Note 6. Depreciation, depletion and amortization
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Total depreciation, depletion and amortization by
segment
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
1,203
|
1,255
|
1,115
|
|
2,458
|
1,969
|
oil production & operations
|
|
1,371
|
1,429
|
1,559
|
|
2,800
|
3,133
|
customers & products
|
|
715
|
717
|
754
|
|
1,432
|
1,499
|
other businesses & corporate
|
|
223
|
224
|
203
|
|
447
|
397
|
|
|
3,512
|
3,625
|
3,631
|
|
7,137
|
6,998
|
Total depreciation, depletion and amortization by geographical
area
|
|
|
|
|
|
|
|
US
|
|
1,159
|
1,083
|
1,161
|
|
2,242
|
2,282
|
Non-US
|
|
2,353
|
2,542
|
2,470
|
|
4,895
|
4,716
|
|
|
3,512
|
3,625
|
3,631
|
|
7,137
|
6,998
|
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. As part of the share buyback
programme announced on 27 April 2021, 443 million ordinary shares
were repurchased for cancellation during the second quarter 2022
for a total cost of $2,288 million. This brings the total
number of shares repurchased in the first half to 743 million for a
total cost of $3,880 million. A further 133 million ordinary
shares were repurchased in July for a total cost of $613 million.
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.
165
million new ordinary shares were issued in April 2022 as non-cash
consideration for the acquisition of the public units of BP
Midstream Partners LP.
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.
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Results for the period
|
|
|
|
|
|
|
|
Profit (loss) for the period attributable to bp
shareholders
|
|
9,257
|
(20,384)
|
3,116
|
|
(11,127)
|
7,783
|
Less: preference dividend
|
|
1
|
—
|
—
|
|
1
|
1
|
Profit (loss) attributable to bp ordinary shareholders
|
|
9,256
|
(20,384)
|
3,116
|
|
(11,128)
|
7,782
|
|
|
|
|
|
|
|
|
Number of shares (thousand)(a)(b)
|
|
|
|
|
|
|
|
Basic
weighted average number of shares outstanding
|
|
19,388,427
|
19,514,477
|
20,272,111
|
|
19,451,040
|
20,285,083
|
ADS
equivalent(c)
|
|
3,231,404
|
3,252,412
|
3,378,685
|
|
3,241,840
|
3,380,847
|
|
|
|
|
|
|
|
|
Weighted average
number of shares outstanding used to calculate diluted earnings per
share
|
|
19,619,628
|
19,514,477
|
20,366,731
|
|
19,451,040
|
20,394,877
|
ADS
equivalent(c)
|
|
3,269,938
|
3,252,412
|
3,394,455
|
|
3,241,840
|
3,399,146
|
|
|
|
|
|
|
|
|
Shares in issue at period-end
|
|
19,135,400
|
19,409,157
|
20,224,314
|
|
19,135,400
|
20,224,314
|
ADS
equivalent(c)
|
|
3,189,233
|
3,234,859
|
3,370,719
|
|
3,189,233
|
3,370,719
|
(a)
Excludes treasury
shares and includes certain shares that will be issued in the
future under employee share-based payment plans.
(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 first quarter and first half
2022 are 179,226 thousand (ADS equivalent 29,871 thousand) and
202,620 thousand (ADS equivalent 33,770 thousand)
respectively.
(c)
One ADS is
equivalent to six ordinary shares.
Top of
page 29
Note 8. Dividends
Dividends payable
BP
today announced an interim dividend of 6.006 cents per ordinary
share which is expected to be paid on 23 September 2022 to ordinary
shareholders and American Depositary Share (ADS) holders on the
register on 12 August 2022. The ex-dividend date will be 11 August
2022. The corresponding amount in sterling is due to be announced
on 6 September 2022, calculated based on the average of the market
exchange rates over three dealing days between 31 August 2022 and 2
September 2022. Holders of ADSs are expected to receive $0.36036
per ADS (less applicable fees). The board has decided not to offer
a scrip dividend alternative in respect of the second quarter 2022
dividend. Ordinary shareholders and ADS holders (subject to certain
exceptions) will be able to participate in a dividend reinvestment
programme. Details of the second quarter dividend and timetable are
available at bp.com/dividends and further details of
the dividend reinvestment programmes are available at bp.com/drip.
