NOT FOR RELEASE OR DISTRIBUTION IN THE UNITED STATES OR TO U.S. PERSONS

ASX Release

12 October 2009

INDEPENDENT EXPERT’S REPORT

Further to the announcement this morning by BBI attaching the summary Independent Expert's Report on the proposed recapitalisation prepared by Grant Samuel & Associates, please see attached the full Independent Expert's Report.

Important Information

This announcement does not constitute an offer to sell, or a solicitation of an offer to buy securities in the United States, or to or from any person that is, or is acting for the account or benefit of, any "U.S. person" (as defined in Regulation S under the U.S. Securities Act of 1933 (the "U.S. Securities Act") ("U.S. Person")). The securities to be issued in the Recapitalisation have not been, and will not be, registered under the U.S. Securities Act and may not be offered or sold in the United States or to, or for the account or benefit of, U.S. Persons unless the securities are registered under the U.S. Securities Act or an exemption from the registration requirements of the U.S. Securities Act is available.

This announcement contains certain forward-looking statements. The words "anticipate", "believe", "expect", "project", "estimate", "likely", "intend", "should", "could", "may", "target", "plan" and other similar expressions are intended to identify forward-looking statements. Indications of, and guidance on, future earnings and financial position and performance are also forward-looking statements. Such forward-looking statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors, many of which are beyond the control of BBI, which may cause actual results to differ materially from those expressed or implied in such statements. There can be no assurance that actual outcomes will not differ materially from these statements. Readers are cautioned not to place undue reliance on forward-looking statements and BBI assumes no obligation to update such information.

ENDS Further Enquiries David Akers Acting Investor Relations Manager Babcock & Brown Infrastructure +61 2 9229 1800 ABOUT BABCOCK & BROWN INFRASTRUCTURE Babcock & Brown Infrastructure (ASX: BBI) is a specialist infrastructure entity which provides investors access to a diversified portfolio of quality infrastructure assets. BBI’s investment strategy focuses on owning, managing and operating quality infrastructure assets in Australia and internationally.

For further information please visit our website: www.bbinfrastructure.com

Financial Services Guide and

Independent Expert’s Report in relation to the Recapitalisation and

Restructure of Babcock & Brown Infrastructure

Grant Samuel & Associates Pty Limited (ABN 28 050 036 372)

9 October 2009

G R A N T S A M U E L & A S S O C I A T E S

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Financial Services Guide

Grant Samuel & Associates Pty Limited (“Grant Samuel”) holds Australian Financial Services Licence No. 240985 authorising it to provide financial product advice on securities and interests in managed investments schemes to wholesale and retail clients.

The Corporations Act, 2001 requires Grant Samuel to provide this Financial Services Guide (“FSG”) in connection with its provision of an independent expert’s report (“Report”) which is included in a document (“Disclosure Document”) provided to members by the company or other entity (“Entity”) for which Grant Samuel prepares the Report.

Grant Samuel does not accept instructions from retail clients. Grant Samuel provides no financial services directly to retail clients and receives no remuneration from retail clients for financial services. Grant Samuel does not provide any personal retail financial product advice to retail investors nor does it provide market-related advice to retail investors.

When providing Reports, Grant Samuel’s client is the Entity to which it provides the Report. Grant Samuel receives its remuneration from the Entity. In respect of the Report for Babcock & Brown Infrastructure (“BBI”) in relation to the proposed recapitalisation involving Brookfield Asset Management Inc. (“Brookfield”) (“the BBI Report”), Grant Samuel will receive a fixed fee of $1,800,000 plus reimbursement of out-of-pocket expenses for the preparation of the Report (as stated in Section 8.3 of the BBI Report).

No related body corporate of Grant Samuel, or any of the directors or employees of Grant Samuel or of any of those related bodies or any associate receives any remuneration or other benefit attributable to the preparation and provision of the Report.

Grant Samuel is required to be independent of the Entity in order to provide a Report. The guidelines for independence in the preparation of Reports are set out in Regulatory Guide 112 issued by the Australian Securities & Investments Commission on 30 October 2007. The following information in relation to the independence of Grant Samuel is stated in Section 8.3 of the BBI Report:

Grant Samuel and its related entities do not have at the date of this report, and have not had within the previous two years, any shareholding in or other relationship with BBI or Brookfield that could reasonably be regarded as capable of affecting its ability to provide an unbiased opinion in relation to the Recapitalisation. Grant Samuel advises that:

Grant Samuel was appointed by Alinta in July 2007 to prepare an independent expert’s report in relation to the proposal by a consortium comprising Babcock & Brown International Pty Ltd (a wholly owned subsidiary of Babcock and Brown Limited) and Singapore Power International Pte Ltd to acquire Alinta; and

a Grant Samuel executive holds a parcel of around 160,000 Securities in BBI. Grant Samuel commenced analysis for the purposes of this report in August 2009 prior to the announcement of the Recapitalisation on 8 October 2009. This work did not involve Grant Samuel’s participation in the setting of the terms of, or any negotiations leading to, the Recapitalisation. Grant Samuel had no part in the formulation of the Recapitalisation. Its only role has been the preparation of this report. Grant Samuel will receive a fixed fee of $1,800,000 for the preparation of this report. This fee is not contingent on the outcome of the Recapitalisation. Grant Samuel’s out of pocket expenses in relation to the preparation of the report will be reimbursed. Grant Samuel will receive no other benefit for the preparation of this report. Grant Samuel considers itself to be independent in terms of Regulatory Guide 112 issued by the ASIC on 30 October 2007.

Grant Samuel has internal complaints-handling mechanisms and is a member of the Financial Ombudsman Service, No. 11929.

Grant Samuel is only responsible for the Report and this FSG. Complaints or questions about the Disclosure Document should not be directed to Grant Samuel which is not responsible for that document. Grant Samuel will not respond in any way that might involve any provision of financial product advice to any retail investor.

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9 October 2009 The Directors Babcock & Brown Infrastructure Limited Babcock & Brown Investor Services Limited in its capacity as responsible entity of the Babcock & Brown Infrastructure Trust Level 23, Chifley Tower, 2 Chifley Square Sydney NSW 2000 Dear Directors

Recapitalisation Proposal

1 Introduction

Babcock & Brown Infrastructure (“BBI”) comprises Babcock & Brown Infrastructure Limited (“BBIL”) and Babcock & Brown Infrastructure Trust (the responsible entity of which is Babcock & Brown Investor Services Ltd) (“BBIT”). The shares in BBIL and the units in BBIT are stapled together to form stapled securities (“Securities”), quoted on the Australian Securities Exchange (“ASX”). BBI’s subsidiaries also have on issue Exchangeable Preference Shares (“EPS”) (listed on the ASX) and Subordinated Prime Adjusting Reset Convertible Securities (“SPARCS”) (listed on the New Zealand Stock Exchange). As at 29 September 2009 the aggregate market values of BBI Securities, EPS and SPARCS were approximately $140 million, $150 million and $55 million respectively. BBI listed on the ASX on 24 June 2002 as Prime Infrastructure Group and changed its name to BBI on 1 July 2005. BBI has grown substantially since then through a series of acquisitions, including the August 2007 acquisition of a number of assets from Alinta Limited (“Alinta”), the largest Australian energy infrastructure owner and operator at that time, the PD Ports business and a 26.4% interest in the Natural Gas Pipeline of America (“NGPL”). BBI’s asset portfolio now consists of the following: Energy Transmission and Distribution

the Australian Energy Transmission and Distribution businesses (“AET&D”), which include:

• a 20.0% interest in the Dampier to Bunbury Natural Gas Pipeline, in Western Australia;

• a 74.1% interest in the WA Gas Network, which distributes gas in Perth and other regional centres in Western Australia;

• a 20.1% interest in the Multinet Gas Network, which distributes gas in Melbourne;

• a 100.0% interest in the Tasmanian Gas Pipeline, which transmits gas from Victoria across Bass Strait to Tasmania; and

• 100.0% ownership of WestNet Energy, an operations and maintenance business servicing electricity and gas businesses in Western Australia;

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a 100% interest in Tas Gas, which distributes gas through a number of cities and towns in Tasmania;

a 42% interest in Powerco, which distributes gas and electricity across the North Island of New Zealand;

a 100% interest in International Energy Group (“IEG”), which operates a natural gas and LPG distribution and services business in the United Kingdom, the Channel Islands (Guernsey and Jersey) and the Isle of Man;

a 26.4% interest in Natural Gas Pipeline Company of America (“NGPL”), which is a major provider of gas pipeline transportation and storage services in the United States; and

a 100% interest in the Cross Sound Cable, which links the electricity grids of New England and New York.

