CORRESP 1 filename1.htm

Via EDGAR Transmission

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


24 January 2007


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 December 19, 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. We are responding to you within the requested ten business days from receipt of your letter on January 10, 2007. 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





We understand you would prefer to limit compliance with many of our comments to future filings. We are currently considering your request in response to prior comments 2, 11 and 15.


We acknowledge your continuing consideration of our request to respond to comments 2, 11 and 15 in our future filings. For your information, we currently expect to file our Annual Report on Form 20-F for the fiscal year ended December 31, 2006 with the Commission on or about April 4, 2007.



Annual Report and Accounts 2005


Operating Results, page 22



We note your response to comment 2 of our letter dated September 27, 2006. Your response states you propose to include a definition of unit lifting costs per boe in future filings. However, you have not proposed to include additional disclosure regarding how management uses the unit lifting costs per boe and unit operating expenditure per boe measures, the limitations of these measures and whether they are comparable to other like measures disclosed by other companies. We believe such information is helpful to investors in understanding the importance and usefulness of these measures. Please provide us with proposed disclosure that covers your responses related to these matters. In addition, your expanded disclosure should state these measures do not include the impact of depreciation and amortization costs and exploration expenses and why these expenses are excluded from the calculation of these measures.


Wherever we refer to ‘E&P lifting costs’ and ‘E&P operating expenditure’ we propose to include a footnoted reference to the ‘Definitions’ section of the Form 20-F which will contain the following definitions:


‘Unit operating expenditure per boe’ is calculated by dividing Production costs (as defined by FAS 19 and FAS 69) and royalties (Other operating costs in the Supplementary information – Oil and Gas disclosures) incurred over the period by the net production for the period. This measure does not include the impact of depreciation and amortisation costs and exploration costs as they are not considered to be costs associated with the operation of producing assets.


‘Unit lifting costs per boe’ is calculated by dividing ‘unit operating expenditure’ as defined above, excluding royalty, tariff and insurance costs incurred over the period by the net production for the period. Unit lifting costs as used in this ratio do not represent “Production (Lifting) Costs” as defined by FAS 19 and FAS 69.


In addition, where ‘E&P lifting costs’ and ‘E&P operating expenditure’ are first referred to in the Financial Review, we propose to add the following disclosure:


These ratios are used by management to monitor the overall operating efficiency over time of E&P producing assets. Unit lifting costs per boe, which excludes royalty, tariff and insurance costs, is used by management to monitor those field production costs which are directly controlled by field management, and allows investors to monitor those costs for BG Group over time although not necessarily on a comparable basis with other exploration and production companies. Unit operating expenditure per boe is used by management to monitor the total ongoing unit cost of operating producing assets, and allows investors to compare BG Group’s aggregated unit operating expenditure with that of other exploration and production companies. The usefulness of these ratios is limited because they provide only historical trend information at an aggregated level and are not necessarily a guide to future costs.




Note 23 – Provisions for Other Liabilities and Charges, page 96



We understand you have not recorded certain asset retirement obligations associated with oil and gas producing facilities for which no legal obligation associated with retirement of such facilities exists. To further our understanding, please describe the nature and location of such facilities for which no asset retirement obligation has been recorded as of December 31, 2005 and 2004. In your response, tell us to what extent you have incurred costs to retire similar production facilities in the same surrounding locations, in which no legal obligation existed during your ownership. If your historical practice implies an intent to incur retirement costs related to these production facilities, for which you have not recorded an asset retirement obligation, tell us what consideration you gave to the recognition of a liability as defined in SFAS 5 under US GAAP.


We make no provision for decommissioning obligations where we assess at the balance sheet date that BG Group has no legal or constructive obligation to incur such costs. A description of the E&P operations for which no legal or constructive decommissioning obligation arose as of December 31, 2005 and 2004 is detailed below.


In each of these locations, review at the balance sheet date concluded that BG had no legal or constructive obligation to incur decommissioning costs. Field development plans supported the view that the expected economic life of these fields and related facilities are expected to extend sufficiently beyond the term of BG’s ownership such that decommissioning costs will be borne by a third party. As regulation, local practices and our field development plans develop, we will continue to re-assess our legal and constructive responsibilities in relation to decommissioning obligations for all oil and gas operations, including those where no liability is recorded at each balance sheet date.




In 2002, BG Group acquired interests in offshore oil and gas fields in north-west of Mumbai. The Panna/Mukta fields lie approximately 95 kilometres north west of Mumbai in water depths of 45 to 70 metres. The two licence areas cover around 300,000 acres. The Tapti contract area is approximately 160 kilometres north-west of Mumbai and amounts to some 363,500 acres, comprising the South and Mid Tapti gas fields. BG is joint operator of the Panna/Mukta and Tapti fields.


