Slides
Page 1
Investor Presentation May 2025
Page 2
GPOR | 2 Forward Looking Statements & Non-GAAP Financial Measures This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actua l results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward -looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect or anticipate will or may occur in the future, including the expected impact of U.S. trade policy and its impact on broader economic conditions, the war in Ukraine and the conflict in the Middle East on our business, our industry and the global economy, estimated future production and net revenue s from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), share repurchases, business strategy and measures to implement strategy, competitive strength, go als, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. Although we believe our estimates and assumptions to be re asonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all re aders that the forward-looking statements contained in this presentation are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward -looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward - looking statements due to the factors listed in Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Gulfport’s Annual Report on Form 10 -K for the year ended December 31, 2024, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in G ulfport’s Quarterly Reports on Form 10-Q and all forward-looking statements speak only as of the date of this presentation. Gulfport’s proved reserves and adjusted proved reserves are those quantities of natural gas, oil, and natural gas liquids, wh ich, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating meth ods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabil istic methods are used for the estimation. Gulfport’s estimate of its total proved reserves are internally generated and audited by Netherland, Sewell Associates, Inc., independent petroleum engineers. Factors affecting ultimate recovery include the scope of Gulfport’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, avai lability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Estimates may change significantly as development of Gulfport’s natural gas, oil and natural gas liquids assets provide additional data. Gulfport’s production forecasts and expectations for future periods are dependent upon many assumpti ons, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases . Gulfport’s management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial p erformance, and believes that they are useful tools to assess Gulfport’s operating results. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), manageme nt believes that these financial measures are useful to an investor in evaluating Gulfport because ( i) analysts utilize these metrics when evaluating company performance and have requested this information as of a recent practic able date, (ii) these metrics are widely used to evaluate a company’s operating performance, and (iii) we want to provide updated information to investors. Investors should not view these metrics as a substitute for measures of per formance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies. T hese non-GAAP financial measures include adjusted EBITDA, adjusted free cash flow, recurring general and administrative expense and present value of estimated future net revenue. A reconciliation of each financial measure to i ts most directly comparable GAAP financial measure is included as part of this presentation. These non - GAAP measure should be considered in addition to, but not instead of, the financial statements prepared in accordance with GA AP.
Page 3
GPOR | 3 2025E Activity Gulfport Energy Overview 1. Market capitalization calculated as of 4/30/25 at a price of $172.50 per share using shares outstanding from the Company’s 1Q2025 10-Q filing. 2. Enterprise value calculated as of 4/30/25 at a price of $172.50 per share using shares outstanding, long-term debt, preferred stock and cash and cash equivalents from the Company’s 1Q2025 10-Q financial statements. The impact of the conversion of the 32,887 outstanding preferred shares would increase common shares outstanding by ~2.3 million common shares and increase the EV / 2026 Adjusted EBITDA multiple by 0.37x to 4.1x. 3. As of 3/31/25 and calculated as $5.3 million cash plus $901.1 million borrowing base availability, which takes into effect $35.0 million of borrowings on revolver and $63.9 million of letters of credit. 4. As of 3/31/25 using net debt to LTM Adjusted EBITDA. Net debt and Adjusted EBITDA are non-GAAP measures. Net debt is defined as total long-term debt minus cash and cash equivalents. 5. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Adjusted free cash flow excludes discretionary acreage acquisitions and common stock repurchases. Adjusted free cash flow yield is calculated using adjusted free cash flow divided by market capitalization using shares outstanding from the Company’s 1Q2025 10-Q filing. 