Via EDGAR Transmission
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Ms. April Sifford
Branch Chief
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010
19th October 2006
BG Group plc
Form 20-F for the Fiscal Year Ended December 31, 2005
Forms 6-K for the Fiscal Quarters Ended March 31, 2006 and June 30, 2006
(File No. 1-9337)
Dear Ms. Sifford,
We are writing in response to your letter of September 27, 2006, containing
comments with respect to the Form 20-F Report of BG Group plc ('BG Group') for
the fiscal year ended December 31, 2005 (the 'Form 20-F') and the Forms 6-K for
the fiscal quarters ended March 31, 2006 and June 30, 2006. For your
convenience, we have repeated your comments along with our reply. Capitalised
terms used in this letter without definition are used as defined in the Form
20-F. Page references made in this letter, unless otherwise indicated, are to
pages in our Annual Report and Accounts 2005 (attached as exhibit 15.2 to the
Form 20-F).
Form 20-F for the Fiscal Year Ended December 31, 2005
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Annual Report and Accounts 2005
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Operating Results, page 22
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1. We note that your E&P group sells about 70% of its UK gas production under
various contracts that are not on a short-term basis. Tell us the nature
and terms of these contracts, and how you account for them. In particular,
address any material contract terms that have significant impact with
regard to your revenue recognition policies.
BG Group sells gas in the UK market under contracts which may be over one
year in duration. Within these contracts, volumes are generally expressed
in daily and annual contract quantities. These quantities generally must be
purchased by the counterparties within the defined timescales. The price
obtained under these contracts is set at the beginning of the contract and
is generally adjusted annually according to a pre-agreed formula.
Page 2
Revenue is recognised under all of these contracts in accordance with IAS
18 paragraph 14, in particular when the risks and rewards of ownership of
the gas have been transferred to the buyer and the amount of revenue can be
measured reliably. This happens when the counterparty takes title to the
gas and is measured based on the quantity delivered at the applicable
contract price. While there are take or pay provisions within some of these
contracts, we do not recognise revenue until the gas is physically
delivered. This is in line with our accounting policy on Revenue
Recognition, disclosed in our Principal accounting policies on page 64.
Since revenue is recognised on this objective basis (transfer of title)
revenue recognition on these contracts is straightforward and is not
affected by any other contract terms.
2. We note the disclosure "unit lifting costs per BOE" and "unit operating
expenditure per BOE". Please identify and disclose the following regarding
this information:
o The source of the data used,
Unit lifting costs per BOE are calculated by taking Production costs shown
on page 132 less insurance and tariff Costs (not separately identified),
and production shown on page 133. The calculation for 2005 was therefore:
Production costs (p132) - insurance costs - tariff Costs
--------------------------------------------------------
Total mmboe gas, oil & liquids (p133)
= (pound)332,000,000 - (pound)9,000,000 - (pound)105,000,000
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183,800,000 boe
=(pound)1.19 per boe
Unit operating expenditure per BOE can be calculated by taking Production
costs and royalties (Other operating costs) shown on page 132 and
production shown on page 133. The calculation for 2005 was therefore:
Production costs (p132) + Other operating costs (p132)
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Total mmboe gas, oil & liquids (p133)
= (pound)332,000,000 + (pound)75,000,000
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183,800,000 boe
=(pound)2.21 per boe
We provided a definition of 'Annual unit operating cost' in Definitions on
page 153.
In future filings we propose to include a definition of unit lifting costs
per boe in the same way as we currently do for unit operating costs.
o How management uses these measures,
Page 3
Management uses these ratios to monitor the overall operating efficiency of
producing assets. Unit operating expenditure per BOE is useful as an
indicator of the total unit cost of operating our producing E&P assets and
we believe that investors find this information useful since our E&P
business is essentially a commodity business. Unit lifting costs per BOE
focuses on production costs in the field and excludes tariff, insurance and
royalty costs.
o The limitations of the measures
These ratios focus on a particular group of historical costs and at a
company level they represent an average of a number of fields which may
have different cost structures. Their usefulness is therefore primarily
limited to backward-looking information at a company aggregate level.
o Whether the measures are comparable to other like measures disclosed
by other companies.
These ratios are used by management to measure performance over time and we
believe that they are useful as they allow investors to do the same. We
believe that the information we disclose about our Unit operating
expenditure is comparable with like measures disclosed by other companies.
