[10-Q] Kosmos Energy Ltd. Quarterly Earnings Report
Filing Impact
Filing Sentiment
Form Type
10-Q
Rhea-AI Filing Summary
Kosmos Energy (KOS) Q2-25 10-Q highlights
- Revenue deterioration: Q2 sales fell 13% YoY to $392.6 M; H1 revenue down 22% to $682.8 M, hurt by lower liftings and weaker Brent pricing.
- Earnings swing: Net loss of $87.7 M (-$0.18/sh) versus $59.8 M profit last year; H1 loss $198.3 M (-$0.42/sh). Gross production costs nearly doubled YoY to $243.1 M while DD&A rose 68% to $151.3 M.
- Cash squeeze: Operating cash flow collapsed to $126.3 M in H1 (vs $496.2 M); cash balance down to $51.7 M from $85.0 M at year-end.
- Leverage: Total debt enlarged to $2.90 B (+$100 M); current maturities $250 M due within 12 months. Net debt/EBITDAX exceeded covenant; lenders waived restricted-cash requirement and loosened the debt-cover ratio to 4.25× through Mar-26.
- Asset progress: Greater Tortue Ahmeyim (GTA) Phase 1 achieved commercial operations in Jun-25, triggering first LNG revenue and increasing long-term receivables from national oil companies to $444.7 M.
- Capex & hedging: H1 capex trimmed to $172.8 M (prior-year $553.0 M). ~8 MMbbl of 2025-26 production hedged with collars/swaps (floors $50-60/bbl).
- Equity impact: Book value slid 15% YTD to $1.02 B as accumulated deficit widened.
Outlook: Near-term liquidity rests on GTA cash inflow, Jubilee infill drilling and maintenance of covenant headroom. High debt load, rising operating costs and volatile oil prices remain key risks.
Kosmos Energy (KOS) risultati Q2-25 10-Q in evidenza
- Deterioramento dei ricavi: le vendite del Q2 sono diminuite del 13% su base annua, raggiungendo 392,6 M$; i ricavi del primo semestre sono calati del 22% a 682,8 M$, penalizzati da volumi di sollevamento inferiori e da prezzi Brent più deboli.
- Variazione degli utili: perdita netta di 87,7 M$ (-0,18$/azione) rispetto a un utile di 59,8 M$ dell’anno precedente; perdita semestrale di 198,3 M$ (-0,42$/azione). I costi di produzione lordi sono quasi raddoppiati su base annua a 243,1 M$, mentre gli ammortamenti e svalutazioni (DD&A) sono aumentati del 68% a 151,3 M$.
- Pressione sulla liquidità: il flusso di cassa operativo è crollato a 126,3 M$ nel primo semestre (rispetto a 496,2 M$); la liquidità disponibile è scesa a 51,7 M$ dai 85,0 M$ di fine anno.
- Indebitamento: il debito totale è salito a 2,90 Mld$ (+100 M$); scadenze correnti per 250 M$ entro 12 mesi. Il rapporto debito netto/EBITDAX ha superato il covenant; i finanziatori hanno rinunciato all’obbligo di cassa vincolata e hanno allentato il rapporto di copertura del debito a 4,25× fino a marzo 2026.
- Progresso degli asset: la Fase 1 di Greater Tortue Ahmeyim (GTA) ha raggiunto operazioni commerciali a giugno 2025, generando i primi ricavi da LNG e aumentando i crediti a lungo termine verso compagnie petrolifere nazionali a 444,7 M$.
- Capex e coperture: il capex del primo semestre è stato ridotto a 172,8 M$ (rispetto a 553,0 M$ dell’anno precedente). Circa 8 milioni di barili di produzione 2025-26 sono coperti da contratti collar e swap (prezzi minimi di 50-60$/barile).
- Impatto sul patrimonio netto: il valore contabile è sceso del 15% da inizio anno a 1,02 Mld$ a causa dell’aumento del deficit accumulato.
Prospettive: la liquidità a breve termine dipende dai flussi di cassa di GTA, dalle perforazioni di completamento a Jubilee e dal mantenimento del margine sui covenant. Rischi principali rimangono l’elevato indebitamento, i costi operativi in aumento e la volatilità dei prezzi del petrolio.
Aspectos destacados del Q2-25 10-Q de Kosmos Energy (KOS)
- Deterioro de ingresos: las ventas del segundo trimestre cayeron un 13% interanual hasta 392,6 M$; los ingresos del primer semestre bajaron un 22% a 682,8 M$, afectados por menores volúmenes de levantamiento y precios Brent más débiles.
- Variación en ganancias: pérdida neta de 87,7 M$ (-0,18$/acción) frente a una ganancia de 59,8 M$ el año pasado; pérdida en el primer semestre de 198,3 M$ (-0,42$/acción). Los costos brutos de producción casi se duplicaron interanual a 243,1 M$, mientras que DD&A aumentó un 68% a 151,3 M$.
- Presión de efectivo: el flujo de caja operativo colapsó a 126,3 M$ en el primer semestre (vs 496,2 M$); el saldo de efectivo bajó a 51,7 M$ desde 85,0 M$ a fin de año.
- Apalancamiento: la deuda total aumentó a 2,90 B$ (+100 M$); vencimientos actuales de 250 M$ a pagar en 12 meses. La deuda neta/EBITDAX excedió el covenant; los prestamistas renunciaron al requisito de efectivo restringido y flexibilizaron la ratio de cobertura de deuda a 4,25× hasta marzo de 2026.
- Avance de activos: la Fase 1 de Greater Tortue Ahmeyim (GTA) alcanzó operaciones comerciales en junio de 2025, generando los primeros ingresos por LNG y aumentando las cuentas a cobrar a largo plazo de compañías petroleras nacionales a 444,7 M$.
- Capex y cobertura: el capex del primer semestre se redujo a 172,8 M$ (frente a 553,0 M$ del año anterior). Aproximadamente 8 millones de barriles de producción 2025-26 están cubiertos con contratos collar/swaps (precios piso de 50-60$/barril).
- Impacto en patrimonio: el valor contable cayó un 15% en lo que va del año hasta 1,02 B$ debido al aumento del déficit acumulado.
Perspectivas: La liquidez a corto plazo depende del flujo de efectivo de GTA, la perforación de relleno en Jubilee y el mantenimiento del margen de covenant. Los principales riesgos son la alta deuda, el aumento de costos operativos y la volatilidad de los precios del petróleo.
Kosmos Energy (KOS) 2025년 2분기 10-Q 주요 내용
- 매출 감소: 2분기 매출이 전년 대비 13% 감소한 3억 9,260만 달러; 상반기 매출은 6억 8,280만 달러로 22% 감소, 생산량 감소와 약화된 브렌트유 가격 영향.
- 수익 변동: 순손실 8,770만 달러(-주당 0.18달러), 작년 동기 5,980만 달러 이익 대비; 상반기 손실 1억 9,830만 달러(-주당 0.42달러). 총 생산비용이 전년 대비 거의 두 배로 증가해 2억 4,310만 달러, 감가상각비(DD&A)는 68% 증가한 1억 5,130만 달러.
- 현금 압박: 영업현금흐름이 상반기에 1억 2,630만 달러로 급감(전년 동기 4억 9,620만 달러 대비); 현금 잔액은 연말 8,500만 달러에서 5,170만 달러로 감소.
- 부채 상황: 총 부채가 29억 달러로 1억 달러 증가; 12개월 내 만기 부채 2억 5,000만 달러. 순부채/EBITDAX 비율이 계약 조건 초과; 대출기관이 제한된 현금 보유 조건 면제하고 2026년 3월까지 부채 커버리지 비율을 4.25배로 완화.
- 자산 진척: Greater Tortue Ahmeyim(GTA) 1단계가 2025년 6월 상업 운전 시작, 첫 LNG 매출 발생 및 국영 석유회사에 대한 장기 채권이 4억 4,470만 달러로 증가.
- 투자 및 헤지: 상반기 투자비용은 1억 7,280만 달러로 축소(전년 5억 5,300만 달러 대비). 2025-26년 생산량 약 800만 배럴을 콜라/스왑으로 헤지(최저 가격 50-60달러/배럴).
- 자본 영향: 누적 적자 확대에 따라 장부가치가 연초 대비 15% 하락해 10억 2천만 달러.
전망: 단기 유동성은 GTA 현금 유입, Jubilee 보충 시추 및 계약 조건 여유 유지에 달려있음. 높은 부채 부담, 상승하는 운영비용, 유가 변동성은 주요 위험 요인으로 남음.
Points clés du 10-Q du T2-25 de Kosmos Energy (KOS)
- Détérioration des revenus : Les ventes du T2 ont chuté de 13 % en glissement annuel à 392,6 M$ ; les revenus du premier semestre ont baissé de 22 % à 682,8 M$, affectés par des volumes plus faibles et un prix du Brent moins favorable.
- Variation des résultats : Perte nette de 87,7 M$ (-0,18 $/action) contre un bénéfice de 59,8 M$ l’année précédente ; perte semestrielle de 198,3 M$ (-0,42 $/action). Les coûts bruts de production ont presque doublé à 243,1 M$, tandis que les amortissements (DD&A) ont augmenté de 68 % à 151,3 M$.
- Tension sur la trésorerie : Le flux de trésorerie opérationnel s’est effondré à 126,3 M$ au premier semestre (contre 496,2 M$) ; la trésorerie a diminué à 51,7 M$ contre 85,0 M$ en fin d’année.
- Endettement : La dette totale a augmenté à 2,90 Md$ (+100 M$) ; échéances courantes de 250 M$ dans les 12 mois. Le ratio dette nette/EBITDAX a dépassé le covenant ; les prêteurs ont renoncé à l’exigence de trésorerie restreinte et assoupli le ratio de couverture de la dette à 4,25× jusqu’en mars 2026.
- Avancement des actifs : La phase 1 de Greater Tortue Ahmeyim (GTA) a atteint les opérations commerciales en juin 2025, générant les premiers revenus de GNL et augmentant les créances à long terme auprès des compagnies pétrolières nationales à 444,7 M$.
- Capex & couverture : Les dépenses d’investissement du premier semestre ont été réduites à 172,8 M$ (contre 553,0 M$ l’année précédente). Environ 8 millions de barils de production 2025-26 sont couverts par des contrats collar/swaps (planchers à 50-60 $/baril).
- Impact sur les capitaux propres : La valeur comptable a chuté de 15 % depuis le début de l’année à 1,02 Md$ en raison de l’élargissement du déficit accumulé.
Perspectives : La liquidité à court terme dépend des flux de trésorerie de GTA, des forages de comblement à Jubilee et du maintien de la marge des covenants. Les principaux risques restent la dette élevée, la hausse des coûts opérationnels et la volatilité des prix du pétrole.
Kosmos Energy (KOS) Q2-25 10-Q Highlights
- Umsatzrückgang: Der Umsatz im Q2 sank im Jahresvergleich um 13 % auf 392,6 Mio. USD; der Halbjahresumsatz fiel um 22 % auf 682,8 Mio. USD, belastet durch geringere Fördermengen und schwächere Brent-Preise.
- Gewinnentwicklung: Nettogewinn von -87,7 Mio. USD (-0,18 USD/Aktie) gegenüber einem Gewinn von 59,8 Mio. USD im Vorjahr; Halbjahresverlust von 198,3 Mio. USD (-0,42 USD/Aktie). Die Bruttoförderkosten verdoppelten sich fast auf 243,1 Mio. USD, während Abschreibungen (DD&A) um 68 % auf 151,3 Mio. USD stiegen.
- Bargeldknappheit: Der operative Cashflow brach im ersten Halbjahr auf 126,3 Mio. USD ein (gegenüber 496,2 Mio. USD); der Kassenbestand sank von 85,0 Mio. USD zum Jahresende auf 51,7 Mio. USD.
- Verschuldung: Die Gesamtschulden stiegen auf 2,90 Mrd. USD (+100 Mio. USD); kurzfristige Fälligkeiten von 250 Mio. USD innerhalb von 12 Monaten. Das Verhältnis Nettoverschuldung/EBITDAX überschritt die Covenants; die Kreditgeber verzichteten auf die Verpflichtung zu gebundenen Barmitteln und lockerten das Verschuldungsdeckungsverhältnis auf 4,25× bis März 2026.
- Asset-Fortschritt: Phase 1 von Greater Tortue Ahmeyim (GTA) nahm im Juni 2025 den kommerziellen Betrieb auf, was erste LNG-Einnahmen auslöste und die langfristigen Forderungen gegenüber nationalen Ölgesellschaften auf 444,7 Mio. USD erhöhte.
- Capex & Absicherung: Die Investitionsausgaben im ersten Halbjahr wurden auf 172,8 Mio. USD reduziert (vorjahr 553,0 Mio. USD). Rund 8 Mio. Barrel Produktion 2025-26 sind mit Collar-/Swap-Kontrakten abgesichert (Mindestpreise 50-60 USD/Barrel).
- Eigenkapitalauswirkung: Der Buchwert sank seit Jahresbeginn um 15 % auf 1,02 Mrd. USD aufgrund eines gestiegenen kumulierten Defizits.
Ausblick: Die kurzfristige Liquidität hängt von den GTA-Cashflows, Infill-Bohrungen in Jubilee und der Einhaltung der Covenant-Spielräume ab. Hohe Verschuldung, steigende Betriebskosten und volatile Ölpreise bleiben wesentliche Risiken.