6. Appalachia acreage includes ~208,000 Utica and ~20,500 Marcellus net reservoir acres. SCOOP acreage includes ~43,000 Woodford and ~30,000 Springer net reservoir acres. 7. EBITDA estimate sourced from Factset as of 4/30/25. Utica and Marcellus YE24 Net Reservoir Acres(6): ~228,500 YE24 Proved Reserves: 3.0 Net T cfe 1Q25 Net Production: ~731 MMcfe/day SCOOP YE24 Net Reservoir Acres(6): ~73,000 YE24 Proved Reserves: 1.0 Net T cfe 1Q25 Net Production: ~198 MMcfe/day Key Highlights NYSE: GPOR Market Cap(1): $3.1 Billion Enterprise Value (‘EV’)(2): $3.8 Billion EV / 2026 EBITDA(2,7): 3.8x Liquidity(3): ~$906 Million Leverage(4): 0.92x D&C Capital: $335 – $355 Million Maintenance Leasehold Capital: $35 – $40 Million 2025E T otal Base Capital: $370 - $395 Million 2025E T otal Net Equivalent Production: 1,040 – 1,065 MMcfe/day 2025E Net Liquids Production: 18.0 – 20.5 MBbl/day ~89% Natural Gas Top-decile adjusted free cash flow yield(5) relative to natural gas peers Remaining Inventory: ~500 gross operated >12 years of net inventory at attractive rates of return ~80% ~20% Utica / Marcellus SCOOP ~83% ~7% ~10% Utica / Marcellus SCOOP Land 2025E Production Mix2025E Capital Program Reaffirmed
Page 4
GPOR | 4 Focused Strategy and Compelling Valuation 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. High Quality Asset Base Natural Gas Weighted with Liquids Opportunities • Multi-basin portfolio provides diversification and capital allocation optionality • Capture value accretion in Utica, Marcellus and SCOOP liquids-rich development and prolific Utica dry gas development • Low breakeven inventory supports sustainable returns and adjusted free cash flow(1) generation Committed to Responsible Stewardship • Safety of employees, contractors and communities is our highest priority • Achieved overall “A” rating for Appalachia assets from MiQ for second consecutive year • Provide community support through giving and volunteering in our operating areas Improve Margins and Free Cash Flow Generation Enhance Shareholder Value through Disciplined Capital Allocation Maintain Strong Balance Sheet • Focus on continuously improving cycle times and reducing operating costs • T op decile adjusted free cash flow(1) yield and positive adjusted free cash flow(1) across wide range of commodity prices • Maintain financial strength and flexibility to execute strategic and operating plans in volatile commodity environment • Hedging program reduces commodity risk and future cash flow volatility • Return capital to shareholders through repurchase of undervalued common stock • Reinvest in strategic acquisition opportunities that provide operating synergies, quality resource depth and optionality to our near-term development activities
Page 5
GPOR | 5 32% 58% -60% -30% 0% 30% 60% GPOR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Upside to NAV Upside (Strip then $65 WTI/$3.75 HH) Upside (Strip then $65 WTI/$4.25 HH) Return of Capital ($MM) FY 2023 FY 2024 Annual adjusted free cash flow(1) $199 $257 Less: discretionary acreage acquisitions ($48) ($45) Less: shares repurchases executed ($149) ($203)(3) Remaining adjusted free cash flow(1) available $2 $9 % of adjusted free cash flow returned to shareholders 99% 96% Completed Available • Common stock repurchase program authorizes purchases up to $1.0 billion of Gulfport outstanding shares • As of March 31, 2025, ~$644 million returned to shareholders since March 2022 at an average price of $108.99 per share • Total reduction of ~5.9 million shares, reducing common stock outstanding by approximately 17% since the initial authorization date in March 2022 • Expect to allocate substantially all FY 2025 adjusted free cash flow(1), excluding discretionary acreage acquisitions, towards common stock repurchases Delivering Value For Shareholders Common Stock Repurchase Program $1.0 Billion Stock Repurchase Authorization ~$356 million Available under current authorization ~$644 million Repurchased as of March 31, 2025, retiring ~5.9 million shares Common Stock Repurchases 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. 2. Sourced from Enverus Intelligence 4Q2024 Gas NAV Compass. All mentions of NAV are on a post-tax basis. Utilized strip prices as of 4/10/25 and share prices as of 4/17/25. Peers include AR, CNX, CRK, EQT, EXE & RRC. 3. Includes $18.4 million to satisfy tax withholding requirements incurred upon vesting of initial emergence performance stock units granted to certain executive officers in 2021. NAV Valuation Upside to Current Share Price(2)
Page 6