In addition, we disclose unit lifting costs as we believe that this is also
useful to investors.
3. On a related note, tell us whether you consider these measures to be
non-GAAP measures, as defined by Item 10(e)(2) of Regulation S-K. If you do
consider them non-GAAP measures, supplementally explain why it is
appropriate to disclose it in Commission filings based on the conditions
identified in Item 10(e)(1)(ii). If it is determined that it is appropriate
to disclose the non-GAAP measures in Commission filings, provide the
disclosure required by Item 10(e)(1)(i) and Question 8 of the Frequently
Asked Questions Regarding the Use of Non-GAAP Financial Measures, which can
be located at
http://www.sec.gov/divisions/corpfin/faqs/nongaapfaq.htm.
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We do not consider the ratios unit lifting costs per BOE and unit operating
expenditure per BOE to be non-GAAP measures. We believe that they fall
within the exclusion described in Item 10(e)(4)(ii); that is they are
ratios or other statistical measures calculated using exclusively financial
measures calculated in accordance with IFRS.
Cash flow before financing, page 26
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4. We note the disclosure "cash flow before financing costs". Tell us whether
you consider this disclosure a non-GAAP measure, as defined by Item
10(e)(2) of Regulation S-K. If so, provide the disclosure required by Item
10(e)(1)(i). In addition, in your response, please describe how management
uses this measure and why you believe it is useful information to an
investor.
Cash flow before financing costs is a subtotal obtained from GAAP measures
identified in the Group's cash flow statement on page 70 and is clearly
captioned as an item which is before cash flows associated with
Page 4
the Group's financing. As such, we do not believe it is a non-GAAP
measure. It was used to provide a tabular presentation of the cash flows
discussed in the narrative in the Financial Review. In this narrative
section, the cash flows associated with financing are clearly identified.
Cash flow before financing provides investors with information on the cash
flows available for dividends, interest payments, share repurchases and
debt servicing, which we believe they find useful.
Principal Accounting Policies
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Revenue Recognition, page 64
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5. Disclose your revenue recognition policies for gas sales under long-term
contracts discussed on page 22, as required by International Accounting
Standard (IAS) Number 18, paragraph 35.
Our principal accounting policy for revenue recognition on page 64 states
that 'revenue associated with exploration and production sales (of crude
oil and petroleum products) is recorded when title passes to the customer.'
Petroleum products include natural gas and this policy therefore covers gas
sales. As noted in response to Question 1 above, revenue in respect of gas
sold under long-term contractual arrangements is recognised when title to
the gas passes to the customer. It should be noted that the stage of
completion method of revenue recognition referred to in IAS 18 paragraph 35
is not applied to these arrangements. As such, we consider that the
accounting policy set out on page 64 adequately discloses the revenue
recognition policy for such sales.
Exploration Expenditure, page 64
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6. You have disclosed your policy with regard to impairment testing is
performed at the cash generating unit level under IFRS. Tell us if any
difference in impairment amounts recognized under IFRS resulted from this
analysis performed at the cash generating unit level as compared to the
grouping of long lived assets to be held and used under U.S. GAAP,
specifically Statement of Financial Accounting Standards (SFAS) 144,
paragraphs 10 through 14. If impairments recognized under these standards
differ, please expand and revise the disclosures in your footnote 21
discussion of U.S. Generally Accepted Accounting Principles (GAAP) to
address them. In your response, please also identify any reversals of prior
impairment amounts that have been recognized in the financial statements
presented under IFRS.
While there are differences in the level at which impairment on exploration
expenditure is assessed under IFRS and US GAAP, these differences did not
result in any difference in amounts recognised for impairment under IFRS
and US GAAP. No impairments were recognised in respect of exploration
assets under either IFRS or US GAAP.
No reversals of prior impairment amounts were recognised in the financial
statements prepared under IFRS.
Commodity Instruments (from January 1, 2005), page 65
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Page 5
7. We note certain gas contracts and related derivative instruments associated
with the purchase and re-sale of third-party gas are presented on a net
basis in the financial statements. Please provide an example of such
arrangements and how they are accounted for under IFRS. In addition, please
tell us if or how these arrangements differ from buy-sell arrangements
under US GAAP and the differences, if any, in accounting for such
arrangements under the guidance of EITF 04-13.
