6-K 1 a30092024bp6kq3.htm 6-K Document




UNITED STATES
証券取引委員会

ワシントンDC20549


6-Kフォーム

外国の非公開発行者の報告書

証券取引法13a-16条または15d-16条に基づく
1934年証券取引法

2024年10月分
登録ファイル番号 1-06262

BP p.l.c.
（発行者の登録名の英訳）

イギリス、ロンドン、SW1Y 4PD、1セント・ジェームス・スクエア
(主要執行オフィスの住所)

登録者がForm 20-FまたはForm 40-Fのカバー下で年次報告書を提出するかどうかをチェックマークで示してください:
20-Fフォーム x  40-Fフォーム ¨
規制S-T規則101(b)(1)に準拠して、申請者が紙でForm 6-Kを提出している場合は、チェックマークで示してください。 ¨
規制S-T規則101(b)(7)に準拠して、申請者が紙でForm 6-Kを提出している場合は、チェックマークで示してください。 ¨

この第６ｋフォームに関する報告書は、ＢＰ p.l.c、ＢＰ CAPITAL MARKETS p.l.c.、及びＢＰ CAPITAL MARKETS AMERICA INC. の登録声明書（フォームＦ－３（ファイル番号 333-277842、333-277842-01 及び 333-277842-02）に含まれる目論見書に参照設けられたものとみなされます； さらに、ＢＰ p.l.c.の登録声明書（フォームＳ－８（ファイル番号333-67206））に含まれる目論見書にも含まれます。ＢＰ p.l.c. 及び ＢＰ p.l.c. の登録声明書（フォームＳ－８（ファイル番号 333-102583 及び 333-103923 ～ 333-280100）に含まれ、この報告書は提出された日から付随する一部となり、後に提出または提供された書類や報告書によって取って代わられることのないようなるものとします。

1
BP p.l.c.および子会社
2024年9月30日終了の役員報告書（Form 6-k）(a)
(a)この6-K形式では、9か月間を指しています 2024年の9か月および2023年の9か月は、それぞれ2024年9月30日および2023年9月30日に終了した9か月間を指します。2024年の第3四半期および2023年の第3四半期は、それぞれ2024年9月30日および2023年9月30日に終了した3か月間を指します。
(b)この議論は、この書式6-kの他の場所で提供されている連結財務諸表と関連する注記とともに読むべきです。bpの年度の連結財務諸表と関連する注記を含む情報と一緒に。 決算報告書20-F 2023年12月31日までの年度のための。

2
2024年第3四半期および9か月のグループ業績
焦点と効率の向上を促進し、堅牢な運用を提供する
財務サマリー
サードセカンドサード99
四半期毎四半期毎四半期毎治療にかかわらず、中央全体生存期間はわずか8ヶ月です。治療にかかわらず、中央全体生存期間はわずか8ヶ月です。
百万ドル20242024202320242023
期間の利益370 70 5,069 2,849 15,444 
非支配持分に関する減額164 199 211 509 576 
当社株主に帰属する当期純利益（純損失）206 (129)4,858 2,340 14,868 
税引前在庫保有（利益）損失*1,182 136 (1,593)467 (261)
在庫保有に伴う利益および損失に対する課税負担（クレジット）(276)(23)381 (105)50 
代替コスト（RC）利益（損失）*1,112 (16)3,646 2,702 14,657 
調整項目の調整前税引き前の純（有利な）不利な影響*1,646 3,053 (511)5,925 (3,783)
調整項目に対する課税負担（クレジット）(491)(281)158 (881)(29)
基礎代替コスト（RC）利益*2,267 2,756 3,293 7,746 10,845 
サードサード99
四半期毎四半期毎治療にかかわらず、中央全体生存期間はわずか8ヶ月です。治療にかかわらず、中央全体生存期間はわずか8ヶ月です。
百万ドル2024202320242023
オペレーティングキャッシュフロー*6,761 8,747 19,870 22,662 
キャピタル支出*(4,542)(3,603)(12,511)(11,542)
売却益およびその他の収益(a)
290 655 1,463 1,543 
株の純現金発行（買取）(b)
(2,001)(2,047)(5,502)(6,568)
財務債務57,470 48,810 57,470 48,810 
純負債*(c)
24,268 22,324 24,268 22,324 
調整後EBITDA*9,654 10,306 29,599 33,142
1株当り発表配当金（株当りセント）8.000 7.270 23.270 21.150 
1株当たり利益（セント）1.26 28.24 14.19 84.77 
1株頭当たり利益（ドル）0.08 1.69 0.85 5.09 
1株当たりの基幹RC利益（セント）13.89 19.14 46.79 61.83 
1株預金証明書当たりの基幹RC利益（ドル）0.83 1.15 2.81 3.71 

(a)売却収益は、要約されたグループキャッシュフロー計算書に記載されている処分収益です。その他の収益に関する詳細は、ページ5を参照してください。
(b)2024年第3四半期と9か月は、従業員シェア計画の受給による希薄化を相殺するために3億ドルを含んでいます（2023年第3四半期2億ドル、2023年9か月7億ドル）。
(c)詳細についてはノート9を参照してください。

RC利益（損失）、基礎RC利益、純負債、調整後EBITDA、基礎RC利益（1株当たり）および基礎RC利益（ADS当たり） 非IFRS計算基準の指標です。在庫保有（利益）損失および調整項目は非IFRS調整です。
* この文書中のアスタリスクでマークされたアイテムについては、34ページの用語集に定義が記載されています.

3

ハイライト(a)
第3四半期の利益は$2億；基礎リプレイスメント原価（RC）ベースの利益*は$23億です
•
四半期の利益はbp株主に帰属しました。$2億で、2024年第2四半期の$1億の損失と2023年第3四半期の$49億の利益と比較しています。2024年第3四半期の結果は、調整前税前の在庫保有損失* $12億と調整項目*による調整前税前の不利な影響$16億を調整して基礎RCベースの利益を導き出しています。調整項目税引前には$1.7十億の減損（注3を参照）と0.4十億の有利な公正価値会計効果*が含まれます。調整項目に関する詳細は28ページを参照してください。
•
四半期の基礎RCベースの利益は$23億で、前四半期の$28億と2023年第3四半期の$33億と比較しています。2024年第2四半期と比較すると、基礎結果には実現された製油マージンの弱さ、弱い原油取引結果、低い液体物成果が反映されており、一部が高いガス物成果で埋め合わせられています。ガスマーケティング及び取引の結果は平均を示しています。
セグメント結果
•
ガス＆低炭素エネルギー：2024年第3四半期の関心と税前RC利益は$10億で、前四半期の$3十億の損失と比較されています。2024年第3四半期の関心と税前RC利益を調整して、調整項目の不利な影響$7億を考慮しますと、第3四半期の基礎関心と税前RC利益は$18億で、2024年第2四半期の$14億と比較されています。第3四半期の関心と税前の基礎結果は、主に高いガス物成果によって大きく推進されています。ガスマーケティング及び取引の結果は平均です。
•
石油生産＆運用：2024年第3四半期の関心と税前RC利益は$19億で、前四半期の$33十億と比較されています。2024年第3四半期の関心と税前RC利益を調整して、調整項目の不利な影響$9億を考慮しますと、第3四半期の関心と税前RC利益は$28億で、2024年第2四半期の$31十億と比較されています。第3四半期の関心と税前の基礎結果は、低い液体物成果と高い探査書き落としに反映されています。
•
カスタマー＆製品：2024年第3四半期のRC事前利益は2,300万ドルで、前四半期の1億ドルの損失に対して比較すると、調整後の項目の純不利影響$4億を加味したRC事前利益は第3四半期に4億ドルで、第2四半期2024年の11億ドルに比べて低下した。カスタマーの第3四半期の基礎となる利益は燃料マージンがほぼ横ばいで、季節的に費用が部分的に相殺された高いボリュームを反映し、1億ドル増加した。一方、製品の第3四半期の基礎となる利益は9億ドル減少し、主に弱い実現した精製マージンと第2四半期よりも低い弱い石油取引貢献によるものであった。
四半期の営業キャッシュフローは68億ドルで、ファイナンス債務が575億ドル、純債務が243億ドルでした。
•
四半期の営業キャッシュフローは68億ドルで、同じ期間の2023年に比べて87億ドルでした。2024年第3四半期末のファイナンス債務は575億ドルで、2023年第4四半期末の520億ドルに比べて増加しました。純債務は第2四半期に比べて243億ドルに増加し、主に営業キャッシュフローの低下、資本支出の増加、および譲渡やその他の収益の減少によるものでした。2023年第4四半期末の純債務は209億ドルでした。
変わらない財務枠組み内での分配の増加
•
強い配当はbpのディシプリンに基づく財務枠組み内での最優先事項であり、バレル当たり約40ドルのブレント、バレル当たり11ドルのRMm、およびmmBtu当たり3ドルのHenry Hub（すべて2021年実数）のキャッシュバランスポイントで支えられています。第3四半期において、bpは1株あたり8セントの配当を発表しました。
•
bpは強固な財務体質と強いインベストメントグレードの信用格付けの維持にコミットしています。サイクルを通じて、私たちは'A'格付け範囲内で信用メトリックスをさらに向上させることを目指しています。
•
bpは、ディシプリンとリターンに焦点を当てたアプローチで、成長エンジンおよび石油、ガス、精製事業へのトランジション投資を継続しています。
•
2024年10月25日に発表された第2四半期の結果に関連する17.5億ドルの自社株買いプログラムが完了しました。第3四半期の結果に関連して、bpは第4四半期の結果を報告する前に175億ドルの自社株買いを実行する予定です。さらに、bpは2024年第4四半期に175億ドルを発表することを確認しています。また、2025年までに少なくとも140億ドルの自社株買いを、bpの2023年第4四半期の結果を基準に市況に応じて発表することをコミットしています。(b) 強力な投資等級の信用格付けを維持条件とし、現在変更はありません。ただし、2025年2月の中期計画の更新の一環として、2025年の自社株買いを含む財務ガイダンスの要素について見直しを行う予定です。
•
通常株式ごとの配当と四半期ごとの自社株買いについて設定する際、取締役会は余剰キャッシュフローの累積レベルや見通し、キャッシュ残高ポイント、強力な投資等級の信用格付けの維持などを考慮し続けます。

(a)この報告書は、2024年9月30日に終了した四半期について、2024年6月30日に終了した四半期と比較して、bpの業績に関する特定の重要な変更について議論しています。2024年6月30日に終了した四半期の財務情報は、2024年7月30日にSECに提出された当社の現行報告書の中で見つけることができます。
(b)2024年2月6日。