GPOR | 6 Base Assumptions Upside Potential Net Production: Low single digit growth of 0% – 5% Improving base decline, reduced cycle times, potential uplift from managed pressure programs and increase in liquids production Cash Costs: $1.32 – $1.43 / Mcfe Reducing per unit cash costs which includes LOE, GP&T, taxes other than income and G&A T otal Capital: $335 – $355 Million D&C $35 – $40 Million Land Continued operational efficiencies, cost reductions and lower maintenance land spend Differentials: Natural Gas: $0.20 - $0.35 off NYMEX Oil: $5.50 - $6.50 off WTI NGL: 40% - 50% of WTI Optimizing marketing strategy to improve sales points reached and realizations Commodity Prices: Flat price scenarios Commodity price improvements 0% 5% 10% 15% 20% GPOR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 FCF Yield 2025E 2026E Adjusted Free Cash Flow Generation Potential 2025E – 2029E Adjusted Free Cash Flow(1,2,3) Illustration ($MM) Adjusted Free Cash Flow Yield(4,5) 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. 2. Based upon flat price cases and base assumptions per year. Includes current hedge position as of April 30, 2025. 3. No payment of cash income taxes assumed in illustration. Company does not currently anticipate paying significant cash income taxes over next five years (estimating <10% of cumulative 5-year adjusted free cash flow). 4. Sourced from J.P. Morgan E&P Valuation Analysis utilizing J.P. Morgan estimates & Bloomberg Finance L.P.; Strip pricing as of 4/7/25 ($63.65/$59.47 per bbl WTI & $4.07/$4.23 per MMBtu NYMEX gas in 2025-26); Share prices as of 4/7/25. Peers include AR, CNX, CTRA, EQT, EXE, NFG, & RRC. 5. Adjusted FCF Yield is calculated using estimated adjusted free cash flow divided by current market capitalization. 6. Market capitalization calculated as of 4/30/25 at a price of $172.50 per share using shares outstanding from the Company’s 1Q2025 10-Q filing. • Sustainable free cash generation underpinned by high-quality assets • Meaningful adjusted free cash flow profile generating ~75% - 110% of market capitalization(6) over the next five years • Delivering highest adjusted free cash flow yield among natural gas peers • The focus on maintenance leasehold and land spend, in combination with our discretionary acreage acquisitions, have bolstered our future drilling programs and lowered our go-forward maintenance land spend Key Highlights 2025E 2026E 2027 Cum ~$2.5 Billion $3.50 NYMEX & $70 WTI $4.00 NYMEX & $70 WTI 2025E 2026E 20262 20272027 – 2029E Cum 5-Year 2027 – 2029E Cum 5-Year ~$3.3 Billion
Page 7
GPOR | 7 $370 – $395 Million 1.04 – 1.065 Bcfe/day $1.20 – $1.29 per Mcfe Return substantially all adjusted free cash flow(3), excluding acquisitions, towards common stock repurchases 18.0 – 21.5 MBbls/day $159.8 Million 0.92x First Quarter 2025 Results 1. Excludes $1.4 million and $1.2 million of non-D&C capital and non-operated D&C capital for 1Q2025, respectively. 2. Includes LOE, GP&T and taxes other than income. 3. Adjusted EBITDA and adjusted free cash flow are non -GAAP financial measures; see supplemental slides. Adjusted free cash flow ex cludes discretionary acreage acquisitions and common stock repurchases. 4. As of 3/31/2025 using net debt to LTM Adjusted EBITDA. Net debt and Adjusted EBITDA are non -GAAP measures. Net debt is defined a s total long-term debt minus cash and cash equivalents. • Delivered 1Q2025 performance ahead of Company expectations and on track to execute on our previously provided full year guidance • Realized natural gas price equivalent, before the effect of hedges, of $4.11 per Mcfe, a $0.45 per Mcfe premium to NYMEX • Repurchased 5.9 million shares of common stock for ~$644.1 million since March 2022 • Reaffirming full year 2025 guidance with natural gas production expected to increase ~20% by fourth quarter 2025 compared to first quarter 2025 • Reallocating drilling activity in late 2025 toward dry gas Utica development to bolster 2026 development economics and adjusted free cash flow generation • Achieved significant drilling efficiencies with average drilling footage per day improving 28% over full year 2024 • Accomplished all-time high completion efficiencies in April 2025 with 105.5 continuous pumping hours on a pad • Completed spring borrowing base redetermination of revolving credit facility and reaffirmed borrowing base at $1.1 billion with elected commitments remaining at $1.0 billion Key Highlights Incurred Capital Expenditures(1) T otal Net Production 1Q2025 Per Unit Operating Cost(2) Adjusted Free Cash Flow(3) Quarter-end Leverage (Net Debt(4) to Adjusted EBITDA(3)) Common Stock Repurchases 929.3 Mcfe/day $1.31 per Mcfe $36.6 Million $60.0 Million Full Year 2025 Guidance T otal Liquids Net Production 15.2 MBbls/day Maintain financial strength
Page 8