Transport

a 100% interest in the Dalrymple Bay Coal Terminal (“DBCT”), which exports metallurgical and thermal coal mined in the Bowen Basin region of Queensland, Queensland;

a 96% interest in WestNet Rail, which provides rail infrastructure access in Western Australia;

a 100% interest in PD Ports, which owns and operates the Port of Tees and Hartlepool, the third largest port in the United Kingdom; and

a 60% interest in Euroports, which operates a ports business from 16 locations located in seven European Union countries.

The global financial crisis which commenced in late 2007 resulted in turmoil in the equity and credit capital markets and has had significant implications for world economic activity. In particular, credit markets tightened substantially, resulting in negative market sentiment towards entities with high levels of gearing. Within the Australian market place, the consequential shift in asset values resulted in a re-assessment of the external asset management business model. Babcock & Brown Limited (“Babcock & Brown”), a subsidiary of which is the manager of BBI, went into administration on 13 March 2009. The growth in BBI’s asset portfolio during 2006 and 2007 was largely debt funded. As a result, when debt and equity markets collapsed in 2008 and economic conditions declined dramatically, BBI found itself with very high levels of debt. BBI has taken a number of steps to address its debt position, the pressure on operational earnings and the changed economic circumstances:

in November 2008, BBI suspended payment of distributions on stapled securities and deferred dividends on BBI EPS until further notice; and

BBI has sold interests in a number of assets:

• a 58% interest in Powerco to funds managed by QIC Limited (“QIC”) for NZ$421.2 million;

• International Energy Group’s (“IEG’s”) Portugal business to Fundo Explorer II for £40.1 million; and

• 40% of the Euroports portfolio to Antin Infrastructure Partners and Arcus European Infrastructure Fund I for €141.5 million (which, after allowing for the funding of BBI’s share of growth capital expenditure and the acquisition of the minority positions within the Euroports portfolio, provided net proceeds to BBI of €35.0 million) which was used to repay a short term loan at the Euroports level.

The net proceeds from these sales have been used to repay $390 million of asset level non-recourse and corporate debt and have enabled BBI to pay obligations associated with the minority interests in WestNet Rail (increasing its ownership interest to 96%).

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At 31 August 2009, BBI had $8.0 billion in total proportionate1 non-recourse debt at the asset level and a further $1.2 billion in corporate debt facilities. Of this amount, $3.2 billion matures in the years ending 30 June 2010 and 2011, including $731 million of corporate debt, approximately $300 million2 of which is required to be repaid in February 2010. While there have been no breaches of any debt covenants within the BBI portfolio, in the case of a number of assets all operating cash flows are being applied to reduce debt at the asset level, resulting in a decline in distributions to BBI at the corporate level, which in turn affects its ability to meet short term corporate debt repayments. On 8 October 2009, BBI announced that it had signed an Implementation Agreement with Brookfield Asset Management Inc (“Brookfield”) (“Recapitalisation”). The Recapitalisation consists of the following:

a $1,500 million equity raising consisting of:

• a $625 million placement to the cornerstone investor, Brookfield (“Cornerstone Placement”);

• a fully underwritten $625 million institutional placement to new and existing institutional investors (“Institutional Placement”); and

• a fully underwritten security purchase plan (“SPP”) to eligible Securityholders to raise $250 million of which Brookfield is sub-underwriting $87.5 million with a priority over other underwriting and sub-underwriting commitments, such that Brookfield’s sub-underwriting will be called upon first in the event of a shortfall (“Sub-underwriting”),

collectively the “Equity Raising”;

asset arrangements with Brookfield (collectively “Asset Acquisitions”) including:

• Brookfield will agree to acquire:

- a 49.9% economic interest in Dalrymple Bay Coal Terminal (“DBCT”) for $295 million; and

- a 100% interest in PD Ports for nominal proceeds;

• Brookfield will provide management services to AET&D and Cross Sound Cable (“CSC”) assets subject to supervision of the boards of the relevant entities and have the right to acquire BBI’s interest in these assets for nominal proceeds;

the repayment of BBI’s outstanding corporate debt (excluding the New Zealand corporate bonds) from the proceeds from the Equity Raising;

the conversion of EPS into Securities and the payment of approximately $48 million of accrued and deferred dividends to the EPS holders; and

a capital distribution of $0.04 per Security totalling approximately $104 million to registered holders of Securities as at 16 November 2009 (“Capital Distribution”).

BBI also proposes to internalise management, change its name to Prime Infrastructure and to consolidate the number of securities on issue (although the Recapitalisation is not conditional on the change of name and consolidation). Following the Recapitalisation, Brookfield will hold a minimum of 35% of the Securities on issue and up to 39.9% under the Sub-underwriting. Investors under the Institutional Placement will hold a further 35% and investors under the SPP will hold approximately 14%. Current holders of Securities and EPS will hold, collectively, approximately 16% of the Securities on issue.

1 “Proportionate” refers to BBI’s effective share of the non-recourse debt in each relevant underlying asset, where such share equals

BBI’s interest in the relevant asset. 2 £82.2 million or approximately $169 million is due in February 2010 although under the cash sweep mechanism agreed with the BBI

corporate lenders, BBI will be required to repay approximately $300 million in corporate debt to meet this debt maturity in February 2010.

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Because the Cornerstone Placement will result in Brookfield acquiring more than 20% of the BBI securities on issue, BBI requires the approval of the holders of Securities for the Cornerstone Placement for the Purposes of the Corporations Act 2001. Approvals of each element of the Equity Raising will also be sought under relevant ASX Listing Rules, and BBI will also seek approval of the overall Recapitalisation proposal. BBI will also seek the approval of the holders of BBI EPS in relation to the aspects of the Recapitalisation. BBI is required to commission an independent expert’s report in relation to the Cornerstone Placement and Sub-underwriting. BBI has engaged Grant Samuel & Associates Pty Limited (“Grant Samuel”) to prepare the report. The report will state whether:

the Recapitalisation as a whole, and the Cornerstone Placement and Sub-underwriting, are fair and reasonable to the holders of BBI Securities; and

the Recapitalisation as a whole is fair and reasonable to the holders of BBI EPS.

This letter contains a summary of Grant Samuel’s opinion and main conclusions and is extracted from Grant Samuel’s full report, of which this letter forms a part. A copy of this letter and the accompanying full report will be available on BBI’s website (www.bbinfrastructure.com) and has been lodged with the ASX.

2 Summary of Opinion

BBI needs to take urgent action to address its financial position. BBI has very high levels of debt, both at a corporate level and at a subsidiary asset level. Its most pressing need is to finance the repayment of approximately $300 million3 of corporate debt that matures in February 2010. BBI has pursued asset sales as a way of reducing debt and, in the short term, addressing its February 2010 corporate debt maturity obligations. However, it has become apparent that asset sales will not achieve the values required. BBI has no choice but to raise new equity. The Recapitalisation will provide a comprehensive solution to BBI’s financial position. It will allow the repayment of all of BBI’s corporate debt (excluding approximately NZ$119 million of New Zealand corporate bonds) and the resumption of distribution payments to holders of Securities. The Recapitalisation will also crystallise (at least to some extent) the uncertain values currently attributable to holders of Securities, EPS and SPARCS. Holders of Securities will receive a Capital Distribution of 4 cents per Security, totalling approximately $104 million. Following the conversion of EPS into Securities, current holders of Securities will be heavily diluted. They will hold a trivial percentage of the expanded Securities on issue and will have only very limited exposure to any future upside in BBI. Holders of EPS will receive their accrued dividends totalling $48 million and will hold the vast majority of the 16% of Securities (post the Recapitalisation) attributable to current holders of Securities and EPS. Based on the equity values implied by the terms of the Recapitalisation, these Securities should have value of around $285 million. Holders of EPS (along with new investors, including the Cornerstone Investor) will be exposed to any future upside in BBI. Holders of SPARCS will enjoy a significant improvement in their position, as the value of their interests (which have a total face value of around $100 million) will effectively be supported by the $1.5 billion of new equity to be injected under the Recapitalisation. Analysis of the Recapitalisation from the perspective of current holders of Securities is relatively straight-forward. BBI needs to raise significant new amounts equity. In the absence of the Recapitalisation or

3 £82.2 million or approximately $169 million is due in February 2010 although under the cash sweep mechanism agreed with the BBI

corporate lenders, BBI will be required to repay approximately $300 million in corporate debt to meet this debt maturity in February 2010.

