[10-Q] NorthWestern Energy Group, Inc. Quarterly Earnings Report
Filing Impact
Filing Sentiment
Form Type
10-Q
Rhea-AI Filing Summary
NorthWestern Energy Group (NWE) reported third-quarter results and regulatory updates. Q3 2025 revenue was $386.95 million, up from $345.16 million a year ago, while net income was $38.23 million versus $46.82 million, reflecting higher administrative costs and interest expense. Diluted EPS was $0.62 compared to $0.76. For the first nine months, operating cash flow was $338.27 million.
The company advanced key initiatives. It entered an all-stock merger of equals agreement with Black Hills, with each NWE share to receive 0.98 Black Hills shares, subject to shareholder and regulatory approvals. NWE incurred $7.6 million of merger-related costs in Q3. In Montana, interim electric and gas rate structures remain in effect pending a final order expected in Q4 2025; Nebraska approved final gas rates effective July 1, 2025. NWE closed the $35.9 million cash acquisition of Energy West operations on July 1, 2025. It also plans to acquire additional interests in Colstrip Units 3 and 4 effective January 1, 2026, with filings aimed at cost recovery.
Capital activities included issuing $400 million Montana first mortgage bonds due 2030 and $100 million South Dakota first mortgage bonds due 2035, and expanding a term loan to $150 million. Shares outstanding were 61,407,029 as of October 24, 2025.
NorthWestern Energy Group (NWE) ha riportato i risultati del terzo trimestre e aggiornamenti normativi. Il fatturato del Q3 2025 è stato di 386,95 milioni di dollari, in aumento rispetto ai 345,16 milioni di dollari dell'anno precedente, mentre l'utile netto è stato di 38,23 milioni contro 46,82 milioni, riflettendo costi amministrativi più elevati e oneri finanziari. L'utile per azione diluito è stato di 0,62 dollari rispetto a 0,76. Nei primi nove mesi, il flusso di cassa operativo è stato di 338,27 milioni di dollari.
L'azienda ha avanzato iniziative chiave. Ha stipulato un accordo di fusione tra uguali interamente azionario con Black Hills, con ogni quota NWE che riceverà 0,98 azioni Black Hills, soggetto all'approvazione degli azionisti e delle autorità regolatorie. NWE ha sostenuto costi di fusione di 7,6 milioni di dollari nel terzo trimestre. In Montana, la struttura tariffaria provvisoria per elettricità e gas resta in vigore in attesa di un ordinanza definitiva prevista nel quarto trimestre 2025; nel Nebraska sono state approvate tariffe finali del gas efficaci dal 1 luglio 2025. NWE ha chiuso l'acquisizione in contanti da 35,9 milioni di dollari delle operazioni Energy West il 1 luglio 2025. Inoltre intende acquisire ulteriori interessi nelle Units Colstrip 3 e 4 a partire dal 1 gennaio 2026, con presentazioni mirate al recupero dei costi.
Le attività di capitale hanno incluso l’emissione di obbligazioni ipotecarie primarie del Montana per 400 milioni di dollari con scadenza 2030 e obbligazioni ipotecarie primarie del Dakota del Sud per 100 milioni di dollari con scadenza 2035, e l'espansione di un prestito a termine a 150 milioni. Le azioni in circolazione ammontavano a 61.407.029 al 24 ottobre 2025.
NorthWestern Energy Group (NWE) informó resultados del tercer trimestre y actualizaciones regulatorias. Los ingresos del tercer trimestre de 2025 fueron de 386,95 millones de dólares, frente a 345,16 millones de dólares del año anterior, mientras que el ingreso neto fue de 38,23 millones frente a 46,82 millones, lo que refleja mayores costos administrativos y gastos por intereses. Las ganancias diluidas por acción fueron de 0,62 dólares en comparación con 0,76. En los primeros nueve meses, el flujo de caja operativo fue de 338,27 millones de dólares.
La empresa avanzó iniciativas clave. Entró en un acuerdo de fusión entre iguales totalmente en acciones con Black Hills, con cada acción de NWE recibiendo 0,98 acciones de Black Hills, sujeto a la aprobación de accionistas y autoridades reguladoras. NWE incurrió en costos de fusión de 7,6 millones de dólares en el tercer trimestre. En Montana, las estructuras de tarifas provisionales de electricidad y gas permanecen vigentes a la espera de una orden final esperada para el cuarto trimestre de 2025; Nebraska aprobó tarifas finales de gas efectivas desde el 1 de julio de 2025. NWE cerró la adquisición en efectivo de Energy West por 35,9 millones de dólares para sus operaciones el 1 de julio de 2025. También planea adquirir intereses adicionales en las Unidades Colstrip 3 y 4 a partir del 1 de enero de 2026, con presentaciones dirigidas a la recuperación de costos.
Las actividades de capital incluyeron la emisión de bonos hipotecarios primarios de Montana por 400 millones de dólares con vencimiento en 2030 y bonos hipotecarios primarios de Dakota del Sur por 100 millones de dólares con vencimiento en 2035, y la ampliación de un préstamo a plazo a 150 millones. Las acciones en circulación eran 61.407.029 al 24 de octubre de 2025.
NorthWestern Energy Group(NWE)는 3분기 실적 및 규제 업데이트를 발표했습니다. 2025년 3분기 매출은 3억 8695만 달러로 전년 동기 3억 4516만 달러 대비 증가했으며, 순이익은 3823만 달러로 4682만 달러에서 감소했습니다. 관리비와 이자비용 증가를 반영합니다. 주당 희석 순이익은 0.62달러로 전년의 0.76달러 대비 감소했습니다. 상반기까지의 운영 현금 흐름은 3억 3827만 달러였습니다.
회사는 핵심 이니셔티브를 추진했습니다. Black Hills와의 동등한 주식 교환 합의에 서명했으며, NWE 주식 1주당 Black Hills 주식 0.98주를 받게 됩니다(주주 및 규제 승인 대상). 3분기에 760만 달러의 합병 관련 비용이 발생했습니다. 몬타나 주에서는 전기 및 가스 요금 체계가 2025년 4분기 예정인 최종 명령을 기다리는 동안 임시로 시행 중이며, 네브래스카 주는 2025년 7월 1일부로 가스 요금 최종안을 승인했습니다. NWE는 2025년 7월 1일 Energy West 운영의 현금 인수를 3590만 달러에 마쳤습니다. 또한 2026년 1월 1일부로 Colstrip 3·4의 추가 지분 인수를 계획하고 있으며 비용 회수를 위한 제출을 하였습니다.
자본 활동으로는 몬타나의 4억 달러 규모의 2030년 만기 1차 주택담보채와 사우스다코타의 1억 달러 규모의 2035년 만기 주택담보채 발행, 그리고 1억 5000만 달러의 기간 융자 확대가 포함되었습니다. 2025년 10월 24일 기준 유통 주식 수는 6천140만 7029주였습니다.
NorthWestern Energy Group (NWE) a communiqué ses résultats du troisième trimestre et des mises à jour réglementaires. Le chiffre d'affaires du T3 2025 s'élevait à 386,95 millions de dollars, en hausse par rapport à 345,16 millions l'année précédente, tandis que le bénéfice net était de 38,23 millions contre 46,82 millions, reflétant des coûts administratifs plus élevés et des charges d'intérêts. Le BPA dilué était de 0,62 $ contre 0,76 $. Pour les neuf premiers mois, le flux de trésorerie opérationnel s'élevait à 338,27 millions de dollars.
L'entreprise a fait progresser des initiatives clés. Elle a conclu un accord de fusion entre égales entièrement en actions avec Black Hills, chaque action NWE devant recevoir 0,98 action Black Hills, sous réserve des approbations des actionnaires et des autorités reglementaires. NWE a engagé 7,6 millions de dollars de coûts liés à la fusion au T3. Dans le Montana, les structures tarifaires provisoires pour l'électricité et le gaz demeurent en vigueur en attendant une ordonnance finale prévue au T4 2025; le Nebraska a approuvé les tarifs finaux du gaz en vigueur à partir du 1er juillet 2025. NWE a clôturé l'acquisition en espèces de Energy West pour 35,9 millions de dollars le 1er juillet 2025. Elle prévoit également d'acquérir des intérêts supplémentaires dans les unités Colstrip 3 et 4 à compter du 1er janvier 2026, avec des dépôts visant le recouvrement des coûts.
Les activités de capital comprenaient l'émission d'obligations hypothécaires prioritaires du Montana pour 400 millions de dollars arrivant à échéance 2030 et d'obligations hypothécaires prioritaires du Dakota du Sud pour 100 millions de dollars arrivant à échéance 2035, et l'extension d'un prêt à terme à 150 millions. Les actions en circulation s'élevaient à 61 407 029 au 24 octobre 2025.
NorthWestern Energy Group (NWE) meldete Ergebnisse des dritten Quartals und regulatorische Updates. Der Umsatz im dritten Quartal 2025 betrug 386,95 Mio. USD, gegenüber 345,16 Mio. USD im Vorjahr, während der Nettogewinn 38,23 Mio. USD betrug gegenüber 46,82 Mio., was auf höhere Verwaltungskosten und Zinsaufwendungen zurückzuführen ist. Verwässerter Gewinn pro Aktie betrug 0,62 USD gegenüber 0,76. In den ersten neun Monaten betrug der operative Cashflow 338,27 Mio. USD.
Das Unternehmen vorantrieb wichtige Initiativen. Es schloss eine rein s stok-äquivalente Fusion mit Black Hills ab, bei der jede NWE-Aktie 0,98 Black Hills-Aktien erhalten wird, vorbehaltlich der Zustimmung der Aktionäre und der Aufsichtsbehörden. NWE hatte im Q3 fusionenbezogene Kosten in Höhe von 7,6 Mio. USD. In Montana bleiben vorläufige Strom- und Gas-Tarifstrukturen bis zu einer endgültigen Entscheidung, voraussichtlich im Q4 2025, in Kraft; im Nebraska wurden endgültige Gaspreise zum 1. Juli 2025 genehmigt. NWE schloss am 1. Juli 2025 die Barkauf-Übernahme der Energy West-Betriebe über 35,9 Mio. USD ab. Zusätzlich plant es, ab dem 1. Januar 2026 weitere Anteile an Colstrip Einheit 3 und 4 zu erwerben und Kostenrückgewinnung durch Einreichungen anzustreben.
Zu den Kapitalmaßnahmen gehörte die Ausgabe von Montana-Erstrang-Hypothekenanleihen in Höhe von 400 Mio. USD mit Fälligkeit 2030 und von South Dakota-Erstrang-Hypothekenanleihen in Höhe von 100 Mio. USD mit Fälligkeit 2035, sowie die Erweiterung eines revolvierenden Term Loan auf 150 Mio. USD. Die ausstehenden Aktien beliefen sich zum 24. Oktober 2025 auf 61.407.029.
أعلنت مجموعة نورثوستيرن للطاقة (NWE) عن نتائج الربع الثالث وتحديثات تنظيمية. بلغت الإيرادات للربع الثالث من عام 2025 نحو 386.95 مليون دولار، مقارنة بـ 345.16 مليون دولار في العام السابق، بينما كان صافي الدخل 38.23 مليون دولار مقابل 46.82 مليون دولار، مع وجود ارتفاع في التكاليف الإدارية ومصاريف الفوائد. بلغ الربح الموزع للسهم المخفف 0.62 دولار مقابل 0.76 دولار. وللأشهر التسعة الأولى، كان التدفق النقدي من الأنشطة التشغيلية 338.27 مليون دولار.
واصلت الشركة دفع مبادرات رئيسية. دخلت في اتفاق اندماج متبادل كامل الأسهم مع Black Hills، بحيث تحصل كل حصة من NWE على 0.98 من أسهم Black Hills، مع خضوع الاتفاق لموافقة المساهمين والجهات التنظيمية. تكبدت NWE 7.6 مليون دولار من تكاليف الاندماج في الربع الثالث. في مونتانا، تبقى هيكلية تسعير الكهرباء والغاز المؤقتة سارية المفعول في انتظار أمر نهائي من المتوقع صدوره في الربع الرابع من 2025؛ كما وافقت نبراسكا على أسعار الغاز النهائية المفعلة اعتباراً من 1 يوليو 2025. أغلقت NWE الاستحواذ النقدي بقيمة 35.9 مليون دولار لعمليات Energy West في 1 يوليو 2025. كما تخطط لاقتناء حصص إضافية في وحدات Colstrip 3 و4 اعتباراً من 1 يناير 2026، مع التقديمات الرامية لاسترداد التكاليف.
شملت أنشطة رأس المال إصدار سندات رهن أساسية لماونتانا بقيمة 400 مليون دولار تستحق في 2030 وسندات رهن أساسية لداكوتا الجنوبية بقيمة 100 مليون دولار تستحق في 2035، وتوسيع قرض طويل الأجل ليصل إلى 150 مليون دولار. كانت قيمة الأسهم المتداولة 61,407,029 اعتباراً من 24 أكتوبر 2025.
Positive
- None.
Negative
- None.
Insights
Solid top-line growth; margin pressured by costs and rates.
NorthWestern Energy delivered Q3 revenue of
Regulatory dynamics remain central. Montana interim rates and partial settlements are in place pending a final order expected in
The pending all‑stock merger with Black Hills (exchange ratio 0.98) awaits multiple approvals. Upcoming milestones include the Montana final order and progress on Colstrip cost recovery mechanisms; actual impact hinges on regulatory outcomes and holder approvals.
NorthWestern Energy Group (NWE) ha riportato i risultati del terzo trimestre e aggiornamenti normativi. Il fatturato del Q3 2025 è stato di 386,95 milioni di dollari, in aumento rispetto ai 345,16 milioni di dollari dell'anno precedente, mentre l'utile netto è stato di 38,23 milioni contro 46,82 milioni, riflettendo costi amministrativi più elevati e oneri finanziari. L'utile per azione diluito è stato di 0,62 dollari rispetto a 0,76. Nei primi nove mesi, il flusso di cassa operativo è stato di 338,27 milioni di dollari.
L'azienda ha avanzato iniziative chiave. Ha stipulato un accordo di fusione tra uguali interamente azionario con Black Hills, con ogni quota NWE che riceverà 0,98 azioni Black Hills, soggetto all'approvazione degli azionisti e delle autorità regolatorie. NWE ha sostenuto costi di fusione di 7,6 milioni di dollari nel terzo trimestre. In Montana, la struttura tariffaria provvisoria per elettricità e gas resta in vigore in attesa di un ordinanza definitiva prevista nel quarto trimestre 2025; nel Nebraska sono state approvate tariffe finali del gas efficaci dal 1 luglio 2025. NWE ha chiuso l'acquisizione in contanti da 35,9 milioni di dollari delle operazioni Energy West il 1 luglio 2025. Inoltre intende acquisire ulteriori interessi nelle Units Colstrip 3 e 4 a partire dal 1 gennaio 2026, con presentazioni mirate al recupero dei costi.
Le attività di capitale hanno incluso l’emissione di obbligazioni ipotecarie primarie del Montana per 400 milioni di dollari con scadenza 2030 e obbligazioni ipotecarie primarie del Dakota del Sud per 100 milioni di dollari con scadenza 2035, e l'espansione di un prestito a termine a 150 milioni. Le azioni in circolazione ammontavano a 61.407.029 al 24 ottobre 2025.
NorthWestern Energy Group (NWE) informó resultados del tercer trimestre y actualizaciones regulatorias. Los ingresos del tercer trimestre de 2025 fueron de 386,95 millones de dólares, frente a 345,16 millones de dólares del año anterior, mientras que el ingreso neto fue de 38,23 millones frente a 46,82 millones, lo que refleja mayores costos administrativos y gastos por intereses. Las ganancias diluidas por acción fueron de 0,62 dólares en comparación con 0,76. En los primeros nueve meses, el flujo de caja operativo fue de 338,27 millones de dólares.
La empresa avanzó iniciativas clave. Entró en un acuerdo de fusión entre iguales totalmente en acciones con Black Hills, con cada acción de NWE recibiendo 0,98 acciones de Black Hills, sujeto a la aprobación de accionistas y autoridades reguladoras. NWE incurrió en costos de fusión de 7,6 millones de dólares en el tercer trimestre. En Montana, las estructuras de tarifas provisionales de electricidad y gas permanecen vigentes a la espera de una orden final esperada para el cuarto trimestre de 2025; Nebraska aprobó tarifas finales de gas efectivas desde el 1 de julio de 2025. NWE cerró la adquisición en efectivo de Energy West por 35,9 millones de dólares para sus operaciones el 1 de julio de 2025. También planea adquirir intereses adicionales en las Unidades Colstrip 3 y 4 a partir del 1 de enero de 2026, con presentaciones dirigidas a la recuperación de costos.
Las actividades de capital incluyeron la emisión de bonos hipotecarios primarios de Montana por 400 millones de dólares con vencimiento en 2030 y bonos hipotecarios primarios de Dakota del Sur por 100 millones de dólares con vencimiento en 2035, y la ampliación de un préstamo a plazo a 150 millones. Las acciones en circulación eran 61.407.029 al 24 de octubre de 2025.
NorthWestern Energy Group(NWE)는 3분기 실적 및 규제 업데이트를 발표했습니다. 2025년 3분기 매출은 3억 8695만 달러로 전년 동기 3억 4516만 달러 대비 증가했으며, 순이익은 3823만 달러로 4682만 달러에서 감소했습니다. 관리비와 이자비용 증가를 반영합니다. 주당 희석 순이익은 0.62달러로 전년의 0.76달러 대비 감소했습니다. 상반기까지의 운영 현금 흐름은 3억 3827만 달러였습니다.
회사는 핵심 이니셔티브를 추진했습니다. Black Hills와의 동등한 주식 교환 합의에 서명했으며, NWE 주식 1주당 Black Hills 주식 0.98주를 받게 됩니다(주주 및 규제 승인 대상). 3분기에 760만 달러의 합병 관련 비용이 발생했습니다. 몬타나 주에서는 전기 및 가스 요금 체계가 2025년 4분기 예정인 최종 명령을 기다리는 동안 임시로 시행 중이며, 네브래스카 주는 2025년 7월 1일부로 가스 요금 최종안을 승인했습니다. NWE는 2025년 7월 1일 Energy West 운영의 현금 인수를 3590만 달러에 마쳤습니다. 또한 2026년 1월 1일부로 Colstrip 3·4의 추가 지분 인수를 계획하고 있으며 비용 회수를 위한 제출을 하였습니다.
