REG - BP PLC - 2Q17 Part 1 of 1 <Origin Href="QuoteRef">BP.L</Origin> - Part 4
01/08/2017 07:06
- Part 4: For the preceding part double click ID:nRSA6610Mc
2017 2016
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet 16,449 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 (12,310) (12,131)
RMI on an IFRS basis 4,139 5,524
Plus: difference between RMI at fair value and RMI on an IFRS basis 248 428
RMI at fair value 4,387 5,952
Less: unpaid RMI* at fair value (1,917) (3,247)
Paid-up RMI 2,470 2,705
Top of page 30
BP p.l.c. Group results
Second quarter and half year 2017
Realizations* and marker prices
Second First Second First First
quarter quarter quarter half half
2017 2017 2016 2017 2016
Average realizations(a)
Liquids* ($/bbl)
US 44.65 46.34 34.89 45.51 31.82
Europe 47.79 53.28 43.62 50.50 37.46
Rest of World(b) 47.11 51.79 42.36 49.46 35.60
BP Average(b) 46.27 49.87 39.68 48.09 34.44
Natural gas ($/mcf)
US 2.32 2.50 1.53 2.41 1.55
Europe 4.48 5.40 4.64 4.93 4.46
Rest of World 3.47 3.85 3.10 3.64 3.21
BP Average 3.19 3.50 2.66 3.34 2.75
Total hydrocarbons* ($/boe)
US 32.46 34.29 24.00 33.39 22.38
Europe 41.10 46.69 39.25 43.84 34.28
Rest of World(b) 33.48 37.93 30.03 35.64 27.20
BP Average(b) 33.59 37.19 28.66 35.37 26.16
Average oil marker prices ($/bbl)
Brent 49.64 53.69 45.59 51.71 39.81
West Texas Intermediate 48.11 51.70 45.53 49.89 39.64
Western Canadian Select 38.55 38.77 33.78 38.66 28.09
Alaska North Slope 50.61 53.82 45.74 52.20 40.00
Mars 46.92 49.59 42.08 48.24 36.25
Urals (NWE - cif) 48.48 51.88 43.37 50.22 37.56
Average natural gas marker prices
Henry Hub gas price(c) ($/mmBtu) 3.19 3.32 1.95 3.25 2.02
UK Gas - National Balancing Point (p/therm) 37.83 48.19 31.37 43.14 30.90
(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 second quarter and first half 2016. There is no impact on the financial results.
(c) Henry Hub First of Month Index.
Exchange rates
Second First Second First First
quarter quarter quarter half half
2017 2017 2016 2017 2016
$/£ average rate for the period 1.28 1.24 1.43 1.26 1.43
$/£ period-end rate 1.30 1.25 1.34 1.30 1.34
$/E average rate for the period 1.10 1.07 1.13 1.08 1.12
$/E period-end rate 1.14 1.07 1.11 1.14 1.11
Rouble/$ average rate for the period 57.24 58.72 65.86 57.98 70.35
Rouble/$ period-end rate 59.05 56.01 63.64 59.05 63.64
Top of page 31
BP p.l.c. Group results
Second quarter and half year 2017
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 2016 (pages 49-50) and are summarized below. There are no material changes in those risk factors for the remaining six
months of the financial year.
The risks 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 subject to fluctuating prices of oil, gas, refined products,
technological change, exchange rate fluctuations, and the general macroeconomic outlook.
· Access, renewal and reserves progression - our inability to access, renew and progress upstream resources in a
timely manner could adversely affect our long-term replacement of reserves.
· Major project* delivery - failure to invest in the best opportunities or deliver major projects successfully could
adversely affect our financial performance.
· Geopolitical - we are exposed to a range of political developments and consequent changes to the operating and
regulatory environment.
· 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 - we may have limited control over the standards, operations and compliance of
our partners, contractors and sub-contractors.
· Digital infrastructure and cybersecurity - breach of our digital security or failure of our digital infrastructure
could damage our operations and our reputation.