上記のコメントには将来を見据えた発言が含まれており、第40ページの注意書きと併せてお読みください。
4
財務結果
ページ４のハイライトに加えて：
•三半期と9か月間のbp株主に帰属可能な利益はそれぞれ$0.2億および$2.3億で、2023年の同じ期間の$4.9億および$14.9億の利益と比較しています。
–bp株主に帰属する利益の在庫評価損益と調整項目の正味影響を考慮した場合、第3四半期と9か月の基礎の代替コスト（RC）利益はそれぞれ23億ドルと77億ドルであり、それぞれ33億ドルと108億ドルと比較される 2023年の同じ期間と比較。第3四半期の基礎の代替コスト利益は主に、低い精製マージンと非常に強い2023年同期の非常に強い結果と比較して、弱い石油取引の貢献を反映しています。四半期のガスのマーケティングと取引の結果は、2023年第3四半期の弱い結果と比較して平均的であった。9か月間の減少は主に、低い精製マージン、低いガスのマーケティングと取引の結果、低い石油取引の貢献、低い実現収益を反映しており、一部低い税金で相殺されています。
–第3四半期および9か月のアイテムの調整により、2023年の同期間と比較して、それぞれ10億ドルと59億ドルの税引前不利益が発生しました。同期間の0.5億ドルと3.8億ドルの税引前有利益と比較して。
–適応項目には、管理の内部パフォーマンス指標に対する公正価値会計効果などが含まれ、第3四半期の前税額影響は4億ドルの有利な影響と、9ヶ月間の前税額影響は9億ドルの不利な影響であり、2023年の同期間の15億ドルと68億ドルの有利な前税額影響と比較している。これは主に、2024年の期間におけるLNGの先物価格の増加によるものであり、2023年の比較期間の減少と比較しています。2024年第3四半期も、ハイブリッド債券に関する公正価値会計効果の有利な影響の影響を受けています。
–2024年第3四半期および9カ月の調整項目には、資産の減損による税引き前影響がそれぞれ$17億の不利影響が含まれています 対比として、2023年同期の税引き前の不利な影響を$6億および$18億と比較すると、それぞれ$37億になります 2023年の同期には、米国の洋上風力プロジェクトに関連する持分法による収益を認識した$5億の減損債務が含まれています
•第3四半期および9カ月の税引前利益または損失に対する有効税率（ETR）はそれぞれ74％および61％でした。これは2023年の同期間の31％および32％と比較しています。第3四半期および9カ月のRCの利益または損失に対するETRはそれぞれ51％および59％でした。これは2023年の同期間の33％および32％と比較しています。補正項目を除いた場合、第3四半期および9カ月の基礎となるETRはそれぞれ42％および40％でした。これは1年前の同期間の33％および39％と比較しています。第3四半期の基礎となるETRが高かったのは、利益の地理的なミックスの変化と、過去の期間に関する調整がないためです。RCの利益または損失に対するETRおよび基礎となるETRは非IFRSの指標です。
•第3四半期および9か月の営業キャッシュフローはそれぞれ68億ドルと199億ドルで、2023年の同じ期間の87億ドルと227億ドルと比較しています。
•第3四半期および9か月の資本支出額はそれぞれ45億ドルと125億ドルであり、2023年と同じ期間の36億ドルと115億ドルと比較しています。2024年の第3四半期および9か月には、ドイツの洋上風力に関する初期支払額が7億ドル含まれています。2023年の9か月には、トラベルセンターズオブアメリカの買収に関して11億ドルが含まれています。
•第3四半期および9か月間の総売却益とその他の収益はそれぞれ30億ドルと150億ドルであり、これはそれぞれ7億ドルと15億ドルと比較しています。 2023年の同じ期間についても同様です。2024年の第3四半期には他の収益はありませんでした。売却された構成アフィリエイトの中流資産の株式49％の売却から得られた収益は、2024年の9か月間で5億ドルでした。2023年の第3四半期および9か月間のその他の収益は、アメリカ内陸部である特定の中流資産を保有する同様の構成アフィリエイトの株式49％の売却から得られた5億ドルでした。
•2023年第四四半期終結時点での財務債務は575億ドルであり、2023年第三四半期終結時点での520億ドルおよび2023年第三四半期終結時点での488億ドルと比較しています。第三四半期終結時点での純負債は243億ドルであり、2023年第四四半期終結時点での209億ドルおよび2023年第三四半期終結時点での22.3億ドルと比較しています。これは、実現されたリファイニングマージンの低下の影響と、約10億ドルの売却収益の第四四半期への再配置によって主に引き起こされました。



5
期間内のRC利益（損失）の利息や税金を控除した前の分析と、利益（損失）への調整
サードサード99
四半期毎四半期毎治療にかかわらず、中央全体生存期間はわずか8ヶ月です。治療にかかわらず、中央全体生存期間はわずか8ヶ月です。
百万ドル2024202320242023
税引き前利益（損失）
gas＆低炭素エネルギー1,007 2,275 1,728 11,911 
石油生産＆運用1,891 3,427 8,218 9,312 
顧客＆製品23 1,549 878 4,784 
その他の事業＆企業653 (500)173 (887)
合併調整- UPII*65 (57)24 (109)
3,639 6,694 11,021 25,011 
年金およびその他の老後生活給付に関連する財務費用および純財務経費調整
(1,059)(978)(3,269)(2,622)
RCベースでの課税(1,304)(1,859)(4,541)(7,156)
非支配株主持分(164)(211)(509)(576)
その他の利益（損失）（bp株主への割り当て）*1,112 3,646 2,702 14,657 
在庫保有による利益（損失）*(1,182)1,593 (467)261 
在庫の評価額の変動に伴う課税（収入）GANEGA276 (381)105 (50)
当社株主に帰属する当期純利益（純損失）206 4,858 2,340 14,868 
利息および税引前の基礎となるRC利益（損失）の分析

サードサード99
四半期毎四半期毎治療にかかわらず、中央全体生存期間はわずか8ヶ月です。治療にかかわらず、中央全体生存期間はわずか8ヶ月です。
百万ドル2024202320242023
利息と税引前の根本的なRC利益（損失）
ガス＆低炭素エネルギー1,756 1,256 4,816 6,945 
石油生産＆運用2,794 3,136 9,013 9,232 
顧客＆製品381 2,055 2,819 5,610 
その他の事業＆法人231 (303)(81)(769)
企業全体の調整 - UPII65 (57)24 (109)
5,227 6,087 16,591 20,909 
年金とその他の退職給付に関連する財務費用および純財務費用
(1,001)(882)(2,914)(2,303)
根本的なRCベースでの課税(1,795)(1,701)(5,422)(7,185)
非支配株主持分(164)(211)(509)(576)
bp株主に帰属する基礎RC利益*2,267 3,293 7,746 10,845 
bp株主に帰属する基礎RC利益の調整が、グループの場合はページ3、セグメントの場合はページ8から16に最も近い相当するIFRS基準の数値で表示されています。
オペレーティングメトリックス
運営メトリクス2024年の9ヶ月2023年の9ヶ月対
ティア1およびティア2のプロセス安全イベント*35+6
報告された記録可能な負傷頻度*0.286+ 4.8％
upstream*の生産(a) （mboe/d）
2,378+3.0%
上流ユニットの生産コスト*(b) ($/boe)
6.25+6.3%
BP運用の上流プラントの信頼性*
95.3%-0.4
BP運用の精製可用性*(a)
94.1%-1.9
(a)8ページ、11ページ、13ページの運用の更新を参照してください。四捨五入により、上流生産はガス＆低炭素エネルギーと石油＆運用の生産と完全に一致しない場合があります。
(b)主にポートフォリオのミックスを反映しています。


6
展望とガイダンス
2024年第4四半期のガイダンス
•Bpは、2024年第4四半期の報告された上流生産が、2024年第3四半期と比較して低くなることを予想しています。
•顧客ビジネスでは、BPは第三四半期と比較して季節的に需要量が低くなることを予想しており、燃料のマージンはサプライコストの動きに対して敏感であるとみなしています。
•製品では、BPは実現された精製マージンが第四四半期に低いままとして残ることを予想していますが、引き割り率の相対的な動きに敏感であることは続くでしょう。

2024年のガイダンスについて
4ページのガイダンスに加えて:
•bpは引き続き、報告および基礎となるアップストリーム生産が2023年と比較してわずかに高いと期待しています。この中で、bpは引き続き、石油生産および運用からの基礎生産が高くなり、ガスおよび低炭素エネルギーからの生産が低くなると予想しています。
•bpは、顧客のビジネスにおいて、コンビニエンスからの成長を引き続き期待しており、トラベルセンターズオブアメリカからの1年間の貢献を含む成長を期待しています；焦点市場における出来高増に基づくCastrolからより強力な貢献；および高いエネルギー販売によるbp pulseからの継続的なマージン成長を予想しています。さらに、bpは燃料マージンが供給コストに対して敏感であると引き続き予想しています。 Castrol 焦点市場における出来高増に支えられ、エネルギー売上高の増加によって推進されるbp pulseからの引き続きのマージン成長を期待しています。また、bpは燃料マージンが供給コストに対して敏感であり続けると期待しています。
•製品業種において、bpは2023年に比べて業界の製油マージンが低い水準であると引き続き予想しており、実現されたマージンは狭い北アメリカ重質原油の差益の影響を受けています。bpは2023年と比較して、製油所のメンテナンス活動が財務への影響が低くなると予想しており、それは低マージン環境を反映しています。2024年のメンテナンス活動は後半に重点が置かれ、四半期毎の中でも第4四半期に最も影響が大きいです。
•2024年の他の事業および法人の基礎年次費用は、$3-4億を予想しています。
•bpは、2023年よりわずかに償却、減損および減価償却を予想して続けています。
•bpは、2024年の基本的なETR*が約40%になると予想していますが、価格環境の変動やグループの利益と損失の地理的構成に与える影響を含むさまざまな要因に影響を受けやすいです。
•bpは2024年の資本支出を約160億ドルにすると引き続き予想しています。
•bpは、2024年に売却とその他の収益が30億ドルを超えると予想しています。2020年第2四半期以降、192億ドルの売却とその他の収益を実現しているbpは、2020年下半期から2025年までに250億ドルの売却とその他の収益を達成すると引き続き期待しています。
•During the fourth quarter, bp completed the transactions to acquire a further 50% of the issued ordinary shares of bp Bunge Bioenergia and 50.03% of the issued ordinary shares of Lightsource bp (see Note 10) and now owns 100% of the ordinary shares of both companies. Full earnings from both companies will be included in bp’s results from the date the transactions complete and finance debt acquired is expected to be approximately $3.7 billion.
•bp continues to expect Gulf of Mexico settlement payments for the year to be around $1.2 billion pre-tax including $1.1 billion pre-tax paid during the second quarter.
bp expects to update on our medium-term plans at the same time as our full year results in February 2025.

The commentary above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 40.
7
gas & low carbon energy*
Financial results
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,007 million and $1,728 million respectively, compared with $2,275 million and $11,911 million for the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $749 million and $3,088 million respectively, compared with a favourable impact of net adjusting items of $1,019 million and $4,966 million for the same periods in 2023. Adjusting items include impacts of fair value accounting effects*, relative to management's internal measure of performance, which are an adverse impact of $275 million and $1,173 million for the third quarter and nine months in 2024 and a favourable impact of $1,816 million and $6,972 million for the same periods in 2023. Under IFRS, reported earnings include the mark-to-market value of the hedges used to risk-manage LNG contracts, but not of the LNG contracts themselves. The underlying result includes the mark-to-market value of the hedges but also recognizes changes in value of the LNG contracts being risk managed. See page 28 for more information on adjusting items.
•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $1,756 million and $4,816 million respectively, compared with $1,256 million and $6,945 million for the same periods in 2023.
•The underlying RC profit before interest and tax for the third quarter compared with the same period in 2023, reflects a lower depreciation, depletion and amortization charge partly offset by lower production. The gas marketing and trading result for the quarter was average compared with a weak result in the third quarter of 2023. The underlying RC profit before interest and tax for the nine months, compared with the same period in 2023, reflects a lower gas marketing and trading result, lower realizations, lower production, higher exploration write-offs and the foreign exchange loss in the first quarter, partly offset by a lower depreciation, depletion and amortization charge.
Operational update
•Reported production for the quarter was 890mboe/d, 6.0% lower than the same period in 2023. Underlying production* was 4.0% lower, mainly due to base decline, partially offset by major projects*.
•Reported production for the nine months was 901mboe/d, 4.1% lower than the same period in 2023. Underlying production was 2.4% lower, mainly due to reduced performance partially offset by major projects ramp up.
•Renewables pipeline* at the end of the quarter was 46.8GW (bp net), including 20.5GW bp net share of Lightsource bp's (LSbp's) pipeline. The renewables pipeline decreased by 11.5GW net during the nine months following high-grading and focus of hydrogen and CCUS projects. In addition, there is over 10GW (bp net) of early stage opportunities in LSbp's hopper.
Strategic progress
gas
•On 1 August bp announced it has completed the acquisition of GETEC ENERGIE GmbH, a leading supplier of energy to commercial and industrial (C&I) customers in Germany. Agreement for this deal was announced in January 2024 and will accelerate the growth of bp’s European gas and power presence.
•On 27 August bp announced it has agreed with EOG Resources Trinidad Limited (EOG) to partner on the Coconut gas development. Coconut will be a 50/50 joint venture with EOG as operator. The final investment decision has been taken by the joint venture partners and first gas is expected in 2027.
•On 2 September bp announced it has entered into an agreement with Perenco T&T to sell four mature offshore gas fields and associated production facilities in Trinidad & Tobago (Immortelle, Flamboyant, Amherstia and Cashima). The deal will also include undeveloped resources from the Parang area. Subject to government approval, the deal is expected to complete by the end of 2024.
•On 16 September bp announced it has agreed for Apollo-managed funds to purchase a non-controlling stake in bp Pipelines TAP Limited, the bp subsidiary that holds a 20% share in Trans Adriatic Pipeline AG (TAP). Upon completion, bp will remain the controlling shareholder of bp Pipelines TAP Limited.
low carbon energy
•On 12 September bp announced that bp and Iberdrola have taken a final investment decision for construction of a 25MW green hydrogen project at bp's Castellón refinery in Spain which is expected to be operational in second half of 2026. The project will be developed by Castellón Green Hydrogen S.L., a 50:50 joint venture between bp and Iberdrola.
•On 16 September bp announced plans to sell its existing US onshore wind energy business and aims to bring together the development of onshore renewable power projects through Lightsource bp. The sale comprises 10 operating onshore wind farms across seven US states with a combined gross capacity of 1.7GW (1.3GW net to bp).
•On 24 October bp announced it has completed its acquisition of the remaining 50.03% interest in Lightsource bp, one of the world’s leading developers and operators of utility-scale solar and battery storage assets operators.
8
gas & low carbon energy (continued)
ThirdSecondThirdNineNine
quarterquarterquartermonthsmonths
$ million20242024202320242023
Profit (loss) before interest and tax1,007 (315)2,275 1,728 11,912 
Inventory holding (gains) losses*— — — — (1)
RC profit (loss) before interest and tax1,007 (315)2,275 1,728 11,911 
Net (favourable) adverse impact of adjusting items749 1,717 (1,019)3,088 (4,966)
Underlying RC profit before interest and tax1,756 1,402 1,256 4,816 6,945 
Taxation on an underlying RC basis(545)(369)(448)(1,432)(1,984)
Underlying RC profit before interest1,211 1,033 808 3,384 4,961 

ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Depreciation, depletion and amortization
Total depreciation, depletion and amortization1,180 1,543 3,682 4,390 
Exploration write-offs
Exploration write-offs1 15 232 13 
Adjusted EBITDA*(a)
Total adjusted EBITDA2,937 2,814 8,730 11,348 
Capital expenditure*
gas1,188 833 2,696 2,177 
low carbon energy908 222 1,703 778 
Total capital expenditure2,096 1,055 4,399 2,955 
(a)A reconciliation to RC profit before interest and tax is provided on page 31.

ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
Production (net of royalties)(b)
Liquids* (mb/d)92 106 97 107 
Natural gas (mmcf/d)4,627 4,875 4,661 4,826 
Total hydrocarbons* (mboe/d)890 946 901 940 
Of which equity-accounted entities:
Liquids (mb/d)2 2 2 2 
Natural gas (mmcf/d)— — — — 
Total hydrocarbons (mboe/d)2 2 2 2 
Average realizations*(c)
Liquids ($/bbl)74.80 76.69 77.23 76.51 
Natural gas ($/mcf)5.80 5.38 5.57 6.11 
Total hydrocarbons ($/boe)37.91 36.82 37.13 40.23 
(b)Includes bp’s share of production of equity-accounted entities in the gas & low carbon energy segment.
(c)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.

9
gas & low carbon energy (continued)
30 September 202430 September 2023
low carbon energy(d)
Renewables (bp net, GW)
Installed renewables capacity* 2.8 2.5 
Developed renewables to FID*6.6 6.1 
Renewables pipeline 46.843.9
of which by geographical area:
Renewables pipeline – Americas17.8 18.4 
Renewables pipeline – Asia Pacific12.9 12.1 
Renewables pipeline – Europe15.4 13.4 
Renewables pipeline – Other0.7 — 
of which by technology:
Renewables pipeline – offshore wind9.6 9.3 
Renewables pipeline – onshore wind6.7 6.1 
Renewables pipeline – solar30.5 28.5 
Total Developed renewables to FID and Renewables pipeline53.4 50.0 
(d)Because of rounding, some totals may not agree exactly with the sum of their component parts.
10
oil production & operations
Financial results
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $1,891 million and $8,218 million respectively, compared with $3,427 million and $9,312 million for the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $903 million and $795 million respectively, compared with a favourable impact of net adjusting items of $291 million and $80 million for the same periods in 2023. See page 28 for more information on adjusting items.
•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* for the third quarter and nine months was $2,794 million and $9,013 million respectively, compared with $3,136 million and $9,232 million for the same periods in 2023.
•The underlying RC profit before interest and tax for the third quarter and nine months, compared with the same periods in 2023, primarily reflect increased depreciation charges, higher costs and higher exploration write-offs partly offset by increased volume.
Operational update
•Reported production for the quarter was 1,488mboe/d, 7.7% higher than the third quarter of 2023. Underlying production* for the quarter was 6.8% higher compared with the third quarter of 2023 reflecting bpx energy performance and major projects* partly offset by base performance and adverse weather conditions in the Gulf of Mexico.
•Reported production for the nine months was 1,477mboe/d, 7.8% higher than the nine months of 2023. Underlying production for the quarter was 7.5% higher compared with the nine months of 2023 reflecting bpx energy performance and major projects* partly offset by base performance.
Strategic Progress
•The Azeri and Chirag fields and the deepwater portion of the Gunashli field (ACG) venture announced the signing of an addendum to the existing production-sharing agreement (PSA)* which enables the parties to progress the exploration, appraisal, development of and production from the non-associated natural gas reservoirs of the ACG field (bp operator with 30.37% equity).
•bp and the State Oil Company of Azerbaijan Republic (SOCAR) signed a memorandum of understanding announcing bp’s intention to join SOCAR in two exploration and development blocks in the Azerbaijan sector of the Caspian Sea. The first block is the Karabagh oil field, the second block is the Ashrafi – Dan Ulduzu – Aypara area, containing a number of existing discoveries and prospective structures.
•Following on from the final investment decision on the Kaskida project in the Gulf of Mexico, bp entered into agreements with Enbridge Offshore Facilities LLC to construct, own and operate oil and gas export pipelines to transport oil from Kaskida to the Green Canyon 19 platform and gas to markets in Louisiana. bp also entered into agreements with Shell Pipeline Company LP to transport oil from Green Canyon 19 to markets in Louisiana via a new build pipeline.
•bp has signed a memorandum of understanding with the government of the Republic of Iraq to negotiate a material integrated redevelopment programme for the Kirkuk region, spanning oil and gas investment, power generation and solar, together with wider exploration activities.
•Aker BP - Oil production has started from the Tyrving field in the Alvheim area. Tyrving is operated by Aker BP (61.26% working interest).The Tyrving development is part of the life extension of the Alvheim field and is expected to increase production while reducing both unit costs and, at just 0.3kg of CO2 per barrel, emissions per barrel. Recoverable resources in Tyrving are approximately 25 million barrels of oil equivalent (gross) (bp 15.9% holding in Aker BP).



ThirdSecondThirdNineNine
quarterquarterquartermonthsmonths
$ million20242024202320242023
Profit before interest and tax1,889 3,268 3,426 8,216 9,312 
Inventory holding (gains) losses*2 (1)1 2 — 
RC profit before interest and tax1,891 3,267 3,427 8,218 9,312 
Net (favourable) adverse impact of adjusting items903 (173)(291)795 (80)
Underlying RC profit before interest and tax2,794 3,094 3,136 9,013 9,232 
Taxation on an underlying RC basis(1,259)(1,171)(1,386)(3,939)(4,565)
Underlying RC profit before interest1,535 1,923 1,750 5,074 4,667 

11
oil production & operations (continued)
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Depreciation, depletion and amortization
Total depreciation, depletion and amortization1,708 1,432 5,063 4,129 
Exploration write-offs
Exploration write-offs309 59 411 352 
Adjusted EBITDA*(a)
Total adjusted EBITDA4,811 4,627 14,487 13,713 
Capital expenditure*
Total capital expenditure1,410 1,644 4,720 4,642 
(a)A reconciliation to RC profit before interest and tax is provided on page 31.

ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
Production (net of royalties)(b)
Liquids* (mb/d)1,084 1,011 1,075 1,005 
Natural gas (mmcf/d)2,348 2,155 2,335 2,118 
Total hydrocarbons* (mboe/d)1,488 1,382 1,477 1,371 
Of which equity-accounted entities:
Liquids (mb/d)274 266 271 271 
Natural gas (mmcf/d)443 453 430 439 
Total hydrocarbons (mboe/d)350 344 346 346 
Average realizations*(c)
Liquids ($/bbl)70.22 71.10 71.26 70.65 
Natural gas ($/mcf)2.25 3.44 2.32 4.37 
Total hydrocarbons ($/boe)53.65 56.76 54.51 57.86 
(b)Includes bp’s share of production of equity-accounted entities in the oil production & operations segment.
(c)Realizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.
12
customers & products
Financial results
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $23 million and $878 million respectively, compared with $1,549 million and $4,784 million for the same periods in 2023. The third quarter and nine months are adjusted by an adverse impact of net adjusting items* of $358 million and $1,941 million respectively, mainly related to impairment of the Gelsenkirchen refinery and associated onerous contract provisions, compared with an adverse impact of net adjusting items of $506 million and $826 million for the same periods in 2023. See page 28 for more information on adjusting items.
•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit before interest and tax* (underlying result) for the third quarter and nine months was $381 million and $2,819 million respectively, compared with $2,055 million and $5,610 million for the same periods in 2023.
•The customers & products underlying result for the third quarter was significantly lower than the same period in 2023, primarily reflecting lower refining margins and a weak oil trading contribution compared with a very strong result in the same period last year, partly offset by a higher customers result. The customers & products underlying result for the nine months was significantly lower than the same period in 2023, primarily reflecting lower refining margins and a lower oil trading contribution, partly offset by a higher customers result.
•customers – the customers underlying result for the third quarter and nine months was higher compared with the same periods in 2023, benefiting from higher retail fuels margins, a stronger Castrol result driven by higher volumes and margins and favourable foreign exchange movements. The underlying result was partly offset by a weaker European midstream performance driven by biofuels margins, lower retail volumes, and the continued impact of the US freight recession on TravelCenters of America.
•products – the products underlying result for the third quarter and nine months was significantly lower compared with the same periods in 2023. In refining, the underlying result for the third quarter was mainly impacted by lower industry refining margins, partly offset by higher commercial optimization. The oil trading contribution for the third quarter was weak, compared with the very strong result in the same period last year. The underlying result for the nine months was lower, primarily due to lower realized refining margins and the first quarter plant-wide power outage at the Whiting refinery, partly offset by a lower impact of turnaround activity. The underlying oil trading result for the nine months was lower than the same period last year.
Operational update
•bp-operated refining availability* for the third quarter and nine months was 95.6% and 94.1%, compared with 96.3% and 96.0% for the same periods in 2023, with the nine months lower mainly due to the first quarter Whiting refinery power outage.
Strategic progress
•In July, bp and Audi announced a new strategic partnership for Formula 1, including bp's development of the FIA defined advanced sustainable fuel(a) for Audi's 2026 entry and Castrol's development of lubricants and EV fluids for Audi's V6 turbo engine and electric motor and battery. The collaboration also included long-term sponsorship, making bp the first official partner of Audi's future Formula 1 factory team.
•On 1 October, bp took full ownership of bp Bunge Bioenergia, one of Brazil’s leading biofuels-producing companies, with capacity to produce around 50,000 barrels a day of ethanol equivalent from sugarcane.
•EV charge points* installed and energy sold in the first nine months grew by around 20% and two-fold respectively, compared to the same period last year, with energy sales now more than 1 TWh. bp continues to grow its global charging network, announcing an agreement in September with LAZ Parking, a privately owned parking operator in the US to collaborate in the development, deployment, and operation of ultra-fast(b) public charging hubs at LAZ-managed locations; and in India, Jio-bp, our fuels and mobility joint venture with Reliance, has now installed 5,000 charge points across India.
•In the third quarter, we continued to strengthen our convenience offer for our US customers, expanding the number of products offered by more than 50% in our recently launched private label brand epic goods. epic goods is our own line of private label consumer-packaged products for sale across our stores. In addition, bp announced the launch of earnify a loyalty program designed to provide customers with a seamless, integrated and rewarding experience, including exclusive discounts on retail store products and fuel purchases to around 5,500 bp, Amoco and ampm branded stores across the US.
•During the third quarter bp’s Archaea Energy started up three renewable natural gas (RNG) landfill plants with a total capacity of more than 4 million mmBtu per annum, bringing the total to seven RNG landfill plants started-up year to date, and expects to commission a further eight plants this year.
(a)For further details please refer to the press release dated 15 July 2024 on bp.com.
(b)"ultra-fast" includes charger capacity of ≥150kW.