GPOR | 8 Reaffirm Full Year 2025 Guidance 1. Assumes the midpoint of 2025 guidance. 2. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Adjusted free cash flow yield is calculated using adjusted free cash flow and dividing by current market capitalization. Total Net Production 1,040 – 1,065 MMcfe/day Per Unit Operating Cost $1.20 – $1.29 per Mcfe Continuous optimization of per unit operating expenses, including LOE, taxes other than income and transportation, gathering, processing and compression costs Forecast flat net daily equivalent production to FY 2024, with natural gas as a percent of total production totaling ~89% for FY 2025 Net Liquids Production 18.0 – 20.5 MBbl/day Expect >30%(1) liquids production growth compared to FY 2024, driving strong margins and adjusted free cash flow generation Incurred Total Base Capital $370 – $395 Million Optimized development program and portfolio allocation expected to drive capital efficiencies and deliver strong corporate margins Resilient Adjusted Free Cash Flow Generation and Yield(2) Compelling valuation for shareholders with top-decile yield relative to peers and increasing adjusted free cash flow generation in improving natural gas commodity environment Reaffirmed Reaffirmed Reaffirmed Reaffirmed
Page 9
GPOR | 9 2022 2023 2024 1Q2025 2022 2023 2024 2025E Significant Improvement in Operational Efficiencies Ohio Drilling and Completion Efficiencies Average Total Footage per Day Average Frac Pumping Hours Utica D&C Cost Per Lateral FtAverage Plugs Drilled per Day 2022 2023 2024 1Q2025 Improved drilling efficiency by ~98% since 2022 and ~28% over FY2024 Improved completion efficiency by ~26% since 2022 2022 2023 2024 1Q2025 Improved drill out efficiency by ~110% since 2022 and ~5% over FY2024 Combined efficiencies translate to D&C per ft ~35% lower since 2022 < $900 / ft 1Q2025 Drilling Highlights • Best Top Hole days on well • Best Spud to Rig Release (15,000’ LL) • Best Spud to Rig Release (>20,000’ LL) • Best 24hr footage in lateral 1Q2025 Completion Highlights • Exceeded both FY2022 and FY2023 despite unseasonably low water levels impacting 1Q2025 • Water sourcing issues eliminated in 2Q2025 and in April 2025 accomplished all-time high completion efficiencies with 105.5 continuous pumping hours on a pad
Page 10
GPOR | 10 Capital Program • Reallocating drilling activity in 2H2025 to dry gas Utica development to bolster 2026 development economics and adjusted free cash flow • Optimized development program and portfolio allocation expected to drive capital efficiencies and robust adjusted free cash flow generation • Reaffirm total D&C capital of $335 – $355 million • Forecast investing $35 – $40 million on maintenance leasehold and land Production • Anticipate natural gas production to increase by approximately 20% by fourth quarter 2025 compared to first quarter 2025 • Reaffirm full year 2025 net daily equivalent production in the range of 1,040 – 1,065 MMcfe/day • Full year 2025 net daily liquids production to increase over 30%(1) compared to full year 2024, in the range of 18.0 to 20.5 MBbl/day $0 $200 1Q2025 2Q2025 3Q2025 4Q2025 $ Millions Utica / Marcellus SCOOP Maintenance Leasehold Actual 2025 Capital Program and Production Outlook - 500 1,000 1Q2025 2Q2025 3Q2025 4Q2025 MMcfe/day Natural Gas NGL Oil Actual Forecasted Total Capital Expenditures Forecasted Total Net Production 1. Assumes the midpoint of 2025 guidance. Forecasting ~75% of total capital to be allocated during 1H2025
Page 11
GPOR | 11 2025 Development Plan Overview • Extended Utica inventory by >2.5 years through discretionary acreage acquisitions largely within the wet gas area of the play and prioritized for near term development • Continue to optimize well performance and implement a managed pressure program, yielding consistent EUR’s per well • Plan to drill 20 gross wells and turn-to-sales 22 gross wells during 2025 Utica Key Highlights 3 Well Pad Spud: 4Q2025 4 Well Pad Spud: 2Q2024 TIL: Late 1Q2025 4 Well Pad Spud: 4Q2024 TIL: 2Q025 4 Well Pad Spud: 4Q2024 TIL: 2Q025 • Marcellus development is within Utica footprint and captures value enhancement through stacked pay synergies and liquids optionality • Estimate 55 – 65 locations, >2 years(1) of drillable inventory • Plan to drill and turn-to-sales 4 gross wells during 2025 Marcellus Key Highlights 1. Based on assumed development cadence of approximately 20 to 25 wells per year. 3 Well Pad Spud: 3Q2024 TIL: Late 1Q2025 4 Well Pad Spud: 1Q2025 TIL: 3Q2025 3 Well Pad Spud: 1Q2025 TIL: 3Q2025 Marcellus 4 Well Pad Spud: 1Q2025 TIL: 2Q2025 • Targeting high return, liquids-rich development in the SCOOP • Plan to complete drilling and turn-to-sales 2 gross wells during 2025 SCOOP Key Highlights 4 Well Pad Spud: 3Q2025 Legend Gulfport Core Acreage Area Pads Turned-in-Line
Page 12