Gas contracts for the purchase and re-sale of third-party gas are presented
on a net basis in the financial statements. An example of such an
arrangement is the forward sale of gas, whereby gas is bought on the
short-term market and re-sold within a day, week or month.
Under the provisions of IAS 39 paragraphs 5 and 9 and FAS 133 paragraphs 6
and 9 such transactions meet the definition of a derivative instrument.
Prior to the physical receipt or delivery of the gas these contracts are
recorded on the balance sheet at fair value with subsequent movements in
fair value recorded within "Other operating income". The profit or loss
realised on the physical purchase and sale of the third party gas is
presented net within "Other operating income".
EITF 04-13 considers buy-sell arrangements as transactions for the purchase
and sale of inventory entered into concurrently, or in contemplation of one
another, with the same counterparty. The third-party gas purchase and
re-sale activities undertaken by BG Group are primarily executed through
brokers and there is no contemplation of the counterparty used.
Accordingly, these arrangements are not buy-sell arrangements under US
GAAP. We also note that arrangements for the purchase and sale of inventory
that are accounted for as derivatives under FAS 133 are excluded from the
scope of EITF 04-13.
As part of our 20-F filing for 2005 we considered the impact of EITF 04-13
and concluded that the Consensus had no impact on our current accounting
practice (see US Generally Accepted Accounting Principles - New US GAAP
Standards, page 115).
Note 2 - Segmental Analysis and Results Presentation, page 71
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8. We note your disclosure of "Business Performance" on a segment basis and
discussion of such presentation on a segment basis to provide readers with
a more clear and consistent understanding of your performance under
requirements of IAS 14. However, we also note you have disclosed and
discussed this measure throughout your filing, outside of the disclosure
requirements of IAS 14, on a consolidated basis. Please note we believe the
presentation of business performance on a consolidated basis is subject to
the provisions of Item 10(e) of Regulation S-K. We refer you to Question 21
of the Frequently Asked Questions Regarding the Use of Non-GAAP Financial
Measures issued on June 13, 2003 for further guidance. It remains unclear
whether the disclosure of business performance on a consolidated basis is
permissible under Item 10(e)(ii). Supplementally tell us why you believe
the presentation of this non-GAAP financial measure meets the provisions of
Item 10(e) and identify where you have provided the required disclosures
within the filing. In your response please address the items discussed in
Questions 8 and 9 of the Frequently Asked
Page 6
Questions Regarding the Use of Non-GAAP Financial Measures issued on June
13, 2003.
As part of our 20-F filing for 2005, we considered the disclosure of
Business Performance on a consolidated basis and concluded that it was
subject to the provisions of Item 10(e) of Regulation S-K.
We consider the disclosure of Business Performance on a consolidated basis
to be permissible under Item 10 (e)(1) (ii) and can be assessed against the
criteria set out in that section as follows:
Sub paragraph (A) prohibits registrants from excluding charges or
liabilities that require, or will require, cash settlement absent an
ability to settle in another manner, from a non-GAAP liquidity measure. We
believe that this does not prevent the presentation of Business Performance
since it is not a liquidity measure.
Sub paragraph (B) does not allow registrants to 'adjust a non-GAAP
performance measure to eliminate or smooth items identified as
non-recurring, infrequent or unusual, when the nature of the charge or gain
is such that it is reasonably likely to recur within two years or there was
a similar charge or gain within the prior two years.' We do not describe
Business Performance as excluding non-recurring items and recognise that
disposals and re-measurement gains and losses could be considered as
recurring.
Furthermore, we note that the answer to Question 8 from the Frequently
Asked Questions states that there is no per se prohibition against removing
a recurring item, whilst recognising that companies must meet the burden of
explaining the usefulness of any such measure. We consider that a full
explanation of the usefulness of Business Performance is provided on Page
152 of the filing. Our discussion on page 152 describes what is excluded
from Business Performance and the substantive reasons why management
believes exclusion of these items provides investors with a clear and
consistent presentation of the underlying operating performance of the
Group's ongoing business and the underlying economic substance behind that
belief. In particular, we note on page 152 that the use of Business
Performance best reflects the underlying performance of the business since
it distinguishes between the temporary timing differences associated with
re-measurements under IAS 39 rules and actual realised gains and losses. In
addition, it allows separate disclosure of gains and losses associated with
the disposal of non-current assets and impairments of non-current assets to
provide a clearer understanding of the results for the period. We also
explain why the exclusion of disposals provides a 'clearer understanding of
the results for the period.'