자본 활동으로는 몬타나의 4억 달러 규모의 2030년 만기 1차 주택담보채와 사우스다코타의 1억 달러 규모의 2035년 만기 주택담보채 발행, 그리고 1억 5000만 달러의 기간 융자 확대가 포함되었습니다. 2025년 10월 24일 기준 유통 주식 수는 6천140만 7029주였습니다.
NorthWestern Energy Group (NWE) a communiqué ses résultats du troisième trimestre et des mises à jour réglementaires. Le chiffre d'affaires du T3 2025 s'élevait à 386,95 millions de dollars, en hausse par rapport à 345,16 millions l'année précédente, tandis que le bénéfice net était de 38,23 millions contre 46,82 millions, reflétant des coûts administratifs plus élevés et des charges d'intérêts. Le BPA dilué était de 0,62 $ contre 0,76 $. Pour les neuf premiers mois, le flux de trésorerie opérationnel s'élevait à 338,27 millions de dollars.
L'entreprise a fait progresser des initiatives clés. Elle a conclu un accord de fusion entre égales entièrement en actions avec Black Hills, chaque action NWE devant recevoir 0,98 action Black Hills, sous réserve des approbations des actionnaires et des autorités reglementaires. NWE a engagé 7,6 millions de dollars de coûts liés à la fusion au T3. Dans le Montana, les structures tarifaires provisoires pour l'électricité et le gaz demeurent en vigueur en attendant une ordonnance finale prévue au T4 2025; le Nebraska a approuvé les tarifs finaux du gaz en vigueur à partir du 1er juillet 2025. NWE a clôturé l'acquisition en espèces de Energy West pour 35,9 millions de dollars le 1er juillet 2025. Elle prévoit également d'acquérir des intérêts supplémentaires dans les unités Colstrip 3 et 4 à compter du 1er janvier 2026, avec des dépôts visant le recouvrement des coûts.
Les activités de capital comprenaient l'émission d'obligations hypothécaires prioritaires du Montana pour 400 millions de dollars arrivant à échéance 2030 et d'obligations hypothécaires prioritaires du Dakota du Sud pour 100 millions de dollars arrivant à échéance 2035, et l'extension d'un prêt à terme à 150 millions. Les actions en circulation s'élevaient à 61 407 029 au 24 octobre 2025.
NorthWestern Energy Group (NWE) meldete Ergebnisse des dritten Quartals und regulatorische Updates. Der Umsatz im dritten Quartal 2025 betrug 386,95 Mio. USD, gegenüber 345,16 Mio. USD im Vorjahr, während der Nettogewinn 38,23 Mio. USD betrug gegenüber 46,82 Mio., was auf höhere Verwaltungskosten und Zinsaufwendungen zurückzuführen ist. Verwässerter Gewinn pro Aktie betrug 0,62 USD gegenüber 0,76. In den ersten neun Monaten betrug der operative Cashflow 338,27 Mio. USD.
Das Unternehmen vorantrieb wichtige Initiativen. Es schloss eine rein s stok-äquivalente Fusion mit Black Hills ab, bei der jede NWE-Aktie 0,98 Black Hills-Aktien erhalten wird, vorbehaltlich der Zustimmung der Aktionäre und der Aufsichtsbehörden. NWE hatte im Q3 fusionenbezogene Kosten in Höhe von 7,6 Mio. USD. In Montana bleiben vorläufige Strom- und Gas-Tarifstrukturen bis zu einer endgültigen Entscheidung, voraussichtlich im Q4 2025, in Kraft; im Nebraska wurden endgültige Gaspreise zum 1. Juli 2025 genehmigt. NWE schloss am 1. Juli 2025 die Barkauf-Übernahme der Energy West-Betriebe über 35,9 Mio. USD ab. Zusätzlich plant es, ab dem 1. Januar 2026 weitere Anteile an Colstrip Einheit 3 und 4 zu erwerben und Kostenrückgewinnung durch Einreichungen anzustreben.
Zu den Kapitalmaßnahmen gehörte die Ausgabe von Montana-Erstrang-Hypothekenanleihen in Höhe von 400 Mio. USD mit Fälligkeit 2030 und von South Dakota-Erstrang-Hypothekenanleihen in Höhe von 100 Mio. USD mit Fälligkeit 2035, sowie die Erweiterung eines revolvierenden Term Loan auf 150 Mio. USD. Die ausstehenden Aktien beliefen sich zum 24. Oktober 2025 auf 61.407.029.
أعلنت مجموعة نورثوستيرن للطاقة (NWE) عن نتائج الربع الثالث وتحديثات تنظيمية. بلغت الإيرادات للربع الثالث من عام 2025 نحو 386.95 مليون دولار، مقارنة بـ 345.16 مليون دولار في العام السابق، بينما كان صافي الدخل 38.23 مليون دولار مقابل 46.82 مليون دولار، مع وجود ارتفاع في التكاليف الإدارية ومصاريف الفوائد. بلغ الربح الموزع للسهم المخفف 0.62 دولار مقابل 0.76 دولار. وللأشهر التسعة الأولى، كان التدفق النقدي من الأنشطة التشغيلية 338.27 مليون دولار.
واصلت الشركة دفع مبادرات رئيسية. دخلت في اتفاق اندماج متبادل كامل الأسهم مع Black Hills، بحيث تحصل كل حصة من NWE على 0.98 من أسهم Black Hills، مع خضوع الاتفاق لموافقة المساهمين والجهات التنظيمية. تكبدت NWE 7.6 مليون دولار من تكاليف الاندماج في الربع الثالث. في مونتانا، تبقى هيكلية تسعير الكهرباء والغاز المؤقتة سارية المفعول في انتظار أمر نهائي من المتوقع صدوره في الربع الرابع من 2025؛ كما وافقت نبراسكا على أسعار الغاز النهائية المفعلة اعتباراً من 1 يوليو 2025. أغلقت NWE الاستحواذ النقدي بقيمة 35.9 مليون دولار لعمليات Energy West في 1 يوليو 2025. كما تخطط لاقتناء حصص إضافية في وحدات Colstrip 3 و4 اعتباراً من 1 يناير 2026، مع التقديمات الرامية لاسترداد التكاليف.
شملت أنشطة رأس المال إصدار سندات رهن أساسية لماونتانا بقيمة 400 مليون دولار تستحق في 2030 وسندات رهن أساسية لداكوتا الجنوبية بقيمة 100 مليون دولار تستحق في 2035، وتوسيع قرض طويل الأجل ليصل إلى 150 مليون دولار. كانت قيمة الأسهم المتداولة 61,407,029 اعتباراً من 24 أكتوبر 2025.
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 | |||||||||||
| OR | |||||||||||
| 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: 000-56598
(Exact name of registrant as specified in its charter)
| Delaware | ||||||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
Registrant’s telephone number, including area code: 605 -978-2900
N/A
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
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 x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes x No o
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 | 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. o
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:
Common Stock, Par Value $0.01, 61,407,029 shares outstanding at October 24, 2025
1
NORTHWESTERN ENERGY GROUP
FORM 10-Q
INDEX
| Page | ||||||||
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS | 3 | |||||||
PART I. FINANCIAL INFORMATION | 5 | |||||||
Item 1. | Financial Statements | 5 | ||||||
Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2025 and 2024 | 5 | |||||||
Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2025 and 2024 | 6 | |||||||
Condensed Consolidated Balance Sheets — September 30, 2025 and December 31, 2024 | 7 | |||||||
Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2025 and 2024 | 8 | |||||||
Condensed Consolidated Statements of Shareholders’ Equity — Three and Nine Months Ended September Ended September 30, 2025 and 2024 | 9 | |||||||
Notes to Condensed Consolidated Financial Statements | 11 | |||||||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 24 | ||||||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 51 | ||||||
Item 4. | Controls and Procedures | 52 | ||||||
PART II. OTHER INFORMATION | 53 | |||||||
Item 1. | Legal Proceedings | 53 | ||||||
Item 1A. | Risk Factors | 53 | ||||||
Item 5. | Other Information | 62 | ||||||
Item 6. | Exhibits | 63 | ||||||
SIGNATURES | 64 | |||||||
2
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to our current expectations of future financial performance, continued growth, changes in economic conditions or capital markets, changes in customer usage patterns and preferences, and statements relating to our pending merger with Black Hills Corporation are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, our examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:
•risks relating to the pending merger transaction pursuant to that certain Agreement and Plan of Merger dated August 18, 2025 (Merger Agreement) between NorthWestern and Black Hills Corporation (Black Hills), including, among others, (1) the risk of delays in consummating the pending merger transaction, including as a result of required regulatory and shareholder approvals, which may not be obtained on the expected timeline, or at all, (2) the risk of any event, change or other circumstance that could give rise to the termination of the Merger Agreement, (3) the risk that required regulatory approvals are subject to conditions not anticipated by NorthWestern and Black Hills, (4) the possibility that any of the anticipated benefits and projected synergies of the pending merger transaction will not be realized or will not be realized within the expected time period, (5) disruption to the parties’ businesses as a result of the announcement and pendency of the merger transaction, including potential distraction of management from current plans and operations of NorthWestern or Black Hills and the ability of NorthWestern or Black Hills to retain and hire key personnel, (6) reputational risk and the reaction of each company’s customers, suppliers, employees or other business partners to the pending merger transaction, (7) the possibility that the pending merger transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events, (8) the outcome of any legal or regulatory proceedings that may be instituted against NorthWestern or Black Hills related to the Merger Agreement or the pending merger transaction, (9) the risks associated with third party contracts containing consent and/or other provisions that may be triggered by the pending merger transaction, (10) legislative, regulatory, political, market, economic and other conditions, developments and uncertainties affecting NorthWestern's or Black Hills' businesses; (11) the evolving legal, regulatory and tax regimes under which NorthWestern and Black Hills operate; (12) restrictions during the pendency of the merger transaction that may impact NorthWestern's or Black Hills' ability to pursue certain business opportunities or strategic transactions; and (13) unpredictability and severity of catastrophic events, including, but not limited to, extreme weather, natural disasters, acts of terrorism or outbreak of war or hostilities, as well as NorthWestern's and Black Hills' response to any of the aforementioned factors;
•adverse determinations by regulators, such as adverse outcomes from the denial of interim rates or final rates not consistent with a reasonable ability to earn our allowed returns or failure to timely approve our requests associated with recovering the operating costs for the additional interests in Colstrip Units 3 and 4, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, and wildfire damages in excess of liability insurance coverage, could have a material effect on our liquidity, results of operations and financial condition;
•our ability to enter agreements to sell excess capacity and associated energy from additional interests in Colstrip Units 3 and 4 on favorable commercial and economic terms;
•the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;
3
•acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;
•supply chain constraints, recent high levels of inflation for product, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;
•changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
•unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and
•adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.
We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.
From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.
Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Energy Group,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Energy Group, Inc. and its subsidiaries.
4
| PART 1. FINANCIAL INFORMATION | ||||||||||||||
ITEM 1.FINANCIAL STATEMENTS
NORTHWESTERN ENERGY GROUP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Revenues | |||||||||||||||||||||||
| Electric | $ | $ | $ | $ | |||||||||||||||||||
| Gas | |||||||||||||||||||||||
| Total Revenues | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | |||||||||||||||||||||||
| Operating and maintenance | |||||||||||||||||||||||
| Administrative and general | |||||||||||||||||||||||
| Property and other taxes | |||||||||||||||||||||||
| Depreciation and depletion | |||||||||||||||||||||||
| Total Operating Expenses | |||||||||||||||||||||||
| Operating income | |||||||||||||||||||||||
| Interest expense, net | ( | ( | ( | ( | |||||||||||||||||||
| Other income, net | |||||||||||||||||||||||
| Income before income taxes | |||||||||||||||||||||||
| Income tax (expense) benefit | ( | ( | ( | ||||||||||||||||||||
| Net Income | $ | $ | $ | $ | |||||||||||||||||||
| Average Common Shares Outstanding | |||||||||||||||||||||||
| Basic Earnings per Average Common Share | $ | $ | $ | $ | |||||||||||||||||||
| Diluted Earnings per Average Common Share | $ | $ | $ | $ | |||||||||||||||||||
| Dividends Declared per Common Share | $ | $ | $ | $ | |||||||||||||||||||
See Notes to Condensed Consolidated Financial Statements
5
NORTHWESTERN ENERGY GROUP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(in thousands)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Net Income | $ | $ | $ | $ | |||||||||||||||||||
| Other comprehensive income, net of tax: | |||||||||||||||||||||||
| Foreign currency translation adjustment | ( | ( | |||||||||||||||||||||
| Reclassification of net losses on derivative instruments | |||||||||||||||||||||||
| Total Other Comprehensive Income | |||||||||||||||||||||||
| Comprehensive Income | $ | $ | $ | $ | |||||||||||||||||||
See Notes to Condensed Consolidated Financial Statements
6
NORTHWESTERN ENERGY GROUP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
| September 30, 2025 | December 31, 2024 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Restricted cash | |||||||||||
| Accounts receivable, net | |||||||||||
| Inventories | |||||||||||
| Regulatory assets | |||||||||||
| Prepaid expenses and other | |||||||||||
Total current assets | |||||||||||
| Property, plant, and equipment, net | |||||||||||
| Goodwill | |||||||||||
| Regulatory assets | |||||||||||
| Other noncurrent assets | |||||||||||
Total Assets | $ | $ | |||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Current maturities of finance leases | $ | $ | |||||||||
| Current portion of long-term debt | |||||||||||
| Short-term borrowings | |||||||||||
| Accounts payable | |||||||||||
| Accrued expenses and other | |||||||||||
| Regulatory liabilities | |||||||||||
Total current liabilities | |||||||||||
| Long-term finance leases | |||||||||||
| Long-term debt | |||||||||||
| Deferred income taxes | |||||||||||
| Noncurrent regulatory liabilities | |||||||||||
| Other noncurrent liabilities | |||||||||||
Total Liabilities | |||||||||||
| Commitments and Contingencies (Note 12) | |||||||||||
| Shareholders' Equity: | |||||||||||
Common stock, par value $ | |||||||||||
| Treasury stock at cost | ( | ( | |||||||||
| Paid-in capital | |||||||||||
| Retained earnings | |||||||||||
| Accumulated other comprehensive loss | ( | ( | |||||||||
Total Shareholders' Equity | |||||||||||
| Total Liabilities and Shareholders' Equity | $ | $ | |||||||||
See Notes to Condensed Consolidated Financial Statements
7
NORTHWESTERN ENERGY GROUP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
OPERATING ACTIVITIES: | |||||||||||
| Net income | $ | $ | |||||||||
| Adjustments to reconcile net income to cash provided by operations: | |||||||||||
| Depreciation and depletion | |||||||||||
| Amortization of debt issuance costs, discount and deferred hedge gain | |||||||||||
| Stock-based compensation costs | |||||||||||
| Equity portion of allowance for funds used during construction | ( | ( | |||||||||
| Gain on disposition of assets | ( | ( | |||||||||
| Impairment of alternative energy storage investment | |||||||||||
| Deferred income taxes | |||||||||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable | |||||||||||
| Inventories | ( | ( | |||||||||
| Other current assets | ( | ( | |||||||||
| Accounts payable | ( | ( | |||||||||
| Accrued expenses and other | |||||||||||
| Regulatory assets | ( | ( | |||||||||
| Regulatory liabilities | ( | ( | |||||||||
| Other noncurrent assets and liabilities | ( | ( | |||||||||
| Cash Provided by Operating Activities | |||||||||||
| INVESTING ACTIVITIES: | |||||||||||
| Property, plant, and equipment additions | ( | ( | |||||||||
| Acquisition of Energy West Operations | ( | ||||||||||
| Investment in debt & equity securities | ( | ( | |||||||||
| Cash Used in Investing Activities | ( | ( | |||||||||
| FINANCING ACTIVITIES: | |||||||||||
| Dividends on common stock | ( | ( | |||||||||
| Issuance of long-term debt | |||||||||||
| Issuance of short-term borrowings | |||||||||||
| Repayments on long-term debt | ( | ( | |||||||||
| Line of credit repayments, net | ( | ( | |||||||||
| Other financing activities, net | ( | ( | |||||||||
| Cash Provided by Financing Activities | |||||||||||
| (Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash | |||||||||||
| Cash, Cash Equivalents, and Restricted Cash, beginning of period | |||||||||||
Cash, Cash Equivalents, and Restricted Cash, end of period | $ | $ | |||||||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash (received) paid during the period for: | |||||||||||
Production tax credits(1) | ( | ||||||||||
| Interest | |||||||||||
| Significant non-cash transactions: | |||||||||||
| Capital expenditures included in accounts payable | |||||||||||
(1) Proceeds from production tax credits transferred are included in cash provided by operating activities within the Condensed Consolidated Statement of Cash Flows.
See Notes to Condensed Consolidated Financial Statements
8
NORTHWESTERN ENERGY GROUP
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Unaudited)
(in thousands, except per share data)
| Three Months Ended September 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| Number of Common Shares | Number of Treasury Shares | Common Stock | Treasury Stock | Paid in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Total Shareholders' Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2024 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | |||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of shares | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2024 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2025 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | |||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of shares | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2025 | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
9
| Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||||||||||||
| Number of Common Shares | Number of Treasury Shares | Common Stock | Treasury Stock | Paid in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Total Shareholders' Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2023 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of shares | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2024 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2024 | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of shares | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2025 | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
See Notes to Condensed Consolidated Financial Statements
10
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Reference is made to Notes to Financial Statements included in the NorthWestern Energy Group's Annual Report)
(Unaudited)
(1) Nature of Operations and Basis of Consolidation
NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 842,100 customers in Montana, South Dakota, Nebraska and Yellowstone National Park, through its subsidiaries NorthWestern Corporation (NW Corp) and NorthWestern Energy Public Service Corporation (NWE Public Service). We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires us to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in our opinion, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2025 have been evaluated as to their potential impact to the Financial Statements through the date of issuance.
The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the condensed disclosures provided are adequate to make the information presented not misleading. We recommend that these Financial Statements be read in conjunction with the audited financial statements and related footnotes included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024.
Supplemental Cash Flow Information
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):
| September 30, | December 31, | September 30, | December 31, | |||||||||||
| 2025 | 2024 | 2024 | 2023 | |||||||||||
| Cash and cash equivalents | $ | $ | $ | $ | ||||||||||
| Restricted cash | ||||||||||||||
| Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows | $ | $ | $ | $ | ||||||||||
Goodwill
We completed our annual goodwill impairment test as of April 1, 2025, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.