· Climate change and carbon pricing - public policies could increase costs and reduce future revenue and strategic
growth opportunities.
· Competition - inability to remain efficient, innovate and retain an appropriately skilled workforce could negatively
impact delivery of our strategy in a highly competitive market.
· Crisis management and business continuity - potential disruption to our business and operations could occur if we do
not address an incident effectively.
· Insurance - our insurance strategy could expose the group to material uninsured losses.
Safety and operational risks
· Process safety, personal safety, and environmental risks - we are exposed to a wide range of health, safety,
security and environmental risks that could result in regulatory action, legal liability, increased costs, damage to our
reputation and potentially denial of our licence to operate.
· Drilling and production - challenging operational environments and other uncertainties can impact drilling and
production activities.
· Security - hostile acts against our staff 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 potentially impact our financial performance.
Compliance and control risks
· US government settlements - failure to comply with the terms of our settlements with legal and regulatory bodies in
the US announced in November 2012 in respect of certain charges related to the Gulf of Mexico oil spill may expose us to
further penalties or liabilities or could result in suspension or debarment of certain BP entities.
· Regulation - changes in the regulatory and legislative environment could increase the cost of compliance, affect our
provisions and limit our access to new exploration opportunities.
· 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.
· Treasury and trading activities - ineffective oversight of treasury and trading activities could lead to business
disruption, financial loss, regulatory intervention or damage to our reputation.
· Reporting - failure to accurately report our data could lead to regulatory action, legal liability and reputational
damage.
Top of page 32
BP p.l.c. Group results
Second quarter and half 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 excluding the impact of the reduction in the rate of the UK North Sea supplementary charge in the third
quarter 2016 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. 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.
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 28.
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 26.
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.
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.
Top of page 33
BP p.l.c. Group results
Second quarter and half year 2017
Glossary (continued)
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'.
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 27.
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
Organic 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.
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
26.
Production-sharing agreement (PSA) 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.
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, Paid-up RMI and Unpaid RMI are non-GAAP measures. Further information is provided on page 29.
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.
Top of page 34
BP p.l.c. Group results
Second quarter and half year 2017
Glossary (continued)
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.
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.
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 27 and 28 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 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 35
BP p.l.c. Group results
Second quarter and half year 2017
Legal proceedings
The following discussion sets out the material developments in the group's material legal proceedings during the first half
of 2017. For a full discussion of the group's material legal proceedings, see pages 261-265 of BP Annual Report and Form
20-F 2016.
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 claims programme 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. On 5 July 2017, the district court issued an order instructing the court supervised settlement programme on how
to implement the Fifth Circuit's opinion. BP continues to evaluate the impact of the Fifth Circuit's decision on
undetermined business economic loss claims, and claims under appeal within the programme, and is considering its next steps
in relation to this order. See Note 2 on page 19 for further information.
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, among other statements, expectations regarding the
expected quarterly dividend payment and timing of such payment; expectations regarding 2017 net debt, organic capital
expenditure and divestment proceeds; expectations regarding the adjusted effective tax rate in 2017; expectations regarding
Upstream third-quarter 2017 reported production; expectations regarding Downstream third-quarter 2017 refining margins and
North American heavy crude oil differentials; plans and expectations with respect to the start-up of new Upstream projects;
expectations with respect to new Upstream production through 2020; expectations regarding Rosneft operational and financial
information for the first half of 2017; expectations with respect to the timing and amount of future payments relating to
the Gulf of Mexico oil spill; and expectations that claims arising under the 2012 PSC settlement will be substantially paid
by the end of 2018; are all forward looking in nature. 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; 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 and under "Risk factors" in BP Annual Report and Form 20-F 2016 as filed with
the US Securities and Exchange Commission.
Contacts
London Houston
Press Office David Nicholas Brett Clanton
+44 (0)20 7496 4708 +1 281 366 8346
Investor Relations Jessica Mitchell Brian Sullivan
bp.com/investors +44 (0)20 7496 4962 +1 281 892 3421
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