Positive
- GTA Phase 1 reached commercial operations, opening a new LNG revenue stream and long-term receivable accruals.
- Capex discipline: H1-25 spend ($173 M) dropped 69% YoY, preserving liquidity.
- Commodity hedges protect ~8 MMbbl through 2026 with floors $50-60/bbl, mitigating downside price risk.
Negative
- Revenue and earnings deterioration: Q2 net loss $87.7 M versus prior-year profit amid 22% H1 top-line slide.
- Operating cash flow collapsed to $126 M (-75% YoY), insufficient for capex and servicing $2.9 B debt.
- Debt leverage rising; covenant relief indicates lender concern and could heighten refinancing costs.
- Production costs surged 61% YoY, pressuring margins.
- Liquidity thin: only $51.7 M cash against $250 M debt due within 12 months.
Insights
TL;DR Losses, cash drain and looser covenants overshadow GTA start-up; equity thesis hinges on rapid LNG cash generation.
Revenue fell sharply while unit costs surged, driving a $88 M quarterly loss. Operating cash flow now covers barely 75% of H1 capex plus interest, forcing an extra $100 M Facility draw. Although GTA Phase 1 reached COD in June and should add stable LNG cash flow, the balance sheet is stretched: $3 B gross debt vs $52 M cash and equity down to 1× 2025 annualized EBITDAX. Management secured temporary covenant relief (debt-cover ceiling raised to 4.25×), but this signals lender concern. Valuation upside requires (i) sustained GTA ramp to 2.45 MMTPA, (ii) production recovery in Ghana/Gulf of Mexico, and (iii) Brent >$70 with hedge protection. Until then, equity remains high-beta to oil prices and execution risk.
TL;DR Leverage elevated; covenant amendment and 2026 senior notes maturity create refinancing risk.
Net borrowings increased to $2.85 B; first material amortization is the $250 M Senior Notes due Apr-26. Free cash flow turned negative, cutting interest-coverage to ~1.1×. Facility lenders waived restricted-cash locks and softened the debt-cover covenant, but this is temporary and reverts to 3.5× in Sept-26. Liquidity is thin: $52 M cash plus $350 M undrawn revolver against $250 M current maturities and $87 M semi-annual interest burden. Successful refinancing or asset monetization (e.g., sell-down in Mauritania/Senegal) is crucial. Credit outlook: negative watch; any GTA delay or oil-price dip could trigger further covenant stress.
Kosmos Energy (KOS) risultati Q2-25 10-Q in evidenza
- Deterioramento dei ricavi: le vendite del Q2 sono diminuite del 13% su base annua, raggiungendo 392,6 M$; i ricavi del primo semestre sono calati del 22% a 682,8 M$, penalizzati da volumi di sollevamento inferiori e da prezzi Brent più deboli.
- Variazione degli utili: perdita netta di 87,7 M$ (-0,18$/azione) rispetto a un utile di 59,8 M$ dell’anno precedente; perdita semestrale di 198,3 M$ (-0,42$/azione). I costi di produzione lordi sono quasi raddoppiati su base annua a 243,1 M$, mentre gli ammortamenti e svalutazioni (DD&A) sono aumentati del 68% a 151,3 M$.
- Pressione sulla liquidità: il flusso di cassa operativo è crollato a 126,3 M$ nel primo semestre (rispetto a 496,2 M$); la liquidità disponibile è scesa a 51,7 M$ dai 85,0 M$ di fine anno.
- Indebitamento: il debito totale è salito a 2,90 Mld$ (+100 M$); scadenze correnti per 250 M$ entro 12 mesi. Il rapporto debito netto/EBITDAX ha superato il covenant; i finanziatori hanno rinunciato all’obbligo di cassa vincolata e hanno allentato il rapporto di copertura del debito a 4,25× fino a marzo 2026.
- Progresso degli asset: la Fase 1 di Greater Tortue Ahmeyim (GTA) ha raggiunto operazioni commerciali a giugno 2025, generando i primi ricavi da LNG e aumentando i crediti a lungo termine verso compagnie petrolifere nazionali a 444,7 M$.
- Capex e coperture: il capex del primo semestre è stato ridotto a 172,8 M$ (rispetto a 553,0 M$ dell’anno precedente). Circa 8 milioni di barili di produzione 2025-26 sono coperti da contratti collar e swap (prezzi minimi di 50-60$/barile).
- Impatto sul patrimonio netto: il valore contabile è sceso del 15% da inizio anno a 1,02 Mld$ a causa dell’aumento del deficit accumulato.
Prospettive: la liquidità a breve termine dipende dai flussi di cassa di GTA, dalle perforazioni di completamento a Jubilee e dal mantenimento del margine sui covenant. Rischi principali rimangono l’elevato indebitamento, i costi operativi in aumento e la volatilità dei prezzi del petrolio.
Aspectos destacados del Q2-25 10-Q de Kosmos Energy (KOS)
- Deterioro de ingresos: las ventas del segundo trimestre cayeron un 13% interanual hasta 392,6 M$; los ingresos del primer semestre bajaron un 22% a 682,8 M$, afectados por menores volúmenes de levantamiento y precios Brent más débiles.
- Variación en ganancias: pérdida neta de 87,7 M$ (-0,18$/acción) frente a una ganancia de 59,8 M$ el año pasado; pérdida en el primer semestre de 198,3 M$ (-0,42$/acción). Los costos brutos de producción casi se duplicaron interanual a 243,1 M$, mientras que DD&A aumentó un 68% a 151,3 M$.
- Presión de efectivo: el flujo de caja operativo colapsó a 126,3 M$ en el primer semestre (vs 496,2 M$); el saldo de efectivo bajó a 51,7 M$ desde 85,0 M$ a fin de año.
- Apalancamiento: la deuda total aumentó a 2,90 B$ (+100 M$); vencimientos actuales de 250 M$ a pagar en 12 meses. La deuda neta/EBITDAX excedió el covenant; los prestamistas renunciaron al requisito de efectivo restringido y flexibilizaron la ratio de cobertura de deuda a 4,25× hasta marzo de 2026.
- Avance de activos: la Fase 1 de Greater Tortue Ahmeyim (GTA) alcanzó operaciones comerciales en junio de 2025, generando los primeros ingresos por LNG y aumentando las cuentas a cobrar a largo plazo de compañías petroleras nacionales a 444,7 M$.
- Capex y cobertura: el capex del primer semestre se redujo a 172,8 M$ (frente a 553,0 M$ del año anterior). Aproximadamente 8 millones de barriles de producción 2025-26 están cubiertos con contratos collar/swaps (precios piso de 50-60$/barril).
- Impacto en patrimonio: el valor contable cayó un 15% en lo que va del año hasta 1,02 B$ debido al aumento del déficit acumulado.
Perspectivas: La liquidez a corto plazo depende del flujo de efectivo de GTA, la perforación de relleno en Jubilee y el mantenimiento del margen de covenant. Los principales riesgos son la alta deuda, el aumento de costos operativos y la volatilidad de los precios del petróleo.
Kosmos Energy (KOS) 2025년 2분기 10-Q 주요 내용
- 매출 감소: 2분기 매출이 전년 대비 13% 감소한 3억 9,260만 달러; 상반기 매출은 6억 8,280만 달러로 22% 감소, 생산량 감소와 약화된 브렌트유 가격 영향.
- 수익 변동: 순손실 8,770만 달러(-주당 0.18달러), 작년 동기 5,980만 달러 이익 대비; 상반기 손실 1억 9,830만 달러(-주당 0.42달러). 총 생산비용이 전년 대비 거의 두 배로 증가해 2억 4,310만 달러, 감가상각비(DD&A)는 68% 증가한 1억 5,130만 달러.
- 현금 압박: 영업현금흐름이 상반기에 1억 2,630만 달러로 급감(전년 동기 4억 9,620만 달러 대비); 현금 잔액은 연말 8,500만 달러에서 5,170만 달러로 감소.
- 부채 상황: 총 부채가 29억 달러로 1억 달러 증가; 12개월 내 만기 부채 2억 5,000만 달러. 순부채/EBITDAX 비율이 계약 조건 초과; 대출기관이 제한된 현금 보유 조건 면제하고 2026년 3월까지 부채 커버리지 비율을 4.25배로 완화.
- 자산 진척: Greater Tortue Ahmeyim(GTA) 1단계가 2025년 6월 상업 운전 시작, 첫 LNG 매출 발생 및 국영 석유회사에 대한 장기 채권이 4억 4,470만 달러로 증가.
- 투자 및 헤지: 상반기 투자비용은 1억 7,280만 달러로 축소(전년 5억 5,300만 달러 대비). 2025-26년 생산량 약 800만 배럴을 콜라/스왑으로 헤지(최저 가격 50-60달러/배럴).
- 자본 영향: 누적 적자 확대에 따라 장부가치가 연초 대비 15% 하락해 10억 2천만 달러.
전망: 단기 유동성은 GTA 현금 유입, Jubilee 보충 시추 및 계약 조건 여유 유지에 달려있음. 높은 부채 부담, 상승하는 운영비용, 유가 변동성은 주요 위험 요인으로 남음.
Points clés du 10-Q du T2-25 de Kosmos Energy (KOS)
- Détérioration des revenus : Les ventes du T2 ont chuté de 13 % en glissement annuel à 392,6 M$ ; les revenus du premier semestre ont baissé de 22 % à 682,8 M$, affectés par des volumes plus faibles et un prix du Brent moins favorable.
- Variation des résultats : Perte nette de 87,7 M$ (-0,18 $/action) contre un bénéfice de 59,8 M$ l’année précédente ; perte semestrielle de 198,3 M$ (-0,42 $/action). Les coûts bruts de production ont presque doublé à 243,1 M$, tandis que les amortissements (DD&A) ont augmenté de 68 % à 151,3 M$.
- Tension sur la trésorerie : Le flux de trésorerie opérationnel s’est effondré à 126,3 M$ au premier semestre (contre 496,2 M$) ; la trésorerie a diminué à 51,7 M$ contre 85,0 M$ en fin d’année.
- Endettement : La dette totale a augmenté à 2,90 Md$ (+100 M$) ; échéances courantes de 250 M$ dans les 12 mois. Le ratio dette nette/EBITDAX a dépassé le covenant ; les prêteurs ont renoncé à l’exigence de trésorerie restreinte et assoupli le ratio de couverture de la dette à 4,25× jusqu’en mars 2026.
- Avancement des actifs : La phase 1 de Greater Tortue Ahmeyim (GTA) a atteint les opérations commerciales en juin 2025, générant les premiers revenus de GNL et augmentant les créances à long terme auprès des compagnies pétrolières nationales à 444,7 M$.
- Capex & couverture : Les dépenses d’investissement du premier semestre ont été réduites à 172,8 M$ (contre 553,0 M$ l’année précédente). Environ 8 millions de barils de production 2025-26 sont couverts par des contrats collar/swaps (planchers à 50-60 $/baril).
- Impact sur les capitaux propres : La valeur comptable a chuté de 15 % depuis le début de l’année à 1,02 Md$ en raison de l’élargissement du déficit accumulé.
Perspectives : La liquidité à court terme dépend des flux de trésorerie de GTA, des forages de comblement à Jubilee et du maintien de la marge des covenants. Les principaux risques restent la dette élevée, la hausse des coûts opérationnels et la volatilité des prix du pétrole.
Kosmos Energy (KOS) Q2-25 10-Q Highlights
- Umsatzrückgang: Der Umsatz im Q2 sank im Jahresvergleich um 13 % auf 392,6 Mio. USD; der Halbjahresumsatz fiel um 22 % auf 682,8 Mio. USD, belastet durch geringere Fördermengen und schwächere Brent-Preise.
- Gewinnentwicklung: Nettogewinn von -87,7 Mio. USD (-0,18 USD/Aktie) gegenüber einem Gewinn von 59,8 Mio. USD im Vorjahr; Halbjahresverlust von 198,3 Mio. USD (-0,42 USD/Aktie). Die Bruttoförderkosten verdoppelten sich fast auf 243,1 Mio. USD, während Abschreibungen (DD&A) um 68 % auf 151,3 Mio. USD stiegen.
- Bargeldknappheit: Der operative Cashflow brach im ersten Halbjahr auf 126,3 Mio. USD ein (gegenüber 496,2 Mio. USD); der Kassenbestand sank von 85,0 Mio. USD zum Jahresende auf 51,7 Mio. USD.
- Verschuldung: Die Gesamtschulden stiegen auf 2,90 Mrd. USD (+100 Mio. USD); kurzfristige Fälligkeiten von 250 Mio. USD innerhalb von 12 Monaten. Das Verhältnis Nettoverschuldung/EBITDAX überschritt die Covenants; die Kreditgeber verzichteten auf die Verpflichtung zu gebundenen Barmitteln und lockerten das Verschuldungsdeckungsverhältnis auf 4,25× bis März 2026.
- Asset-Fortschritt: Phase 1 von Greater Tortue Ahmeyim (GTA) nahm im Juni 2025 den kommerziellen Betrieb auf, was erste LNG-Einnahmen auslöste und die langfristigen Forderungen gegenüber nationalen Ölgesellschaften auf 444,7 Mio. USD erhöhte.
- Capex & Absicherung: Die Investitionsausgaben im ersten Halbjahr wurden auf 172,8 Mio. USD reduziert (vorjahr 553,0 Mio. USD). Rund 8 Mio. Barrel Produktion 2025-26 sind mit Collar-/Swap-Kontrakten abgesichert (Mindestpreise 50-60 USD/Barrel).