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some similar equity raising, it is conceivable (but by no means certain) that BBI could raise sufficient funds through asset sales to meet its February 2010 maturity commitments. However, BBI would continue to be financially vulnerable, and there could be no assurance that equity markets would continue to provide an opportunity to raise significant amounts of new equity. At worst, in the absence of the Recapitalisation or other equity raising, BBI could enter some form of insolvency administration. This would almost certainly result in holders of Securities realising zero value for their interests in BBI. The directors of BBI have considered an alternative proposal (“RBS Proposal”) from a consortium headed by Royal Bank of Scotland (“RBS”) and concluded that the RBS Proposal is inferior to the Recapitalisation. Given BBI’s requirement for new equity, and the absence of any superior alternative, holders of Securities will be better off if the Recapitalisation proceeds than if it does not. Evaluation of the Cornerstone Placement and Sub-underwriting requires an assessment of the underlying value attributable to holders of Securities. However, attribution of underlying value to holders of Securities is not straightforward. Grant Samuel’s valuation suggests that there is a real risk that no underlying value would be available for holders of Securities after taking into account the face value of EPS and SPARCS. In this context, allocation of underlying value between holders of Securities, EPS and SPARCS is to some extent judgemental. Grant Samuel has considered two bases for this allocation. On the basis that the value allocation assumes that holders of EPS and SPARCS have absolute priority to value, the underlying value attributable to holders of Securities would be 0-14 cents. On the basis that EPS and SPARCS were assumed to convert into Securities assuming a volume weighted average price of Securities of 5 cents, the underlying value attributable to holders of Securities would be 3-6 cents. The value to be realised by holders of Securities through the Capital Distribution of 4 cents per Security falls within the ranges of value attributed to the Securities (depending on the basis of assessment, either 0 -14 cents or 3-6 cents per Security). Accordingly, in Grant Samuel’s view the Cornerstone Placement and Sub-underwriting are fair. Because they are fair, they are also reasonable to the holders of Securities. Given the valuation analysis set out above, in Grant Samuel’s opinion the Recapitalisation is fair. The terms of the Asset Acquisitions are generally consistent with terms that might be concluded with third parties. In the absence of the Recapitalisation, there would be a real risk that BBI would ultimately be placed in some form of insolvency administration, in which case holders of Securities would almost certainly realise no value. Accordingly, in Grant Samuel’s view the Recapitalisation is fair and reasonable having regard to the interests of holders of Securities, in the absence of a superior alternative proposal. Analysis of the Recapitalisation from the perspective of current holders of EPS is more complex. If the Recapitalisation (or some similar equity raising) did not proceed and BBI consequently entered some form of insolvency administration, it appears likely that holders of EPS would recover no value (although, given that they have priority relative to the holders of Securities, the prospect of their realising at least some value cannot be absolutely ruled out). Based on the values implied by the Recapitalisation, holders of EPS will collectively realise value of approximately $333 million (through the payment of accrued dividends and their holdings of Securities). This is clearly a better outcome than the potential alternative of ranking behind corporate debt providers in an insolvency administration. It represents a substantial premium to the market value of the EPS, which was approximately $150 million when BBI went into trading halt prior to the announcement of the Recapitalisation. On the other hand, the Recapitalisation also crystallises a significant loss for holders of the EPS relative to their face value of $779 million (although holders of EPS will retain some exposure to upside in BBI’s asset base through their holding of Securities). Holders of EPS have to compare the relatively certain value that they will receive if the Recapitalisation proceeds (notwithstanding that it is a significant discount to the face value of the EPS) with the potential loss of all of their investment value if the Recapitalisation does not proceed. In Grant Samuel’s view holders of EPS are likely to be better off if the Recapitalisation proceeds than if it does not. A secondary question for holders of EPS is whether the Recapitalisation is equitable in the sense of fairly sharing the residual equity value between holders of Securities, EPS and SPARCS. There are no clear guidelines as to what constitutes “fairness” in this context. Arguably, given that they would rank last in any form of insolvency value realisation process and would almost certainly realise no value, holders of Securities have the weakest claim to any equity value. In this context it could be argued that holders of

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Securities are receiving a disproportionate share of value. However, holders of Securities will need to realise some non-trivial value for any restructuring to proceed. It appears that holders of SPARCS have a good prospect of realising the face value of their investments, and on that basis will achieve a better outcome than holders of EPS. In an absolute sense, on the other hand, given the modest total face value of the SPARCS, any value transfer is limited. In addition, any attempt to limit the amount of value that accrues for the benefit of the holders of SPARCS would effectively need their approval, increasing transaction risk. The reality is that there is a need to balance the competing interests of the different sets of security holders with the practical imperative of minimising transaction risk and delivering at least some value to the holders of Securities, EPS and SPARCS. On balance (and having regard to the consequences if the Recapitalisation does not proceed), Grant Samuel believes that the allocation of value as between holders of Securities, EPS and SPARCS is broadly fair. Grant Samuel has therefore concluded that the Recapitalisation is fair and reasonable having regard to the interests of holders of EPS.

3 Key Conclusions

BBI needs to take urgent action to address its financial position.

BBI’s rapid growth during the 2006 to 2008 period involved the assumption of significant debt. With the onset of the global financial crisis, BBI’s asset values have fallen. In some cases underlying asset performance has declined. Debt providers have become far more risk averse and are seeking to reduce debt exposures wherever possible. At 31 August 2009, BBI had $8.0 billion in total proportionate non-recourse debt at the asset level and a further $1.2 billion in corporate debt facilities. In the case of a number of asset level debt facilities, lenders have commenced to “sweep” all available free cash flows or subsidiary companies have decided to devote all free cash flows to debt reduction. The result for these assets is that surplus cash flows are no longer available to BBI to service its corporate debt facilities. At the corporate level, BBI faces debt maturities of $731 million over the two years ending 30 June 2011, of which approximately $300 million is due in February 2010. BBI does not have the cash resources to fund this payment and its forecasts show that it will generate essentially no free cash at a corporate level over the period to February 2010. Accordingly, BBI needs to take urgent action to raise the cash required to meet its February 2010 maturity commitments. There is a very real risk that a failure to meet these commitments would result in some form of insolvency appointment.

BBI has no choice but to pursue a substantial equity raising.

BBI has pursued a strategy of asset sales over the past 12 months, including the sale of a 58% stake in Powerco New Zealand and a 40% stake in the Euroports portfolio. However, it has become apparent that further asset sales are not a viable strategy for addressing BBI’s financial position:

BBI’s experience is that it is very difficult to realise reasonable values in the current market environment, especially when BBI is perceived as a distressed seller. Asset divestment costs are in some cases significant. For assets that are heavily geared, BBI would generally realise little or no value on divestment;

in certain cases shareholder agreements preclude asset sales or are likely to significantly hamper sales processes and therefore reduce the amounts realisable; and

BBI has run a sale process for DBCT, which is BBI’s most valuable “unencumbered” asset available for sale. The value indications received through that process are such that the reduction in debt achievable by the sale would not be sufficient to offset the loss of earnings from the asset. In fact, the loss of earnings would be such that BBI would immediately become in breach of forward looking interest cover covenants on its corporate debt facilities. This situation is likely to apply to other assets theoretically available for sale.

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It is conceivable (although probably unlikely) that BBI could raise sufficient proceeds through asset sales to meet its February 2010 maturity commitments, without in that process breaching corporate debt covenants. However, that would leave BBI in a highly vulnerable financial position, with further corporate debt maturities due later in 2010 and early in 2011 and a diminished stock of assets available for sale. While deferral by a further twelve months of a comprehensive solution to its financial position could provide some opportunity for a recovery of asset values and an improvement in credit markets, BBI would also be exposed to the risk that current favourable equity market conditions would not persist. In any event, given the impending corporate debt maturities facing BBI in February 2010, there is real doubt as to whether material asset sales could be completed within the limited time available. There is presumably at least some possibility that BBI could negotiate some form of debt moratorium with its bankers. However, such a course of action would be inevitably risky and there could be no certainty of success. The reality is that BBI will need to raise significant new equity over the next twelve months. Given the risks associated with the deferral of an equity raising, it is clear that BBI has no realistic choice but to pursue a substantial equity raising as soon as possible.

The Recapitalisation is the most attractive restructuring proposal available to BBI.

