03.04.08 LNG Projects DB

Europe UKOil & Gas

8 April 2003

BG Group PlcReuters: BG.L Bloomberg: BG/ LN Exchange: L Ticker: BG.L

LNG: projects intonumbers

Caroline Cook(44)131 240 [email protected]

Al Stanton+44 131 240 [email protected]

Paul Sankey(44)131 240 [email protected]

Deutsche Bank AG

DISCLOSURES AND ANALYST CERTIFICATIONS ARE LOCATED AT THE END OF THE BODY OF THIS RESEARCH

Emerging Themes

HoldPrice at 07 April 2003(GBP) 251.00Price target 26552-week range (GBP) 313-222

A review of BG's LNG-based assets hasadded 0-5% to our financial forecasts andNAV - and increased our price target from245p to 265p. Strong asset-backing andpositive newsflow should continue overQ2, but our rating remains Hold versusthe deeper discounts to be foundelsewhere in the sector.

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Europe UKOil & Gas

8 April 2003

BG Group PlcReuters: BG.L Bloomberg: BG/ LN Exchange: L Ticker: BG.L

LNG: projects into numbers

Caroline Cook(44)131 240 [email protected]

Al Stanton+44 131 240 [email protected]

Paul Sankey(44)131 240 [email protected]

A review of BG's LNG-based assets has added 0-5% to ourfinancial forecasts and NAV - and increased our price target from245p to 265p. Strong asset-backing and positive newsflow shouldcontinue over Q2, but our rating remains Hold versus the deeperdiscounts to be found elsewhere in the sector.

Year End Dec 31 2002 2003E 2004E 2005E

EPS New (GBP) 13.50 16.90 17.90 17.00

EPS Old (GBP) 13.50 16.90 17.50 17.00

EPS Growth 0% 26% 6% -5%

DPS (net) 3.10 3.18 3.26 3.34

Div./Yield x 1.1% 1.4% 1.4% 1.5%

P/E x 20.40 14.80 14.00 14.70

DACFM x 11.4 8.0 7.8 8.2

ROACE 11.3 13.6 13.4 11.6Source: Deutsche Bank AG Estimates and Company data

Deutsche Bank AG

DISCLOSURES AND ANALYST CERTIFICATIONS ARE LOCATED AT THE END OF THE BODY OF THIS RESEARCH

Emerging Themes

HoldPrice at 07 April 2003(GBP) 251.00Price target 26552-week range (GBP) 313-222

Price/Price Relative

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BG Group Plc (R.H. SCALE)

1m 3m 12mAbsolute 2.6% 0.6% -18.3%FTSE -0.3% -11.7% -30.1%

Stock DataMarket Cap (GBP) 8,329Shares Outstanding (m) 3,529.4Free float 100%CY03 P/E-to-growth 7.2xEst. 5 year EPS growth 2.3%FTSE 3,593.30Index Membership FTSE 100

Long-term Natural GrowthWith final approvals for the second phase of the Egyptian LNGproject imminent, BG’s pan-Atlantic gas business is taking realshape. Less captive to the emerging market risks of the group’sdownstream gas distribution business, consistent performancelooks far more within management’s control. With little of theassociated development capital on balance sheet, we suspect thatLNG will play a vital role as BG seeks to maintain group returnsagainst the dilution pressures of strong upstream volume growth.Downstream gas for “upstreamers”In this report, we have revamped our modelling of the LNGbusiness. We detail the current project portfolio, estimate returnsand try to identify the next potential LNG targets: India, Iran,Equatorial Guinea and El Paso LNG? The review has added 0-5% toour group earnings estimates 2003-07E. In conjunction with a widerasset review, we have raised our estimate of BG’s NAV to 258p.Momentum adds to absolute valueSince late 2002, we have noted an increasingly positive shift in ournumbers for BG. Aided not only by still-strong oil and gas prices,there has also been accretion from the disposal of Kashagan andthe continued elimination of completion risk on new upstreamprojects. We expect this positive newsflow to continue with newsimminent on Egypt and Trinidad, and a good set of Q1 figures (13May). We have raised our price target to 265p, but find ourrecommendation limited to a Hold relative to the upside potentialwe see in peers BP, Eni, TOTAL and Statoil (all rated Buy).

8 April 2003 Oil & Gas BG Group Plc

Page 2 Deutsche Bank AG

BG GROUP PLC Integrated Oils GBp 250.331-Dec Hold

Per Share Data 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002E 2003E 2004E Price and Price Relative

EPS (Before Amort. of Goodwill) 14.4 17.1 13.8 12.0 -13.2 -13.7 18.6 19.8 19.2 14.1 12.8 17.7 18.7Goodwill per Share 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.8 0.8 0.8 0.8 0.8CEPS 42.3 51.5 40.0 41.0 41.6 27.9 34.5 35.9 33.9 17.1 19.9 26.7 28.4Net DPS 14.2 14.5 14.5 14.5 9.0 9.0 8.6 9.2 6.4 3.0 3.1 3.2 3.3BVPS 463.8 442.5 442.4 432.9 335.5 227.1 257.0 211.7 102.2 97.4 91.3 105.1 119.7

Valuation

P / E (x) 8.9 9.2 11.0 11.9 nm nm 12.2 11.8 13.1 19.2 21.4 14.1 13.4P / CE (x) 3.0 3.1 3.8 3.5 2.6 5.2 6.5 6.5 7.4 15.8 13.8 9.4 8.8Yield (%) 11.0 9.2 9.5 10.1 8.3 6.2 3.8 3.9 2.6 1.1 1.1 1.3 1.3P / BV (x) 0.3 0.4 0.3 0.3 0.3 0.7 0.9 1.1 2.5 2.8 3.0 2.4 2.1

EV / Sales (%) 98.1 111.3 106.1 106.8 194.8 239.9 295.2 306.7 247.0 324.4 412.3 324.6 292.4EV / Adj. EBDIT (x) 4.6 4.7 3.9 3.9 7.3 6.3 5.4 6.1 5.7 7.7 7.7 5.8 5.4EV / EBITn (x) 16.2 12.9 8.7 8.5 16.3 10.0 7.3 8.6 8.8 11.9 10.6 7.7 7.2EV / Adj. EBIT (x) 7.7 8.4 8.5 9.1 54.6 14.5 8.6 9.6 11.3 11.4 11.7 8.6 8.1EV / EBI (x) 12.0 8.6 15.6 18.2 nm nm 12.9 13.9 18.1 17.3 21.3 14.2 13.0EV / Free Cash Flow (x) nm 19.8 6.2 nm nm 13.3 27.9 108.3 12.8 nm nm 745.1 329.3EV / Capital Employed (x) 0.4 0.4 0.4 0.4 0.4 0.7 0.8 0.9 2.9 2.1 2.1 2.0 1.7

Avg. Adjusted No. of Shares (m) 4,298.0 4,322.0 4,336.0 4,370.0 4,405.0 4,348.0 3,940.0 3,906.0 3,475.0 3,498.0 3,529.4 3,529.4 3,529.4Avg. Market Cap. (GBP m) 5,525 6,812 6,591 6,248 4,762 6,280 8,904 9,141 8,707 9,470 9,704 8,832 8,832 Rel. Perf.: -1m: 0.0% -3m: 2.4% -12m:15.2%Enterprise Value (GBP m) 10,062 11,560 10,294 9,186 8,538 10,317 13,207 14,679 11,781 8,667 9,120 8,436 8,242The share price used for the market cap. and valuations is the average over that financial year, except in the current year and afterwards.

P&L (GBP m) Sales and Free Cash Flow per Share

Turnover 10,254 10,386 9,698 8,601 4,383 4,300 4,474 4,787 4,769 2,672 2,212 2,599 2,819Personnel Costs 2,014 3,160 1,804 1,588 1,285 805 591 600 600 177 187 204 223Adjusted EBDIT 2,168 2,463 2,642 2,364 1,165 1,644 2,454 2,404 2,050 1,122 1,182 1,452 1,524

Depreciation 861 1,094 1,424 1,353 1,009 932 915 882 1,004 365 405 475 503EBIT 1,298 1,340 1,182 977 118 677 1,508 1,497 1,043 754 774 974 1,017Adjusted EBIT 1,307 1,369 1,218 1,011 156 712 1,539 1,522 1,046 757 777 977 1,021

Net Interest Result -311 -354 -184 -122 -280 -350 -416 -445 -459 -63 -80 -72 -61Amortisation of Goodwill 0 0 0 0 0 0 0 0 29 27 29 29 29Associates (Reported Pre-Tax) 7 30 15 17 49 22 53 113 132 140 143 146 149Other Financial Items 47 21 97 129 0 0 0 0 276 -51 0 0 0Exceptional Items (Reported Pre-Ta -195 -1,650 -192 -394 -48 288 73 56 -9 149 -14 0 0Pre-Tax Profit 846 -613 918 607 -161 637 1,218 1,221 954 902 794 1,018 1,076

Income Tax 371 -77 504 471 458 942 405 376 304 287 374 411 422Associates (Reported Post-Tax) 0 0 0 0 0 0 0 0 0 0 0 0 0Exceptional Items (Reported Post-T 0 0 0 0 0 0 0 0 0 0 0 0 0Stated Net Profit Pre-Min. 475 -536 414 136 -619 -305 813 845 650 615 420 607 654Adj. Net Profit Pre-Min. 622 737 601 530 -571 -593 740 789 685 521 463 636 683Minorities 2 -3 4 6 10 2 8 15 19 29 10 11 24

Cash Flow (GBP m) Margin Trends (%)

EBIT 1,298 1,340 1,182 977 118 677 1,508 1,497 1,043 754 774 974 1,017Depreciation 861 1,094 1,424 1,353 1,009 932 915 882 1,004 365 405 475 503Increase (+) Decrease (-) in Provisio 79 131 181 70 0 165 -50 -129 -73 -217 -2 0 0Increase (-) Decrease(+) in NWC 119 62 988 -864 0 517 -62 -584 620 -249 -111 0 0Operating Cash Flow 2,357 2,627 3,775 1,536 1,127 2,291 2,311 1,666 2,594 653 1,066 1,449 1,521

Proceeds from Share Issues 66 27 19 56 0 -1,228 -39 -1,653 47 10 9 0 0

Interest Paid (-) Received (+) -311 -354 -184 -122 -280 -350 -416 -445 -459 -63 -80 -72 -61Tax Paid -371 77 -504 -471 -458 -942 -405 -376 -304 -287 -374 -411 -422Dividends Paid -728 -629 -634 -646 -638 -537 -327 -348 -348 -121 -106 -111 -112

Capex -2,329 -2,002 -1,543 -1,293 -980 -462 -1,303 -1,021 -1,234 -776 -1,000 -1,005 -1,055Net Other Investments 72 200 546 78 0 97 309 -626 446 253 -379 624 0

Other Cash Flow Related Items 872 -149 961 -49 726 672 -293 -20 5,770 153 400 157 137Change in Net Debt (-) Cash (+) -372 -203 2,436 -911 -503 -459 -163 -2,823 6,512 -178 -464 631 7

Balance Sheet (GBP m) Returns on Capital (%)

Net Working Capital 413 554 -391 -296 -843 -1,664 -1,227 -406 -210 -133 -735 -1,412 -1,455of which Inventories 593 588 400 309 103 103 96 119 99 98 98 98 98Net Financial Debt (-) Cash (+) -4,246 -4,449 -2,013 -2,924 -3,427 -3,886 -4,049 -6,872 -360 -538 -1,002 -371 -364

Gross Tangible Fixed Assets 40,034 41,600 39,922 40,864 38,786 33,007 34,053 36,085 6,743 6,134 7,423 8,428 9,483Net Tangible Fixed Assets 24,132 24,928 23,524 23,659 21,369 16,222 17,029 17,250 3,863 3,707 4,591 5,121 5,673Goodwill 0 0 0 0 0 0 0 0 567 444 415 386 357Gross Depreciable Intangible Fixed 654 509 257 141 93 101 199 232 309 354 383 412 441Net Depreciable Intangible Fixed As 638 485 257 141 93 101 199 232 309 354 383 412 441Participations & Associates 99 108 150 238 0 323 374 549 562 663 663 663 663Other LT Assets 596 1,040 975 1,221 0 327 252 122 95 125 125 125 125

Pension Provisions 154 488 595 561 640 589 519 423 58 52 52 52 52Other Long-Term Provisions 584 2,077 2,105 1,881 1,058 1,070 1,100 1,118 761 812 812 812 812Other LT Liabilities 537 572 616 674 714 855 849 928 257 228 228 228 228

Stated Shareholder’s Equity 19,933 19,124 19,181 18,919 14,778 8,892 9,976 8,218 3,550 3,406 3,224 3,708 4,223Minorities 424 405 5 4 2 17 134 188 200 124 124 124 124Total Net Worth 20,357 19,529 19,186 18,923 14,780 8,909 10,110 8,406 3,750 3,530 3,348 3,832 4,347S’holder’s Equity After G-will Write 19,933 19,124 19,181 18,919 14,778 8,892 9,976 8,218 2,983 2,962 2,809 3,322 3,866

Key Ratios Average Net Debt (-) Cash (+) / Mkt. Cap. (%)

Personnel Costs / Sales 19.6 30.4 18.6 18.5 29.3 18.7 13.2 12.5 12.6 6.6 8.4 7.8 7.9Headcount (Average of the Year) 70000 76453 69971 55382 43106 21891 18894 19594 19745 4309 4460 4772 5106Value Added / Employee in EUR 77477 92022 81028 86142 68672 161766 239921 232732 220250 484610 488124 517573 510082

Adj. EBDIT Mgn 21.1 23.7 27.2 27.5 26.6 38.2 54.9 50.2 43.0 42.0 53.4 55.9 54.0Adj. EBIT Mgn 12.7 13.2 12.6 11.8 3.6 16.6 34.4 31.8 21.9 28.3 35.1 37.6 36.2Adj. Net Prof. Pre-Min. Mgn 6.1 7.1 6.2 6.2 -13.0 -13.8 16.5 16.5 14.4 19.5 20.9 24.5 24.2

Depreciation / Sales 7.6 9.4 14.1 14.8 23.0 21.7 20.5 18.4 21.1 13.7 18.3 18.3 17.8Capex / Sales 22.7 19.3 15.9 15.0 22.4 10.7 29.1 21.3 25.9 29.0 45.2 38.7 37.4

Inventories / Sales 5.8 5.7 4.1 3.6 2.3 2.4 2.1 2.5 2.1 3.7 4.4 3.8 3.5Net Working Capital / Sales 4.0 5.3 -4.0 -3.4 -19.2 -38.7 -27.4 -8.5 -4.4 -5.0 -33.2 -54.3 -51.6Free Cash-Flow / Sales (Post-Tax) -4.3 5.6 17.2 -3.1 -9.2 18.1 10.6 2.8 19.3 -16.1 -15.0 0.4 0.9

Interest Cover (x) 4.2 3.9 6.6 8.3 0.6 2.0 3.7 3.4 2.3 12.0 9.7 13.5 16.8Net Debt (-) Cash (+) / Equity -20.9 -22.8 -10.5 -15.5 -23.2 -43.6 -40.0 -81.8 -9.6 -15.2 -29.9 -9.7 -8.4

Return on Stated Equity 3.1 3.8 3.1 2.8 -3.4 -5.0 7.8 8.5 10.8 13.4 12.8 17.2 15.9Return on Adjusted Equity 3.1 3.8 3.1 2.8 -3.4 -5.0 7.8 8.5 11.9 16.6 15.7 20.4 18.3Return on Cap. Employed (Post-Tax 6.5 5.1 2.6 2.1 -1.7 -1.9 6.5 6.3 6.1 12.2 10.1 13.7 13.8Average Age of Tangible Fixed Asse 20.4 17.2 12.0 13.5 17.3 18.0 18.6 21.4 2.9 6.6 7.0 7.0 7.6Source: Company Data, Deutsche Bank Estimates.

Caroline Cook Tel: +44 131 240 7642 Updated: 04-Apr-03

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BG GROUP PLC REL. F.T. INDEX 100 (R.H.SCALE)1993 1994 1995 1996 1997 1998 1999 2000 2001 20022003

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Deutsche Bank AG Page 3

Investment Thesis

LNG-enabledIn this report, we have revamped our modelling of BG’s LNG portfolio. We take anin-depth look at the structure and potential returns of LNG production (in Trinidad,Egypt, Bolivia and Indonesia) and BG’s LNG delivery options (shipping andregasification). We find a business that essentially enables the production of BG’s`upstream gas reserves (contributing 65% of BG’s forecast output growth 2002-2008). We estimate integrated project returns of 12-15%. Although these are lowerthan the 20-25% IRR’s we see on many of the industry’s new oil developments,they remain a multiple of BG’s WACC. As importantly, success has allowed BG toscale one of the industry’s notorious barriers to entry. This “right to replace” shouldsee BG drive further growth through the addition of new projects and (maybe) theunlocking of high RoACE trading returns through the optimisation of global LNGtrades. By 2010, we estimate BG could be selling as much LNG as the industry’scurrent leader (Shell) does today.