(2) Pending Merger with Black Hills Corporation
On August 18, 2025, we entered into a Merger Agreement with Black Hills and River Merger Sub Inc., a direct wholly owned subsidiary of Black Hills (Merger Sub). The Merger Agreement provides for an all-stock merger of equals between NorthWestern and Black Hills upon the terms and subject to the conditions set forth therein. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (Merger), with NorthWestern continuing as the surviving entity and a
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direct wholly owned subsidiary of Black Hills, which would assume a new corporate name (NewCo) as the resulting parent company of the combined corporate group. Under the provisions of Accounting Standards Codification Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of NorthWestern, par value $0.01 per share, issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of common stock of Black Hills, par value $1.00 per share (Black Hills Common Stock).
In connection with this pending merger, we have incurred merger-related costs. During the three months ended September 30, 2025, we have incurred $7.6 million of merger-related costs, which are included in our Administrative and general expenses.
Regulatory and Shareholder Approvals
Our pending merger with Black Hills was unanimously approved by our board of directors and Black Hills' board of directors. The completion of the Merger is subject to the satisfaction or waiver of certain conditions to closing, including (1) the effectiveness of a registration statement on Form S-4 to be filed in connection with the Merger; (2) the approval of applicable transaction-related proposals by NorthWestern and Black Hills' shareholders in accordance with applicable law; (3) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and approval from the Federal Energy Regulatory Commission (FERC), the Montana Public Service Commission (MPSC), the Nebraska Public Service Commission (NPSC), and the South Dakota Public Utilities Commission (SDPUC), in each case on such terms and conditions that would not result in a material adverse effect on NewCo; (4) the absence of any court order or regulatory injunction prohibiting the completion of the Merger; (5) the authorization for listing of shares of Black Hills Common Stock to be issued in the Merger on a mutually agreed stock exchange; (6) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (7) compliance by each party in all material respects with its covenants; (8) the absence of a material adverse effect on each party; and (9) receipt of each party of an opinion relating to the anticipated tax-free treatment of the Merger.
In October 2025, we filed applications with the MPSC, NPSC, and SDPUC for approval of the Merger. We anticipate filing an application with the FERC in the fourth quarter of 2025. We anticipate the transaction closing in the second half of 2026, subject to the satisfaction or waiver of certain closing conditions.
(3) Acquisition of Energy West Operations
In July 2024, NW Corp entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas distribution system and operations serving approximately 33,000 customers located in Great Falls, Cut Bank, and West Yellowstone, Montana. In May 2025, the MPSC approved this acquisition and on July 1, 2025, NW Corp completed this acquisition for approximately $35.9 million in cash, which is subject to certain post-closing working capital adjustments. Determination of the final purchase price is expected to be completed in the fourth quarter of 2025. Upon the completion of the acquisition, NW Corp transferred the utility operations to its two wholly-owned subsidiaries, NorthWestern Great Falls Gas LLC and NorthWestern Cut Bank Gas LLC.
The assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the Financial Accounting Standards Board Accounting Standards Codification. These assets and liabilities are subject to rate-setting provisions that provide for revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values.
(4) Regulatory Matters
Montana Rate Review
In July 2024, we filed a Montana electric and natural gas rate review with the MPSC. In November 2024, the MPSC partially approved our requested interim rates effective December 1, 2024, subject to refund. Subsequently, we modified our request through rebuttal testimony. In March 2025, we filed a natural gas settlement with certain parties. In April 2025, we filed a partial electric settlement with certain other parties. Both settlements are subject to approval by the MPSC.
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The partial electric settlement includes, among other things, agreement on base revenue increases (excluding base revenues associated with Yellowstone County Generating Station (YCGS)), allocated cost of service, rate design, updates to the amount of revenues associated with property taxes (excluding property taxes associated with YCGS), regulatory policy issues related to requested changes in regulatory mechanisms, and agreement to support a separate motion for revised electric interim rates. The partial electric settlement provides for the deferral and annual recovery of incremental operating costs related to wildfire mitigation and insurance expenses through the Wildfire Mitigation Balancing Account.
The natural gas settlement includes, among other things, agreement on base revenues, allocated cost of service, rate design, updates to the amount of revenues associated with property taxes, and agreement to support a separate motion for revised natural gas interim rates.
The details of our filing request, as adjusted in rebuttal testimony, are set forth below:
| Requested Revenue Increase (Decrease) Through Rebuttal Testimony (in millions) | |||||||||||
| Electric | Natural Gas | ||||||||||
| Base Rates | $ | ||||||||||
Power Cost & Credit Adjustment Mechanism (PCCAM)(1) | ( | n/a | |||||||||
Property Tax (tracker base adjustment)(1) | ( | ||||||||||
| Total Revenue Increase Requested through Rebuttal Testimony | $ | $ | |||||||||
(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.
The details of our interim rates granted are set forth below:
| Interim Revenue Increase (Decrease) Granted (in millions) | |||||||||||
Electric(1) | Natural Gas(2) | ||||||||||
| Base Rates | $ | $ | |||||||||
PCCAM(3) | ( | n/a | |||||||||
Property Tax (tracker base adjustment)(3)(4) | |||||||||||
| Total Interim Revenue Granted | $ | ( | $ | ||||||||
(1) These electric interim rates were effective December 1, 2024, through May 22, 2025. See further discussion on revised electric interim rates below.
(2) These natural gas interim rates were effective December 1, 2024, and are expected to remain in effect until the MPSC final order rates are effective.
(3) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.
(4) Our requested interim property tax base increase went into effect on January 1, 2025, as part of our 2024 property tax tracker filing.
The details of our settlement agreement are set forth below:
Requested Revenue Increase (Decrease) through Settlement Agreements (in millions) | |||||||||||
Electric(1) | Natural Gas | ||||||||||
Base Rates: | |||||||||||
Base Rates (Settled) | $ | $ | |||||||||
Base Rates - YCGS (Non-settled)(2)(3) | n/a | ||||||||||
Requested Base Rates | |||||||||||
Pass-through items: | |||||||||||
Property Tax (tracker base adjustment) (Settled)(4) | ( | ||||||||||
Property Tax (tracker base adjustment) - YCGS (Non-settled)(2)(4) | n/a | ||||||||||
PCCAM (Non-settled)(2)(3)(4) | ( | n/a | |||||||||
Requested Pass-Through Rates | ( | ||||||||||
Total Requested Revenue Increase | $ | $ | |||||||||
(1) We implemented these electric rates on July 2, 2025, on an interim basis, subject to refund.
(2) These items were not included within the partial electric settlement and will be contested items that are expected to be determined in the MPSC's final order.
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(3) Intervenor positions on YCGS propose up to an $11.6 million reduction to the base rate revenue request and an additional $38.4 million decrease to the PCCAM base.
(4) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.
On May 23, 2025, as permitted by Montana statute, we implemented our initially requested electric rates, reflecting a base rate revenue increase of $156.5 million, on an interim basis, subject to refund with interest. On June 20, 2025, we submitted the revised electric interim rates of $110.3 million as shown within the above table to the MPSC for approval. The MPSC subsequently approved this request and the revised rates were implemented on July 2, 2025. We have deferred base rate revenues collected between May 23, 2025, and July 1, 2025, down to our requested revised electric interim rates as shown within the above table. As of September 30, 2025, we have deferred approximately $3.5 million of base rate revenues collected.
As discussed above, if the MPSC chooses to accept the intervenors positions on the remaining contested issues or does not accept the Settlement Agreements in its final order, losses related to excess interim revenues collected will be incurred. Additionally, any difference between interim and final approved rates will be refunded to customers with interest. However, if final approved rates are higher than interim rates, we will not recover the difference.
A hearing on the electric and natural gas rate review was held in June 2025, and final briefs were submitted in August 2025. Interim rates will remain in effect on a refundable basis, with interest, until the MPSC issues a final order. A final order is expected during the fourth quarter of 2025.
Nebraska Natural Gas Rate Review
In June 2024, we filed a natural gas rate review with the NPSC. Interim rates, which increased base natural gas rates $2.3 million, were implemented on October 1, 2024. In April 2025, we reached a settlement agreement with certain parties for a base rate annual revenue increase of $2.4 million. In June 2025, the NPSC approved this settlement agreement and final rates were implemented on July 1, 2025.
Colstrip Acquisitions and Requests for Cost Recovery
As previously disclosed, we entered into definitive agreements with Avista Corporation (Avista) and Puget Sound Energy (Puget) to acquire their respective interests in Colstrip Units 3 and 4 for $0 and expect to complete these acquisitions on January 1, 2026. Accordingly, we will be responsible for associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates, until requested in a future Montana rate review. Puget and Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests. At closing, we will reimburse Puget and Avista for the proportionate amount of the long-term capital enhancement work they each funded subsequent to executing the definitive agreements and up until the acquisition close date.
Avista Interests - The 222 megawatts of generation capacity from Colstrip Units 3 and 4 to be acquired from Avista (Avista Interests) was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that would provide a near-term cost-recovery mechanism expected to largely offset approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requests that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interest. Under the PCCAM design, market sales, which include long-term power sales contracts, flow back to retail customers as a reduction to energy supply costs and would be subject to the 90/10 sharing mechanism. Furthermore, the waiver request indicates that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interest would continue to flow back to retail customers through the PCCAM as a reduction to energy supply costs. We expect a decision from the MPSC by the first quarter of 2026.
Puget Interests - The incremental interest in Colstrip Units 3 and 4 to be acquired from Puget (Puget Interests) increases our ownership share of the facility to 55 percent and provides an increase in voting share in determining strategic direction and investment decisions at the facility. While we expect our future opportunity to serve large load customers may be supported by this resource, we expect to sell excess capacity in the near term. We expect to sign a contract in the fourth quarter of 2025 to sell the dispatchable capacity and associated energy from the Puget Interest beginning January 1, 2026, through late 2027. Revenues from this agreement are expected to largely offset the estimated $30.0 million of annual incremental operating and maintenance costs associated with the Puget Interests. In addition, in October 2025, we submitted a request to the FERC for approval of cost-based rates for our subsidiary that will own the Puget Interests. We expect this rate approval to be effective by January 1, 2026.
(5) Income Taxes
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We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.
On July 4, 2025, the One Big Beautiful Bill Act (OBBB) was signed into law, which includes significant changes to the U.S. tax code and related laws. Key provisions of the OBBB include modifications and extensions to certain provisions of the Tax Cuts and Jobs Act of 2017, changes to interest expense limitations, and updates to energy-related tax incentives. We have evaluated the potential impact of the OBBB to our financial statements and determined that the impact is not material.
During the three months ended September 30, 2025 income tax expense was $8.8 million compared to an income tax benefit of $3.2 million for the same period in 2024. For the three months ended September 30, 2025, the effective tax rate was 18.7 % compared to (7.3 )% for the same period in 2024. The higher effective tax rate was primarily due to the prior year gas repairs safe harbor method change, non-deductible merger-related transaction expenses, higher plant depreciation flow through items, and lower production tax credits.
During the nine months ended September 30, 2025 income tax expense was $27.4 million compared to $11.4 million for the same period in 2024. For the nine months ended September 30, 2025, the effective tax rate was 16.7 % compared to 7.4 % for the same period in 2024. The higher effective tax rate was primarily due to the prior year gas repairs safe harbor method change, higher plant depreciation flow through items, lower production tax credits, and non-deductible merger-related transaction expenses, partly offset by higher flow through repairs deductions.
(6) Comprehensive Income (Loss)
The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||||||||||||||||||||||||||
| Before-Tax Amount | Tax Expense | Net-of-Tax Amount | Before-Tax Amount | Tax Expense | Net-of-Tax Amount | ||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | $ | ( | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||
| Reclassification of net income on derivative instruments | ( | ( | |||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
| Nine Months Ended | |||||||||||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||||||||||||||||||||||||||
| Before-Tax Amount | Tax Expense | Net-of-Tax Amount | Before-Tax Amount | Tax Expense | Net-of-Tax Amount | ||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | $ | $ | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||||||||
| Reclassification of net income on derivative instruments | ( | ( | |||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | $ | $ | ( | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):
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| September 30, 2025 | December 31, 2024 | ||||||||||
| Foreign currency translation | $ | $ | |||||||||
| Derivative instruments designated as cash flow hedges | ( | ( | |||||||||
| Postretirement medical plans | |||||||||||
| Accumulated other comprehensive loss | $ | ( | $ | ( | |||||||
The following tables display the changes in AOCL by component, net of tax (in thousands):
| Three Months Ended | |||||||||||||||||||||||||||||
| September 30, 2025 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Other comprehensive income before reclassifications | ( | ( | |||||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | ||||||||||||||||||||||||||||
| Net current-period other comprehensive income (loss) | ( | ||||||||||||||||||||||||||||
| Ending balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Three Months Ended | |||||||||||||||||||||||||||||
| September 30, 2024 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Other comprehensive loss before reclassifications | |||||||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | ||||||||||||||||||||||||||||
| Net current-period other comprehensive income | |||||||||||||||||||||||||||||
| Ending balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
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| Nine Months Ended | |||||||||||||||||||||||||||||
| September 30, 2025 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Defined Benefit Pension Plan and Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Other comprehensive loss before reclassifications | |||||||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | ||||||||||||||||||||||||||||
| Net current-period other comprehensive income | |||||||||||||||||||||||||||||
| Ending balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Nine Months Ended | |||||||||||||||||||||||||||||
| September 30, 2024 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Pension and Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
| Other comprehensive loss before reclassifications | ( | ( | |||||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | ||||||||||||||||||||||||||||
| Net current-period other comprehensive income (loss) | ( | ||||||||||||||||||||||||||||
| Ending balance | $ | ( | $ | $ | $ | ( | |||||||||||||||||||||||
(7) Financing Activities
On March 21, 2025, NW Corp issued and sold $400.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.07 percent maturing on March 21, 2030 . These bonds were issued and sold to certain initial purchasers without being registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon exemptions therefrom in compliance with Rule 144A under the Securities Act, or under Regulation S under the Securities Act for sales to non-U.S. persons. Proceeds were utilized to redeem NW Corp's $161.0 million of 5.01 percent Montana First Mortgage Bonds due May 1, 2025 and $75.0 million of 3.11 percent Montana First Mortgage Bonds due July 1, 2025 , to repay outstanding borrowings under our NW Corp revolving credit facility, and for general utility purposes.
On April 11, 2025, we amended our existing NorthWestern Energy Group $100.0 million Term Loan Credit Agreement (Term Loan) to extend the maturity date from April 11, 2025 to April 10, 2026 . On September 29, 2025, we amended our Term Loan to increase the total commitment to $150.0 million. As of September 30, 2025, we have borrowed $150.0 million under the Term Loan and the proceeds were used for general corporate purposes.
On May 1, 2025, NWE Public Service issued and sold $100.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.49 percent maturing on May 1, 2035 . These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were utilized to repay at maturity $64.0 million of NWE Public Service's 5.01 percent South Dakota First Mortgage Bonds due on May 1, 2025 and for other general utility purposes.
(8) Segment Information
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Our reportable segments are engaged in the electric and natural gas utility businesses.
Our Chief Operating Decision Maker (CODM), who is our Chief Executive Officer, uses segment net income to evaluate if our operating segments are earning their authorized rate of return and in the annual budget and forecasting process. Our CODM also uses segment net income to determine how to allocate capital resources between our operating segments and when to allocate the resources necessary to file for rate reviews. Segment asset and capital expenditure information is not provided for our reportable segments. As an integrated electric and gas utility, we operate significant assets that are not dedicated to a specific reportable segment.
Financial data for the reportable segments are as follows (in thousands):
| Three Months Ended | |||||||||||||||||
| September 30, 2025 | Electric | Gas | Total | ||||||||||||||
| Operating revenues | $ | $ | $ | ||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | |||||||||||||||||
| Operating, general, and administrative | |||||||||||||||||
| Property and other taxes | |||||||||||||||||
| Depreciation and depletion | |||||||||||||||||
| Interest expense, net | ( | ( | ( | ||||||||||||||
| Other income, net | |||||||||||||||||
| Income tax (expense) benefit | ( | ( | |||||||||||||||
| Segment net income (loss) | $ | $ | ( | $ | |||||||||||||
| Reconciliation to consolidated net income | |||||||||||||||||
Other, net(1) | ( | ||||||||||||||||
| Consolidated net income | $ | ||||||||||||||||
| Three Months Ended | |||||||||||||||||
| September 30, 2024 | Electric | Gas | Total | ||||||||||||||
| Operating revenues | $ | $ | $ | ||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | |||||||||||||||||
| Operating, general, and administrative | |||||||||||||||||
| Property and other taxes | |||||||||||||||||
| Depreciation and depletion | |||||||||||||||||
| Interest expense, net | ( | ( | ( | ||||||||||||||
| Other income, net | |||||||||||||||||
| Income tax (expense) benefit | ( | ||||||||||||||||
| Segment net income (loss) | $ | $ | ( | $ | |||||||||||||
| Reconciliation to consolidated net income | |||||||||||||||||
Other, net(1) | ( | ||||||||||||||||
| Consolidated net income | $ | ||||||||||||||||
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| Nine Months Ended | |||||||||||||||||
| September 30, 2025 | Electric | Gas | Total | ||||||||||||||
| Operating revenues | $ | $ | $ | ||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | |||||||||||||||||
| Operating, general, and administrative | |||||||||||||||||
| Property and other taxes | |||||||||||||||||
| Depreciation and depletion | |||||||||||||||||
| Interest expense, net | ( | ( | ( | ||||||||||||||
| Other income, net | |||||||||||||||||
| Income tax expense | ( | ( | ( | ||||||||||||||
| Segment net income | $ | $ | $ | ||||||||||||||
| Reconciliation to consolidated net income | |||||||||||||||||
Other, net(1) | ( | ||||||||||||||||
| Consolidated net income | $ | ||||||||||||||||
| Nine Months Ended | |||||||||||||||||
| September 30, 2024 | Electric | Gas | Total | ||||||||||||||
| Operating revenues | $ | $ | $ | ||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | |||||||||||||||||
| Operating, general, and administrative | |||||||||||||||||
| Property and other taxes | |||||||||||||||||
| Depreciation and depletion | |||||||||||||||||
| Interest expense, net | ( | ( | ( | ||||||||||||||
| Other income, net | |||||||||||||||||
| Income tax (expense) benefit | ( | ( | |||||||||||||||
| Segment net income | $ | $ | $ | ||||||||||||||
| Reconciliation to consolidated net income | |||||||||||||||||
Other, net(1) | ( | ||||||||||||||||
| Consolidated net income | $ | ||||||||||||||||
(1) Consists of unallocated corporate costs, including merger-related costs, and certain limited unregulated activity within the energy industry.
(9) Revenue from Contracts with Customers
Nature of Goods and Services
We provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which includes single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products.
Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to customers in our Montana and South Dakota jurisdictions. We recognize revenue when electricity is delivered to the customer. Payments on our tariff-based sales are generally due 0-30 days after the billing date.
Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to customers in our Montana, South Dakota, and Nebraska jurisdictions. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff-based sales are generally due 0-30 days after the billing date.
Disaggregation of Revenue
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The following tables disaggregate our revenue by major source and customer class (in millions):
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||||||||||||||||||||||||||
| Electric | Natural Gas | Total | Electric | Natural Gas | Total | ||||||||||||||||||||||||||||||
| Montana | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
| South Dakota | |||||||||||||||||||||||||||||||||||
| Nebraska | |||||||||||||||||||||||||||||||||||
| Residential | |||||||||||||||||||||||||||||||||||
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| South Dakota | |||||||||||||||||||||||||||||||||||
| Nebraska | |||||||||||||||||||||||||||||||||||
| Commercial | |||||||||||||||||||||||||||||||||||
| Industrial | |||||||||||||||||||||||||||||||||||
| Lighting, governmental, irrigation, and interdepartmental | |||||||||||||||||||||||||||||||||||
| Total Retail Revenues | |||||||||||||||||||||||||||||||||||
| Regulatory Amortization | ( | ||||||||||||||||||||||||||||||||||
| Transmission | |||||||||||||||||||||||||||||||||||
| Transportation, wholesale and other | |||||||||||||||||||||||||||||||||||
Total Revenues(1) | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
| Nine Months Ended | |||||||||||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||||||||||||||||||||||||||
| Electric | Natural Gas | Total | Electric | Natural Gas | Total | ||||||||||||||||||||||||||||||
| Montana | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
| South Dakota | |||||||||||||||||||||||||||||||||||
| Nebraska | |||||||||||||||||||||||||||||||||||
| Residential | |||||||||||||||||||||||||||||||||||
| Montana | |||||||||||||||||||||||||||||||||||
| South Dakota | |||||||||||||||||||||||||||||||||||
| Nebraska | |||||||||||||||||||||||||||||||||||
| Commercial | |||||||||||||||||||||||||||||||||||
| Industrial | |||||||||||||||||||||||||||||||||||
| Lighting, governmental, irrigation, and interdepartmental | |||||||||||||||||||||||||||||||||||
| Total Retail Revenues | |||||||||||||||||||||||||||||||||||
| Regulatory Amortization | |||||||||||||||||||||||||||||||||||
| Transmission | |||||||||||||||||||||||||||||||||||
| Transportation, wholesale and other | |||||||||||||||||||||||||||||||||||
Total Revenues(1) | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
(10) Earnings Per Share
Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the
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treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:
| Three Months Ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| Basic computation | |||||||||||
| Dilutive effect of: | |||||||||||
Performance and restricted share awards(1) | |||||||||||
| Diluted computation | |||||||||||
(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.
| Nine Months Ended | |||||||||||
| September 30, 2025 | September 30, 2024 | ||||||||||
| Basic computation | |||||||||||
| Dilutive effect of: | |||||||||||
Performance and restricted share awards(1) | |||||||||||
| Diluted computation | |||||||||||
As of September 30, 2025, there were 20,406 shares from performance share awards which were antidilutive and excluded from the earnings per share calculations, compared to 16,015 shares as of September 30, 2024.
(11) Employee Benefit Plans
We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (credit) for our pension and other postretirement plans consists of the following (in thousands):
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| Three Months Ended September 30, | Three Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Components of Net Periodic Benefit Cost (Credit) | |||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||
| Interest cost | |||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | |||||||||||||||||||
| Recognized actuarial loss (gain) | ( | ( | |||||||||||||||||||||
Settlement loss recognized(1) | |||||||||||||||||||||||
| Net periodic benefit cost (credit) | $ | $ | $ | ( | $ | ( | |||||||||||||||||
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| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| Nine Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Components of Net Periodic Benefit Cost (Credit) | |||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||
| Interest cost | |||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | |||||||||||||||||||
| Recognized actuarial loss (gain) | ( | ( | |||||||||||||||||||||
Settlement loss recognized(1) | |||||||||||||||||||||||
| Net periodic benefit cost (credit) | $ | $ | $ | ( | $ | ( | |||||||||||||||||
(1) Settlement loss is related to the partial annuitization of NorthWestern Energy's MT Pension Plan participants. We purchased the contract with $221.4 million of plan assets, which was approximately 92 percent of the associated pension obligation settled. The insurance company will take over the payments of these benefits starting November 1, 2025. As a result of this transaction, during the nine months ended September 30, 2025, we recorded a non-cash, non-operating settlement charge of $1.2 million. This charge is recorded within other income, net on the Condensed Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities to the financial statements included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024, the MPSC allows recovery of pension costs on a cash funding basis. As such, this charge was deferred as a regulatory asset on the Condensed Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Condensed Consolidated Statements of Income.
(12) Commitments and Contingencies
| ENVIRONMENTAL LIABILITIES AND REGULATION | ||||||||||||||
Except as set forth below, the circumstances set forth in Note 18 - Commitments and Contingencies to the financial statements included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024 appropriately represent, in all material respects, the current status of our environmental liabilities and regulation.
Environmental Protection Agency (EPA) Rules
On April 25, 2024, the EPA released final rules related to greenhouse gas (GHG) emission standards (GHG Rules) for existing coal-fired facilities and new coal and natural gas-fired facilities as well as final rules strengthening the MATS requirements (MATS Rules). Compliance with the rules would require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively.
On June 11, 2025, the EPA issued a Notice of Proposed Rulemaking containing two proposals to reform GHG regulations. If either the lead or alternative proposal is adopted, our additional material compliance costs would be eliminated. On June 11, 2025, the EPA also issued a Notice of Proposed Rulemaking to rescind the 2024 MATS Rule, which if enacted, would restore the original 2012 MATS standards. There is no mandated timeline for final action on the rules.
These GHG Rules and MATS Rules as well as future additional environmental requirements - federal or state - could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such requirements.
| LEGAL PROCEEDINGS | ||
State of Montana - Riverbed Rents
On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State’s Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen Montana, LLC (Talen) as defendants. The State claimed it owns the riverbeds underlying 10 of our, and formerly Talen’s, hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such
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lands. The facilities at issue include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.
The litigation has a long prior history in state and federal court, including before the United States Supreme Court, as detailed in Note 18 - Commitments and Contingencies to the financial statements included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024. The Federal District Court held a bench trial from January 4 to January 18, 2022, which addressed the issue of navigability concerning the six facilities that had not been dismissed from the proceedings. On August 25, 2023, the Federal District Court issued its Findings of Fact, Conclusions of Law, and Order (the Order), which found all but one of the segments of the riverbeds in dispute not navigable, and thus not owned by the State of Montana. The one segment found navigable, and thus owned by the State, was the segment on which the Black Eagle development was located. After briefing and oral argument, the 9th Circuit affirmed the Federal District Court's Order in full on March 4, 2025.
The District Court is scheduled to hold a bench trial to determine damages for the Sun River to Black Eagle Falls Segment of the Missouri River on September 21, 2026. If the Federal District Court calculates damages as the State District Court did in 2008, we do not anticipate the resulting annual rent for the Black Eagle segment would have a material impact to our financial position or results of operations. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.
Other Legal Proceedings
We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.
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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.
We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
| OVERVIEW | ||||||||||||||
NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 842,100 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024.
On August 18, 2025, we entered into the Merger Agreement with Black Hills and Merger Sub that provides for an all-stock merger of equals between NorthWestern and Black Hills. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern, with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume a new corporate name as the resulting parent company of the combined corporate group. The Merger will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise. It is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers. Under the provisions of Accounting Standards Codification Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of common stock of NorthWestern issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of Black Hills Common Stock. See Note 2 - Pending Merger with Black Hills Corporation to the Condensed Consolidated Financial Statements included herein for additional information regarding this pending Merger.
We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:
•Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
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•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050.
As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three and nine months ended September 30, 2025 and 2024.
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| HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2024 RESULTS | ||||||||||||||
| Three Months Ended September 30, 2025 vs. 2024 | ||||||||||||||||||||
| Income Before Income Taxes | Income Tax (Expense) Benefit(3) | Net Income | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Third Quarter, 2024 | $ | 43.6 | $ | 3.2 | $ | 46.8 | ||||||||||||||
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income: | ||||||||||||||||||||
| Rates | 29.3 | (7.4) | 21.9 | |||||||||||||||||
Electric retail volumes | 5.8 | (1.5) | 4.3 | |||||||||||||||||
Production tax credits, offset within income tax benefit | 3.0 | (3.0) | — | |||||||||||||||||
Electric transmission revenue | 2.1 | (0.5) | 1.6 | |||||||||||||||||
| Natural gas transportation | 1.3 | (0.3) | 1.0 | |||||||||||||||||
Natural gas retail volumes | 0.6 | (0.2) | 0.4 | |||||||||||||||||
Non-recoverable Montana electric supply costs | (3.0) | 0.8 | (2.2) | |||||||||||||||||
| Montana property tax tracker collections | (2.8) | 0.7 | (2.1) | |||||||||||||||||
| Other | 0.9 | (0.2) | 0.7 | |||||||||||||||||
Variance in expense items(2) impacting net income: | ||||||||||||||||||||
| Operating, maintenance, and administrative, excluding merger-related costs | (11.5) | 2.9 | (8.6) | |||||||||||||||||
| Merger-related costs | (7.6) | — | (7.6) | |||||||||||||||||
| Property and other taxes not recoverable within trackers | (0.9) | 0.2 | (0.7) | |||||||||||||||||
Depreciation | (5.8) | 1.5 | (4.3) | |||||||||||||||||
Interest expense | (5.0) | 1.3 | (3.7) | |||||||||||||||||
| Prior year gas repairs safe harbor method change | — | (7.0) | (7.0) | |||||||||||||||||
| Other | (3.0) | 0.7 | (2.3) | |||||||||||||||||
| Third Quarter, 2025 | $ | 47.0 | $ | (8.8) | $ | 38.2 | ||||||||||||||
| Change in Net Income | $ | (8.6) | ||||||||||||||||||
(1) Exclusive of depreciation and depletion shown separately below
(2) Excluding fuel, purchased supply, and direct transmission expense
(3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent.
Consolidated net income for the three months ended September 30, 2025 was $38.2 million as compared with $46.8 million for the same period in 2024. This decrease was primarily due to higher operating expenses, including merger-related costs and depreciation, higher interest expense, and a prior year income tax benefit from a gas repairs safe harbor method change. These were offset in part by new rates and customer usage.
| SIGNIFICANT TRENDS AND REGULATION | ||||||||||||||
Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2024 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:
Montana Rate Review
In July 2024, we filed a Montana electric and natural gas rate review with the MPSC. In March 2025, we filed a natural gas settlement with certain parties. In April 2025, we filed a partial electric settlement with certain other parties. Both settlements are subject to approval by the MPSC.
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The partial electric settlement includes, among other things, agreement on base revenue increases (excluding base revenues associated with YCGS), allocated cost of service, rate design, updates to the amount of revenues associated with property taxes (excluding property taxes associated with YCGS), regulatory policy issues related to requested changes in regulatory mechanisms, and agreement to support a separate motion for revised electric interim rates. The partial electric settlement provides for the deferral and annual recovery of incremental operating costs related to wildfire mitigation and insurance expenses through the Wildfire Mitigation Balancing Account.
The natural gas settlement includes, among other things, agreement on base revenues, allocated cost of service, rate design, updates to the amount of revenues associated with property taxes, and agreement to support a separate motion for revised natural gas interim rates.
The details of our settlement agreement are set forth below:
Requested Revenue Increase (Decrease) through Settlement Agreements (in millions) | |||||||||||
Electric(1) | Natural Gas | ||||||||||
Base Rates: | |||||||||||
Base Rates (Settled) | $ | 66.4 | $ | 18.0 | |||||||
Base Rates - YCGS (Non-settled)(2)(3) | 43.9 | n/a | |||||||||
Requested Base Rates | 110.3 | 18.0 | |||||||||
Pass-through items: | |||||||||||
Property Tax (tracker base adjustment) (Settled)(4) | (5.2) | 0.1 | |||||||||
Property Tax (tracker base adjustment) - YCGS (Non-settled)(2)(4) | 4.0 | n/a | |||||||||
PCCAM (Non-settled)(2)(3)(4) | (94.5) | n/a | |||||||||
Requested Pass-Through Rates | (95.7) | 0.1 | |||||||||
Total Requested Revenue Increase | $ | 14.6 | $ | 18.1 | |||||||
(1) We implemented these electric rates on July 2, 2025, on an interim basis, subject to refund.
(2) These items were not included within the partial electric settlement and will be contested items that are expected to be determined in the MPSC's final order.
(3) Intervenor positions on YCGS propose up to an $11.6 million reduction to the base rate revenue request and an additional $38.4 million decrease to the PCCAM base.
(4) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.
On June 20, 2025, we submitted the revised electric interim rates of $110.3 million as shown within the above table to the MPSC for approval. The MPSC subsequently approved this request and the rates were implemented on July 2, 2025.
As discussed above, if the MPSC chooses to accept the intervenors positions on the remaining contested issues or does not accept the Settlement Agreements in its final order, losses related to excess interim revenues collected will be incurred. Additionally, any difference between interim and final approved rates will be refunded to customers with interest. However, if final approved rates are higher than interim rates, we will not recover the difference.
A hearing on the electric and natural gas rate review was held in June 2025, and final briefs were submitted in August 2025. Interim rates will remain in effect on a refundable basis, with interest, until the MPSC issues a final order. A final order is expected during the fourth quarter of 2025.
For further information on our Montana rate review, see Note 4 - Regulatory Matters to the Condensed Consolidated Financial Statements included herein.
Montana Large Load Tariff
The MPSC requested information on our plan to serve potential large load customers and related resource adequacy issues. We responded in March 2025, outlining our policy and legal positions, emphasizing the importance of economic development for Montana and our commitment to serving our existing customers. We expect to submit a filing with the MPSC during the fourth quarter of 2025 to address data center development discussed below, incorporating rate design that prevents cost shifting of infrastructure upgrades needed to serve large load customers to other retail customers.
Data Center Development
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In July 2025, we entered into a nonbinding letter of intent with Quantica Infrastructure to evaluate the transmission infrastructure and generation resources needed to support their proposed need. We had previously disclosed in December 2024, two separate nonbinding letters of intent to provide electric supply services for data centers being developed in Montana. The combined energy service requirement associated with these letters of intent is currently expected to be 175 megawatts beginning in late 2027, or earlier, with growth of up to 1,100 megawatts or more by 2030. We have signed a development agreement with Sabey, and are working with each of these parties to execute electric service agreements.
Resources and regulatory mechanisms to be utilized for serving these requests are pending further evaluation and regulatory considerations.
Colstrip Acquisitions and Requests for Cost Recovery
As previously disclosed, we entered into definitive agreements with Avista and Puget to acquire their respective interests in Colstrip Units 3 and 4 for $0 and expect to complete these acquisitions on January 1, 2026. Accordingly, we will be responsible for associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates, until requested in a future Montana rate review. Puget and Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests. At closing, we will reimburse Puget and Avista for the proportionate amount of the long-term capital enhancement work they each funded subsequent to executing the definitive agreements and up until the acquisition close date.
Avista Interests - The 222 megawatts of generation capacity from Colstrip Units 3 and 4 to be acquired from Avista (Avista Interests) was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that would provide a near-term cost-recovery mechanism expected to largely offset approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requests that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interest. Under the PCCAM design, market sales, which include long-term power sales contracts, flow back to retail customers as a reduction to energy supply costs and would be subject to the 90/10 sharing mechanism. Furthermore, the waiver request indicates that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interest would continue to flow back to retail customers through the PCCAM as a reduction to energy supply costs. We expect a decision from the MPSC by the first quarter of 2026.
Puget Interests - The incremental interest in Colstrip Units 3 and 4 to be acquired from Puget (Puget Interests) increases our ownership share of the facility to 55 percent and provides an increase in voting share in determining strategic direction and investment decisions at the facility. While we expect our future opportunity to serve large load customers may be supported by this resource, we expect to sell excess capacity in the near term. We expect to sign a contract in the fourth quarter of 2025 to sell the dispatchable capacity and associated energy from the Puget Interest beginning January 1, 2026, through late 2027. Revenues from this agreement are expected to largely offset the estimated $30.0 million of annual incremental operating and maintenance costs associated with the Puget Interests. In addition, in October 2025, we submitted a request to the FERC for approval of cost-based rates for our subsidiary that will own the Puget Interests. We expect this rate approval to be effective by January 1, 2026.
Generation Capacity in South Dakota
The Southwest Power Pool (SPP) has recently updated its resource accreditation and Planning Reserve Margin (PRM) requirements in response to growing reliability concerns. As a result, SPP is requiring additional accredited capacity by 2030 to meet the updated PRM targets. In October 2025, we submitted a project with the Southwest Power Pool (SPP) under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota, to meet regional capacity needs by 2030. Anticipated costs for this project are approximately $300 million. This project represents incremental capital expenditures not currently reflected in our five year estimated capital expenditure forecast included within Management’s Discussion and Analysis in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024. We expect to update our capital expenditures forecast in the first half of 2026 upon the completion of the transmission interconnection study regarding the necessary transmission upgrades needed for this additional generation capacity.
Acquisition of Energy West Montana Operations
In July 2024, NW Corp entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas distribution and system operations serving approximately 33,000 customers located in Great Falls, Cut Bank, and West Yellowstone, Montana. In May 2025, the MPSC approved this acquisition and on July 1, 2025, NW Corp completed this acquisition for approximately $35.9 million in cash, which is subject to certain post-close working capital adjustments that we
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expect to finalize in the fourth quarter of 2025.
Regional Transmission Development Activities
In December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the North Plains Connector (NPC) Consortium project. The project is entering the permitting phase and we expect initial regulatory filings in 2026. Construction is expected to commence in 2028, with the project expected to be operational by 2032. Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will make our investment decision when the regulatory approvals and permits are in place. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region.
We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana. Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West.