The measures discussed and disclosed throughout the filing are also
consistent with the way we present the underlying performance of the
business in our quarterly earnings releases. As well as being useful to
investors, we know that analysts also find this measure helpful since we
provide more rather than less disclosure by disaggregating and separately
explaining these components of the income statement.
Page 7
Business Performance is also one of the primary measures used by management
in its management of the Group.
As Business Performance is not used on the face of the annual financial
statements or another note to the annual financial statements other than
Note 2 'Segmental Analysis and Results Presentation' we do not consider its
presentation to contravene the requirements of sub paragraph (C). We
believe that Business Performance on a consolidated basis is permissible
within the context of segmental reporting as we have presented it in Note
2, on the basis that the consolidated segment profit or loss measure is
presented to meet the reconciliation requirements within segmental
reporting, as clarified in Question 21 of the Frequently Asked Questions.
Nor do we consider the presentation of Business Performance to be
prohibited by either sub paragraph (D) or (E) as it is presented neither in
the context of Pro forma financial information nor is it either titled or
described in a way which could cause it to be confused with a GAAP
financial measure.
In recognition of the use of a non-GAAP measure, we believe we have
provided the information required by Regulation S-K 10(e)(1)(i). A
reconciliation to GAAP has been provided in Note 2. Equal prominence has
also been given to both GAAP and non-GAAP measures in the 2005 highlights
under clearly labeled captions shown on the inside front cover and the
profit for the year table shown in the Financial Review on page 24. As
explained above, a detailed explanation for management's reasons for, and
the underlying economic substance behind, using the non-GAAP measures is
set out on page 152. Furthermore, note references on each of the pages
where these non-GAAP measures appear direct the reader to the quantitative
reconciliations to GAAP and qualitative explanations of these measures.
9. Please explain why the geographic areas identified in your segmental
analysis presented in Note 2 differ from the geographic areas reported in
the supplemental information regarding proved reserves on page 128. In your
response, please also address why you have combined Egypt with the Atlantic
Basin geographic area.
Paragraph 31 of IAS 14 describes how geographic segments should be selected
for external reporting. In particular, it states that the segments should
be those organisational units for which information is provided to the
board of directors and to the chief executive officer for the purpose of
evaluating the unit's past performance and for making decisions about
future allocations of resources. The geographic segments disclosed in Note
2 are in line with this guidance.
For the purposes of additional reporting of E&P activities only,
disclosures were made, as required, in accordance with FAS 69. Paragraph 12
of FAS 69 requires reserves of oil and gas to be separately disclosed for
an enterprise's home country and each foreign geographic area in which
significant reserves are located. FAS 69 states: 'Foreign geographic areas
are individual countries or groups of countries as appropriate for
meaningful disclosure in the circumstances.'
Page 8
Accordingly, we identified the UK (the Group's home country) as one of the
reportable geographic areas. In addition, we selected foreign geographic
areas disclosed in the supplementary information which grouped reserves to
reflect the nature of markets for BG Group's proved gas and oil reserves in
these countries. In particular, a large proportion of the gas reserves
located in Egypt is used to supply the Atlantic Basin market via our LNG
projects in Egypt.
Additional disclosure on the reasons for the geographic presentation
adopted for reserves was provided in Form 20-F for 2004, as an introductory
paragraph to the Supplementary information and is included below for
information.
'BG Group's strategy aims to connect competitively priced gas to high value
markets. Hydrocarbon reserves, and gas in particular, are developed in
relation to the markets which they are intended to supply. Based on the
above, the information below is disclosed on the basis of the following
geographic areas: (i) the United Kingdom, (ii) Atlantic Basin, (iii) Asia
and the Middle East, and (iv) Rest of the World. The countries in the
Atlantic Basin and Asia and the Middle East geographic areas are grouped to
reflect the nature of markets for BG Group's proved gas and oil reserves in
those countries.
The allocation of the countries within these areas is:
Atlantic Basin - Canada, Egypt, Trinidad and USA
Asia and the Middle East - India, Kazakhstan, Thailand, Israel and the
Areas of Palestinian Authority
Rest of the World - Bolivia, Brazil, Italy, Mauritania, Norway, Spain,
Tunisia and Venezuela.'