Positive momentumSince late 2002, we have noted an increasingly positive shift in our numbers for BG.Our NAV (raised to 258p today) is up 8% since the turn of the year. Still-high oil andgas prices, the disposal of Kashagan and our review of the LNG business haveimproved our earnings and cashflow forecasts. We expect Q1 figures (due 13 May)to again illustrate BG’s below-average volatility, and a touch more exposure to Q1’sUS gas prices (thanks to Trinidad Train 2, and perhaps Lake Charles). We expect BGto show earnings growth of 26% 2002-03, and to be one of the very few withenough organic strength to offset our expectation of falling oil prices in 2004.

Asset backedBG falls into that group of companies small enough for our estimates of NAV not tobe an abstract concept – and the share price has steadfastly refused to fall muchbelow this figure, despite wider market weakness. With our NAV estimate on therise for the first time since 2000, we expect BG’s share price trading range tofollow. Newsflow over the next few months (expansions at Egyptian and TrinidadLNG, further progress in India, Q1 figures) should be similarly supportive.Nonetheless, the BG valuation fails to offer the deep value we see in companiessuch as Eni and Statoil (both trading at 17% discounts to our core asset values, bothrated Buy). In addition, a 2003E debt-adjusted cashflow multiple only 0.5x below BP(Buy) and 1.5x above TOTAL (Buy) looks full value for a smaller company that lacksan equivalent exposure to a high returns upstream, or the expected 2003 rally inrefining and marketing. Our recommendation remains Hold.



Table of Contents

BG LNG – developing a new business ............................................. 5Who, what and why?...............................................................................................5The LNG plants........................................................................................................6Shipping and trading ................................................................................................8New business expense..........................................................................................10

The LNG plants ................................................................................ 11Trinidad: strong foundation ....................................................................................11Egypt: first to market .............................................................................................18Tangguh: more knowledge than power..................................................................25Pacific LNG: rainforest dream (or is that nightmare...) ............................................28

Lake Charles and Brindisi – how might they work? ..................... 31Regas: the last link.................................................................................................31BG and regas.........................................................................................................31Lake Charles: US gateway .....................................................................................32Brindisi – the fourth leg..........................................................................................33Widening the regasification range ..........................................................................35

Cash: how does the money flow?.................................................. 37The LNG division – a financial rationale ..................................................................37Unlocking production .............................................................................................38LNG presence........................................................................................................38LNG in the P&L......................................................................................................39LNG returns and the off balance sheet effect.........................................................40



BG LNG – developing a newbusinessIn this publication, we examine the portfolio and structure of BG’s LNG business. Inthis first section we summarise the asset base and place the earnings contributionin a group context. This is followed by an in-depth review of BG’s LNG plants, inwhich we look at the ownership, physical flows and our estimates of projecteconomics. We then discuss BG’s regasification terminals and the outlook for globalLNG trading. Finally – and most importantly – we wrap our various projecteconomics into financial forecasts for the division, and take a look at BG’s “LNG-enabled” production profile, and the implications of this asset-heavy activity forgroup returns.

Who, what and why?BG has been in LNG since the 1960s when it imported the UK’s first cargo to theIsle of Grain terminal (now mothballed and owned by National Grid/Lattice). Thebusiness in its current form really began to emerge in the mid-1990s when BGdeveloped its first gas discovery in Trinidad and became involved in the local LNGproject. Although the division is clearly there to make money, its principal aim is toenable the development of BG’s upstream gas reserves.

Internally, the LNG business is the baby of Martin Houston – currently executivevice president for Atlantic, Europe and Mediterranean Basin. Also involved (byregional leadership) are Dave Roberts (for the Eastern Hemisphere –Iran, India andIndonesia) and Rick Waddell (South America). Interestingly, both of these gentlemenare new entrants to BG, joining in 2002-03 from ChevronTexaco and Enron,respectively. Over the same period, BG has also added a number of new staff in theUS to handle the LNG trading opportunities presented by the ownership ofregasification capacity.

Figure 1: BG’s earnings mix

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BG’s LNG business consists of a variety of different profit (and loss) centres. Theonly meaningful current contribution is from the LNG processing plant in Trinidad –and it is from the expansions to this, coupled with the plant in Egypt, that most ofthe (visible) future growth will come. In addition, the division has the potential togenerate positive cashflow through the lease of its LNG tankers, and the tradingcapacity of the Lake Charles regasification terminal in the US. Longer term, BG hasa variety of projects that may be developed (Italian regasification, Bolivian,Indonesian and Iranian LNG). The negative implication of this continueddevelopment comes in the form of a fairly substantial (and consistent) stream ofnew business expenses.

The LNG plantsBG has two active LNG processing plants. Trinidad has been up and running since1999, and is about to see the commissioning of its third train. Capacity will thenstand at 10mt/year (or 1.3bcf/d), of which BG has a net 30% share. The plant is fedby gas from both BP and BG-led upstream developments. BG’s upstream partners(who do not share corresponding stakes in the LNG plant itself) are ChevronTexaco,Eni, Petrotrin and PetroCanada. The next phase of the project is expected to see theconstruction of a fourth train (perhaps up to 5.2mt/year in size, 33% net to BG). Ourdivisional forecasts assume that this is onstream by 2007, but further delays (and/ora change to the shareholding structure) are possible.

The other “active” plant is in Egypt. While the plant is not due to start operationsuntil late Q3 2005, construction work is now well underway. The first train is to havecapacity of 3.6mt/year with BG and Edison both holding 35.5%, and the remaindersplit between the Egyptian government (24%) and the initial LNG purchaser, GdF(5%). Gas feed will come from the 50/50 BG/Edison offshore gas developments inthe West Delta Deep concession. Priced at $1.35bn, the first phase appears highcost and is absolutely dependent on a much cheaper subsequent doubling ofcapacity (currently planned for late 2006).

Beyond the active plants, BG is generating a list of potential projects, of whichIndonesia (Tangguh with BP) and Bolivia (Pacific with Repsol and BP) look the mostlikely. The company has also discussed some involvement with the Iranian LNGschemes (South Pars 11-14). We understand that BG would be unwilling to act inthe upstream under the buyback contracts, but is offering to develop theliquefaction chain and act as the offtaker (probably for India). Independently, wehave also heard reference to the company’s becoming actively involved inMarathon’s possible LNG project in Equatorial Guinea (where this inexperiencedLNG player has already found more than 5tcf).

We provide a full analysis of BG’s LNG plants in the next section.

Deutsche B

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8 April 2003

Oil &

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BG

Group P

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Figure 2: BG’s global LNG portfolio


USA Alaska

Trinidad

Venezuela

Algeria

Libya

AustraliaDarwin

Brunei Malaysia

Bontang

Sakhalin

Tangguh

Oman

Snøhvit

Gorgon

Possible new BG LNG projects

Abu Dhabi

Iran

Egypt

Nigeria

AngolaEq. Guinea

YemenQatar

Arun

NW Shelf

Existing BG LNG projects



Shipping and tradingThis sub-division of the LNG business has been primarily concerned with theownership and leasing of a series of LNG carriers. In late 2001, however, thecompany acquired access rights to much of the capacity of the Lake Charles LNGregasification terminal in Louisiana. Also set to join the division in 2007 is the yet-to-be-built regasification terminal at Brindisi in southern Italy. Further out still could bethe successful completion of the long-mooted Pipivav regasification facility in India.As BG’s LNG business develops, this part of the P&L will carry not only the costs ofthese facilities, but also any “trading” profits that BG manages to extract bysupplying LNG cargoes into the markets.

Figure 3: BG’s LNG shipping fleet

72 mcm lng x2

1.55 bcf gas x2

126 mcm lng x4

2.76 bcf gas x4

138 mcm lng x2

3.02 bcf gas x2

LT charter to Gas Natural

Due for delivery in 2005/06

Due for delivery in 2003/04

138 mcm lng x5

3.02 bcf gas x5

Current fleet on shorter term charter

Shipping capacity due to rise from 645mcm to 1,600mcm by end-06


The shipping fleetBG’s LNG fleet currently consists of two wholly owned vessels (both on long-termcharter to Gas Natural), and four vessels on charter to BG (which then sub-lets themto others). By the end of 2003, BG should have another vessel on long-term charter(either to trade its own gas, or to again sub-let). Another (on sale-and-lease-back) is



due in 2004. To coincide with the expected start-up of Egyptian LNG in 2005, BGhas options for the delivery of five new tankers over the 2005-06 period.Interestingly, BG released an option over a sixth vessel in early 2003 – perhapsadding credence to an increasingly wide-spread industry view that LNGtransportation capacity is no longer the bottle-neck (or money-making opportunity) itonce was.

BG’s target is to be balanced in terms of shipping capacity versus LNG production.Assuming that both the tankers due for delivery in 2003-04 are 138,000 cubicmetres in size, the company will have the rights to 921,000 cubic metres of capacityby the end of next year. This compares to our expectation that in 2004, facilities inwhich BG has a stake will be selling 4.2bcm of LNG/year (net to BG). To carry thisLNG output (which is compressed in a ratio of 620:1 when liquid), BG’s ships wouldneed to fill up seven to eight times over the year (not unrealistic given the 16-daytrip from Trinidad to the US, and 30-day trip to Spain).

By the end of 2006, BG should have a further 690,000 cubic metres of shippingcapacity compared to the 5bcm/year annual output of ELNG Train 1 (implying 12trips for each boat – with only a six to nine-day trip to Italy or Spain/southern France,albeit a long 50 days if some volume is actually taken to the US rather than swappedfrom Trinidad).

Figure 4: The LNG trade: distance versus cost for BG’s ships

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0.60

0.80

1.00

1.20

1.40

1.60

1.80

500 1500 2500 3500 4500 5500 6500 7500 8500 9500 10500 11500 12500

Distance - Nautical Miles

Uni

t Tra

nspo

rt C

ost,

$ pe

r m

mbt

u Egypt-Italy

Egypt -Spain/ France

Trinidad-Spain

Egypt-Lake Charles

Trinidad Lake Charles


In 2000-01, BG’s LNG fleet earned an average £17m/year, with 2001 finding extrastrength in the tight shipping market of the early winter. Moving forward, we haveassumed that BG continues to make a constant margin on its rising capacity (hitting£30-35m/year in 2006E). There may be years where this out (or under) performs ourexpectations according to boat availability at each point. As all of BG’s new shipswill almost certainly be leased with a fixed charge, BG’s gearing to daily charterrates will be high.

Regasification terminalsThe regasification business will carry much of the trading – or wholesaling –profitsfrom BG’s global LNG contacts. Currently, this element consists of trading thirdparty LNG into Lake Charles (or one of the open-access terminals in northern



Europe). We describe our understanding of the Lake Charles opportunity in greaterdetail in the specific section below. In summary, however, BG pays a fixed chargeevery day for its access to the terminal. It then buys LNG from others on(predominantly) a pass-through pricing basis, with BG making only just enough tocover the fixed charge, the actual regasification cost, and a small margin. The moreLNG BG manages to get into Lake Charles on this basis, the more likely it is to coverthe fixed costs.

In the future, this business will become more BG-specific if the company choosesto buy some of its own LNG (perhaps from Trinidad or Egypt) for subsequentsupply. At that point, BG could arbitrage on its own account the best pricingopportunities between, say, the US and Europe.

As these own-trading opportunities materialise, so should BG’s regasification accessbe improving. The Brindisi terminal in Italy is due onstream in 2007, and will allowBG some access to the market on its own account (although 20% of the capacityhas to be made available to others under the Italian regulatory regime). In addition,many of the new terminals planned for Spain and the UK (if not France) are likely tocarry similar open-access provisions.

Our financial forecasts include our estimates for shipping, the use of Lake Charlesand the completion of Brindisi. In aggregate this sub-division’s earnings areestimated to range around £40-45m in 2006/07E, but could be higher (or lower)depending on year-to-year freight rates and trading opportunities.

New business expenseBG’s development of new business opportunities in LNG is substantial enoughrelative to the division’s current earnings to create notable volatility in quarter-to-quarter returns. Averaging around £20-25m/year since demerger, the currentexpense covers internal project identification work, external consultants and pre-bidding by contractors. Upon project commercialisation, BG can look to capitalisethe past expenses (as it did for Egypt in Q4-2001).

We see little chance of a notable reduction in BG’s new business expenses over themedium term. BG currently has project teams active on Egypt phase II and Brindisiregasification. We suspect that Pacific LNG (Bolivia) is incurring charges fromproject-leader, Repsol, as it attempts to manage a tricky combination of Californian-Mexican-Chilean-Bolivian politics. Reports from Indonesia suggest that the BP-ledTangguh development team is on a watching brief ahead of a more concretecommitment for phase I volumes from the Chinese. Finally, BG continues to plugaway at the potential of Iranian export/Indian import schemes.

Our financial forecasts assume a constant expense of £20m/year.



The LNG plantsIn this section, we take a detailed look at the structure and profitability of BG’s twomost advanced LNG projects – Trinidad and Egypt. We then review progress andsome estimated economics on the two potential projects currently in the portfolio –Tangguh in Indonesia and Pacific in Bolivia.

Trinidad: strong foundationThe Atlantic LNG plant is BG’s only currently producing LNG asset. Train 1 startedproduction in 1999, was joined by Train 2 in August of 2002 and should see Train 3come onstream this summer. BG has a 26% stake in the first train but 32.5% in thenew capacity. By the end of this year, the plant should be exporting more than1.3bcf/d as LNG (or over 400mmcfd net to BG) with sales going primarily into theUS and Spain. With a plentiful gas reserves base, and excellent proximity to the USgas market, Trinidad has probably become one of the world’s most prized LNGassets.

Figure 5: Trinidad gas: big volumes for a small island

0

3000

6000

9000

12000

15000

18000

BP

Rep

sol

BG

Che

vron

EOG

Petr

otri

n

BH

P

TOTA

L

Talis

man EN

I

Vol

ume

(bcf

)


More than Brian LaraIn May 1971, the day after the second birthday of local cricket maestro, Brian Lara,the original holder of BG’s acreage in Trinidad discovered its first gas field. This wasfollowed by a wealth of other finds through the 1970s and 1980s, but with littleaccompanying development activity into an unsurprisingly small local market.

BG moved into the Trinidad acreage in 1988, when the asset formed part of theacquisition of Tenneco’s non-US business. Both of the ex-Tenneco permits – Eastand North Coast Marine Areas (ECMA, NCMA) – had discovered gas, the keychallenge was one of commercialisation. Not only did BG face a problem in terms offinding a market, but it also had to compete against the local supply dominance ofAmoco (BP from 1999).

Following much negotiation, BG brought the Dolphin field in ECMA onstream in1996 with a 175mmcfd supply contract into the local market. This coincided with



the start of construction of the first train of the Atlantic LNG project. While BG didnot have the leverage to gain supply rights into the plant (all the gas in Train 1 issupplied by the BP fields), it bought itself some future potential by stumping up for a26% share in the processing plant.

Train 1 started production in April 1999, only a month after Brian Lara made his5,000th test run for the West Indies. Meanwhile, BG’s early capex commitment hadmade it part of the Trinidad establishment, and was, no doubt, crucial in securingthe company’s greater share – and actual supply rights – in the subsequent LNGexpansions.

Figure 6: Trinidad: what’s where

Arima

San Fernando

Frederick

Longdenville

PORT OF SPAINCocorite

A

BC

B

A

E

DB

A

C AP

Posa

North Posa

South Domoil

Manicou

Iguana

Couva

Punta Sur

SoldadoWest

Iris

Mejillones/Patao

Dragón

Poinsettia

Orchid

Poinsettia-SW

Mejillones Sur

DolphinDeep

El Diablo

East Manzanilla

Starfish

Angostura

La Novia

CarapalRidge

Corosan

Cocuina

Loran

IronHorse

Cashima

Manakin

Coralita

East Queen's Beach

North EastQueen's Beach

LantanaOilbird

Mango

Parula

CHACONIA

N.SOLDADO

S-759

C-6S-648SOLDADOMAIN

FYZABAD

MORUGA WEST

PARRYLANDS

ICACOS

SIPARIA

EAST SOLDADO

PALO SECOBONASSESW SOLDADO

GUAPOPOINTFORTIN ERIN

BRIGHTONMARINE

NORTHMARINE EAST BRIGHTON MARINE

OROPOUCHE

SAN FRANCIQUE

MANDINGO

FOREST RES.