Montana Wildfire Risk Mitigation
The Montana Legislature approved House Bill 490 in April 2025, with broad bipartisan support in both the House (90-0) and Senate (40-8), and the Governor signed this bill into law in May 2025. This bill requires development, approval, and implementation of electric facilities providers' wildfire mitigation plans. Importantly, House Bill 490 helps address some preexisting liability risks facing electric facilities providers in Montana. It changes Montana law, recognizing utilities' obligation to provide a public service for customers that is different from typical businesses; circumscribes certain damages; and enacts liability protections related to wildfire and wildfire prevention efforts involving providers. More specifically, House Bill 490 precludes common law strict liability claims for damages related to wildfire and electric activities or wildfire mitigation activities; establishes a statutory standard of care, supplanting common law causes of action and other theories of recovery; and creates a rebuttable presumption that an electric facilities provider acted reasonably if it substantially followed an approved wildfire mitigation plan. The legislation also defines the availability of damages by allowing noneconomic personal injury damages only when there is bodily injury and punitive damages only when an injured party proves by clear and convincing evidence that an electric facilities provider's actions were grossly negligent or intentional. We filed our wildfire mitigation plan with the MPSC in August 2025 for review and approval.
| RESULTS OF OPERATIONS | ||||||||||||||
Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.
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Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.
OVERALL CONSOLIDATED RESULTS
Three Months Ended September 30, 2025 Compared with the Three Months Ended September 30, 2024
Consolidated net income for the three months ended September 30, 2025 was $38.2 million as compared with $46.8 million for the same period in 2024. This decrease was primarily due to higher operating expenses, including merger-related costs and depreciation, higher interest expense, and a prior year income tax benefit from a gas repairs safe harbor method change. These were offset in part by new rates and customer usage.
Consolidated gross margin for the three months ended September 30, 2025 was $127.1 million as compared with $102.8 million in 2024, an increase of $24.3 million, or 23.6 percent. This increase was primarily due to higher retail rates, natural gas and electric usage, electric transmission revenues, and natural gas transportation revenues. These were partly offset by higher operating and maintenance costs, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.
| Electric | Natural Gas | Total | |||||||||||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Reconciliation of gross margin to utility margin: | |||||||||||||||||||||||||||||||||||
| Operating Revenues | $ | 339.8 | $ | 306.5 | $ | 47.2 | $ | 38.7 | $ | 387.0 | $ | 345.2 | |||||||||||||||||||||||
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 77.2 | 80.8 | 9.7 | 7.1 | 86.9 | 87.9 | |||||||||||||||||||||||||||||
| Less: Operating and maintenance | 48.6 | 42.5 | 15.5 | 13.4 | 64.1 | 55.9 | |||||||||||||||||||||||||||||
| Less: Property and other taxes | 35.4 | 32.3 | 10.7 | 9.3 | 46.1 | 41.6 | |||||||||||||||||||||||||||||
| Less: Depreciation and depletion | 52.3 | 47.6 | 10.5 | 9.4 | 62.8 | 57.0 | |||||||||||||||||||||||||||||
| Gross Margin | 126.3 | 103.3 | 0.8 | (0.5) | 127.1 | 102.8 | |||||||||||||||||||||||||||||
| Operating and maintenance | 48.6 | 42.5 | 15.5 | 13.4 | 64.1 | 55.9 | |||||||||||||||||||||||||||||
| Property and other taxes | 35.4 | 32.3 | 10.7 | 9.3 | 46.1 | 41.6 | |||||||||||||||||||||||||||||
| Depreciation and depletion | 52.3 | 47.6 | 10.5 | 9.4 | 62.8 | 57.0 | |||||||||||||||||||||||||||||
Utility Margin(1) | $ | 262.6 | $ | 225.7 | $ | 37.5 | $ | 31.6 | $ | 300.1 | $ | 257.3 | |||||||||||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Utility Margin | |||||||||||||||||||||||
| Electric | $ | 262.6 | $ | 225.7 | $ | 36.9 | 16.3 | % | |||||||||||||||
| Natural Gas | 37.5 | 31.6 | 5.9 | 18.7 | |||||||||||||||||||
Total Utility Margin(1) | $ | 300.1 | $ | 257.3 | $ | 42.8 | 16.6 | % | |||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the three months ended September 30, 2025 was $300.1 million as compared with $257.3 million for the same period in 2024, an increase of $42.8 million, or 16.6 percent. Primary components of the change in utility margin include the following (in millions):
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Utility Margin 2025 vs. 2024 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim rates (subject to refund) | $ | 27.1 | |||
Electric retail volumes | 5.8 | ||||
Base rates | 2.2 | ||||
Transmission revenue due to market conditions and rates | 2.1 | ||||
Montana natural gas transportation | 1.3 | ||||
| Natural gas retail volumes, including $1.4 million due to acquisition of Energy West Operations | 0.6 | ||||
Non-recoverable Montana electric supply costs | (3.0) | ||||
| Montana property tax tracker collections | (2.8) | ||||
| Other | 0.9 | ||||
| Change in Utility Margin Items Impacting Net Income | 34.2 | ||||
| Utility Margin Items Offset Within Net Income | |||||
Property and other taxes recovered in revenue, offset in property and other taxes | 3.6 | ||||
Production tax credits, offset in income tax expense | 3.0 | ||||
Operating expenses recovered in revenue, offset in operating and maintenance expense | 2.0 | ||||
| Change in Utility Margin Items Offset Within Net Income | 8.6 | ||||
Increase in Consolidated Utility Margin(1) | $ | 42.8 | |||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher residential and commercial demand in Montana, and customer growth in all jurisdictions, partly offset by lower commercial demand in South Dakota and lower industrial demand. Natural gas retail volumes were impacted by favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.
Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the three months ended September 30, 2025, we under-collected supply costs of $21.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $2.3 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance).
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | |||||||||||||||||||||||
| Operating and maintenance | $ | 64.1 | $ | 55.9 | $ | 8.2 | 14.7 | % | |||||||||||||||
| Administrative and general | 46.7 | 34.9 | 11.8 | 33.8 | |||||||||||||||||||
| Property and other taxes | 46.1 | 41.6 | 4.5 | 10.8 | |||||||||||||||||||
| Depreciation and depletion | 62.8 | 57.0 | 5.8 | 10.2 | |||||||||||||||||||
| Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 219.7 | $ | 189.4 | $ | 30.3 | 16.0 | % | |||||||||||||||
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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $219.7 million for the three months ended September 30, 2025, as compared with $189.4 million for the three months ended September 30, 2024. Primary components of the change include the following (in millions):
| Operating Expenses | |||||
2025 vs. 2024 | |||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | |||||
| Merger-related costs, including consulting and legal fees | $ | 7.6 | |||
Depreciation expense due to plant additions and higher depreciation rates | 5.8 | ||||
| Wildfire mitigation expense, partly offset by higher base revenues | 3.8 | ||||
Labor and benefits(1) | 1.6 | ||||
Electric generation maintenance | 1.3 | ||||
Insurance expense, primarily due to increased wildfire risk premiums | 1.0 | ||||
| Property and other taxes not recoverable within trackers | 0.9 | ||||
Technology implementation and maintenance expenses | 0.7 | ||||
Uncollectible accounts | 0.5 | ||||
| Prior period partial recovery from previously impaired alternative energy storage investment | 0.5 | ||||
| Other | 2.1 | ||||
| Change in Items Impacting Net Income | 25.8 | ||||
| Operating Expenses Offset Within Net Income | |||||
Property and other taxes recovered in trackers, offset in revenue | 3.6 | ||||
Operating and maintenance expenses recovered in trackers, offset in revenue | 2.0 | ||||
Pension and other postretirement benefits, offset in other income(1) | (0.6) | ||||
Deferred compensation, offset in other income | (0.5) | ||||
| Change in Items Offset Within Net Income | 4.5 | ||||
| Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 30.3 | |||
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Consolidated operating income for the three months ended September 30, 2025 was $80.3 million as compared with $67.9 million in the same period of 2024. This increase was primarily due to new rates, customer usage, electric transmission revenues, and natural gas transportation revenues. These were partly offset by unfavorable weather in Montana, higher operating, administrative, and general costs, including merger-related costs, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.
Consolidated interest expense was $38.4 million for the three months ended September 30, 2025 as compared with $33.4 million for the same period of 2024. This increase was due to higher borrowings and interest rates and lower capitalization of Allowance for Funds Used During Construction (AFUDC).
Consolidated other income was $5.1 million for the three months ended September 30, 2025 as compared with $9.1 million for the same period of 2024. This decrease was primarily due to lower capitalization of AFUDC and higher non-service component pension expense.
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Consolidated income tax expense was $8.8 million for the three months ended September 30, 2025 as compared to an income tax benefit of $3.2 million for the same period of 2024. Our 2024 results included an income tax benefit related to a natural gas repairs safe harbor method change. Our effective tax rate for the three months ended September 30, 2025 was 18.7% as compared with (7.3)% for the same period in 2024.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| Income Before Income Taxes | $ | 47.0 | $ | 43.7 | |||||||||||||||||||
| Income tax calculated at federal statutory rate | 9.9 | 21.0 | % | 9.2 | 21.0 | % | |||||||||||||||||
| Permanent or flow-through adjustments: | |||||||||||||||||||||||
| State income tax, net of federal provisions | 0.1 | 0.2 | 0.1 | 0.1 | |||||||||||||||||||
| Flow-through repairs deductions | (5.2) | (11.1) | (4.6) | (10.5) | |||||||||||||||||||
| Production tax credits | (1.3) | (2.8) | (2.4) | (5.6) | |||||||||||||||||||
| Amortization of excess deferred income tax | (0.4) | (0.8) | (0.2) | (0.5) | |||||||||||||||||||
| Gas repairs safe harbor method change | — | — | (7.0) | (16.0) | |||||||||||||||||||
| Plant and depreciation flow-through items | 3.3 | 7.0 | 1.8 | 4.2 | |||||||||||||||||||
| Merger transaction costs | 1.9 | 4.1 | — | — | |||||||||||||||||||
| Other, net | 0.5 | 1.1 | (0.1) | 0.0 | |||||||||||||||||||
| (1.1) | (2.3) | (12.4) | (28.3) | ||||||||||||||||||||
Income tax expense (benefit) | $ | 8.8 | 18.7 | % | $ | (3.2) | (7.3) | % | |||||||||||||||
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
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Nine Months Ended September 30, 2025 Compared with the Nine Months Ended September 30, 2024
Consolidated net income for the nine months ended September 30, 2025 was $136.4 million as compared with $143.6 million for the same period in 2024. This decrease was primarily due to higher operating expenses, including merger-related costs and depreciation, higher Montana property tax tracker collections, interest expense, and a prior year income tax benefit from a gas repairs safe harbor method change. These were offset in part by new rates, customer usage, and higher electric transmission revenues.
Consolidated gross margin for the nine months ended September 30, 2025 was $387.8 million as compared with $338.3 million in 2024, an increase of $49.5 million, or 14.6 percent. This increase was primarily due to higher retail rates, natural gas and electric usage, electric transmission revenues, and natural gas transportation revenues. These were partly offset by higher operating and maintenance expense, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.
| Electric | Natural Gas | Total | |||||||||||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Reconciliation of gross margin to utility margin: | |||||||||||||||||||||||||||||||||||
| Operating Revenues | $ | 954.7 | $ | 909.8 | $ | 241.6 | $ | 230.6 | $ | 1,196.3 | $ | 1,140.4 | |||||||||||||||||||||||
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 229.5 | 257.0 | 70.9 | 82.1 | 300.4 | 339.1 | |||||||||||||||||||||||||||||
| Less: Operating and maintenance | 139.8 | 126.3 | 43.4 | 41.1 | 183.2 | 167.4 | |||||||||||||||||||||||||||||
| Less: Property and other taxes | 106.0 | 96.6 | 31.3 | 28.4 | 137.3 | 125.0 | |||||||||||||||||||||||||||||
| Less: Depreciation and depletion | 157.2 | 142.4 | 30.4 | 28.2 | 187.6 | 170.6 | |||||||||||||||||||||||||||||
| Gross Margin | 322.2 | 287.5 | 65.6 | 50.8 | 387.8 | 338.3 | |||||||||||||||||||||||||||||
| Operating and maintenance | 139.8 | 126.3 | 43.4 | 41.1 | 183.2 | 167.4 | |||||||||||||||||||||||||||||
| Property and other taxes | 106.0 | 96.6 | 31.3 | 28.4 | 137.3 | 125.0 | |||||||||||||||||||||||||||||
| Depreciation and depletion | 157.2 | 142.4 | 30.4 | 28.2 | 187.6 | 170.6 | |||||||||||||||||||||||||||||
Utility Margin(1) | $ | 725.2 | $ | 652.8 | $ | 170.7 | $ | 148.5 | $ | 895.9 | $ | 801.3 | |||||||||||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Utility Margin | |||||||||||||||||||||||
| Electric | $ | 725.2 | $ | 652.8 | $ | 72.4 | 11.1 | % | |||||||||||||||
| Natural Gas | 170.7 | 148.5 | 22.2 | 14.9 | |||||||||||||||||||
Total Utility Margin(1) | $ | 895.9 | $ | 801.3 | $ | 94.6 | 11.8 | % | |||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the nine months ended September 30, 2025 was $895.9 million as compared with $801.3 million for the same period in 2024, an increase of $94.6 million, or 11.8 percent. Primary components of the change in utility margin include the following (in millions):
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Utility Margin 2025 vs. 2024 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim rates (subject to refund) | $ | 57.2 | |||
Transmission revenue due to market conditions and rates | 12.0 | ||||
Electric retail volumes | 9.9 | ||||
Base rates | 8.0 | ||||
Montana natural gas transportation | 4.2 | ||||
| Natural gas retail volumes, including $1.4 million due to acquisition of Energy West Operations | 0.9 | ||||
| Montana property tax tracker collections | (9.6) | ||||
Non-recoverable Montana electric supply costs | (4.7) | ||||
| Other | 0.3 | ||||
| Change in Utility Margin Items Impacting Net Income | 78.2 | ||||
| Utility Margin Items Offset Within Net Income | |||||
Property and other taxes recovered in revenue, offset in property and other taxes | 10.2 | ||||
Production tax credits, offset in income tax expense | 5.0 | ||||
Operating expenses recovered in revenue, offset in operating and maintenance expense | 1.2 | ||||
| Change in Utility Margin Items Offset Within Net Income | 16.4 | ||||
Increase in Consolidated Utility Margin(1) | $ | 94.6 | |||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher commercial demand in Montana, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana impacting residential demand, lower commercial demand in South Dakota, and lower industrial demand. Natural gas retail volumes were driven by favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.
For the nine months ended September 30, 2025, we under-collected supply costs of $52.7 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $5.9 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance).
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | |||||||||||||||||||||||
| Operating and maintenance | $ | 183.2 | $ | 167.4 | $ | 15.8 | 9.4 | % | |||||||||||||||
| Administrative and general | 121.8 | 106.7 | 15.1 | 14.2 | |||||||||||||||||||
| Property and other taxes | 137.5 | 125.0 | 12.5 | 10.0 | |||||||||||||||||||
| Depreciation and depletion | 187.6 | 170.6 | 17.0 | 10.0 | |||||||||||||||||||
| Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 630.1 | $ | 569.7 | $ | 60.4 | 10.6 | % | |||||||||||||||
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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $630.1 million for the nine months ended September 30, 2025, as compared with $569.7 million for the nine months ended September 30, 2024. Primary components of the change include the following (in millions):
| Operating Expenses | |||||
2025 vs. 2024 | |||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | |||||
Depreciation expense due to plant additions and higher depreciation rates | $ | 17.0 | |||
Electric generation maintenance | 8.5 | ||||
| Merger-related costs, including consulting and legal fees | 7.6 | ||||
Insurance expense, primarily due to increased wildfire risk premiums | 7.3 | ||||
| Wildfire mitigation expense, partly offset by higher base revenues | 5.3 | ||||
Labor and benefits(1) | 4.0 | ||||
Property and other taxes not recoverable within trackers | 2.3 | ||||
Technology implementation and maintenance expenses | 2.1 | ||||
Uncollectible accounts | 0.8 | ||||
| Litigation outcome (Pacific Northwest Solar) | (2.4) | ||||
| Non-cash impairment of alternative energy storage investment | (1.7) | ||||
| Other | (0.7) | ||||
| Change in Items Impacting Net Income | 50.1 | ||||
| Operating Expenses Offset Within Net Income | |||||
Property and other taxes recovered in trackers, offset in revenue | 10.2 | ||||
Operating and maintenance expenses recovered in trackers, offset in revenue | 1.2 | ||||
Pension and other postretirement benefits, offset in other income(1) | (0.6) | ||||
Deferred compensation, offset in other income | (0.5) | ||||
| Change in Items Offset Within Net Income | 10.3 | ||||
| Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 60.4 | |||
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
Consolidated operating income for the nine months ended September 30, 2025 was $265.8 million as compared with $231.6 million in the same period of 2024. This increase was primarily due to new rates, customer usage, electric transmission revenues, and natural gas transportation revenues. These were partly offset by higher operating, administrative, and general costs, including merger-related costs, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.
Consolidated interest expense was $111.1 million for the nine months ended September 30, 2025 as compared with $96.3 million for the same period of 2024. This increase was due to higher borrowings and interest rates and lower capitalization of AFUDC.
Consolidated other income was $9.1 million for the nine months ended September 30, 2025 as compared to $19.6 million during the same period of 2024. This decrease was primarily due to lower capitalization of AFUDC, a prior year reversal of $2.3 million from a previously disclosed CREP penalty due to a favorable legal ruling, and a $1.0 million expense accrual related to an estimated penalty for the CREP informed by a recent MPSC ruling, partly offset by an increase of $2.5 million driven by a prior year non-cash impairment of an alternative energy storage equity investment.
Consolidated income tax expense for the nine months ended September 30, 2025 was $27.4 million as compared to $11.4 million in the same period of 2024. Our 2024 results included an income tax benefit related to a natural gas repairs safe harbor method change. Our effective tax rate for the nine months ended September 30, 2025 was 16.7% as compared with 7.4% for the same period in 2024.
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The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| Income Before Income Taxes | $ | 163.8 | $ | 155.0 | |||||||||||||||||||
| Income tax calculated at federal statutory rate | 34.4 | 21.0 | % | 32.5 | 21.0 | % | |||||||||||||||||
| Permanent or flow-through adjustments: | |||||||||||||||||||||||
| State income tax, net of federal provisions | 1.0 | 0.6 | 0.7 | 0.5 | |||||||||||||||||||
| Flow-through repairs deductions | (16.1) | (9.8) | (13.8) | (8.9) | |||||||||||||||||||
| Production tax credits | (4.0) | (2.4) | (7.4) | (4.8) | |||||||||||||||||||
| Amortization of excess deferred income tax | (1.2) | (0.7) | (0.8) | (0.5) | |||||||||||||||||||
| Share-based compensation | (0.3) | (0.2) | 0.3 | 0.2 | |||||||||||||||||||
| Gas repairs safe harbor method change | — | — | (7.0) | (4.5) | |||||||||||||||||||
| Plant and depreciation flow-through items | 10.0 | 6.1 | 6.0 | 3.8 | |||||||||||||||||||
| Merger transaction costs | 1.9 | 1.2 | — | — | |||||||||||||||||||
| Other, net | 1.7 | 0.9 | 0.9 | 0.6 | |||||||||||||||||||
| (7.0) | (4.3) | (21.1) | (13.6) | ||||||||||||||||||||
| Income tax expense | $ | 27.4 | 16.7 | % | $ | 11.4 | 7.4 | % | |||||||||||||||
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
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ELECTRIC SEGMENT
We have various classifications of electric revenues, defined as follows:
•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory
mechanisms.
