.30 Production Taxes (as a % of Oil & Gas Sales) 7.5% - 8.0% 7.5% - 8.0% Oil Differential to NYMEX WTI (per Bbl) ($5.25 - $5.60) ($5.00 - $5.40) Gas Realization as a % of Henry Hub/MCF 70.0% - 72.5% 70.0% - 75.0% DD&A Rate per Boe $15.00 - $15.50 $15.00 - $15.50 UPDATE: • Production and Cap Ex guidance reiterated in NOG’s 2Q 2026 Operational Update • Includes 2H 2026 contribution from Duvernay acquisition (closed late 2Q) • Capital expenditures, even inclusive of Duvernay transaction, remain unchanged, driven primarily by cost efficiencies • LOE guidance tightened lower • Further improvement to oil differentials for the year • Overall gas realization widened slightly higher, aided by Permian shut-ins in 2Q and strong NGL prices
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Q2 2025 Earnings Presentation | 11 NOG Investment Case
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Q2 2026 Earnings Presentation | 12 NOG – The Premier Non-Op 5-Basin North American Platform NOG's total addressable market continues to expand, providing broad access to price resilient, high-quality plays 27% Williston ~178,000 Net Acres Oil: 66% | Gas: 34% 35% Permian ~46,000 Net Acres Oil: 59% | Gas: 41% 30% Appalachian ~96,000 Net Acres Oil: 2% | Gas: 98% 8% Uinta ~16,000 Net Acres Oil: 91% | Gas: 9% NEW Duvernay ~78,000 Net Acres Oil: ~80% | Light Oil Planting a flag in long-lived prolific oily basin Our model provides NOG with un-matched optionality to pursue multiple basins, commodities and even adjacent businesses such as midstream or minerals all in the pursuit of business durability and optimization of shareholder returns. Basin contribution to aggregate production Q2 2026
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Q2 2026 Earnings Presentation | 13 The NOG Investment Case 1 2 3 4 5 North American Non-Op Franchise 5-Basin North American platform. 146 Mboe/d production. 1.7MM+ gross acres. Total addressable market expanding – the flywheel keeps spinning Proven Acquisition Engine Durable Free Cash Flow Growing Capital Returns Valuation Re-Rating Opportunity $6B+ deployed since 2018. Disciplined underwriting. Record ground game activity YTD. Every acquisition makes the next one better. >$351MM FCF (LTM) and 24 consecutive positive FCF quarters exceeding $1.9B total. Built to generate cash through cycles, not just in them. $0.45/share Q2 2026 dividend. 11x growth since 2021. ~$600MM returned to shareholders since 2021. Dividend built for the cycle trough – this is a compounder. Trading at cycle-trough multiples while inventory deepens, TAM expands, and the coiled spring unwinds.
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Q2 2026 Earnings Presentation | 14 A Proven Acquisition Engine Every deal expands the flywheel — more data, more partners, more TAM 33 54 76 99 124 135 146 0 20 40 60 80 100 120 140 160 2020 2021 2022 2023 2024 2025 Q2 2026 Average Daily Production (MBoe/d) Key Acquisitions Driving Growth 2018–20 Williston Basin Build-out Single-basin foundation 2021 Marcellus (Appalachian) Gas diversification 2022 Permian Entry Premier basin access at scale 2023 Mascot, Forge, Novo, Delaware & Utica Fastest-growing US oil basin2024 XCL (Uinta) JDA model evolution 2025 Ohio Utica (Infinity) Integrated Gas Play at Scale 2026 Duvernay (Parallax) Canada entry, TAM expansion