- Eigenkapitalauswirkung: Der Buchwert sank seit Jahresbeginn um 15 % auf 1,02 Mrd. USD aufgrund eines gestiegenen kumulierten Defizits.
Ausblick: Die kurzfristige Liquidität hängt von den GTA-Cashflows, Infill-Bohrungen in Jubilee und der Einhaltung der Covenant-Spielräume ab. Hohe Verschuldung, steigende Betriebskosten und volatile Ölpreise bleiben wesentliche Risiken.
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| (Mark One) | |||||
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended June 30, 2025
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from to
Commission file number: 001-35167
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of | (I.R.S. Employer | ||||||||||
| incorporation or organization) | Identification No.) | ||||||||||
| (Address of principal executive offices) | (Zip Code) | ||||||||||
| Title of each class | Trading Symbol | Name of each exchange on which registered: | ||||||||||||
| London Stock Exchange | ||||||||||||||
Registrant’s telephone number, including area code: +1 214 445 9600
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☒ | Accelerated filer | ☐ | ||||||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | ||||||||||||
| (Do not check if a smaller reporting company) | ||||||||||||||
| Emerging growth company | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
| Class | Outstanding at July 31, 2025 | |||||||
| Common Shares, $0.01 par value | ||||||||
Table of Contents
TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.
| Page | |||||
| PART I. FINANCIAL INFORMATION | |||||
Glossary and Select Abbreviations | 3 | ||||
Item 1. Financial Statements | 7 | ||||
Consolidated Balance Sheets | 7 | ||||
Consolidated Statements of Operations | 8 | ||||
Consolidated Statements of Stockholders’ Equity | 9 | ||||
Consolidated Statements of Cash Flows | 10 | ||||
Notes to Consolidated Financial Statements | 11 | ||||
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 34 | ||||
Item 3. Quantitative and Qualitative Disclosures about Market Risk | 47 | ||||
Item 4. Controls and Procedures | 49 | ||||
| PART II. OTHER INFORMATION | |||||
Item 1. Legal Proceedings | 49 | ||||
Item 1A. Risk Factors | 49 | ||||
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 49 | ||||
Item 3. Defaults Upon Senior Securities | 50 | ||||
Item 4. Mine Safety Disclosures | 50 | ||||
Item 5. Other Information | 50 | ||||
Signatures | 51 | ||||
Item 6. Exhibits | 51 | ||||
Index to Exhibits | 52 | ||||
2
Table of Contents
KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
| “2D seismic data” | Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area. | |||||||
| “3D seismic data” | Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data. | |||||||
| “ANP-STP” | Agencia Nacional Do Petroleo De Sao Tome E Principe. | |||||||
| “API” | A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones. | |||||||
| “ASC” | Financial Accounting Standards Board Accounting Standards Codification. | |||||||
| “ASU” | Financial Accounting Standards Board Accounting Standards Update. | |||||||
| “Barrel” or “Bbl” | A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit. | |||||||
| “BBbl” | Billion barrels of oil. | |||||||
| “BBoe” | Billion barrels of oil equivalent. | |||||||
| “Bcf” | Billion cubic feet. | |||||||
| “Boe” | Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil. | |||||||
| “BOEM” | Bureau of Ocean Energy Management. | |||||||
| “Boepd” | Barrels of oil equivalent per day. | |||||||
| “Bopd” | Barrels of oil per day. | |||||||
| “BP” | BP p.l.c. and related subsidiaries. | |||||||
| “Bwpd” | Barrels of water per day. | |||||||
“3.125% Convertible Senior Notes” | 3.125% Convertible Senior Notes due 2030. | |||||||
| “Debt cover ratio” | The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months. | |||||||
| “Developed acreage” | The number of acres that are allocated or assignable to productive wells or wells capable of production. | |||||||
| “Development” | The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems. | |||||||
| “DST” | Drill stem test. | |||||||
| “Dry hole” or “Unsuccessful well” | A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities. | |||||||
| “DT” | Deepwater Tano. | |||||||
| “EBITDAX” | Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) debt modifications and extinguishments, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. | |||||||
| “ESG” | Environmental, social, and governance. | |||||||
| “ESP” | Electric submersible pump. | |||||||
| “E&P” | Exploration and production. | |||||||
3
Table of Contents
| “Facility” | Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time). | |||||||
| “FASB” | Financial Accounting Standards Board. | |||||||
| “Farm‑in” | An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment. | |||||||
| “Farm‑out” | An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment. | |||||||
| “FEED” | Front End Engineering Design. | |||||||
| “Field life cover ratio” | The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility. | |||||||
| “FLNG” | Floating liquefied natural gas vessel. | |||||||
| “FPS” | Floating production system. | |||||||
| “FPSO” | Floating production, storage and offloading vessel. | |||||||
| “GAAP” | Generally Accepted Accounting Principles in the United States of America. | |||||||
| “GEPetrol” | Guinea Equatorial De Petroleos. | |||||||
| “GHG” | Greenhouse gas. | |||||||
| “GNPC” | Ghana National Petroleum Corporation. | |||||||
| “Greater Tortue Ahmeyim” | Ahmeyim and Guembeul discoveries. | |||||||
| “GTA UUOA” | Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit. | |||||||
| “HLS” | Heavy Louisiana Sweet. | |||||||
| “Jubilee UUOA” | Unitization and Unit Operating Agreement covering the Jubilee Unit. | |||||||
| “Interest cover ratio” | The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months. | |||||||
| “LNG” | Liquefied natural gas. | |||||||
| “Loan life cover ratio” | The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets to (y) the aggregate loan amounts outstanding under the Facility. | |||||||
| “LSE” | London Stock Exchange. | |||||||
| “LTIP” | Long Term Incentive Plan. | |||||||
| “MBbl” | Thousand barrels of oil. | |||||||
| “MBoe” | Thousand barrels of oil equivalent. | |||||||
| “Mcf” | Thousand cubic feet of natural gas. | |||||||
| “Mcfpd” | Thousand cubic feet per day of natural gas. | |||||||
| “MMBbl” | Million barrels of oil. | |||||||
| “MMBoe” | Million barrels of oil equivalent. | |||||||
| “MMBtu” | Million British thermal units. | |||||||
| “MMcf” | Million cubic feet of natural gas. | |||||||
| “MMcfd” | Million cubic feet per day of natural gas. | |||||||
| “MMTPA” | Million metric tonnes per annum. | |||||||
4
Table of Contents
| “Natural gas liquid” or “NGL” | Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others. | |||||||
| “Net debt” | Total long-term debt less cash and cash equivalents and total restricted cash. | |||||||
| “NYSE” | New York Stock Exchange. | |||||||
| “Petroleum contract” | A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area. | |||||||
| “Petroleum system” | A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate. | |||||||
| “Plan of development” or “PoD” | A written document outlining the steps to be undertaken to develop a field. | |||||||
| “Productive well” | An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. | |||||||
| “Prospect(s)” | A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes. | |||||||
| “Proved reserves” | Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2). | |||||||
| “Proved developed reserves” | Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. | |||||||
| “Proved undeveloped reserves” | Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects. | |||||||
| “RSC” | Ryder Scott Company, L.P. | |||||||
| “SOFR” | Secured Overnight Financing Rate | |||||||
| “SEC” | Securities and Exchange Commission. | |||||||
| “7.125% Senior Notes” | 7.125% Senior Notes due 2026. | |||||||
| “7.750% Senior Notes” | 7.750% Senior Notes due 2027. | |||||||
| “7.500% Senior Notes” | 7.500% Senior Notes due 2028. | |||||||
“8.750% Senior Notes” | 8.750% Senior Notes due 2031. | |||||||
| “SMH” | Societe Mauritanienne des Hydrocarbures | |||||||
| “Stratigraphy” | The study of the composition, relative ages and distribution of layers of sedimentary rock. | |||||||
| “Stratigraphic trap” | A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks. | |||||||
| “Structural trap” | A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata. | |||||||
| “TAG GSA” | TEN Associated Gas - Gas Sales Agreement. | |||||||
| “TEN” | Tweneboa, Enyenra and Ntomme. | |||||||
“Tortue Phase 1 SPA” | Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG. | |||||||
| “Trap” | A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate. | |||||||
| “Trident” | Trident Energy. | |||||||
5
Table of Contents
| “Undeveloped acreage” | Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources. | |||||||
| “WCTP” | West Cape Three Points. | |||||||
6
Table of Contents
KOSMOS ENERGY LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| June 30, 2025 | December 31, 2024 | ||||||||||
| (Unaudited) | |||||||||||
| Assets | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Receivables | |||||||||||
| Inventories | |||||||||||
| Prepaid expenses and other | |||||||||||
| Derivatives | |||||||||||
| Total current assets | |||||||||||
| Property and equipment, net | |||||||||||
| Other assets: | |||||||||||
| Restricted cash | |||||||||||
| Long-term receivables | |||||||||||
| Deferred tax assets | |||||||||||
| Derivatives | |||||||||||
| Other | |||||||||||
| Total assets | $ | $ | |||||||||
| Liabilities and stockholders’ equity | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | $ | |||||||||
| Accrued liabilities | |||||||||||
| Current maturities of long-term debt | |||||||||||
| Derivatives | |||||||||||
| Total current liabilities | |||||||||||
| Long-term liabilities: | |||||||||||
| Long-term debt, net | |||||||||||
| Derivatives | |||||||||||
| Asset retirement obligations | |||||||||||
| Deferred tax liabilities | |||||||||||
| Other long-term liabilities | |||||||||||
| Total long-term liabilities | |||||||||||
| Stockholders’ equity: | |||||||||||
Preference shares, $ | |||||||||||
Common stock, $ | |||||||||||
| Additional paid-in capital | |||||||||||
| Accumulated deficit | ( | ( | |||||||||
Treasury stock, at cost, | ( | ( | |||||||||
| Total stockholders’ equity | |||||||||||
| Total liabilities and stockholders’ equity | $ | $ | |||||||||
See accompanying notes.
7
Table of Contents
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | |||||||||||||||||||
| Gain on sale of assets | |||||||||||||||||||||||
| Other income, net | |||||||||||||||||||||||
| Total revenues and other income | |||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Oil and gas production | |||||||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||
| General and administrative | |||||||||||||||||||||||
| Depletion, depreciation and amortization | |||||||||||||||||||||||
| Interest and other financing costs, net | |||||||||||||||||||||||
| Derivatives, net | ( | ( | ( | ||||||||||||||||||||
| Other expenses, net | |||||||||||||||||||||||
| Total costs and expenses | |||||||||||||||||||||||
| Income (loss) before income taxes | ( | ( | |||||||||||||||||||||
| Income tax expense | |||||||||||||||||||||||
| Net income (loss) | $ | ( | $ | $ | ( | $ | |||||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Basic | $ | ( | $ | $ | ( | $ | |||||||||||||||||
| Diluted | $ | ( | $ | $ | ( | $ | |||||||||||||||||
Weighted average number of shares used to compute net income (loss) per share: | |||||||||||||||||||||||
| Basic | |||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||
See accompanying notes.
8
Table of Contents
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
(Unaudited)
| Additional | |||||||||||||||||||||||||||||||||||
| Common Shares | Paid-in | Accumulated | Treasury | ||||||||||||||||||||||||||||||||
| Shares | Amount | Capital | Deficit | Stock | Total | ||||||||||||||||||||||||||||||
2025: | |||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2024 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | |||||||||||||||||||||||||||||||
| Restricted stock units | ( | — | — | ||||||||||||||||||||||||||||||||
| Net loss | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||
| Balance as of March 31, 2025 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | |||||||||||||||||||||||||||||||
| Restricted stock units | ( | — | — | ||||||||||||||||||||||||||||||||
Tax withholdings and cash settlements on restricted stock units | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||
| Net loss | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||
| Balance as of June 30, 2025 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
2024: | |||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2023 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
Capped call transactions | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | |||||||||||||||||||||||||||||||
| Restricted stock units | ( | — | — | ||||||||||||||||||||||||||||||||
Tax withholdings and cash settlements on restricted stock units | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||
| Net income | — | — | — | — | |||||||||||||||||||||||||||||||
| Balance as of March 31, 2024 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | |||||||||||||||||||||||||||||||
| Restricted stock awards and units | ( | — | — | ||||||||||||||||||||||||||||||||
Tax withholdings and cash settlements on restricted stock units | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||
| Net income | — | — | — | — | |||||||||||||||||||||||||||||||
| Balance as of June 30, 2024 | $ | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||||||||||
See accompanying notes.
9
Table of Contents
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| Six Months Ended June 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Operating activities | |||||||||||
| Net income (loss) | $ | ( | $ | ||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depletion, depreciation and amortization (including deferred financing costs) | |||||||||||
| Deferred income taxes | |||||||||||
| Unsuccessful well costs and leasehold impairments | |||||||||||
| Change in fair value of derivatives | ( | ||||||||||
Cash settlements on derivatives, net (including $ | ( | ||||||||||
| Equity-based compensation | |||||||||||
| Gain on sale of assets | ( | ||||||||||
| Debt modifications and extinguishments | |||||||||||
| Other | ( | ( | |||||||||
| Changes in assets and liabilities: | |||||||||||
| Decrease in receivables | |||||||||||
| Decrease in inventories and prepaid expenses | |||||||||||
| Increase (decrease) in accounts payable and accrued liabilities | ( | ||||||||||
| Net cash provided by operating activities | |||||||||||
| Investing activities | |||||||||||
| Oil and gas assets | ( | ( | |||||||||
Notes receivable and other investing activities | ( | ( | |||||||||
| Net cash used in investing activities | ( | ( | |||||||||
| Financing activities | |||||||||||
| Borrowings under long-term debt | |||||||||||
| Payments on long-term debt | ( | ( | |||||||||
Net proceeds from issuance of senior notes | |||||||||||
| Purchase of capped call transactions | ( | ||||||||||
Other financing costs | ( | ( | |||||||||
| Net cash provided by financing activities | |||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | ( | ||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | |||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | $ | |||||||||
| Supplemental cash flow information | |||||||||||
| Cash paid for: | |||||||||||
| Income taxes, net of refund received | $ | $ | |||||||||
See accompanying notes.