13
customers & products (continued)
ThirdSecondThirdNineNine
quarterquarterquartermonthsmonths
$ million20242024202320242023
Profit (loss) before interest and tax(1,157)(270)3,143 413 5,044 
Inventory holding (gains) losses*1,180 137 (1,594)465 (260)
RC profit (loss) before interest and tax23 (133)1,549 878 4,784 
Net (favourable) adverse impact of adjusting items358 1,282 506 1,941 826 
Underlying RC profit before interest and tax381 1,149 2,055 2,819 5,610 
Of which:(a)
customers – convenience & mobility897 790 670 2,057 1,762 
Castrol – included in customers216 211 185 611 517 
products – refining & trading(516)359 1,385 762 3,848 
Taxation on an underlying RC basis(67)(125)(167)(525)(1,215)
Underlying RC profit before interest314 1,024 1,888 2,294 4,395 
(a)A reconciliation to RC profit before interest and tax by business is provided on page 30.

ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Adjusted EBITDA*(b)
customers – convenience & mobility 1,410 1,151 3,545 3,032 
Castrol – included in customers261 228 740 641 
products – refining & trading(66)1,819 2,120 5,184 
1,344 2,970 5,665 8,216 
Depreciation, depletion and amortization
Total depreciation, depletion and amortization963 915 2,846 2,606 
Capital expenditure*
customers – convenience & mobility455 435 1,518 2,345 
Castrol – included in customers50 60 167 172 
products – refining & trading476 367 1,578 1,305 
Total capital expenditure931 802 3,096 3,650 
(b)A reconciliation to RC profit before interest and tax by business is provided on page 30.

Retail(c)
ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
bp retail sites* – total (#)21,200 21,150 21,200 21,150 
Strategic convenience sites*2,950 2,750 2,950 2,750 
(c)Reported to the nearest 50.

Marketing sales of refined products (mb/d)ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
US1,240 1,280 1,197 1,212 
Europe1,130 1,093 1,049 1,041 
Rest of World457 474 463 469 
2,827 2,847 2,709 2,722 
Trading/supply sales of refined products354392 364359 
Total sales volume of refined products3,1813,239 3,0733,081 




14
customers & products (continued)
Refining marker margin*
ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
bp average refining marker margin (RMM) ($/bbl)16.5 31.8 19.2 28.2 

Refinery throughputs (mb/d)ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
US671 690 622 671 
Europe769 760 774 773 
Total refinery throughputs1,440 1,450 1,396 1,444 
bp-operated refining availability* (%)95.6 96.3 94.1 96.0 
15
other businesses & corporate
Other businesses & corporate comprises technology, bp ventures, launchpad, regions, corporates & solutions, our corporate activities & functions and any residual costs of the Gulf of Mexico oil spill.
Financial results
•The replacement cost (RC) profit before interest and tax for the third quarter and nine months was $653 million and $173 million respectively, compared with a loss of $500 million and $887 million for the same periods in 2023. The third quarter and nine months are adjusted by a favourable impact of net adjusting items* of $422 million and $254 million respectively, compared with an adverse impact of net adjusting items of $197 million and $118 million for the same periods in 2023. Adjusting items include impacts of fair value accounting effects* which are a favourable impact of $494 million for the quarter and $272 million for the nine months in 2024, and an adverse impact of $146 million and a favourable impact of $51 million for the same periods in 2023. See page 28 for more information on adjusting items.
•After adjusting RC profit before interest and tax for adjusting items, the underlying RC profit or loss before interest and tax* for the third quarter and nine months was a profit of $231 million and a loss of $81 million respectively, compared with a loss of $303 million and $769 million for the same periods in 2023.


ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Profit (loss) before interest and tax653 (500)173 (887)
Inventory holding (gains) losses*— — — — 
RC profit (loss) before interest and tax653 (500)173 (887)
Net (favourable) adverse impact of adjusting items(a)
(422)197 (254)118 
Underlying RC profit (loss) before interest and tax231 (303)(81)(769)
Taxation on an underlying RC basis(64)162 38 201 
Underlying RC profit (loss) before interest167 (141)(43)(568)
(a)Includes fair value accounting effects relating to hybrid bonds. See page 35 for more information.



16
Financial statements
Group income statement
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Sales and other operating revenues (Note 5)
47,254 53,269 143,433 157,989 
Earnings from joint ventures – after interest and tax406 (198)834 357 
Earnings from associates – after interest and tax280 271 844 675 
Interest and other income438 410 1,233 1,036 
Gains on sale of businesses and fixed assets(48)264 197 389 
Total revenues and other income48,330 54,016 146,541 160,446 
Purchases30,139 29,951 86,677 88,245 
Production and manufacturing expenses5,004 6,080 18,543 19,293 
Production and similar taxes469 456 1,397 1,334 
Depreciation, depletion and amortization (Note 6)
4,117 4,145 12,365 11,868 
Net impairment and losses on sale of businesses and fixed assets (Note 3)
1,842 542 3,888 1,899 
Exploration expense372 97 798 496 
Distribution and administration expenses3,930 4,458 12,319 12,039 
Profit (loss) before interest and taxation 2,457 8,287 10,554 25,272 
Finance costs1,101 1,039 3,392 2,802 
Net finance (income) expense relating to pensions and other post-retirement benefits(42)(61)(123)(180)
Profit (loss) before taxation 1,398 7,309 7,285 22,650 
Taxation1,028 2,240 4,436 7,206 
Profit (loss) for the period370 5,069 2,849 15,444 
Attributable to
bp shareholders206 4,858 2,340 14,868 
Non-controlling interests
164 211 509 576 
370 5,069 2,849 15,444 
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic1.26 28.24 14.19 84.77 
Diluted1.23 27.59 13.83 82.99 
Per ADS (dollars)
Basic0.08 1.69 0.85 5.09 
Diluted0.07 1.66 0.83 4.98 



17
Condensed group statement of comprehensive income
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Profit (loss) for the period370 5,069 2,849 15,444 
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences838 (590)248 (126)
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assets— (2)— (2)
Cash flow hedges and costs of hedging(111)(56)(326)434 
Share of items relating to equity-accounted entities, net of tax(41)25 (39)(205)
Income tax relating to items that may be reclassified91 (69)127 (74)
777 (692)10 27 
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset(51)(111)(357)(1,053)
Remeasurements of equity investments(8)— (38)— 
Cash flow hedges that will subsequently be transferred to the balance sheet10 (1)7 (1)
Income tax relating to items that will not be reclassified(a)
12 57 745 388 
(37)(55)357 (666)
Other comprehensive income 740 (747)367 (639)
Total comprehensive income1,110 4,322 3,216 14,805 
Attributable to
bp shareholders922 4,140 2,705 14,241 
Non-controlling interests188 182 511 564 
1,110 4,322 3,216 14,805 

(a)Nine months 2024 includes a $658-million credit in respect of the reduction in the deferred tax liability on defined benefit pension plan surpluses following the reduction in the rate of the authorized surplus payments tax charge in the UK from 35% to 25%.
18
Condensed group statement of changes in equity
bp shareholders’Non-controlling interestsTotal
$ millionequityHybrid bondsOther interestequity
At 1 January 202470,283 13,566 1,644 85,493 
Total comprehensive income 2,705 470 41 3,216 
Dividends(3,739)— (282)(4,021)
Cash flow hedges transferred to the balance sheet, net of tax
(8)— — (8)
Repurchase of ordinary share capital(5,554)— — (5,554)
Share-based payments, net of tax903 — — 903 
Issue of perpetual hybrid bonds(a)
(4)1,300 — 1,296 
Redemption of perpetual hybrid bonds, net of tax(a)
9 (1,300)— (1,291)
Payments on perpetual hybrid bonds— (520)— (520)
Transactions involving non-controlling interests, net of tax
231 — 201 432 
At 30 September 202464,826 13,516 1,604 79,946 
bp shareholders’Non-controlling interestsTotal
$ millionequityHybrid bondsOther interestequity
At 1 January 202367,553 13,390 2,047 82,990 
Total comprehensive income14,241 438 126 14,805 
Dividends(3,598)— (326)(3,924)
Repurchase of ordinary share capital(6,666)— — (6,666)
Share-based payments, net of tax531 — — 531 
Issue of perpetual hybrid bonds(1)163 — 162 
Payments on perpetual hybrid bonds(5)(494)— (499)
Transactions involving non-controlling interests, net of tax363 — (86)277 
At 30 September 202372,418 13,497 1,761 87,676 

(a)During the first quarter 2024 BP Capital Markets PLC issued $1.3 billion of US dollar perpetual subordinated hybrid bonds with a coupon fixed for an initial period up to 2034 of 6.45% and voluntarily bought back $1.3 billion of the non-call 2025 4.375% US dollar hybrid bond issued in 2020. Taken together these transactions had no significant impact on net debt or gearing.

19
Group balance sheet
30 September31 December
$ million20242023
Non-current assets
Property, plant and equipment99,555 104,719 
Goodwill12,873 12,472 
Intangible assets10,626 9,991 
Investments in joint ventures12,446 12,435 
Investments in associates7,932 7,814 
Other investments1,340 2,189 
Fixed assets144,772 149,620 
Loans2,270 1,942 
Trade and other receivables2,270 1,767 
Derivative financial instruments11,849 9,980 
Prepayments1,419 623 
Deferred tax assets5,478 4,268 
Defined benefit pension plan surpluses7,968 7,948 
176,026 176,148 
Current assets
Loans220 240 
Inventories21,493 22,819 
Trade and other receivables26,133 31,123 
Derivative financial instruments6,358 12,583 
Prepayments 1,149 2,520 
Current tax receivable1,153 837 
Other investments167 843 
Cash and cash equivalents34,595 33,030 
91,268 103,995 
Assets classified as held for sale (Note 2)
2,414 151 
93,682 104,146 
Total assets269,708 280,294 
Current liabilities
Trade and other payables54,385 61,155 
Derivative financial instruments3,762 5,250 
Accruals 5,818 6,527 
Lease liabilities2,726 2,650 
Finance debt4,484 3,284 
Current tax payable1,706 2,732 
Provisions4,106 4,418 
76,987 86,016 
Liabilities directly associated with assets classified as held for sale (Note 2)
32 62 
77,019 86,078 
Non-current liabilities
Other payables9,063 10,076 
Derivative financial instruments12,303 10,402 
Accruals1,197 1,310 
Lease liabilities8,292 8,471 
Finance debt52,986 48,670 
Deferred tax liabilities8,950 9,617 
Provisions14,649 14,721 
Defined benefit pension plan and other post-retirement benefit plan deficits 5,303 5,456 
112,743 108,723 
Total liabilities189,762 194,801 
Net assets79,946 85,493 
Equity
bp shareholders’ equity64,826 70,283 
Non-controlling interests15,120 15,210 
Total equity79,946 85,493 