Note 12 - Other Intangible Assets, page 86
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10. We note you have recorded (pound)340 m in unproved oil and gas reserve
expenditures during fiscal year 2004 that relates to the acquisition of a
subsidiary. Please expand your disclosures to describe the nature of this
amount or tell us where such disclosure is currently located within the
document.
IFRS 3 paragraph 66 requires disclosures of business combinations that were
effected during the period or between the balance sheet date and the
approval of the financial statements to enable users to evaluate the nature
and financial effect of these business combinations. Accordingly, no
information in respect of 2004 acquisitions was included in our 2005 20-F.
We provided more detail on the nature of the assets acquired through the
acquisition of subsidiaries in the 20-F filing in 2004. Note 14 of these
Financial Statements provided the required disclosures under FRS 6
paragraphs 21 to 35 (UK GAAP). An extract from the 2004 20-F is attached as
Appendix 1 for ease of reference.
The fair values of the assets and liabilities acquired were restated on
adoption of IFRS in 2005. Details of these restatements were provided in
Note 33 (page 119) of the 2005 Financial Statements.
11. We note the use of the term "backfill". Define what this term means.
Page 9
BG Group's business includes a number of long term contractual commitments
requiring multiphase developments over the period of the commitments. The
term "backfill" is used on three occasions in Note 12, as follows:
- Rosetta Backfill to existing gas sales agreement
- Buzzard N. Terrace (UK) Backfill to existing development
- Palo Marcado (Bolivia) Planned backfill to existing gas sales
agreement
Long-term sales or infrastructure agreements often require phased
development to optimise use of the contractual arrangement. Hence, where
the commitments can be met currently from existing fields, the development
of discovered fields is deferred until existing sources decline and sales
contract or infrastructure capacity becomes available.
The term "backfill" is used to describe reserves that will refill or
replace existing resources or capacity, or satisfy existing commitments.
Gas produced from Rosetta and Palo Marcado will be used to meet existing
gas sales contractual commitments when the current gas source depletes. For
Buzzard N. Terrace, the hydrocarbons produced from the future development
will utilise infrastructure capacity which will become available as
existing sources decline.
Although we believe this term is generally understood, we propose to
include a definition of backfill in future filings.
12. Please reconcile the amounts reported in the roll forward of activity in
other intangible assets during fiscal years 2005 and 2004 with the gross
exploration expenditures presented at the bottom of the table on page 22.
The main reconciling item in 2005 and 2004 between the roll forward of
activity in other intangible assets and the gross exploration expenditures
reported on page 22 relates to the exploration spend on the North Caspian
PSA disposal group in Kazakhstan.
During 2003, BG Group announced its agreement to sell its interest in the
North Caspian PSA with the disposal being completed in April 2005. During
2004 and 2005 the disposal group was classified as held for sale and
accounted for in accordance with IFRS 5. Exploration expenditures
capitalised against the disposal group of (pound)60 million in 2005 and
(pound)150 million in 2004 were recorded on the balance sheet within
"Assets classified as held for sale" and not "Other intangible assets". The
expenditures were however included in the gross exploration measure
included in the table on page 22. We included reference to the treatment of
these exploration costs in footnote (a) to the Capital Investment table on
page 25 and footnote (b) to the Costs Incurred in Gas and Oil activities
table on page 131.
There was an additional reconciling item in 2004 which related to the
acquisition of a further 40% interest in the Rosetta gas field in Egypt.
The "Other intangible assets" roll forward includes (pound)4 million in
relation to intangible assets acquired; we do not classify acquired
exploration assets as exploration expenditure and hence this amount is not
included in the gross exploration measure presented on page 22.
Page 10
The tables below show the reconciliation of capitalised exploration
reported in the roll forward of "Other intangible assets" on page 86 to the
gross exploration measure presented on page 22.
