REG - BP PLC - 4Q16 Part 1 of 1 <Origin Href="QuoteRef">BP.L</Origin> - Part 3
07/02/2017 07:06
- Part 3: For the preceding part double click ID:nRSG1699Wb
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 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. In addition,
derivative instruments are used to manage the price risk associated with certain future natural gas sales. Gains and losses
arising are recognized in the income statement from the time the derivative commodity contract is entered into.
IFRS requires 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 storage capacity, oil and gas processing and liquefied natural gas (LNG) that,
under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments,
which 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
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 certain derivative instruments used to risk manage LNG and oil and gas prices 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. The impacts of fair value
accounting effects, relative to management's internal measure of performance, are shown in the table above. A
reconciliation to GAAP information is set out below.
Fourth Third Fourth
quarter quarter quarter Year Year
2015 2016 2016 $ million 2016 2015
Upstream
Replacement cost profit (loss) before interest and
(2,367) 1,241 1,036 tax adjusted for fair value accounting effects 1,211 (1,042)
87 (45) (344) Impact of fair value accounting effects (637) 105
(2,280) 1,196 692 Replacement cost profit before interest and tax 574 (937)
Downstream
Replacement cost profit before interest and
670 1,235 800 tax adjusted for fair value accounting effects 5,610 6,955
168 (257) 99 Impact of fair value accounting effects (448) 156
838 978 899 Replacement cost profit before interest and tax 5,162 7,111
Total group
Profit (loss) before interest and tax adjusted for
(3,898) 2,112 1,346 fair value accounting effects 655 (8,179)
255 (302) (245) Impact of fair value accounting effects (1,085) 261
(3,643) 1,810 1,101 Profit (loss) before interest and tax (430) (7,918)
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Additional information (continued)
Realizations and marker prices
Fourth Third Fourth
quarter quarter quarter Year Year
2015 2016 2016 2016 2015
Average realizations(a)
Liquids* ($/bbl)
37.42 39.16 41.93 US 36.25 44.94
40.49 42.87 45.66 Europe 40.53 49.71
39.62 41.92 45.27 Rest of World(b) 39.29 48.52
38.91 40.99 43.89 BP Average(b) 38.27 47.32
Natural gas ($/mcf)
1.71 2.19 2.29 US 1.90 2.10
6.08 3.94 4.81 Europe 4.40 7.27
4.00 2.98 3.35 Rest of World 3.19 4.25
3.47 2.77 3.08 BP Average 2.84 3.80
Total hydrocarbons* ($/boe)
26.70 27.71 30.32 US 25.76 31.80
39.03 37.10 40.48 Europe 36.31 47.64
31.09 29.24 30.98 Rest of World(b) 28.62 35.74
30.34 29.37 31.40 BP Average(b) 28.24 35.46
Average oil marker prices ($/bbl)
43.76 45.86 49.33 Brent 43.73 52.39
42.07 44.88 49.23 West Texas Intermediate 43.34 48.71
29.11 31.60 35.44 Western Canadian Select 30.78 36.83
43.62 44.65 50.06 Alaska North Slope 43.67 52.44
38.79 41.83 46.23 Mars 40.14 48.19
41.42 43.73 47.73 Urals (NWE - cif) 41.68 50.97
Average natural gas marker prices
2.27 2.81 2.98 Henry Hub gas price ($/mmBtu)(c) 2.46 2.67
36.64 31.00 45.76 UK Gas - National Balancing Point (p/therm) 34.63 42.61
(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. The comparative data for prior periods has been restated. 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
2015 2016 2016 2016 2015
1.52 1.31 1.24 $/£ average rate for the period 1.35 1.53
1.48 1.30 1.22 $/£ period-end rate 1.22 1.48
1.09 1.12 1.08 $/E average rate for the period 1.11 1.11
1.09 1.12 1.05 $/E period-end rate 1.05 1.09
65.88 64.60 63.12 Rouble/$ average rate for the period 67.06 61.25
73.17 63.14 60.63 Rouble/$ period-end rate 60.63 73.17
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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 reductions in the rate of the UK North Sea supplementary charge (in the third
quarter 2016 and the first quarter 2015) 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 on an accruals basis is a non-GAAP measure. It comprises additions to property, plant and equipment,
intangible assets and investments in joint ventures and associates, and reflects consideration payable in business
combinations. It does not include additions arising from asset exchanges and certain other non-cash items. The nearest
equivalent measure on an IFRS basis for the group is Additions to non-current assets. BP believes that Capital expenditure
on an accruals basis provides useful information for investors as it is the measure used by management to plan and
prioritize the group's investment of its resources and allows investors to understand how the group balances funds between
shareholder distributions and investment for the future. Further information and a reconciliation to GAAP information is
provided on page 23.
Consolidation adjustment - UPII is unrealized profit in inventory arising on inter-segment transactions.
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 25.
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 an accruals basis, 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 an accruals 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 23.
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.
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Glossary (continued)
Net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill 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.
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 5, 7 and 9, and by segment and type is shown on page 24.
Organic capital expenditure is a subset of Capital expenditure on an accruals basis, and is a non-GAAP measure. Organic
capital expenditure comprises capital expenditure on an accruals 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. An analysis of organic capital expenditure by segment and region, and a
reconciliation to GAAP information is provided on page 23.
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.
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.
Top of page 29
Glossary (continued)
RC profit or loss per share is a non-GAAP measure. Earnings per share is defined in Note 7. 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.
Reserves replacement ratio is the extent to which the year's production has been replaced by proved reserves added to our
reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved
recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and
disposals.
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 24 and 25 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 7. 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.
Top of page 30
Legal proceedings
For a full discussion of the group's material legal proceedings, see pages 237-242 of BP Annual Report and Form 20-F 2015,
pages 33 to 34 of BP p.l.c. Group results - Second quarter and half year 2016 and page 31 of BP p.l.c. Group results -
Third quarter and nine months 2016.
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 organic capital expenditure,
divestment proceeds, adjusted effective tax rate and depreciation, depletion and amortization charges; expectations
regarding Upstream 2017 underlying production and first-quarter 2017 reported production, Downstream first-quarter 2017
refining margins and turnaround activity and Other businesses and corporate 2017 average quarterly charges; expectations
with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill; and statements that
claims arising under the 2012 PSC settlement are expected to be substantially paid in 2017; 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 ofterrorism; cyber-attacks or sabotage; and other factors discussed
under "Principal risks and uncertainties" in our Form 6-K for the period ended 30 June 2016 and under "Risk factors" in BP
Annual Report and Form 20-F 2015 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 Craig Marshall
bp.com/investors +44 (0)20 7496 4962 +1 281 892 4312
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