REG - BP PLC - 4Q17 part 1 of 1 <Origin Href="QuoteRef">BP.L</Origin> - Part 4
06/02/2018 07:05
- Part 4: For the preceding part double click ID:nRSF9787Dc
fair value accounting effects (151) (174) (344) 27 (637)
Replacement cost profit before
interest and tax 1,928 1,242 692 5,221 574
Downstream
Replacement cost profit before interest and
tax adjusted for fair value accounting effects 1,856 2,283 800 7,356 5,610
Impact of fair value accounting effects (83) (108) 99 (135) (448)
Replacement cost profit before interest and tax 1,773 2,175 899 7,221 5,162
Total group
Profit (loss) before interest and tax adjusted for
fair value accounting effects 2,090 3,803 1,346 9,582 655
Impact of fair value accounting effects (234) (282) (245) (108) (1,085)
Profit (loss) before interest and tax 1,856 3,521 1,101 9,474 (430)
Top of page 27
BP p.l.c. Group results
Fourth quarter and full year 2017
Readily marketable inventory* (RMI)
31 December 31 December
$ million 2017 2016
RMI at fair value* 5,661 5,952
Paid-up RMI* 2,688 2,705
Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP's integrated supply
and trading function (IST) which could be sold to generate funds if required. Paid-up RMI is RMI that BP has paid for.
We believe that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better
understand and evaluate the group's inventories and liquidity position by enabling them to see the level of discretionary
inventory held by IST and to see builds or releases of liquid trading inventory.
See the Glossary on page 30 for a more detailed definition of RMI. RMI, RMI at fair value, paid-up RMI and unpaid RMI are
non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided
below.
31 December 31 December
$ million 2017 2016
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet 19,011 17,655
Less: (a) inventories which are not oil and oil products and (b) oil and oil
product inventories which are not risk-managed by IST (13,929) (12,131)
RMI on an IFRS basis 5,082 5,524
Plus: difference between RMI at fair value and RMI on an IFRS basis 579 428
RMI at fair value 5,661 5,952
Less: unpaid RMI* at fair value (2,973) (3,247)
Paid-up RMI 2,688 2,705
Top of page 28
BP p.l.c. Group results
Fourth and full year 2017
Realizations* and marker prices
Fourth Third Fourth
quarter quarter quarter Year Year
2017 2017 2016 2017 2016
Average realizations(a)
Liquids* ($/bbl)
US 51.50 43.58 41.93 46.55 36.25
Europe 57.92 50.02 45.66 52.13 40.53
Rest of World(b) 59.09 49.54 45.27 51.83 39.29
BP Average(b) 56.16 47.45 43.89 49.92 38.27
Natural gas ($/mcf)
US 2.28 2.34 2.29 2.36 1.90
Europe 5.56 5.10 4.81 5.09 4.40
Rest of World 3.51 3.03 3.35 3.45 3.19
BP Average 3.23 2.89 3.08 3.19 2.84
Total hydrocarbons* ($/boe)
US 35.75 31.30 30.32 33.47 25.76
Europe 52.17 45.26 40.48 46.09 36.31
Rest of World(b) 37.27 33.13 30.98 35.44 28.62
BP Average(b) 37.48 33.23 31.40 35.38 28.24
Average oil marker prices ($/bbl)
Brent 61.26 52.08 49.33 54.19 43.73
West Texas Intermediate 55.23 48.18 49.23 50.79 43.34
Western Canadian Select 38.74 38.16 35.44 38.55 30.78
Alaska North Slope 61.31 52.04 50.06 54.43 43.67
Mars 57.70 48.46 46.23 50.65 40.14
Urals (NWE - cif) 60.17 50.73 47.73 52.84 41.68
Average natural gas marker prices
Henry Hub gas price(c) ($/mmBtu) 2.93 2.99 2.98 3.11 2.46
UK Gas - National Balancing Point (p/therm) 51.94 41.59 45.76 44.95 34.63
(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b) Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to fourth quarter and full year 2016. There is no impact on the financial results.
(c) Henry Hub First of Month Index.