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Q2 2026 Earnings Presentation | 15 Q2 2026 Earnings Presentation | 15 1) Assumes July 10, 2026 Strip. Levered return calculated using the average return profile through 2040, and 1/3 deal debt fi nancing. NOG M&A Delivering Strong IRRs NOG underwrites every acquisition to the same disciplined standard. The inputs below are the basis of the look-back - no upside case, no reserve-life extension UNDERWRITING INPUT BASIS USED Commodity price deck July 10, 2026, Oil and Gas Strip $3.5bn+ RECENT ACQUISITIONS ANALYZED 20 NON -BUDGETED ACQUISITIONS COMPLETED 2021 -2025 Potential upside remains via asset sales relative to the hold-to-life blowdown model, which is excluded from the figures to the right. Return horizon 14+year NPV profile Asset Valuation Historical actuals with asset outlook through 2040 Initial Leverage 1/3 Purchase Price at acquisition close AVERAGE HOLD -TO-LIFE RETURNS Based on internal look-back analysis of 20 non-budgeted acquisitions completed from 2021-20251 20> % IRR 2.2 MOIC x
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Q2 2026 Earnings Presentation | 16 NOG – A Growth Compounder Trading at a Value Multiple Not all reserve reports are the same. NOG's Non-Op status results in conservative reserves bookings, understating inventory and value. • NOG's PDP PV-10 alone ($4.4 billion), approximates its Q2 2026 enterprise value ($4.6 billion)1 • NOG's PUD & Probable reserves bookings are conservative due to its Non-Op status • For example, NOG's unbooked upside includes locations associated with its Utica and Marcellus acreage, where minimal inventory is currently included in reserves, as well as secondary zones in the Uinta and Permian, and emerging plays such as the Barnett • Excluding ground game and major acquisitions, development activity since 12/31/2023 has exceeded booked activity by 1.60x 1) Based on NOG's June 30, 2026, internal reserve evaluation run at $70.00 WTI and $3.75 MMBtu. PV-10 is a non-GAAP financial (see appendix). Enterprise value $4.6B as of June 30, 2026. PDP PV-10 ~$4.4 BN WIPs, PUDs & Probs PV-10 ~$3.7 BN Unbooked Upside
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Q2 2026 Earnings Presentation | 17 Capital Allocation, Deleveraging and Beyond 1) Assumes consistent commodity assumptions of $70 oil, $3.50 gas, capture rate NYMEX 2027 to 2029, strip 2026. The above gr aph is for illustrative purposes only and is not necessarily indicative of future results. Actual results may differ materially and readers are cautioned not to place undue reliance ther eon. See "Important Disclosures" in the appendix. We anticipate robust excess free cash flow while maintaining our production1 NOG has the ability to achieve a pro forma Net Debt / Adjusted EBITDA ratio of <1.5x by year-end 2026 while maintaining production with healthy excess Free Cash Flow after paying its dividend. Ranked Priorities • Reduce leverage to target 1.0x to 1.5x • Equity share repurchases • Free cash flow growth Excess FCF Dividends ILLUSTRATIVE CUMULATIVE FREE CASH FLOW2
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Q2 2025 Earnings Presentation | 18 Appendix: Supplemental Information
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Q2 2026 Earnings Presentation | 19 Historical Operating & Financial Information HISTORICAL OPERATING INFORMATION 2023 2024 2025 2Q25 2Q26 PRODUCTION Oil (MBbls) 22,013.0 26,510.6 27,611.0 7,001.9 6,213.0 Natural Gas and NGLs (Mmcf) 84,341.9 113,476.3 130,084.0 31,203.9 42,254.0 Total Production (Mboe) 36,070.0 45,423.4 49,291.7 12,203.0 13,255.0 REVENUE Realized Oil Price, including settled derivatives ($/bbl) (3) $ 73.88 $ 71.48 $ 64.35 $ 64.58 $ 69.37 Realized Natural Gas and NGL Price, including settled derivatives ($/Mcf) $ 3.90 $ 3.00 $ 3.32 $ 3.45 $ 3.63 Total Oil & Gas Revenues, including settled derivatives (millions) $ 1,955.7 $ 