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Dividends paid per ordinary share
|
|
|
|
|
|
|
|
cents
|
|
5.460
|
5.460
|
5.250
|
|
10.920
|
10.500
|
pence
|
|
4.356
|
4.160
|
3.712
|
|
8.515
|
7.480
|
Dividends paid per ADS (cents)
|
|
32.76
|
32.76
|
31.50
|
|
65.52
|
63.00
|
Note 9. Net debt
Net debt*
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Finance
debt(a)
|
|
52,866
|
60,606
|
68,247
|
|
52,866
|
68,247
|
Fair
value (asset) liability of hedges related to finance
debt(b)
|
|
3,058
|
1,265
|
(1,285)
|
|
3,058
|
(1,285)
|
|
|
55,924
|
61,871
|
66,962
|
|
55,924
|
66,962
|
Less: cash and cash equivalents
|
|
33,108
|
34,414
|
34,256
|
|
33,108
|
34,256
|
Net
debt(c)
|
|
22,816
|
27,457
|
32,706
|
|
22,816
|
32,706
|
Total equity
|
|
81,563
|
78,519
|
93,232
|
|
81,563
|
93,232
|
Gearing*
|
|
21.9%
|
25.9%
|
26.0%
|
|
21.9%
|
26.0%
|
(a)
The fair value of
finance debt at 30 June 2022 was $49,056 million (31 March 2022
$59,601 million, 30 June 2021 $70,589 million).
(b)
Derivative
financial instruments entered into for the purpose of managing
interest rate and foreign currency exchange risk associated with
net debt with a fair value liability position of $246 million
at 30 June 2022 (first quarter 2022 liability of $173 million
and second quarter 2021 liability of $308 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.
As part
of actively managing its debt portfolio, in the second quarter the
group bought back $4.5 billion of finance debt (first quarter 2022
$nil, second quarter 2021 $nil) consisting entirely of US dollar
bonds. Year to date the group has bought back a total of $4.5
billion of finance debt ($3.9 billion equivalent for the
comparative period in 2021 consisting of US dollar, euro and
sterling bonds). Derivatives associated with non-US dollar debt
bought back in the comparative period were also terminated. In
addition, on 25 July 2022 the group exercised its option to redeem
finance debt with an outstanding aggregate principal amount of $2.9
billion on 24 August 2022. These transactions have no significant
impact on net debt or gearing.
Note 10. Statutory accounts
The
financial information shown in this publication, which was approved
by the Board of Directors on 1 August 2022, is unaudited and does
not constitute statutory financial statements. Audited financial
information will be published in BP Annual Report and Form 20-F 2022. BP Annual
Report and Form 20-F 2021 has been filed with the Registrar
of Companies in England and Wales. The report of the auditor on
those accounts was unqualified, did not include a reference to any
matters to which the auditor drew attention by way of emphasis
without qualifying the report and did not contain a statement under
section 498(2) or section 498(3) of the UK Companies Act
2006.
Top of
page 30
Additional information
Capital expenditure*
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Capital expenditure
|
|
|
|
|
|
|
|
Organic capital expenditure*
|
|
2,845
|
2,573
|
2,511
|
|
5,418
|
5,417
|
Inorganic
capital expenditure*(a)
|
|
(7)
|
356
|
3
|
|
349
|
895
|
|
|
2,838
|
2,929
|
2,514
|
|
5,767
|
6,312
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Capital expenditure by segment
|
|
|
|
|
|
|
|
gas
& low carbon energy(a)
|
|
823
|
861
|
747
|
|
1,684
|
2,632
|
oil production & operations
|
|
1,208
|
1,254
|
1,148
|
|
2,462
|
2,467
|
customers & products
|
|
675
|
715
|
519
|
|
1,390
|
1,051
|
other businesses & corporate
|
|
132
|
99
|
100
|
|
231
|
162
|
|
|
2,838
|
2,929
|
2,514
|
|
5,767
|
6,312
|
Capital expenditure by geographical area
|
|
|
|
|
|
|
|
US
|
|
1,253
|
1,097
|
890
|
|
2,350
|
2,377
|
Non-US
|
|
1,585
|
1,832
|
1,624
|
|
3,417
|
3,935
|
|
|
2,838
|
2,929
|
2,514
|
|
5,767
|
6,312
|
(a)
First half 2021
includes the final payment of $712 million in respect of the
strategic partnership with Equinor.