OTHER INTANGIBLE ASSETS page 86
(extract) Expenditure on unproved gas
and oil reserves
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2005 2004
(pound)m (pound)m
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Cost as at 1 January 519 158
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Additions 165 116
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Acquisition of subsidiary undertakings - 340
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Disposals and transfers (212) (92)
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Currency translation adjustments 60 (3)
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Cost and net book value as at 31 December 532 519
===========================================================================
RECONCILIATION TO GROSS EXPLORATION EXPENDITURE
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Other intangible additions (as above) 165 116
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Add: Exploration expenditure on North
Caspian PSA disposal group classified 60 150
as held for sale
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Less: Intangible assets acquired on
Rosetta field not classified as an - (4)
exploration expenditure
===========================================================================
Capitalised exploration expenditure 225 262
(page 22)
===========================================================================
Other exploration expenditure expensed to 111 74
profit/loss
===========================================================================
Gross exploration expenditure (page 22) 336 336
===========================================================================
Note 23 - Provisions for Other Liabilities and Charges, page 96
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13. Tell us why you have not recorded any new charges in decommissioning costs
during fiscal years 2005 and 2004. We would expect new decommissioning
obligations to be incurred as new activity is performed each year. For
example, as new wells are drilled or other exploration and development
activity is performed. In addition, in your response, please tell us how
you have accounted for the decommissioning costs associated with MetroGAS
upon deconsolidation of its financial results. We may have further comment
after reviewing your response.
We operate under various contractual arrangements and legal frameworks in a
number of countries. Decommissioning obligations, whether legal or
constructive, do not arise in a number of our material operations.
When new obligations arise as a result of new wells or other facilities in
operations where a legal or constructive obligation arises these are
Page 11
treated as adjustments to the existing provision for that field or
facility. Where an obligation arises for a new field, this is reported as
an addition to provisions and is disclosed separately, where material. In
2005 such additions amounted to (pound)5m (2004: (pound)5m), and were
combined with "transfers and other adjustments".
We made no provision for decommissioning costs associated with MetroGAS
because BG Group had no present obligation (legal or constructive) to incur
such costs. Such obligation is a pre-condition for making a provision under
IAS 37, paragraph 14. Similarly, FAS 143, paragraph 2 states that the
provisions it contains relate specifically to legal and constructive
obligations associated with the retirement of a tangible long-lived asset.
Note 27 - Commitments and Contingencies
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F - Legal Proceedings, page 100
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14. Please expand your disclosure of the dispute between First Gas Power
Corporation and Siemens to provide the information required by IAS 37,
paragraphs 84-89, with regard to the suspension of liquidating damages to
which Siemens is entitled.
As at 31 December 2005, the principal point at issue, namely FGPC's claim
for (pound)62 million of liquidated damages, had already been decided in
FGPC's favour as noted in the disclosure. In addition, the tribunal had
already awarded Siemens certain extensions of time which would have
entitled them to the suspension of FGPC's claim for liquidated damages had
those extensions of time exceeded a specified number of days. However, the
extensions of time awarded to Siemens were not sufficient to prevent FGPC
from being awarded its liquidated damages claim in full. Accordingly,
Siemens only claim at that point was for the costs associated with the
extensions of time that were granted. That issue, together with FGPC's
counterclaim for defective works, was finally resolved when the tribunal
issued its final award on 21 April 2006. In that award, Siemens was awarded
(pound)5 million in respect of the costs associated with the delays for
which they were granted extensions of time and FGPC was awarded (pound)6
million in respect of its counterclaim. Subsequently, the parties have
agreed that Siemens will pay FGPC (pound)6 million in full and final
settlement of all outstanding claims, including FGPC's costs.
Given the status of this dispute at 31 December 2005, it was not a matter
that was required to be disclosed pursuant to Item 8.A.7 of Form 20-F. This
voluntary disclosure was therefore made simply by way of an update to the
disclosure made in BG Group's 2004 20-F.
Turning to the information required by IAS 37, no provisions were
recognised at the balance sheet date in respect of this dispute. As such
the requirements of paragraph's 84 and 85 are not applicable.
Paragraph 86 of IAS 37 requires that, unless the possibility of any outflow
in settlement is remote, the following is disclosed for contingent
liabilities:
(a) an estimate of its financial effect, measured under paragraphs 36-52;
Page 12
(b) an indication of the uncertainties relating to the amount or timing of
any outflow; and
(c) the possibility of any reimbursement.
Where an inflow of economic benefits is probable, paragraph 89 further
requires a brief description of the nature of the contingent assets at the
balance sheet date, and where practicable an estimate of their financial
effect.
Given the status of this dispute as at 31 December 2005, we assessed the
possibility of any outflow in respect of this matter as being remote.
Accordingly, we believe that the disclosures given on page 100 satisfied
the requirements of IAS 37 within the context of the overall uncertainty of
a tribunal ruling.
Although this dispute has now been resolved, we intend to provide a further
update in the 2006 Annual Report and Accounts which will describe how this
matter was finally resolved.