2,235.3 $ 2,282.6 $ 635.3 $ 584.5 Adjusted EBITDA (millions)(1) $ 1,428.3 $ 1,619.1 $ 1,628.8 $ 440.4 $ 401.0 Key Operating Statistics ($/Boe) Average Realized Price (3) $ 54.22 $ 49.21 $ 44.82 $ 45.86 $ 44.10 Production Expenses 9.62 9.46 9.61 9.95 9.59 Production Taxes 4.44 3.46 2.66 2.92 3.45 General & Administrative Expenses - Cash Adjusted (2) 0.83 0.81 0.87 0.89 0.94 Total Cash Costs (2) $ 14.89 $ 13.73 $ 13.14 $ 13.76 $ 13.98 Operating Margin ($/Boe) (2)(3) $ 39.33 $ 35.48 $ 31.68 $ 32.10 $ 30.12 Operating Margin % (2)(3) 72.5% 72.1% 70.7% 70.0% 68.3% HISTORICAL FINANCIAL INFORMATION ($'S IN MILLIONS) 2023 2024 2025 2Q25 2Q26 ASSETS Current Assets $ 509.4 $ 500.7 $ 586.0 $ 588.4 $ 502.1 Total Property and Equipment, net $ 3,931.6 $ 5,082.2 $ 4,746.4 $ 5,093.1 $ 5,293.1 Other Assets $ 43.4 $ 20.9 $ 77.0 $ 21.0 $ 32.7 Total Assets $ 4,484.4 $ 5,603.8 $ 5,409.4 $ 5,702.5 $ 5,827.9 LIABILITIES Current Liabilities $ 385.8 $ 544.3 $ 539.3 $ 488.2 $ 630.5 Long-term Debt, net $ 1,835.6 $ 2,369.3 $ 2,395.4 $ 2,365.9 $ 2,724.8 Other Long-Term Liabilities $ 215.3 $ 369.8 $ 348.3 $ 435.4 $ 477.2 Stockholders' Equity $ 2,047.7 $ 2,320.4 $ 2,126.3 $ 2,413.0 $ 1,995.3 Total Liabilities & Stockholders' Equity $ 4,484.4 $ 5,603.8 $ 5,409.4 $ 5,702.5 $ 5,827.9 CREDIT STATISTICS Adjusted EBITDA (Annual, Q2 2025/26 LTM) (1) 1,428.3 1,619.1 1,628.8 1,761.70 1,497.22 Net Debt 1,840.8 2,386.2 2,350.1 2,349.40 2,702.40 Total Debt $ 1,866.1 $ 2,395.1 $ 2,423.2 $ 2,385.10 $ 2,750.00 Net Debt/Adjusted EBITDA (1)(4) 1.29x 1.47x 1.60x 1.33x 1.80x Total Debt/Adjusted EBITDA (1)(4) 1.31x 1.48x 1.44x 1.35x 1.84x1) Adjusted EBITDA is a non-GAAP measure. See reconciliation on the slide that follows. 2) Excludes certain acquisition related expenses. 3) Excludes the impact of certain non-cash adjustments to oil revenues. 4) Net debt is total debt less cash and acquisition deposits.
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Q2 2026 Earnings Presentation | 20 NON-GAAP Reconciliations: Adjusted EBITDA & Other ADJUSTED EBITDA BY QUARTER (IN THOUSANDS) 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Net Income (Loss) $ 298,446 $ 71,698 $ 138,982 $ 99,585 $ (129,074) $ (70,732) $ (522,847) $ 236,628 Add: Interest Expense, Net 36,837 45,259 43,850 44,435 42,975 41,120 42,788 41,442 Income Tax Expense 98,777 16,140 46,805 32,193 (39,728) (15,326) (173,070) 73,968 Depreciation, Depletion, Amortization and Accretion 185,657 204,674 205,690 205,741 199,351 204,076 197,098 192,885 Impairment of Oil and Gas Assets - - - 115,576 318,674 268,497 268,276 - Non-Cash Share Based Compensation 3,018 3,539 3,540 3,729 4,016 4,078 3,710 4,409 Gain on the Extinguishment of Debt - - - - - 10,833 14 - Other Adjustments - 5,116 5,000 6,000 6,000 8,719 - - Acquisition Transaction Costs (1,901) 760 423 1,046 165 1,366 6,686 7,698 (Gain) Loss on Unsettled Interest Rate Derivatives 20 (283) 144 (1) 131 292 (1,566) (1,474) Loss on Foreign Currency Transactions - - - - - - - 4,655 Gain Contingent Consideration - - - - - - - (2,682) (Gain) Loss on Unsettled Commodity Derivatives (208,441) 59,728 (9,699) (67,888) (15,379) (86,376) 521,423 (156,502) Adjusted EBITDA $ 412,413 $ 406,631 $ 434,735 $ 440,416 $387,131 $366,547 $ 342,512 $ 401,027 OTHER NON-GAAP METRICS BY QUARTER (IN THOUSANDS) 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Total General and Administrative Expense $ 10,005 $ 15,528 $ 14,481 $ 15,628 $ 14,101 $ 17,121 $ 23,174 $ 24,529 Non-cash General and Administrative Expense 3,018 3,539 3,540 3,729 4,015 4,078 3,710 4,409 Total General and Administrative Expense - Cash 6,987 11,989 10,941 