20
Condensed group cash flow statement
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Operating activities
Profit (loss) before taxation1,398 7,309 7,285 22,650 
Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities
Depreciation, depletion and amortization and exploration expenditure written off
4,427 4,219 13,008 12,233 
Net impairment and (gain) loss on sale of businesses and fixed assets1,890 278 3,691 1,510 
Earnings from equity-accounted entities, less dividends received
(196)421 (273)391 
Net charge for interest and other finance expense, less net interest paid
324 136 1,040 301 
Share-based payments
278 298 946 519 
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans
(52)(40)(118)(130)
Net charge for provisions, less payments
(48)(342)33 (1,662)
Movements in inventories and other current and non-current assets and liabilities
1,798 (783)1,223 (5,280)
Income taxes paid
(3,058)(2,749)(6,965)(7,870)
Net cash provided by operating activities6,761 8,747 19,870 22,662 
Investing activities
Expenditure on property, plant and equipment, intangible and other assets(4,223)(3,456)(11,404)(10,038)
Acquisitions, net of cash acquired(218)(9)(440)(761)
Investment in joint ventures(76)(102)(524)(692)
Investment in associates(25)(36)(143)(51)
Total cash capital expenditure(4,542)(3,603)(12,511)(11,542)
Proceeds from disposal of fixed assets16 59 117 102 
Proceeds from disposal of businesses, net of cash disposed274 79 840 924 
Proceeds from loan repayments19 12 59 39 
Cash provided from investing activities309 150 1,016 1,065 
Net cash used in investing activities(4,233)(3,453)(11,495)(10,477)
Financing activities
Net issue (repurchase) of shares (Note 7)
(2,001)(2,047)(5,502)(6,568)
Lease liability payments(703)(663)(2,076)(1,838)
Proceeds from long-term financing2,401 8 7,396 6,046 
Repayments of long-term financing(956)(264)(2,253)(3,891)
Net increase (decrease) in short-term debt(73)(71)(8)(948)
Issue of perpetual hybrid bonds(a)
— 30 1,296 162 
Redemption of perpetual hybrid bonds(a)
— — (1,288)— 
Payments relating to perpetual hybrid bonds(271)(258)(798)(744)
Payments relating to transactions involving non-controlling interests (Other interest)— — — (180)
Receipts relating to transactions involving non-controlling interests (Other interest)(7)527 517 536 
Dividends paid - bp shareholders(1,297)(1,249)(3,720)(3,585)
 - non-controlling interests
(96)(191)(282)(326)
Net cash provided by (used in) financing activities(3,003)(4,178)(6,718)(11,336)
Currency translation differences relating to cash and cash equivalents179 (104)(92)(118)
Increase (decrease) in cash and cash equivalents(296)1,012 1,565 731 
Cash and cash equivalents at beginning of period34,891 28,914 33,030 29,195 
Cash and cash equivalents at end of period34,595 29,926 34,595 29,926 


(a)See Condensed group statement of changes in equity - footnote (a) for further information.
21
Notes
Note 1. Basis of preparation
The interim financial information included in this report has been prepared in accordance with IAS 34 'Interim Financial Reporting'.
The results for the interim periods are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of the results for each period. All such adjustments are of a normal recurring nature. This report should be read in conjunction with the consolidated financial statements and related notes for the year ended 31 December 2023 included in bp Annual Report and Form 20-F 2023.
bp prepares its consolidated financial statements included within bp Annual Report and Form 20-F on the basis of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the UK, and European Union (EU), and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the UK and EU differ in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the periods presented. The financial information presented herein has been prepared in accordance with the accounting policies expected to be used in preparing bp Annual Report and Form 20-F 2024 which are the same as those used in preparing bp Annual Report and Form 20-F 2023.
In July 2024, the new UK government announced further changes (effective from 1 November 2024) to the Energy Profits Levy including a 3% increase in the rate, an extension to 31 March 2030 and the removal of the Levy’s main investment allowance. The 30 October 2024 Autumn Budget may also announce further restrictions on capital allowance claims for Levy purposes. These changes have not yet been substantively enacted and therefore have not been applied in accounting for deferred tax in the third quarter 2024. The impacts will be reflected in the group consolidated financial statements when the changes are substantively enacted.
There are no new or amended standards or interpretations adopted from 1 January 2024 onwards that have a significant impact on the financial information.
Significant accounting judgements and estimates
bp's significant accounting judgements and estimates were disclosed in bp Annual Report and Form 20-F 2023. These have been subsequently considered at the end of this quarter to determine if any changes were required to those judgements and estimates. No significant changes were identified.

Note 2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 30 September 2024 is $2,414 million, with associated liabilities of $32 million and includes agreed sales of receivables relating to a prior divestment monetized at the beginning of the fourth quarter and divestments that are agreed but not yet completed as described below.
On 14 February 2024, bp and ADNOC announced that they had agreed to form a new joint venture (JV) in Egypt (51% bp and 49% ADNOC). As part of the agreement, bp will contribute its interests in three development concessions, as well as exploration agreements, in Egypt to the new JV. ADNOC will make a proportionate cash contribution. Subject to regulatory approvals and clearances, the formation of the JV is expected to complete during the fourth quarter of 2024. The carrying amount of assets classified as held for sale at 30 September 2024 is $1,453 million, with associated liabilities of $23 million.
On 16 November 2023, bp entered into an agreement to sell its Türkiye ground fuels business to Petrol Ofisi. This includes the group's interest in three joint venture terminals in Türkiye. Completion of the sale is subject to regulatory approvals and is expected to complete during the fourth quarter 2024. The carrying amount of assets classified as held for sale at 30 September 2024 is $107 million, with associated liabilities of $9 million. Cumulative foreign exchange losses within reserves of approximately $950 million are expected to be recycled to the group income statement at completion.

22
Note 3. Impairment and losses on sale of businesses and fixed assets
Net impairment charges and losses on sale of businesses and fixed assets for the third quarter and nine months were $1,842 million and $3,888 million respectively, compared with net charges of $542 million and $1,899 million for the same periods in 2023 and include net impairment charges for the third quarter and nine months of $1,730 million and $3,675 million respectively, compared with net impairment charges of $612 million and $1,779 million for the same periods in 2023. 
Gas & low carbon energy
Third quarter and nine months of 2024 impairments includes a net impairment charge of $734 million and $1,859 million respectively, compared with net charges of $224 million and $1,284 million for the same periods in 2023 in the gas & low carbon energy segment. 2024 includes amounts in Mauritania & Senegal which principally arose as a result of increased forecast future expenditure. The recoverable amount of the cash generating unit within this business was based on a value-in-use calculation.
Oil production & operations
Third quarter and nine months of 2024 impairments includes a net impairment charge of $767 million and $900 million respectively, compared with net charges of $142 million and $178 million for the same periods in 2023 in the oil production & operations segment. 2024 includes amounts in the North Sea. The recoverable amounts of the cash generating units within this business were based on value-in-use calculations.
Customers & products
Third quarter and nine months of 2024 impairments includes a net impairment charge of $223 million and $914 million respectively, compared with net charges of $221 million and $247 million for the same periods in 2023 in the customers & products segment. 2024 includes amounts in Germany relating to the ongoing review of the Gelsenkirchen refinery. The recoverable amount of the cash generating unit within this business was based on a value-in-use calculation.

Note 4. Analysis of replacement cost profit (loss) before interest and tax and reconciliation to profit (loss) before taxation
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
gas & low carbon energy1,007 2,275 1,728 11,911 
oil production & operations1,891 3,427 8,218 9,312 
customers & products23 1,549 878 4,784 
other businesses & corporate653 (500)173 (887)
3,574 6,751 10,997 25,120 
Consolidation adjustment – UPII*65 (57)24 (109)
3,639 6,694 11,021 25,011 
Inventory holding gains (losses)*
gas & low carbon energy— — — 1 
oil production & operations(2)(1)(2)— 
customers & products(1,180)1,594 (465)260 
Profit (loss) before interest and tax2,457 8,287 10,554 25,272 
Finance costs1,101 1,039 3,392 2,802 
Net finance expense/(income) relating to pensions and other post-retirement benefits(42)(61)(123)(180)
Profit (loss) before taxation1,398 7,309 7,285 22,650 
RC profit (loss) before interest and tax*
US1,122 1,467 4,277 6,786 
Non-US2,517 5,227 6,744 18,225 
3,639 6,694 11,021 25,011 

23
Note 5. Sales and other operating revenues
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
By segment
gas & low carbon energy8,526 10,313 23,010 38,627 
oil production & operations6,468 6,225 19,559 18,155 
customers & products38,437 42,908 119,432 119,841 
other businesses & corporate614 672 1,746 2,000 
54,045 60,118 163,747 178,623 
Less: sales and other operating revenues between segments
gas & low carbon energy385 367 1,026 1,743 
oil production & operations5,860 5,747 17,755 17,244 
customers & products(138)508 180 472 
other businesses & corporate684 227 1,353 1,175 
6,791 6,849 20,314 20,634 
External sales and other operating revenues
gas & low carbon energy8,141 9,946 21,984 36,884 
oil production & operations608 478 1,804 911 
customers & products38,575 42,400 119,252 119,369 
other businesses & corporate(70)445 393 825 
Total sales and other operating revenues47,254 53,269 143,433 157,989 
By geographical area
US19,388 22,032 59,586 61,257 
Non-US36,712 43,382 112,752 128,224 
56,100 65,414 172,338 189,481 
Less: sales and other operating revenues between areas8,846 12,145 28,905 31,492 
47,254 53,269 143,433 157,989 
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to revenues from contracts with customers:
Crude oil618 496 1,704 1,653 
Oil products30,997 35,486 93,385 96,845 
Natural gas, LNG and NGLs6,458 6,396 17,196 21,881 
Non-oil products and other revenues from contracts with customers3,213 2,765 9,249 7,387 
Revenue from contracts with customers41,286 45,143 121,534 127,766 
Other operating revenues(a)
5,968 8,126 21,899 30,223 
Total sales and other operating revenues47,254 53,269 143,433 157,989 

(a)Principally relates to commodity derivative transactions including sales of bp own production in trading books.


Note 6. Depreciation, depletion and amortization
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Total depreciation, depletion and amortization by segment
gas & low carbon energy1,180 1,543 3,682 4,390 
oil production & operations1,708 1,432 5,063 4,129 
customers & products963 915 2,846 2,606 
other businesses & corporate266 255 774 743 
4,117 4,145 12,365 11,868 
Total depreciation, depletion and amortization by geographical area
US1,735 1,479 5,008 4,071 
Non-US2,382 2,666 7,357 7,797 
4,117 4,145 12,365 11,868 


24
Note 7. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated by dividing the profit (loss) for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. Against the authority granted at bp's 2024 annual general meeting, 350 million ordinary shares repurchased for cancellation were settled during the third quarter 2024 for a total cost of $2,001 million. A further 150 million ordinary shares were repurchased between the end of the reporting period and the date when the financial statements are authorised for issue for a total cost of $796 million. This amount has been accrued at 30 September 2024. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the period-end commitment to repurchase shares subsequent to the end of the period.
The calculation of EpS is performed separately for each discrete quarterly period, and for the year-to-date period. As a result, the sum of the discrete quarterly EpS amounts in any particular year-to-date period may not be equal to the EpS amount for the year-to-date period.
For the diluted EpS calculation the weighted average number of shares outstanding during the period is adjusted for the number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Results for the period
Profit (loss) for the period attributable to bp shareholders206 4,858 2,340 14,868 
Less: preference dividend— — 1 1 
Less: (gain) loss on redemption of perpetual hybrid bonds(a)
— — (10)— 
Profit (loss) attributable to bp ordinary shareholders206 4,858 2,349 14,867 
Number of shares (thousand)(b)(c)
Basic weighted average number of shares outstanding
16,321,349 17,204,488 16,553,408 17,537,170 
ADS equivalent(d)
2,720,224 2,867,414 2,758,901 2,922,861 
Weighted average number of shares outstanding used to calculate diluted earnings per share
16,709,108 17,609,601 16,980,519 17,914,383 
ADS equivalent(d)
2,784,851 2,934,933 2,830,086 2,985,730 
Shares in issue at period-end16,155,806 17,061,004 16,155,806 17,061,004 
ADS equivalent(d)
2,692,634 2,843,500 2,692,634 2,843,500 
(a)See Condensed group statement of changes in equity - footnote (a) for further information.
(b)If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. The numbers of potentially issuable shares that have been excluded from the calculation for the second quarter 2024 are 374,406 thousand (ADS equivalent 62,401 thousand).
(c)Excludes treasury shares and includes certain shares that will be issued in the future under employee share-based payment plans.
(d)One ADS is equivalent to six ordinary shares.