Top of
page 31
Adjusting items*
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
gas & low carbon energy
|
|
|
|
|
|
|
|
Gains
on sale of businesses and fixed assets(a)
|
|
—
|
9
|
—
|
|
9
|
1,034
|
Net
impairment and losses on sale of businesses and fixed
assets(b)
|
|
(265)
|
(252)
|
1,270
|
|
(517)
|
1,147
|
Environmental and other provisions
|
|
—
|
—
|
—
|
|
—
|
—
|
Restructuring, integration and rationalization costs
|
|
1
|
4
|
(21)
|
|
5
|
(29)
|
Fair
value accounting effects(c)(d)
|
|
(74)
|
(5,015)
|
(1,311)
|
|
(5,089)
|
(1,064)
|
Other
|
|
(5)
|
135
|
(251)
|
|
130
|
(241)
|
|
|
(343)
|
(5,119)
|
(313)
|
|
(5,462)
|
847
|
oil production & operations
|
|
|
|
|
|
|
|
Gains
on sale of businesses and fixed assets(e)
|
|
1,278
|
249
|
216
|
|
1,527
|
384
|
Net
impairment and losses on sale of businesses and fixed
assets(b)
|
|
268
|
(1,204)
|
1,751
|
|
(936)
|
1,542
|
Environmental and other provisions
|
|
(204)
|
58
|
(776)
|
|
(146)
|
(841)
|
Restructuring, integration and rationalization costs
|
|
(7)
|
(10)
|
(90)
|
|
(17)
|
(94)
|
Fair value accounting effects
|
|
—
|
—
|
—
|
|
—
|
—
|
Other
|
|
—
|
55
|
(225)
|
|
55
|
(201)
|
|
|
1,335
|
(852)
|
876
|
|
483
|
790
|
customers & products
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
31
|
261
|
8
|
|
292
|
(89)
|
Net impairment and losses on sale of businesses and fixed
assets
|
|
(434)
|
(13)
|
(35)
|
|
(447)
|
(78)
|
Environmental and other provisions
|
|
(35)
|
—
|
(8)
|
|
(35)
|
(8)
|
Restructuring, integration and rationalization costs
|
|
9
|
1
|
(10)
|
|
10
|
(51)
|
Fair
value accounting effects(d)
|
|
(62)
|
(377)
|
(139)
|
|
(439)
|
320
|
Other
|
|
16
|
(47)
|
(3)
|
|
(31)
|
(3)
|
|
|
(475)
|
(175)
|
(187)
|
|
(650)
|
91
|
other businesses &
corporate(f)
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
—
|
(1)
|
—
|
|
(1)
|
—
|
Net impairment and losses on sale of businesses and fixed
assets
|
|
(15)
|
(1)
|
(50)
|
|
(16)
|
(51)
|
Environmental and other provisions
|
|
(89)
|
(3)
|
(72)
|
|
(92)
|
(72)
|
Restructuring, integration and rationalization costs
|
|
(3)
|
13
|
(74)
|
|
10
|
(99)
|
Fair
value accounting effects(d)
|
|
(686)
|
(425)
|
73
|
|
(1,111)
|
(374)
|
Rosneft(f)
|
|
—
|
(24,033)
|
(46)
|
|
(24,033)
|
(46)
|
Gulf of Mexico oil spill
|
|
(21)
|
(19)
|
(18)
|
|
(40)
|
(29)
|
Other
|
|
(13)
|
9
|
21
|
|
(4)
|
(3)
|
|
|
(827)
|
(24,460)
|
(166)
|
|
(25,287)
|
(674)
|
Total before interest and taxation
|
|
(310)
|
(30,606)
|
210
|
|
(30,916)
|
1,054
|
Finance
costs(g)
|
|
(30)
|
(158)
|
(202)
|
|
(188)
|
(350)
|
Total before taxation
|
|
(340)
|
(30,764)
|
8
|
|
(31,104)
|
704
|
Total
taxation(h)
|
|
(461)
|
1,471
|
(426)
|
|
1,010
|
(427)
|
Total after taxation for period
|
|
(801)
|
(29,293)
|
(418)
|
|
(30,094)
|
277
|
(a)
First half 2021
relates to a gain from the divestment of a 20% stake in Oman Block
61.
(b)
See Note 3 for
further information.
(c)
Under IFRS bp
marks-to-market the derivative financial instruments used to
risk-manage LNG contracts, but does not mark-to-market the physical
LNG contracts themselves, resulting in a mismatch in accounting
treatment. The fair value accounting effect reduces this mismatch,
and the underlying result reflects how bp risk-manages its LNG
contracts.
(d)
For further
information, including the nature of fair value accounting effects
reported in each segment, see page 37.
(e)
Second quarter and
first half 2022 include gains of $904 million related to the deemed
disposal of 12% of the group's interest in Aker BP, an associate of
bp, following completion of Aker BP's acquisition of Lundin Energy,
and $361 million in relation to the disposal of the group's
interest in the Rumaila field in Iraq to Basra Energy Company, an
associate of bp.
(f)
From first quarter
2022 the results of Rosneft, previously reported as a separate
segment, are also included in other businesses & corporate.
Comparative information for 2021 has been restated to reflect the
changes in reportable segments. For more information see Note 1
Basis of preparation - Investment in Rosneft.
(g)
Includes the
unwinding of discounting effects relating to Gulf of Mexico oil
spill payables, the income statement impact associated with the
buyback of finance debt (see Note 9 for further information) and
temporary valuation differences associated with the group’s
interest rate and foreign currency exchange risk management of
finance debt.
(h)
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.