11,899 10,086 13,043 19,464 20,120 Less: Acquisition Transaction Costs (1,901) 760 423 1,046 165 1,366 6,686 7,698 Total General and Administrative Expense - Cash Adjusted 8,888 11,229 10,518 10,853 9,921 11,677 12,778 12,422 Total Principal Balance on Debt $ 1,980,108 $ 2,395,108 $ 2,335,108 $ 2,385,108 $ 2,423,165 $ 2,423,165 $ 2,578,000 $ 2,750,000 Less: Cash and Acquisition Deposits (59,856) (8,933) (37,576) (35,687) (31,798) (73,099) (37,041) (47,603) Net Debt $ 1,920,252 $ 2,386,175 $ 2,297,532 $ 2,349,421 $ 2,391,367 $ 2,350,066 $ 2,540,959 $ 2,702,397
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Q2 2026 Earnings Presentation | 21 NON-GAAP Reconciliations: ROCE & Recycle Ratio 1) Excludes impairment of oil and gas assets of $971.0 million. 2) Excludes certain acquisition related expenses. 3) Excludes the impact of certain non-cash adjustments to oil revenues. 4) Adjusted depletion expense by $67.4 million. 5) Excludes depletion expense of $29.0 million. Note: Adjusted EBITDA is a non-GAAP measure. Numbers may be off due to rounding. • Cash Margin: $30.12/Boe(2) (3) • + Realized avg. commodity price: $44.10/Boe (3) • - Cash Costs: $13.98/Boe (2) • DD&A Rate: $14.55/Boe • Adj. EBIT: $716.4MM(5) (Q2 26 annualized) • + Adj. EBITDA: $401.0 MM (Q2 2026) • - DD&A: $221.9MM(5) (Q2 2026) • Capital Employed: $5,657.7MM(1)(4) (Avg. of Q2/25 and Q2/26) • + Total Assets: $6,217.0MM(1)(4) (Avg. of Q2/25 and Q2/26) • - Current Liabilities: $559.3M (Avg. of Q2/25 and Q2/26) EBIT Capital Employed÷ = 12.7% Cash Margin DD&A÷ = 2.1x
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Q2 2026 Earnings Presentation | 22 NON-GAAP Reconciliations: Free Cash Flow FREE CASH FLOW (FCF) - QUARTERLY FREE CASH FLOW (FCF) - ANNUAL (IN THOUSANDS) 1Q24 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 1Q26 2Q26 Net Cash Provided by Operating Activities $ 392,147 $ 340,477 $ 385,761 $ 290,278 $ 407,426 $ 362,112 $ 423,120 $ 312,630 $ 323,615 $ 321,617 Exclude: Changes in Working Capital and Other Items (39,665) 33,675 (8,704) 68,581 (19,997) (23,700) (30,295) 3,929 (26,442) 32,061 Less: Capital Expenditures (1) (298,507) (240,405) (199,918) (262,477) (251,735) (212,234) (273,931) (273,350) (266,812) (194,676) Free Cash Flow $ 53,975 $ 133,747 $ 177,139 $ 96,382 $ 135,694 $ 126,178 $ 118,894 $ 43,209 $ 30,361 $ 159,002 (1) Capital Expenditures are calculated as follows: Cash Paid for Capital Expenditures $ 407,006 $ 223,173 $ 381,824 $ 662,623 $ 263,971 $ 327,361 $ 352,339 $ 308,032 $ 634,623 $ 379,811 Less: Non-Budgeted Acquisitions, inclusive of Acquisition Transaction Costs (127,834) (21,770) (204,571) (508,147) (22,204) (61,555) (79,536) (67,195) (406,338) (171,527) Plus: Change in Accrued Capital Expenditures and Other 19,335 39,002 22,665 108,001 9,968 (53,572) 1,128 32,513 38,527 (13,608) Capital Expenditures $ 298,507 $ 240,405 $ 199,918 $ 262,477 $ 251,735 $ 212,234 $ 273,931 $ 273,350 $ 266,812 $ 194,676 (IN THOUSANDS) 2020 2021 2022 2023 2024 2025 Net Cash Provided by Operating Activities $ 331,685 $ 396,467 $ 928,418 $ 1,183,321 $ 1,408,663 $ 1,505,288 Exclude: Changes in Working Capital and Other Items (34,136) 85,812 62,399 106,134 53,887 (70,063) Less: Capital Expenditures (1) (212,051) (253,479) (523,060) (926,547) (1,001,307) (1,011,250) Free Cash Flow $ 70,232 $ 214,041 $ 457,954 $ 362,908 $ 461,243 $ 423,975 (1) Capital Expenditures are calculated as follows: Cash Paid for Capital Expenditures $ 283,632 $ 614,222 $ 1,355,197 $ 1,861,134 $ 1,674,626 $ 1,251,703 Less: Non-Budgeted Acquisitions, Inclusive of Acquisition Transaction Costs - (389,657) (880,935) (973,434) (862,321) (230,490) Plus: Change in Accrued Capital Expenditures and Other (71,581) 28,914 48,798 38,847 189,002 (9,963) Capital Expenditures $ 212,051 $ 253,479 $ 523,060 $ 926,547 $ 1,001,307 $ 1,011,250