Exchange rates
Fourth Third Fourth
quarter quarter quarter Year Year
2017 2017 2016 2017 2016
$/£ average rate for the period 1.33 1.31 1.24 1.29 1.35
$/£ period-end rate 1.34 1.34 1.22 1.34 1.22
$/E average rate for the period 1.18 1.17 1.08 1.13 1.11
$/E period-end rate 1.19 1.18 1.05 1.19 1.05
Rouble/$ average rate for the period 58.46 58.99 63.12 58.36 67.06
Rouble/$ period-end rate 57.60 57.94 60.63 57.60 60.63
Top of page 29
BP p.l.c. Group results
Fourth quarter and full year 2017
Legal proceedings
The following discussion sets out the material developments in the group's material legal proceedings during the fourth
quarter. For a full discussion of the group's material legal proceedings, see pages 261-265 of BP Annual Report and Form
20-F 2016, and page 35 of BP p.l.c. Group results second quarter and half year 2017.
Matters relating to the Deepwater Horizon accident and oil spill (the Incident)
Plaintiffs' Steering Committee (PSC) settlements - Economic and Property Damages Settlement Agreement The Economic and
Property Damages Settlement established a court-supervised settlement programme (CSSP) to resolve certain economic and
property damage claims arising from the Incident.
Following numerous court decisions, on 31 March 2015, the United States district court in New Orleans denied the PSC motion
seeking to alter or amend a revised policy relating to business economic loss claims. Such policy required the matching of
revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded
at different times. The PSC appealed the district court decision and, on 22 May 2017, the Fifth Circuit issued an opinion
upholding the policy in part and reversing the policy in part. The Fifth Circuit ordered that the portion of the policy
upheld, which covers the substantial majority of the remaining business economic loss claims, be applied as the governing
methodology for all applicable business economic loss claims. BP filed a petition for a rehearing which was denied on 21
June 2017. In May to July 2017, the district court issued a series of orders instructing the CSSP on how to implement the
Fifth Circuit's opinion. On 10 August 2017, the district court denied BP's motion to clarify or reconsider these orders. BP
appealed all of these orders and decisions on 8 September 2017; the appeals have been consolidated with four appeals filed
by claimants in early to mid-September 2017 challenging the same set of orders and decisions, albeit raising different
issues than are raised by BP's appeal. These appeals are currently pending before the Fifth Circuit.
As a result of significantly higher average claims determinations issued by the CSSP in the period and the continuing
effect of the May 2017 Fifth Circuit opinion, the provision for the costs associated with the 2012 PSC settlement was
increased in the fourth quarter of 2017. The amounts ultimately payable may differ from the amount provided and the timing
of payments is uncertain. See Note 2 on page 17 for further details.
Other civil complaints Following numerous court decisions, on 11 January 2018, the United States district court in New
Orleans issued an order requiring all remaining private plaintiffs with economic loss or property damage claims outside of
the CSSP to file by 11 April 2018 a verified sworn statement regarding the actual damages each such plaintiff seeks in its
pending litigation and an explanation of how those alleged damages were causally related to the Incident.
Non-US government lawsuits On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa filed two class actions
(which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BP
Exploration & Production Inc., BP America Production Company (BPAPC), and other purported BP subsidiaries. In these class
actions, plaintiffs seek an order requiring the BP defendants to repair the damage to the Gulf of Mexico, to pay penalties,
and to compensate plaintiffs for damage to property, to health and for economic loss. BP was formally served with the
action on 8 December 2017.
Other legal proceedings
California False Claims Act matters On 4 November 2014, the California Attorney General filed a notice in California state
court that it was intervening in a previously-sealed California False Claims Act (CFCA) lawsuit filed by relator
Christopher Schroen against BP, BP Energy Company, BP Corporation North America Inc., BP Products and BPAPC. On 7 January
2015, the California Attorney General filed a complaint in intervention alleging that BP violated the CFCA and the
California Unfair Competition Law by falsely and fraudulently overcharging California state entities for natural gas and
making similar allegations in addition to individual claims. In January 2018 the parties reached a settlement pursuant to
which BP, while denying liability, agreed to pay $102 million to the state of California.
Top of page 30
BP p.l.c. Group results
Fourth quarter and full year 2017
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.
Adjusted effective tax rate (ETR) is a non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an
underlying RC basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC
basis for the period adjusted for taxation on non-operating items and fair value accounting effects. For the 2016
calculation, taxation on an underlying RC basis also reflects an adjustment to eliminate a $434-million credit that arises
from the reduction in the rate of the North Sea supplementary charge in the third quarter of 2016. Information on
underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted 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. The nearest equivalent measure on an IFRS basis is the ETR on profit
or loss for the period.
BP-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided
by installed production capacity. 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
weather related downtime.
Capital expenditure is total cash capital expenditure as stated in the condensed group cash flow statement.
Consolidation adjustment - UPII is unrealized profit in inventory arising on inter-segment transactions.