BBI has had various informal approaches regarding potential equity injections, but has received only one formal proposal other than the Recapitalisation proposal. On 17 September 2009, BBI received a refinancing proposal from The Royal Bank of Scotland (“RBS”), acting on behalf of an investor group comprising primarily international hedge funds. BBI and its advisers engaged with RBS to seek further clarification and received an updated proposal (the “RBS Proposal”) on 28 September 2009. On 30 September BBI announced that it would not proceed with the RBS Proposal, on the basis that it had formed the view that the RBS Proposal is less attractive than the Recapitalisation for a number of reasons, including: the RBS Proposal would achieve a deferral of BBI’s short term debt maturity obligations.

However, it would result in the injection of relatively little new equity (particularly after taking transaction costs into account) and would not meaningfully improve BBI’s overall financial position;

the new debt and convertible notes that formed part of the RBS Proposal would be relatively

costly;

there could be no guarantee of any re-rating of BBI listed securities, given that there would be no capacity to resume distributions and potential further dilution of Securities;

there would be considerable execution risks associated with the RBS Proposal.

For these reasons, in Grant Samuel’s view the Recapitalisation is significantly more attractive than the RBS Proposal. Given BBI’s extensive asset portfolio, the likely complexity of any recapitalisation proposal and the limited time now available to BBI, it appears unlikely that any proposal superior to the Recapitalisation will become available to BBI.

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Valuation of BBI is problematic.

Grant Samuel’s valuation of BBI is summarised below:

BBI – Valuation Summary Valuation (A$ million) Low High AET&D 48 148 CSC - - NGPL 660 742 Tas Gas 162 182 Powerco 246 283 IEG 48 103 Total –transmission and distribution assets 1,164 1,458 DBCT 581 681 WestNet Rail 88 146 Euroports 247 298 PD Ports - 21 Total – transport assets 916 1,146 Total Asset Values 2,080 2,604 Corporate Costs (150) (100) Corporate Debt (1,165) (1,165) Corporate Swaps (97) (97) Net Asset Value 668 1,242

The valuation represents the full underlying value of BBI. The value exceeds the price at which, based on current market conditions, Grant Samuel would expect equity interests in BBI to trade on the ASX in the ordinary course of trading. The valuation of BBI reflects valuation evidence based on discounted cash flow analysis, capitalisation of earnings and, where available, recent transactions or the results of various sales processes conducted by BBI over the last 12 months. Grant Samuel’s valuation of BBI is set out in more detail in Appendix B. It should be understood that valuation of BBI is problematic. BBI’s extreme gearing means that there is a significant “margin for error” in the valuation. Given total debt within BBI of approximately $9.2 billion (including BBI’s share of off-balance sheet non-recourse debt, which is not shown in the table above, but excluding EPS and SPARCS), the valuation implies a total enterprise value of approximately $9.9-10.4 billion. Valuations are inherently imprecise. A relatively small shift in estimated enterprise value could result in the estimated value of BBI’s net assets falling to zero. A significant proportion of BBI’s value is contributed by assets held outside Australia. Grant Samuel has valued these assets on a local currency basis and translated the estimated values into Australian dollar equivalents using spot exchange rates. Movements in exchange rates could have a significant impact on the estimated underlying value of BBI. Moreover, there have been few recent transactions involving assets similar to those of BBI. BBI’s experience based on its asset divestment program has been that there have been very few parties interested in asset acquisitions, and pricing has been at levels well below historical pricing. While some of this may have reflected BBI’s status as a distressed seller, it is almost certainly the case that values of infrastructure assets have declined substantially, given that there are no longer the volumes of debt available to support highly geared acquisitions. However, in the absence of significant numbers of transactions to provide evidence as to current market values, the extent of this decline is not clear. In this context valuations are subjective. The valuation reflects estimates of the value that could be realised for the assets of BBI on the basis of an orderly realisation. The reality is that such values could almost certainly not be realised by BBI in the short term, given its current financial position and a market perception that it is a forced

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seller. In the case of some of its assets, high levels of debt at an asset level also mean that it would be difficult to realise full underlying value. In the event that BBI was forced to realise its assets in an accelerated time frame (for example, as part of a formal or informal insolvency process), it is possible that the values actually realised could be materially lower than those estimated above.

The conversion of EPS to Securities will result in the wholesale dilution of current holders of Securities.

If the Recapitalisation proceeds, EPS will be converted into Securities. The number of Securities to be issued will be calculated by dividing the face value of the EPS ($779 million) by the volume weighted average price (“VWAP”) of Securities for the 20 trading days ending on 10 November 2009, after adjusting the VWAP for a 7½% discount. The VWAP will also be adjusted by subtracting the amount of the Capital Distribution ($0.04 per Security). The terms of the EPS are proposed to be amended to include a cap and collar for the conversion process, such that the maximum and minimum adjusted VWAPs for the purposes of the conversion (after adjusting for the Capital Distribution) will be 0.2 cents and 0.1 cents, to exclude the risk of manipulative outcomes and also reflecting the minimum price at which securities can trade on ASX. The terms of the Recapitalisation (in which Brookfield will inject $625 million for a 35% interest, excluding the Sub-underwriting of the SPP) imply a value of $286 million for the 16% of the Securities after the Recapitalisation that will be held collectively by current holders of Securities and EPS. The following table shows the number of Securities to be held by current holders of EPS after the conversion, and the sharing of the $286 million between holders of EPS and current holders of Securities:

Impact of EPS Conversion VWAP (cents) 0.2 0.1 Securities issued on conversion of EPS (billions) ($779 million ÷ (VWAP x 92.5%))

421.081 99.4%

842.162 99.7%

Securities currently on issue (billions) 2.592 0.6%

2.592 0.3%

Value attributable to holders of EPS ($ millions) 284 285 Value attributable to current holders of Securities ($ millions)

2 1

Total implied value of 16% Securities 286 286

The result will be that the holders of EPS will capture almost all the value attributable to the 16% of the Securities after the Recapitalisation that will be held collectively by current holders of Securities and EPS. Grant Samuel has assumed for the purpose of its analysis that of the total implied value of $286 million available to holders of Securities and EPS, the value attributable to the holders of EPS will be approximately $285 million.

The Cornerstone Placement and Sub-underwriting are fair and reasonable to holders of Securities.

A conventional analysis of whether a proposal is “fair and reasonable” for the purposes of Section 611 (7) (where a party acquires a shareholding of more than 20% without making a takeover offer) involves two separate elements: an assessment as to whether the proposal is “fair”, based on a comparison of the price at which

the new shareholder is acquiring or subscribing for shares with the estimated underlying value of existing shares; and

an assessment as to whether the proposal is “reasonable” , which can involve a judgement as to

whether it is in shareholders’ best interests to vote in favour of a proposal notwithstanding that it is not “fair”.

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Application of this framework to analysing the Cornerstone Placement and Sub-underwriting is problematic. In the first instance there is no clear basis for determining the underlying value attributable to Securities. The EPS and SPARCS, which have aggregate face value of $879 million, rank ahead of the Securities. Arguably, for estimates of underlying value of less than $879 million, no underlying value should be attributed to the Securities. Valuing the Securities on the basis that they rank for value behind the EPS and SPARCS would suggest a range of underlying values for the Securities of 0-14 cents per Security:

Underlying Value Attributable to Securities Assuming Securities rank behind EPS and SPARCS ($ millions)

Low High Estimated net asset value of BBI 668 1,242 Face value of EPS (779) (779) Face value of SPARCS (100) (100) (Deficiency)/Surplus (211) 363 Underlying value attributable to Securities - 363 Underlying value - 0.14

The mid-point of Grant Samuel’s valuation range for BBI would imply an underlying value attributable to holders of Securities of $76 million (i.e. the mid-point of $(211) million and $353 million), which equates to 3 cents per Security. An alternative approach to estimating the underlying value attributable to the Securities is to assume the conversion of all EPS and SPARCS into Securities and the sharing of underlying value on a pro-rata basis. The following table assumes conversion on the basis of a VWAP of 5 cents (approximating recent Security prices):

Underlying Volume Attributable to Securities Assuming conversion of EPS and SPARCS (S millions)

Low High No of Securities issued on conversion of EPS ($779 million ÷ ($0.05 x 92.5%)) (billions)

16.843 16.843

No of Securities issued on conversion of SPARCS ($100 million ÷ ($0.05 x 97.5%)) (billions)

2.051 2.051

Securities currently on issue (billions) 2.592 2.592 Total Securities on issue post-conversion (billions) 21.486 21.486 Proportion attributable to current Securities 12.1% 12.1% Estimated net asset value ($ millions) 668 1,242 Underlying value attributable to current holders of Securities ($ millions)

81 150

Underlying value per Security ($) 0.03 0.06

This analysis suggests underlying values in the range 3-6 cents per Security. A further issue with the “fair and reasonable” framework as conventionally applied is that it does not take into account the Capital Distribution of 4 cents per Security. The conventional analysis essentially seeks to determine whether shareholders are in some way compensated for a loss of control through the payment by the new substantial shareholder of a price corresponding to full underlying value. In the case of the Recapitalisation, however, holders of Securities will also receive the Capital Distribution as compensation for their “loss of control”. This Capital Distribution will be paid out of proceeds from (and could not be paid in the absence of) the Cornerstone Placement and other elements of the Equity Raising. In Grant Samuel’s view in these circumstances it is not meaningful to assess the Cornerstone Placement and Sub-underwriting without taking into account the Capital Distribution.