(shut-in)

BALATA

MAHAICA

HIBISCUS

TABAQUITE

BARRACKPORE/PENAL/WILSON

COORA/QUARRY/APEX QUARRY

MACKENZIE/ GRAND RAVINE

CRUSE MAHOGANY

MORNEDIABLO

CATSHILL-ORTOIRE

BEACH

MORUGA EAST

GALEOTA

POUI

NAVETTE

GOUDRON

INNISS /ANTILLES-TRINITY

PELICAN

DOLPHIN

FLAMBOYANT

MORA

EASTGALEOTA

SAMAAN

TEAK

OSPREY

DORADO

AMHERSTIA

KISKADEE

RENEGADE

IMMORTELLE

IBIS

CASSIA

PEDERNALES

Neal & Massy

Petrotrin

Open

Primera

Petrotrin

Petrotrin

Open

Open

Trinmar

Inelectra

Vermilion

TED

Venture

Perenco

Petrotrin

Open

Petrotrin

Petrotrin

Trinmar Venture

Primera

Petrotrin

BPTalism

an

Petrotrin

MOVL

Petrotrin

BG

Mariscal Sucre

TotalFinaElf(under negotiation)

Open

Open

BHP BillitonKPA

BHP Billiton ShellOpen

Petrotrin

Open

EOG

EOG

BG BP

Trintomar

BP

BG

BG

Open OpenEOG

BG BP

EOG

ChevronTexaco

Open

Open

S.E.C.C.

BP East Block

South Marine

Block 23b

Block 27

Block Y

PenalExt.

Block 1b

Block 5a

Soldado Area

Open

Block 25a

GuayaguayareBay

Southwest Peninsula

North Marine

Open

Pedernales

Open

Golfo deParia Este

Block X

Central Range Block

Block ZEastern Block

Northern Basin Consortium

Block 1a

Petrotrin Operated Area

PointLigoure

Block S11

North CoastMarine A-1

Open

Block 9

Norte de PariaBlock 24Trinm

ar

Oropouche

Block W

Central Block

GuapoTerritorial

East Brighton Marine

MayaroBay

Block 6b

Block 5a

Block E

Modified Ua

Galeota

Block 5b

Modified Ub

Block 3b

Block 25b

Open Block 3a

Block 2c

Open

Block 2abOpen

BP West Block

Block 4a

Block 26

Block 4b

Block 2

Block 6d

Lower ReverseL Block

Posa-65A-1

Posa-36A-1

115-1

Posa-103A-1

143GPA-1X

Morro-1Manamo-2 708

115-2

Serpiente-1

PCH-1

Capure-2

Posa-123-1

PCPX-1

PCA-58

GOPA-1a

125

670177A-1

643576

207

541

700d

Posa-100A-1

1

538

743111-1

5

3

366

Posa-86-1

SN-6591413

2

NM-16

1

1

2

S-368

6

S-646

S-818

48

ApexCedros-4

2,311

255

Mck-6,7

S-369

S-177PLM-1S-435

AL-13,17

SouthMarine-1

3

2

Q-205

MD-1

2

4

SFB-1

North Brighton-1

Tarouba-1

1

5

361

33

2

7

Cardiff-1

13

Point a Pierre-1

1

Barrackpore-355

Tablelands-1

La Fortitude-1St.Croix-1

6

7

E227,229Morpho-2

MD-39

E3Rock Dome-1,3

Rochard-1

GBM

Guayaguayare-613

Carambola-1

Canari Marine-1

6332

1

134

1

2CatshillOrtoire

16

Roseau-1

2

BalataWest

BC

4

3

Posa-48-1

5

2

Posa-40-1

14

32

NM-2 1715

BM-73

SouthBoundary

NorthMarine7

EastDomoil-1

1

2

Domoil-1

1stCouva-3

Goodrich-1

Couva-2

CouvaMarine Chickland-1

2

Charuma-1

1,2

Brickfield-1236

2229

Esmerelda-1HarmonyHall-3

223

Laventille-1

B-1

Guaico-1

3

Avocado-1

32

PuertoGrande-1

Freeport

219

34

Springvale-1

Montserrat-1JohnsonRoad

Congo River-1

Mayo-1

Balata E-11

4 Colenso

Tamba-1

Capure-1PSX-1

South Galeota

Morpho-1

42

3

1

Columbus-1 OffshorePoint Citron-1

SW Galeota-1 RLE-1

RLW-1

Pamberi-1

3

SEG-9

Banyan-1

1

1

SE Galeota

12

2

SEG-107

1

SEG-15

Claro-1

Kapok-1

Sparrow-2

SEG-2Renegade-1

SEG-5

Pomello-1

Immortelle-1,9

1

SEP-1

13

6

314

1 16

1

1

Manakin-1SouthEastQueen's Beach-1

Mejillones-1 Patao-1

Patao Sur-1

2a

KK4-3

Uquire-1

KK4-1

1

K4-4

2

KK4-5

1 13

HH6-1

LL9-1

KK6-2

Maracas-1

KK6-3

KK6-4 KK6-1

Amber-1Topaz-1

Aripo-1Kairi-1

Kairi-2

Canteen-1

Betty-1

NorthBasin-1,2

Alice-1

1

Emerald

Diamond-1,22

Angostura-2

1

C.O.-47

G-646

5

Guayaguayare-606

G-3891

2

E29

Iguana River-1

15

LizardSprings

Guayaguayare-6014

AntillesTrinity

W.Tourmaline-1,21X

12

GS-2

WP-2

GS-1G-619

2

Guayaguayare-621

55

2Agostini-1

1

Radix-1

Palmiste1

Galeota Ridge-5

NP

3,4

2Rincon-1

2AGR-2

3

GR-4,6 1

1East Galeota

Tourmaline2

Cocos-1

1

South Darien

1

South WestDarien 1

2

Cocal-13,4

SW Poui-1

2

NE Poui-1,2

11

EP-2

OPR-18

Teak NW-1

Nariva-1

SW Nariva-1

SD-2

W.Samaan-1

OPR-17

SD-1B

OPR-14

1Salman Deep-1A

1

Tatou-1

La Savanne-1

OPR-10

OPR-9

OPR-12

OPR-3

OPR-11

OPR-20

2,3

Mokatika-1

1

2

Kitchener-1

Spitfire-1

Crapaud-1AA-1

North EastManzanilla

2

Motmot-1

OffshoreCascadoux-1

Turtle-1

OPR-1

OA-1,2

OffshorePoint Radix-2

Omega-1

SE Galeota-4

1,41 1

1

2

1,2

4

1

2

Marlin-1

Barracuda-1

5

3

Dorado-1 2

1

East Mayaro-2

EM-3,4

EM-5

East Mayaro-1

East MayaroSE-1,2

Las Cuevas-1

RedSnapper-1

Haydn-1

Adelpha-1

Sandpiper-1

El Niño-1

1533

E15

13

1

South Marine

AL-3

Manamo-1

South Marine-4

Barrackpore -9,15

Balata West

Glod-1 5

San Fernando Bay-1

G-10

Tanager-1

1

3a

Coromandel-1

2Flanagin-1

OPR-15New Grant-11

Maravel-1

OPR-16

5

Guayaguayare-603

21

Arima-1

1

1

Alma-1

Canteen-2

17

1

Parang-1

Sparrow-1

1

38

2,3

1

24"

Atla

ntic

LN

G g

as p

ipel

ine

16" gas

6" gas

4"

possible site forMariscal Sucre LNG plant

20" gas

Iron smelting 30"" gas

Methanol,Urea,Ammonia

24" Atlantic LN

G

gas pipeline

20"

gas

4"

6" gas

6" co

nden

sate

Point Fortin-Atlantic LNG Plant

gas

oil

oil

oil oil

oilgas to LNG

16" gas

Pointe-a-Pierre

oil

18" oil

PhoenixPark

16" oil

Point Lisas

gas

30" gas

oil14" oil

8",10",12"

oil pipelines

24" gas

8" oil

10" o

il

Bombax gas

40" gas Mahogany-Atlantic LNG12" liquids from Mahogany

24" gas pipeline

Dolphin to Poui/Galeota Point

10" ga

s

12" li

quids

to Ga

leota

48" BombaxCassia-Beach

gas pipeline

16" gas

24" gas

40" g

as to

Atlan

tic LN

G

8" gas

8" condensate

36" gas to Atlantic LNG

36"gas

10"condensate

TOBAGO

TRINIDAD


Labyrinthine structureThe Trinidad project is odd both in terms of the asymmetry between ownership, gassupply and gas offtake, and in the varying commercial structures that have beenemployed across the different trains.

Train 1 is owned by five companies (BP, BG, Repsol, Tractabel and NGC), suppliedby one (BP, with upstream partner Repsol) and sells its gas to two (Gas Natural,24% owned by Repsol, and Cabot, now owned by Tractabel). All of the Gas Naturalofftake (40% of the plant total) is supposed to go to Spain, and the Tractabel portionhas access rights to the Everett LNG terminal in the US and to Puerto Rico. Inreality, some of the gas can be redirected to other markets.



BG’s only economic interest in the Train 1 chain is in the plant itself. This is madeattractive by the peculiar set-up of the project. Rather than acting as a traditionaltolling facility (i.e only charging a tariff high enough to provide a basic return oninvestment), Train 1 is a profit centre in its own right. In effect the plant shares theend-user price with the gas supplier, such that revenues actually vary with the end-user price realised for each cargo. The attractiveness of this arrangement is furtherenhanced by the ten year tax holiday granted from start-up in 1999. For BG, thismakes LNG division earnings sensitive to both US and European gas prices.

Trains 2 and 3 are much more conventional in structure. They are tolling facilitieswhich charge a fixed fee for processing. The three plant shareholders are BP, BGand Repsol. All three are involved in the supply of gas (although the BG upstreamalso features ChevronTexaco, Eni, PetroCanada and Petrotrin as minority partners).Gas Natural again appears as an offtaker (50% of Train 2 and 75% of Train 3), withthe remainder sold to El Paso for import into the Elba Island terminal in the US. Themajor profit centre in the expansions is the upstream (which carries the variability inend-user gas prices).



Figure 7: Trinidad LNG: a complex structure

Train 1BP 34%BG 26%

Repsol 10%Tractabel 10%

NGC 10%

Train 2

BP 70%Repsol 30%

Gas

BP 42.5%BG 32.5%

Repsol 25%

Train 4BP 42.5% ??BG 32.5%??

Repsol 25% ??...??

3.3mt 3.3mt 5.2mt

BG operated ECMA and NCMA*

Train 3BP 42.5%BG 32.5%

Repsol 25%

3.3mt

100% Train 150% Train 275% Train 3

?? 67% Train 4

50% Train 225% Train 3

?? 33% Train 4

LNG60% Cabot/Tractabel - US

40% Enagas - Spain LNG50% Enagas - Spain50% El Paso - US

LNG75% Enagas - Spain25% El Paso - US LNG

unknown? Are BG and BP buyers?

*Supply from NCMA (BG 46%, Petrotrin 19.5%, Eni 17.3%, PetroCanada 17.3%) and ECMA (BG 50%, ChevronTexaco 50%)


For BG, the economic effect of Trains 2 and 3 is seen in the E&P and LNG divisions.In E&P, we should see the supply of around 100mmcfd net by the end of 2003, allof which becomes gas destined for the US market (and thus carries with itsensitivity to the US gas price). In the LNG division, we see basic tariff income thatsteadily remunerates the capital investment. Normally, we would expect suchreturns to be sub-10%. However, the convergence in ownership between upstreamsuppliers and plant owners in Trains 2 and 3, coupled with a still-lower tax rate thanthat seen in the upstream, does seem to be reflected in the focus of slightly moreprofit downstream. Our numbers suggests a plant rate of return of 10-12% (whichwe have also used for Train 4).

The existing longevity of the Trinidad projects does not lend itself to straightforwardestimates of integrated project returns. Moreover, it is almost impossible todisentangle the cost of developing gas for domestic Trinidad use (which is pricedquite cheaply) versus the more lucrative LNG export volumes. If we ignore thisdistinction, our models suggest a cross-chain return (net to BG’s variousshareholdings) of 15-16% at a long-term US gas price of $3.25/mcf. Any years of



higher US gas prices will clearly enhance this figure (we are currently forecasting$4.40/mcf for 2003).

Interestingly, BP’s more prolific gas trend (and lower field development costs) doesappear to give it a more appetising rate of return. Again, it is hard to separate outthe old domestic oil and gas from the new streams, but we estimate that net toBP’s various interests, the Trinidad chain delivers an integrated return of 20-22%.For Repsol (which acquired its 30% upstream stake in BP’s acreage for just under$1bn, but has always paid its way in the plant), we estimate a return of 12%.

Figure 8: Trinidad returns: how cheap is the upstream gas?

0%

5%

10%

15%

20%

25%

30%

35%

BG BP Repsol

Proj

ect r

ate

of r

etur

n

E&P

Plant

Integrated




Time for Train 4?Atlantic LNG is currently preoccupied with the approval (or not) for Train 4. The earlyengineering for this 5.2mt/year expansion (to send out almost 700mmcfd of gas)was completed in February 2002. However, a combination of persistent governmentconcerns about the size of the overall reserves base (does Trinidad have enough leftfor its domestic needs?) and lobbying from other potential suppliers keen to get inon the act has delayed the process.

Across the course of the past two years, we have heard repeated suggestions thatthe fourth phase of the plant expansion may be done on the basis of “biddablecapacity”. This would imply that in whole (or part) the current owners would have tobid for the right to expansion capacity against alternative gas suppliers. A review ofrecent discoveries and acreage in Trinidad would suggest that only EOG Resourcesis currently in a position to offer gas in the very near term. Others (from TOTAL andBHP through to Shell) would (it appears) need to undertake new exploration activity.

Assuming that the fourth train does proceed, it may be the first in which BG“trading” actually bids to buy volumes from BG “E&P-LNG”. Whereas BG had nointernational LNG trading capability at the time of the sales of Train 1-3 volumes, themap should look very different in 2006-07. By then, BG should have access to morecapacity at the Lake Charles terminal in the US, should have brought the ItalianBrindisi import terminal online, and may have dedicated capacity at other “open-access” regasification points in the UK, northern Europe and Spain. Any LNG thatBG “buys on its own account” could be traded across these various markets.

Although the international traded LNG market is constantly growing in volume, therisk profile of BG Group is likely to increase if it does become a trader on its ownaccount. The pricing of its current LNG sales may vary already, but there is noofftake risk – this is dealt with via the long term take-or-pay contracts. By selling itsown LNG into the end-user market, BG effectively becomes its own take-or-paycounterpart. Beyond the international downstream gas companies, this is a gamethat has so far only enticed Shell among the conventional oils. To cover thisemerging volume bet, we suspect that BG will continue to hold a strong balancesheet, while adding both regasification entry points and trading expertise (people).

El Paso twist?El Paso’s global LNG assets are up for sale. Dominated by actual and potentialregasification capacity, the package also includes the offtake rights for 2.5mt/year(300mmcf/d) of LNG from Trinidad Trains 2 and 3. Given BG’s immediately availableLake Charles import capacity (500mmcfd now, at least 630mmcfd by 2005), is it abuyer for this contract? Would BG be willing now to take on that internal take-or-payobligation? Assuming a 10c/mf trading margin for El Paso, we estimate that thewholesaling rights on the contract could cost a new buyer $200m. El Paso’s otherLNG purchase contract is the right to take 1.8mt/year (220mmcfd) from Norway’splanned Snøhvit project (probably of no interest to BG).

In terms of currently operating assets, the company has 760mmcfd of USregasification capacity at Elba Island and Cove Point (we doubt that BG could add thisentirely on an anti-trust basis, but it could be worth over $700m on the basis of recentdeals). Proposed regasification projects include two in Mexico: one on the east coastwith Shell for domestic use (Altimiria); and the other on the west for onward pipelineexport to the US. While we understand that Shell’s Altimira could be approved soon,the other looks some way down the queue (behind Marathon and Sempra). SinceBG’s interest is associated with the Sempra project (it would connect to BolivianLNG), we doubt BG would be interested in this piece of the portfolio.



More speculatively, El Paso has also proposed a regasification point in the Bahamasfor linkage into a Florida-bound pipeline system. It also has the rights to one of theproposed technologies for floating regasification – the “Energy Bridge” project.Again, we doubt whether BG would be interested in this project.