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.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. The nearest
equivalent measure on an IFRS basis is the ETR on profit or loss for the period.
Fair value accounting effects are non-GAAP adjustments to our IFRS profit (loss) relating to certain physical inventories,
pipelines and storage capacity. Management uses a fair-value basis to value these items which, under IFRS, are accounted
for on an accruals basis with the exception of trading inventories, which are valued using spot prices. The adjustments
have the effect of aligning the valuation basis of the physical positions with that of any associated derivative
instruments, which are required to be fair valued under IFRS, in order to provide a more representative view of the
ultimate economic value. Further information is provided on page 26.
Gearing - See Net debt and net debt ratio definition.
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 and is 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. Further information
and a reconciliation to GAAP information is provided on page 24.
Inventory holding gains and losses 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, 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 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. 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. See Replacement cost (RC) profit or loss definition
below.
Liquids - Liquids for Upstream and Rosneft comprises crude oil, condensate and natural gas liquids. For Upstream, liquids
also includes bitumen.
Top of page 31
BP p.l.c. Group results
Fourth quarter and full year 2017
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.
Net debt and net debt ratio are non-GAAP measures. Net debt is calculated as gross 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.
The net debt ratio is defined as the ratio of net debt to the total of net debt plus shareholders' equity. All components
of equity are included in the denominator of the calculation. BP believes these measures provide useful information to
investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash
equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from
shareholders. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'. The
nearest equivalent GAAP measures on an IFRS basis are gross debt and gross debt ratio. A reconciliation of gross debt to
net debt is provided on page 23.
Net wind generation capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial
operation, including BP's share of equity-accounted entities. The gross data is the equivalent capacity on a gross-JV
basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership.
Non-operating items are charges and credits included in the financial statements that BP discloses separately because it
considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be
part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the
group's reported financial performance. Non-operating items within equity-accounted earnings are reported net of
incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by region is shown on
pages 7, 9 and 11, and by segment and type is shown on page 25.
Operating cash flow is net cash provided by (used in) operating activities as stated in the condensed group cash flow
statement. When used in the context of a segment rather than the group, the terms refer to the segment's share thereof.
Operating cash flow excluding amounts related to the Gulf of Mexico oil spill / Gulf of Mexico oil spill payments or
Underlying operating cash flow is a non-GAAP measure calculated by excluding post-tax operating cash flows relating to the
Gulf of Mexico oil spill as reported in Note 2 from Net cash provided by operating activities as reported in the condensed
group cash flow statement. BP believes it is helpful to disclose net cash provided by operating activities excluding
amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis is Net cash provided by operating activities.
Operating cash margin is operating cash flow divided by the applicable number of barrels of oil equivalent produced, at
$52/bbl flat oil prices. Expected operating cash margins are calculated over the period 2016-2025.
Organic balance and organic cash balance are non-GAAP terms that refer to the point BP's organic sources of cash equal
organic uses of cash. Organic sources of cash and organic uses of cash are referred to as organic cash flows which is also
a non-GAAP measure. Organic sources of cash is the sum of operating cash flow, excluding amounts related to the Gulf of
Mexico oil spill, and proceeds of loan repayments. Organic uses of cash is organic capital expenditure plus dividends. BP
believes that the organic balance point is useful for investors because it is closely tracked by management to evaluate
BP's financial 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 nearest equivalent measure on an IFRS basis for organic
sources of cash is net cash provided by operating activities and the nearest equivalent measures on an IFRS basis for
organic uses of cash are total cash capital expenditure and dividends paid - BP shareholders.
Organic capital expenditure is a subset of capital expenditure and is a non-GAAP measure. Organic capital expenditure
comprises capital expenditure 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. An
analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page
24.
Production-sharing agreement (PSA) / Production-sharing contract is an arrangement through which an oil 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.
Top of page 32
BP p.l.c. Group results
Fourth quarter and full year 2017
Glossary (continued)
Readily marketable inventory (RMI) is inventory held and price risk-managed by our integrated supply and trading function
(IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are
available and excludes inventory which is required to meet operational requirements and other inventory which is not price
risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and
marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out
(FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been
paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided
on page 27.
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.
Refining availability represents Solomon Associates' operational availability, 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.
Replacement cost (RC) profit or loss reflects the replacement cost of inventories sold in the period and is arrived at by
excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that
is required to be disclosed for each operating segment under IFRS. 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.