Top of
page 32
Net debt including leases
Net debt including leases*
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Net debt
|
|
22,816
|
27,457
|
32,706
|
|
22,816
|
32,706
|
Lease liabilities
|
|
8,056
|
8,466
|
8,863
|
|
8,056
|
8,863
|
Net
partner (receivable) payable for leases entered into on behalf of
joint operations
|
|
14
|
206
|
109
|
|
14
|
109
|
Net debt including leases
|
|
30,886
|
36,129
|
41,678
|
|
30,886
|
41,678
|
Total
equity
|
|
81,563
|
78,519
|
93,232
|
|
81,563
|
93,232
|
Gearing including leases*
|
|
27.5%
|
31.5%
|
30.9%
|
|
27.5%
|
30.9%
|
Gulf of Mexico oil spill
|
|
30 June
|
31 December
|
$ million
|
|
2022
|
2021
|
Gulf of Mexico oil spill payables and provisions
|
|
(9,390)
|
(10,433)
|
Of
which - current
|
|
(1,217)
|
(1,279)
|
|
|
|
|
Deferred tax asset
|
|
2,340
|
3,959
|
During
the second quarter pre-tax payments of $1,204 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 2021 - Financial
statements - Notes 6, 8, 19, 21, 22, 28, and 32.
Working capital* reconciliation
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Movements in
inventories and other current and non-current assets and
liabilities as per condensed group cash flow statement(a)
|
|
(4,416)
|
(1,771)
|
26
|
|
(6,187)
|
(2,767)
|
Adjusted for inventory holding gains (losses)* (Note 4 excluding
Rosneft)
|
|
2,146
|
3,501
|
885
|
|
5,647
|
2,527
|
Adjusted for fair value accounting effects relating to
subsidiaries
|
|
(676)
|
(5,817)
|
(1,377)
|
|
(6,493)
|
(1,118)
|
Working capital release (build) after adjusting for net inventory
gains (losses) and fair value accounting effects
|
|
(2,946)
|
(4,087)
|
(466)
|
|
(7,033)
|
(1,358)
|
(a)
The movement in
working capital includes outflows relating to the Gulf of Mexico
oil spill on a pre-tax basis of $1,209 million and
$1,256 million in the second quarter and first half of 2022
respectively. For the same periods in 2021 the amount was an
outflow of $1,204 million and $1,339 million
respectively.
Top of
page 33
Surplus cash flow* reconciliation
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Sources:
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
10,863
|
8,210
|
5,411
|
|
19,073
|
11,520
|
Cash provided from investing activities
|
|
329
|
1,046
|
282
|
|
1,375
|
4,507
|
Other
proceeds(a)
|
|
409
|
164
|
—
|
|
573
|
—
|
Receipts relating to transactions involving non-controlling
interests
|
|
—
|
7
|
3
|
|
7
|
671
|
Cash inflow
|
|
11,601
|
9,427
|
5,696
|
|
21,028
|
16,698
|
|
|
|
|
|
|
|
|
Uses:
|
|
|
|
|
|
|
|
Lease liability payments
|
|
(472)
|
(498)
|
(514)
|
|
(970)
|
(1,074)
|
Payments on perpetual hybrid bonds
|
|
(161)
|
(148)
|
(328)
|
|
(309)
|
(383)
|
Dividends paid – BP shareholders
|
|
(1,062)
|
(1,068)
|
(1,062)
|
|
(2,130)
|
(2,126)
|
–
non-controlling interests
|
|
(63)
|
(65)
|
(107)
|
|
(128)
|
(158)
|
Total capital expenditure*
|
|
(2,838)
|
(2,929)
|
(2,514)
|
|
(5,767)
|
(6,312)
|
Net repurchase of shares relating to employee share
schemes
|
|
—
|
(500)
|
(500)
|
|
(500)
|
(500)
|
Payments relating to transactions involving non-controlling
interests
|
|
(1)
|
(5)
|
—
|
|
(6)
|
—
|
Currency translation differences relating to cash and cash
equivalents
|
|
(414)
|
(125)
|
24
|
|
(539)
|
(34)
|
Cash outflow
|
|
(5,011)
|
(5,338)
|
(5,001)
|
|
(10,349)
|
(10,587)
|
|
|
|
|
|
|
|
|
Cash used to meet net debt target
|
|
—
|
—
|
—
|
|
—
|
3,729
|
|
|
|
|
|
|
|
|
Surplus cash flow
|
|
6,590
|
4,089
|
695
|
|
10,679
|
2,382
|
(a)
Other proceeds for
the second quarter and first half 2022 include $409 million and
$573 million respectively of proceeds from the disposal of a loan
note related to the Alaska divestment. The cash was received in the
fourth quarter 2021, reported as a financing cash flow and was not
included in other proceeds at the time due to potential recourse
from the counterparty. The proceeds have been recognized as the
potential recourse reduces and by end second quarter 2022 all
proceeds have been recognized.