Egypt: first to market

From explorer to producerBG has been active in Egypt since the late 1970s when, as the old British GasCorporation, the company was a preliminary adviser to the government on thepotential gasification of the economy. Modern involvement really began in 1995when, under the previous E&P management, BG took 40% and 50% stakesrespectively in the Nile Delta exploration blocks Rosetta (with Shell and Edison) andWest Delta Deep (“WDDM”, with Edison).

BG began exploring the acreage in 1997 and has so far delivered an explorationsuccess rate of almost 100% for the discovery of 10 major gas fields. Initialdevelopment efforts were focused on the more-inshore Rosetta field, which cameonstream in January 2001. The project sells all of its gas into the highly-lucrativedomestic gas market (where Egypt has offered both generous prices and tax termsto accelerate the gasification of the economy). This market will also take the firstphase of production from the Scarab/Saffron fields in the WDDM block (dueonstream end March/early April 2003). We estimate that these two projects havefull-cycle rates of return in excess of 35%.

Figure 9: Egypt: west versus east

Alexandria Port Said

El Qantara

Libra

Fayoum

Saurus

Baltim NE

Simian

Tersa

Sienna

Taalab

Abu Monkar

Ringa

Taurus

North Idku

Busseili

Serpent

SapphireSequoia

Denise

Akhen

Qantara

Seti Plio

12" oil

AmyriaTerminal/LPG Plant

AmyriaRefinery

Mex RefineryAlexandria

24" w

et ga

spip

eline

20" g

as p

ipel

ine

Abu

Qir

- Dam

anhu

r

20" gas

20"/28" gas pipeline

Abu Qir-Tanta

plan

ned

pipe

line

to Id

ku

IdkuGas Plant

24" gas

12" oil pipeline

Gulf of Suez-Cairo-Alexandria

12" & 22" gas pipelines8" condensate pipeline

Talkha distribution station

16'' gas

28" g

as pi

peline

12" gas pipeline8"

cond

ensa

te lin

e

Abu M

adi/Q

ar'a-T

alkha

-Tan

ta

24" gas pipeline8"

14"

30" gas pipeline

Ha`py-W

est Harbour

wet gas pipeline

Tem

sah-El G

amil

24" gas pipeline

24"

planned gas

36" gas

10"+4"+3"

gas

14"+3"gas

plan

ned

12"

gas

12" g

as p

ipel

ine

Por

t Fou

ad-E

l Gam

il

36" InterSinai gas

16" gas

42" gas

planned 20" gas

ABU QIR

WEST ABU QIR

NORTH ABU QIR

SCARAB

ABU MADI WEST

ROSETTA

P1

P2

BALTIMSOUTH

EL QAR`ANORTHWEST

SAFFRON

EL QAR'A

ABU MADI

EAST DELTA NORTH

HA`PY

EAST DELTA SOUTH

BALTIMNORTH

BALTIMEAST

NIDOCO

EL WASTANI

TUNA

MYAS

TEMSAH

ASFOUR

KARAWAN

KAROUS

SETH

DARFEEL

PORT FOUAD

WAKARABU SEIF

BARBONI

BARRACUDA

NOURAS

SEGAN

Wepco

GEOGE BG

BP

Open

BG

BG

BP

BP

BP

Wepco

BP

Shell

MedGas

Open

MedGas

MedGas

MedGas

Open IEOCPetroDelta

Odyssey

INA Naftaplin

Petrobel

Nidoco

MedGas

Open

Odyssey

Open

PetroDelta

Nidoco Centurion

PetroTemsah

PetroTemsah

BP

MedGas

PetroTemsah

PetroTemsah

Open

IEOC

Petro-Said

RashidArea 2

WestMediterranean Deep

South Delta (24)

NorthAlexandria Block C

West Delta

RestrictedArea

Northwest Damietta

Ras El Barr

Ha'py

West Delta Deep

North AlexandriaBlock B

North Alexandria Block A

North Idku

Rosetta

RashidArea 1

NorthSinai

Res

tric

ted

Are

a

Res

tric

ted

Are

a

El Mansoura

AbuMadi West

Abu Madi

El ManzalaKhilala

Baltim E

Northeastern Desert

Tuna

Port Fouad

Denise

North Bardawil

Karous

Seth




BG’s domestic gas projects contain at least 5.3tcf of gas, which will be supplied intothe domestic market over a 20-year period. BG’s luxury (or problem?) is thatexploration activity in the WDDM permit in particular has yielded a further 12tcf ofgas reserves. As these discoveries were being made, it became increasinglyapparent that Egypt’s local demand was well-supplied by existing contracts out to2008. If BG’s growing excess of gas was not to form part of a long queue behindother (Eni, Shell, Apache and BP) projects, the company had to find an alternativeroute to gas commercialisation.

From late 1999/early 2000, it became increasingly apparent that BG was going tofocus on the development of LNG as its alternative sales route. Rival projects hadalready been mooted by Shell, Eni and BP, and Shell had also proposed a gas-to-liquids plant for the local distillate market. Although the other players had a longerhistory of activity in Egypt, and more demonstrable project management and marketskills, BG won the race to the first (conventional) LNG project in January 2002.

We find it hard to not to conclude that BG’s greater focus on the opportunitydelivered its success. Also notable, however, was BG’s local commitment to thedownstream Nile Valley Gas Company for the gasification of parts of Upper Egypt.Moreover, our economics also suggest an integrated project rate of return onEgyptian LNG phases I and II of around 12%. Although not uncommon for a long-lead time gas project, this rate of return is clearly below that commonly expected fordeepwater oil or even some of the development-led projects on offer in OPEC andthe FSU. In the interests of generating a longer-term global LNG position, it ispossible that BG’s thresholds for investment were set below those of companieswith a wider range of international opportunity.

Figure 10: Egypt returns: bit less money to go around

0%

5%

10%

15%

20%

25%

Trinidad Egypt

Proj

ect r

ate

of r

etur

n

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The LNG project structureEgyptian LNG has essentially been constructed as a “tolling facility”. This meansthat it forms part of a cost chain from the end-user price back to the wellheadupstream price. This is different to Train 1 in Trinidad (where the LNG plant itselfgets a piece of the variable end-user price), but matches its subsequent expansions.We understand that the downstream facilities in Egypt have been set up to



generate a rate of return of some 8% nominal (i.e. the price charged for liquefactionis enough to cover costs plus an 8% return on investment).

Currently, the downstream consists of four separate companies. The “Egyptian LNGCompany” and the “Operating Company” will be involved in all aspects of LNGprocessing and export (owning things like the port facilities and providing thepersonnel). The “Train 1” company will own the actual 3.6mt/year of first phaseliquifaction capacity. All three of these companies are owned by BG, Edison (both35.5%), EGAS, EGPC (both 12%) and GdF (5%). The fourth company is theemergent “Train 2” company, which will presumably have BG, Edison, EGPC andEGAS as partners as well as (possibly) the as-yet-to-be-named LNG buyer.

This structure allows subsequent “trains” of capacity to be added to the projectwithout requiring an identical ownership structure each time. For example, if BPwanted to build a train on the BG site it could do that with 100% capacityownership, but lease (from BG and the original ELNG partners) access to theassociated facilities and operating personnel.

Figure 11: Egyptian LNG: project structure

Train 1

BG 35.5%Edison 35.5%

EGAS 12%EGPC 12%

GdF 5%

Train 2

Upstream

West Delta DeepBG 50%

Edison 50%

Upstream

New supplies from others??

Operating company


EGAS 12%EGPC 12%

GdF 5%

ELNG (port facilities, site)


EGAS 12%EGPC 12%

GdF 5%

Train 3...and so on

???BG 35.5%

Edison 35.5%EGAS 12%EGPC 12%

XXXXX?

GasServices


LNG sales and supplyThe first train of LNG has been sold to GdF on a 20-year contract for first deliveriesin Q3 2005. While no delivered price has been released, we estimate that the figurewill be around $2.75/mcf at an $18/bbl Brent benchmark price.

The gas supply will come from the Simian Sienna discoveries that lie to the northeast of the about-to-start-up Scarab Saffron development. We estimate that Simianand Sienna contain around 5.5tcf of gas, of which 3.6tcf will be needed to supplythe GdF contract. The upstream gas price will reflect the end-user price less the



cost of regasification (thought to be around 25-30c/mcf), shipping (around 25c/mcf)and liquifaction (we estimate up to $1.45/mcf to generate an 10% return on the$1.35bn of capex). The resulting wellhead price of $0.75/mcf is much lower than thedomestic gas sales price ($2.50/mcf at $18 Brent). Nonetheless, thanks to the lowdevelopment cost, project returns still (just) clear BG’s 15% hurdle rate for newupstream projects.

The second train of LNG has yet to be officially sold. However, with BG announcingvarious co-operative agreements with Enel this year, and getting close to launch onthe Brindisi regasification project, it looks highly likely that Italy will buy some of thegas. BG’s past comments about wanting some of its own equity gas to trade intothe Lake Charles regasification facility in the US also suggests that BG will takesome of the volume onto its own balance sheet.

It is possible that incremental production from a mix of Scarab, Saffron, Simian andSienna could initially supply the additional 480-500mmcfd needed for the secondLNG train. More likely, however, BG will begin to develop other discoveries on theWDDM block – of which the 4.3tcf Sapphire field directly adjacent to the ScarabSaffron facilities looks the most likely.

The second LNG train will benefit from much lower ($550m) costs than the first.Given the netback system that applies to the wellhead price, this should generatemore attractive upstream returns for the expansion. If the gas is sold into Europe,the downstream costs could again range around 50-60c/mcf for shipping andregasification, while the plant may require only 70c/mcf to remunerate the capex.This could generate a wellhead price of up to $1.50/mcf (using the $18 Brentbenchmark). Alternatively, it opens the way for BG to trade gas into the US. Whileshipping and regasification costs could amount to a far higher $1.40-1.60/mcf,access to a higher priced market (perhaps $3.20-3.50/mcf versus Europe’s $2.60-3.00/mcf) could still leave $1.00-1.10/mcf for the upstream.



Figure 12: LNG: the global cost stacks

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00

Trinidad II & III (BP)

Indonesia Bontang I (IX)

Trindad II& III (BG)

10 Year Henry Hub Average

Nigeria IV-V

Venezuela

Nigeria III

Algeria

Egypt LNG II

Abu Dhabi

Pacific LNG

Trinidad I

Qatar Rasgas III

DB 5 Year Henry Hub Forecast

Indonesia Tangguh

Qatar Rasgas

Oman II

Nigeria I-II

Malaysia Tiga

Egypt LNG I

Iran

Oman

Norway Snoevhit

$ per mmbtu

Upstream at 15% Pipe Plant Shipping to Lake Charles/California Regas.


Our base-case economics for the first two trains of ELNG supplied from WDDMassume a weighted average gas price of around $1/mcf. This generates a projectIRR of 18%. Combined with a 10% return on the $1.9bn due to go into thedownstream, our numbers suggest that the integrated cash return on ELNG forBG’s net shares is 12-13%. This relatively low figure emphasises the importance toBG of keeping the LNG capex off balance sheet (see later), and potentiallyenhancing returns either through incremental spot sales into peaks in the US gasmarket – or further project expansion.

Expanding ELNG – does BG have enough gas?If we assume that all of Rosetta and Scarab Saffron’s 5.5tcf of gas reserves flowinto the highly priced domestic market, that leaves BG with 12tcf of discovered(proven plus probable) reserves for export. Each of the planned trains requires 3.6tcffor a 20-year supply deal. In theory, that would leave 5tcf – sufficient for a third train.

There are, however, various constraints on this straightforward calculation. Mostsimply, if BG’s acreage really contains no additional gas, we suspect that theeconomics might favour the extension of the contracts on the first two trains out to30 years – a more realistic view of the operating life of the physical machinery. Suchan approach would leave only 1.2tcf of spare gas – insufficient for a third train.



The position of the Egyptian government is more difficult to read. Originally, thepromotion of the gas industry in Egypt was all about the gasification of the economyand the substitution of expensive dollar-denominated crude imports. Recently, withthe prospect of LNG pushed hard by the industry, the focus has switched toattracting in investment capital and generating a new flow of dollar-denominatedexports. Looking forward, unless BG and the other upstream companies start to findyet more gas there is a risk that government concerns could reverse.

Figure 13: Egypt gas: sustaining the surplus needs more exploration

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2000 2005E 2010E 2015E 2020E

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Gas demand Contracted prodnAccelerated develpmnt (domestic use) Export-led develpmnt


Our simple estimates concur with published views that Egypt is long of contractedgas to around 2008, and has more than enough in reserve to see it through to 2010-2012. However, much beyond that and the export of LNG through BG’s scheme andthe rival Fenosa/Eni plant (see later) could start to leave the domestic market short.

We estimate that Egypt’s current discovered gas reserves are around 55-60tcf. Ofthis, around 10tcf have been used already, 10tcf will go into the domestic marketuntil 2010, and another 10-11tcf has been committed to LNG exports. Theremaining 27tcf gives a ratio of 16-17 years of domestic use at the forecast 2010consumption rate. With energy and dollars of such great concern to the Egyptiangovernment, we may need to see another burst of exploration activity before BG isgiven the right to allocate any more reserves for export.

The alternative to BG-only LNG exports is to aggregate the discovered volumes ofothers into a new expansion. Both BP and Apache have undeveloped gas nearby.BP has found around 5tcf in its North Alexandria acreage (although we understandthe block’s tax terms are punitive) and may have a new trend in the WestMediterranean Deep block. Apache has also found 1-2tcf so far in a new trend in itsWest Mediterranean Block 1. These finds are around 70km offshore BG’s LNG siteat Idku. In addition, Shell has a very large block located in the deeper waters to thenorth of WDDM. Early drilling was unsuccessful, but we understand three morewells are planned close to the BG acreage this year.

The attraction of this (and any other uncontracted gas) to BG’s expansions isundoubtedly complicated by the ongoing construction of another LNG plant on theeastern part of the Nile Delta. This Union Fenosa-promoted scheme (known by its



location at Damietta) was a surprise entrant to the Egypt LNG race in 2000.Nonetheless a combination of Fenosa bringing a guaranteed market in the form ofits own gas-fired power generation needs in Spain, coupled with the (somewhatunclear) involvement of the Egyptian authorities, got the plant off the ground. Theconstruction contract was awarded in January 2002, and activity is apparentlyunderway to meet a first deliveries target of Q1 2005.

Gas is to be supplied to Damietta straight off the national gas grid by state-ownedEGPC. Given that this gas is sold to the grid (by BG, BP, Eni, Shell and all of theother local producers), at the high domestic gas price, we remain unclear as to howthis is compatible with a profitable LNG project (which needs very cheap gas asfeedstock). It has been suggested that “blending” the company volumes with theessentially free profit gas taken by the Egyptian government in the form of tax fromthe company concessions would effectively lower the cost of this gas. Quite whythe government would do this, and for what alternative gain, remains uncertain.

Eni entered the Damietta project as operator last December following its acquisitionof 50% of Fenosa’s gas subsidiary. While Eni (Egypt’s largest and oldest foreignproducer) has yet to be more forthcoming on the project structure, we aresomewhat happier now that the ultimate development will be a sensible one.Indeed, we wonder whether the eventual outcome will be a direct gas feed fromthe offshore gas production of Eni, BP and Shell that bypasses the grid and allows amore transparent pricing structure. Further confirmation of this potential shift couldlie in Eni’s recently announced expanded exploration programme for Egypt in 2003.

For BG, the increasingly concrete Fenosa project is undoubtedly an annoyance.While both parties argue that Egypt can sustain two projects – one for the westernDelta, and the other from the east – the plants are a mere 160km apart. If BG’s sitecan really take six trains, the building of a $200m (or so) pipeline link to ELNG mustsurely make more economic sense than a second $1bn facility. The more gas eachplant can attract, the higher its expansion returns.

Figure 14: Egypt: remaining gas reserves by company

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With government concerns about over-exporting its resources potentially on therise, the battle for the next LNG expansion is shaping up to be as hard fought as thelast. With almost 60tcf discovered in Egypt to date, it is very possible that as muchagain waits to be found – but it needs to stay cheap and easy to develop if it is tocompete with the almost endless reserves of Algeria, Nigeria, Qatar.....