10
Table of Contents
KOSMOS ENERGY LTD.
Notes to Consolidated Financial Statements
(Unaudited)
1. Organization
Kosmos Energy Ltd. is incorporated in the State of Delaware as a holding company for Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.
Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.
Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America.
2. Accounting Policies
General
The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The interim consolidated financial statements were prepared in accordance with the requirements of the SEC for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim consolidated financial statements. These interim consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2024, included in our annual report on Form 10-K.
Reclassifications
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Restricted cash - long-term | |||||||||||
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows | $ | $ | |||||||||
Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. When our debt cover ratio exceeds 2.50 x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54 x, partially due to pre-production operating costs associated with the GTA Phase 1 project. During the first quarter of 2025,
11
Table of Contents
the Facility lenders waived the requirement to maintain a restricted cash balance through 2025, by which time both GTA revenue and expenses are expected to be realized.
Joint Interest Billings
The Company’s joint interest billings consist of receivables from partners with interests in common oil and natural gas properties operated by the Company for shared costs. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.
Inventories
Inventories consisted of $151.5 million and $167.5 million of materials and supplies and $11.7 million and $3.4 million of hydrocarbons as of June 30, 2025 and December 31, 2024, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Revenue Recognition
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month of or month after the sale.
Oil and gas revenue is composed of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
Revenues from contracts with customers: | |||||||||||||||||||||||
Ghana | $ | $ | $ | $ | |||||||||||||||||||
Equatorial Guinea | |||||||||||||||||||||||
Mauritania/Senegal | |||||||||||||||||||||||
Gulf of America | |||||||||||||||||||||||
Total revenues from contracts with customers | |||||||||||||||||||||||
| Provisional oil sales contracts | ( | ( | ( | ||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | |||||||||||||||||||
Concentration of Credit Risk
Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are readily available, we believe that the loss of our purchasers and/or marketing agents would not have a long‑term material adverse effect on our financial position or results of operations.
12
Table of Contents
Recent Accounting Standards
Recently Adopted
In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The amendment requires disclosures of significant segment expenses that are regularly provided to the chief operating decision maker (“CODM”) and included within each reported measure of segment profit or loss, an amount and description of its composition for other segment items, and interim disclosures of a reportable segment’s profit or loss and assets. The amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024.
Not Yet Adopted
In December 2023, the FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures (Topic 740).” The amendments focus on income tax disclosures around effective tax rates and cash income taxes paid. The amendments in the ASU are effective for annual periods beginning after December 15, 2024. Early adoption is permitted, however, we do not plan to early adopt ASU 2023-09. The Company is currently assessing the impact of this standard on its financial statement disclosures.
In November 2024, the FASB issued ASU 2024-03, “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses”. The amendments in ASU 2024-03 require more detailed disclosures about specified categories of costs and expenses included in certain expense captions presented on the face of the income statement. This ASU is effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The Company is currently assessing the impact of this standard on its financial statement disclosures.
In November 2024, the FASB issued ASU 2024-04, “Debt - Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments.” The amendments in ASU 2024-04 clarify the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as an induced conversion. The amendments in the ASU are effective for annual periods beginning after December 15, 2025. Early adoption is permitted, however, we do not plan to early adopt ASU 2024-04. The Company is currently assessing the impact this standard will have on its consolidated financial statements.
3. Receivables
Receivables consisted of the following:
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
Joint interest billings, net | $ | $ | |||||||||
Oil and gas sales | |||||||||||
Other current receivables | |||||||||||
Total receivables | $ | $ | |||||||||
Long-term receivables | $ | $ | |||||||||
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. Joint interest billings are classified as current and long-term receivables based on when collection is expected to occur.
13
Table of Contents
Long-term receivables
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us to finance a portion of the respective national oil company’s share of certain development and production costs incurred for the GTA Phase 1 project through the Commercial Operations Date of the Gimi FLNG vessel. The Commercial Operations Date was achieved in June 2025 following the successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. As of June 30, 2025 and December 31, 2024, the principal balance due from the national oil companies was $355.5 million and $280.1 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. As of June 30, 2025 and December 31, 2024, accrued interest on the balance due from the national oil companies was $68.1 million and $56.6 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. Interest income on the long-term notes receivable was $6.2 million and $4.7 million for the three months ended June 30, 2025 and 2024, respectively, and $11.5 million and $9.4 million for the six months ended June 30, 2025 and 2024, respectively.
4. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
| Oil and gas properties: | |||||||||||
| Proved properties | $ | $ | |||||||||
| Unproved properties | |||||||||||
| Total oil and gas properties | |||||||||||
| Accumulated depletion | ( | ( | |||||||||
| Oil and gas properties, net | |||||||||||
| Other property | |||||||||||
| Accumulated depreciation | ( | ( | |||||||||
| Other property, net | |||||||||||
| Property and equipment, net | $ | $ | |||||||||
We recorded depletion expense of $141.7 million and $81.1 million for the three months ended June 30, 2025 and 2024, respectively, and $253.1 million and $173.3 million for the six months ended June 30, 2025 and 2024, respectively. During the six months ended June 30, 2025, additions to our proved properties primarily related to development costs associated with the first phase of the GTA development in Mauritania and Senegal and infill development in the Jubilee Field in Ghana.
14
Table of Contents
5. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2025.
| June 30, 2025 | |||||
| (In thousands) | |||||
| Beginning balance | $ | ||||
| Additions to capitalized exploratory well costs pending the determination of proved reserves | |||||
| Reclassification due to determination of proved reserves | |||||
| Capitalized exploratory well costs charged to expense | |||||
| Ending balance | $ | ||||
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands, except project counts) | |||||||||||
| Exploratory well costs capitalized for a period of one year or less | $ | $ | |||||||||
Exploratory well costs capitalized for a period of one to five years | |||||||||||
Exploratory well costs capitalized for a period of six to ten years | |||||||||||
| Ending balance | $ | $ | |||||||||
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | |||||||||||
As of June 30, 2025, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal and the Tiberius discovery in Keathley Canyon Block 964 in the Outer Wilcox play in the Gulf of America.
Yakaar and Teranga Discoveries — In May 2016, we drilled the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we drilled the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted to the government of Senegal. In September 2019, we drilled the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. In March 2024, the current phase of the Cayar Block exploration license was extended an additional two years to July 2026. The Yakaar and Teranga discoveries are being analyzed as a joint development. During 2025, we are working with the partnership to finalize the concept design.
Tiberius Discovery — In July 2023, we spud the Tiberius infrastructure-led exploration prospect located in Block 964 of Keathley Canyon in the Gulf of America, which encountered hydrocarbon pay. Initial fluid and core analysis supports the production potential of the well, with characteristics analogous with similar nearby discoveries in the Wilcox trend. In March 2024, we completed the acquisition of an additional 16.7 % participating interest in the Keathley Canyon Blocks 920 and 964, offshore Gulf of America. As a result of the transaction, Kosmos’ participating interest in the Tiberius discovery area increased from 33.3 % to 50.0 %. The Tiberius project is being analyzed as a phased development with discussions currently ongoing with our partner to finalize the development plan. Following additional evaluation, a final investment decision for the development of the project is expected to be made.
15
Table of Contents
6. Debt
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
| Outstanding debt principal balances: | |||||||||||
| Facility | $ | $ | |||||||||
| Total long-term debt | |||||||||||
| Unamortized deferred financing costs and discounts(1) | ( | ( | |||||||||
| Total debt, net | |||||||||||
| Less: Current maturities of long-term debt | ( | ||||||||||
| Long-term debt, net | $ | $ | |||||||||
(1)Includes $27.3 million and $30.4 million of unamortized deferred financing costs related to the Facility, $12.3 million and $14.1 million of unamortized deferred financing costs and discounts related to the Senior Notes, and $10.1 million and $11.1 million of unamortized deferred financing costs related to the 3.125
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2025, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the Facility was $350.0 million. Final maturity of the Facility is December 31, 2029. In March 2025, during the Spring 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana and Equatorial Guinea.
Interest on the Facility is the aggregate of the applicable margin (4.00 % to 5.50 %, depending on the length of time that has passed from the date the Facility was entered into), plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published. Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 30 % per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20 % per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835 — Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.
The Facility provides a revolving credit and letter of credit facility. As of June 30, 2025, we had no letters of credit issued under the Facility.
When our debt cover ratio exceeds 2.50 x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54 x, partially due to pre-production operating costs associated with the GTA Phase 1 project. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance through 2025, by which time both GTA revenue and expenses are expected to be realized.
In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the next two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0 x and 4.25 x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50 x for assessment dates thereafter. The change is intended to align the covenant calculation with recent
16
Table of Contents
business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.
We were in compliance with the financial covenants contained in the Facility as of March 31, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.
In April 2019, the Company issued $650.0 million of 7.125 % Senior Notes and received net proceeds of approximately $640.0 million after deducting fees.
The 7.125 % Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 7.125 % Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the 7.750 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The 7.125 % Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.750 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of $400.0 million of the 7.125 % Senior Notes pursuant to the Company’s cash tender offers for portions of the 7.125 % Senior Notes, the 7.750 % Senior Notes, and the 7.500 % Senior Notes announced on September 9, 2024 (the “Tender Offers”). The 7.125 % Senior Notes contain customary cross default provisions.
In October 2021, the Company issued $400.0 million of 7.750 % Senior Notes and received net proceeds of approximately $395.0 million after deducting fees.
The 7.750 % Senior Notes mature on May 1, 2027. Interest is payable in arrears each May 1 and November 1, commencing on May 1, 2022. The 7.750 % Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the 7.125 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The 7.750 % Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125 % Senior Notes, the 7.500 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of $50.0 million of the 7.750 % Senior Notes pursuant to the Tender Offers. The 7.750 % Senior Notes contain customary cross default provisions.
In March 2021, the Company issued $450.0 million of 7.500 % Senior Notes and received net proceeds of approximately $444.4 million after deducting fees.
The 7.500 % Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500 % Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The 7.500 % Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 8.750 % Senior Notes and the 3.125 % Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of approximately $49.7 million of the 7.500 % Senior Notes pursuant to the Tender Offers. The 7.500 % Senior Notes contain customary cross default provisions.
17
Table of Contents
In September 2024, the Company issued $500.0 million of 8.750 % Senior Notes (the “8.750 % Senior Notes”) and received net proceeds of approximately $494.9 million after deducting fees.
The 8.750 % Senior Notes mature on October 1, 2031. Interest is payable in arrears each April 1 and October 1, commencing on April 1, 2025. The 8.750 % Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes and the 3.125 % Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The 8.750 % Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company’s Gulf of America assets and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes and the 3.125 % Convertible Senior Notes. The 8.750 % Senior Notes contain customary cross default provisions.
In March 2024, the Company issued $400.0 million of 3.125 % Convertible Senior Notes (the “3.125 % Convertible Senior Notes”) and received net proceeds of $390.4 million after deducting fees.
The 3.125 % Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. Interest is payable in arrears each March 15 and September 15, commencing September 15, 2024. The 3.125 % Convertible Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes and the 8.750 % Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility, to the extent of the value of the assets securing such indebtedness). The 3.125 % Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes and the 8.750 % Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries. The 3.125 % Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the 7.125 % Senior Notes, the 7.750 % Senior Notes, the 7.500 % Senior Notes and the 8.750 % Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries.
The 3.125 % Convertible Senior Notes indenture contains customary terms and covenants.
The Company recorded the 3.125 % Convertible Senior Notes, including the debt itself and all embedded derivatives, at cost less debt issuance costs of $9.6 million and has presented the 3.125 % Convertible Senior Notes as a single financial instrument in Long-term debt, net in our consolidated balance sheet. No portion of the embedded derivatives required bifurcation from the host debt contract. As of June 30, 2025, the effective annual interest rate on the 3.125 % Convertible Senior Notes is approximately 3.70 %, including amortization of debt issuance costs.
The conversion rate for the 3.125 % Convertible Senior Notes is initially 142.4501 shares of our common stock per $1,000 principal amount of 3.125 % Convertible Senior Notes (which is the equivalent to an initial conversion price of approximately $7.02 per share of our common stock), subject to adjustments. As of June 30, 2025, no shares have been converted.
Capped Call Transactions
In connection with the issuance of the 3.125 % Convertible Senior Notes, the Company used $49.8 million of the net proceeds from the issuance of the 3.125 % Convertible Senior Notes to enter into capped call transactions (the “Capped Call Transactions”). The Capped Call Transactions are generally expected to reduce potential dilution to holders of our common stock upon any conversion of the 3.125 % Convertible Senior Notes and/or offset any cash payments that we are required to make in excess of the principal amount of any 3.125 % Convertible Senior Notes that are converted, as the case may be, with such reduction and/or offset subject to a cap.