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Holders of Securities are receiving value of 4 cents per Security, by comparison with estimates of underlying value for the Securities of 0-14 cents (on the basis that EPS and SPARCS take priority in terms of the realisation of value) or 3-6 cents (on the basis of notional conversion of the EPS and SPARCS at a VWAP for the Securities of 5 cents). On either basis holders of Securities are realising value within the estimated range of underlying values for the Securities. Grant Samuel believes the concept of “fairness” in the context of the Recapitalisation is of limited meaning. However, to the extent that the concept is meaningful, in Grant Samuel’s view the Cornerstone Placement and Sub-underwriting are fair having regard to the interests of holders of Securities. In any event, whatever judgements are made regarding fairness, the Cornerstone Placement is clearly reasonable. BBI urgently needs to raise substantial amounts of new equity. The Cornerstone Placement is a key part of the Equity Raising, which is likely to be substantially more difficult to achieve in its absence. In the absence of the Equity Raising there is at least some risk that BBI will face some insolvency event, which would almost certainly result in holders of Securities losing all value. Under the Recapitalisation current holders of Securities will in aggregate realise $104 million through the Capital Distribution and some very modest further value on account of their diluted holding of Securities. Holders of Securities will be better off if the Cornerstone Placement proceeds than if it does not. Overall, Grant Samuel has concluded that the Cornerstone Placement and Sub-underwriting are fair and reasonable having regard to the interests of holders of Securities.

The terms of the Asset Acquisitions are generally consistent with terms that might be concluded with third parties.

Pursuant to the proposed Asset Acquisitions, Brookfield will be acquiring: a 49.9% economic interest in DBCT for $295 million; and

all of BBI’s interests in PD Ports, for nominal consideration.

In addition, Brookfield will provide management services to the AET&D and CSC assets subject to supervision of the boards of the relevant entities and have the right to acquire BBI’s interest in these assets for nominal consideration. Grant Samuel has valued a 100% interest in DBCT in the range $581-681 million. This reflects, amongst other valuation evidence, the results of the sale process that BBI ran for DBCT during 2009. The price to be paid by Brookfield for a 49.9% economic interest in DBCT is consistent with this valuation range. Moreover, the proposals that BBI received through its sale process for DBCT would have resulted in BBI realising significantly less than the face value of the offers and significantly less than Brookfield will pay for its 49.9% economic interest, given transaction costs and various retention amounts. On the other hand, under the arrangements whereby BBI will sell a 49.9% economic interest to Brookfield, BBI will remain liable for various contingent liabilities and for stamp duty if Brookfield converts its economic interests into shares and units in the relevant DBCT entities. In certain circumstances either Brookfield or BBI will be entitled to procure the sale of 100% of DBCT (or if the other party proposes to sell, the option to acquire 100% of DBCT). These arrangements are set out in more detail in section 13.6.4 of the Prospectus. While these arrangements are on balance disadvantageous for BBI, the reality is that the creation of an effective joint venture over DBCT would always involve some diminution in BBI’s rights to deal with DBCT on an unfettered basis.

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Overall, the arrangements in relation to DBCT will result in BBI realising value equal to current market value and receiving significantly more cash than if DBCT was to be sold to a third party. In Grant Samuel’s view the terms of the transaction are, overall, no less advantageous than those that would apply to a sale to an arm’s length third party. Grant Samuel has estimated that the full underlying value of BBI’s interest in AET&D is in the range $48-148 million. This represents the estimated value that could be realised for the underlying assets of AET&D on a “willing buyer/willing seller” basis”, less the debt in the AET&D structure. It essentially assumes away the financing risk in the AET&D structure. However, the reality is that AET&D is financially distressed, with surplus cash flow being retained at an individual asset level to service asset level debt facilities, and insufficient free cash flow available to support a re-financing of the AET&D corporate debt facility of $518 million. In these circumstances BBI is unlikely to be able to realise the theoretical full underlying value of its interest in AET&D. Moreover, Grant Samuel’s valuation of the AET&D assets does not take into account potential transaction costs, which in the case of some of the assets could result in a significant reduction in net realisations. In Grant Samuel’s view there would be at least some prospect that BBI would realise zero value for its interest in AET&D in the current market. BBI’s interest in AET&D may have some positive value for Brookfield, given that the debt is limited recourse and that Brookfield will have exposure to any asset value recovery. However, in the absence of the Recapitalisation or some other restructuring, this optionality is unlikely to have any value for BBI: instead values are more likely to be crystallised such that all value is captured by the relevant lenders and there is no residual value for BBI. BBI will provide an indemnity to Brookfield in respect of the management fees payable by AET&D to Brookfield. Even in a worst case outcome in which the indemnity was called upon in full, the liability would not be material in the context of the overall Recapitalisation. Grant Samuel’s assessment is that BBI’s interests in PD Ports and CSC have values of around zero, with asset level debt matching or exceeding current market values for the relevant assets. In Grant Samuel’s view BBI is unlikely to be able to achieve any significant value for its interests in PD Ports and CSC through transactions with arm’s length third parties. In Grant Samuel’s view the terms of the Asset Acquisitions are, overall, consistent with those that would be concluded with third parties, although arguably there is the prospect that some value may be transferred to Brookfield through the arrangements relating to AET&D. However, any value transfer is not likely to be material. In any event, the Asset Acquisitions are an integral part of the Recapitalisation. BBI urgently needs to complete the Recapitalisation (or some other substantial equity raising) to address its pressing financial position.

The Recapitalisation is fair and reasonable to holders of Securities.

Grant Samuel has concluded that the Cornerstone Placement and Sub-underwriting are fair and reasonable to holders of BBI Securities. The terms of the Asset Acquisitions are generally consistent with terms that might be concluded with third parties. Under the Recapitalisation, holders of Securities will realise cash value totalling $104 million, although their future exposure to any recovery in the value of BBI will be minimal. In Grant Samuel’s view there would be a real risk, if the Recapitalisation did not proceed, that BBI would end up in some form of insolvency administration. Accordingly, while the value of Securities in the absence of the Recapitalisation is uncertain, it could well be zero. There is no recapitalisation proposal available to BBI that is superior to the Recapitalisation. On this basis, holders of Securities will be better off if the Recapitalisation proceeds than if it does not. Control of BBI will pass to Brookfield, at least in part. Brookfield will have a minimum holding of 35% and up to 39.9%, which will effectively prevent any change of control transaction without Brookfield’s approval. On the other hand Brookfield will have only limited day to day influence over the operation of BBI. It will have three non-executive directors on the Board of directors, but will not appoint the Chairman or chief executive.

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Given that current holders of Securities will have limited exposure to BBI following the Recapitalisation (as a result of the dilution of their interests following the conversion of EPS), other advantages and disadvantages of the Recapitalisation are not material. BBI would be liable to pay Brookfield up to $7.5 million (of external costs incurred by Brookfield) if the Recapitalisation was not approved. Overall, Grant Samuel believes that holders of Securities will be better off if the Recapitalisation proceeds than if it does not. In Grant Samuel’s view the Recapitalisation is fair and reasonable to holders of Securities.

The Recapitalisation is fair and reasonable to holders of EPS.