Tangguh: more knowledge than powerBG entered the Muturi PSC in Indonesia as operator in 1992. Although this followedthe discovery of gas in the adjacent acreage by Occidental in 1990-91, activity in theregion only took off following the entry of ARCO (now BP) in late 1993. By August1994, ARCO had discovered the giant Wiriagar Deep gas field (over 4 tcf) on theBerau and Wiriagar PSCs. Then in 1997, ARCO found the very large Vorwata fieldthat overlaps from Berau into BG’s Muturi licence. Today, the three adjacent PSCsare thought to contain in excess of 24tcf on a proven plus probable plus possible(3P) basis, of which BG’s net share currently stands at 11%.

Plans for an LNG plant began emerging around 1995, and gained added vigour whenBP took out ARCO in late 1999 (the SuperMajor now holds 39% of the project).

While there is absolutely no likelihood of Tangguh’s huge gas volumes beingconsumed locally, at least it has been found in a country with a strong track recordin LNG development. Bontang (TOTAL/BP/Eni) is now the world’s largest LNG plant,and ExxonMobil’s Arun was a leader in its time. Nonetheless, Tangguh has (and stillis) stuck in a long queue of “stranded gas” waiting to get into the markets ofnorthern Asia – or even the US. Tangguh is competing against cheap expansions ofplants such as the local Bontang, nearby Malaysia and the more distant AustralianNorth West Shelf. In addition, it has new-build competitors in Shell’s RussianSakhalin, Austrialia/Timor’s Bayu-Undan and even Bolivia’s Pacific LNG.



Figure 15: Tangguh: in the LNG hotbed

Ubadari

Vorwata

RoabibaWiriagar Deep

Ofaweri

Wos

BP

BP BG

BP

Pertamina

Babo

Berau

Wiriagar Muturi

West Arguni

Java

Java Sea

Natuna Sea

MALAYSIA-Sarawak

Kalimantan

MALAYSIA-Sabah

MakassarStrait

Sumbawa

Mindanao

Sulu Sea

Bali

Flores

Sulawesi

Sumba

Timor

Wetar

EASTTIMOR

Banda Sea

Seram

CelebesSea

MoluccaSea

Arnhem Land

Arafura Sea

Tanimbar

Aru

Irian Jaya

Bintulu

Bontang

SunriseBayu-Undan

The Tangguh fields


Priced to goTangguh’s strengths lie in its location and costs. The project is in shallow waters,the reservoirs are high quality and the gas is low in CO2 and sulphur. As a result, weestimate that the upstream can (just) clear the traditional 15% returns thresholdwith a $0.5/mcf wellhead gas price. In terms of location, Indonesia is relatively nearto the gas markets of North East Asia. Tangguh will also benefit from the (now)terminal decline of the Arun LNG project, and the increasingly notable lack of spacefor more trains at Bontang. If Indonesia is to maintain its strong track record interms of reliability of supply, the state company, Pertamina, should want to favourTangguh purely in the name of diversified risk.

We estimate that the cost stack for Tangguh on top of the 50c/mcf welhead price,assuming shipping to north Asia, should be around $1.25/mcf for the plant, 65c/mcfof shipping and 35c/mcf of regasification. This would generate a delivered cost ofaround $2.75/mcf. Prices in North East Asia, in an $18 Brent environment, havehistorically been around $3.00/mcf, indicating a good margin for those LNGproducers who actually succeed in signing contracts (or some leeway for Tangguhshould more competition actually start to bring prices down).

Owners and marketersSince BP took over the project, there have been several changes of ownershipstructure – all apparently geared at LNG sales. First, BP increased its stake to 50%,and then the Japanese trading houses of Mitsubishi, Kanematsu and Nissho Iwaiestablished a combined holding of almost 40%. Most recently, CNOOC took 12% ofBP’s holding. This last move was directly linked to the Chinese decision to award



Tangguh at least part of the supply contract for the country’s second plannedregasification terminal at Fujian.

BP has been actively lobbying for this access for some time (and indeed wasdisappointed to lose the first import contract to Shell’s North West Shelf). TheSuperMajor has a variety of downstream interests in China and clearly sees this as agame of long-term return. For now, however, Tangguh is still not assured. TheChinese have committed to buy only 2.6mtpa (or only 70% of the size of BG’s firsttrain in Egypt). Tangguh needs more to get off the ground. Until it unlocks suchpurchasers in (Japan, South Korea, Taiwan?), the tentative start-up date of 2007 stilllooks optimistic, in our view. In addition, the reported Chinese price of $2.50/mcf(including shipping) would reduce Tangguh’s wellhead price right down to the50c/mcf we see as the minimum upstream threshold.

Figure 16: Reserves ownership in Tangguh

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Should I stay, or should I go?In our view, BG in Tangguh has echoes of Kashagan. While this is clearly a gasproject in a business of core interest to BG, it fails in many other ways, in ouropinion. The company only has a 10% stake and virtually no other interests in Asia.It hardly seems to fit the company’s preference for control, with timing andmarketing (and probably erosion of upstream profitability to favour a long-termdownstream strategy in China) being run by BP.

BG’s disposal of 16.67% of Kashagan (for $1.23bn) was slightly accretive to the“risked” value we carried in our estimate of group NAV, but a slight discount to theplain “unrisked” discounted sum of our field cashflow. Over the years, we havefound that applying a “risk factor” to some of the more uncertain projects within ourcore value estimates provides a more accurate reflection of the industry’s appraisalof value – and allows the discount to unwind as the operator proves up thecommerciality and timing.

Our value of Tangguh is similarly “risked”. Our base case starts up in 2007, butexpands over the succeeding years to a four-train project. We risk this value with a60% weighting – to give a value of $2.65bn for the entire project and £195m(5.5p/share) net to BG. The most recent deal in Tangguh (CNOOC’s 12%) valued the



project at only $2.2bn (implying 4.6p/share net to BG). However, we believe thatCNOOC achieved this price in exchange for allowing BP greater access to theChinese market. A more representative comparison might be the $2.9bn implied bythe 7% bought by Mitsubishi in late 2001.

Either way, while the deal is not of a similar scale to Kashagan, realising £160-200mfor a still-dormant asset would again improve BG’s near-term returns, managementfocus and valuation.

Pacific LNG: rainforest dream (or is that nightmare...)In a mirror image of Egypt, BG first entered Bolivia as an explorer in 1995. It farmedinto the then-Chevron operated Caipipendi licence in southern Bolivia for a 35%stake. Lying just over the border from the hugely gas-prolific Noroeste Basin inArgentina, the key issues have always revolved more around commercialisation thanactual discovery. Argentina has plenty of its own gas, so where would any new gas(rather than oil) discoveries find a market in the centre of the Southern Cone?

Brazil firstThe Caipipendi partners discovered the Margarita gas field in 1997, and subsequentappraisal now puts reserves close to 15tcf. Shortly after the Margarita discovery,however, Petrobras discovered the equally vast San Alberto (1998, 11tcf) and SanAntonio (1998, 6tcf), with TOTAL completing the quadruplet in 1999 with the 10tcfItau.

In terms of commercialisation, the Petrobras fields (in which BG has no equity) havea clear lead. The Brazilian market was the obvious choice, and the required Bolivia-Brazil pipeline (BBPL) was completed in 1999 amidst great hopes of the rapidgasification of the oil and hydro-reliant Brazilian economy. To date, only San Albertoand San Antonio can really be classified as “onstream” and feeding this market.

BG responded to the commercialisation challenge with a series of additionalinvestments. In 1999, it took operatorship of the privatised Comgas – probably thekey gas utility in Brazil located in the heart of the industrial city of Sao Paulo. In thesame year, the company acquired Tesoro’s interests in Bolivia: a stake in the Itaufield, but more importantly 100% of two small -–but actually producing – gas fieldslocated just to the west of the new discovery trend. These projects brought accessto the Bolivia-Brazil pipeline, and thus a link to Comgas’ downstream demand. Thecompany has since added to its transportation rights through the auctioning of spareBBPL capacity.



Figure 17: Bolivian gas: big volumes searching for a market

Icua

Churumas

Ibibobo

Supuati

Huayco

Itau

MADREJONES

CAIGUA(shut in)

SANANDITA(shut in)

LOS MONOS(shut in)

SAN ALBERTO

SABALO

VUELTAGRANDECAMATINDI

MARGARITA

CHACO SUR

PALO MARCADO

MADREJONES

MACUETASUR

CAMPO DURAN

IPAGUAZU

VILLAMONTES

LOS SURIS

SAN ROQUE

TAIGUATI

ESCONDIDO

LA VERTIENTE

ÑUPUCO

Base for Pacific LNG

BG’s current sales to Brazil

Petrobras exports

Petrobras exports


Ships not pipesDespite these integrating moves, Brazilian gas demand has not developed atanything like the pace expected. As a result, the Margarita partners (Repsol, BG andBP), have developed a potential LNG export project. The plan would see gas fromMargarita (and probably also the TOTAL/Exxon/BG Itau) flow west through Chile tothe coast, be liquefied and shipped to Mexico, and then regasified and piped toCalifornia. In terms of the number of borders crossed, this is already a difficultproject – but given that one is the historically disputed Bolivia/Chile line, it carriesextra political complexity.

Politics aside, we believe the project does appear to make economic sense. Thefields clearly contain the vast gas reserves needed to commercialise an LNG plant.As importantly, the gas is very rich in liquids (condensate and LPG) that can bestripped from the gas at the coastal processing plant. This highly valued liquidsstream creates an effective cross-subsidy for the gas chain. Indeed, we estimatethat the fields can generate a cash return of some 20% with a wellhead LNG priceas low as $0.5/mcf.

If we take this 50c/mcf as the base price for the upstream, and add to it the costs ofliquifaction and a cross-Andes pipeline ($1.50/mcf for a two train (1bcf/d) plant),shipping (up to 60c/mcf given the distances involved) and the regasification/piping



from Mexico to California (perhaps 50-60c/mcf), we estimate that Pacific LNG canmake it to California for $3.20/mcf. Given that this would equate to a Henry Hubprice of around $3/mcf, the economic premise does not look unreasonable, in ourview.

More homeworkIn terms of risk, however, the project is clearly more vulnerable than a simple pieceof coastal export from Trinidad or Egypt. Even if BG were able to keep the vast bulkof the capex off balance sheet, an integrated project return similar to Egypt’s12-13% would be too low in our view. An upstream return of 25% (as opposed toour base case 20%), would require a wellhead price closer to $0.75/mcf, butgenerate an integrated project return closer to 15%. Can the consortium squeezeproject costs lower – or convince the market of higher US gas prices – to generatethis returns shift?

Recent comments from Mexico that it is indeed treating the regasification requestfrom Sempra (the proposed US buyer of Pacific LNG volumes) seriously doessuggest this project could begin to move soon. Nonetheless, the potential politicalimplications for any Bolivian leader that forgives Chile for stealing its coastline in thelate 1890s cannot be underestimated.



Lake Charles and Brindisi –how might they work?In this section, we discuss BG’s position in regasification – the point of marketaccess for global LNG. The assets will most probably earn a utility-like processingfee – but carry the potential for higher returns if BG can access more volume andbegin to optimise the carriage of global LNG between continents.

Regas: the last linkA regasification terminal is one of the simplest parts of the LNG chain. It merelyallows tankers to offload their LNG into vaporisers that return the liquefied gas to agaseous state ready for use. There are various new regasification terminals beingbuilt around the world today, and most cost in the range $300-400m (compared tothe first phase of a similarly sized liquefaction plant that could cost around $1bn). Inmost markets, regasification is not a delivery bottleneck. Where it is, this occurs dueto intense environmental (or more recently, security) lobbying.

The “next big thing” in regasification is expected to be offshore facilities. Byplugging floating capacity (in the form of the tankers themselves or receivingplatforms) into (often-existing) off-to-onshore pipeline networks, the securityconcerns would be relieved, and many of the environmental objections met. This isbecoming known in the industry as “over the horizon” – the ultimate in “not in mybackyard” solutions!

Although Edison had planned a floating LNG facility for northern Italy, this is now onhold (not least because of its estimated $500m cost). The most likely real test casefor floating regasification will be the US. This market is short of regasificationcapacity, yet is perfect for such imports. The market is substantial (and thus able toabsorb large quantities of gas without massive price distortions) and highly seasonal(thus willing to pay premiums for peaking supply).

As the US domestic supply curve begins to diminish against the prospect ofpotentially rising demand, LNG imports should provide the best answer. Volumescan come into the market to “peak-shave” the winter season (or any other pricespikes). Our analysis of global gas projects shows that over 1,000tcf of reservescould now reach the US as LNG at under $3.50/mcf – the benchmark long-term USgas price of many commentators. The sooner the US adds to its current 2.3bcf/d ofimport capacity (equivalent to less than 4% of total market demand), the quicker USgas prices are likely to stabilise.

BG and regas.For BG, access to regasification capacity creates an entry point into new markets.Without such capacity, BG’s LNG sales would almost certainly end at theliquefaction plant gate: it would pass the marketing and offtake risk to adownstream gas provider. With regasification capacity, BG can actually take its LNGproduction into end-user markets.

Most simply, this access probably makes BG’s LNG available to a wider range ofpotential buyers. Not all gas sellers would want to commit to buy a whole train’s



worth of LNG, but if BG can aggregate a set of smaller buyers, it can create amarket for its product. At a more complex level, the access allows BG to trade LNGon its own account. BG can then choose each month, or each year, where to sell itsLNG. Is Europe paying more than the US? Is California offering more than Korea...and so on.

Figure 18: BG and the world of regas.

Lake Charles

Brindisi

Pipivav

BG actual and possible LNG production sites

BG actual and possible regasification terminals

Existing regasification terminal

Possible new regasification terminals


Furthermore, a combination of different production facilities and regas capacity ondifferent continents (in BG’s case, Europe vs. North America) can allow BG tooptimise the physical transfer of product. For example, some Trinidad gas currentlygoes to Spain. BG may buy some of the Egyptian LNG expansion for sale in the US.Best solution: swap the cargoes so no gas molecule actually makes the cross-Ocean voyage. This could allow shipping costs of a combined $1.20/mcf, to bereplaced with $0.75/mcf. The implied saving of $1.2m on a standard LNG cargo issmall, but it could be a useful profit centre if applied, say, to all 65 cargoes/year thatGas Natural is contracted to ship from Trinidad to Spain beyond 2003.

Lake Charles: US gatewayIn late 2001, BG bid for and won the right to use the capacity of the Lake Charlesregasification facility in Louisiana. BG has the right to 81% of the current 630mmcfdof capacity until 2005, and then 100%. It also has the right to use all of Lake Charlesplanned expansion to 1.2bcf/d (probably around 2006-07).

In exchange for this right, BG says that it pays a fixed fee of $51m/year (equivalentto 27c/mcf assuming full use of the current capacity share) and a small (3-5c/mcf)gasification charge. BG is heavily incentivised to maximise capacity utilisation. Notonly does this obviously spread the fixed charge over the largest number of units,



but it also prevents others from accessing the plant. The terminal owner CMS hasthe right to re-offer any capacity that BG does not use. Thus if BG leaves capacityopen because it cannot acquire enough LNG to trade, others can enter the marketand thereby reduce the effective market price for gas.

Other than some of the commissioning volumes of Trinidad Train 2, BG currentlyhas no gas of its own to trade into Lake Charles. To fill the terminal, BG mustapproach sellers such as Nigeria, Algeria or Qatar and offer them the opportunity toship surplus cargoes. We understand that BG has been undertaking most of thesetrades on a “pass-through” basis. The original seller thus takes the end-user gasprice, but passes BG a “facilitation” fee in exchange.

The numbers do not suggest that BG covered its costs at Lake Charles in 2002. Thisis not surprising for a start-up business. Not only has BG not been able to accessenough cargoes to fill the plant, but it has (apparently) suffered from discounted hubgas prices. With only one pipeline link from Lake Charles to the adjacent Henry Hubgas exchange, traders have “seen” BG’s cargoes coming and have priced themarket down at the appropriate moment. Over 2003-04, prospects should improve.The US gas market is again looking strong, BG’s trading team has been enhancedand more pipeline links to other trading hubs should be completed.

Into 2005-06, the Lake Charles proposition could begin to change once more. If BGdoes buy some of its own LNG from Egypt (or bids for El Paso’s ownership of2.5mt/year of Trinidad LNG, see page 15, the company will be able to trade intoLake Charles on its own account. This should enable greater capacity utilisation (anda lower unit fixed charge), while allowing BG to optimise its capture of (a probably)still strong US gas price.