The Capped Call Transactions qualify for a derivative scope exception as they are indexed to our common stock and are not required to be accounted for as a separate derivative. Consequently, the Capped Call Transactions have been included as a net reduction to additional-paid-in-capital within stockholders’ equity in our consolidated balance sheet and do not require subsequent remeasurement.
Principal Debt Repayments
18
Table of Contents
At June 30, 2025, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
| Payments Due by Year | |||||||||||||||||||||||||||||||||||||||||
| Total | 2025(2) | 2026 | 2027 | 2028 | 2029 | Thereafter | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Principal debt repayments(1) | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
__________________________________
(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of June 30, 2025 are based on our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)Represents payments for the period July 1, 2025 through December 31, 2025.
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Interest expense | $ | $ | $ | $ | |||||||||||||||||||
| Amortization—deferred financing costs | |||||||||||||||||||||||
| Debt modifications and extinguishments | |||||||||||||||||||||||
| Capitalized interest | ( | ( | ( | ( | |||||||||||||||||||
| Deferred interest | ( | ( | ( | ||||||||||||||||||||
| Interest income | ( | ( | ( | ( | |||||||||||||||||||
| Other, net | |||||||||||||||||||||||
| Interest and other financing costs, net | $ | $ | $ | $ | |||||||||||||||||||
Cash payments for interest totaled $87.3 million and $61.0 million for the three months ended June 30, 2025 and 2024, respectively, and $109.9 million and $91.4 million for the six months ended June 30, 2025 and 2024, respectively. Capitalized interest totaled $4.3 million and $41.5 million for the three months ended June 30, 2025 and 2024, respectively, and $8.5 million and $83.9 million for the six months ended June 30, 2025 and 2024, respectively. The decrease in capitalized interest during the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 is primarily due to the achievement of first gas production on the GTA Phase 1 project on December 31, 2024, after which we no longer capitalize interest on the project.
7. Derivative Financial Instruments
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurement.
Oil Derivative Contracts
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of June 30, 2025. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.
19
Table of Contents
| Weighted Average Price per Bbl | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Deferred | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Premium | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Payable/ | Sold | |||||||||||||||||||||||||||||||||||||||||||||||||
| Term | Type of Contract | Index | MBbl | (Receivable) | Swap | Put | Floor | Ceiling | ||||||||||||||||||||||||||||||||||||||||||
| 2025: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Jul - Dec | Two-way collars | Dated Brent | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
Jul - Dec | Three-way collars | Dated Brent | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2026: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Jan - Jun | Two-way collars | Dated Brent | ||||||||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Three-way collars | Dated Brent | ||||||||||||||||||||||||||||||||||||||||||||||||
Jan - Jun | Swaps(1) | Dated Brent | ||||||||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Swaps(1) | Dated Brent | ||||||||||||||||||||||||||||||||||||||||||||||||
__________________________________
(1)Includes call option contracts sold to counterparties to enhance Swaps.
In July 2025, we entered into Dated Brent enhanced swap contracts for 2.0 MMBbl from January 2026 through December 2026 with a sub-floor price of $55.00 per barrel and a swap price of $69.70 per barrel.
Interest Rate Derivative Contracts
The following table summarizes our open interest rate swaps whereby we pay a fixed rate of interest and the counterparty pays a variable SOFR-based rate as of June 30, 2025:
Weighted Average | ||||||||||||||||||||||||||
Term | Type of Contract | Floating Rate | Notional | Fixed Rate | ||||||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||||
Jul - Dec 2025 | Swap | 1-Month TERM SOFR | $ | % | ||||||||||||||||||||||
The following tables disclose the Company’s derivative instruments as of June 30, 2025 and December 31, 2024, and gain/(loss) from derivatives during the three and six months ended June 30, 2025 and 2024, respectively:
| Estimated Fair Value | ||||||||||||||||||||
| Asset (Liability) | ||||||||||||||||||||
| Type of Contract | Balance Sheet Location | June 30, 2025 | December 31, 2024 | |||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Derivatives not designated as hedging instruments: | ||||||||||||||||||||
| Derivative assets: | ||||||||||||||||||||
| Commodity | Derivatives assets—current | $ | $ | |||||||||||||||||
| Provisional oil sales | Receivables: Oil and gas sales | |||||||||||||||||||
| Interest rate | Derivatives assets—current | |||||||||||||||||||
| Commodity | Derivatives assets—long-term | |||||||||||||||||||
| Derivative liabilities: | ||||||||||||||||||||
| Commodity | Derivatives liabilities—current | ( | ||||||||||||||||||
| Commodity | Derivatives liabilities—long-term | ( | ||||||||||||||||||
| Total derivatives not designated as hedging instruments | $ | $ | ||||||||||||||||||
20
Table of Contents
| Amount of Gain/(Loss) | Amount of Gain/(Loss) | |||||||||||||||||||||||||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||||||||||
| Type of Contract | Location of Gain/(Loss) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||||||||||||||||||
| Provisional oil sales | Oil and gas revenue | $ | ( | $ | $ | ( | $ | ( | ||||||||||||||||||||||||
| Commodity | Derivatives, net | ( | ||||||||||||||||||||||||||||||
Interest rate | Interest expense | |||||||||||||||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | $ | $ | $ | ( | |||||||||||||||||||||||||||
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2025 and December 31, 2024, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.
8. Fair Value Measurements
In accordance with ASC 820 — Fair Value Measurement, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
•Level 1 — quoted prices for identical assets or liabilities in active markets.
•Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.
•Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
21
Table of Contents
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2025 and December 31, 2024, for each fair value hierarchy level:
| Fair Value Measurements Using: | |||||||||||||||||||||||
| Quoted Prices in | |||||||||||||||||||||||
| Active Markets for | Significant Other | Significant | |||||||||||||||||||||
| Identical Assets | Observable Inputs | Unobservable Inputs | |||||||||||||||||||||
| (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| June 30, 2025 | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Commodity derivatives | $ | $ | $ | $ | |||||||||||||||||||
| Interest rate derivatives | |||||||||||||||||||||||
| Decommissioning trust fund: | |||||||||||||||||||||||
| Debt securities | |||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
| Commodity derivatives | ( | ( | |||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Commodity derivatives | $ | $ | $ | $ | |||||||||||||||||||
| Provisional oil sales | |||||||||||||||||||||||
| Interest rate derivatives | |||||||||||||||||||||||
| Decommissioning trust fund: | |||||||||||||||||||||||
| Debt securities | |||||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil and gas sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for credit losses, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
Commodity Derivatives
Our commodity derivatives represent swaps, crude oil collars, put options and call options for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 7 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
Interest Rate Derivatives
Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable SOFR-based rate. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) SOFR yield curves provided by independent third parties and corroborated
22
Table of Contents
with forward active market-quoted SOFR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.
Decommissioning Trust Fund
In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. Each partner will contribute annually to the trust in proportion to its respective paying interest of the estimated future dismantlement, abandonment and restoration costs associated with the decommissioning of the Jubilee Field. Contributions to the trust are used by the trustee of the fund, the Bank of Ghana, to purchase and sell authorized securities at the direction of the Jubilee unit partners.
As of June 30, 2025, the investments held in the decommissioning trust fund are US Treasury debt securities. We have classified the investments as trading securities and recorded such investments at fair market value as a long-term investment in our consolidated balance sheet using observable inputs including Kosmos’ share of the fund and broker/dealer bid/ask prices of the investments held by the fund at June 30, 2025. Contributions made to the decommissioning trust are reported as investing activities in our consolidated cash flows. All realized and unrealized gains and losses resulting from the sales and maturities or changes in fair value of the securities are recognized in Other income, net. During the six months ended June 30, 2025, we contributed $11.5 million to the decommissioning trust fund.
The following table summarizes Kosmos’ portion of the investment activity in debt securities held by the decommissioning trust during the three and six months ended June 30, 2025 and 2024:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
Type of Security | Purchases | Net Proceeds (1) | Unrealized Gain (Loss) | Purchases | Net Proceeds (1) | Unrealized Gain (Loss) | ||||||||||||||||||||||||||||||||
| 2025 | ||||||||||||||||||||||||||||||||||||||
Debt securities | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | ( | |||||||||||||||||||||||||||||||||||||
Other(1) | ||||||||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||
| 2024 | ||||||||||||||||||||||||||||||||||||||
Debt securities | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | ||||||||||||||||||||||||||||||||||||||
Other(1) | ||||||||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(1) Represents net receivables relating to interest.
The following table presents the costs and fair values of investments in debt securities held in the decommissioning trust fund according to the contractual maturities at June 30, 2025 and December 31, 2024:
| June 30, 2025 | December 31, 2024 | |||||||||||||||||||||||||
Cost | Estimated Fair Value | Cost | Estimated Fair Value | |||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
Less than 5 years | $ | $ | $ | $ | ||||||||||||||||||||||
5 years to 10 years | ||||||||||||||||||||||||||
Due after 10 years | ||||||||||||||||||||||||||
Total | $ | $ | $ | $ | ||||||||||||||||||||||
23
Table of Contents
Debt
The following table presents the carrying values and fair values at June 30, 2025 and December 31, 2024:
| June 30, 2025 | December 31, 2024 | ||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||||||||
| Facility | |||||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||
The carrying values of our 7.125 % Senior Notes, 7.750 % Senior Notes, 7.500 % Senior Notes, 8.750 % Senior Notes and 3.125 % Convertible Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125 % Senior Notes, 7.750 % Senior Notes, 7.500 % Senior Notes, 8.750 % Senior Notes and 3.125 % Convertible Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.
Nonrecurring Fair Value Measurements - Long-lived assets
Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
The Company calculates the estimated fair values of its long-lived assets using the income approach described in the ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices, production, and risk adjustment factors.
During the three and six months ended June 30, 2025 and 2024, the Company did no
24
Table of Contents
9. Equity-based Compensation
Restricted Stock Units
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $7.3 million and $10.5 million during the three months ended June 30, 2025 and 2024, respectively, and $15.7 million and $17.8 million during the six months ended June 30, 2025 and 2024, respectively. The total tax benefit for the three months ended June 30, 2025 and 2024 was $1.2 million and $1.7 million, respectively, and $2.6 million and $2.8 million during the six months ended June 30, 2025 and 2024, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.3 million and nil for the three months ended June 30, 2025 and 2024, respectively, and $3.4 million and $(9.5 ) million during the six months ended June 30, 2025 and 2024, respectively. The fair value of awards vested during the three months ended June 30, 2025 and 2024 was $0.6 million and $1.4 million, respectively, and $19.7 million and $81.6 million during the six months ended June 30, 2025 and 2024, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all of these grants vest over three years . Upon vesting, restricted stock units become issued and outstanding stock.
For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200 % of the awards granted. The grant date fair value ranged from $3.05 to $13.06 per award. The Monte Carlo simulation model utilized multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculated the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 58.0 % to 105.0 %. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.2 % to 4.2 %.
The following table reflects the outstanding restricted stock units as of June 30, 2025:
| Weighted- | Market / Service | Weighted- | |||||||||||||||||||||
| Service Vesting | Average | Vesting | Average | ||||||||||||||||||||
| Restricted Stock | Grant-Date | Restricted Stock | Grant-Date | ||||||||||||||||||||
| Units | Fair Value | Units | Fair Value | ||||||||||||||||||||
| (In thousands) | (In thousands) | ||||||||||||||||||||||
| Outstanding at December 31, 2024 | $ | $ | |||||||||||||||||||||
| Granted(1) | |||||||||||||||||||||||
| Forfeited(1) | ( | ( | |||||||||||||||||||||
| Vested | ( | ( | |||||||||||||||||||||
| Outstanding at June 30, 2025 | |||||||||||||||||||||||
__________________________________
(1)The restricted stock units with a combination of market and service vesting criteria may vest between 0 % and 200 % of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100 % results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.
As of June 30, 2025, total equity-based compensation to be recognized on unvested restricted stock units is $35.0 million over a weighted average period of 1.82 years. At June 30, 2025, the Company had approximately 3.6 million shares that remain available for issuance under the LTIP.
25
Table of Contents
10. Income Taxes
We evaluate our estimated annual effective income tax rate each quarter, based on current and forecasted business results and enacted tax laws, and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero statutory tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.
Income before income taxes is composed of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| United States | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| Foreign | ( | ( | |||||||||||||||||||||
| Income before income taxes | $ | ( | $ | $ | ( | $ | |||||||||||||||||
For the three months ended, June 30, 2025 and 2024, our effective tax rate was (38 )% and 56 %, respectively. For the six months ended June 30, 2025 and 2024, our effective tax rate was (26 )% and 45 %, respectively. For the three and six months ended June 30, 2025 and 2024, our overall effective tax rates were impacted by:
•The difference in our 21% U.S. income tax reporting rate and the statutory income tax rates applicable to our foreign operations, primarily in Ghana and Equatorial Guinea,
•Jurisdictions that have a 0% statutory tax rate or that are tax exempt,
•Jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and
•Other non-deductible expenses.
In July 2025, new U.S tax legislation was signed into law in the United States known as the "One Big Beautiful Bill Act" or "OBBBA". The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. We are currently in the process of evaluating the implications of this new legislation and the potential impact to the Company. The legislation was signed into law after the close of our second quarter, and therefore no adjustments have been made in our operating results for the six months ended June 30, 2025. Additional disclosures will be provided in future periods if necessary as the impact of the legislation is determined.
