Sign in
GE

GULFPORT ENERGY CORP (GPOR)·Q1 2025 Earnings Summary

Executive Summary

  • Q1 2025 came in ahead of company expectations with premium realizations (+$0.45/Mcfe vs Henry Hub) and reaffirmed full‑year 2025 guidance; adjusted EBITDA was $218.3M and adjusted FCF was $36.6M, despite front‑loaded capex and winter‑elevated unit costs .
  • Versus S&P Global consensus, GPOR delivered a revenue beat and a modest EPS beat, while reported (S&P standardized) EBITDA tracked below consensus due to definitional differences versus company‑reported adjusted EBITDA. Revenue $338.1M vs $320.7M consensus (+5.4%); EPS 5.63 vs 5.23 (+7.6%); S&P EBITDA $77.6M vs $202.5M; company adjusted EBITDA $218.3M (see estimates section for definitions and sources) .
  • Sequential volumes dipped as planned to 929.3 MMcfe/d on Q1 turn‑in‑line cadence and liquids mix, but management reiterated a ~20% increase in average daily natural gas production by 4Q25 vs 1Q25 and maintained 2025 production guidance of 1,040–1,065 MMcfe/d .
  • Capital allocation remained shareholder‑friendly: $60M of buybacks in Q1 (341K shares at ~$176) with $356M remaining authorization; liquidity stood at ~$906M and the $1.1B borrowing base was reaffirmed post‑quarter .

What Went Well and What Went Wrong

What Went Well

  • Premium gas realizations and marketing uplift: realized price of $4.11/Mcfe before hedges, a $0.45/Mcfe premium to Henry Hub; CFO highlighted differentials “ahead of analyst consensus expectations” and better than the narrow end of guidance .
  • Operational execution and efficiency: drilling footage/day improved ~28% vs FY24; record continuous pumping hours (97.5 and 105.5 hours) and <$900/ft Utica D&C target achieved; the Kage pad delivered early rates nearly 2x the high‑performing Lake VII pad due to design/flowback optimizations .
  • Capital returns and balance sheet: $60M buybacks in Q1; trailing 12‑month net leverage ~0.9x; liquidity ~$906M; lenders reaffirmed the $1.1B borrowing base with $1.0B elected commitments .

What Went Wrong

  • Planned sequential production decline: average production fell to 929.3 MMcfe/d (from 1.06 Bcfe/d in Q4) due to turn‑in‑line timing and liquids mix; management acknowledged the trade‑off with a front‑loaded program and shorter liquids plateaus .
  • Elevated unit cash costs seasonally: cash operating costs were $1.31/Mcfe, with winter weather impacts; LOE rose to $0.24/Mcfe (vs $0.18 y/y) and TGPC to $0.99/Mcfe (vs $0.90 y/y) .
  • GAAP optics: a small net loss ($0.5M) despite strong adjusted EBITDA, and S&P standardized EBITDA tracked below consensus while company‑reported adjusted EBITDA rose to $218.3M (definitional differences; see Estimates Context) .

Financial Results

GAAP financials vs prior periods (S&P Global)

MetricQ3 2024Q4 2024Q1 2025
Revenues ($)$211.418M*$279.684M*$338.144M*
Net Income ($)-$13.967M*-$273.242M*-$0.464M*
Diluted EPS (Continuing)-$0.834*-$15.336*-$0.074*
EBITDA ($)$158.969M*$82.173M*$77.636M*
EBITDA Margin (%)75.19%*29.38%*22.96%*
Net Income Margin (%)-6.61%*-97.70%*-0.14%*

* Values retrieved from S&P Global.

Non‑GAAP and cash flow metrics (company‑reported)

MetricQ3 2024Q4 2024Q1 2025
Adjusted EBITDA ($)$178.1M $202.8M $218.3M
Adjusted Free Cash Flow ($)$72.6M $125.2M $36.6M
Net Cash from Operating Activities ($)$189.7M $148.8M $177.3M