Given BBI’s financial position, BBI urgently needs to raise fresh equity. As a practical matter any equity raising is likely to seek to circumscribe the value attributable to holders of EPS, because the alternative would be a significant value transfer from the providers of new equity to holders of EPS. A threshold issue for holders of EPS is whether the value attributable to the EPS under the Recapitalisation exceeds the value likely to be available under the most likely alternative. In Grant Samuel’s view, in the absence of the Recapitalisation there is a meaningful risk that BBI will end up in some form of insolvency administration. It is difficult to estimate with any confidence what values might accrue for the benefit of holders of EPS in this circumstance. However, in Grant Samuel’s view it is highly likely that the values realised for BBI’s assets would be well below the full underlying values estimated in Grant Samuel’s valuation of BBI. In Grant Samuel’s view there would be a real prospect that holders of EPS would realise no value for their securities (although it is conceivable that they could realise at least some value). Based on the values implied by the terms of the Recapitalisation, holders of EPS will receive value of around $333 million (consisting of Securities with an implied value of $285 million and cash dividends of $48 million). This is significantly less than the face value of the EPS of $779 million. However, it represents a substantial premium to the market value of the EPS, which was approximately $150 million when BBI went into trading halt prior to the announcement of the Recapitalisation. In addition, holders of EPS will get the benefit of any re-rating of Securities after the Recapitalisation. Holders of EPS effectively have to compare the delivery of relatively certain value if the Recapitalisation proceeds, albeit at a substantial discount to the face value of the EPS, with the potential loss of all of their investment value if the Recapitalisation does not proceed. This comparison is essentially judgemental, because the future value of Securities following the Recapitalisation is not certain, and because there is a wide range of outcomes for holders of EPS if the Recapitalisation does not proceed and BBI enters some form of insolvency administration. In Grant Samuel’s view, the relative certainty provided by the Recapitalisation, notwithstanding that it does crystallise a loss of value, is preferable to the risk of more substantial value destruction for holders of EPS if the Recapitalisation does not proceed. A secondary question for holders of EPS is whether the Recapitalisation is equitable in the sense of fairly sharing the residual equity value between holders of Securities, EPS and SPARCS. There are no clear guidelines as to what constitutes “fairness” in this context. In the ordinary course the claims of holders of EPS and SPARCS against the asset values of BBI are clearly defined. The value entitlement of EPS and SPARCS is limited to their face value, and rank ahead of the Securities in the context of a winding up. However, value allocation on that basis in the current circumstance is not practical, given the limited total value available and the need to deliver at least some value to holders of all forms of equity if the Recapitalisation is to proceed. Arguably, given that they would rank last in any form of insolvency value realisation process and would almost certainly realise no value, holders of Securities have the weakest claim to any equity value. In this context it could be argued that holders of Securities are receiving a disproportionate share of value. However, holders of Securities will need to realise some non-trivial value for any restructuring to proceed. It appears that holders of SPARCS have a good prospect of realising the face value of their investments, and on that basis will achieve a better outcome than holders of EPS.

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In an absolute sense, on the other hand, given the modest total face value of the SPARCS, any value transfer is limited. Moreover, any attempt to limit the amount of value delivered to holders of the SPARCS would effectively require an amendment to the rights of the holders of the SPARCS, which would in turn require that the Recapitalisation be made subject to the approval of the holders of SPARCS. This would increase the level of transaction risk with only relatively modest potential benefits for holders of EPS. The reality is that there is a need to balance the competing interests of the different sets of security holders with the practical imperative of minimising transaction risk and delivering at least some value to the holders of Securities, EPS and SPARCS. On balance (and having regard to the consequences if the Recapitalisation does not proceed), Grant Samuel believes that the allocation of value as between holders of Securities, EPS and SPARCS is broadly fair. Given that holders of EPS will collectively hold almost all of the 16% of BBI Securities not held by new investors, the structure and prospects of BBI following the Recapitalisation are also a relevant factor in assessing the benefits of the Recapitalisation for holders of EPS. The Recapitalisation will provide a comprehensive solution to BBI’s financial position. All of BBI’s corporate debt (excluding the New Zealand corporate bonds) will be repaid and some pressing asset level debt will also be repaid. BBI will effectively be able to cut free subsidiary assets that clearly have no value (such as PD Ports and CSC) and the effective deconsolidation of AET&D will simplify the group, including from the perspective of investors. Holders of BBI Securities, including current holders of EPS, will be exposed to any upside in the BBI asset base that might result from an improvement in debt and equity markets or underlying economic conditions. On the other hand, holders of EPS (as holders of Securities after the Recapitalisation) will have lost their exposure to any potential recovery in value in the AET&D asset portfolio. Their investment exposure to DBCT will be reduced and may be further affected if Brookfield exercises its right to trigger a 100% sale in the future and BBI is not in a position to purchase their interest. At a corporate level, Brookfield’s position on the register, with a holding of Securities of at least 35% and up to 39.9%, will mean that there can be no takeover of BBI without Brookfield’s approval and will limit trading liquidity (although there is currently limited trading liquidity in BBI securities). While it will not have outright control, with only three non-executive directors on the board and no right to appoint the Chairman or senior executives, Brookfield will clearly be in a position to influence the future direction of BBI. These factors are disadvantages, but are not material in the overall context of the Recapitalisation. In Grant Samuel’s view holders of EPS are likely to be better off if the Recapitalisation proceeds than if it does not. Grant Samuel has therefore concluded that the Recapitalisation is fair and reasonable having regard to the interests of holders of EPS.

4 Other Matters

This report is general financial product advice only and has been prepared without taking into account the objectives, financial situation or needs of individual holders of BBI Securities or BBI EPS. Because of that, before acting in relation to their investment, shareholders should consider the appropriateness of the advice having regard to their own objectives, financial situation or needs. Holders of Securities and EPS should read the Explanatory Memorandum issued by BBI in relation to the Recapitalisation Voting for or against the Recapitalisation and its component parts is a matter for individual holders of Securities and EPS, based on their own views as to value and future market conditions and their particular circumstances including risk profile. Holders of Securities and EPS who are in doubt as to the action they should take should consult their own professional adviser.

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This letter does not constitute investment advice. Grant Samuel gives no opinion as to whether holders of Securities or EPS should buy, hold or sell BBI Securities or EPS. Grant Samuel has prepared a Financial Services Guide as required by the Corporations Act, 2001. The Financial Services Guide is included at the beginning of this summary. The opinion is made as at the date of this letter and reflects circumstances and conditions as at that date.

Yours faithfully GRANT SAMUEL & ASSOCIATES PTY LIMITED

Table of Contents

1 Terms of the Proposal ...................................................................................................................................1

2 Scope of the Report........................................................................................................................................7

3 Industry Overview.......................................................................................................................................13 3.1 Energy Industry................................................................................................................................13 3.2 Port and Rail Industry .....................................................................................................................28

4 Profile of BBI ...............................................................................................................................................33 4.1 Background.......................................................................................................................................33 4.2 Assets .................................................................................................................................................34 4.3 Structure and Fees............................................................................................................................36 4.4 Financial Performance.....................................................................................................................38 4.5 Financial Position .............................................................................................................................41 4.6 Cash Flow..........................................................................................................................................44 4.7 Taxation Position..............................................................................................................................44 4.8 Capital Structure and Ownership...................................................................................................44 4.9 Security Price Performance.............................................................................................................45

5 Description of BBI Assets............................................................................................................................49 5.1 Energy Transmission and Distribution ..........................................................................................49 5.2 Transport ..........................................................................................................................................59

6 Valuation of BBI ..........................................................................................................................................68 6.1 Valuation Summary .........................................................................................................................68 6.2 Methodology .....................................................................................................................................69 6.3 Valuation of AET&D .......................................................................................................................73 6.4 Valuation of Other Energy Transmission and Distribution Assets..............................................91 6.5 Valuation of Transport Assets.......................................................................................................103 6.6 Corporate Costs..............................................................................................................................118 6.7 Corporate Net Borrowings ............................................................................................................119 6.8 Other Liabilities..............................................................................................................................119

7 Evaluation of the Recapitalisation............................................................................................................120 7.1 Conclusion.......................................................................................................................................120 7.2 BBI’s Financial Position ................................................................................................................122 7.3 Effect of the Recapitalisation.........................................................................................................122 7.4 Alternatives to the Recapitalisation ..............................................................................................122 7.5 Impact of the Conversion of EPS ..................................................................................................124 7.6 Underlying Value Attributable to Securities................................................................................126 7.7 Evaluation of the Cornerstone Placement and Sub-underwriting .............................................127 7.8 Evaluation of the Asset Acquisitions.............................................................................................128 7.9 Impact of the Restructuring on Holders of Securities.................................................................129 7.10 Impact of the Recapitalisation on Holders of EPS ......................................................................130 7.11 Decisions for Holders of Securities and EPS................................................................................132