Issued ordinary share capital as at 30 September 2024 comprised 16,262,632,593 ordinary shares (31 December 2023 17,174,461,587 ordinary shares). This includes shares held in trust to settle future employee share plan obligations and excludes 717,435,379 ordinary shares which have been bought back and are held in treasury by bp (31 December 2023 726,338,898 ordinary shares).

Note 8. Dividends
Dividends payable
bp today announced an interim dividend of 8.000 cents per ordinary share which is expected to be paid on 20 December 2024 to ordinary shareholders and American Depositary Share (ADS) holders on the register on 8 November 2024. The ex-dividend date will be 7 November 2024 for ordinary shareholders and 8 November 2024 for ADS holders. The corresponding amount in sterling is due to be announced on 5 December 2024, calculated based on the average of the market exchange rates over three dealing days between 29 November 2024 and 3 December 2024. Holders of ADSs are expected to receive $0.48 per ADS (less applicable fees). The board has decided not to offer a scrip dividend alternative in respect of the third quarter 2024 dividend. Ordinary shareholders and ADS holders (subject to certain exceptions) will be able to participate in a dividend reinvestment programme. Details of the third quarter dividend and timetable are available at bp.com/dividends and further details of the dividend reinvestment programmes are available at bp.com/drip.
ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
Dividends paid per ordinary share
cents8.000 7.270 22.540 20.490 
pence6.050 5.732 17.425 16.592 
Dividends paid per ADS (cents)48.00 43.62 135.24 122.94 

25
Note 9. Net debt
Net debt*30 September31 December30 September
$ million202420232023
Finance debt(a)
57,470 51,954 48,810 
Fair value (asset) liability of hedges related to finance debt(b)
1,393 1,988 3,440 
58,863 53,942 52,250 
Less: cash and cash equivalents34,595 33,030 29,926 
Net debt(c)
24,268 20,912 22,324 
Total equity79,946 85,493 87,676 
Gearing*23.3%19.7%20.3%
(a)The fair value of finance debt at 30 September 2024 was $54,324 million (31 December 2023 $48,795 million, 30 September 2023 $43,387 million).
(b)Derivative financial instruments entered into for the purpose of managing foreign currency exchange risk associated with net debt with a fair value liability position of $123 million at 30 September 2024 (fourth quarter 2023 liability of $73 million and third quarter 2023 liability of $102 million) are not included in the calculation of net debt shown above as hedge accounting is not applied for these instruments.
(c)Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement.

Note 10. Events after the reporting period
On 1 October 2024, the group acquired a further 50% of the issued ordinary shares of bp Bunge Bioenergia and now owns 100% of the ordinary shares. The transaction will be accounted for as a business combination achieved in stages using the acquisition method. Total consideration is estimated at $0.8 billion including deferred consideration. Reported finance debt and cash acquired in the transaction is expected to be approximately $0.7 billion and $0.3 billion, respectively.
On 24 October 2024, the group acquired a further 50.03% of the issued ordinary shares of Lightsource bp and now owns 100% of the ordinary shares. The transaction will be accounted for as a business combination achieved in stages using the acquisition method. Total consideration is estimated at $0.5 billion including deferred and contingent consideration. Reported finance debt and cash acquired in the transaction is expected to be approximately $3.0 billion and $0.3 billion, respectively.
Immediately prior to the business combination, 2.4GW of Lightsource bp’s operational and construction assets in the United States were transferred from Lightsource bp into a new joint venture between bp and the Lightsource bp founders, and certain management and staff. bp will apply equity accounting to this investment for bp’s approximate 50% share.
As the above transactions have only recently completed, the initial provisional purchase price allocations and the related measurement of acquired asset and liability fair values, and accounting policy alignments are ongoing.

Note 11. Statutory accounts
The financial information shown in this publication, which was approved by the Board of Directors on 28 October 2024, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in bp Annual Report and Form 20-F 2024.


26
Additional information
Capital expenditure*
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Capital expenditure
Organic capital expenditure*4,341 3,597 11,906 10,325 
Inorganic capital expenditure*(a)
201 6 605 1,217 
4,542 3,603 12,511 11,542 
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Capital expenditure by segment
gas & low carbon energy2,096 1,055 4,399 2,955 
oil production & operations1,410 1,644 4,720 4,642 
customers & products(a)
931 802 3,096 3,650 
other businesses & corporate105 102 296 295 
4,542 3,603 12,511 11,542 
Capital expenditure by geographical area
US1,389 1,583 4,801 5,941 
Non-US3,153 2,020 7,710 5,601 
4,542 3,603 12,511 11,542 
(a)Nine months 2023 includes $1.1 billion, net of adjustments, in respect of the TravelCenters of America acquisition.
27
Adjusting items*
ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
gas & low carbon energy
Gains on sale of businesses and fixed assets19 — 29 16 
Net impairment and losses on sale of businesses and fixed assets(a)
(772)(224)(1,898)(1,284)
Environmental and related provisions— — — — 
Restructuring, integration and rationalization costs(24)(1)(24)— 
Fair value accounting effects(b)(c)
(275)1,816 (1,173)6,972 
Other(d)
303 (572)(22)(738)
(749)1,019 (3,088)4,966 
oil production & operations
Gains on sale of businesses and fixed assets(82)246 109 352 
Net impairment and losses on sale of businesses and fixed assets(a)
(770)(52)(919)(184)
Environmental and related provisions(53)99 65 6 
Restructuring, integration and rationalization costs(1)— (1)(1)
Fair value accounting effects— — — — 
Other3 (2)(49)(93)
(903)291 (795)80 
customers & products
Gains on sale of businesses and fixed assets12 18 21 21 
Net impairment and losses on sale of businesses and fixed assets(a)
(295)(242)(1,069)(361)
Environmental and related provisions(4)— 3 (11)
Restructuring, integration and rationalization costs(39)1 (38)— 
Fair value accounting effects(c)
157 (198)38 (230)
Other(e)
(189)(85)(896)(245)
(358)(506)(1,941)(826)
other businesses & corporate
Gains on sale of businesses and fixed assets3 — 35 — 
Net impairment and losses on sale of businesses and fixed assets(6)(23)9 (60)
Environmental and related provisions(8)(8)11 (39)
Restructuring, integration and rationalization costs(50)(3)(38)(13)
Fair value accounting effects(c)
494 (146)272 51 
Gulf of Mexico oil spill(20)(19)(39)(46)
Other9 2 4 (11)
422 (197)254 (118)
Total before interest and taxation(1,588)607 (5,570)4,102 
Finance costs(f)
(58)(96)(355)(319)
Total before taxation(1,646)511 (5,925)3,783 
Taxation on adjusting items(g)
535 (158)1,229 (203)
Taxation – tax rate change effect(h)
(44)— (348)232 
Total after taxation for period(1,155)353 (5,044)3,812 
(a)See Note 3 for further information.
(b)Under IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value accounting effect includes the change in value of LNG contracts that are being risk managed, and the underlying result reflects how bp risk-manages its LNG contracts.
(c)For further information, including the nature of fair value accounting effects reported in each segment, see pages 5, 8 and 35.
(d)Third quarter and nine months 2023 include a $540 million impairment charge recognized through equity-accounted earnings relating to US offshore wind projects.
(e)All periods in 2024 include recognition of onerous contract provisions related to the Gelsenkirchen refinery. The unwind of these provisions will be reported as an adjusting item as the contractual obligations are settled.
(f)Includes the unwinding of discounting effects relating to Gulf of Mexico oil spill payables and the income statement impact of temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt. Nine months 2023 also includes the income statement impact associated with the buyback of finance debt. Third quarter and nine months 2024 also includes the unwinding of discounting effects relating to certain onerous contract provisions.
(g)Includes certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.
(h)Nine months 2024 and nine months 2023 include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at 31 December 2022 that are expected to unwind before 31 March 2028. The EPL increases the headline rate of tax to 75% and applies to taxable profits from bp’s North Sea business made from 1 January 2023 until 31 March 2028. In July 2024 the new UK government announced further changes to the EPL including a 3% increase in the rate and an extension to 31 March 2030, together with changes to investment allowances and capital allowances. These changes have not yet been substantively enacted and have therefore not been accounted for at 30 September 2024. The impacts will be reflected in the financial statements when the changes are substantively enacted.
28
Net debt including leases
Net debt including leases*30 September31 December30 September
$ million202420232023
Net debt*24,268 20,912 22,324 
Lease liabilities11,018 11,121 10,879 
Net partner (receivable) payable for leases entered into on behalf of joint operations
(98)(131)(124)
Net debt including leases35,188 31,902 33,079 
Total equity79,946 85,493 87,676 
Gearing including leases*30.6%27.2%27.4%

Gulf of Mexico oil spill

30 September31 December
$ million20242023
Gulf of Mexico oil spill payables and provisions(7,869)(8,735)
Of which - current(1,115)(1,133)
Deferred tax asset1,192 1,320 
During the second quarter 2024 pre-tax payments of $1,129 million were made relating to the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. Payables and provisions presented in the table above reflect the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. Where amounts have been provided on an estimated basis, the amounts ultimately payable may differ from the amounts provided and the timing of payments is uncertain. Further information relating to the Gulf of Mexico oil spill, including information on the nature and expected timing of payments relating to provisions and other payables, is provided in bp Annual Report and Form 20-F 2023 - Financial statements - Notes 7, 22, 23, 29, and 33.

29
Adjusted earnings before interest, taxation, depreciation and amortization (adjusted EBITDA)*

ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Profit for the period370 5,069 2,849 15,444 
Finance costs1,101 1,039 3,392 2,802 
Net finance (income) expense relating to pensions and other post-retirement benefits(42)(61)(123)(180)
Taxation1,028 2,240 4,436 7,206 
Profit before interest and tax2,457 8,287 10,554 25,272 
Inventory holding (gains) losses*, before tax1,182 (1,593)467 (261)
3,639 6,694 11,021 25,011 
Net (favourable) adverse impact of adjusting items*, before interest and tax1,588 (607)5,570 (4,102)
5,227 6,087 16,591 20,909 
Add back:
Depreciation, depletion and amortization4,117 4,145 12,365 11,868 
Exploration expenditure written off310 74 643 365 
Adjusted EBITDA9,654 10,306 29,599 33,142 

Reconciliation of customers & products RC profit before interest and tax to underlying RC profit before interest and tax* to adjusted EBITDA* by business

ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
RC profit before interest and tax for customers & products23 1,549 878 4,784 
Less: Adjusting items* gains (charges) (358)(506)(1,941)(826)
Underlying RC profit before interest and tax for customers & products381 2,055 2,819 5,610 
By business:
customers – convenience & mobility897 670 2,057 1,762 
Castrol – included in customers216 185 611 517 
products – refining & trading(516)1,385 762 3,848 
Add back: Depreciation, depletion and amortization963 915 2,846 2,606 
By business:
customers – convenience & mobility513 481 1,488 1,270 
Castrol – included in customers45 43 129 124 
products – refining & trading450 434 1,358 1,336 
Adjusted EBITDA for customers & products1,344 2,970 5,665 8,216 
By business:
customers – convenience & mobility1,410 1,151 3,545 3,032 
Castrol – included in customers261 228 740 641 
products – refining & trading(66)1,819 2,120 5,184 

30
Reconciliation of gas & low carbon energy and oil production & operations RC profit before interest and tax to adjusted EBITDA*

ThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
gas & low carbon energy
RC profit before interest and tax1,007 2,2751,728 11,911
Less: Net favourable (adverse) impact of adjusting items* (749)1,019 (3,088)4,966 
Underlying RC profit before interest and tax*1,756 1,256 4,816 6,945 
Add back: Depreciation, depletion and amortization1,1801,5433,6824,390
Exploration write-offs1 15 232 13 
Adjusted EBITDA2,937 2,814 8,730 11,348 
oil production & operations
RC profit before interest and tax1,8913,4278,2189,312
Less: Net favourable (adverse) impact of adjusting items(903)291 (795)80 
Underlying RC profit before interest and tax2,794 3,136 9,013 9,232 
Add back: Depreciation, depletion and amortization1,7081,4325,0634,129
Exploration write-offs309 59 411 352 
Adjusted EBITDA4,811 4,627 14,487 13,713 