Production, realizations, and unit costs

KPIQ1 2024Q1 2025
Total Production (Mcfe/d)1,053,722 929,280
Gas (Mcf/d)973,564 837,816
Oil & Condensate (Bbl/d)3,329 5,282
NGL (Bbl/d)10,031 9,962
Avg Price (ex‑hedges, $/Mcfe)$2.48 $4.11
Realized incl. settled derivs ($/Mcfe)$3.16 $3.99
LOE ($/Mcfe)$0.18 $0.24
Taxes other than income ($/Mcfe)$0.09 $0.08
TGPC ($/Mcfe)$0.90 $0.99
Recurring cash G&A ($/Mcfe)$0.11 $0.12
Interest ($/Mcfe)$0.16 $0.16

Production by area (Q1 2025)

AreaNet Daily Production (MMcfe/d)
Utica/Marcellus731.1
SCOOP198.2

Capital and balance sheet highlights (Q1 2025)

  • Incurred capex: $159.8M (operated D&C $148.6M; land $11.2M; plus ~$1.2M non‑op) .
  • Liquidity: ~$906.5M (cash $5.3M + ~$901.1M revolver availability) .
  • Debt/LCs: $35.0M revolver, $25.7M 2026 notes, $650.0M 2029 notes, $63.9M LCs .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Avg daily production (MMcfe/d)FY 20251,040–1,065 1,040–1,065 Maintained
Avg daily liquids (MBbl/d)FY 202518.0–20.5 18.0–20.5 Maintained
Gas mix (%)FY 2025~89% ~89% Maintained
Operated D&C capex ($M)FY 2025335–355 335–355 Maintained
Total base capex ($M)FY 2025370–395 370–395 Maintained
LOE ($/Mcfe)FY 20250.19–0.22 0.19–0.22 Maintained
Taxes other than income ($/Mcfe)FY 20250.08–0.10 0.08–0.10 Maintained
TGPC ($/Mcfe)FY 20250.93–0.97 0.93–0.97 Maintained
Recurring cash G&A ($/Mcfe)FY 20250.12–0.14 0.12–0.14 Maintained
Gas differential to NYMEX ($/Mcf)FY 2025($0.20)–($0.35) ($0.20)–($0.35) Maintained
NGL (% of WTI)FY 202540%–50% 40%–50% Maintained
Oil differential to WTI ($/Bbl)FY 2025($5.50)–($6.50) ($5.50)–($6.50) Maintained
Program optimization2H 2025n/aAdd 4‑well Utica dry gas pad; defer 4‑well Marcellus pad to 2026 Optimization

Note: Management reaffirmed full‑year guidance on the call and in the Q1 release .

Earnings Call Themes & Trends

TopicPrevious Mentions (Q3’24, Q4’24)Current Period (Q1’25)Trend
Realizations/basisPremium all‑in realizations; hedge gains; diverse marketing; basis locked; Q4 all‑in $3.36/Mcfe, +$0.57 vs NYMEX $4.11/Mcfe pre‑hedge, +$0.45/Mcfe vs Henry Hub; diff better than consensus and better than guidance range Improving
Capital efficiency2025 per‑ft D&C down ~20% vs 2024; drilling footage/day +9% y/y; frac hours/day +25% Drilling footage/day +28% vs FY24; continuous pumping records; <$900/ft Utica D&C achieved Improving
Liquids vs gas mixQ3 added Utica condensate pad; pivot to liquids to boost margins; repurchases expanded Near‑term shift to more dry gas; add Utica dry gas pad; defer Marcellus pad to 2026; still liquids‑rich activity in 2025 Rebalancing to gas
Production cadenceFront‑loaded capex; rising production through the year; Q4 commentary detailed cadence Q1 planned trough on TIL timing and liquids decline; expect growth through 2025; ~20% NG increase by Q4 vs Q1 Seasonal/accelerating
M&A/acreage~$45M 2024 discretionary acreage; added liquids‑rich inventory Open to bolt‑ons; high bar; focused on dry/wet gas returns; discretionary acreage optionality highlighted Opportunistic
Hedging2025 ~50% gas protected with collars; upside above $4; less overall hedged in 2025–26 Strategy consistent; collars preserve upside; liquids still small to revenue Stable
MidstreamNew Marcellus G&P/Fx enhances NGL recovery (Q4 call) Assessing takeaway like Borealis on netback basis; uncommitted volumes are an advantage Optimizing