Reconciliation of customers & products RC profit before
interest and tax to underlying RC profit before interest and tax*
to adjusted EBITDA* by business
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
$ million
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
RC profit before interest and tax for customers &
products
|
|
3,531
|
1,981
|
640
|
|
5,512
|
1,574
|
Less: Adjusting items* gains (charges)
|
|
(475)
|
(175)
|
(187)
|
|
(650)
|
91
|
Underlying RC profit before interest and tax for customers
& products
|
|
4,006
|
2,156
|
827
|
|
6,162
|
1,483
|
By business:
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
679
|
522
|
951
|
|
1,201
|
1,609
|
Castrol – included in customers
|
|
223
|
256
|
265
|
|
479
|
599
|
products
– refining & trading
|
|
3,327
|
1,634
|
(124)
|
|
4,961
|
(126)
|
|
|
|
|
|
|
|
|
Add back: Depreciation, depletion and amortization
|
|
715
|
717
|
754
|
|
1,432
|
1,499
|
By business:
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
315
|
326
|
329
|
|
641
|
653
|
Castrol – included in customers
|
|
38
|
39
|
39
|
|
77
|
78
|
products
– refining & trading
|
|
400
|
391
|
425
|
|
791
|
846
|
|
|
|
|
|
|
|
|
Adjusted EBITDA for customers & products
|
|
4,721
|
2,873
|
1,581
|
|
7,594
|
2,982
|
By business:
|
|
|
|
|
|
|
|
customers
– convenience & mobility
|
|
994
|
848
|
1,280
|
|
1,842
|
2,262
|
Castrol – included in customers
|
|
261
|
295
|
304
|
|
556
|
677
|
products
– refining & trading
|
|
3,727
|
2,025
|
301
|
|
5,752
|
720
|
Top of
page 34
Realizations* and marker prices
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
Average realizations(a)
|
|
|
|
|
|
|
|
Liquids* ($/bbl)
|
|
|
|
|
|
|
|
US
|
|
89.80
|
70.34
|
53.64
|
|
80.41
|
49.36
|
Europe
|
|
113.92
|
104.41
|
69.19
|
|
108.72
|
64.83
|
Rest of World
|
|
106.77
|
88.84
|
64.44
|
|
97.82
|
61.04
|
BP Average
|
|
100.94
|
83.80
|
60.69
|
|
92.41
|
56.91
|
Natural gas ($/mcf)
|
|
|
|
|
|
|
|
US
|
|
6.28
|
3.90
|
3.03
|
|
5.12
|
3.24
|
Europe
|
|
16.06
|
33.77
|
8.94
|
|
25.02
|
7.78
|
Rest of World
|
|
8.42
|
7.88
|
4.13
|
|
8.15
|
4.03
|
BP Average
|
|
8.31
|
8.24
|
4.08
|
|
8.28
|
4.03
|
Total hydrocarbons* ($/boe)
|
|
|
|
|
|
|
|
US
|
|
69.71
|
52.17
|
41.14
|
|
61.21
|
39.02
|
Europe
|
|
106.29
|
134.62
|
63.85
|
|
121.37
|
58.93
|
Rest of World
|
|
71.65
|
62.38
|
40.27
|
|
66.98
|
38.16
|
BP Average
|
|
73.24
|
64.70
|
41.84
|
|
68.96
|
39.77
|
Average oil marker prices ($/bbl)
|
|
|
|
|
|
|
|
Brent
|
|
113.93
|
102.23
|
68.97
|
|
107.94
|
64.98
|
West Texas Intermediate
|
|
108.77
|
95.22
|
66.19
|
|
101.99
|
62.22
|
Western Canadian Select
|
|
90.25
|
79.90
|
53.10
|
|
85.08
|
49.57
|
Alaska North Slope
|
|
112.17
|
96.13
|
68.58
|
|
104.15
|
64.89
|
Mars
|
|
105.27
|
93.43
|
66.01
|
|
99.35
|
62.39
|
Urals (NWE – cif)
|
|
77.29
|
87.26
|
66.69
|
|
82.40
|
62.96
|
Average natural gas marker prices
|
|
|
|
|
|
|
|
Henry
Hub gas price(b) ($/mmBtu)
|
|
7.17
|
4.96
|
2.83
|
|
6.06
|
2.77
|
UK Gas – National Balancing Point (p/therm)
|
|
130.11
|
232.84
|
64.79
|
|
182.73
|
57.19
|
(a)
Based on sales of
consolidated subsidiaries only – this excludes equity-accounted
entities.
(b)
Henry Hub First of
Month Index.