8 Qualifications, Declarations and Consents ..............................................................................................133 Appendices 1 Selection of Discount Rate 2 Discounted Cash Flow Model Assumptions 3 Valuation Evidence from Comparable Listed Companies 4 Valuation Evidence from Transactions

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1 Terms of the Proposal

Background Babcock & Brown Infrastructure Group (“BBI”) is an Australian Securities Exchange (“ASX”) listed investment fund focussed on owning and operating energy transmission and distribution and transport infrastructure and associated assets. It listed on the ASX on 24 June 2002 as Prime Infrastructure Group and changed its name to BBI on 1 July 2005. BBI is one of three listed infrastructure funds that were established by Babcock & Brown Limited (“Babcock & Brown”) over the last decade, along with Babcock & Brown Power (“BBP”) and Babcock & Brown Wind Partners (“BBW”) (now Infigen Energy). BBI is a stapled group that comprises Babcock & Brown Infrastructure Limited (“BBIL”) and Babcock & Brown Infrastructure Trust (“BBIT”), of which Babcock & Brown Investor Services Limited (“BBIS”) is the responsible entity. Babcock & Brown Infrastructure Management Pty Limited (“BBIM”) is the manager of BBI. The boards of directors of BBIL and BBIS are the same, except that the Managing Director of BBIL is not on the board of BBIS. BBIS and BBIM are wholly owned subsidiaries of Babcock & Brown International Pty Limited (“B&B Group”), the main operating subsidiary of Babcock & Brown. B&B Group holds a 5.94% interest in BBI. On 31 August 2007, following a competitive process, a consortium comprising B&B Group and Singapore Power International Pte Limited (“Singapore Power”) acquired Alinta Limited (“Alinta”), the largest Australian energy infrastructure owner and operator. Following the acquisition, the assets and liabilities of Alinta were distributed between Singapore Power, BBI, BBP and BBW. BBI funded the assets that it acquired through a combination of:

the issue to Alinta shareholders of 380.8 million BBI stapled securities (Securities);

the issue to Alinta shareholders of 778.7 million $1.00 BBI exchangeable preference shares (“EPS”) (which were quoted on the ASX); and

the assumption of $1.1 billion of limited recourse debt, including a committed, limited recourse debt bridging line of $518 million (which was refinanced in July 2008).

On completion of the acquisition, BBI had approximately $650 million of additional debt capacity that it stated was available to pursue acquisition opportunities. The global financial crisis which commenced in late 2007 resulted in turmoil in the equity and credit capital markets and has had significant implications for world economic activity. In particular, credit markets tightened substantially, resulting in negative market sentiment towards entities with high levels of gearing and the external asset management business model. The changed market conditions have been catastrophic for Babcock & Brown and its listed investment funds. From mid 2008 Babcock & Brown focussed on restructuring its business (including its relationships with its listed funds) and debt facilities. Despite its efforts, voluntary administrators were appointed to Babcock & Brown on 13 March 2009 and it was delisted from the ASX on 18 June 2009. Subsequently, on 24 August 2009, the creditors of Babcock & Brown voted to place Babcock & Brown into liquidation. The appointment of liquidators to Babcock & Brown has not had a material impact on B&B Group which is continuing an orderly realisation of its assets to reduce debt. BBI has also been impacted by the changed market conditions since late 2007. BBI acquired a number of assets over the period from September to December 2007, in particular growing its portfolio of European Ports (“Euroports”) and acquiring an effective 26.4% interest in the Natural Gas Pipeline of America (“NGPL”). Despite BBI’s confirmation in December 2007 that its balance sheet was in a strong position with conservative gearing, BBI’s Security price subsequently fell substantially (from $1.57 to $0.82). In June 2008, BBI announced that it would undertake a review of its capital management policies, including gearing levels and distribution policy, and would contemplate the sale

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of various assets (Powerco, Dalrymple Bay Coal Terminal (“DBCT”), PD Ports Limited (“PD Ports”), Euroports and WestNet Rail). BBI subsequently announced a number of initiatives including:

a revised distribution policy under which payments would be funded from free cash flow. As a result, the final distribution for the year ended 30 June 2008 was reduced from 7.5 cents per Security to 2.5 cents per Security and distribution guidance for the year ending 30 June 2009 was reduced from 16.0 cents per Security to 10.0 cents per Security. In November 2008, BBI suspended payment of distributions on Securities and deferred dividends on EPS until further notice;

the sale of interests in a number of assets:

• a 58% interest in Powerco to funds managed by QIC Limited (“QIC”) for NZ$421.2 million;

• International Energy Group’s (“IEG’s”) Portugal business to Fundo Explorer II for £40.1 million; and

• 40% of the Euroports portfolio to Antin Infrastructure Partners (“Antin”) and Arcus European Infrastructure Fund I (“Arcus”) for €141.5 million (which, after allowing for the funding of BBI’s share of growth capital expenditure and the acquisition of the minority positions within the Euroports portfolio, provided net proceeds to BBI of €35.0 million which was used to repay a short term loan at the Euroports level).

The net proceeds from these sales have been used to repay $390 million of asset level non-recourse and corporate debt and have enabled BBI to pay obligations associated with the minority interests in WestNet Rail (increasing its ownership interest to 96%). BBI also announced that it was continuing to pursue sales of interests in DBCT and PD Ports; and

the internalisation of its management, under which:

• the management agreements and the exclusive financial advisory agreement between BBI and Babcock & Brown will be terminated for no consideration;

• all employees dedicated to the management of BBI will be offered re-employment in an internalised management structure within BBI;

• BBIS will continue as responsible entity of BBIT, but its ownership will be transferred to its directors, and it will be subject to arrangements under which the right to appoint and remove BBIS directors will vest in BBIT unitholders. Once BBIS has been transferred to the directors it will cease to have any rights to receive management fees, and will only be entitled to recovery of the costs it incurs in acting as responsible entity; and

• BBIL will change its name to Prime Infrastructure Holdings Limited and BBIT will be renamed Prime Infrastructure Trust. BBIS will also change its name.

The internalisation is subject to the approval of BBI’s corporate lenders. On 26 August 2009, BBI released its results for the year ended 30 June 2009. Although the underlying operating businesses performed well given current market conditions (with EBITDA increasing from $788.9 million to $1.0 billion), BBI announced a net loss after tax of $977.1 million as a result of an $895.1 million (pre tax) impairment charge and a $227.0 million (pre tax) unfavourable mark-to-market movement associated with interest rate and foreign exchange hedges, offset in part by a $123.7 million (pre tax) gain on the sale of a 58% interest in Powerco. The impairment change was primarily against BBI’s PD Ports and Euroports businesses. At 31 August 2009, BBI had $8.0 billion in total proportionate4 non-recourse debt at the asset level and a further $1.2 billion in corporate debt facilities. Of this amount, $3.2 billion matures in the years

4 “Proportionate” refers to BBI’s effective share of the non-recourse debt in each relevant underlying asset, where such share equals

BBI’s interest in the relevant asset.

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ending 30 June 2010 and 2011, including $731 million of corporate debt, approximately $300 million5 of which is required to be repaid in February 2010. Despite the changes outlined above, BBI’s security price declined to 7.8 cents prior to a trading halt on 2 September 2009, as it become apparent that BBI’s focus on sales of assets as its primary strategy for achieving debt repayment would be difficult in the current market environment, with timing and value outcomes uncertain. In addition, while there have been no breaches of any debt covenants within the BBI portfolio, in the case of a number of assets all operating cash flows are being applied to reduce debt at the asset level, resulting in a decline in distributions to BBI at the corporate level, which in turn affects its ability to meet short term debt repayments. As a result, it has been necessary for BBI to pursue a more comprehensive equity recapitalisation of its business. On 4 September 2009, BBI announced that it was in discussions with a potential cornerstone investor, although the structure and details of any transaction had not been finalised. BBI stated that it was likely that any transaction would require the full conversion into Securities of EPS and BBI Networks (New Zealand) Subordinated Prime Adjusting Reset Convertible Securities (“SPARCS”) and that the ownership interests of holders of Securities, and EPS holders and SPARCS holders post conversion, would be significantly diluted by the recapitalisation. BBI entered into an interim agreement with the potential cornerstone investor to continue to develop the proposed transaction. This agreement included a non-solicitation obligation on BBI, a capped cost reimbursement provision in favour of the potential cornerstone investor and a three month right of first refusal over the sale of certain assets. On 17 September 2009, BBI received a refinancing proposal from The Royal Bank of Scotland, acting on behalf of an investor group comprising primarily international hedge funds (collectively the “RBS Consortium”). The RBS Consortium proposal contemplated injecting approximately $1.35 billion of new capital into BBI, comprising $600 million of new Convertible and Redeemable Bonds, a new corporate debt facility of $350 million and $400 million of new equity, half of which would come from existing Securityholders. BBI commented that the new equity raised after transaction costs and other payments (including the closure of interest rate swaps) would not materially change BBI’s gearing levels, or address near term maturities of its debt facilities. On 28 September 2009, the RBS Consortium submitted a revised proposal (“RBS Proposal”) addressing BBI’s concerns discussed above. The RBS Proposal included additional funding of $250 million and revised security arrangements. No other changes were made to the original proposal. On 30 September 2009, BBI rejected the RBS Proposal on the following basis:

it did not fundamentally address BBI’s debt position (of the new funding proposal of $1,500 million only $500 million was equity); and

there were considerable execution risks associated with the proposal, including the number of parties involved and the requirement for those parties to complete due diligence and agree transaction terms in a timely manner.