•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.
Three Months Ended September 30, 2025 Compared with the Three Months Ended September 30, 2024
| Revenues | Change | Megawatt Hours (MWH) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2025 | 2024 | $ | % | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 110,788 | $ | 100,737 | $ | 10,051 | 10.0 | % | 686 | 685 | 334,448 | 328,962 | |||||||||||||||||||||||||||||||||||
| South Dakota | 21,358 | 19,062 | 2,296 | 12.0 | 151 | 145 | 51,768 | 51,393 | |||||||||||||||||||||||||||||||||||||||
| Residential | 132,146 | 119,799 | 12,347 | 10.3 | 837 | 830 | 386,216 | 380,355 | |||||||||||||||||||||||||||||||||||||||
| Montana | 116,911 | 109,655 | 7,256 | 6.6 | 838 | 830 | 77,154 | 75,857 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 32,490 | 30,053 | 2,437 | 8.1 | 277 | 288 | 13,223 | 13,115 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 149,401 | 139,708 | 9,693 | 6.9 | 1,115 | 1,118 | 90,377 | 88,972 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 12,070 | 11,852 | 218 | 1.8 | 695 | 726 | 81 | 80 | |||||||||||||||||||||||||||||||||||||||
Other(1) | 14,393 | 14,071 | 322 | 2.3 | 79 | 82 | 30,219 | 30,319 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Electric | $ | 308,010 | $ | 285,430 | $ | 22,580 | 7.9 | % | 2,726 | 2,756 | 506,893 | 499,726 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | 980 | (6,805) | 7,785 | 114.4 | |||||||||||||||||||||||||||||||||||||||||||
| Transmission | 27,923 | 25,750 | 2,173 | 8.4 | |||||||||||||||||||||||||||||||||||||||||||
| Wholesale and Other | 2,838 | 2,103 | 735 | 35.0 | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 339,751 | $ | 306,478 | $ | 33,273 | 10.9 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(2) | 77,179 | 80,761 | (3,582) | (4.4) | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(3) | $ | 262,572 | $ | 225,717 | $ | 36,855 | 16.3 | % | |||||||||||||||||||||||||||||||||||||||
(1) Included within this line is our lighting customer class, which we have historically counted each lighting district as one customer. We have retroactively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class.
(2) Exclusive of depreciation and depletion.
(3) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Cooling Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
| Montana | 337 | 441 | 393 | 24% cooler | 14% cooler | ||||||||||||||||||||||||
| South Dakota | 730 | 628 | 634 | 16% warmer | 15% warmer | ||||||||||||||||||||||||
| Heating Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 143 | 169 | 266 | 15% warmer | 46% warmer | ||||||||||||||||||||||||
| South Dakota | 67 | 39 | 77 | 72% colder | 13% warmer | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
38
The following summarizes the components of the changes in electric utility margin for the three months ended September 30, 2025 and 2024 (in millions):
Utility Margin 2025 vs. 2024 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim Rates (subject to refund) | $ | 25.2 | |||
Retail volumes | 5.8 | ||||
| Transmission revenue due to market conditions and rates | 2.1 | ||||
Base rates | 1.2 | ||||
| Non-recoverable Montana electric supply costs | (3.0) | ||||
| Montana property tax tracker collections | (2.3) | ||||
| Other | 0.4 | ||||
| Change in Utility Margin Items Impacting Net Income | 29.4 | ||||
| Utility Margin Items Offset Within Net Income | |||||
Production tax credits, offset in income tax expense | 3.0 | ||||
Property and other taxes recovered in revenue, offset in property and other taxes | 2.5 | ||||
Operating expenses recovered in revenue, offset in operating and maintenance expense | 2.0 | ||||
| Change in Utility Margin Items Offset Within Net Income | 7.5 | ||||
Increase in Utility Margin(1) | $ | 36.9 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher residential and commercial demand in Montana, and customer growth in all jurisdictions, partly offset by lower commercial demand in South Dakota and lower industrial demand.
For the three months ended September 30, 2025, we under-collected supply costs of $21.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $2.3 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance).
The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and property taxes and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
39
Nine Months Ended September 30, 2025 Compared with the Nine Months Ended September 30, 2024
| Revenues | Change | Megawatt Hours (MWH) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2025 | 2024 | $ | % | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 307,589 | $ | 304,128 | $ | 3,461 | 1.1 | % | 2,159 | 2,114 | 333,363 | 327,644 | |||||||||||||||||||||||||||||||||||
| South Dakota | 59,885 | 53,764 | 6,121 | 11.4 | 459 | 435 | 51,740 | 51,395 | |||||||||||||||||||||||||||||||||||||||
| Residential | 367,474 | 357,892 | 9,582 | 2.7 | 2,618 | 2,549 | 385,103 | 379,039 | |||||||||||||||||||||||||||||||||||||||
| Montana | 307,773 | 310,813 | (3,040) | (1.0) | 2,438 | 2,410 | 77,248 | 75,712 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 89,542 | 84,182 | 5,360 | 6.4 | 807 | 834 | 13,178 | 13,070 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 397,315 | 394,995 | 2,320 | 0.6 | 3,245 | 3,244 | 90,426 | 88,782 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 32,058 | 34,803 | (2,745) | (7.9) | 2,083 | 2,190 | 80 | 80 | |||||||||||||||||||||||||||||||||||||||
Other(1) | 28,507 | 27,437 | 1,070 | 3.9 | 133 | 131 | 28,671 | 28,636 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Electric | $ | 825,354 | $ | 815,127 | $ | 10,227 | 1.3 | % | 8,079 | 8,114 | 504,280 | 496,537 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | 38,995 | 18,637 | 20,358 | 109.2 | |||||||||||||||||||||||||||||||||||||||||||
| Transmission | 82,625 | 70,573 | 12,052 | 17.1 | |||||||||||||||||||||||||||||||||||||||||||
| Wholesale and Other | 7,728 | 5,461 | 2,267 | 41.5 | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 954,702 | $ | 909,798 | $ | 44,904 | 4.9 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(2) | 229,534 | 256,989 | (27,455) | (10.7) | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(3) | $ | 725,168 | $ | 652,809 | $ | 72,359 | 11.1 | % | |||||||||||||||||||||||||||||||||||||||
(1) Included within this line is our lighting customer class, which we have historically counted each lighting district as one customer. We have retroactively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class.
(2) Exclusive of depreciation and depletion.
(3) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Cooling Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
Montana | 392 | 484 | 459 | 19% cooler | 15% cooler | ||||||||||||||||||||||||
| South Dakota | 829 | 682 | 707 | 22% warmer | 17% warmer | ||||||||||||||||||||||||
| Heating Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 4,696 | 4,661 | 4,720 | 1% colder | 1% warmer | ||||||||||||||||||||||||
| South Dakota | 5,297 | 4,847 | 5,692 | 9% colder | 7% warmer | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
40
The following summarizes the components of the changes in electric utility margin for the nine months ended September 30, 2025 and 2024 (in millions):
Utility Margin 2025 vs. 2024 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim rates (subject to refund) | $ | 45.1 | |||
| Transmission revenue due to market conditions and rates | 12.0 | ||||
Retail volumes | 9.9 | ||||
Base rates | 2.9 | ||||
| Montana property tax tracker collections | (6.9) | ||||
Non-recoverable Montana electric supply costs | (4.7) | ||||
| Other | 0.2 | ||||
| Change in Utility Margin Items Impacting Net Income | 58.5 | ||||
| Utility Margin Items Offset Within Net Income | |||||
Property and other taxes recovered in revenue, offset in property and other taxes | 7.8 | ||||
Production tax credits, offset in income tax expense | 5.0 | ||||
Operating expenses recovered in revenue, offset in operating and maintenance expense | 1.1 | ||||
| Change in Utility Margin Items Offset Within Net Income | 13.9 | ||||
Increase in Utility Margin(1) | $ | 72.4 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher commercial demand in Montana, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana impacting residential demand, lower commercial demand in South Dakota, and lower industrial demand.
For the nine months ended September 30, 2025, we under-collected supply costs of $52.7 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $5.9 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance).
The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
41
NATURAL GAS SEGMENT
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Three Months Ended September 30, 2025 Compared with the Three Months Ended September 30, 2024
| Revenues | Change | Dekatherms (Dkt) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2025 | 2024 | $ | % | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 10,891 | $ | 8,422 | $ | 2,469 | 29.3 | % | 890 | 739 | 215,448 | 185,578 | |||||||||||||||||||||||||||||||||||
| South Dakota | 2,036 | 1,745 | 291 | 16.7 | 109 | 108 | 42,719 | 42,389 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 2,344 | 1,791 | 553 | 30.9 | 142 | 143 | 37,778 | 37,834 | |||||||||||||||||||||||||||||||||||||||
| Residential | 15,271 | 11,958 | 3,313 | 27.7 | 1,141 | 990 | 295,945 | 265,801 | |||||||||||||||||||||||||||||||||||||||
| Montana | 8,734 | 6,190 | 2,544 | 41.1 | 964 | 609 | 30,053 | 26,094 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 1,577 | 1,262 | 315 | 25.0 | 245 | 225 | 7,562 | 7,336 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 1,145 | 795 | 350 | 44.0 | 134 | 134 | 5,071 | 5,009 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 11,456 | 8,247 | 3,209 | 38.9 | 1,343 | 968 | 42,686 | 38,439 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 680 | 115 | 565 | 491.3 | 928 | 15 | 243 | 238 | |||||||||||||||||||||||||||||||||||||||
| Other | 142 | 169 | (27) | (16.0) | 16 | 23 | 225 | 196 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Gas | $ | 27,549 | $ | 20,489 | $ | 7,060 | 34.5 | % | 3,428 | 1,996 | 339,099 | 304,674 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | 5,240 | 8,025 | (2,785) | (34.7) | |||||||||||||||||||||||||||||||||||||||||||
Transportation, wholesale and other | 14,412 | 10,169 | 4,243 | 41.7 | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 47,201 | $ | 38,683 | $ | 8,518 | 22.0 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(1) | 9,754 | 7,127 | 2,627 | 36.9 | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(2) | $ | 37,447 | $ | 31,556 | $ | 5,891 | 18.7 | % | |||||||||||||||||||||||||||||||||||||||
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Heating Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 174 | 203 | 307 | 14% warmer | 43% warmer | ||||||||||||||||||||||||
| South Dakota | 67 | 39 | 77 | 72% colder | 13% warmer | ||||||||||||||||||||||||
| Nebraska | 30 | 7 | 34 | 329% colder | 12% warmer | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
42
The following summarizes the components of the changes in natural gas utility margin for the three months ended September 30, 2025 and 2024:
Utility Margin 2025 vs. 2024 | |||||
| (in millions) | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim rates (subject to refund) | $ | 1.9 | |||
Montana natural gas transportation | 1.3 | ||||
Base rates | 1.0 | ||||
| Retail volumes ($1.4 million due to acquisition of Energy West - See footnote 3) | 0.6 | ||||
| Montana property tax tracker collections | (0.5) | ||||
| Other | 0.5 | ||||
| Change in Utility Margin Items Impacting Net Income | 4.8 | ||||
| Utility Margin Items Offset Within Net Income | |||||
Property and other taxes recovered in revenue, offset in property and other taxes | 1.1 | ||||
| Change in Utility Margin Items Offset Within Net Income | 1.1 | ||||
Increase in Utility Margin(1) | $ | 5.9 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Natural gas retail volumes were impacted by favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.
43
Nine Months Ended September 30, 2025 Compared with the Nine Months Ended September 30, 2024
| Revenues | Change | Dekatherms (Dkt) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2025 | 2024 | $ | % | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 80,277 | $ | 75,933 | $ | 4,344 | 5.7 | % | 9,355 | 9,220 | 196,526 | 185,412 | |||||||||||||||||||||||||||||||||||
| South Dakota | 23,172 | 21,244 | 1,928 | 9.1 | 2,420 | 2,113 | 42,867 | 42,477 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 20,076 | 16,106 | 3,970 | 24.6 | 1,915 | 1,812 | 37,941 | 37,924 | |||||||||||||||||||||||||||||||||||||||
| Residential | 123,525 | 113,283 | 10,242 | 9.0 | 13,690 | 13,145 | 277,334 | 265,813 | |||||||||||||||||||||||||||||||||||||||
| Montana | 45,991 | 42,016 | 3,975 | 9.5 | 5,777 | 5,307 | 27,743 | 26,112 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 16,672 | 14,283 | 2,389 | 16.7 | 2,448 | 2,139 | 7,551 | 7,353 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 10,932 | 8,982 | 1,950 | 21.7 | 1,390 | 1,328 | 5,105 | 5,045 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 73,595 | 65,281 | 8,314 | 12.7 | 9,615 | 8,774 | 40,399 | 38,510 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 1,308 | 703 | 605 | 86.1 | 1,014 | 98 | 240 | 237 | |||||||||||||||||||||||||||||||||||||||
| Other | 1,003 | 1,036 | (33) | (3.2) | 148 | 156 | 213 | 196 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Gas | $ | 199,431 | $ | 180,303 | $ | 19,128 | 10.6 | % | 24,467 | 22,173 | 318,186 | 304,756 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | 993 | 18,686 | (17,693) | (94.7) | |||||||||||||||||||||||||||||||||||||||||||
Transportation, wholesale and other | 41,169 | 31,645 | 9,524 | 30.1 | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 241,593 | $ | 230,634 | $ | 10,959 | 4.8 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(1) | 70,867 | 82,100 | (11,233) | (13.7) | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(2) | $ | 170,726 | $ | 148,534 | $ | 22,192 | 14.9 | % | |||||||||||||||||||||||||||||||||||||||
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Heating Degree Days | 2025 as compared with: | ||||||||||||||||||||||||||||
| 2025 | 2024 | Historic Average | 2024 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 4,764 | 4,792 | 4,844 | 1% warmer | 2% warmer | ||||||||||||||||||||||||
| South Dakota | 5,297 | 4,847 | 5,692 | 9% colder | 7% warmer | ||||||||||||||||||||||||
| Nebraska | 4,398 | 3,985 | 4,470 | 10% colder | 2% warmer | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
44
The following summarizes the components of the changes in natural gas utility margin for the nine months ended September 30, 2025 and 2024:
Utility Margin 2025 vs. 2024 | |||||
| (in millions) | |||||
| Utility Margin Items Impacting Net Income | |||||
| Interim rates (subject to refund) | $ | 12.1 | |||
Base rates | 5.1 | ||||
Montana natural gas transportation | 4.2 | ||||
| Retail volumes ($1.4 million due to acquisition of Energy West - See footnote 3) | 0.9 | ||||
| Montana property tax tracker collections | (2.7) | ||||
| Other | 0.1 | ||||
| Change in Utility Margin Items Impacting Net Income | 19.7 | ||||
| Utility Margin Items Offset Within Net Income | |||||
| Property and other taxes recovered in revenue, offset in property tax expense | 2.4 | ||||
Operating expenses recovered in revenue, offset in operating and maintenance expense | 0.1 | ||||
| Change in Utility Margin Items Offset Within Net Income | 2.5 | ||||
Increase in Utility Margin(1) | $ | 22.2 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Natural gas retail volumes were driven by favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.
45
| LIQUIDITY AND CAPITAL RESOURCES | ||||||||||||||
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 16 - Common Stock in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024 for further information regarding these dividend restrictions. As of September 30, 2025, we are in compliance with these provisions.
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.
As of September 30, 2025, our total net liquidity was approximately $262.2 million, including $6.2 million of cash and cash equivalents and $256.0 million of revolving credit facility availability with no letters of credit outstanding.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Operating Activities | |||||||||||
| Net income | $ | 136.4 | $ | 143.6 | |||||||
| Adjustments to reconcile net income to cash provided by operations | 213.6 | 175.3 | |||||||||
| Changes in working capital | (1.5) | 35.9 | |||||||||
| Other noncurrent assets and liabilities | (10.2) | (10.9) | |||||||||
| Cash Provided by Operating Activities | 338.3 | 343.9 | |||||||||
| Investing Activities | |||||||||||
| Property, plant and equipment additions | (374.5) | (400.5) | |||||||||
| Acquisition of Energy West Operations | (35.9) | — | |||||||||
| Investment in debt & equity securities | (8.1) | (4.6) | |||||||||
| Cash Used in Investing Activities | (418.5) | (405.1) | |||||||||
| Financing Activities | |||||||||||
| Issuance of long-term debt | 500.0 | 215.0 | |||||||||
| Issuance of short-term borrowings | 50.0 | 100.0 | |||||||||
| Repayments on long-term debt | (300.0) | (100.0) | |||||||||
| Dividends on common stock | (121.0) | (118.9) | |||||||||
| Line of credit repayments, net | (44.0) | (32.0) | |||||||||
| Other financing activities, net | (3.3) | (0.2) | |||||||||
| Cash Provided by Financing Activities | 81.7 | 63.9 | |||||||||
| Increase in Cash, Cash Equivalents, and Restricted Cash | 1.5 | 2.7 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, beginning of period | 29.0 | 25.2 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, end of period | $ | 30.5 | $ | 27.9 | |||||||
Operating Activities
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As of September 30, 2025, cash, cash equivalents, and restricted cash were $30.5 million as compared with $29.0 million as of December 31, 2024 and $27.9 million as of September 30, 2024. Cash provided by operating activities totaled $338.3 million for the nine months ended September 30, 2025 as compared with $343.9 million during the nine months ended September 30, 2024. The changes in cash flows from operating activities generally follow the results of operations, as discussed above in the consolidated results of operations for the nine months ended September, 2025, and are affected by changes in working capital. The decrease in cash provided by operating activities is primarily due to merger transaction costs, lower collections of accounts receivable balances due to timing of colder weather, and an increase in our net cash outflows for energy supply costs, as shown in the table below, partly offset by the proceeds from production tax credits transferred.
| Uncollected energy supply costs (in millions) | |||||||||||||||||
| Beginning of period | End of period | Net cash inflows (outflows) | |||||||||||||||
| 2024 | $ | 7.8 | $ | 1.8 | $ | 6.0 | |||||||||||
| 2025 | $ | 5.9 | $ | 26.6 | $ | (20.7) | |||||||||||
Increase in net cash outflows | $ | (26.7) | |||||||||||||||
Investing Activities
Cash used in investing activities totaled $418.5 million during the nine months ended September 30, 2025, as compared with $405.1 million during the nine months ended September 30, 2024. Plant additions during the first nine months of 2025 include maintenance additions of approximately $261.3 million and capacity related capital expenditures of $113.2 million. Plant additions during the first nine months of 2024 included maintenance additions of approximately $216.5 million and capacity related capital expenditures of approximately $184.0 million. During the nine months ended September 30, 2025, we completed the acquisition of the Energy West Operations for $35.9 million. See Note 3 - Acquisition of Energy West Operations to the Condensed Consolidated Financial Statements included herein for additional information regarding this acquisition.