GPOR | 12 - 5,000 10,000 - 400 800 1,200 1,600 2,000 0 10 20 30 Gross Gas (Mcf/d) / Flowing Pressure (PSI) Gross Oil Volume (Bo/d) Producing Days - 350 Marcellus Utica Condensate Utica Wet Gas Utica Dry Gas Cumulative Bbls 1 Month 6 Months 12 Months Recent Condensate Well Performance Utica Liquids-Rich Development Providing Strong Results 1. Production rate normalized to 15,000 ft lateral and assumes ethane rejection, per Gulfport’s gathering contracts. Kage Avg IP30 in full ethane recovery totals 3,240 Boe/d, 56% oil and 77% liquids. Lake VII Avg IP90 in full ethane recovery totals 2,011 Boe/d, 44% oil and 75% liquids. 2. Representing average cumulative production by type curve area over the next five years of development. Utica Wet Gas assumes oil yield of < 15 Bbl / MMcf. Production data normalized to 15,000 ft lateral. 3. Based on flat $3.50 / Mcf natural gas and $70 / Bbl oil. Average internal rates of returns based on a 15,000’ lateral length type curve for each defined development area over the next five years of development. • Turned-to-sales in March 2025, the Kage pad is located further west in the condensate window and delivering strong oil production • Well productivity, optimized facility design and revised managed pressure flowback delivering normalized rates nearly double the Lake VII development • Avg IP30(1): ~3,095 Boe/d, 59% Oil, 74% Liquids Key Highlights Utica dry gas, Utica liquids and Marcellus providing returns in excess of 70% IRR Cumulative MMcfe Production(2,3) Cumulative Liquids Production(2) Kage Pad Daily Production History Daily Oil Rate Daily Gas Rate Flowing Tubing Pressure Well Level Free Cash Flow Generated First 24 Months(2) ($MM) $3.00 Gas / $70 Oil $3.50 Gas / $70 Oil $4.00 Gas / $70 Oil $ MM) Marcellus Utica Condensate Utica Wet Gas Utica Dry 0% 50% 100% - 10,000 Marcellus Utica Condensate Utica Wet Gas Utica Dry Gas Rates of Return Cumulative MMcfe 1 Month 6 Months 12 Months IRR Extended inventory by >2.5 years through discretionary acreage acquisitions largely within the Utica wet gas window Lake VII Pad (Normalized to 15,000’ LL) Avg IP90(1): ~1,797 Boe/d 50% Oil, 67% Liquids Kage Pad (Normalized to 15,000’ LL) Avg IP30(1): ~3,095 Boe/d 59% Oil, 74% Liquids
Page 13
GPOR | 13 • Diversified and right-sized takeaway capacity • 625,000 MMBtu/d(1) of firm takeaway from the Utica • 200,000 MMBtu/d(1) of firm takeaway from the SCOOP • Strategic connectivity from wellhead provides access to premium basin egress pipelines and netback enhancement • Premium Gulf Coast transportation allows delivery to growing LNG demand center and industrial corridor at NYMEX-plus pricing • Proactively hedge in-basin exposure to secure pricing Advantaged Firm Portfolio Provides Access to Diverse Markets 1. Primary reservation volume only. Excludes zero-leg and secondary-leg reservation volume. Assumes run-rate gross reservation volume on a MMBtu/d basis. 2. Percentages represent approximate gross production exposure to basin regions. Regional Exposure(1) 2025E(2) Midwest 450,000 MMBtu/d firm takeaway 30% - 40% Gulf Coast 175,000 MMBtu/d firm takeaway 10% - 15% MidCon 200,000 MMBtu/d firm takeaway 15% - 20% In-Basin Exposure 30% – 40% MidCon SCOOP Basin (NGPL TexOK, OGT, NGPL Midcon) Premium Gulf Coast (TGP 500L, Transco St 85) Midwest (Chicago CG, REX Z3, Lebanon) Utica Basin (Tetco M2, TGP 200L)
Page 14
GPOR | 14 No Significant Maturities Until 2028 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2025 2026 2027 2028 2029 ($ Millions) First Quarter 2025 Overview Strong Capital Structure and Financial Profile 1. Liquidity as of 3/31/2025 and calculated as $5.3 million cash plus $901.1 million borrowing base availability, which takes into effect $35.0 million of borrowings on revolver and $63.9 million of letters of credit. 2. As of 3/31/2025 using net debt to TTM Adjusted EBITDA. Net debt is a non-GAAP measure. It is defined as total long-term debt minus cash and cash equivalents. As of March 31, 2025 Coupon 6.750% $650 Outstanding L/Cs Total Elected Commitments Senior Notes Maturity Sept 2029 Cash and Liquidity • $5.3 million of cash equivalents • ~$906 million of liquidity(1) Debt • $35.0 million borrowings under credit facility • $25.7 million of senior notes due 2026 • $650 million of senior notes due 2029 • Leverage of 0.92x(2) Preferred Equity • Preferred stock: 32.9 thousand shares • Dividend: 10% Cash / 15% Payment-in-Kind • Convertible to ~2.3 million common shares Common Equity • Common stock: 17.8 million shares • Authorized common stock repurchase of up to $1.0 billion • Repurchased ~$644.1 million as of March 31, 2025 Maturity Sept 2028 $1.1B Borrowing Base $1,000 Borrowings under Credit Facility Elected Commitment Under Credit Facility $1.1B Borrowing Base Maturity 2026 Coupon 8.000% $25.7
Page 15