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Q2 2026 Earnings Presentation | 23 NOG continues to execute a strategy built around the safeguard of returns during a commodity down-cycle, while retaining flexibility to capture the opportunistic upside Hedges as of July 31, 2026. This table does not include volumes subject to swaptions, basis swaps, puts, and call options, whic h could increase the amounts of volumes hedged at the option of NOG’s counterparties. For additional information, see Note 10 to our financial statements included in our Form 10 -Q filed with the SEC for the quarter ended June 30, 2026. Hedge Profile—SWAPS CRUDE OIL DERIVATIVE SWAPS NATURAL GAS DERIVATIVE SWAPS Contract Period Total Hedged Volumes (BBL/day) Total Hedged Volumes (BBL) Weighted Average Price ($/BBL) Contract Period Total Hedged Volumes (mmBTU/day) Total Hedged Volumes (mmBTU) Weighted Average Price ($/mmBTU) 2026 Q3 18,245 1,678,567 $67.55 Q3 115,054 10,585,000 $4.03 Q4 17,245 1,586,567 $68.08 Q4 131,685 12,115,000 $4.16 Avg./Total 17,745 3,265,134 $67.81 Avg./Total 125,054 23,010,000 $4.10 2027 Q1 7,750 697,500 $69.47 Q1 79,167 7,125,000 $3.98 Q2 7,750 705,250 $69.47 Q2 80,879 7,360,000 $3.98 Q3 5,500 506,000 $70.50 Q3 80,000 7,360,000 $3.98 Q4 5,500 506,000 $70.50 Q4 64,783 5,960,000 $3.94 Avg./Total 6,616 2,414,750 $69.90 Avg./Total 76,178 27,805,000 $3.97 2028 Q1 500 45,500 $70.04 Q1 28,077 2,555,000 $3.83 Q2 500 45,500 $70.04 Q2 20,220 1,840,000 $3.83 Q3 500 46,000 $70.04 Q3 20,000 1,840,000 $3.83 Q4 500 46,000 $70.04 Q4 16,630 1,530,000 $3.85 Avg./Total 500 183,000 $70.04 Avg./Total 21,216 7,765,000 $3.83 2029 Q1 500 45,000 $70.04 Q2 500 45,500 $70.04 Q3 500 46,000 $70.04 Q4 500 46,000 $70.04 Avg./Total 500 182,500 $70.04
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Q2 2026 Earnings Presentation | 24 NOG continues to execute a strategy built around the safeguard of returns during a commodity down-cycle, while retaining flexibility to capture the opportunistic upside Hedge Profile—COLLARS and PUTS Hedges as of July 31, 2026. This table does not include volumes subject to swaptions, basis swaps, puts, and call options, whic h could increase the amounts of volumes hedged at the option of NOG’s counterparties. For additional information, see Note 10 to our financial statements included in our Form 10 -Q filed with the SEC for the quarter ended June 30, 2026. CRUDE OIL DERIVATIVE COLLARS & PUTS NATURAL GAS DERIVATIVE COLLARS & PUTS Contract Period Sub Floor Total Hedged Volumes (BBL/day) Floor Total Hedged Volumes (BBL/day) Ceiling Total Hedged Volumes (BBL/day) Sub Floor Total Hedged Volumes (BBL) Floor Total Hedged Volumes (BBL) Ceiling Total Hedged Volumes (BBL) Sub Floor Price ($/BBL) Floor Price ($/BBL) Ceiling Price ($/BBL) Contract Period Floor Total Hedged Volumes (mmBTU/day) Ceiling Total Hedged Volumes (mmBTU/day) Floor Total Hedged Volumes (mmBTU) Ceiling Total Hedged Volumes (mmBTU) Floor Price ($/mmBTU) Ceiling Price ($/mmBTU) 2026 Q3 2,250 19,187 26,680 207,000 1,765,163 2,454,587 $47.22 $62.34 $71.44 Q3 150,486 150,486 13,844,706 13,844,706 $3.45 $4.89 Q4 2,250 19,187 26,680 207,000 1,765,163 2,454,587 $47.22 $62.34 $71.44 Q4 146,735 146,735 13,499,642 13,499,642 $3.47 $5.07 Avg./Total 2,250 19,187 26,680 414,000 3,530,326 4,909,174 $47.22 $62.34 $71.44 Avg./Total 150,295 150,295 27,654,348 27,654,348 $3.46 $4.97 2027 Q1 2,500 