Exchange rates
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
2022
|
2022
|
2021
|
|
2022
|
2021
|
$/£ average rate for the period
|
|
1.26
|
1.34
|
1.40
|
|
1.30
|
1.39
|
$/£ period-end rate
|
|
1.21
|
1.32
|
1.38
|
|
1.21
|
1.38
|
|
|
|
|
|
|
|
|
$/€ average rate for the period
|
|
1.06
|
1.12
|
1.21
|
|
1.09
|
1.21
|
$/€ period-end rate
|
|
1.05
|
1.12
|
1.19
|
|
1.05
|
1.19
|
|
|
|
|
|
|
|
|
$/AUD average rate for the period
|
|
0.71
|
0.72
|
0.77
|
|
0.72
|
0.77
|
$/AUD period-end rate
|
|
0.69
|
0.75
|
0.75
|
|
0.69
|
0.75
|
|
|
|
|
|
|
|
|
Rouble/$ average rate for the period
|
|
67.50
|
88.48
|
74.20
|
|
77.95
|
74.31
|
Rouble/$ period-end rate
|
|
54.68
|
82.59
|
72.70
|
|
54.68
|
72.70
|
Top of
page 35
Principal risks and uncertainties
The
principal risks and uncertainties affecting bp are described in the
Risk factors section of bp Annual
Report and Form 20-F 2021 (pages 76-79) and are summarized
below. There are no material changes in those principal risks and
uncertainties for the remaining six months of the financial
year.
The
risks and uncertainties summarized below, separately or in
combination, could have a material adverse effect on the
implementation of our strategy, our business, financial
performance, results of operations, cash flows, liquidity,
prospects, shareholder value and returns and
reputation.
Strategic and commercial risks
●
Prices and markets – our financial
performance is impacted by fluctuating prices of oil, gas and
refined products, technological change, exchange rate fluctuations,
and the general macroeconomic outlook.
●
Accessing and progressing hydrocarbon resources
and low carbon opportunities – inability to access and
progress hydrocarbon resources and low carbon opportunities could
adversely affect delivery of our strategy.
●
Major project* delivery – failure
to invest in the best opportunities or deliver major projects
successfully could adversely affect our financial
performance.
●
Geopolitical – exposure to a range
of political developments and consequent changes to the operating
and regulatory environment could cause business
disruption.
●
Liquidity, financial capacity and financial,
including credit, exposure – failure to work within
our financial framework could impact our ability to operate and
result in financial loss.
●
Joint arrangements and contractors
– varying levels of control over the standards, operations
and compliance of our partners, contractors and sub-contractors
could result in legal liability and reputational
damage.
●
Digital infrastructure, cyber security and data
protection – breach or failure of our or third
parties’ digital infrastructure or cyber security, including
loss or misuse of sensitive information could damage our
operations, increase costs and damage our reputation.
●
Climate change and the transition to a lower
carbon economy – developments in policy, law,
regulation, technology and markets, including societal and investor
sentiment, related to the issue of climate change could increase
costs, reduce revenues, constrain our operations and affect our
business plans and financial performance.
●
Competition – inability to remain
efficient, maintain a high-quality portfolio of assets and innovate
could negatively impact delivery of our strategy in a highly
competitive market.
●
Talent and capability – inability
to attract, develop and retain people with necessary skills and
capabilities could negatively impact delivery of our
strategy.
●
Crisis management and business
continuity – failure to address an incident
effectively could potentially disrupt our business.
●
Insurance – our insurance strategy
could expose the group to material uninsured losses.
Safety and operational risks
●
Process safety, personal safety, and
environmental risks – exposure to a wide range of
health, safety, security and environmental risks could cause harm
to people, the environment and our assets and result in regulatory
action, legal liability, business interruption, increased costs,
damage to our reputation and potentially denial of our licence to
operate.
●
Drilling and production –
challenging operational environments and other uncertainties could
impact drilling and production activities.
●
Security – hostile acts against
our employees and activities could cause harm to people and disrupt
our operations.
●
Product quality – supplying
customers with off-specification products could damage our
reputation, lead to regulatory action and legal liability, and
impact our financial performance.
Compliance and control risks
●
Ethical misconduct and non-compliance
– ethical misconduct or breaches of applicable laws by our
businesses or our employees could be damaging to our reputation,
and could result in litigation, regulatory action and
penalties.
●
Regulation – changes in the law
and regulation could increase costs, constrain our operations and
affect our business plans and financial performance.
●
Trading and treasury trading activities
– ineffective oversight of trading and treasury trading
activities could lead to business disruption, financial loss,
regulatory intervention or damage to our reputation and affect our
permissions to trade.
●
Reporting – failure to accurately
report our data could lead to regulatory action, legal liability
and reputational damage.
Top of
page 36
Legal proceedings
For a
full discussion of the group’s material legal proceedings,
see pages 248-249 of bp Annual
Report and Form 20-F 2021.