26
Table of Contents
11. Net Income (Loss) Per Share
The following table is a reconciliation between net income (loss) and the amounts used to compute basic and diluted net income (loss) per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share. Potentially dilutive securities include shares issuable upon conversion of our 3.125 % Convertible Senior Notes using the if-converted method and restricted stock units awards under our equity-based compensation plan.
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||
| Numerator: | |||||||||||||||||||||||
| Net income (loss) allocable to common stockholders | $ | ( | $ | $ | ( | $ | |||||||||||||||||
| Denominator: | |||||||||||||||||||||||
| Weighted average number of shares outstanding: | |||||||||||||||||||||||
| Basic | |||||||||||||||||||||||
| Restricted stock units(1) | |||||||||||||||||||||||
Shares issuable assuming conversion of | |||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Basic | $ | ( | $ | $ | ( | $ | |||||||||||||||||
| Diluted | $ | ( | $ | $ | ( | $ | |||||||||||||||||
__________________________________
(1)We excluded restricted stock units of 5.2 million and 1.2 million for the three months ended June 30, 2025 and 2024, respectively, and $5.9 million and $2.8 million for the six months ended June 30, 2025 and 2024, respectively from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.
(2)Represents the dilutive impact for the Company’s 3.125 % Convertible Senior Notes due 2030. As of June 30, 2025, the if-converted value is less than the outstanding principal of the 3.125 % Convertible Senior Notes and therefore anti-dilutive. The 3.125 % Convertible Senior Notes are subject to a capped call arrangement that potentially reduces the dilutive effect. Any potential impact of the capped call arrangement is excluded from this table as any proceeds under the capped call arrangement are considered anti-dilutive.
12. Commitments and Contingencies
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes that the likelihood of an unfavorable outcome having a material impact is neither reasonably possible nor probable of occurring.
As of June 30, 2025, we have a commitment to drill one development well in Equatorial Guinea.
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal, which obligate us separately to finance the respective national oil companies’ share of certain development and production costs incurred for the GTA Phase 1 project through the Commercial Operations Date of the Gimi FLNG vessel. The Commercial Operations Date was achieved in June 2025 following the successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. Kosmos’ total share, excluding accrued interest, for the two agreements combined, as of June 30, 2025 and December 31, 2024, was $355.5 million and $280.1 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets.
In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $126.1 million as of June 30, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated 11 year period.
27
Table of Contents
Performance Obligations
As of June 30, 2025 and December 31, 2024, the Company had performance and supplemental bonds totaling $156.5 million and $169.4 million, respectively, related to bonding requirements stipulated by the BOEM and other third parties for anticipated plugging and abandonment costs of certain wells and the removal of certain facilities in our Gulf of America fields.
We have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.
13. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
| Accrued liabilities: | |||||||||||
| Exploration, development and production | $ | $ | |||||||||
Revenue payable | |||||||||||
| General and administrative expenses | |||||||||||
| Interest | |||||||||||
| Income taxes | |||||||||||
| Taxes other than income | |||||||||||
| Derivatives | |||||||||||
| Other | |||||||||||
| $ | $ | ||||||||||
__________________________________
The increase in revenue payable during the six months ended June 30, 2025 is primarily related to timing of a Jubilee lifting and receipt of related proceeds.
28
Table of Contents
Asset Retirement Obligations
The following table summarizes the changes in the Company's asset retirement obligations as of and during the six months ended June 30, 2025:
| June 30, 2025 | |||||
| (In thousands) | |||||
| Asset retirement obligations: | |||||
| Beginning asset retirement obligations | $ | ||||
| Liabilities incurred during period | |||||
| Liabilities settled during period | ( | ||||
| Revisions in estimated retirement obligations | |||||
| Accretion expense | |||||
| Ending asset retirement obligations | $ | ||||
29
Table of Contents
14. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At June 30, 2025, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America. The Company’s Chief Operating Decision Maker (“CODM”) is the Chief Executive Officer, who makes decisions about allocating resources and assessing performance for the entire company. To assess performance of the reporting segments, the CODM regularly reviews oil and gas revenues, oil and gas production costs, exploration expenses and capital expenditures by reporting segment in deciding how to allocate resources and in assessing performance. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:
| Ghana | Equatorial Guinea | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Three months ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Gain on sale of assets | |||||||||||||||||||||||||||||||||||||||||
| Other income, net | ( | ||||||||||||||||||||||||||||||||||||||||
| Total revenues and other income | ( | ||||||||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | |||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | ( | ||||||||||||||||||||||||||||||||||||||||
| General and administrative | ( | ||||||||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Derivatives, net | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Other expenses, net | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Total costs and expenses | ( | ||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||
| Income tax expense | |||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | ( | $ | ( | $ | ( | $ | $ | ( | ||||||||||||||||||||||||||||||
Consolidated capital expenditures, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
30
Table of Contents
| Ghana | Equatorial Guinea | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Six months ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Gain on sale of assets | |||||||||||||||||||||||||||||||||||||||||
| Other income, net | ( | ||||||||||||||||||||||||||||||||||||||||
| Total revenues and other income | ( | ||||||||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | |||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||||||||||||||||||||
| General and administrative | ( | ||||||||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Derivatives, net | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Other expenses, net | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Total costs and expenses | ( | ||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | ( | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | $ | ( | $ | ( | $ | ( | $ | ( | $ | $ | ( | |||||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| As of June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Property and equipment, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
31
Table of Contents
Ghana | Equatorial Guinea | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Three months ended June 30, 2024 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Other income, net | ( | ||||||||||||||||||||||||||||||||||||||||
| Total revenues and other income | ( | ||||||||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | |||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||||||||||||||||||||
| General and administrative | ( | ||||||||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||
| Derivatives, net | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Other expenses, net | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||
| Total costs and expenses | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | ( | ||||||||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | |||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | $ | ( | $ | $ | |||||||||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
32
Table of Contents
Ghana | Equatorial Guinea | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Six months ended June 30, 2024 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Other income, net | ( | ||||||||||||||||||||||||||||||||||||||||
| Total revenues and other income | ( | ||||||||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | |||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | |||||||||||||||||||||||||||||||||||||||||
| General and administrative | ( | ||||||||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||
| Derivatives, net | |||||||||||||||||||||||||||||||||||||||||
| Other expenses, net | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||
| Total costs and expenses | ( | ( | |||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | ( | ||||||||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | ( | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | $ | $ | $ | $ | ( | $ | $ | |||||||||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| As of June 30, 2024 | |||||||||||||||||||||||||||||||||||||||||
| Property and equipment, net | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
| Six Months Ended June 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Consolidated capital expenditures: | |||||||||||
| Consolidated Statements of Cash Flows - Investing activities: | |||||||||||
| Oil and gas assets | $ | $ | |||||||||
| Adjustments: | |||||||||||
| Changes in capital accruals | ( | ||||||||||
| Exploration expense, excluding unsuccessful well costs and leasehold impairments(1) | |||||||||||
| Capitalized interest | ( | ( | |||||||||
| Other | |||||||||||
| Total consolidated capital expenditures, net | $ | $ | |||||||||
______________________________________
(1)Costs related to unsuccessful exploratory wells and leaseholds that are subsequently written off to Exploration expense are included in oil and gas assets when incurred.
33
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2024, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.
Recent Developments
Ghana
During the second quarter of 2025, Ghana production averaged approximately 87,800 Boepd gross (29,100 Boepd net), including the partial impact on the quarter of the two week scheduled shutdown of the Jubilee FPSO.
Jubilee development drilling progressed in the second quarter of 2025 with the drilling of one producer well. The well was successfully brought online in July 2025. The rig is currently undergoing scheduled maintenance and then is planned to return to drill and complete one additional producer well in the Jubilee Field in the fourth quarter of 2025 to be followed by a planned four-well drilling campaign in 2026.
In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana. The partnership is currently working on a Jubilee Plan of Development Amendment to be submitted for approval, a new gas sales agreement covering future gas sales from the Jubilee Field, as well as the necessary submissions for parliamentary approval. All of which are expected to be submitted before the end of the third quarter of 2025.
Gulf of America
Production from the Gulf of America averaged approximately 19,600 Boepd net (~84% oil) for the second quarter of 2025.
In July 2024, we announced start-up of oil production from the first phase of the Winterfell development in the Green Canyon area of the Gulf of America (25% working interest). In October 2024, shortly after startup of the third well, production at the field was curtailed due to sand production from the third well. Production from the first two wells was restored in December 2024. Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. Winterfell-3 was temporarily plugged and abandoned during the first quarter of 2025 while the partnership evaluates options to restore production from the Winterfell-3 fault block. The Winterfell development drilling project continued to make progress during the second quarter of 2025 with the drilling of Winterfell-4. Completion operations on Winterfell-4 are currently underway with the well expected online later in the third quarter of 2025.
Equatorial Guinea
Production in Equatorial Guinea averaged approximately 22,000 Bopd gross (7,700 Bopd net) in the second quarter of 2025, lower than expectations due to subsea multiphase flow pump (MPP) mechanical failures at Ceiba during the quarter. The partnership has agreed a plan to repair and replace the pumps with the first replacement pump expected to be installed in the fourth quarter of 2025.
34
Table of Contents
Mauritania and Senegal
Greater Tortue Ahmeyim Project
Production in Mauritania and Senegal averaged approximately 29,200 Boepd gross (7,100 Boepd net) in the second quarter of 2025, as production from the GTA field was ramping up.
The Greater Tortue Ahmeyim (GTA) liquified natural gas (LNG) project achieved first gas production from the subsea system to the FPSO on December 31, 2024. First LNG was achieved in February 2025 and the first gross LNG cargo was successfully exported in April 2025 with six gross cargoes exported through July 2025. Additionally, the Gimi FLNG vessel Commercial Operations Date was achieved in the second quarter of 2025 with successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum.
Sao Tome and Principe
In May 2025, we received approval for a twelve month extension to May 2026 for the current exploration phase for Block 5 offshore Sao Tome and Principe.
Corporate
In July 2025, new U.S tax legislation was signed into law in the United States known as the "One Big Beautiful Bill Act" or "OBBBA". The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. We are currently in the process of evaluating the implications of this new legislation and the potential impact to the Company. The legislation was signed into law after the close of our second quarter, and therefore no adjustments have been made in our operating results for the six months ended June 30, 2025. Additional disclosures will be provided in future periods if necessary as the impact of the legislation is determined.
35
Table of Contents
Results of Operations
All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Certain operating results and statistics for the three and six months ended June 30, 2025 and 2024 are included in the following tables:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (In thousands, except per volume data) | |||||||||||||||||||||||
| Sales volumes: | |||||||||||||||||||||||
| Oil (MBbl) | 5,363 | 5,210 | 9,023 | 10,099 | |||||||||||||||||||
| Gas (MMcf) | 7,120 | 4,101 | 11,292 | 8,437 | |||||||||||||||||||
| NGL (MBbl) | 113 | 60 | 204 | 148 | |||||||||||||||||||
| Total (MBoe) | 6,663 | 5,954 | 11,109 | 11,653 | |||||||||||||||||||
| Total (Boepd) | 73,216 | 65,423 | 61,376 | 64,028 | |||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Oil sales | $ | 354,518 | $ | 435,100 | $ | 624,923 | $ | 837,217 | |||||||||||||||
| Gas sales | 36,049 | 14,494 | 53,678 | 29,632 | |||||||||||||||||||
| NGL sales | 2,068 | 1,306 | 4,169 | 3,154 | |||||||||||||||||||
| Total oil and gas revenue | $ | 392,635 | $ | 450,900 | $ | 682,770 | $ | 870,003 | |||||||||||||||
| Average oil sales price per Bbl | $ | 66.10 | $ | 83.51 | $ | 69.26 | $ | 82.90 | |||||||||||||||
| Average gas sales price per Mcf | 5.06 | 3.53 | 4.75 | 3.51 | |||||||||||||||||||
| Average NGL sales price per Bbl | 18.30 | 21.77 | 20.44 | 21.31 | |||||||||||||||||||
| Average total sales price per Boe | $ | 58.93 | $ | 75.73 | $ | 61.46 | $ | 74.66 | |||||||||||||||
| Costs: | |||||||||||||||||||||||
| Oil and gas production, excluding workovers | $ | 241,306 | $ | 134,281 | $ | 394,933 | $ | 213,166 | |||||||||||||||
| Oil and gas production, workovers | 1,812 | 16,452 | 15,493 | 31,185 | |||||||||||||||||||
| Total oil and gas production costs | $ | 243,118 | (1) | $ | 150,733 | $ | 410,426 | (1) | $ | 244,351 | |||||||||||||
| Depletion, depreciation and amortization | $ | 151,268 | $ | 90,094 | $ | 271,935 | $ | 191,022 | |||||||||||||||
| Average cost per Boe: | |||||||||||||||||||||||
| Oil and gas production, excluding workovers | $ | 36.22 | $ | 22.55 | $ | 35.55 | $ | 18.29 | |||||||||||||||
| Oil and gas production, workovers | 0.27 | 2.76 | 1.39 | 2.68 | |||||||||||||||||||
| Total oil and gas production costs | $ | 36.49 | (1) | $ | 25.31 | $ | 36.94 | (1) | $ | 20.97 | |||||||||||||
| Depletion, depreciation and amortization | 22.70 | 15.13 | 24.48 | 16.39 | |||||||||||||||||||
| Total | $ | 59.19 | $ | 40.44 | $ | 61.42 | $ | 37.36 | |||||||||||||||
______________________________________
(1)Includes $69.1 million and $127.2 million for the three and six months ended June 30, 2025, respectively, related to the LNG production at the GTA Phase 1 project in Mauritania and Senegal. All gas sales in Mauritania and Senegal are LNG sales. First LNG was achieved in February 2025 and the first LNG cargo was successfully completed in April 2025.