6,750 6,750 225,000 607,500 607,500 $45.00 $61.14 $73.76 Q1 67,500 67,500 6,075,000 6,075,000 $3.45 $4.85 Q2 2,500 6,750 6,750 227,500 614,250 614,250 $45.00 $61.14 $73.76 Q2 55,604 55,604 5,060,000 5,060,000 $3.44 $4.44 Q3 421 3,842 3,842 38,750 353,500 353,500 $45.00 $63.04 $75.31 Q3 55,000 55,000 5,060,000 5,060,000 $3.44 $4.44 Q4 — 3,000 3,000 — 276,000 276,000 $— $64.03 $76.37 Q4 39,837 39,837 3,665,000 3,665,000 $3.44 $4.41 Avg./Total 1,346 5,072 5,072 491,250 1,851,250 1,851,250 $45.00 $61.94 $74.44 Avg./Total 54,411 54,411 19,860,000 19,860,000 $3.44 $4.56 2028 Q1 9,890 9,890 900,000 900,000 $3.50 $4.17 Q2 10,110 10,110 920,000 920,000 $3.50 $4.17 Q3 10,000 10,000 920,000 920,000 $3.50 $4.17 Q4 10,000 10,000 920,000 920,000 $3.50 $4.07 Avg./Total 10,000 10,000 3,660,000 3,660,000 $3.50 $4.15 2029 Q1 9,889 9,889 890,000 890,000 $3.50 $3.88 Q2 10,110 10,110 920,000 920,000 $3.50 $3.88 Q3 10,000 10,000 920,000 920,000 $3.50 $3.88 Q4 6,630 6,630 610,000 610,000 $3.50 $3.88 Avg./Total 9,151 9,151 3,340,000 3,340,000 $3.50 $3.88
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Q2 2026 Earnings Presentation | 25 NOG continues to execute a strategy built around the safeguard of returns during a commodity down-cycle, while retaining flexibility to capture the opportunistic upside Hedge Profile—Basis SWAPS Hedges as of July 31, 2026. This table does not include volumes subject to swaptions, basis swaps, puts, and call options, whic h could increase the amounts of volumes hedged at the option of NOG’s counterparties. For additional information, see Note 10 to our financial statements included in our Form 10 -Q filed with the SEC for the quarter ended June 30, 2026. MIDLAND-CUSHING BASIS SWAP WAHA BASIS SWAP APP BASIS SWAP REX BASIS SWAP Contract Period Total Hedged Volumes (BBL/day) Total Hedged Volumes (BBL) Weighted Average Price ($/BBL) Contract Period Total Hedged Volumes (mmBTU/day ) Total Hedged Volumes (mmBTU) Weighted Average Price ($/mmBTU) Contract Period Total Hedged Volumes (mmBTU/da y) Total Hedged Volumes (mmBTU) Weighted Average Price ($/mmBTU) Contract Period Total Hedged Volumes (mmBTU/da y) Total Hedged Volumes (mmBTU) Weighted Average Price ($/mmBTU) 2026 Q3 27,806 2,558,176 $0.94 Q3 33,152 3,050,000 $(0.84) Q3 53,043 4,880,000 $(1.17) Q3 29,837 2,745,000 $(0.26) Q4 27,029 2,486,682 $0.95 Q4 50,000 4,600,000 $(0.84) Q4 80,000 7,360,000 $(1.13) Q4 45,000 4,140,000 $(0.26) Avg./Total 27,418 5,044,858 $0.94 Avg./Total 41,576 7,650,000 $(0.84) Avg./Total 66,522 12,240,000 $(1.15) Avg./Total 37,418 6,885,000 $(0.26) 2027 Q1 15,478 1,393,000 $0.90 Q1 39,667 3,570,000 $(0.94) Q1 76,722 6,905,000 $(0.80) Q1 65,000 5,850,000 $(0.20) Q2 15,522 1,412,500 $0.90 Q2 50,330 4,580,000 $(0.95) Q2 75,000 6,825,000 $(0.84) Q2 65,000 5,915,000 $(0.20) Q3 15,500 1,426,000 $0.90 Q3 50,000 4,600,000 $(0.95) Q3 75,000 6,900,000 $(0.91) Q3 65,000 5,980,000 $(0.20) Q4 14,826 1,364,000 $0.88 Q4 49,674 4,570,000 $(0.95) Q4 75,000 6,900,000 $(0.93) Q4 65,000 5,980,000 $(0.20) Avg./Total 15,330 5,595,500 $0.90 Avg./Total 47,452 17,320,000 $(0.95) Avg./Total 75,425 27,530,000 $(0.87) Avg./Total 65,000 23,725,000 $(0.20) 2028 Q1 2,000 182,000 $0.79 Q1 10,220 930,000 $(1.01) Q1 37,033 3,370,000 $(0.88) Q1 40,000 3,640,000 $(0.19) Q2 2,000 182,000 $0.79 Q2 0 0 $— Q2 20,000 1,820,000 $(0.86) Q2 40,000 3,640,000 $(0.19) Q3 2,000 184,000 $0.79 Q3 0 0 $— Q3 20,000 1,840,000 $(0.86) Q3 40,000 3,680,000 $(0.19) Q4 2,000 184,000 $0.79 Q4 0 0 $— Q4 20,000 1,840,000 $(0.86) Q4 40,000 3,680,000 $(0.19) Avg./Total 2,000 732,000 $0.79 Avg./Total 2,541 930,000 $(1.01) Avg./Total 24,235 8,870,000 $(0.86) Avg./Total 40,000 14,640,000 $(0.19) 2029 Q1 20,000 1,800,000 $(0.75) Q1 10,000 900,000 $(0.16) Q2 20,000 1,820,000 $(0.75) Q2 10,000 910,000 $(0.16) Q3 20,000 1,840,000 $(0.75) Q3 10,000 920,000 $(0.16) Q4 20,000 1,840,000 $(0.75) Q4 10,000 920,000 $(0.16) Avg./Total 20,000 7,300,000 $(0.75) Avg./Total 10,000 3,650,000 $(0.16)