Financing Activities
Cash provided by financing activities totaled $81.7 million during the nine months ended September 30, 2025, as compared with $63.9 million during the nine months ended September 30, 2024. During the nine months ended September 30, 2025, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $500.0 million and short-term borrowings of $50.0 million, partly offset by repayment of $300.0 million of Montana and South Dakota First Mortgage bonds, net repayments under our revolving lines of credit of $44.0 million, and payment of dividends of $121.0 million. During the nine months ended September 30, 2024, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $215.0 million and short-term borrowings of $100.0 million, partly offset by payment of dividends of $118.9 million, repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds, and net repayments under our revolving lines of credit of $32.0 million.
Cash Requirements and Capital Resources
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.
Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of September 30, 2025, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our
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current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Short-term Borrowings
For information on our recent short-term borrowings activity, see Note 7 - Financing Activities to the Condensed Consolidated Financial Statements included herein. For further information on our short-term borrowings, see Note 10 - Short-Term Borrowings and Credit Arrangements in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024.
Credit Facilities
Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.
For further information on our credit facilities, see Note 10 - Short-Term Borrowings and Credit Arrangements in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024.
As of September 30, 2025 and 2024, the outstanding balances of our credit facilities were $369.0 million and $286.0 million, respectively. As of October 24, 2025, the availability under our credit facilities was approximately $278.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities.
For further information on our recent long-term debt activity, see Note 7 - Financing Activities to the Condensed Consolidated Financial Statements included herein.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of October 24, 2025, our current ratings with these agencies are as follows:
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| Issuer Rating | Senior Secured Rating | Senior Unsecured Rating | Outlook | ||||||||||||||||||||
| NorthWestern Energy Group | |||||||||||||||||||||||
Fitch(1) | BBB | - | BBB | Stable | |||||||||||||||||||
| Moody’s | - | - | - | - | |||||||||||||||||||
| S&P | BBB | - | - | Positive | |||||||||||||||||||
| NW Corp | |||||||||||||||||||||||
Fitch(1) | BBB | A- | BBB+ | Stable | |||||||||||||||||||
| Moody’s | Baa2 | A3 | Baa2 | Stable | |||||||||||||||||||
S&P | BBB | A- | - | Positive | |||||||||||||||||||
| NWE Public Service | |||||||||||||||||||||||
Fitch(1) | BBB | A- | BBB+ | Stable | |||||||||||||||||||
| Moody’s | Baa2 | A3 | - | Stable | |||||||||||||||||||
| S&P | BBB | A- | - | Stable | |||||||||||||||||||
(1) This Fitch Issuer Rating represents the Issuer Default Rating.
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 2025.
| Total | 2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | |||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||
Long-term debt(1) | $ | 3,163,660 | $ | — | $ | 105,000 | $ | — | $ | 548,660 | $ | 33,000 | $ | 2,477,000 | |||||||||||||||||||||||||||
| Finance leases | 2,798 | 2,798 | 0 | — | — | — | — | ||||||||||||||||||||||||||||||||||
Term Loan Credit Agreement | 150,000 | — | 150,000 | — | — | — | — | ||||||||||||||||||||||||||||||||||
Estimated pension and other postretirement obligations(2) | 41,600 | 2,600 | 9,750 | 9,750 | 9,750 | 9,750 | N/A | ||||||||||||||||||||||||||||||||||
Qualifying facilities liability(3) | 183,682 | 15,090 | 55,393 | 56,665 | 42,400 | 14,134 | — | ||||||||||||||||||||||||||||||||||
Supply and capacity contracts(4) | 4,251,525 | 100,066 | 446,538 | 358,434 | 362,660 | 357,029 | 2,626,798 | ||||||||||||||||||||||||||||||||||
Contractual interest payments on debt(5) | 1,569,900 | 36,625 | 144,008 | 137,913 | 141,216 | 109,651 | 1,000,487 | ||||||||||||||||||||||||||||||||||
Commitments for significant capital projects(6) | 117,677 | 59,524 | 57,876 | 277 | — | — | — | ||||||||||||||||||||||||||||||||||
Total Commitments(7) | $ | 9,480,842 | $ | 216,703 | $ | 968,565 | $ | 563,039 | $ | 1,104,686 | $ | 523,564 | $ | 6,104,285 | |||||||||||||||||||||||||||
_________________________
(1)Represents cash payments for long-term debt and excludes $14.5 million of debt discounts and debt issuance costs, net.
(2)We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.
(3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from $124 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $183.7 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $166.1 million.
(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC.
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(5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 5.51 percent on the outstanding balance through maturity of the facilities.
(6)Represents significant firm purchase commitments for construction of planned capital projects.
(7)The table above excludes potential tax payments related to uncertain tax benefits as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation and asset retirement obligations as the amount and timing of cash payments may be uncertain.
| CRITICAL ACCOUNTING POLICIES AND ESTIMATES | ||||||||||||||
Our discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.
We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024. As of September 30, 2025, there have been no material changes in these policies.
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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and counterparty credit exposure. We have established comprehensive risk management policies and procedures to manage these market risks. There have been no material changes in our market risks as disclosed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2024.
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ITEM 4.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS
See Note 12 - Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.
ITEM 1A. RISK FACTORS
Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2024 for disclosure of the risk factors that could have a significant impact on our business, financial condition, results of operations or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. Other than noted below, these risk factors have not changed materially since such disclosure.
| Risks Related to the Merger | ||||||||||||||
Because the exchange ratio is fixed and because the market prices of NorthWestern Common Stock and Black Hills Common Stock will fluctuate, NorthWestern shareholders cannot be certain of the market value of the Merger consideration they will receive in the Merger or the difference between the market value of the Merger consideration they will receive in the Merger and the market value of NorthWestern Common Stock immediately prior to the Merger.
The exchange ratio in the Merger is fixed and will not be adjusted in the event of any change in the stock prices of NorthWestern or Black Hills prior to the Merger. There may be a significant amount of time between the dates when the shareholders of NorthWestern or Black Hills vote on the Merger Agreement at the special meeting of each company and the date when the Merger is completed. The absolute and relative prices of shares of NorthWestern Common Stock and Black Hills Common Stock may vary significantly between the date the Merger Agreement, the date hereof, the date of the meetings and the date of the completion of the Merger. These variations may be caused by, among other things, changes in the businesses, operations, results or prospects of NorthWestern or Black Hills, market expectations of the likelihood that the Merger will be completed and the timing of completion, the prospects of post-merger operations, general market and economic conditions and other factors. In addition, it is impossible to predict accurately the market price of the Black Hills Common Stock to be received by NorthWestern shareholders after the completion of the Merger. Accordingly, the prices of NorthWestern Common Stock and Black Hills Common Stock on the date hereof and on the date of the meetings may not be indicative of their prices immediately prior to completion of the Merger and the price of the combined company common stock after the Merger is completed.
The ability of NorthWestern and Black Hills to complete the Merger is subject to various closing conditions, including the receipt of approval of NorthWestern and Black Hills stockholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect NorthWestern or Black Hills or cause the Merger to be abandoned. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of NorthWestern common stock or other securities and the future business and financial results of NorthWestern.
To complete the Merger, NorthWestern and Black Hills stockholders must vote to approve a number of proposals related to the Merger and the Merger Agreement. Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) the effectiveness of a registration statement on Form S-4 to be filed in connection with the Merger; (2) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (the HSR Act), and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (3) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (4) the authorization for listing of shares of Black Hills Common Stock to be issued in connection with the Merger on the New York Stock Exchange (NYSE) or other mutually-agreed stock exchange; (5) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (6) compliance by each party in all material respects with its covenants under the Merger Agreement; (7) the absence of a material adverse effect on each party; and (8) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger. If the foregoing conditions are not satisfied or waived, one or both of NorthWestern or Black Hills would not be required to complete the Merger.
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NorthWestern and Black Hills have not yet obtained stockholder approval or the regulatory consents and approvals required to complete the Merger. Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger. NorthWestern and Black Hills will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval. The Merger Agreement may require NorthWestern and/or Black Hills to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither NorthWestern nor Black Hills will be obligated to complete the Merger.
There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge. Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. NorthWestern or Black Hills may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
The special meetings at which the NorthWestern stockholders and the Black Hills stockholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known. As a result, if stockholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further stockholder approval. Such actions could have an adverse effect on the combined company.
If NorthWestern and Black Hills are unable to complete the Merger, or there is a significant delay in completing the Merger, NorthWestern would be subject to a number of risks, including the following:
•NorthWestern would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings;
•the attention of management of NorthWestern may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to NorthWestern;
•the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company;
•NorthWestern will have been subject to certain restrictions on the conduct of its business, which may prevent NorthWestern from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending;
•the trading price of NorthWestern Common Stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and
•the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.
NorthWestern can provide no assurance that the various closing conditions will be satisfied and that the required governmental approvals and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the Merger. In addition, NorthWestern can provide no assurance that these conditions will not result in the abandonment or delay of the Merger. The occurrence of any of these events individually or in combination could have a material adverse effect on NorthWestern's results of operations and the trading price of NorthWestern's Common Stock or other securities.
The Merger Agreement contains provisions that limit NorthWestern's ability to pursue alternatives to the Merger, could discourage a potential acquirer of NorthWestern from making a favorable alternative transaction proposal and, in certain circumstances, could require NorthWestern to pay a termination fee to Black Hills.
Under the Merger Agreement, NorthWestern and Black Hills have agreed, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly solicit competing acquisition proposals or to enter into discussions concerning, or provide confidential information in connection with, any unsolicited alternative acquisition proposals. Additionally, the NorthWestern board of directors and the Black Hills board of directors are each required to recommend the approval of the applicable transaction-related proposals to its respective stockholders, subject to certain exceptions. Prior to the approval of the transaction-related proposals by their respective stockholders, the NorthWestern board of directors or the Black Hills board of directors may change its recommendation in response to an unsolicited proposal for an alternative transaction, if
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such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that the proposal constitutes or would reasonably be expected to lead to a “Superior Black Hills Proposal” or “Superior NorthWestern Proposal”, as applicable (as such terms are defined in the Merger Agreement), and that failure to take such action would be inconsistent with their fiduciary duties under applicable law to the applicable company and its stockholders under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. Prior to the approval of the transaction-related proposals by their respective stockholders, the NorthWestern board of directors and the Black Hills board of directors may also change its recommendation upon the occurrence of a “Black Hills Intervening Event” or “NorthWestern Intervening Event”, as applicable (as such terms are defined in the Merger Agreement), and such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that failing to change its recommendation would be inconsistent with its fiduciary duties under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. The Merger Agreement is subject to a “force-the-vote” provision, which means neither NorthWestern nor Black Hills would have an independent right to terminate the Merger Agreement to accept a superior proposal. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of NorthWestern from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher market value than the market value proposed to be received or realized in the Merger, or might result in a potential acquirer proposing to pay a lower price than it would otherwise have proposed to pay. As a result of these restrictions, NorthWestern may not be able to enter into an agreement with respect to a more favorable alternative transaction, or may be able to do so only by incurring potentially significant liability to Black Hills.
The Merger Agreement contains certain customary termination rights for each of NorthWestern and Black Hills; provided, that, either party would be required to pay to the other a termination fee equal to $100 million upon termination of the Merger Agreement in certain circumstances involving (i) a change in recommendation by such party’s board of directors (including, in certain circumstances, the failure of such party to publicly reaffirm its recommendation upon request) or (ii) a party entering into a definitive agreement in respect of a competing transaction within twelve months of termination of the Merger Agreement in certain circumstances involving a potential competing acquisition proposal.
NorthWestern is subject to risk of the Merger having adverse impact on its credit rating while the Merger is pending.
NorthWestern cannot be assured that its credit ratings will not be lowered as a result of the Merger or for any other reason, including the failure to consummate the Merger. Any reduction in NorthWestern's credit ratings, or the criteria used by rating agencies to determine such ratings, could adversely affect its ability to complete the Merger, its access to capital, its cost of capital and its other operating costs, and its ability to refinance or repay NorthWestern's existing debt and complete new financings, which could have a material adverse effect on NorthWestern's business, financial condition, results of operations or the trading price of its common stock or other securities.
The market prices of NorthWestern Common Stock and other securities may be subject to fluctuation while the Merger is pending.
The market price of NorthWestern Common Stock and other securities may fluctuate significantly while the Merger is pending, and any adverse developments related to the Merger or otherwise could result in holders of NorthWestern Common Stock or other securities losing some or all of the value of their investment. In addition, if the stock market experiences significant price and volume fluctuations, such fluctuations could be exacerbated by the pendency of the Merger, which could adversely affect the market for, or liquidity of, NorthWestern Common Stock or other securities, regardless of NorthWestern's actual operating performance.
Because the Merger Agreement contemplates that Black Hills will issue shares of Black Hills Common Stock to NorthWestern’s stockholders based upon a fixed exchange ratio (subject to certain adjustments for reclassifications, stock splits, and stock dividends), developments with respect to Black Hills and its shares of common stock may affect NorthWestern Common Stock irrespective of their relevance to standalone NorthWestern and even though NorthWestern may have no control over, or knowledge of, such developments. As a result, the market price of NorthWestern Common Stock during the pendency of the Merger may not accurately reflect the value of NorthWestern absent the Merger.
NorthWestern is subject to contractual restrictions in the Merger Agreement that may hinder its operations while the Merger is pending. The corollary restrictions applicable to Black Hills may not prevent Black Hills from taking actions that are adverse to NorthWestern or its stockholders.
The Merger Agreement includes certain customary restrictions with respect to the operation of NorthWestern's and Black Hills' respective businesses between the date of the Merger Agreement and the consummation of the Merger. These restrictions
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may prevent NorthWestern from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the Merger or termination of the Merger Agreement.
Despite these mutual restrictions, NorthWestern and Black Hills will continue to operate their businesses independently of one another during the pendency of the Merger. The restrictions in the Merger Agreement, which are subject to numerous exceptions, may not be adequate to prevent Black Hills from taking actions that are adverse to NorthWestern or its stockholders.
NorthWestern will incur significant transaction and other costs in connection with the Merger.
NorthWestern has incurred and expects to incur additional significant costs associated with the Merger, including transaction fees and costs of combining the operations of the two companies. Additional unanticipated costs also may be incurred in the integration of the businesses of NorthWestern and Black Hills. Any net benefit from any anticipated elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not be achieved in the near term or at all. Transaction costs could have a material adverse impact on the results of operations of NorthWestern, and the failure to achieve the anticipated benefits and efficiencies from the Merger, or the incurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the current or future market value of NorthWestern Common Stock or other securities could be adversely impacted.
Uncertainties associated with the Merger may cause a loss of management personnel and other key employees of NorthWestern and Black Hills, which could adversely affect the future business and operations of the combined company following the Merger.
Each of NorthWestern and Black Hills depends on the experience and industry knowledge of its officers and other key employees to execute its business plans. The success of the combined company after the Merger will depend in part on its ability to retain key management personnel and other key employees. Current and prospective employees of NorthWestern and Black Hills may experience uncertainty about their roles within the combined company following the Merger or other concerns regarding the timing and completion of the Merger or the operations of the combined company following the Merger, any of which may have an adverse effect on the ability of NorthWestern and Black Hills to retain or attract key management and other key personnel. If NorthWestern or Black Hills is unable to retain personnel, including NorthWestern’s or Black Hills’ key management, who are critical to the future operations of the companies, NorthWestern and Black Hills could face disruptions in their operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key NorthWestern and Black Hills personnel could diminish the anticipated benefits of the Merger. No assurance can be given that the combined company, following the Merger, will be able to retain or attract key management personnel and other key employees of NorthWestern and Black Hills to the same extent that NorthWestern and Black Hills have previously been able to retain or attract their own employees.
The business relationships of NorthWestern and Black Hills may be subject to disruption due to uncertainty associated with the Merger, which could have a material effect on the business, financial condition, cash flows and results of operations of NorthWestern or Black Hills pending the combined company and following the Merger.
Parties with which NorthWestern or Black Hills do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with NorthWestern or Black Hills following the Merger. NorthWestern’s and Black Hills’ business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom they do business may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than NorthWestern or Black Hills following the Merger. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations, of NorthWestern or Black Hills, regardless of whether the Merger is completed, as well as a material and adverse effect on the combined company’s ability to realize the expected cost savings and other benefits of the Merger. The risk, and adverse effects, of any disruption could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.
The Merger may not be accretive to NorthWestern's or Black Hills' earnings and may cause dilution to the combined company's earnings per share, which may negatively affect the current or future market price of NorthWestern Common Stock or other securities.
Expectations that the Merger will be accretive to earnings per share are based on preliminary estimates any of which may prove to be incorrect or may change materially. NorthWestern and Black Hills may encounter additional transaction and
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integration-related costs other than those they currently anticipate, may fail to realize all of the benefits anticipated in the Merger or may be subject to other factors that affect preliminary estimates or the ability of either company to realize operational efficiencies. Any of these factors could cause a decrease in NorthWestern's and Black Hills' earnings per share, or negatively affect the current or future market price of NorthWestern Common Stock or other securities.
If the Merger does not qualify as a “reorganization” within the meaning of Section 368(a) of the Code, certain NorthWestern stockholders may be required to pay substantial U.S. federal, state and/or local income taxes.
The Merger is intended to qualify as a “reorganization” within the meaning of Section 368(a) of the Code, and it is a condition to each party’s obligation to complete the Merger that it receive an opinion from counsel, dated as of the closing date of the Merger, to the effect that, on the basis of facts, representations and assumptions set forth or referred to in such opinion, the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Code. However, the foregoing opinions of counsel will each be based on, among other things, the law in effect as of the date of the opinions, certain representations made by NorthWestern and Black Hills and certain assumptions, all of which must be consistent with the state of facts existing at the time of the Merger. If there is a change in law after the date of the opinions, or if any of these representations and assumptions are, or become, inaccurate or incomplete, an opinion may be invalid, and the conclusions reached therein could be jeopardized. In addition, no ruling has been or will be sought from the U.S. Internal Revenue Service (IRS) as to the U.S. federal income tax consequences of the Merger and the other transactions contemplated by the Merger Agreement. There can be no assurance that the IRS will not assert, or that a court will not sustain, a position contrary to the conclusion set forth in any such opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Code.