Submission of resolutions passed at Annual General Meetings to the
National Storage Mechanism
In
accordance with Listing Rules 9.6.2 and 9.6.3, copies of all
resolutions passed by BP p.l.c. other than resolutions concerning
ordinary business transacted at the company's previous Annual
General Meetings have been submitted to the national storage
mechanism and are available for inspection at https://data.fca.org.uk/#/nsm/nationalstoragemechanism.
Glossary
Non-GAAP
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-GAAP
measures are sometimes referred to as alternative performance
measures.
Adjusted EBITDA is a non-GAAP measure presented for bp's
operating segments and is defined as replacement cost (RC) profit
before interest and tax, excluding net adjusting items*, 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.
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 other provisions,
restructuring, integration and rationalization costs, fair value
accounting effects, financial impacts relating to Rosneft for the
2022 financial reporting period 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-GAAP measures.
An analysis of adjusting items by segment and type is shown on page
31.
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 and customers & products
businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil
price, on average over 2021-25, 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 2020 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). If asset is subsequently sold bp will continue to record
capacity as developed to FID. If bp equity share increases
developed capacity to FID will increase proportionately to share
increase for any assets where bp held equity at the point of
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-GAAP 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-GAAP
measures. The nearest equivalent measure on an IFRS basis is the
ETR on profit or loss for the period.
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.
Top of
page 37
Glossary (continued)
Fair value accounting effects are non-GAAP 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. 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. The
fair values of derivative instruments used to risk manage certain
oil, gas, power and other contracts, are deferred to match with the
underlying exposure and the commodity contracts for business
requirements are accounted for on an accruals basis. 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.
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, reduces the measurement
differences between that of the derivative financial instruments
used to risk manage the LNG contracts and the measurement of the
LNG contracts themselves, which therefore gives a better
representation of performance in each period.
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.
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Glossary (continued)
Gearing and net debt are non-GAAP 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 GAAP measures on an IFRS basis are finance debt and
finance debt ratio. A reconciliation of finance debt to net debt is
provided on page 29.
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
GAAP 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 a GAAP estimate.
Gearing including leases and net debt including leases are
non-GAAP 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 GAAP 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
32.
Green hydrogen – Hydrogen made from solar, wind and
hydro-electricity.
Hydrocarbons –
Liquids and natural gas. Natural gas is converted to oil equivalent
at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital
expenditure on a cash basis and a non-GAAP 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 GAAP
information is provided on page 30.
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-GAAP adjustments
to our IFRS profit (loss) and represent:
a.
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
b.
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.
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.
Top of
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Glossary (continued)
Organic capital expenditure is a non-GAAP 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 GAAP information is provided on page
30.
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
GAAP 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 PPA 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 GAAP 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 GAAP
information is provided on page 1. 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 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 and Thorntons, and also includes sites in
India through our Jio-bp JV.
Retail sites in growth markets are retail sites that are
either bp branded or co-branded with our partners in China, Mexico
and Indonesia and also include 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-branded vehicle energy and carry one of
the strategic convenience brands (e.g. M&S, Thorntons, Rewe to
Go). To be considered a strategic convenience brand 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, but exclude sites in growth
markets.
Top of
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Glossary (continued)
Surplus cash flow is a non-GAAP measure and 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.
For the
first half of 2022, the sources of cash includes other proceeds
related to the proceeds from the disposal of a loan note related to
the Alaska divestment. The cash was received in the fourth quarter
2021, was reported as a financing cash flow and was not included in
other proceeds at the time due to potential recourse from the
counterparty. The proceeds are being recognized as the potential
recourse reduces. See page 33 for the components of our sources of
cash and uses of cash.
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 this represents a more up to
date reflection of the safety environment.
Underlying effective tax rate (ETR) is a non-GAAP 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-GAAP
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
GAAP 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 a
GAAP estimate.
Underlying production – 2022 underlying production,
when compared with 2021, 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-GAAP measure and is
RC profit or loss* (as defined on page 39) after excluding net
adjusting items and related taxation. See page 31 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 GAAP information is provided on page
1 for the group and pages 6-15 for the segments.
Underlying RC profit or loss per share is a non-GAAP
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 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
shareholders.
Top of
page 41
Glossary (continued)
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 cost is 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.
Working capital is movements in inventories and other
current and non-current assets and liabilities as reported in the
condensed group cash flow statement.