Note 30 - Notes to the Consolidated Cash Flow Statement, page 107
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15. IAS 7, paragraphs 18 and 20 state cash flows from operating activities
reported using the indirect method should be presented by adjusting profit
or loss. Tell us why you believe your starting point of "Operating profit
before share of results from joint ventures and associates" meets this
requirement.
We believe that since profit or loss is not defined within IAS 7 this
allows preparers a certain amount of flexibility around the starting point
of the cash flow statement. Our starting point of "Operating profit before
share of results from joint ventures and associates" was selected as this
reduces the number of items to be adjusted for to arrive at operating cash
flow. It is also clearly identified on the face of the income statement.
With 2005 being the year of first time adoption of IFRS in Europe, many
companies have had to interpret and apply IFRSs concurrently with the
emergence of what constitutes common practice. As a result we note there
have been differing interpretations of IAS 7 among first time adopters. It
now appears a common interpretation of profit or loss in the context of IAS
7 which has emerged following the first full year of IFRS is "Profit before
tax" and we intend to use this as the starting point for the cash flow
statement in our future filings.
Note 31 - U.S. Generally Accepted Accounting Principles
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g), page 111
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16. With regard to liquidating damages, tell us what specific IAS standard you
are relying upon to justify this accounting treatment.
In considering the appropriate accounting treatment for liquidated damages
under IFRS, we had regard to the following accounting standards:
o IAS 18 paragraph 7 defines revenue as the gross inflow of
economic benefits during the period arising in the ordinary
course
Page 13
of business when those inflows result in increases in equity,
other than increases relating to contributions from equity
participants.
o IAS 16 paragraphs 65 and 66 indicate that any payments of
compensation received from third parties in respect of
impairments or losses of property, plant and equipment are
separate economic events and should be included in determining
profit or loss when they become receivable.
The liquidated damages received by BG Group represent contractual
compensation from a third party for a loss of operating revenue suffered by
the Group. In accordance with the above standards, once we were satisfied
that these amounts could be reliably measured and that it was probable that
the economic benefit would be received; the amounts were recognised as
revenue.
i), page 112
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17. We note that the gain on the deconsolidation of MetroGAS will not be
recognized for U.S. GAAP until all conditions precedent to the
restructuring plan are resolved. Tell us what U.S. accounting standard you
are relying on as the basis for this treatment. We may have further
comment.
We performed a detailed review of applicable guidance before arriving at
our conclusion on the appropriate US GAAP treatment of the gain on
deconsolidation recognised under IFRS. The conclusion took account of a
number of standards.
FAS 94, paragraph 15(d) amends APB Opinion 18 to clarify that the
limitations it contains on the application of consolidation accounting
should also be applied as limitations to the use of the equity method. GASA
and MetroGAS were therefore accounted for using the cost method at 31
December 2005, pending final regulatory approval of the restructuring. APB
18, paragraph 19(l) prohibits losses on an investment in an entity which
ceases to be equity accounted and is carried prospectively under the cost
method from being reversed. In practice, the same treatment is applied to
subsidiaries which are deconsolidated. We therefore concluded that the gain
recognised on deconsolidation under IFRS could not be recognised in income
under US GAAP as at 31 December 2005.
We noted also that both FAS 15, paragraph 6 and FAS 140, paragraph 16
contain similar requirements in respect of gains from troubled debt
restructurings and extinguishment of financial liabilities, respectively,
namely that a gain should not be recognised until a debt restructuring is
consummated or a liability fully extinguished by completion of all
precedent requirements.
Based on the above considerations, we concluded that it would not be in
accordance with US GAAP to recognise the gain in income whilst regulatory
approval was outstanding and it was therefore deferred as a single item
within current liabilities at 31 December 2005.
*****
Page 14
Pursuant to the Staff's request, we acknowledge that:
o we are responsible for the adequacy and accuracy of the disclosure in
our filings with the Commission;
o Staff comments or changes to disclosure in response to Staff comments
do not foreclose the Commission from taking any action with respect to
our filings; and
o we may not assert Staff comments as a defense in any proceeding
initiated by the Commission or any person under the federal securities
laws of the United States.
We understand that the Division of Enforcement has access to all information
provided to the Staff of the Division of Corporation Finance in their review of
our filing or in response to the Staff's comments on our filing.
Please do not hesitate to call our Chris O'Shea with respect to this response on
+44 118 929 3633 or Pamela Gibson of Shearman & Sterling LLP on +44 20 7655
5006.