Reconciliation of basic earnings per ordinary share / ADS to underlying replacement cost profit (loss) per ordinary share* / ADS*
ThirdThirdNineNine
quarterquartermonthsmonths
Per ordinary share (cents)2024202320242023
Profit (loss) for the period attributable to bp shareholders1.26 28.24 14.19 84.77 
Inventory holding (gains) losses*, before tax7.24 (9.26)2.82 (1.49)
Taxation charge (credit) on inventory holding gains and losses(1.69)2.21 (0.63)0.29 
6.81 21.19 16.38 83.57 
Net (favourable) adverse impact of adjusting items*, before tax(a)
10.08 (2.97)35.71 (21.57)
Taxation charge (credit) on adjusting items(a)
(3.00)0.92 (5.30)(0.17)
Underlying RC profit (loss)13.89 19.14 46.79 61.83 
ThirdThirdNineNine
quarterquartermonthsmonths
Per ADS (dollars)2024202320242023
Profit (loss) for the period attributable to bp shareholders0.08 1.69 0.85 5.09 
Inventory holding (gains) losses, before tax0.43 (0.56)0.17 (0.09)
Taxation charge (credit) on inventory holding gains and losses(0.10)0.14 (0.04)0.01 
0.41 1.27 0.98 5.01 
Net (favourable) adverse impact of adjusting items, before tax(a)
0.61 (0.18)2.14 (1.29)
Taxation charge (credit) on adjusting items(a)
(0.19)0.06 (0.31)(0.01)
Underlying RC profit (loss)0.83 1.15 2.81 3.71 
(a)Nine months 2024 calculated based on adjusting items and taxation credits thereon of $5,925 million and $881 million respectively, as adjusted for the gain on redemption of hybrid bonds of $13 million and taxation thereon of $3 million respectively (see Note 7).
31
Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss* and underlying ETR*
Taxation (charge) creditThirdThirdNineNine
quarterquartermonthsmonths
$ million2024202320242023
Taxation on profit or loss before taxation(1,028)(2,240)(4,436)(7,206)
Taxation on inventory holding gains and losses276 (381)105 (50)
Taxation on a replacement cost (RC) profit or loss basis(1,304)(1,859)(4,541)(7,156)
Total taxation on adjusting items491 (158)881 29 
Taxation on underlying replacement cost profit or loss(1,795)(1,701)(5,422)(7,185)
Effective tax rateThirdThirdNineNine
quarterquartermonthsmonths
%2024202320242023
ETR on profit or loss before taxation74 31 61 32 
Adjusted for inventory holding gains or losses(23)2 (2)— 
ETR on RC profit or loss51 33 59 32 
Excluding adjusting items(9)— (19)7 
Underlying ETR42 33 40 39 
32
Realizations* and marker prices
ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
Average realizations(a)
Liquids* ($/bbl)
US63.31 63.95 63.83 62.44 
Europe75.45 90.76 80.44 80.59 
Rest of World80.79 78.34 81.39 80.05 
bp average70.68 71.85 71.89 71.40 
Natural gas ($/mcf)
US1.18 2.24 1.39 2.09 
Europe12.22 11.22 10.68 17.20 
Rest of World5.80 5.38 5.57 6.11 
bp average4.75 4.88 4.61 5.66 
Total hydrocarbons* ($/boe)
US42.18 45.39 42.65 43.77 
Europe74.03 80.61 74.73 87.43 
Rest of World47.57 45.61 47.22 48.73 
bp average46.81 47.28 46.91 49.47 
Average oil marker prices ($/bbl)
Brent80.34 86.75 82.79 82.07 
West Texas Intermediate75.28 82.54 77.71 77.36 
Western Canadian Select59.98 65.42 62.22 60.72 
Alaska North Slope 78.95 87.95 82.24 81.74 
Mars74.20 82.99 77.50 76.80 
Urals (NWE – cif)70.10 73.62 70.39 58.20 
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu)
2.15 2.54 2.10 2.69 
UK Gas – National Balancing Point (p/therm)81.77 82.04 75.75 99.01 
(a)Based on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
(b)Henry Hub First of Month Index.

Exchange rates
ThirdThirdNineNine
quarterquartermonthsmonths
2024202320242023
$/£ average rate for the period1.30 1.27 1.28 1.24 
$/£ period-end rate1.34 1.22 1.34 1.22 
$/€ average rate for the period1.10 1.09 1.09 1.08 
$/€ period-end rate1.12 1.06 1.12 1.06 
$/AUD average rate for the period0.67 0.65 0.66 0.67 
$/AUD period-end rate0.69 0.64 0.69 0.64 
33
Legal proceedings
For a full discussion of the group’s material legal proceedings, see pages 242-243 of bp Annual Report and Form 20-F 2023.