Change
in working capital adjusted for inventory holding gains/losses and
fair value accounting effects relating to subsidiaries is a
non-GAAP measure. It is calculated by adjusting for inventory
holding gains/losses reported in the period and from the second
quarter 2021 onwards, it is also adjusted for fair value accounting
effects relating to subsidiaries reported within adjusting items
for the period. This represents what would have been reported as
movements in inventories and other current and non-current assets
and liabilities, if the starting point in determining net cash
provided by operating activities had been underlying replacement
cost profit rather than profit for the period. The nearest
equivalent measure on an IFRS basis for this is movements in
inventories and other current and non-current assets and
liabilities. In the context of describing working capital after
adjusting for Gulf of Mexico oil spill outflows, change in working
capital also excludes movements in inventories and other current
and non-current assets and liabilities relating to the Gulf of
Mexico oil spill.
bp
utilizes various arrangements in order to manage its working
capital including discounting of receivables and, in the supply and
trading business, the active management of supplier payment terms,
inventory and collateral.
Trade marks
Trade
marks of the bp group appear throughout this announcement. They
include:
bp, Amoco,
Aral, Castrol ON and
Thorntons
Top of
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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: expectations regarding the conflict in
Ukraine and inflationary pressures, including the impacts and
consequences on demand; plans, expectations and assumptions
regarding oil and gas demand, supply, prices or volatility and
storage levels; expectations regarding major project ramp-up,
divestment and maintenance activity; expectations regarding
refining margins and product demand; expectations regarding
implementation of bp’s strategy, bp’s business,
financial performance, results of operations, cash flows,
liquidity, prospects, shareholder value and returns and reputation;
expectations regarding future hydrocarbon production and project
ramp-up; expectations regarding future project start-ups;
expectations with regards to bp’s transformation to an IEC;
expectations regarding price assumptions used in accounting
estimates; bp’s plans and expectations regarding the amount
and timing of share buybacks and quarterly and interim dividends;
plans and expectations regarding bp’s credit rating,
including in respect of maintaining a strong investment grade
credit rating; plans and expectations regarding the allocation of
surplus cash flow to share buybacks and strengthening the balance
sheet; plans and expectations regarding bp’s exit of its
shareholding in Rosneft and other investments in Russia; plans and
expectations with respect to the total depreciation, depletion and
amortization and other businesses & corporate underlying annual
charge for 2022; plans and expectations regarding investments in
the UK, including in charging infrastructure; plans and
expectations regarding the divestment programme, including the
amount and timing of proceeds; plans and expectations regarding
bp’s renewable energy and alternative energy businesses;
expectations regarding the UK government’s new levy on the
profits of UK oil and gas companies; expectations regarding the
underlying effective tax rate for 2022; expectations regarding the
timing and amount of future payments relating to the Gulf of Mexico
oil spill; expectations regarding the impact of the recent outage
at Freeport LNG; plans and expectations regarding bp’s
defined benefit pension plans; plans and expectations regarding
capital expenditure, including that capital expenditure will be
within a range of $14-15 billion in 2022; plans and expectations
regarding projects, joint ventures and other partnerships and
agreements, including partnerships and other collaborations with
Iberdrola, Eni, Korea Gas Corporation, ADNOC, Masdar, Marubeni,
HyCC, Shenzhen Huize New Energy Co. Ltd, Julius Stiglechner GmbH,
Submer, and AENA, as well as plans and expectations regarding the
operation of China’s largest fast EV charging hub, the
Herschel Expansion project in the Gulf of Mexico, the Gas Natural
Acu power plant in Brazil, the Asian Renewable Energy Hub in
Western Australia, submission of bids for offshore wind leases in
the Netherlands, the sale of its interest in the Sunrise oil sands
project, the acquisition of an interest in the Bay du Nord project,
the building of a hydrogen refuelling station at the bp truckstop
in Queensland, the development of EV charge points and the HyGreen
Teesside green hydrogen project.
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, the impact of COVID-19, 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; 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 Rosneft’s business or outlook, bp’s
ability to sell its interests in Rosneft, or the price for which bp
could sell such interests; the possibility that actions of any
competent authorities or any other relevant persons may limit
bp’s ability to sell its interests in Rosneft, or the price
for which it 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 other factors
discussed elsewhere in this report, as well as those factors
discussed under “Risk factors” in bp’s Annual
Report and Form 20-F 2021 as filed with the US Securities and
Exchange Commission.
This announcement contains inside information. The person
responsible for arranging the release of this announcement on
behalf of BP p.l.c. is Ben Mathews, Company Secretary.
Top of
page 43
Contacts
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London
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Houston
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Press Office
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David Nicholas
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Megan Baldino
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+44 (0) 7831 095541
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+1
907 529 9029
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Investor Relations
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Craig Marshall
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Graham Collins
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bp.com/investors
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+44 (0) 203 401 5592
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+1 832 753 5116
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BP
p.l.c.’s LEI Code 213800LH1BZH3D16G760
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: 2
August 2022
|
|
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/s/ Ben
J. S. Mathews
|
|
------------------------
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Ben J.
S. Mathews
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Company
Secretary
|
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