36
Table of Contents
The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of June 30, 2025:
| Actively Drilling or | Wells Suspended or | ||||||||||||||||||||||||||||||||||||||||||||||
| Completing | Waiting on Completion | ||||||||||||||||||||||||||||||||||||||||||||||
| Exploration | Development | Exploration | Development | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||
| Ghana | |||||||||||||||||||||||||||||||||||||||||||||||
| Jubilee Unit | — | — | 1 | 0.39 | — | — | 3 | 1.16 | |||||||||||||||||||||||||||||||||||||||
| TEN | — | — | — | — | — | — | 5 | 1.02 | |||||||||||||||||||||||||||||||||||||||
| Equatorial Guinea | |||||||||||||||||||||||||||||||||||||||||||||||
Block G | — | — | — | — | — | — | 1 | 0.40 | |||||||||||||||||||||||||||||||||||||||
Gulf of America | |||||||||||||||||||||||||||||||||||||||||||||||
Winterfell(1) | 1 | 0.25 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
Tiberius | — | — | — | — | 1 | 0.50 | — | — | |||||||||||||||||||||||||||||||||||||||
| Mauritania / Senegal | |||||||||||||||||||||||||||||||||||||||||||||||
Greater Tortue Ahmeyim | — | — | — | — | 1 | 0.27 | — | — | |||||||||||||||||||||||||||||||||||||||
| Senegal Cayar Profond | — | — | — | — | 3 | 2.70 | — | — | |||||||||||||||||||||||||||||||||||||||
| Total | 1 | 0.25 | 1 | 0.39 | 5 | 3.47 | 9 | 2.58 | |||||||||||||||||||||||||||||||||||||||
(1)Includes the Winterfell-4 well which is considered a step out well from an accounting perspective, but is being drilled as part of the Winterfell phased development.
37
Table of Contents
The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.
Three months ended June 30, 2025 compared to three months ended June 30, 2024
| Three Months Ended | |||||||||||||||||
| June 30, | Increase | ||||||||||||||||
| 2025 | 2024 | (Decrease) | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Oil and gas revenue | $ | 392,635 | $ | 450,900 | $ | (58,265) | |||||||||||
| Gain on sale of assets | 600 | — | 600 | ||||||||||||||
| Other income, net | 283 | 36 | 247 | ||||||||||||||
| Total revenues and other income | 393,518 | 450,936 | (57,418) | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Oil and gas production | 243,118 | 150,733 | 92,385 | ||||||||||||||
| Exploration expenses | 4,069 | 13,235 | (9,166) | ||||||||||||||
| General and administrative | 19,074 | 25,161 | (6,087) | ||||||||||||||
| Depletion, depreciation and amortization | 151,268 | 90,094 | 61,174 | ||||||||||||||
| Interest and other financing costs, net | 54,834 | 37,279 | 17,555 | ||||||||||||||
| Derivatives, net | (21,566) | (2,852) | (18,714) | ||||||||||||||
| Other expenses, net | 6,481 | 2,162 | 4,319 | ||||||||||||||
| Total costs and expenses | 457,278 | 315,812 | 141,466 | ||||||||||||||
| Income (loss) before income taxes | (63,760) | 135,124 | (198,884) | ||||||||||||||
| Income tax expense | 23,980 | 75,354 | (51,374) | ||||||||||||||
| Net income (loss) | $ | (87,740) | $ | 59,770 | $ | (147,510) | |||||||||||
Oil and gas revenue. Oil and gas revenue decreased by $58.3 million during the three months ended June 30, 2025 as compared to the three months ended June 30, 2024 primarily as a result of lower average realized oil and gas prices. We sold 6,663 MBoe at an average realized price per barrel equivalent of $58.93 during the three months ended June 30, 2025 and 5,954 MBoe at an average realized price per barrel equivalent of $75.73 during the three months ended June 30, 2024.
Oil and gas production. Oil and gas production costs increased by $92.4 million during the three months ended June 30, 2025 as compared to the three months ended June 30, 2024 primarily as a result of increased sales volumes and operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal.
Exploration expenses. Exploration expenses decreased by $9.2 million during the three months ended June 30, 2025, as compared to the three months ended June 30, 2024 primarily as a result of decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased by $61.2 million during the three months ended June 30, 2025, as compared with the three months ended June 30, 2024 primarily as a result of increased sales volumes and higher depletion rates per boe across our portfolio owing to increased cost basis related to the respective development activities in 2024.
Interest and other financing costs, net. Interest and other financing costs, net increased by $17.6 million during the three months ended June 30, 2025, as compared to the three months ended June 30, 2024 primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $22.0 million loss on debt modifications and extinguishments related to the amendment and restatement of the Facility during the second quarter of 2024.
38
Table of Contents
Derivatives, net. During the three months ended June 30, 2025 and 2024, we recorded a gain of $21.6 million and a gain of $2.9 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.
Income tax expense. For the three months ended June 30, 2025 and 2024, changes to our effective tax rates are driven by which tax jurisdictions our income (loss) before income taxes is generated. The jurisdictions in which we operate have statutory tax rates ranging from 0% to 35%.
Six months ended June 30, 2025 compared to six months ended June 30, 2024
| Six Months Ended | |||||||||||||||||
| June 30, | Increase | ||||||||||||||||
| 2025 | 2024 | (Decrease) | |||||||||||||||
(In thousands) | |||||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Oil and gas revenue | $ | 682,770 | $ | 870,003 | $ | (187,233) | |||||||||||
| Gain on sale of assets | 600 | — | 600 | ||||||||||||||
| Other income, net | 579 | 72 | 507 | ||||||||||||||
| Total revenues and other income | 683,949 | 870,075 | (186,126) | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Oil and gas production | 410,426 | 244,351 | 166,075 | ||||||||||||||
| Exploration expenses | 13,738 | 25,295 | (11,557) | ||||||||||||||
| General and administrative | 45,329 | 53,426 | (8,097) | ||||||||||||||
| Depletion, depreciation and amortization | 271,935 | 191,022 | 80,913 | ||||||||||||||
| Interest and other financing costs, net | 106,676 | 53,727 | 52,949 | ||||||||||||||
| Derivatives, net | (14,834) | 20,970 | (35,804) | ||||||||||||||
| Other expenses, net | 8,470 | 4,191 | 4,279 | ||||||||||||||
| Total costs and expenses | 841,740 | 592,982 | 248,758 | ||||||||||||||
| Income (loss) before income taxes | (157,791) | 277,093 | (434,884) | ||||||||||||||
| Income tax expense | 40,555 | 125,637 | (85,082) | ||||||||||||||
| Net income (loss) | $ | (198,346) | $ | 151,456 | $ | (349,802) | |||||||||||
Oil and gas revenue. Oil and gas revenue decreased by $187.2 million during the six months ended June 30, 2025, as compared to the six months ended June 30, 2024 primarily as a result of lower average realized oil and gas prices and lower sales volume at Jubilee driven by lower production and owing to the two week planned shutdown. We sold 11,109 MBoe at an average realized price per barrel equivalent of $61.46 during the six months ended June 30, 2025 and 11,653 MBoe at an average realized price per barrel equivalent of $74.66 during the six months ended June 30, 2024.
Oil and gas production. Oil and gas production costs increased by $166.1 million during the six months ended June 30, 2025, as compared to the six months ended June 30, 2024 primarily as a result of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal.
Exploration expenses. Exploration expenses decreased by $11.6 million during the six months ended June 30, 2025, as compared to the six months ended June 30, 2024 primarily as a result of decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $80.9 million during the six months ended June 30, 2025, as compared with the six months ended June 30, 2024 primarily as a result of higher depletion rates per boe across our portfolio owing to increased cost basis related to the respective development activities in 2024.
Interest and other financing costs, net. Interest and other financing costs, net increased $52.9 million during the six months ended June 30, 2025, as compared to the six months ended June 30, 2024, primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $22.0 million loss
39
Table of Contents
on debt modifications and extinguishments related to the amendment and restatement of the Facility during the second quarter of 2024.
Derivatives, net. During the six months ended June 30, 2025 and 2024, we recorded a gain of $14.8 million and a loss of $21.0 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.
Income tax expense. For the six months ended June 30, 2025 and 2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rate applicable to our Ghanaian and 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a deepwater exploration and production company. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt, as well as partner carries.
Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This oil price volatility could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position support our remaining capital program for 2025.
As such, our 2025 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our appraisal and development activities in the Gulf of America, Mauritania and Senegal.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploration, appraisal and exploitation drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploration, appraisal, exploitation and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
As of June 30, 2025, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the Facility was $350.0 million. In March 2025, during the Spring 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the next two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.
40
Table of Contents
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the six months ended June 30, 2025 and 2024:
| Six Months Ended | |||||||||||
| June 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Sources of cash, cash equivalents and restricted cash: | |||||||||||
| Net cash provided by operating activities | $ | 126,280 | $ | 496,220 | |||||||
| Net proceeds from issuance of senior notes | — | 390,430 | |||||||||
| Borrowings under long-term debt | 200,000 | 175,000 | |||||||||
| 326,280 | 1,061,650 | ||||||||||
| Uses of cash, cash equivalents and restricted cash: | |||||||||||
| Oil and gas assets | 172,766 | 552,993 | |||||||||
Notes receivable and other investing activities | 86,791 | 2,575 | |||||||||
| Payments on long-term debt | 100,000 | 350,000 | |||||||||
| Purchase of capped call transactions | — | 49,800 | |||||||||
Other financing costs | 1 | 30,925 | |||||||||
| 359,558 | 986,293 | ||||||||||
| Increase (decrease) in cash, cash equivalents and restricted cash | $ | (33,278) | $ | 75,357 | |||||||
Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2025 was $126.3 million compared with net cash provided by operating activities for the six months ended June 30, 2024 of $496.2 million. The decrease in cash provided by operating activities in the six months ended June 30, 2025 when compared to the same period in 2024 is primarily a result of lower average realized oil and gas prices, lower sales volumes in Ghana and higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1 project for the six months ended June 30, 2025.
41
Table of Contents
The following table presents our liquidity and financial position as of June 30, 2025 and December 31, 2024:
| June 30, 2025 | December 31, 2024 | ||||||||||
| (In thousands) | |||||||||||
Outstanding debt principal balances: | |||||||||||
| Facility | $ | 1,000,000 | $ | 900,000 | |||||||
| 7.125% Senior Notes | 250,000 | 250,000 | |||||||||
| 7.750% Senior Notes | 350,000 | 350,000 | |||||||||
| 7.500% Senior Notes | 400,274 | 400,274 | |||||||||
| 8.750% Senior Notes | 500,000 | 500,000 | |||||||||
| 3.125% Convertible Senior Notes | 400,000 | 400,000 | |||||||||
| Total long-term debt | 2,900,274 | 2,800,274 | |||||||||
| Cash and cash equivalents | 51,694 | 84,972 | |||||||||
Total restricted cash | 305 | 305 | |||||||||
| Net debt | $ | 2,848,275 | $ | 2,714,997 | |||||||
| Availability under the Facility | $ | 350,000 | $ | 450,000 | |||||||
| Available borrowings plus cash and cash equivalents | $ | 401,694 | $ | 534,972 | |||||||
Capital Expenditures and Investments
For our 2025 capital expenditure budget, we expect to incur capital costs as we:
• drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and the Gulf of America;
• complete development of the first phase of GTA; and
• advance appraisal and development efforts for the existing discoveries in the Gulf of America and internationally.
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our paying interests in our operations including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third‑party projects, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition opportunities to support and expand our asset portfolio which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, health, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate, or one or more of our assumptions proves to be incorrect, or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell assets, equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.
2025 Capital Program
We estimate we will spend approximately $350 million of capital for the year ending December 31, 2025, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:
•Approximately $275 million related to maintenance activities across our producing Ghana, Equatorial Guinea and Gulf of America assets, including infill development drilling and facilities integrity spend;
•Approximately $50 million related to the completion of the first phase of the GTA development in Mauritania and Senegal;
42
Table of Contents
•Approximately $25 million related to progressing our appraisal and development programs in the Gulf of America, Mauritania and Senegal.
The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploitation and drilling results among other factors. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil, natural gas and LNG and the prices we receive from the sale of oil, natural gas and LNG, and our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration, appraisal and development drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploration, appraisal, exploitation and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
Significant Sources of Capital
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana and Equatorial Guinea. As of June 30, 2025, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the Facility was $350.0 million.
In March 2025, during the Spring 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of June 30, 2025, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the next two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations. We were in compliance with the financial covenants contained in the Facility as of March 31, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.
43
Table of Contents
The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.
Senior Notes
We have four series of senior notes outstanding as of June 30, 2025, which we collectively refer to as the “Senior Notes.” Our 7.125% Senior Notes have an outstanding balance of $250.0 million and mature on April 4, 2026. Interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.750% Senior Notes have an outstanding balance of $350.0 million and mature on May 1, 2027. Interest is payable on the 7.750% Senior Notes each May 1 and November 1. Our 7.500% Senior Notes have an outstanding balance of approximately $400.3 million and mature on March 1, 2028. Interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 8.750% Senior Notes have an outstanding balance of $500.0 million and mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.