GPOR | 15 • Achieved overall “A” rating for Appalachia assets from MiQ for second consecutive year • Lowered Scope 1 methane intensity rate(1) by 36% over the last 3 years • Conducted Company’s first climate risk assessment and integrated climate- related risk into Enterprise Risk Management (ERM) program • Reused or recycled ~75% of our water generated from production and flowback • Progressed in multi-year program to convert natural-gas driven pneumatic devices to air in the SCOOP Focused on Continuous Improvement and Responsible Stewardship • Reduced combined total recordable incident rate by 44% in 2024 compared to 2023 and 74% since 2021 • Partnered with organizations that support Gulfport’s key focus areas: education, health and human services, environmental stewardship and military and veterans • Paid over $360 million in royalties to local landowners and working interest owners in 2023 • Experienced 7-member board including, 5 independent directors • Separated role of Chairman and CEO while retaining Lead Independent Director role • Increased environmental, safety, and governance short-term compensation incentive metrics to a 30% weighting EnvironmentalSocial Governance Reduced Combined Total Recordable Incident Rate 74 % since 2021 Vendor Code of Conduct can be found on Gulfport’s website Improved Methane Intensity Rate 36% (1) since 2021 For additional information please refer to Gulfport’s Corporate Sustainability Report Note: More details on our initiatives can be found on the Gulfport website: www.gulfportenergy.com 1. Reported full year 2023 and based on EPA required Subpart W reporting. www.gulfportenergy.com/sustainability
Page 16
Appendix
Page 17
GPOR | 17 SEC YE 2024 YE 2024 YE 20242 YE 20243 PDP PDNP PUD ~$1.8 Billion ~$3.0 Billion(4) ~$3.8 Billion(4) ~$4.6 Billion(4) 2024 Proved Reserve Summary 1. Per Company reserve report for year ending 12/31/24. 2. Proved undeveloped reserves, under SEC reserve reporting guidelines, only includes wells scheduled to be drilled within the next five years. 3. PV-10 is a non-GAAP measure; see supplemental slides. 4. Flat price cases at stated price scenarios. Net Reserves as of December 31, 2024(1) Gas Oil NGL Total (Bcf) (MMBbls) (MMBbls) (Bcfe) Proved Developed Producing 1,844 7 29 2,061 Proved Developed Non-Producing 34 0 2 47 Proved Undeveloped(2) 1,478 15 49 1,861 Total Proved Reserves 3,356 22 80 3,969 Proved Reserve Components SEC Year End Proved Reserves PV-10(3,4) 52%47% PDP PDNP PUD 85% 3% 12% Gas Oil NGL $3.50 Gas / $70.00 Oil $3.00 Gas / $70.00 Oil $2.13 Gas / $76.32 Oil $4.00 Gas / $70.00 Oil
Page 18
GPOR | 18 Incurred Capital Expenditures – $ millions Operated D&C $335 $355 Maintenance Leasehold and Land $35 $40 T otal Base Capital Expenditures $370 $395 Production Net Daily Gas Equivalent – MMcfe/day 1,040 1,065 Net Daily Liquids Production – MBbls/day 18.0 20.5 % Gas ~89% Realizations (before hedges)(1) Natural Gas (Differential to NYMEX) - $/Mcf ($0.20) ($0.35) NGL (% of WTI) 40% 50% Oil (Differential to NYMEX WTI) - $/Bbl ($5.50) ($6.50) Expenses Lease Operating Expense - $/Mcfe $0.19 $0.22 Taxes Other Than Income - $/Mcfe $0.08 $0.10 GPT&C - $/Mcfe $0.93 $0.97 Recurring Cash G&A(2) - $/Mcfe $0.12 $0.14 Reaffirm Full Year 2025 Guidance FY 2025E Note: Guidance for the year ending 12/31/25 is based on multiple assumptions and certain analyses made by the Company based o n its experience and perception of historical trends and current conditions and may change due to future developments. Actual re sults may not conform to the Company’s expectations and predictions. Please refer to page 2 for more detail of forward -looking statements. 1. Based upon current forward pricing at April 16, 2025 and basis marks. 2. Recurring cash G&A is a non-GAAP financial measures; see supplemental slides. 3. Adjusted free cash flow is a non-GAAP financial measures; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. • Significant increase in adjusted free cash flow(3) generation in current commodity market(1) • Plan to allocate substantially all adjusted free cash flow(3), excluding acquisitions, towards common stock repurchases 2025E Adjusted Free Cash Flow Generation Guidance FY 2025E Guidance
Page 19
GPOR | 19 Utica Dry Gas Utica Wet Gas Utica Condensate Marcellus SCOOP TIL Well Mix Development Plan Overview Well Count Lateral Spud Drilled Turned-to-Sales 2024 Operated Activity Utica Dry Gas 11 gross (10.8 net) 15,800’ Utica Wet Gas 3 gross (3.0 net) 17,800’ Utica Condensate 6 gross (5.9 net) 13,100’ Marcellus - - SCOOP 2 gross (1.8 net) 11,500’ Utica Dry Gas 10 gross (9.8 net) 17,100’ Utica Wet Gas - - Utica Condensate 8 gross (7.6 net) 14,700’ Marcellus - - SCOOP 3 gross (2.4 net) 12,400’ Utica Dry Gas 12 gross (11.7 net) 18,000’ Utica Wet Gas - - Utica Condensate 4 gross (3.6 net) 17,300’ Marcellus - - SCOOP 3 gross (2.4 net) 12,400’ Utica Dry Gas 14 gross (14.0 net) 16,900’ Utica Wet Gas 1 gross (1.0 net) 15,700’ Utica Condensate - - Marcellus 4 gross (4.0 net) 8,600’ SCOOP - - Utica Dry Gas 16 gross (15.9 net) 16,000’ Utica Wet Gas 4 gross (4.0 net) 17,300’ Utica Condensate - - Marcellus 4 gross (4.0 net) 8,600’ SCOOP 2 gross (1.8 net) 11,500’ Utica Dry Gas 14 gross (14.0 net) 15,600’ Utica Wet Gas 4 gross (4.0 net) 17,300’ Utica Condensate 4 gross (4.0 net) 12,100’ Marcellus 4 gross (4.0 net) 8,600’ SCOOP 2 gross (1.8 net) 11,500’ 2025 Operated Activity Well Count Lateral 15,600 14,700 17,100 14,000 2024 2025E Drilled TILs Average Net Lateral Length 2024 2025E Note: Utica Wet Gas assumes oil yield of < 15 Bbl / MMcf.