Management Commentary

  • “Gulfport began 2025 with strong momentum… shifted second‑half 2025 capital allocation towards natural gas drilling and reaffirmed full‑year guidance, driven primarily by a forecasted 20% growth in our natural gas volumes by the fourth quarter of 2025.” — John Reinhart .
  • “Our all‑in realized price for the first quarter was $4.11 per Mcfe before the impact of cash‑settled derivatives… $0.45 above the NYMEX Henry Hub index price, highlighting the benefit of our diverse marketing portfolio.” — Michael Hodges .
  • “The Kage [Utica condensate] is performing exceptionally well and delivering early rates nearly double those of the nearby Lake VII pad,” driven by frac design, facilities, and flowback strategy — John Reinhart .
  • “We are reaffirming our full year operated drilling and completion capital guidance of $335 million to $355 million.” — John Reinhart .
  • “We continue to forecast robust adjusted free cash flow generation during 2025 and… plan to return substantially all… through common stock repurchases.” — John Reinhart .

Q&A Highlights

  • Front‑loaded capex and production seasonality: Management does not “regret” the approach; Q1 lower volumes were planned; shift to dry gas should smooth plateaus and accelerate cash flow in peak pricing seasons .
  • 2025 program optimization and early 2026 setup: Deferring a Marcellus pad to 2026 and adding a dry‑gas Utica pad positions GPOR for a constructive gas macro in 2026; no specific 2026 guidance yet .
  • Netbacks/takeaway: GPOR will evaluate projects like Borealis expansion on a netback basis; uncommitted volumes provide flexibility to capture premium opportunities .
  • Cost/efficiency trajectory: <$900/ft Utica D&C is being achieved; further downside possible if current efficiency gains hold .
  • Hedging philosophy: Strategy unchanged; strong balance sheet enables strategic, upside‑preserving collars on gas; liquids hedging limited given revenue mix .
  • M&A posture: Open but high bar; preference for opportunities with undeveloped inventory that compete with buybacks and organic returns .

Estimates Context

S&P Global consensus vs reported (Q1 2025):

  • Revenue: $320.73M consensus vs $338.14M actual → Beat by $17.41M (+5.4%)*
  • Primary EPS (S&P normalized): 5.23 consensus vs 5.63 actual → Beat by 0.40 (+7.6%)*
  • EBITDA (S&P standardized): $202.51M consensus vs $77.64M actual → Miss (-$124.87M; -61.6%)*
  • Company‑reported adjusted EBITDA: $218.3M (non‑GAAP) .

Notes:

  • S&P “Primary EPS” and S&P “EBITDA” are standardized/normalized constructs which differ from company non‑GAAP metrics; GPOR’s adjusted EBITDA of $218.3M better reflects management’s operating performance framework .
  • CFO cited realized pricing and differentials that were ahead of consensus as key supports in Q1 .

* Values retrieved from S&P Global.

Key Takeaways for Investors

  • Reaffirmed 2025 plan with premium realizations and strong marketing execution; expect production to build through the year with ~20% higher natural gas volumes by 4Q25 vs 1Q25, a key setup for an improving 2026 gas macro .
  • Program optimization (dry‑gas shift in late 2025; Marcellus deferral) should enhance 2026 gas leverage while preserving 2025 liquids‑driven margin uplift; watch for updated TIL cadence and Q2/Q3 volumes .
  • Operational momentum is tangible: drilling/completions records, <$900/ft Utica costs, and standout Kage pad performance support well‑level returns and potential capex per‑ft downside .
  • Near‑term headwinds (Q1 seasonal costs, planned volume trough) appear transient; per‑unit costs are expected to decline as volumes ramp through 2025 within guided ranges .
  • Capital returns remain front‑and‑center (substantially all adjusted FCF to buybacks), underpinned by $906M liquidity and an unanimously reaffirmed $1.1B borrowing base .
  • Basis/marketing is a differentiator; management will selectively add takeaway where netbacks improve economics, leveraging uncommitted volumes .
  • Estimate revisions: Street models may raise 2025 realized price assumptions/differentials and modestly increase Q2–Q4 volumes; be mindful of metric definitions when comparing EBITDA prints (S&P standardized vs company adjusted) .

Additional Notes

  • We searched for a Q1 2025 “8‑K 2.02” item; none was available in the document catalog for the quarter. We relied on the Q1 press release and the full earnings call transcript instead .
  • Scheduling press release confirms timing/logistics for the May 7 call .