If the Merger does not qualify as a “reorganization” within the meaning of Section 368(a) of the Code, each NorthWestern stockholder will recognize gain or loss, for U.S. federal—and applicable state and local—income tax purposes equal to the value of the Black Hills stock received in the Merger (plus any cash received in respect of fractional shares) minus the stockholder’s adjusted tax basis in the stockholder’s NorthWestern stock. Depending on the amount of gain, if any, that is recognized, a NorthWestern stockholder that is subject to U.S. federal, state, or local income taxes may incur a significant income tax liability.
NorthWestern and/or Black Hills may be subject to litigation challenging the Merger while it is pending, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.
Lawsuits in connection with the Merger while it is pending may be filed against NorthWestern, Black Hills, any parties to the Merger Agreement and/or their respective directors and officers, which could prevent or delay the consummation of the Merger and/or result in additional costs to us. The ultimate resolution of any such lawsuit cannot be predicted with certainty, and an adverse ruling in any such lawsuit may cause the Merger to be delayed or not to be completed and/or result in additional costs to NorthWestern and Black Hills, which could cause NorthWestern and Black Hills not to realize some or all of the anticipated benefits of the Merger. The defense or settlement of any lawsuit that remains unresolved at the time the Merger is consummated may adversely affect the combined company’s business, financial condition, results of operations and cash flows. NorthWestern cannot currently predict the outcome of or reasonably estimate the possible loss or range of loss from any such lawsuit.
| Risks Relating to the Combined Company Following Completion of the Merger | ||||||||||||||
Failure to successfully combine the businesses of NorthWestern and Black Hills in the expected time frame or at all may adversely affect the future results of the combined company, and, consequently, the value of the Black Hills common stock to be received by the NorthWestern shareholders in the Merger.
The success of the Merger will depend, in part, on the ability of the combined company to realize in a timely fashion the anticipated benefits and efficiencies from combining the businesses of NorthWestern and Black Hills. The process of integration may reveal that benefits and efficiencies are less than anticipated and may result in additional expenses, all of which could reduce the anticipated benefits of the Merger.
Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including:
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•whether United States federal and state public utility, antitrust and other regulatory authorities whose approval is required to complete the Merger impose conditions on the Merger, which may have an adverse effect on the combined company, including its ability to achieve the anticipated benefits of the Merger;
•the ability of the two companies to combine certain of their operations or take advantage of expected growth opportunities;
•general market and economic conditions;
•general competitive factors in the marketplace; and
•higher than expected costs required to achieve the anticipated benefits of the Merger.
Failure to achieve the anticipated benefits and efficiencies from the Merger, or the occurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the market value of the combined company’s common stock could be adversely impacted.
NorthWestern stockholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management.
It is currently anticipated that NorthWestern stockholders and Black Hills stockholders will hold approximately 44 percent and 56 percent, respectively, of the combined company’s common stock then-issued and outstanding after the completion of the Merger. Consequently, NorthWestern stockholders, as a group, will have reduced ownership and voting power in the combined company compared to their current ownership and voting power in NorthWestern. As a result of the reduced ownership percentages, current NorthWestern stockholders will have less influence on the management and policies of the combined company than they had with NorthWestern. Further, provisions of the Merger Agreement will result in individuals designated by Black Hills, and not previously subject to a vote of NorthWestern stockholders, holding six out of eleven positions on the combined company board of directors and there will be changes to the management of the combined company.
The market price of the combined company's Common Stock after the completion of the Merger may be affected by factors different from those that historically have affected or currently affect NorthWestern Common Stock.
Upon completion of the Merger, NorthWestern stockholders who receive Merger consideration will become holders of Black Hills Common Stock, which will trade on the NYSE or other mutually-agreeable exchange under a new name and ticker to be announced. NorthWestern's business differs from that of Black Hills and certain adjustments may be made to the combined company as a result of the Merger. The financial position of the combined company after completion of the Merger may differ from NorthWestern's financial position before the completion of the Merger, and the results of operations and/or cash flows of the combined company after the completion of the Merger may be affected by factors different from those currently affecting the financial position or results of operations and/or cash flows of NorthWestern and Black Hills, respectively. Accordingly, the market price of the combined company's common stock after the completion of the Merger may be affected by factors different from those currently affecting the market prices of NorthWestern Common Stock and Black Hills Common Stock, respectively, in the absence of the Merger. In addition, general fluctuations in stock markets could adversely affect the market for, or liquidity of, the combined company's common stock, regardless of the combined company’s actual operating performance.
The failure to integrate the businesses and operations of NorthWestern and Black Hills successfully in the expected time frame may adversely affect the combined company's future results.
NorthWestern and Black Hills have operated and, until the completion of the Merger, will continue to operate independently. Following the completion of the Merger, their respective businesses may not be integrated successfully. It is possible that the integration process could result in the loss of key NorthWestern employees or key Black Hills employees; the loss of customers, service providers, vendors or other business counterparties, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger; or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. Specifically, the following challenges, among others, must be addressed in integrating the operations of NorthWestern and Black Hills in order to realize the anticipated benefits of the Merger:
•combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, diversified business;
•combining the businesses of NorthWestern and Black Hills in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the Merger;
•avoiding delays in connection with the completion of the Merger or the integration process;
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•integrating personnel from the two companies and minimizing the loss of key employees;
•identifying and eliminating redundant functions and assets;
•harmonizing the companies’ operating practices, employee development and compensation programs, internal controls and other policies, procedures and processes;
•maintaining existing agreements with customers, service providers, vendors and other business counterparties and avoiding delays in entering into new agreements with prospective customers, service providers, vendors and other business counterparties;
•addressing possible differences in business backgrounds, corporate cultures and management philosophies;
•consolidating the companies’ operating, administrative and information technology infrastructure and financial systems; and
•establishing the combined company’s headquarters in Rapid City, South Dakota.
In addition, at times the attention of certain members of either company’s or both companies’ management and resources may be focused on completion of the Merger and the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may be beneficial, which may disrupt each company’s ongoing operations and the operations of the combined company. Furthermore, following the Merger, the board of directors and executive leadership of the combined company will consist of former directors from each of NorthWestern and Black Hills and former executive officers from each of NorthWestern and Black Hills, respectively. Combining the boards of directors and management teams of each company into a single board and a single management team could require the reconciliation of differing priorities and philosophies.
Each of NorthWestern and Black Hills may have liabilities that are not known to the other party.
Each of NorthWestern and Black Hills may have liabilities that the other party failed, or was unable, to discover in the course of performing its respective due diligence investigations. NorthWestern and Black Hills may learn additional information about the other party that materially adversely affects it, such as unknown or contingent liabilities and liabilities related to compliance with applicable laws. As a result of these factors, the combined company may incur additional costs and expenses and may be forced to later write-down or write-off assets, restructure operations or incur impairment or other charges that could result in the combined company reporting losses. Even if NorthWestern's and Black Hills' respective due diligence has identified certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with its expectations. If any of these risks materialize, this could adversely affect the combined company’s financial condition and results of operations and could contribute to negative market perceptions about, or price movements of, the combined company’s common stock following the Merger.
Each of NorthWestern and Black Hills and their respective subsidiaries has substantial amounts of indebtedness. Consequently, the combined company will have substantial indebtedness following the Merger. As a result, the rating of the combined company’s indebtedness could be downgraded, and it may be difficult for the combined company to pay or refinance its debts or take other actions, and the combined company may need to divert its cash flow from operations to debt service payments.
The combined company’s debt service obligations with respect to this indebtedness could have an adverse impact on its earnings and cash flows for as long as the indebtedness is outstanding.
The combined company’s indebtedness could also have important consequences to holders of the common stock of the combined company. For example, it could:
•make it more difficult for the combined company to pay or refinance its debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause the combined company to not have sufficient cash flows from operations to make its scheduled debt payments;
•require a substantial portion of the combined company’s cash flows from operations to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes;
•result in a downgrade in the rating of the combined company’s indebtedness, which could limit its ability to borrow additional funds or increase the interest rates applicable to its indebtedness;
•increase the risk of default on debt obligations of the combined company;
•limit the flexibility of the combined company in planning for or reacting to changes in its business and the industry in which it operates;
•increase the exposure of the combined company to a rise in interest rates, which would generate greater interest expense or the costs of obtaining applicable interest rate fluctuation hedges; or
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•require that additional or more stringent terms, conditions or covenants be placed on the combined company.
There can be no assurance that the combined company will be able to repay or refinance such borrowings and obligations.
In addition, the Merger will result in NorthWestern becoming a wholly owned subsidiary of Black Hills. The combined company may decide to incur additional indebtedness at subsidiaries of Black Hills, which could have an effect on outstanding securities, including because such subsidiary indebtedness is “structurally senior” to the indebtedness of its parent company with respect to the assets of such subsidiary.
The combined company may fail to realize all of the anticipated benefits of the Merger.
The success of the Merger will depend, in part, on the combined company’s ability to realize the anticipated benefits and cost savings from combining Black Hills’ and NorthWestern’s businesses and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that are not foreseen, in which case, among other things, the Merger may not be accretive to free cash flow and may not generate significant discretionary cash flow to return to shareholders via share buybacks or other means. Some of the assumptions that NorthWestern and Black Hills have made, such as the achievement of the anticipated benefits related to the geographic, commodity and asset diversification and the expected size, scale, inventory and financial strength of the combined company, may not be realized. The integration process may, for each of NorthWestern and Black Hills, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact the combined company.
The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.
Following the Merger, the size, geographic footprint and complexity of the combined company will increase significantly compared to the business of each of NorthWestern and Black Hills. The combined company’s future success will depend, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and geographies and associated increased costs and complexity. The combined company may also face increased scrutiny from, and/or additional regulatory requirements of, governmental authorities as a result of the significant increase in the size, geographic footprint and complexity of its business. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings or other benefits currently anticipated from the Merger.
There is no guarantee that the combined company will declare and pay dividends following the Merger.
Although each of NorthWestern and Black Hills has returned capital to its respective stockholders in the past, including through cash dividends on their respective shares of common stock, the board of directors of the combined company may determine not to declare dividends or use other means to return capital to its stockholders in the future or may reduce the amount, proportion or rate of capital returned to its stockholders through dividends or other means in the future. Decisions on whether, when, by what means and in what amounts to return capital to its stockholders will remain in the discretion of the board of directors of the combined company (as reconstituted following the Merger). Any dividend payment or share repurchase amounts will be determined by the board of directors of the combined company from time to time, and it is possible that the board of directors of the combined company may increase or decrease the amount of dividends paid or shares repurchased in the future, or determine not to declare dividends and/or repurchase shares in the future, at any time and for any reason. We expect that any such decisions will depend on the combined company’s financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that the board of directors of the combined company deems relevant, including, but not limited to:
•whether the combined company has enough discretionary cash flow to return capital to its stockholders due to its cash requirements, capital spending plans, cash flows or financial position;
•the combined company’s desire to maintain or improve the credit ratings on its debt; and
•applicable restrictions under South Dakota law. Stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared.
The combined company is expected to record a significant amount of goodwill as a result of the Merger, and such goodwill could become impaired in the future.
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Accounting standards in the United States require that one party to the Merger be identified as the acquirer. In accordance with these standards, the Merger will be accounted for as an acquisition of NorthWestern’s Common Stock by Black Hills and will follow the acquisition method of accounting for business combinations. NorthWestern's assets and liabilities will be consolidated with those of Black Hills on the combined company’s financial statements. The excess of the consideration transferred over the fair values of NorthWestern’s assets and liabilities will be recorded as goodwill.
The combined company will be required to assess goodwill for impairment at least annually. To the extent goodwill becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined company's future operating results and statements of financial position which may, in turn, have a material adverse effect on the trading price or liquidity of the combined company's securities.
The combined company's ability to utilize NorthWestern's and/or Black Hills' historic net operating loss carryforwards and certain other tax attributes may be limited.
As of December 31, 2024, NorthWestern had U.S. federal net operating loss carryforwards (NOLs) of approximately $486.6 million, which do not expire. As of December 31, 2024, Black Hills had NOLs of approximately $547.2 million, which also do not expire. However, the NOLs of each of NorthWestern and Black Hills can only be used to offset 80% of U.S. federal taxable income. The combined company's ability to utilize these NOLs and other tax attributes to reduce future taxable income following the closing of the Merger depends on many factors, including its future income, which cannot be assured, and which will be determined after the Merger on a consolidated basis with that of NorthWestern and Black Hills. It is possible that the amount of NOLs and other tax attributes that the combined company is able to utilize in any tax period ending after the closing of the Merger may be less than the amount that NorthWestern and Black Hills together (or either of them separately) would have been able to use had the Merger not taken place.
Additionally, Section 382 of the Code (Section 382) and Section 383 of the Code generally impose an annual limitation on the amount of NOLs and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs with respect to NorthWestern and/or Black Hills, utilization of NorthWestern and/or Black Hills' NOLs would be subject to an annual limitation under Section 382, generally determined by multiplying (1) the fair market value of its stock at the time of the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs, subject to certain adjustments. Any unused annual limitation may be carried over to later years.
The completion of the Merger may cause NorthWestern and/or Black Hills to undergo an ownership change under Section 382, which would trigger a limitation (calculated as described above) on NorthWestern's ability to utilize its and/or Black Hills' historic NOLs and other tax attributes.
Future sales or issuances of Black Hills Common Stock could have a negative impact on the Black Hills Common Stock price.
Under the terms of the Merger Agreement, NorthWestern stockholders will receive a fixed exchange ratio of 0.98 shares of Black Hills Common Stock for each share of NorthWestern Common Stock they own at the close of the Merger. Based on the 61,393,380 shares of NorthWestern Common Stock outstanding as of July 25, 2025, Northwestern stockholders would receive approximately 60,165,512 shares of Black Hills Common Stock upon the closing of the Merger. The treatment of outstanding equity awards of each of NorthWestern and Black Hills will vary depending on the type of award, its terms and conditions, and determinations made or to be made by each company or its board of directors, but additional shares, or cash in respect of share equivalents, would be issued to settle equity awards, and such shares are not reflected in the share totals included in the preceding sentence. The Black Hills Common Stock that NorthWestern stockholders will receive upon the exchange of NorthWestern Common Stock for the Merger consideration or in settlement of outstanding equity awards generally may be sold immediately in the public market. It is possible that some former NorthWestern stockholders may seek to sell some or all of the shares of Black Hills Common Stock they receive as Merger consideration, and the Merger Agreement contains no restriction on the ability of former NorthWestern stockholders to sell such shares of Black Hills Common Stock following completion of the Merger. Other Black Hills stockholders may also seek to sell shares of Black Hills Common Stock held by them following completion of the Merger. These sales or other dispositions of a significant number of shares of Black Hills Common Stock (or the perception that such sales or other dispositions may occur), coupled with the increase in the outstanding number of shares of Black Hills Common Stock as a result of the Merger (as well as any increase resulting from future issuances of Black Hills
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Common Stock), may affect the market for Black Hills Common Stock in an adverse manner and may cause the price of Black Hills Common Stock to fall.
Future disclosures relating to the Merger may not align with investor expectations.
In connection with the Merger, Black Hills expects to file a registration statement on Form S-4, including a prospectus and joint proxy statement for the NorthWestern stockholders' meeting and the Black Hills stockholders' meeting. Information that will be contained in such registration statement and other future disclosures relating to the Merger, which are expected to include (among other things) detailed background about the process leading the Merger, prospective financial information reviewed by the NorthWestern and Black Hills board of directors in connection with the Merger, and updated historical financial information of NorthWestern and Black Hills and pro forma financial information of the combined company, may not align with investor expectations. Such disclosures, the anticipation of such disclosures, or reactions to such disclosures could have an adverse effect on the business of NorthWestern and trading price or liquidity of NorthWestern Common Stock or other securities. Persons making investment decisions about NorthWestern securities prior to such disclosures will be required to do so without the benefit of such information and with the risk that such information may not align with their expectations or that it may have an unexpected impact on NorthWestern or the trading price or liquidity of its securities.
ITEM 5. OTHER INFORMATION
Rule 10b5-1 Plans
During the three months ended September 30, 2025, no
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ITEM 6. EXHIBITS -
(a) Exhibits
Exhibit 2.1 — Agreement and Plan of Merger, dated as of August 18, 2025, by and among Black Hills Corporation, NorthWestern Energy Group, Inc., and River Merger Sub Inc.(incorporated by reference to Exhibit 2.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598).*
Exhibit 3.1 — Second Amended and Restated Bylaws of NorthWestern Energy Group, Inc., dated August 18, 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598).
Exhibit 10.1 — Chief Executive Officer Agreement, dated August 18, 2025, between Black Hills Corporation and Brian B. Bird dated August 18, 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598).**
Exhibit 10.2 — Amendment No. 3 to Term Loan Credit Agreement and Lender Joinder Agreement. (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated October 3, 2025, Commission File No. 000-56598).
Exhibit 31.1 — Certification of chief executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.
Exhibit 31.2 — Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.
Exhibit 32.1 — Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.
Exhibit 32.2 — Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.
Exhibit 101.INS—Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit 101.SCH—Inline XBRL Taxonomy Extension Schema Document
Exhibit 101.CAL—Inline XBRL Taxonomy Extension Calculation Linkbase Document
Exhibit 101.DEF—Inline XBRL Taxonomy Extension Definition Linkbase Document
Exhibit 101.LAB—Inline XBRL Taxonomy Label Linkbase Document
Exhibit 101.PRE—Inline XBRL Taxonomy Extension Presentation Linkbase Document
Exhibit 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*Schedules and Exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby agrees to supplementally furnish to the SEC upon request any omitted schedule or exhibit to the Agreement and Plan of Merger.
**Certain personal information in this exhibit has been omitted in accordance with Regulation S-K Item 601(a)(6).
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| NorthWestern Energy Group, Inc. | |||||||||||
| Date: | October 30, 2025 | By: | /s/ CRYSTAL LAIL | ||||||||
| Crystal Lail | |||||||||||
| Vice President and Chief Financial Officer | |||||||||||
| Duly Authorized Officer and Principal Financial Officer | |||||||||||
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Northwestern Corp
NASDAQ:NWE
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