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Q2 2026 Earnings Presentation | 26 Important Disclosures Forward Looking Statements This presentation contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this presentation regarding Northern Oil and Gas, Inc.’s (“NOG,” “we,” “us” or “our”) dividend plans and practices, financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under NOG's revolving credit facility, NOG's intention or ability to pay or increase dividends on its capital stock, and impairment are forward-looking statements. When used in this presentation, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production, sales, market size, collaborations, cash flows, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond NOG’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on NOG’s current properties and properties pending acquisition; infrastructure constraints and related factors affecting NOG’s properties; general economic or industry conditions, whether internationally, nationally and/or in the communities in which NOG conducts business, including any future economic downturn, cost inflation, supply chain disruptions, the impact of continued or further inflation, disruption in the financial markets, changes in the interest rate environment and actions taken by OPEC and other oil producing countries as it pertains to the global supply and demand of, and prices for, crude oil, natural gas and NGLs; ongoing legal disputes over, and potential shutdown of, the Dakota Access Pipeline; NOG’s ability to identify and consummate additional development opportunities and potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from NOG’s acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on NOG’s cash position and levels of indebtedness; changes in NOG’s reserves estimates or the value thereof; disruption to NOG’s business due to acquisitions and other significant transactions; changes in local, state, and federal laws, regulations or policies that may affect NOG’s business or NOG’s industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs), and similar changes in foreign jurisdictions where NOG currently operates or in the future may operate, including Canada; conditions of the securities markets; exchange rate fluctuations; risks associated with NOG’s Convertible Notes, including the potential impact that the Convertible Notes may have on NOG’s financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of NOG; the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuances, including counterparty risk; increasing attention to environmental, social and governance matters; NOG’s ability to raise or access capital on acceptable terms; cyber-incidents could have a material adverse effect on NOG’s business, financial condition or results of operations; changes in accounting principles, policies or guidelines; events beyond NOG’s control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions and shipping channels, including the joint U.S.-Israel strikes on Iran, continued instability in the Middle East and the effects of any changes to conditions in or impacting Venezuela; and other economic, competitive, governmental, regulatory and technical factors affecting NOG’s operations, products and prices.