The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally in right of payment with all of its existing and future senior indebtedness (including the 3.125% Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.
3.125% Convertible Senior Notes due 2030
We have one series of senior convertible notes outstanding. Our 3.125% Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. Interest is payable in arrears each March 15 and September 15, commencing September 15, 2024.
The 3.125% Convertible Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility, to the extent of the value of the assets securing such indebtedness). The 3.125% Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries.
The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.
In connection with the issuance of the 3.125% Convertible Senior Notes, the Company entered into capped call transactions (the “Capped Call Transactions”). The Capped Call Transactions are generally expected to reduce potential dilution to holders of our common stock upon any conversion of the 3.125% Convertible Senior Notes and/or offset any cash payments that we are required to make in excess of the principal amount of any 3.125% Convertible Senior Notes that are converted, as the case may be, with such reduction and/or offset subject to a cap.
44
Table of Contents
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2025, and the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the instrument’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not include amortization of deferred financing costs.
| Asset | ||||||||||||||||||||||||||||||||||||||||||||||||||
| (Liability) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value at | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Years Ending December 31, | June 30, | |||||||||||||||||||||||||||||||||||||||||||||||||
| 2025(2) | 2026 | 2027 | 2028 | 2029 | Thereafter | Total | 2025 | |||||||||||||||||||||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fixed rate debt: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| 7.125% Senior Notes | $ | — | $ | 250,000 | $ | — | $ | — | $ | — | $ | — | $ | 250,000 | $ | 241,655 | ||||||||||||||||||||||||||||||||||
| 7.750% Senior Notes | — | — | 350,000 | — | — | — | 350,000 | 311,279 | ||||||||||||||||||||||||||||||||||||||||||
| 7.500% Senior Notes | — | — | — | 400,274 | — | — | 400,274 | 329,446 | ||||||||||||||||||||||||||||||||||||||||||
8.750% Senior Notes | — | — | — | — | — | 500,000 | 500,000 | 377,360 | ||||||||||||||||||||||||||||||||||||||||||
3.125% Convertible Senior Notes | — | — | — | — | — | 400,000 | 400,000 | 275,208 | ||||||||||||||||||||||||||||||||||||||||||
| Variable rate debt: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average interest rate | 8.38 | % | 8.31 | % | 8.29 | % | 8.94 | % | 9.31 | % | — | % | ||||||||||||||||||||||||||||||||||||||
| Facility(1) | $ | — | $ | — | $ | 94,086 | $ | 396,487 | $ | 509,427 | $ | — | $ | 1,000,000 | $ | 1,000,000 | ||||||||||||||||||||||||||||||||||
Total principal debt repayments | $ | — | $ | 250,000 | $ | 444,086 | $ | 796,761 | $ | 509,427 | $ | 900,000 | $ | 2,900,274 | ||||||||||||||||||||||||||||||||||||
| Interest & commitment fee payments on long-term debt | 122,775 | 211,459 | 185,271 | 136,866 | 86,819 | 93,750 | 836,940 | |||||||||||||||||||||||||||||||||||||||||||
Operating leases(3) | 2,116 | 4,296 | 4,226 | 3,844 | 2,808 | — | 17,290 | |||||||||||||||||||||||||||||||||||||||||||
Purchase obligations(4) | 18,654 | — | — | — | — | — | 18,654 | |||||||||||||||||||||||||||||||||||||||||||
Decommissioning Trust Funds(5) | — | 11,460 | 11,460 | 11,460 | 11,460 | 80,218 | 126,058 | |||||||||||||||||||||||||||||||||||||||||||
| Firm transportation commitments | 1,705 | 4,182 | 2,074 | — | — | — | 7,961 | |||||||||||||||||||||||||||||||||||||||||||
__________________________________
(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of June 30, 2025. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)Represents the period July 1, 2025 through December 31, 2025.
(3)Primarily relates to corporate and foreign office leases.
(4)Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties operated by Kosmos will be billed for their working interest share of such costs. Does not include our share of operator’s purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. The Company’s liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 13 - Additional Financial Information for additional information regarding these liabilities.
(5)In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total commitment to be approximately $126.1 million as of June 30, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated 11 year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
As of June 30, 2025, we have a commitment to drill one development well in Equatorial Guinea.
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal, which obligate us separately to finance the respective national oil companies’ share of certain development and production costs incurred for the GTA Phase 1 project through the Commercial Operations Date of the Gimi FLNG vessel. The Commercial Operations Date was achieved in June 2025 following the successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. Kosmos’ total share, excluding accrued interest, for the two agreements combined as of June 30, 2025 and December 31, 2024, was $355.5 million and $280.1 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. The amount financed by Kosmos is expected to be repaid through the national oil companies’ share of future revenues.
45
Table of Contents
We have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.
Critical Accounting Policies
We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. Other than items discussed in Note 2 — Accounting Policies, there have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2024.
Cautionary Note Regarding Forward-looking Statements
This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:
•the impact of a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions on us and the overall business environment;
•the impacts of the continued war in Ukraine and ongoing instability in the Middle East and the effects these events have on the oil and gas industry as a whole, including increased volatility with respect to oil, natural gas and LNG prices and operating and capital expenditures;
•our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;
•uncertainties inherent in making estimates of our oil and natural gas data;
•the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
•projected and targeted capital expenditures and other costs, commitments and revenues;
•termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities;
•our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
•the ability to obtain financing and to comply with the terms under which such financing may be available;
•the volatility of oil, natural gas and LNG prices, as well as our ability to implement hedges addressing such volatility on commercially reasonable terms;
•the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;
•the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
•other competitive pressures;
•potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;
•current and future government regulation of the oil and gas industry, applicable monetary/foreign exchange sectors or regulation of the investment in or ability to do business with certain countries or regimes;
•cost of compliance with laws and regulations;
46
Table of Contents
•changes in, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders, or the implementation, or interpretation, of those laws, regulations and executive orders;
•adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
•environmental liabilities;
•geological, geophysical and other technical and operations problems, including drilling and oil and gas production and processing;
•military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
•the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;
•our vulnerability to severe weather events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change;
•our ability to meet our obligations under the agreements governing our indebtedness;
•the availability and cost of financing and refinancing our indebtedness;
•the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, performance bonds and other secured debt;
•our ability to obtain surety or performance bonds on commercially reasonable terms;
•the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
•our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and
•other risk factors discussed in the “Item 1A. Risk Factors” section of our quarterly reports on Form 10-Q and our annual report on Form 10-K.
The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.
Item 3. Qualitative and Quantitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.
We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data — Note 2 — Accounting Policies, Note 7 — Derivative Financial Instruments and Note 8— Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the six months ended June 30, 2025:
| Derivative Contracts Assets (Liabilities) | ||||||||||||||||||||
| Commodities | Interest Rates | Total | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Fair value of contracts outstanding as of December 31, 2024 | $ | 9,468 | $ | 2,202 | $ | 11,670 | ||||||||||||||
| Changes in contract fair value | 7,227 | 656 | 7,883 | |||||||||||||||||
| Contract maturities | (4,298) | (1,983) | (6,281) | |||||||||||||||||
| Fair value of contracts outstanding as of June 30, 2025 | $ | 12,397 | $ | 875 | $ | 13,272 | ||||||||||||||
47
Table of Contents
Commodity Price Risk
The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Substantially all of our oil sales are indexed against Dated Brent, and Heavy Louisiana Sweet. Oil prices in the first six months of 2025 ranged between $61.09 and $83.06 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first six months of 2025.
Commodity Derivative Instruments
We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of swaps, collars, put options and call options. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative contracts on commercially reasonable terms.
Commodity Price Sensitivity
The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2025. Volumes and weighted average prices are net of any offsetting derivatives entered into.
| Weighted Average Price per Bbl | Asset | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Deferred | (Liability) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Premium | Fair Value at | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Payable/ | Sold | June 30, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Term | Type of Contract | Index | MBbl | (Receivable) | Swap | Put | Floor | Ceiling | 2025(2) | |||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2025: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Jul - Dec | Two-way collars | Dated Brent | 4,000 | $ | 1.35 | $ | — | $ | — | $ | 60.00 | $ | 74.94 | $ | (1,544) | |||||||||||||||||||||||||||||||||||||||||
Jul - Dec | Three-way collars | Dated Brent | 1,000 | 1.13 | — | 55.00 | 70.00 | 85.00 | 3,329 | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan - Jun | Two-way collars | Dated Brent | 1,000 | 1.55 | — | — | 60.00 | 74.75 | 120 | |||||||||||||||||||||||||||||||||||||||||||||||
| Jan - Dec | Three-way collars | Dated Brent | 2,000 | — | — | 50.00 | 60.00 | 75.51 | (576) | |||||||||||||||||||||||||||||||||||||||||||||||
Jan - Jun | Swaps(1) | Dated Brent | 1,000 | — | 72.90 | — | — | 80.00 | 5,980 | |||||||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Swaps(1) | Dated Brent | 1,000 | — | 72.46 | — | — | 80.00 | 5,088 | |||||||||||||||||||||||||||||||||||||||||||||||
__________________________________
(1)Includes call option contracts sold to counterparties to enhance Swaps.
(2)Fair values are based on the average forward oil prices on June 30, 2025.
In July 2025, we entered into Dated Brent enhanced swap contracts for 2.0 MMBbl from January 2026 through December 2026 with a sub-floor price of $55.00 per barrel and a swap price of $69.70 per barrel.
At June 30, 2025, our open commodity derivative instruments were in a net asset position of $12.4 million. As of June 30, 2025, a hypothetical 10% price increase in the oil price curves would decrease future pre-tax earnings by approximately $43.0 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $41.3 million. For example, if oil prices averaged $50.00 or $60.00 per barrel Dated Brent the rest of 2025 and 2026, our average realized pricing after derivatives would be approximately $55.00 and $62.00 per barrel, respectively, excluding any impact of differentials (including the impact of hedges put in post quarter end).
Interest Rate Derivative Instruments
See Note 7 — Derivative Financial Instruments and Note 8 — Fair Value Measurements for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.
48
Table of Contents
Interest Rate Sensitivity
Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility, which as of June 30, 2025 total $1.0 billion and have a weighted average interest rate of 8.1%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10%, our weighted average interest rate would increase to approximately 8.6%. At this level of floating rate debt, we would pay an estimated additional $4.2 million interest expense per year. The impact of the 2025 fixed interest rate swap would reduce the estimated additional interest expense to $1.1 million for the six months ending December 31, 2025. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings and future payments associated with the GTA FPSO arrangement.
As of June 30, 2025, the fair market value of our interest rate swaps was a net asset of approximately $0.9 million. If SOFR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2025, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.
Item 1A. Risk Factors
There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” sections of our annual report on Form 10-K for the year ended December 31, 2024.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
49
Table of Contents
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information.
Rule 10b5-1 and Non Rule 10b5-1 Trading Arrangements
During the six months ended June 30, 2025, certain of our officers and directors adopted terminated Rule 10b5-1 trading arrangements as follows.
On February 27, 2025, Sir John Grant , a member of our board of directors , adopted a trading plan intended to satisfy the conditions under Rule 10b5-1(c) of the Exchange Act. Sir John Grant’s plan was for the sale of up to 27,923 shares of our common stock on June 5, 2025, in order to cover income tax liability from the vesting of restricted share units that were granted to him under the Company’s Long Term Incentive Plan. Sir John Grant sold 27,923 shares on June 5, 2025 and the plan has now been terminated .
During the six months ended June 30, 2025, none of our officers or directors adopted or terminated any non-Rule 10b5-1 trading arrangement.
50
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Kosmos Energy Ltd. | |||||||||||
| (Registrant) | |||||||||||
| Date | August 4, 2025 | /s/ NEAL D. SHAH | |||||||||
| Neal D. Shah | |||||||||||
| Senior Vice President and Chief Financial Officer | |||||||||||
| (Principal Financial Officer) | |||||||||||
Item 6. Exhibits
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.
51
Table of Contents
INDEX OF EXHIBITS
| Exhibit Number | Description of Document | |||||||
| 31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||
| 31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||||
| 32.1 | Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||||
| 32.2 | Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||||
| 101.INS | XBRL Instance Document | |||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document | |||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document | |||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |||||||
___________________________________
52
FAQ
How did Kosmos Energy's revenue perform in Q2 2025?
Oil & gas revenue fell 13% YoY to $392.6 million due to lower liftings and weaker Brent prices.
What was KOS's earnings per share for the quarter?
Diluted EPS was -$0.18, a reversal from +$0.12 in Q2 2024.
How much debt does Kosmos Energy carry?
Total principal debt rose to $2.90 billion, with $250 million maturing within 12 months.
What is the status of the Greater Tortue Ahmeyim project?
GTA Phase 1 achieved commercial operations in June 2025, enabling LNG sales at ~2.45 MMTPA.
Did lenders modify Kosmos's credit covenants?
Yes. The Facility’s debt-cover ratio was temporarily relaxed to 4.25× through March 2026 and the restricted-cash requirement was waived for 2025.
Kosmos Energy Ltd
NYSE:KOS
KOS Rankings
KOS Latest News
KOS Latest SEC Filings
Aug 4, 2025
[8-K] Kosmos Energy Ltd. Reports Material Event
Jul 15, 2025
[SCHEDULE 13G/A] Kosmos Energy Ltd. SEC Filing
KOS Stock Data
932.12M
467.83M
2.09%
95.57%
8.35%
Oil & Gas E&P
Crude Petroleum & Natural Gas
United States
DALLAS