Figure 19: BG’s position in US regasification

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

Everett Lake Charles Cove Point Elba Island

bcf/

d

Existing Expansion by 2005 Throughput 2002


Brindisi – the fourth legThe opportunity to trade gas into Lake Charles gains extra flexibility if its comes withan ability to trade gas into Europe. In the wake of a series of agreements in late2002, BG now appears close to a final investment decision on a regasificationterminal in southern Italy. Partnered with Enel, the Brindisi plant is due onstream in



2007, and should ultimately have 8bcm (770mmcfd) of regasification capacity (for acost of $300-350m).

Italy offers a large market with high seasonality (and thus demand for the flexiblesupply that favours LNG over long distance pipelines). Its peninsula status anddeclining domestic output limits the likelihood of significant over-supply. This,combined with the continued dominance of just a few large players (Eni, Enel,Edison), should provide relatively stable prices. The market is also extremely closeto Egypt, allowing BG to maximise the wellhead value of its LNG feedstock byminimising the shipping costs (estimated at only 20c/mcf).

The Italian regulatory regime demands that 20% of the terminal capacity is open toothers. The remainder can be retained by the developer, subject to a rate of returncap of 10%. Relative to Egypt Train 2 (planned size 5bcm), the first 4bcm phase ofBrindisi would allow 3.2bcm of imports net to BG and its partner.

In terms of the optimisation trade noted above, if Enel does become the partner, BGcould look at swaps between Nigeria, Egypt and the US. For example, Enel’scontracted LNG from Nigeria costs almost 80c/mcf to transport to Italy. In a goodyear, that could go to the US (into Lake Charles) for just over $1/mcf shipping, whileEnel took more volumes from Egypt only 20c/mcf away.

Over time, we would expect BG to add access to other terminals in Europe. Giventhat the company has shown little interest in Spain or in the proposals for UK regas,we suspect that it foresees no shortage of capacity - or complexity of access. Bothcountries (like the current import hub on the Belgian coast), are likely to offertransparent open access regimes, which BG can exploit as required.



Figure 20: European regasification terminals

Terminal under construction

Existing terminal

Proposed terminal

BilbaoBilbao

El FerrolEl Ferrol

Isle ofGrain

Isle ofGrain

BrindisiBrindisiSaguntoSagunto

RovigoRovigo

SinesSines

BordeauxBordeaux

FosFos

MontoirMontoir

HuelvaHuelva

MilfordHaven

MilfordHaven

BarcelonaBarcelona

ZeebruggeZeebrugge

CartagenaCartagena

La SpeziaLa Spezia


Widening the regasification rangeBG’s only other regas project on the table is at Pipivav on the west coast of India.BG has had this plan on the backburner since the late 1990s, and hassimultaneously been attempting to develop a downstream market through itsMahanagar and Gujurat Gas subsidiaries.

This project currently appears lost in a murky world of Indian bureaucracy.Nonetheless, BG has been making a huge (and very public) effort of late toemphasise its commitment to India. We wonder whether this is also linked withBG’s apparent progress in the Iranian LNG scheme. BG is emerging at the front ofthe queue to develop the liquefaction element of Iran’s super-giant South Pars gasfield. Clearly, this development will be enhanced for BG if it also the offtaker. IranianLNG could well be competitive into Europe (as Qatari LNG is), but the obviousmarket is India.

Whether BG emerges with its Pipivav regas terminal (estimated size 7bcm) or joinsthe partners of the existing terminals is uncertain. The rival import terminals are atDabhol (the old Enron plant, complete), Dahej (state-owned Petronet, complete) andHazira (Shell, under construction).



On the other side of the world, BG could end up a partner in other US regasterminals should it choose to join the bidding for El Paso’s LNG assets (thecompleted Cove Point and Elba Island US terminals and a share in Shell’s plannedAltimira regas project on the Mexican east coast). In addition, Sempra (thedownstream offtaker signed up for the prospective Bolivia LNG project) could lookfor partners in its proposed west coast of Mexico terminal.



Cash: how does the moneyflow?In this section, we combine our project economics into volume and financialforecasts for the upstream and LNG divisions of BG. While our estimated integratedproject returns for BG E&P-LNG are not as high as those available, say, tosuccessful deepwater oil players, they are a multiple of the company’s WACC. In asector with very high barriers to entry, BG appears to have earned the “right toreplicate” and should continue to see the LNG division expand rapidly as newprojects – and elements of the LNG chain – are added. Overall, we see a businessresponsible for enabling 65% of BG’s upstream production growth 2002-08E, and,from the midstream assets alone, adding £130m to EBIT over the next five years.

The LNG division – a financial rationaleThe LNG activities of BG are essentially an enabling business that allows thecommercialisation of otherwise stranded gas. The base earnings of the assets existonly because they are sharing a piece of the price chain that feeds through from theultimate buyer of gas back to the upstream output. In our view, the trick for BGmanagement is to ensure that those upstream reserves chosen for LNG exportshave a high enough economic rent to support the midstream activity, withoutdecimating project returns.

In most respects, therefore, our earnings for BG’s LNG divisions are no more thanutility returns; a constant margin on the leased shipping fleet; a traders margin onregasification; and remunerated capital investment in the LNG plants. The divisionappears high growth only because BG is continuously adding new projects – lessbecause the existing assets are themselves becoming more profitable.

This “right to replace” is a key component of BG’s LNG strategy, in our view. Theoil and gas industry is full of very high barriers to entry: history, politics, balancesheets and project management expertise. Overcoming these is hard for anysmaller company. BG appears to have managed to scale the barrier in the LNGsegment.

The integrated project returns we estimate for BG’s LNG chains are in the 12-15%range, and are not comparable to the 20-25% rates of return we see on many of theindustry’s new oil developments – particularly in the deep water. Nonetheless, thereis a strong argument to be made that these higher returns are not available to BG –it has no useful track record with which to gain entry. Instead, the company isfocusing on a business that still returns more than the cost of capital, does allow itto achieve high growth, and ultimately may be attractive to a larger industry predatorwishing to round out its gas portfolio.

BG can keep its LNG business growing by continuing to access new projects. Egyptcould expand further. It may succeed with Bolivia and Indonesia. It may enter Iran orEquatorial Guinea. Our earnings estimates may also be too low in those yearswhere BG manages to unlock the trading potential of its portfolio. This could occurat Lake Charles if BG is able to access reasonably-priced spot cargoes in a boomperiod for US gas prices. It could also happen if BG can begin to optimise thecarriage of global LNG. Gas sources and market access points on both sides of the



Atlantic could eliminate unnecessary shipping, and thus unlock “free” profits (albeitsmall per cargo) for all concerned.

Unlocking productionThe most obvious effect of BG’s LNG business is to unlock production that mightotherwise be stranded by a lack of market. We expect BG’s LNG-enabledproduction to rise from 5,500boed to hit 175,000boed by 2008E. As a proportion ofthe company’s overall output, we estimate the “LNG-enabled” percentage shouldrise from 1% of group production in 2002 to 27% by 2008.

Figure 21: BG’s LNG-enabled production

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2002 2003E 2004E 2005E 2006E 2007E 2008E 2009E 2010E

000b

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30%

35%

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as %

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Trinidad Bolivia Egypt Indonesia as % total


Overall, we expect the LNG-enabled output to contribute two-thirds of BG’s totalgroup output growth over that six-year period (taking the group from 378,000boed in2002 to 630,000boed in 2008E). Interestingly, much of this expansion is back-endloaded. Further growth in Trinidad, or success in Bolivia and Indonesia, is unlikely tocontribute before 2007. Within BG’s target period (to 2006), the LNG-enabled outputrises to a smaller 50,000boed to account for a still-measured 10% of groupproduction.

LNG presenceFrom its rising gas output, BG is developing a presence in the traded LNG marketover and above its shipping capacity. We expect BG’s LNG output to rise from1.1mtpa in 2002 to reach 9.2mtpa in 2008E. Nearer term, we expect BG to exceedits 2.3mtpa LNG volume target for 2003 (we carry 2.6mtpa), but to find the 6mtpatarget for 2006 dependent on a fair wind behind current expansions (we carry alower 4.8mtpa average for 2006E but jumping to 8.1mtpa in 2007E).

To put these volumes in perspective, we see the global LNG market using some110mtpa in 2003E. Of this, the major trader is Shell with 10mtpa net – in our view,not an unreasonable target achievement for BG by the end of this decade.



Figure 22: BG’s LNG output

0

1

2

3

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7

8

9

10

2002 2003E 2004E 2005E 2006E 2007E 2008E 2009E 2010E

LNG

out

put (

net t

o B

G m

tpa)

Trinidad train 1 Trindad train 2 Trinidad train 3 Trinidad train 4

ELNG 1 ELNG 2 Pacific Tangguh

BG targets


LNG in the P&LAs noted above, our divisional LNG forecast represents the utility-like returns of theassets concerned, less a continuous new business expense. There may be yearswhen the environment delivers a more favourable trading environment, but we havenot included that upside in our medium-term forecasts.

Figure 23: BG’s LNG EBIT profile

-50

0

50

100

150

200

2000 2002 2004E 2006E 2008E 2010E

EBIT

(and

PB

T to

tal)

£ m

n

New business

Shipping/marketing

Brindisi

Egypt

Trinidad

PBT

EBIT


Within the division, we expect LNG EBIT to rise from £8m in 2002, to reach £140mby 2007E. For 2010E, we carry £175m, but that could be improved further bysuccess at Tangguh or Bolivia. Overall, this takes the LNG contribution to groupEBIT from 1% in 2002 to 10% in 2007E. In the very near term, we expect 2003earnings to jump notably (to £47m) thanks to the strong US gas price and the startup of Trains 2 and 3 in Trinidad.



Slightly less appealing than our implied 100%/year average growth in LNG EBIT, isthe impact on pre-tax profit. A key element of BG’s LNG strategy is the projectfinancing of individual assets. It is expected that Egypt and Brindisi will followTrinidad Train 1 in being formed as joint-venture companies with responsibility fortheir own financing. While this keeps the project capex off balance sheet, BG’s P&Lmust still bear the associated interest. Our estimates show this interest liabilityrising from £10m in 2002 to reach £35-40m by 2007E. This restricts the pre-taxprofit contribution to £100m in 2007E, from essentially break-even in 2002.

LNG returns and the off balance sheet effectOur previous publication, BG: Is there money in international gas?, June 2002,examined our view that many export-led gas projects are likely to be less profitable(with lower margins and returns) than the sale of conventional crude or gas into localmarkets. By its nature, the upstream has to bear the midstream costs of transportto market. In our view, only a few gas projects globally have low enough wellheaddevelopment costs to carry this extra burden, and remain as competitive asconventional developments. We would place Qatar, Nigeria, Algeria, Bontang andperhaps BP’s larger gas reserves in Trinidad in this category.

Our forecasts do show BG’s upstream business experiencing slight returns dilutionover time. This, in our view, reflects a mix of the upfront capital intensity of growth,and the shift away from old legacy projects into this new international gas stream.

Figure 24: BG’s shifting upstream production mix

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300

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2000 2002E 2004E 2006E 2008E 2010E

Prod

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00bo

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0%

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% U

K

UK Bolivia Egypt India

Indonesia Kazakhstan Thailand Tunisia

Trinidad UK proportion


It is important, therefore, that BG does not compound this upstream dilution withthe burden of the midstream assets. By keeping much of the LNG developmentcapital off balance sheet, it is the earnings stream, rather than the cost, which isemphasised. When combined with a steady improvement in the performance ofBG’s gas distribution assets, we do expect an increase in BG’s downstream returns(LNG, distribution, power) that offsets the upstream weakness. In addition, wesuspect that the more this downstream improvement can be sourced from the LNGbusiness, rather than customer utilities in Latin America and India, the higher thequality of the profile and the more responsive it will be to management control.



BG is clearly not alone in either its focus on group (over segment) returns, or itsfinancing routes for LNG projects. It has also attempted to be fair in its returnstargets by deducting the associates interest from the “return” element of groupROACE (not as dilutive as adding the capital, but intellectually honest). Nonetheless,when one takes into account all the capital being employed to drive BG’s above-average growth rates, the unavoidable “cost of growth” is clear.

Figure 25: BG’s divisional returns – willdownstream gas offset the upstream

Figure 26: BG’s group ROACE – choose youraccounting

5%

7%

9%

11%

13%

15%

2001 2002 2003E 2004E 2005E 2006E 2007E

Ro

AC

E/R

oFA

E&P G&P G&P with extra capital

off balance sheet capital "gap"

10%

11%

12%

13%

14%

15%

2001 2002 2003E 2004E 2005E 2006E 2007E

RoA

CE/

RoF

ARoACE (DB) RoACE (BG)

Source: Deutsche Bank estimates and company information Source: Deutsche Bank estimates and company information

As we illustrate in Figures 25 and 26, including all of the project finance capital in thedivisional returns of BG’s downstream gas business dilutes the results by awidening 1-4% over our forecast period. To show the impact of this on groupROACE we have added the extra capital rather than following BG’s method ofdeducting the associated interest. This results in a ROACE 1-2% lower than underBG’s methodology. Interestingly, the shift changes a pattern of high growth atconstant returns into one of slight dilution 2001-07E.

While these “fully-integrated” accounts may leave BG shy of the nirvana-like top-quartile growth and rising returns, set within a sector context, we believe BG’scombination remains better than most.



Figure 27: Sector returns vs. earnings growth 2003-07E

-4%

-3%

-2%

-1%

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2%

-5% -3% -1% 1% 3% 5%

EPS Growth % 2003E-07E

Cha

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in R

OC

E 2

003E

-07E

average


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Figure 28: BG’s net asset value as at 4 April 2003Remaining Reserves Net Asset Net Asset Net Asset

Field Risk Interest % Liquid mmbbls Gas bcf Oil Equ. mmboe Value £m Value p/share Value $mUpstream AssetsBolivia 140 6430 1212 343 9.7 514.4Los Suris & Palo Marcado 100.0 4 249 45 23.6 0.7 35.4Itau (risked 60%) 0.60 25.0 21 1538 277 56.7 1.6 85.1La Vertiente & Escondido 100.0 6 568 100 46.9 1.3 70.3Margarita (as LNG from 2008, risked 60%) 0.60 37.5 110 4075 789 215.7 6.1 323.6Egypt 1 8500 1417 1254.1 35.5 1881.1Rosetta 1.00 40.0 1 741 124 221.4 6.3 332.1Saffron, Scarab 1.00 50.0 0 1646 274 644.5 18.3 966.8Egypt LNG Train 1+2 1.00 50.0 0 3882 647 197.4 5.6 296.1Other uncontracted gas (10c) 1.00 50.0 0 2231 372 148.7 4.2 223.1Basic return on LNG infrastructure 1.00 35.0 42.0 1.2 63.0India 37 900 187 347 9.8 520Panna and Mukhta 1.00 30.0 30 100 46 170.6 4.8 255.9Tapti (development 70% risked) 0.70 30.0 8 800 141 176.0 5.0 264.1IndonesiaTangguh ( from 2007, 65% risked) 0.65 11.0 8 1664 285 211.0 6.0 316.6Kazakhstan 599 4449 1340 1921.2 54.5 2913.0Karachaganak 32.5 599 4449 1340 1231.4 34.9 1847.2Kashagan (sold 16.67%) 16.7 793.5 22.5 1230.0Tax on disposal at 30% -169.7 -4.8 -263.0CPC JV 2.0 65.9 1.9 98.8ThailandBongkot 22.2 10 674 122 266.5 7.6 399.8Tunisia 38 796 171 363.3 10.3 544.9Miskar 100.0 16 555 108 328.5 9.3 492.8Hasdrubal (Risked 75%) 0.75 100.0 22 241 62 34.8 1.0 52.2Trinidad and Tobago 0 3896 649 957.8 27.1 1436.6East Coast Marine Area (Dolphin) 50.0 0 1768 295 270.1 7.7 405.1North Coast Marine Area 45.90 0 1083 181 249.9 7.1 374.9Atlantic LNG Train 1 26.00 0 0 0 242.2 6.9 363.2Atlantic LNG Train 2 & 3 32.5 0 0 0 256.0 7.3 383.9Other uncontracted gas (10c/mcf) 1045 174 69.7 2.0 104.5Trinidad project debt (excluded from balance sheet) -130.0 -3.7 -195.0UKCS 250.4 1744.5 541.2 2276.2 64.5 3414.3Major UK developmentsBlake 44.0 19 0 19 102.2 2.9 153.3Buzzard 21.4 107 0 107 220.2 6.2 330.2Everest Lomond 59.5 12 380 75 641.2 18.2 961.8Armada 46.8 12 215 48 162.1 4.6 243.1Elgin Franklin 14.1 49 223 86 405.5 11.5 608.2Jade 35.0% 9 122 30 122.2 3.5 183.4Joanne 30.5% 8 93 23 104.0 2.9 156.0Judy 30.5% 3 46 10 64.8 1.8 97.2Minerva 65.0% 0 98 16 84.7 2.4 127.0Other fields various 32 568 127 369.5 10.5 554.2UK technical reserves various 32 537 121 61.7 1.7 92.6Other Upstream 0 434 72 14.7 0.4 22.0Stake in GAIL 1.00 0 0 0 7.5 0.2 11.2Israel (risked 25%) 0.25 various 0 434 72 7.2 0.2 10.8Total Upstream 1,115 30,023 6,119 8,016 227.2 12,055Source: Deutsche Bank estimates and company information