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. RC profit or loss per share is
calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than
profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share
because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful
comparisons between reporting periods. 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.
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.
Reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery,
and extensions and discoveries.
Return on average capital employed (ROACE) is a non-GAAP measure and is underlying replacement cost profit, after adding
back non-controlling interest and interest expense net of notional tax at an assumed 35%, divided by average capital
employed, excluding cash and cash equivalents and goodwill. Interest expense is finance cost excluding the unwinding of the
discount on provisions and other payables, and for full year 2017 interest expense was $1,421 million before tax. BP
believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency.
The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP
shareholders and average capital employed respectively.
Tier 1 process safety events are losses of primary containment from a process of greatest consequence - causing harm to a
member of the workforce, costly damage to equipment or exceeding defined quantities. 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.
Top of page 33
BP p.l.c. Group results
Fourth quarter and full year 2017
Glossary (continued)
Underlying production is production after adjusting for divestments and entitlement impacts in our production-sharing
agreements. 2017 underlying production does not include the Abu Dhabi onshore concession renewal.
Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items and fair value accounting
effects. Underlying RC profit or loss and adjustments for fair value accounting effects are not recognized GAAP measures.
See pages 25 and 26 for additional information on the non-operating items and fair value accounting effects that are used
to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact.
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 non-operating items and fair
value accounting effects. 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 is RC profit or loss before interest and
taxation. Underlying profit in the headline on page 1 refers to full year underlying RC profit for the group.
Underlying RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 6. Underlying RC profit
or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable
to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the
underlying RC profit or loss per share 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. 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.
Upstream operating efficiency is calculated as production for BP-operated sites, excluding US Lower 48 and adjusted for
certain items including entitlement impacts in our production-sharing agreements divided by installed production capacity
for BP-operated sites, excluding US Lower 48. Installed production capacity is the agreed rate achievable (measured at the
export end of the system) when the installed production system (reservoir, wells, plant and export) is fully optimized and
operated at full rate with no planned or unplanned deferrals.
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.
Top of page 34
BP p.l.c. Group results
Fourth quarter and full year 2017
Cautionary statement
In order to utilize the 'safe harbor' provisions of the United States Private Securities Litigation Reform Act of 1995 (the
'PSLRA'), 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 - 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 expected quarterly dividend payment and timing of such payment; plans
and expectations regarding cash flows and returns to 2021 and beyond; expectations regarding 2018 organic capital
expenditure and depreciation, depletion and amortization charges; plans and expectations with respect to gearing including
to target gearing within a 20-30% band; plans and expectations to target a net debt ratio of 20-30%; expectations regarding
divestment transactions and the amount and timing of divestment proceeds; expectations regarding the adjusted effective tax
rate in 2018; plans and expectations regarding the continuation of the share buyback programme; expectations regarding
Upstream 2018 underlying production and first-quarter 2018 reported production; expectations regarding Downstream
first-quarter 2018 refining margins, turnaround activity and discounts for North American heavy crude oil; expectations
regarding Other businesses and corporate 2018 average quarterly charges; expectations with respect to cash margins of 2016
and 2017 Upstream project start-ups; plans and expectations regarding the joint development agreement with Rosneft with
respect to subsoil resources within the Kharampurskoe and Festivalnoye licence areas; plans and expectations regarding the
joint ventures with Shandong Dongming Petrochemical Group; plans and expectations regarding the strategic partnership with
Lightsource; expectations regarding the determination of business economic loss claims in respect of the 2012 PSC
settlement; and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil
spill including 2012 PSC settlement payments. 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 may differ materially from those expressed in such statements, depending on a variety of factors,
including: the specific factors identified in the discussions accompanying such forward-looking statements; 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 divestments; future levels of industry product supply, demand and pricing, including supply growth in
North America; OPEC quota restrictions; PSA 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; 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; our access to future credit
resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance
with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft's management and board of
directors; 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, under "Principal risks and uncertainties" in our Form 6-K for the period ended 30 June 2017 and
under "Risk factors" in BP Annual Report and Form 20-F 2016 as filed with the US Securities and Exchange Commission.
This document contains references to non-proved resources and production outlooks based on non-proved resources that the
SEC's rules prohibit us from including in our filings with the SEC. U.S. investors are urged to consider closely the
disclosures in our Form 20-F, SEC File No. 1-06262. This form is available on our website at www.bp.com. You can also
obtain this form from the SEC by calling 1-800-SEC-0330 or by logging on to their website at www.sec.gov.
Contacts
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