The production sharing contracts for the Panna/Mukta and Tapti fields provide that the Contractors shall notify the Government upon determination by it that the estimated remaining recoverable reserves of any field net of operating costs equal two and one half times the estimated abandonment cost whereupon the Government shall, within sixty days, take control of the field and the abandonment obligation or, failing which, the Contractor may then proceed to recover the abandonment cost from the remaining production and abandon such field. The production sharing contracts for the Panna/Mukta and Tapti fields are due to expire in 2019. As at December 31, 2005 and 2004 BG expected that the Government would take control of the field, either on termination of the PSC or in the event that the remaining recoverable reserves equate to two and one half times the estimated decommissioning costs. Accordingly, we concluded that there was no present legal or constructive obligation to incur decommissioning costs in relation to these operations.






BG is currently the operator of two producing concessions, (West Delta Deep Marine (WDDM) and Rosetta) and three exploration concessions (El Burg, El Manzala and North Sidi Kerir Deep). These concessions are located offshore the Nile Delta.


The Concession Agreements state that title to all fixed and moveable assets vests in the national oil company when their total cost has been cost recovered under the Concession or, if earlier, upon the termination of the Concession.


The Concession Agreement is a law which is subordinate to the 1953 Petroleum Law and requires the parties to comply with the Petroleum Law. The 1953 Petroleum Law states that upon the termination of the Concession the Contractor shall deliver to the national oil company the area under the Concession in “good condition” with all movable and fixed properties necessary for continuing the operation of the Area.


As at December 31, 2005 and 2004, BG concluded that there are sufficient reserves for the government to operate the fields on the date of termination of the Concession and that the infrastructure installed by the Contractors will be retained by the national oil company for ongoing operations. Accordingly, BG Group did not have a present legal or constructive obligation to decommission these facilities in Egypt.




BG has been joint operator of the Karachaganak gas condensate field in north-west Kazakhstan since 1998. Since the signing of the Final Production Sharing Agreement (FPSA) a phased investment programme has resulted in the enhancement of existing facilities, construction of new gas and liquids processing and gas injection facilities and the installation of 650 kilometres of new pipeline.


The existing PSA is for a term of 40 years and is due to terminate in 2037. The productive life of the field is expected to extend for in excess of 30 years beyond that date. The Republic will own 100% of the working interest for the remainder of the field life. A legal obligation for the contractors’ decommissioning would only arise at the time the Republic elect not to retain title to the assets once such assets have been cost recovered by the contractors. As at December 31, 2005 and 2004 we concluded that because of the substantial value available to the Republic it would retain the assets beyond 2037 and accordingly BG had no present obligation to incur costs related to decommissioning.






As at December 31, 2005 and 2004:



India, Egypt and Kazakhstan were the only locations where BG conducted or had in recent history, conducted oil and gas operations where no legal or constructive obligation to decommission such facilities existed.



We had no practice or history of incurring costs to retire similar facilities in surrounding locations for which we had not recorded decommissioning obligations, neither had we acted in a manner through historic practice or otherwise that implied intent to incur such costs in the future. Accordingly, we concluded that a liability did not exist under the definitions of SFAS 5.


Note 31 – U.S. Generally Accepted Accounting Principles

i), page 112


Based on the disclosures in note 6 on page 81, we understand the loss of control of GASA and MetroGAS is due to the signing of a Master Restructuring Agreement with the other shareholders and creditors, in which the debt and equity of GASA will be restructured. We further note from your response to comment 17 of our letter dated September 27, 2006 that gain recognition from the change in ownership has been deferred under US GAAP as of December 31, 2005. Please tell us how you considered the guidance of Staff Accounting Bulletin Topic 5.H in determining if recognition of a gain on this transaction is appropriate under US GAAP.


We have considered the guidance in Staff Accounting Bulletin (SAB) Topic 5.H and concluded that it does not yet apply to the GASA and MetroGAS debt restructuring since a change in interest has not occurred. However, since new shares in GASA, a private unlisted company, will be issued in consideration of the debt cancellation, reducing the equity interests that BG holds in the subsidiaries, we will apply the provisions of SAB Topic 5.H upon the change in interest.


We continue to conclude that the gain should not be recognised. APB 18, paragraph 19 (l) prohibits losses from being reversed in relation to an investment in an entity which ceases to be equity accounted and is carried prospectively under the cost method.


In accordance with FAS 15, paragraph 6 and FAS 140, paragraph 16, we also continue to conclude that the gain should not be recognised until a debt restructuring is consummated or a liability fully extinguished.






Pursuant to the Staff’s request, we acknowledge that:


we are responsible for the adequacy and accuracy of the disclosure in our filings with the Commission;

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

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,



Ashley Almanza

Chief Financial Officer

For and on behalf of BG Group plc




U.S. Securities and Exchange Commission


Mr. Gary Newberry


Ms. Shannon Buskirk