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Figure 29: BG’s net asset value (continued) as at 4 April 2003Remaining Reserves Net Asset Net Asset Net Asset

Field Risk Interest % Liquid mmbbls Gas bcf Oil Equ. Mmboe Value £m Value p/share Value £m

Midstream and Downstream Assets EV/EBITDA 2003E

Global T&D (DCF with upstream equiv. WACC of 10% nom.)) 10.9 1066.5 30.2 1599.7

T&D values by recent deals/market cap. (for reference only, not used incurrent corporate valuation)

989.5 28.0 1484.2

Comgas (Brazil) 60.0 751.2 21.3 1126.7

Gujurat Gas (India) 65.0 75.4 2.1 113.1

Metrogas (Argentina) 45.1 0.0 0.0 0.0

Phoenix Gas (N Ireland) 50.0 98.0 2.8 147.1

BBPL (Bolivia/Brazil) 8.1 26.7 0.8 40.0

PTL (N Ireland) 50.0 38.2 1.1 57.4

Other assets (UK Interconnector, Mahanagar, Cruz del Sur, NVGC)

EV/EBITDA 2003E

UK and International Powergen (DCF with 6% WACC, multiples) 9.5 776.3 22.0 1164.5

LNG (Lake Charles, Shipping, DCF) 0.75 114.2 3.2 171.3

Other project debt excluded from balance sheet -232.3 -6.6 -348.4

Total Midstream and Downstream 134.6 1724.8 48.9 2587.2

Corporate Effects 166.0 4.7 249.0

Cash/(Net Debt) end-02 estimate (ex-minority shares of Comgas/Metrogas) -808.3 -22.9 -1212.5

Core NAV 6,568.6 186.2 9,852.9

Risked Upside 2,530.1 71.7 3,795.1

Total NAV 9,098.7 257.9 13,648.0Source: Deutsche Bank estimates and company information

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Figure 30: BG profit and loss account (£m)Year end 31 December 1997 1998 Restated 1999 2000 2001 2002 2003E 2004E 2005E 2006E 2007E

Transco 1,119 1,224

BG Storage 9 7 -8 3 21 0 0 0 0 0 0

E&P 118 161 220 513 606 731 866 852 757 821 837

LNG -4 -9 -3 25 29 8 47 46 66 101 140

Transmission and Distribution 12 13 21 78 119 50 74 135 175 195 222

Power 22 29 47 102 104 124 127 128 130 131 132

Corporate and other 14 145 53 -33 -46 -25 -23 -24 -24 -25 -25

EBIT 1,290 1,570 330 688 833 888 1,091 1,137 1,104 1,223 1,305

Interest/Provisions -343 -416 -88 -80 -80 -80 -72 -61 -67 -85 -90

Exceptional Items 288 73 19 -34 149 -14 0 0 0 0 0

Pre tax Profit 1,235 1,227 261 574 903 794 1,018 1,076 1,037 1,138 1,215

Tax rate (%) 125 34 23 28 32 47.1 40.4 39.2 37.9 37.1 36.9

Tax -1,540 -414 -59 -161 -287 -374 -411 -422 -393 -422 -448

Group Net Income -305 813 202 413 616 420 607 654 644 716 767

Minorities -2 -8 -15 -19 -29 -10 -11 -24 -44 -58 -66

Reported Net Income -307 805 187 394 587 410 596 630 600 657 701

BG Adjusted Net Income -595 732 168 425 471 475 596 630 600 657 701

EPS (Reported) (p) -7.1 20.6 4.8 11.3 16.7 11.6 16.9 17.9 17.0 18.6 19.9

EPS (BG Adjusted/Clean) (p) -13.7 18.7 4.3 12.2 13.4 13.5 16.9 17.9 17.0 18.6 19.9

EPS growth (YoY) -237 182 10 0 26 6 -5 10 7

CFPS (p) 29.3 36.5 10.3 20.4 25.3 25.8 31.8 33.3 31.5 34.8 37.3

Dividend Per Share (p) 4.0 4.3 4.6 2.90 3.0 3.1 3.2 3.3 3.3 3.4 3.5

Dividend Payout Ratio (%) -57 21 95 26 18 27 19 18 20 18 18

Gearing (net debt/equity) (%) NM 40 9 11 15 30 10 8 8 4 1

Gearing (net debt/net debt+equity) (%) NM 29 8 10 13 23 9 8 8 4 1

ROACE (Post-tax) (%) -2 7 7 13 13.0 11.3 13.6 13.4 11.6 11.7 11.6

ROACE (normalised to BG) (%) 9.9 11.5 13.2 11.4 11.5 11.5

Oil Production (kb/d) 44 69 69 68 77 115 125 122 116 140 171

Gas Production (MMcfd) 698 1015 1035 1277 1326 1548 1861 2043 2176 2265 2558

Total Production (kboe/d) 161 238 241 281 298 373 435 463 479 518 597

Production growth (y/y) (%) 48 1 16 6 25 17 6 3 8 15

T&D volumes (net BG share) 3.1 3.2 5.0 7.3 10.6 11.5 13.7 16.7 18.6 19.9 21.7

Oil Price Forecast ($/bbl) 19.31 13.11 27.16 29.00 24.63 25.00 25.50 20.50 21.00 21.50 22.00

Gas Price Forecast (p/therm) 14.9 14.2 13.5 14.0 15.5 14.3 15.2 14.3 13.0 12.8 11.8

Exchange Rate ($/£) 1.64 1.65 1.58 1.52 1.45 1.50 1.60 1.50 1.50 1.50 1.50Source: Deutsche Bank estimates and company information

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Figure 31: BG cashflow (£m)Year end 31 December 1997 1998 Restated 1999 2000 2001 2002 2003E 2004E 2005E 2006E 2007E

Net income -305 813 202 413 616 420 607 654 644 716 767

Depreciation 1,041 961 402 622 392 395 475 503 507 559 637

Exploration expensed 61 16 28 0 13 10 25 45 55 70 75

Provisions, book (profit)/loss -624 -139 -63 -229 -44 -2

Other non-cash 1,102 -221 -168 -94 -90 88 15 -28 -94 -118 -165

Funds from operations 1,275 1,430 401 712 887 911 1,123 1,174 1,112 1,227 1,315

Disposals 108 121 653 475 17 624

Other/Shares Issued 15 -197 9

Sources 1,383 1,566 401 1,365 1,165 937 1,747 1,174 1,112 1,227 1,315

Exploration -182 -113 -113 -120 -180 -160 -160 -160 -160 -160

Development -813 -381 -580 -878 -820 -845 -895 -880 -765 -860

Capital expenditure -463 -995 -494 -693 -998 -1,000 -1,005 -1,055 -1,040 -925 -1,020

Equity dividends -537 -327 -348 -332 -103 -106 -111 -112 -115 -118 -121

Share buybacks -1,102 -39 0

Acquisitions -120 -802 -151 0 -396

Applications -2102 -1481 -1644 -1176 -1101 -1502 -1116 -1167 -1155 -1043 -1141

Working capital 53 -62 -1 164 -249 -111

Surplus/(deficit) -666 23 -1,244 353 -185 -676 631 7 -43 184 174

Net debt/(cash) 3,886 4,049 302 360 538 1,002 371 364 407 223 49

Shareholders funds 8,909 10,110 3,348 3,358 3,530 3,348 3,870 4,440 4,961 5,498 6,075

Net debt/equity (%) 44 40 9 11 15 30 10 8 8 4 1

Net debt/debt+equity (%) 30 29 8 10 13 23 9 8 8 4 1Source: Deutsche Bank estimates and company information

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Figure 32: International valuation matrix as at 4 April 20034 April, 2003 Price/ Earnings Ratio (x) Debt-Adjusted Cashflow Multiple (x) Yield

(Clean Earnings) Debt/(debt+equity) (%)

Debt/Equity

(%)

F'castDiv.

F’castDiv.

Yield

Earn'gsCover

CashCover

Company Price/ Price Rec. 2002E 2003E 2004E 2005E 2006E 2007E 2002E 2003E 2004E 2005E 2006E 2007E 2003E 2007E 2003E 2007E 2003E 2003E 2003E 2003ECurrency target

IntegratedUS/UK average 19.5 14.0 15.1 14.5 13.9 13.4 10.8 8.2 8.4 8.1 7.8 7.6 21 19 28 25 6.2 3.5 2.5 4.7OECD average 15.4 11.4 11.7 11.0 10.4 10.1 8.2 6.6 6.5 6.1 5.7 5.4 21 9 29 16 5.2 3.6 2.9 6.3Emerging Markets average 7.5 6.9 7.1 6.4 5.2 5.0 5.7 5.2 4.8 4.1 3.5 3.2 6 -14 20 -8 0.5 3.2 9.5 14.6Global average 10.8 9.5 9.9 9.3 8.5 8.3 7.1 5.9 5.7 5.3 4.8 4.5 16 1 27 7 6.9 3.4 5.4 9.6Three SistersBP 407.00 p 470 Buy 19.6 14.6 15.5 15.2 14.6 14.6 10.6 8.5 8.5 8.2 7.9 7.8 23 23 30 29 16.1 4.0 1.7 3.4Exxon Mobil 35.05 $ 40 Buy 22.3 17.7 18.5 17.9 17.1 16.6 12.2 10.3 10.5 10.2 9.8 9.5 5 9 5 10 0.9 2.7 2.1 3.7Shell RD 39.12 E 42 Hold 18.6 13.6 14.1 13.1 12.6 12.2 11.2 8.0 8.3 8.0 7.9 7.8 23 25 28 31 1.9 4.8 1.5 1.9Shell T&T 388.00 p 430 Hold 18.4 14.3 14.5 13.5 13.1 12.6 10.2 8.1 8.4 8.1 7.9 7.9 23 25 28 31 16.9 4.3 1.6 3.1Three Sisters Average 19.7 15.1 15.7 14.9 14.3 14.0 11.0 8.7 8.9 8.7 8.4 8.3 19 20 23 25 8.9 3.9 1.7 3.0European Mid CapsBG 250.25 p 265 Hold 20.4 14.8 14.0 14.7 13.4 12.6 11.4 8.0 7.8 8.2 7.3 6.7 9 1 10 1 3.2 1.3 5.3 10.0Eni 13.20 E 16.50 Buy 11.9 9.6 9.9 9.0 8.3 7.8 7.0 6.1 6.1 5.6 5.2 4.8 35 21.2 52 26.1 0.8 5.9 1.8 3.7Norsk Hydro 276.50 NOK 265.00 Hold 12.9 8.4 8.2 6.8 6.6 6.6 5.7 4.4 4.3 4.0 3.9 3.7 28 23 39 31 11.0 4.0 3.0 8.2Repsol 13.61 E 13.50 Hold 11.5 8.5 9.1 8.5 7.7 7.3 5.0 5.4 5.0 4.7 4.2 3.8 28 11 38 12 0.4 2.6 4.4 11.6Statoil 56.00 NOK 62.00 Buy 10.9 8.6 10.1 9.6 8.6 8.6 5.2 4.0 4.2 4.2 3.8 3.6 25 20 33 26 3.0 5.3 2.2 5.6TOTAL 123.80 E 140.00 Hold 15.9 11.8 12.4 12.3 11.7 11.5 9.7 6.6 6.5 6.4 6.1 6.0 15 10 20 15 4.3 3.5 2.4 4.7Mid Cap European Average 13.9 10.3 10.6 10.1 9.4 9.1 7.3 5.7 5.7 5.5 5.1 4.8 23 14 32 18 3.8 3.8 3.2 7.3US Mid CapsChevronTexaco 64.40 $ 60.00 Hold 18.4 13.5 16.7 16.3 15.2 14.0 10.4 7.3 7.8 7.5 7.1 6.7 24 15 32 17 2.9 4.5 1.7 3.4ConocoPhillips * 52.31 $ 52.00 Hold 18.9 9.4 12.1 10.7 11.4 10.8 9.6 7.0 7.6 6.7 6.8 6.5 38 35 60 53 1.5 2.9 3.7 7.6Occidental 30.62 $ 32.00 Hold 10.4 8.9 12.5 13.2 12.2 12.2 6.0 5.5 6.2 6.3 5.7 5.7 32 17 47 20 1.0 3.4 3.3 6.4Marathon 23.77 $ 20.50 Sell 14.6 8.3 9.9 10.2 10.4 10.9 5.0 3.7 3.9 3.7 3.7 3.8 37 21 59 27 0.9 3.9 3.1 9.6Mid Cap US Average 15.6 10.0 12.8 12.6 12.3 12.0 7.8 5.9 6.4 6.1 5.8 5.7 32.8 21.8 49.6 29.3 1.6 3.6 2.9 6.8CEE Refining & MarketingHellenic Petroleum 4.92 E 6.80 Hold 13.4 10.6 6.5 6.4 6.2 6.2 8.3 7.0 4.4 3.8 3.3 3.0 7 -22 8 -18 0.2 3.1 3.1 6.1OMV 103.90 E 99.00 Hold 8.5 7.7 6.7 6.7 6.8 7.5 5.2 5.4 5.0 4.9 4.9 5.2 28 29 37 40 3.4 3.3 4.0 6.9MOL 5290 HUF 6900 Buy 10.7 9.4 9.7 7.5 6.1 5.5 5.7 5.3 5.6 4.5 3.5 2.7 25 -18 35 -15 125.0 2.4 4.5 11.8PKN 17.20 PLN 19.00 Hold 13.2 9.9 9.2 8.1 7.2 6.8 3.5 3.9 3.3 2.4 1.6 0.9 6 -67 7 -40 0.48 2.8 3.6 9.1CEE Refining & Marketing Average 11.5 9.4 8.0 7.2 6.6 6.5 5.7 5.4 4.6 3.9 3.3 3.0 17 -20 22 -8 32.3 2.9 3.8 8.5Rest of WorldBHP Billiton 9.41 AUD 11.05 Buy 10.2 15.7 12.8 11.0 9.9 8.9 6.3 9.7 8.7 7.8 7.0 6.1 35 14 53 17 0.14 1.5 0.0 4.2Gazprom ** 12.10 $ 17.76 Buy 11.5 8.7 6.9 5.4 4.1 3.7 11.8 10.1 6.2 4.5 2.9 2.0 25 0 20 0 0.00 0.0 10.0 16.7LUKoil Holdings 14.06 $ 21.75 Buy 6.5 4.2 4.7 3.9 3.5 3.3 4.4 3.0 3.2 2.6 2.3 2.0 6 -4 7 -4 0.39 2.8 8.6 13.0Petrobras 16.53 $ 23.00 Buy 6.5 3.9 3.9 3.6 3.2 2.2 3.7 3.5 3.2 2.9 2.6 2.2 23 0 70 0 1.1 6.4 4.0 7.0Sasol *** 90.10 ZAR 135 Buy 7.1 4.9 4.5 3.9 3.4 3.0 7.7 4.9 4.0 3.6 3.0 2.3 20 -35 24 -26 3.2 3.6 3.5 3.3Surgut 0.29 $ 0.41 Hold 8.0 5.0 5.4 4.7 4.4 4.1 5.3 2.9 2.9 2.3 1.9 1.5 -58 -67 -37 -40 0.00 0.4 51.6 67.9Tatneft 0.84 $ 0.82 Hold 3.1 2.6 3.0 3.3 3.3 3.3 3.2 4.3 2.6 2.6 2.4 2.2 13 3 16 3 0.03 3.2 12.2 16.6Woodside 10.61 AUD 14.70 Buy 9.7 9.6 12.9 12.5 12.5 14.8 8.9 7.5 10.3 8.5 8.2 9.5 21 -10 27 -9 0.39 3.7 3.3 4.0YUKOS Oil 9.67 $ 11.20 Buy 6.4 5.9 6.8 5.9 5.6 5.4 4.4 3.8 4.1 3.4 3.0 2.7 -73 -68 -42 -40 0.24 2.5 6.7 8.0Rest of World Average 7.5 6.9 7.1 6.4 5.2 5.0 5.7 5.2 4.8 4.1 3.5 3.2 6.0 -14.0 19.8 -7.7 0.5 3.2 9.5 14.6* Conoco Phillips - Merged figures post 1 January 2002** P/E and forecast dividend based on ADR data*** Sasol data based on June year end data/estimates for the appropriate year.Source: Deutsche Bank estimates, Reuters and company information

8 April 2003

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Figure 33: Growth as at 4 April 20034 April, 2003 Compound Growth Yield/ Payout Size and Structure01-Jan-00 EPS Adj % Div. % Volume

boe %Div. YieldTo US Inv

%

PayoutRatio %

Mkt Cap($bn).