Yours sincerely,
/s/ Ashley Almanza
Ashley Almanza
Chief Financial Officer
For and on behalf of BG Group plc
cc: U.S. Securities and Exchange Commission
Mr. Gary Newberry
Ms. Shannon Buskirk
Page 15
Appendix 1
Extract from BG Group's 2004 20-F (additional information in respect of
question 10)
14 ACQUISITION OF SUBSIDIARY UNDERTAKINGS
The acquisition of BG Canada Exploration and Production, Inc. (formerly El Paso
Oil and Gas Canada, Inc.), which was completed for cash consideration on 24
March 2004, was accounted for under the acquisition method. Details of the
acquisition balance sheet are as follows:
Book Fair value Fair value
value revaluation at acquisition
(pound)m (pound)m (pound)m
- ------------------------------------------------------------------------------------------------------------------
Fixed assets
- ------------------------------------------------------------------------------------------------------------------
Intangible assets(a) - 74 74
- ------------------------------------------------------------------------------------------------------------------
Tangible assets 214 (132) 82
- ------------------------------------------------------------------------------------------------------------------
Current assets
- ------------------------------------------------------------------------------------------------------------------
Stocks 1 - 1
- ------------------------------------------------------------------------------------------------------------------
Debtors: amounts falling due within one year 15 - 15
- ------------------------------------------------------------------------------------------------------------------
Debtors: amounts falling due after more than one year 22 3 25
- ------------------------------------------------------------------------------------------------------------------
Cash at bank and in hand 10 - 10
- ------------------------------------------------------------------------------------------------------------------
Creditors: amounts falling due within one year (17) - (17)
- ------------------------------------------------------------------------------------------------------------------
Provisions for liabilities and charges (1) - (1)
==================================================================================================================
Net assets 244 (55) 189
==================================================================================================================
Fair value of consideration - - 189
==================================================================================================================
The adjustments relate primarily to the revaluation of exploration and
production fixed assets to fair value.
The losses of BG Canada Exploration and Production, Inc., prior to the date of
acquisition were as follows:
1 Jan to Year ended
24 Mar 2004 31 Dec 2003
(pound)m (pound)m
- ------------------------------------------------------------------------------------------------------------------
Loss after taxation (2) (43)
==================================================================================================================
If BG Canada Exploration and Production, Inc. had been acquired at the beginning
of the year, it is estimated that BG Group's consolidated profit on ordinary
activities before taxation would not have been materially different.
In addition, BG Group acquired Mauritania Holdings BV on 31 March 2004, Aventura
Energy, Inc. on 5 May 2004 and other minor entities. All were for cash
consideration, except for (pound)3m relating to Mauritania which was deferred
consideration. These were accounted for under the acquisition method. Details of
the combined balance sheets are as follows:
Book Fair value Fair value
value revaluation at acquisition
(pound)m (pound)m (pound)m
- ------------------------------------------------------------------------------------------------------------------
Fixed assets
- ------------------------------------------------------------------------------------------------------------------
Intangible assets(a) 43 116 159
- ------------------------------------------------------------------------------------------------------------------
Tangible assets 26 (16) 10
- ------------------------------------------------------------------------------------------------------------------
Current assets
- ------------------------------------------------------------------------------------------------------------------
Debtors: amounts falling due within one year 2 - 2
- ------------------------------------------------------------------------------------------------------------------
Cash at bank and in hand 2 - 2
- ------------------------------------------------------------------------------------------------------------------
Creditors: amounts falling due within one year (1) - (1)
- ------------------------------------------------------------------------------------------------------------------
Provisions for liabilities and charges (5) 4 (1)
==================================================================================================================
Net assets 67 104 171
==================================================================================================================
Fair value of consideration - - 171
==================================================================================================================
The adjustments relate primarily to the revaluation of exploration and
production fixed assets to fair value.
The losses of the combined entities prior to the date of acquisition were as
follows:
Since Year ended
1 Jan 2004 31 Dec 2003
(pound)m (pound)m
- ------------------------------------------------------------------------------------------------------------------
Loss after taxation (1) -
==================================================================================================================
If the combined entities had been acquired at the beginning of the year, it is
estimated that BG Group's consolidated profit on ordinary activities before
taxation would not have been materially different.
(a) Intangible assets comprise expenditure on unproved gas and oil reserves.