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Q2 2026 Earnings Presentation | 27 Important Disclosures Forward Looking Statements (cont.) NOG has based any forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond NOG’s control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of NOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025, as updated by subsequent reports NOG files with the SEC, which describe factors that could cause NOG’s actual results to differ from those set forth in the forward-looking statements. NOG does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. NOG assumes no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this presentation, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by NOG in its reports filed with the SEC which attempt to advise interested parties of the risks and factors that may affect NOG’s business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, NOG’s actual results may vary materially from those expected or projected.
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Q2 2026 Earnings Presentation | 28 Important Disclosures Industry and Marketing Data Although all information and opinions expressed in this presentation, including market data and other statistical information (including estimates and projections relating to addressable markets), were obtained from sources believed to be reliable and are included in good faith, NOG has not independently verified the information and makes no representation or warranty, express or implied, as to its accuracy or completeness. Some data is also based on the good faith estimates of NOG, which are derived from its review of internal sources as well as the independent sources described above. This presentation contains preliminary information only, is subject to change at any time and, is not, and should not be assumed to be, complete or to constitute all the information necessary to adequately make an informed decision regarding your engagement with NOG. While NOG is not aware of any misstatements regarding the industry and market data presented in this presentation, such data involve risks and uncertainties and are subject to change based on various factors, including those factors discussed under “Forward Looking Statements” above. NOG has no intention and undertakes no obligation to update or revise any such information or data, whether as a result of new information, future events or otherwise, except as required by law. Non-GAAP Financial Measures This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). These measures include (i) Adjusted EBITDA, (ii) PV-10, (iii) Net Debt, (iv) Return on Capital Employed (“ROCE”), (v) Recycle Ratio and (iv) Free Cash Flow. These non-GAAP financial measures are not measures of financial performance prepared or presented in accordance with GAAP and may exclude items that are significant in understanding and assessing our financial results. Therefore, these measures should not be considered in isolation, and users of any such information should not place undue reliance thereon. Please refer to the slides titled “Non- GAAP Reconciliations: Adjusted EBITDA & Other,” “Non-GAAP Reconciliations: ROCE & Recycle Ratio,” “Non-GAAP Reconciliations: Free Cash Flow” under the Appendix to this presentation for a reconciliation of these measures to the most directly comparable GAAP measures and NOG’s definitions (which may be materially different than similarly titled measures used by other companies) of these measures as well as certain additional information regarding these measures. NOG believes the presentation of these metrics may be useful to investors because it supplements investors’ understanding of its operating performance by providing information regarding its ongoing performance that excludes items it believes do not directly affect its core operations. NOG is unable to provide a quantitative reconciliation of PV-10 to its most directly comparable GAAP measure because management cannot reliably quantify certain of the necessary components of such GAAP measure. From time-to-time NOG provides forward-looking Free Cash Flow estimates or targets; however, NOG is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
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Q2 2026 Earnings Presentation | 29 Important Disclosures Reserves Information Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions used by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. Investors are urged to consider closely the disclosures and risk factors in the reports NOG files with the SEC. Use of Projections This presentation may contain projections, such as, but not limited to, production volumes; cash expenses, including operating expenses, G&A and interest expense; capital expenditures; P&A and decommissioning expenditures; and collateral obligations. NOG’s independent auditors have not audited, reviewed, compiled, or performed any procedures with respect to the projections for the purpose of their inclusion in this presentation, and accordingly, have not expressed an opinion or provided any other form of assurance with respect thereto for the purpose of this presentation. These projections are for illustrative purposes only and should not be relied upon as being indicative of future results. The assumptions and estimates underlying the projected information are inherently uncertain and are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the projected information. Even if NOG’s assumptions and estimates are correct, projections are inherently uncertain due to a number of factors outside NOG’s control. Accordingly, there can be no assurance that the projected results are indicative of NOG’s future performance or that actual results will not differ materially from those presented in the projected information. Inclusion of the projected information in this presentation should not be regarded as a representation by any person that the results contained in the projected information will be achieved. Estimates for NOG’s future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. NOG’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, NOG can give no assurance that its future production volumes will be as estimated.