Ent Value($bn)

EV/2001Prov Res

StateO'ship

%

LargestS'hold

.%

CapEmp.($bn)

CapEmp

($bn).

EV/Cap.Emp %)

Price toBook

Ratio %

EarningsVolatility

IndexCompany 2003-07E 2003-07E 2003-07E 2003E 2007E 2003E 2007E Current

EstimateCurrent

Estimate2003E 2006E 2003E 2003E 1992-03E

IntegratedThree SistersBP -1.7 6.4 4.3 4.0 5.4 58 79 142.6 162.9 10 - 4 91.6 96.3 178 200 0.81Exxon Mobil 1.7 2.1 2.8 2.7 2.9 48 48 234.8 237.4 11 - 4 79.1 90.4 300 297 0.54Shell RD 1.5 3.9 1.1 4.8 5.6 62 68 87.92 99.29 5 - 3 50.2 55.5 198 220 0.38Shell T&T 1.5 3.9 1.1 4.3 5.4 62 68 59.10 66.68 3 - 3 33.4 37.0 199 222 0.38Three Sisters Average 0.8 4.1 2.3 3.9 4.8 57 66 131.1 141.6 8 na 4 63.6 69.8 219 235 0.53

European Mid CapsBG 2.5 0.9 7.6 1.3 1.4 19 18 13.9 15.4 10 - - 6.8 8.1 225 226 1.15Eni 5.2 4.0 4.9 5.9 6.9 56 54 53.5 64.0 9 30 30 46.7 49.6 137 179 0.69Norsk Hydro 4.4 2.6 5.0 4.0 4.7 33 31 9.8 13.7 7 44 44 14.9 17.7 92 89 0.55Repsol 3.9 8.7 4.6 2.6 3.7 23 27 17.8 29.0 5 - 10 27.7 29.0 105 93 0.48Statoil 0.3 0.0 4.5 5.3 5.6 46 48 14.3 17.3 4 82 82 12.2 14.0 142 150 0.37TOTAL -0.5 3.1 4.0 3.5 4.1 41 47 87.0 95.2 9 1 5 44.9 46.4 212 230 1.15Mid Cap European Average 2.6 3.2 5.1 3.8 4.4 36 38 32.7 39.1 7 25 22 25.5 27.5 152 161 0.73

US Mid CapsChevronTexaco -0.9 2.5 2.7 4.5 4.9 60 69 68.5 79.6 7 - 9 45.7 52.3 174 204 0.61ConocoPhillips* -3.3 6.1 1.3 2.9 3.6 27 39 35.5 56.3 12 - - 53.6 60.6 105 66 0.79Occidental -7.6 0.0 -1.6 3.4 3.4 30 41 11.5 15.6 7 - 4 10.2 10.6 153 113 naMarathon -6.6 0.0 -1.9 3.9 3.9 32 42 7.4 11.4 11 - - 9.2 9.3 124 80 naUS Mid Cap Average -4.6 2.1 0.1 3.6 4.0 37.5 48.0 30.7 40.7 9.1 na 9 29.7 33.2 139.3 115.9 0.7

CEE Refining & MarketingHellenic Petroleum 14.3 16.5 8.2 0.0 0.1 33 35 1.3 1.4 na 58 - 1.6 2.0 92 97 naOMV 0.5 4.1 0.2 3.3 3.8 25 29 3.0 3.7 11 35 35 3.6 4.9 103 122 naMOL 15.5 15.8 2.9 2.4 4.3 22 24 2.2 3.0 1 - - 2.9 3.2 105 115 naPKN 9.0 12.1 3.3 2.8 4.4 28 30 1.8 2.1 na - - 2.4 2.8 88 86 naCEE Refining & Marketing Average 9.8 12.1 3.6 2.1 3.1 27 29 2.1 2.6 6 35 35 2.6 3.2 97 105 na

Rest of WorldBHP Billiton 15.5 13.2 6.2 2.7 4.5 43 40 34.9 41.5 na - - 17.5 17.5 237 282 naGazprom ** 23.6 6.0 0.5 1.1 1.4 10 5 28.6 31.4 na 38 38 52.9 57.2 59 61 naLUKoil Holdings 6.0 35.4 3.4 2.8 9.2 12 31 11.4 13.2 1 - - 16.5 22.1 80 56 naPetrobras 8.0 20.7 6.9 6.4 0.0 25 39 18.0 27.8 3 56 56 22.6 27.9 123 127 naSasol *** 14.2 8.6 3.6 5.9 8.9 34 34 7.1 7.2 na - - 2.8 2.6 258 297 0.30Surgut 4.8 5.1 5.9 0.4 0.5 2 9 12.7 8.3 1 - - 8.4 10.3 99 92 naTatneft -6.2 -2.6 0.0 3.2 2.9 8 9 1.7 2.6 5 31 31 5.5 6.3 47 29 naWoodside 6.0 2.3 -6.4 3.2 2.1 31 50 4.2 5.0 4 - 34 2.5 2.4 196 212 naYUKOS Oil 2.2 28.1 4.8 2.5 6.8 15 37 20.5 16.4 1 - 82 6.7 10.1 244 144 naRest of World Average 7.8 11.9 2.7 3.2 3.3 23.6 30.5 17.6 19.8 2.5 - - 20.5 22.4 134.4 130.7 0.3* Conoco Phillips - Merged figures post 1 January 2002** Gazprom dividend and share numbers calculated using ADR data, Market Cap. calculated using both ordinary and ADR shares*** Sasol data based on June year end data/estimates for the appropriate year.Source: Deutsche Bank estimates and company information

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Figure 34: ROCE (%) as at 4 April 2003Company 2001 2002E 2003E 2004E 2005E 2006E 2007E Net changeIntegratedThree SistersBP pro-forma 19.8 13.0 15.4 13.3 13.4 13.6 13.4 -2.0BP 9.9 6.9 9.7 8.2 8.3 8.6 8.5 -1.3Exxon Mobil 20.5 15.0 17.0 15.2 14.8 14.7 14.5 -2.5RD/Shell pro-forma 21.4 15.7 15.3 13.7 13.8 13.6 13.4 -1.9RD/Shell 19.8 13.6 13.6 12.2 12.3 12.2 12.1 -1.5Three Sisters Average 17.9 12.6 14.4 12.6 12.6 12.6 12.4 -1.9

European Mid CapsBG 13.0 11.3 13.6 13.4 11.6 11.7 11.6 -2.0Eni 18.0 14.4 13.7 12.0 12.3 12.6 12.6 -1.1Norsk Hydro 9.1 7.6 8.1 7.9 8.4 8.2 7.9 -0.2Repsol 8.2 7.0 9.0 8.2 8.4 8.9 9.0 0.0Statoil 15.2 14.8 15.8 12.6 12.5 13.0 12.8 -3.0TOTAL 17.4 14.6 16.3 15.0 14.6 14.9 14.8 -1.5Mid Cap European Average 13.5 11.6 12.8 11.5 11.3 11.6 11.5 -1.3

US Mid CapsChevronTexaco 21.0 10.9 12.2 9.7 9.4 9.7 10.0 -2.2ConocoPhillips * 10.4 4.2 7.3 5.6 6.0 5.5 5.6 -1.7Occidental 17.0 11.8 14.2 10.5 9.6 10.0 10.4 -3.8Marathon 17.4 8.1 11.2 9.6 9.1 8.7 7.2 -4.0Mid Cap US Average 15.7 8.7 11.2 8.8 8.5 8.5 8.3 -2.9

CEE Refining & MarketingHellenic Petroleum 4.1 7.8 8.0 12.2 11.6 11.1 10.5 2.5OMV 13.1 10.6 11.7 11.8 10.8 9.9 8.5 -3.2MOL 0.5 7.7 8.3 7.8 9.8 11.5 12.6 4.3PKN 5.0 7.3 8.3 8.1 8.3 8.8 9.0 0.7CEE Refining & Marketing Average 5.7 8.4 9.1 10.0 10.1 10.3 10.2 1.1

Rest of WorldBHP Billiton 9.1 10.2 9.0 10.4 11.6 12.6 14.3 5.3Gazprom 0.9 5.3 6.2 7.8 9.6 12.3 12.8 6.6LUKoil Holdings 18.2 14.5 17.9 14.4 15.7 15.8 15.4 -2.5Petrobras 14.0 11.2 16.8 15.7 16.1 17.4 17.3 0.5Sasol *** 33.7 32.4 33.5 38.1 40.4 45.4 52.7 19.2Surgut 27.2 20.7 25.0 21.7 23.2 23.2 22.8 -2.2Tatneft 17.4 10.0 13.3 10.7 9.4 8.9 8.3 -4.9Woodside 25.7 21.2 19.7 13.0 15.2 14.0 10.4 -9.3YUKOS Oil 96.1 49.4 49.8 36.7 37.1 33.9 31.4 -18.3Rest of World Average 25.9 17.7 19.1 16.8 17.7 18.3 18.6 -0.4* Conoco Phillips - Merged figures post 1 January 2002*** Sasol data based on June year end data/estimates for the appropriate year.Source: Deutsche Bank estimates and company information



Disclosures

Additional Information Available upon Request

Disclosure ChecklistCompany Ticker Recent Price DisclosureBG Group Plc BG.L 236.00 2,6,8,9

ChevronTexaco Corporation CVX 64.40 6,8,9

ENI S.P.A. ENI.MI 13.20 2,6,7,8,9,10

Repsol-YPF, S.A. REP.MC 13.61 2,5,6,8,9,10

ConocoPhillips COP 52.31 6,8,9

1. Within the past year, Deutsche Bank and/or its affiliate(s) has managed or co-managed a public offering for thiscompany, for which it received fees.

2. Deutsche Bank and/or its affiliate(s) makes a market in securities issued by this company.

3. Deutsche Bank and/or its affiliate(s) acts as a corporate broker or sponsor to this company.

4. The author of or an individual who assisted in the preparation of this report (or a member of his/her household) hasa direct ownership position in securities issued by this company or derivatives thereof.

5. An employee of Deutsche Bank and/or its affiliate(s) serves on the board of directors of this company.

6. Deutsche Bank and/or its affiliate(s) owns one percent or more of any class of common equity securities of thiscompany.

7. Deutsche Bank and/or its affiliate(s) has received compensation from this company for the provision of investmentbanking or financial advisory services within the past year.

8. Deutsche Bank and/or its affiliate(s) expects to receive or intends to seek compensation for investment bankingservices from this company in the next three months.

9. Deutsche Bank and/or its affiliate(s) was a member of a syndicate which has underwritten, within the last fiveyears, the last public offering of this company.

10. Deutsche Bank and/or its affiliate(s) holds 1% or more of the share capital of this company, calculated undercomputational methods required by German law.

11. Please see special footnote below for other relevant disclosures.

Deutsche Bank AG and/or one of its affiliates is advising BP plc, on the proposed acquisition of a 51% stake in E.ON

AG's Veba Oel unit and the sale of BP's Gelsenberg unit to E.ON, including its 25.5% stake in Ruhrgas. Separately,

Deutsche Bank AG and/or an affiliate(s) is advising BP plc., UK on the proposed disposal of its North and North East

German service station assets to Polski Koncern Naftowy SA., Poland (aka PKN). Separately, Deutsche Bank AG and/or

an affiliate(s) is advising BP plc., UK on the proposed disposal of the upstream oil businesses of Veba Canada Oil & Gas

to Petro-Canada, Canada. Separately, Deutsche Bank AG and/or an affiliate is acting as advisor to BP plc., UK in respect

of the proposed disposal of certain E&P assets to Apache Corp., USA.

The above-mentioned conflicts of interest may also pertain to other companies cross-referenced in this report.

For company specific disclosures relating to cross-referenced recommendations or estimates made in this

report, please refer to the most recently published single-company report on that company or visit our global

disclosure look-up page on our website at http://equities.research.db.com.

The views expressed in this report accurately reflect the personal views of theundersigned lead analyst about the subject issuers and the securities of thoseissuers. In addition, the undersigned lead analyst has not and will not receive anycompensation for providing a specific recommendation or view in this report.

Caroline Cook



Historical Recommendations and Target Price: BG Group Plc (BG.L) (as of 4/7/2003)

98765

4

321

GBP-

GBP50.00

GBP100.00

GBP150.00

GBP200.00

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Apr00

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Oct00

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Oct01

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Date

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uri

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Previous Recommendations

Strong BuyBuyMarket PerformUnderperformNot RatedSuspended Rating

CurrentRecommendations

BuyHoldSellNot RatedSuspended Rating

*New Recommendation1. 10/26/2000: Downgrade to Market Perform

2. 2/20/2002: Market Perform, Target Price Change GBP 260.00



5. 11/20/2002: Hold, Target Price Change GBP 250.00





Rating Key Rating Dispersion and Banking Relationships

Buy: Total return expected to appreciate 10% or more over a12-month period

Hold: Total return expected to be between 10% to –10%over a 12-month period

Sell: Total return expected to depreciate 10% or more over a12-month period

0

100

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Companies Covered Cos. w/ Banking Relationship

Additional information available on requestThe information and opinions in this report were prepared by Deutsche Bank AG or one of its affiliates (collectively “Deutsche Bank”). The information herein is believedby Deutsche Bank to be reliable and has been obtained from public sources believed to be reliable, but Deutsche Bank makes no representation as to the accuracy orcompleteness of such information.

Important Information Regarding Our Independence. The research analysts responsible for the preparation of this report receive compensation that is basedupon, among other factors, Deutsche Bank’s overall investment banking revenues.

Deutsche Bank may engage in securities transactions in a manner inconsistent with this research report and with respect to securities covered by this report, will sell toor buy from customers on a principal basis. Disclosures of conflicts of interest, if any, are discussed at the end of the text of this report or on the Deutsche Bank websiteat http://equities.research.db.com/cgi-in/compose?PAGE=HOMEPAGE.

Opinions, estimates and projections in this report constitute the current judgement of the author as of the date of this report. They do not necessarily reflect the opinionsof Deutsche Bank and are subject to change without notice. Deutsche Bank has no obligation to update, modify or amend this report or to otherwise notify a readerthereof in the event that any matter stated herein, or any opinion, projection, forecast or estimate set forth herein, changes or subsequently becomes inaccurate, or ifresearch on the subject company is withdrawn. Prices and availability of financial instruments also are subject to change without notice. This report is provided forinformational purposes only. It is not to be construed as an offer to buy or sell or a solicitation of an offer to buy or sell any financial instruments or to participate in anyparticular trading strategy in any jurisdiction. The financial instruments discussed in this report may not be suitable for all investors and investors must make their owninvestment decisions using their own independent advisors as they believe necessary and based upon their specific financial situations and investment objectives. If afinancial instrument is denominated in a currency other than an investor’s currency, a change in exchange rates may adversely affect the price or value of, or the incomederived from, the financial instrument, and such investor effectively assumes currency risk. In addition, income from an investment may fluctuate and the price or valueof financial instruments described in this report, either directly or indirectly, may rise or fall. Furthermore, past performance is not necessarily indicative of future results.

Unless governing law provides otherwise, all transactions should be executed through the Deutsche Bank entity in the investor’s home jurisdiction. In the U.S. this reportis approved and/or distributed by Deutsche Bank Securities Inc., a member of the NYSE, the NASD, NFA and SIPC. In the United Kingdom this report is approved and/orcommunicated by Deutsche Bank AG London, a member of the London Stock Exchange. This report is distributed in Hong Kong by Deutsche Bank AG, Hong KongBranch, in Korea by Deutsche Securities Korea Co. and in Singapore by Deutsche Bank AG, Singapore Branch. In Japan this report is approved and/or distributed byDeutsche Securities Limited, Tokyo Branch. Additional information relative to securities, other financial products or issuers discussed in this report is availableupon request. This report may not be reproduced, distributed or published by any person for any purpose without Deutsche Bank's prior written consent. Please citesource when quoting.

Copyright 2003 Deutsche Bank AG

GRCM2003PROD00582

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Documents

03.04.08 LNG Projects DB