Glossary
Non-IFRS measures are provided for investors because they are closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions. Non-IFRS measures are sometimes referred to as alternative performance measures.
Adjusted EBITDA is a non-IFRS measure presented for bp's operating segments and is defined as replacement cost (RC) profit before interest and tax, excluding net adjusting items* before interest and tax, and adding back depreciation, depletion and amortization and exploration write-offs (net of adjusting items). Adjusted EBITDA by business is a further analysis of adjusted EBITDA for the customers & products businesses. bp believes it is helpful to disclose adjusted EBITDA by operating segment and by business because it reflects how the segments measure underlying business delivery. The nearest equivalent measure on an IFRS basis for the segment is RC profit or loss before interest and tax, which is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS. A reconciliation to IFRS information is provided on pages 30-31 for the segments.
Adjusted EBITDA for the group is defined as profit or loss for the period, adjusting for finance costs and net finance (income) or expense relating to pensions and other post-retirement benefits and taxation, inventory holding gains or losses before tax, net adjusting items before interest and tax, and adding back depreciation, depletion and amortization (pre-tax) and exploration expenditure written-off (net of adjusting items, pre-tax). The nearest equivalent measure on an IFRS basis for the group is profit or loss for the period. A reconciliation to IFRS information is provided on page 30 for the group.
Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors to better understand and evaluate the group’s reported financial performance. Adjusting items include gains and losses on the sale of businesses and fixed assets, impairments, environmental and related provisions and charges, restructuring, integration and rationalization costs, fair value accounting effects and costs relating to the Gulf of Mexico oil spill and other items. Adjusting items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. Adjusting items are used as a reconciling adjustment to derive underlying RC profit or loss and related underlying measures which are non-IFRS measures. An analysis of adjusting items by segment and type is shown on page 28.
Blue hydrogen – Hydrogen made from natural gas in combination with carbon capture and storage (CCS).
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement. Capital expenditure for the operating segments, gas & low carbon energy businesses and customers & products businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil price 2021 real to balance bp’s sources and uses of cash assuming an average bp refining marker margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real terms.
Consolidation adjustment – UPII is unrealized profit in inventory arising on inter-segment transactions.
Developed renewables to final investment decision (FID) – Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share at the time of FID). If asset is subsequently sold bp will continue to record capacity as developed to FID.
Divestment proceeds are disposal proceeds as per the condensed group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss is a non-IFRS measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Taxation on a RC basis for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses. Information on RC profit or loss is provided below. bp believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. Taxation on a RC basis and ETR on RC profit or loss are non-IFRS measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to IFRS information is provided on page 32.
Electric vehicle charge points / EV charge points are defined as the number of connectors on a charging device, operated by either bp or a bp joint venture as adjusted to be reflective of bp’s accounting share of joint arrangements.
34
Glossary (continued)
Fair value accounting effects are non-IFRS adjustments to our IFRS profit (loss). They reflect the difference between the way bp manages the economic exposure and internally measures performance of certain activities and the way those activities are measured under IFRS. Fair value accounting effects are included within adjusting items. They relate to certain of the group's commodity, interest rate and currency risk exposures as detailed below. Other than as noted below, the fair value accounting effects described are reported in both the gas & low carbon energy and customer & products segments.
bp uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories, other than net realizable value provisions, are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity.
bp enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing, liquefied natural gas (LNG) and certain gas and power contracts that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole.
These include:
•Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period.
•Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments used to risk manage the near-term portions of the LNG contracts are fair valued under IFRS. The fair value accounting effect, which is reported in the gas and low carbon energy segment, represents the change in value of LNG contacts that are being risk managed and which is reflected in the underlying result, but not in reported earnings. Management believes that this gives a better representation of performance in each period.
Furthermore, the fair values of derivative instruments used to risk manage certain other oil, gas, power and other contracts, are deferred to match with the underlying exposure. The commodity contracts for business requirements are accounted for on an accruals basis.
In addition, fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the other businesses & corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period.
Gas & low carbon energy segment comprises our gas and low carbon businesses. Our gas business includes regions with upstream activities that predominantly produce natural gas, integrated gas and power, and gas trading. Our low carbon business includes solar, offshore and onshore wind, hydrogen and CCS and power trading. Power trading includes trading of both renewable and non-renewable power.
35
Glossary (continued)
Gearing and net debt are non-IFRS measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt does not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt is provided on page 26.
We are unable to present reconciliations of forward-looking information for net debt or gearing to finance debt and total equity, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable IFRS forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in an IFRS estimate.
Gearing including leases and net debt including leases are non-IFRS measures. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group’s lease portfolio on net debt and gearing. The nearest equivalent measures on an IFRS basis are finance debt and finance debt ratio. A reconciliation of finance debt to net debt including leases is provided on page 29.
Green hydrogen – Hydrogen produced by electrolysis of water using renewable power.
Hydrocarbons – Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Hydrogen pipeline – Hydrogen projects which have not been developed to final investment decision (FID) but which have advanced to the concept development stage.
Inorganic capital expenditure is a subset of capital expenditure on a cash basis and a non-IFRS measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in projects which expand the group’s activities through acquisition. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis. Further information and a reconciliation to IFRS information is provided on page 27.
Installed renewables capacity is bp's share of capacity for operating assets owned by entities where bp has an equity share.
Inventory holding gains and losses are non-IFRS adjustments to our IFRS profit (loss) and represent:
•the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting of inventories other than for trading inventories, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed as inventory holding gains and losses represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach; and
•an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade by grade basis, during the period. This is calculated from each operation’s inventory management system on a monthly basis using the discrete monthly movement in market prices for these inventories.
The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions that are price risk-managed. See Replacement cost (RC) profit or loss definition below.
Liquids – Liquids comprises crude oil, condensate and natural gas liquids. For the oil production & operations segment, it also includes bitumen.
Low carbon activity – An activity relating to low carbon including: renewable electricity; bioenergy; electric vehicles and other future mobility solutions; trading and marketing low carbon products; blue or green hydrogen* and carbon capture, use and storage (CCUS).
Note that, while there is some overlap of activities, these terms do not mean the same as bp’s strategic focus area of low carbon energy or our low carbon energy sub-segment, reported within the gas & low carbon energy segment.
36
Glossary (continued)
Major projects have a bp net investment of at least $250 million, or are considered to be of strategic importance to bp or of a high degree of complexity.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow statement.
Organic capital expenditure is a non-IFRS measure. Organic capital expenditure comprises capital expenditure on a cash basis less inorganic capital expenditure. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in developing and maintaining the group’s assets. The nearest equivalent measure on an IFRS basis is capital expenditure on a cash basis and a reconciliation to IFRS information is provided on page 27.
We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest IFRS estimate.
Production-sharing agreement/contract (PSA/PSC) is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the bp share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties. For the gas & low carbon energy and oil production & operations segments, realizations include transfers between businesses.
Refining availability represents Solomon Associates’ operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime.
The Refining marker margin (RMM) is the average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate.
Renewables pipeline – Renewable projects satisfying the following criteria until the point they can be considered developed to final investment decision (FID): Site based projects that have obtained land exclusivity rights, or for power purchase agreement based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted.
Replacement cost (RC) profit or loss / RC profit or loss attributable to bp shareholders reflects the replacement cost of inventories sold in the period and is calculated as profit or loss attributable to bp shareholders, adjusting for inventory holding gains and losses (net of tax). RC profit or loss for the group is not a recognized IFRS measure. bp believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to bp shareholders. A reconciliation to IFRS information is provided on page 3. RC profit or loss before interest and tax is bp's measure of profit or loss that is required to be disclosed for each operating segment under IFRS.
Reported recordable injury frequency measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. This represents reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Reported incidents are investigated throughout the year and as a result there may be changes in previously reported incidents. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this represents a more up to date reflection of the safety environment.
Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral, Thorntons and TravelCenters of America and also includes sites in India through our Jio-bp JV.
Solomon availability – See Refining availability definition.
Strategic convenience sites are retail sites, within the bp portfolio, which sell bp-supplied vehicle energy (e.g. bp, Aral, Arco, Amoco, Thorntons, bp pulse, TA and PETRO) and either carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or a differentiated bp-controlled convenience offer. To be considered a strategic convenience site, the convenience offer should have a demonstrable level of differentiation in the market in which it operates. Strategic convenience site count includes sites under a pilot phase.
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Glossary (continued)
Surplus cash flow does not represent the residual cash flow available for discretionary expenditures. It is a non-IFRS financial measure that should be considered in addition to, not as a substitute for or superior to, net cash provided by operating activities, reported in accordance with IFRS. bp believes it is helpful to disclose the surplus cash flow because this measure forms part of bp's financial frame.
Surplus cash flow refers to the net surplus of sources of cash over uses of cash, after reaching the $35 billion net debt target. Sources of cash include net cash provided by operating activities, cash provided from investing activities and cash receipts relating to transactions involving non-controlling interests. Uses of cash include lease liability payments, payments on perpetual hybrid bond, dividends paid, cash capital expenditure, the cash cost of share buybacks to offset the dilution from vesting of awards under employee share schemes, cash payments relating to transactions involving non-controlling interests and currency translation differences relating to cash and cash equivalents as presented on the condensed group cash flow statement.
Technical service contract (TSC) – Technical service contract is an arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, the oil and gas company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a profit margin which reflects incremental production added to the oilfield.
Tier 1 and tier 2 process safety events – Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Reported process safety events are investigated throughout the year and as a result there may be changes in previously reported events. Therefore comparative movements are calculated against internal data reflecting the final outcomes of such investigations, rather than the previously reported comparative period, as this represents a more up to date reflection of the safety environment.
Transition growth – Activities, represented by a set of transition growth engines, that transition bp toward its objective to be an integrated energy company, and that comprise our low carbon activity* alongside other businesses that support transition, such as our power trading and marketing business and convenience.
Underlying effective tax rate (ETR) is a non-IFRS measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis for the group is calculated as taxation as stated on the group income statement adjusted for taxation on inventory holding gains and losses and total taxation on adjusting items. Information on underlying RC profit or loss is provided below. Taxation on an underlying RC basis presented for the operating segments is calculated through an allocation of taxation on an underlying RC basis to each segment. bp believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. Taxation on an underlying RC basis and underlying ETR are non-IFRS measures. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period.
We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable IFRS forward-looking financial measure. These items include the taxation on inventory holding gains and losses and adjusting items, that are difficult to predict in advance in order to include in an IFRS estimate. A reconciliation to IFRS information is provided on page 32.
Underlying production – 2024 underlying production, when compared with 2023, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract*.
Underlying RC profit or loss / underlying RC profit or loss attributable to bp shareholders is a non-IFRS measure and is RC profit or loss* (as defined on page 37) after excluding net adjusting items and related taxation. See page 28 for additional information on the adjusting items that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the items and their financial impact.
Underlying RC profit or loss before interest and tax for the operating segments or customers & products businesses is calculated as RC profit or loss (as defined above) including profit or loss attributable to non-controlling interests before interest and tax for the operating segments and excluding net adjusting items for the respective operating segment or business.
bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period, by adjusting for the effects of these adjusting items. The nearest equivalent measure on an IFRS basis for the group is profit or loss attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments and businesses is RC profit or loss before interest and taxation. A reconciliation to IFRS information is provided on page 3 for the group and pages 8-16 for the segments.
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Glossary (continued)
Underlying RC profit or loss per share / underlying RC profit or loss per ADS is a non-IFRS measure. Earnings per share is defined in Note 7. Underlying RC profit or loss per ordinary share is calculated using the same denominator as earnings per share as defined in the consolidated financial statements. The numerator used is underlying RC profit or loss attributable to bp shareholders, rather than profit or loss attributable to bp ordinary shareholders. Underlying RC profit or loss per ADS is calculated as outlined above for underlying RC profit or loss per share except the denominator is adjusted to reflect one ADS equivalent to six ordinary shares. bp believes it is helpful to disclose the underlying RC profit or loss per ordinary share and per ADS because these measures may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp ordinary shareholders. A reconciliation to IFRS information is provided on page 31.
upstream includes oil and natural gas field development and production within the gas & low carbon energy and oil production & operations segments.
upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity, excluding non-operated assets and bpx energy. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime.
upstream unit production costs are calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities.
Trade marks
Trade marks of the bp group appear throughout this announcement. They include:
bp, Amoco, Aral, ampm, bp pulse, Castrol, PETRO, TA, Thorntons, Gigahub, epic goods and earnify
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Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement:
The discussion in this results announcement contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past events and circumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, the following, among other statements, are all forward looking in nature: plans, expectations and assumptions regarding oil and gas demand, supply, prices or volatility; expectations regarding reserves; expectations regarding production and volumes; expectations regarding bp’s customers & products business; expectations regarding margins; expectations regarding underlying effective tax rate; expectations regarding turnaround and maintenance activity; expectations regarding financial performance, results of operations, finance debt acquired in the fourth quarter, and cash flows; expectations regarding future project start-ups; expectations regarding the timing of bp’s update on its medium-term plans; expectations regarding shareholders returns; expectations regarding bp’s convenience businesses; bp’s financial guidance, including previous guidance for at least $14 billion of share buybacks through 2025; bp’s plans and expectations regarding the amount and timing of share buybacks and dividends; plans and expectations regarding bp’s credit rating, including in respect of maintaining a strong investment grade credit rating and targeting further improvements in credit metrics; plans and expectations regarding the allocation of surplus cash flow to share buybacks; plans and expectations regarding the sale of bp’s Türkiye ground fuels business; plans and expectations regarding development of bp’s electric vehicle (EV) charging infrastructure and RNG landfill plants; plans and expectations related to bp’s transition growth engines, including expected capital expenditures; plans and expectations regarding the amount or timing of payments related to divestment and other proceeds, and the timing, quantum and nature of certain acquisitions and divestments; expectations regarding the timing and amount of future payments relating to the Gulf of Mexico oil spill; expectations regarding bp’s development of hydrogen and sale of its US onshore wind energy business; plans and expectations regarding bp’s guidance for 2024 and the fourth quarter of 2024, including expected growth, margins, businesses & corporate underlying annual charge, timing and amount of divestment and other proceeds, depreciation, depletion and amortization; plans and expectations regarding capital expenditure; and plans and expectations regarding bp-operated projects, ventures, investments, joint ventures, partnerships and agreements with commercial entities and other third party partners, including but not limited to ADNOC, Audi, EOG Resources Trinidad Limited, Iberdrola, Perenco T&T, the Republic of Iraq, SOCAR, Shell Pipeline Company LP and Enbridge Offshore Facilities LC.
By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp.
Actual results or outcomes may differ materially from those expressed in such statements, depending on a variety of factors, including: the extent and duration of the impact of current market conditions including the volatility of oil prices, the effects of bp’s plan to exit its shareholding in Rosneft and other investments in Russia, overall global economic and business conditions impacting bp’s business and demand for bp’s products as well as the specific factors identified in the discussions accompanying such forward-looking statements; changes in consumer preferences and societal expectations; the pace of development and adoption of alternative energy solutions; developments in policy, law, regulation, technology and markets, including societal and investor sentiment related to the issue of climate change; the receipt of relevant third party and/or regulatory approvals including ongoing approvals required for the continued developments of approved projects; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America and continued base oil and additive supply shortages; OPEC+ quota restrictions; PSA and TSC effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately payable and timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp’s access to future credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; the possibility that international sanctions or other steps taken by governmental authorities or any other relevant persons may impact bp’s ability to sell its interests in Rosneft, or the price for which bp could sell such interests; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and those factors discussed under “Principal risks and uncertainties” in bp’s Report on Form 6-K regarding results for the six-month period ended 30 June 2024 as filed with the US Securities and Exchange Commission (the “SEC”) as well as those factors discussed under “Risk factors” in bp’s Annual Report and Form 20-F for fiscal year 2023 as filed with the SEC.
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The following table shows the unaudited consolidated capitalization and indebtedness of the BP group as of 30 September 2024:
Capitalization and indebtedness
30 September
$ million2024
Share capital and reserves
Capital shares (1-2)4,262 
Paid-in surplus (3)16,763 
Merger reserve (3)27,206 
Treasury shares(9,127)
Investments in equity instruments5 
Cash flow hedge reserve1 
Costs of hedging reserve(95)
Foreign currency translation reserve(1,644)
Profit and loss account 27,455 
BP shareholders' equity64,826 
Hybrid bonds13,516 
Other interest1,604 
Equity attributable to non-controlling interests15,120 
Total equity79,946 
Finance debt and lease liabilities (4-6)
Lease liabilities due within one year2,726 
Finance debt due within one year4,484 
Lease liabilities due after more than one year8,292 
Finance debt due after more than one year 52,986 
Total finance debt and lease liabilities68,488 
Total (7)(8)148,434 
1.Issued share capital as of 30 September 2024 comprised 16,262,632,593 ordinary shares, par value US$0.25 per share, and 12,706,252 preference shares, par value £1 per share. This excludes 717,435,379 ordinary shares which have been bought back and are held in treasury by bp. These shares are not taken into consideration in relation to the payment of dividends and voting at shareholders’ meetings.
2.Capital shares represent the ordinary and preference shares of bp which have been issued and are fully paid.
3.Paid-in surplus and merger reserve represent additional paid-in capital of bp which cannot normally be returned to shareholders.
4.Finance debt and lease liabilities recorded in currencies other than US dollars has been translated into US dollars at the relevant exchange rates existing on 30 September 2024.
5.Finance debt and lease liabilities presented in the table above consists of borrowings and obligations under leases. This includes one hundred percent of lease liabilities for joint operations where bp is the only party with the legal obligation to make lease payments to the lessor. Other contractual obligations are not presented in the table above – see BP Annual Report and Form 20-F 2023 – Liquidity and capital resources for further information.
6.At 30 September 2024, the parent company, BP p.l.c. had issued guarantees totalling $56,754 million relating to group finance debt issued by subsidiaries. Thus 99% of the group’s finance debt had been guaranteed by BP p.l.c. In addition, BP p.l.c. guarantees $11.9 billion of perpetual subordinated hybrid bonds issued by a subsidiary. At 30 September 2024, $211 million of finance debt was secured by the pledging of assets. The remainder of finance debt was unsecured.
7.At 30 September 2024, the group had issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the group balance sheet, were $1,838 million in respect of the borrowings of equity-accounted entities and $438 million in respect of the borrowings of other third parties.
8.Total capitalisation and indebtedness includes non-controlling interests of $15,120 million at 30 September 2024 which includes $12.0 billion related to perpetual hybrid bonds and $1.5 billion related to perpetual subordinated hybrid securities issued by a group subsidiary.
9.There has been no material change since 30 September 2024 in the consolidated capitalization and indebtedness of bp.
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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.


BP p.l.c.
(Registrant)


Dated: 29 October 2024/s/ BEN MATHEWS
Ben J. S. Mathews
Company Secretary
                                        

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