Page 20
GPOR | 20 Tetco M2 Basis Rex Zone 3 Basis NGPL TXOK Basis TGP 500 Basis Transco Station 85 Basis Swaps Swaps Swaps Swaps Swaps Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu 2Q 2025 230,000 ($0.96) 110,000 ($0.20) 40,000 ($0.29) 10,000 $0.31 5,000 $0.38 3Q 2025 230,000 ($0.96) 110,000 ($0.20) 40,000 ($0.29) 10,000 $0.31 5,000 $0.38 4Q 2025 230,000 ($0.96) 110,000 ($0.20) 40,000 ($0.29) 10,000 $0.31 5,000 $0.38 FY 2025(2) 230,000 ($0.96) 110,000 ($0.20) 40,000 ($0.29) 10,000 $0.31 5,000 $0.38 1Q 2026 130,000 ($0.98) 80,000 ($0.18) 30,000 ($0.30) 10,000 $0.54 5,000 $0.52 2Q 2026 130,000 ($0.98) 80,000 ($0.18) 30,000 ($0.30) 10,000 $0.54 5,000 $0.52 3Q 2026 130,000 ($0.98) 80,000 ($0.18) 30,000 ($0.30) 10,000 $0.54 5,000 $0.52 4Q 2026 130,000 ($0.98) 80,000 ($0.18) 30,000 ($0.30) 10,000 $0.54 5,000 $0.52 FY 2026 130,000 ($0.98) 80,000 ($0.18) 30,000 ($0.30) 10,000 $0.54 5,000 $0.52 Natural Gas Oil Propane Swaps Collars Calls Sold Swaps Swaps Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Put $/MMBtu Avg. Call $/MMBtu Volume MMBtu/d Avg. Call $/MMBtu Volume Bbl/d Avg. Price $/Bbl Volume Bbl/d Avg. Price $/Bbl 2Q 2025 270,000 $3.82 233,407 $3.40 $4.26 200,000 $5.76 3,000 $73.29 2,000 $30.09 3Q 2025 270,000 $3.82 240,000 $3.42 $4.27 200,000 $5.76 3,000 $73.29 3,000 $29.89 4Q 2025 270,000 $3.82 240,000 $3.42 $4.27 173,478 $5.93 3,000 $73.29 3,000 $29.89 FY 2025(2) 270,000 $3.82 237,818 $3.41 $4.26 191,127 $5.81 3,000 $73.29 2,669 $29.94 1Q 2026 200,000 $3.64 170,000 $3.63 $4.48 - - - - 2,000 $30.12 2Q 2026 200,000 $3.64 170,000 $3.63 $4.48 - - - - 2,000 $30.12 3Q 2026 200,000 $3.64 170,000 $3.63 $4.48 - - - - 1,000 $30.74 4Q 2026 200,000 $3.64 170,000 $3.63 $4.48 - - - - 1,000 $30.74 FY 2026 200,000 $3.64 170,000 $3.63 $4.48 - - - - 1,496 $30.33 Hedged Production Natural Gas, Oil and Propane Hedge Summary (1) 1. As of 4/30/25. 2. April 2025 – December 2025. Basis Hedge Summary(1)
Page 21
GPOR | 21 - 200 400 600 800 20 19 18 17 16 $15 14 $13 Top 12 11 Top 10 9 Top 8 7 6 5 4 3 Top 2 Top 1 12 Month Normalized Production by Well (MMcfe / 1,000’ of lateral) Gulfport Recent Utica Well Performance Note: Gulfport well data is sourced internally. All peer data sourced from Enverus. Includes all wells with equal or greater than 7,000’ lengths brought online since 2021 with at least twelve months of production data available. Peers include Ascent Resources, Encino Energy, EQT and Expand Energy. 1. Data is two-stream equivalents. Mcfe is equal to one thousand cubic feet of natural gas equivalent, with one barrel of oil being equivalent to 20,000 cubic feet of natural gas. - 100 200 300 400 500 600 700 Peer 4 Peer 3 Peer 2 Peer 1 Gulfport Normalized Cumulative Production (MMcfe / 1,000’ ft of lateral) 12 Months 6 Months Gulfport Utica Well Productivity Outperforming Peers(1) Top 20 Performing Utica Wells(1) Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport
Page 22
GPOR | 22 Recent SCOOP Well Performance Note: Gulfport well data is sourced internally. All peer data sourced from Enverus. Includes all wells with equal or greater than 7,000’ lengths brought online since 2021 with at least twelve months of production data available. Peers include Continental Resources, Devon Energy, ConocoPhillips and Ovintiv. 1. Data is two-stream equivalents. Mcfe is equal to one thousand cubic feet of natural gas equivalent, with one barrel of oil being equivalent to 20,000 cubic feet of natural gas. - 100 200 300 400 500 600 700 Peer 4 Peer 3 Peer 2 Peer 1 Gulfport Normalized Cumulative Production (MMcfe / 1,000’ ft of lateral) 12 Months 6 Months Gulfport Oklahoma Well Productivity Outperforming Peers(1) Top 20 Performing SCOOP / STACK Wells(1) - 200 400 600 800 1,000 20 19 Top 18 Top 17 Top 16 15 14 Top 13 12 11 10 9 Top 8 7 6 5 Top 4 Top 3 Top 2 Top 1 12 Month Normalized Production by Well (MMcfe / 1,000’ of lateral) Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport Gulfport
Page 23
GPOR | 23 Adjusted EBITDA is a non-GAAP financial measure equal to net (loss) income, the most directly comparable GAAP financial measure, plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion, net non-cash derivative loss (gain), non-recurring general and administrative expenses comprised of expenses related to the continued administration of our prior Chapter 11 filing, stock-based compensation and other items which include non-material expenses. Below is a reconciliation of net (loss) income (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. Adjusted EBITDA (In thousands) (Unaudited) Three Months Ended March 31, 2025 Three Months Ended March 31, 2024 Net (loss) income (GAAP) $ (464) $ 52,035 Adjustments: Interest expense 13,356 15,003 Income tax (benefit) expense (176) 14,853 DD&A and accretion 66,240 80,578 Non-cash derivative loss 136,658 20,186 Non-recurring general and administrative expenses 365 810 Stock-based compensation expenses 3,040 2,403 Other, net (702) (125) Adjusted EBITDA (Non-GAAP) $ 218,317 $ 185,743
Page 24
GPOR | 24 Adjusted Free Cash Flow 1. Includes cash capitalized general and administrative expense and incurred capitalized interest expenses. 2. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. 3. For the three months ended March 31, 2025, includes $1.4 million and $1.2 million of non-D&C capital and non-operated capital expenditures, respectively. 4. For the three months ended March 31, 2024, includes $1.8 million and $2.7 million of non-D&C capital and non-operated capital expenditures, respectively. Adjusted free cash flow is a non-GAAP measure defined as adjusted EBITDA plus certain non-cash items that are included in net cash provided by (used in) operating activities but excluded from adjusted EBITDA less interest expense, current income tax expense (benefit), capitalized expenses incurred and capital expenditures incurred, excluding discretionary acreage acquisitions. Gulfport includes ranges of expectations for adjusted free cash flow for 2025. We are unable, however, 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. Accordingly, Gulfport is relying on the exception provided by Item 10(e)(1)(i)(B) of Regulation S-K to exclude such reconciliation. Items excluded in net cash provided by operating activities to arrive at adjusted free cash flow include interest expense, income taxes, capitalized expenses as well as one-time items or items whose timing or amount cannot be reasonably estimated. Below is a reconciliation of net cash provided by operating activities (the most comparable GAAP measure) to free cash flow. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. (In thousands) (Unaudited) Three Months Ended March 31, 2025 Three Months Ended March 31, 2024 Net cash provided by operating activity (GAAP) $ 177,280 $ 188,022 Adjustments: Interest expense 13,356 15,003 Non-recurring general and administrative expenses 365 810 Current income tax benefit (169) — Other, net (1,875) (1,138) Changes in operating assets and liabilities, net Accounts receivable - oil, natural gas, and natural gas liquids sales 2,118 (37,457) Accounts receivable - joint interest and other 20 4,145 Accounts payable and accrued liabilities 27,674 16,656 Prepaid expenses (485) (299) Other assets 33 1 Total changes in operating assets and liabilities $ 29,360 $ (16,954) Adjusted EBITDA (Non-GAAP) $ 218,317 $ 185,743 Interest expense (13,356) (15,003) Current income tax benefit 169 — Capitalized expenses incurred(1) (6,165) (5,654) Capital expenditures incurred, excluding discretionary acreage acquisitions (2,3,4) (162,362) (126,238) Adjusted free cash flow (Non-GAAP) $ 36,603 $ 38,848
Page 25
GPOR | 25 Recurring General and Administrative (G&A) Expense Recurring general and administrative expense is a non-GAAP financial measure equal to general and administrative expense (GAAP) plus capitalized general and adminis trative expense, less non-recurring general and administrative expenses comprised of expenses related to the continued administration of our prior Chapter 11 filing. Gulfport includes a recurring cash general and administrative expense estimate for 2025. We are unable, however, 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. Accordingly, Gulfport is relying on the exception provided by Item 10 (e)(1)(i) (B) of Regulation S-K to exclude such reconciliation. Items excluded in general and administrative expense to arrive at recurring general and administrative expense include capitalized expenses as well as one -time items or items whose timing or amount cannot be reasonably estimated. Below is a reconciliation of general and administrative expense (the most comparable GAAP measure) to recurring general and administrative expense. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. (In thousands) (Unaudited) Three Months Ended March 31, 2025 Three Months Ended March 31, 2024 Cash Non-Cash Total Cash Non-Cash Total General and administrative expense (GAAP) $ 5,961 $ 3,040 $ 9,001 $ 6,795 $ 2,403 $ 9,198 Capitalized general and administrative expense 4,734 1,498 6,232 4,522 1,183 5,706 Non-recurring general and administrative expense (365) — (365) (810) — (810) Recurring General and Administrative Expense (Non-GAAP) $ 10,330 $ 4,538 $ 14,868 $ 10,507 $ 3,586 $ 14,093 Totals may not sum or recalculate due to rounding
Page 26
GPOR | 26 Present value of estimated future net revenue (PV-10) Note: Reserves as of December 31, 2024 utilized prices of $76.32/Bbl of oil, $31.30/Bbl for NGLs and $2.13/MMBtu of natural gas. Reserves as of December 31, 2023 utilized prices of $78.21/Bbl of oil, $31.42/Bbl for NGLs and $2.64/MMBtu of natural gas. Prices are determined in accordance with the SEC requirement to use the unweighted arithmetic average of the first day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. PV – 10 is a non-GAAP measure derived from standardized measure of discounted future new cash flows (GAAP). Management uses PV -10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consi stent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. (In thousands) (Unaudited) December 31, 2024 December 31, 2023 Proved Developed Proved Undeveloped Total Proved Proved Developed Proved Undeveloped Total Proved Estimated future net revenue $1,620 $1,876 $3,496 $2,535 $2,235 $4,769 Present value of estimated future net revenue (PV-10) $1,059 $699 $1,757 $1,590 $819 $2,409 Standardized measure $1,747 $2,383
Page 27
Thank You. Investor Relations 405.252.4550 investor_relations@gulfportenergy.com www.gulfportenergy.com