On 8 October BBI announced a recapitalisation which included signing an Implementation Agreement with Brookfield Asset Management Inc (“Brookfield”) (the “Recapitalisation”). Brookfield is a global asset manager focused on real assets in the property and infrastructure sectors and is listed on the New York, Toronto and NYSE Euronet Stock Exchanges. Brookfield has over US$80 billion of assets under management, including US$15 billion of infrastructure assets comprised of 163

5 £82.2 million or approximately $169 million is due in February 2010 although under the cash sweep mechanism agreed with the

BBI corporate lenders, BBI will be required to repay approximately $300 million in corporate debt to meet this debt maturity in February 2010.

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hydro power plants in Canada, the United States and Brazil, one wind farm and over 8,800 kilometres of electricity transmission lines in Chile and Canada. Overview of the Proposal The Recapitalisation consists of the following:

a $1,500 million equity raising consisting of the issue of new Securities (“New Securities”):

• a $625 million placement to the cornerstone investor, Brookfield (“Cornerstone Placement”);

• a fully underwritten $625 million institutional placement to new and existing institutional investors (“Institutional Placement”); and

• a fully underwritten security purchase plan (“SPP”) to eligible holders of Securities to raise $250 million. Brookfield will sub-underwrite the SPP up to a maximum of $87.5 million and will be given a priority over amounts called upon pursuant to this underwriting (“Sub-underwriting”),

collectively the “Equity Raising”. This will result in Brookfield holding between 35-39.9% of the number of Securities on issue upon completion of the Recapitalisation depending on the participation in the SPP;

asset arrangements with Brookfield (collectively “Asset Acquisitions”) as follows:

• Brookfield will acquire:

- a 49.9% interest in DBCT for approximately $295 million; and

- 100% interest in PD Ports for nominal proceeds6;

• Brookfield will provide management services to the Australian Energy Transmission & Distribution (“AET&D”) and Cross Sound Cable (“CSC”) assets, subject to supervision of the boards of the relevant entities, and have the right to acquire BBI’s interest in these assets for nominal proceeds;

the repayment of BBI’s outstanding corporate debt from the proceeds from the Equity Raising;

the conversion of EPS into Securities and the payment of $48 million of accrued and deferred dividends to the EPS holders; and

a capital distribution of $104 million (or $0.04 per Security) (“Capital Distribution”) to registered Securityholders as at 16 November 2009 (“Eligible Securityholders”).

All the New Securities under the Equity Raising will be offered for and issued at the same price. The offer price will be set so that New Securities issued under the:

Cornerstone Placement will represent 35%;

Institutional Placement will represent 35%; and

SPP will represent 14%;

of the total number of Securities on issue upon completion of the Recapitalisation.

The number of Securities on issue upon completion of the Recapitalisation will depend on the number of Securities issued on conversion of the EPS and the number of Securities (if any) issued on conversion

6 As part of the PD Ports acquisition, Brookfield will also repay £100 million (approximately $200 million) in term and acquisition

facilities within PD Ports, and make payments to terminate associated swaps.

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of SPARCS. For further details on the calculation of the offer price, please refer to Section 3.6 of the Prospectus.

BBI will internalise its management. The current external manager, BBIM, will be removed and the existing management team will be directly employed by a subsidiary of BBI. BBI also proposes to change its name to Prime Infrastructure and to consolidate the number of Securities on issue (although the Recapitalisation is not conditional on the change of name and consolidation of Securities).

The following table illustrates BBI’s effective ownership interest in the current asset portfolio, pre and post Recapitalisation:

BBI Asset Ownership

Asset Effective Ownership pre Recapitalisation

Effective Ownership post Recapitalisation

Energy Transmission & Distribution NGPL 26.4% 26.4% Powerco NZ 42% 42% IEG 100% 100% Tas Gas 100% 100% AET&D Various Held for sale CSC 100% Held for sale

Transport Infrastructure DBCT 100% 50.1% WestNet Rail 96% 100% Euroports 60% 60% PD Ports 100% Sold

Source: BBI Further details of the Recapitalisation are explained in Section 2 of the Prospectus. Approvals Required The Recapitalisation will only proceed if the following resolutions are passed by the holders of Securities or EPS (as applicable) at the meetings to be held on 16 November 2009:

an ordinary resolution of holders of Securities approving the issue of new Securities under the Cornerstone Placement and under a sub-underwriting;

an ordinary resolution of holders of Securities approving the issue of new Securities to the Institutional Investors under the Institutional Placement;

an ordinary resolution of holders of Securities approving the issue of new Securities to Eligible holders of Securities under the SPP;

collectively the “BBI Recapitalisation Resolutions”; and

a special resolution of EPS holders approving an amendment to the terms of the EPS, the conversion of the EPS in accordance with the terms of the EPS and the lifting of the dividend stopper to allow for the payment of the Capital Distribution (“EPS Resolutions” and together with the BBI Recapitalisation Resolutions the “Recapitalisation Resolutions”).

The Recapitalisation Resolutions are inter-conditional. Therefore, if any of the Recapitalisation Resolutions are not passed, the Recapitalisation will not proceed.

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BBI is also proposing a number of additional resolutions to be approved by holders of Securities, including the consolidation of Securities on issue immediately after conversion of EPS and any SPARCS and the change of name. If these additional resolutions are not passed, the Recapitalisation will still proceed. The Recapitalisation is also subject to a number of conditions precedent (as set out in Section 13.6 of the Prospectus) including:

receipt of regulatory approvals (including approval from Foreign Investment Review Board in Australia and Overseas Investment Office in New Zealand);

receipt of agreed lender approvals and required third party consents;

the underwriting agreement not having been terminated; and

no material adverse change in BBI.

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2 Scope of the Report

2.1 Purpose of the Report

The Cornerstone Placement as part of the Recapitalisation is subject to the approval of BBI Securityholders in accordance with Item 7 of Section 611 of the Corporations Act, 2001. Section 606 of the Corporations Act, 2001 (“Corporations Act”) effectively prohibits a person from acquiring a relevant interest in a public company where that person’s voting power increases from 20% or below to in excess of 20% or, if that person already has voting power in excess of 20%, their voting power would increase further, except in certain limited circumstances. As Brookfield’s relevant interest will increase from 0% to between 35-39.9% (depending on number of Securities that Brookfield will subscribe for pursuant to the Sub-Underwriting), the Brookfield would otherwise breach Section 606. Item 7 of Section 611 allows non associated shareholders to waive the Section 606 prohibition by passing a resolution in a general meeting. Consequently, BBI is seeking Securityholder approval for the issue of Securities in excess of 20% of issued capital to Brookfield under the Recapitalisation. Item 7(b) of Section 611 requires that shareholders voting pursuant to Item 7 of Section 611 of the Corporations Act be provided with a comprehensive analysis of the proposed transaction. The directors of the company may satisfy their obligations to provide such an analysis by commissioning an independent expert’s report. The directors of BBI who are not associated with Brookfield (“the independent directors”) have engaged Grant Samuel & Associates Pty Limited (“Grant Samuel”) to prepare an independent expert’s report for the purposes of Section 611 stating whether, in its opinion, the proposed Recapitalisation as a whole, and the Cornerstone Placement and Sub-underwriting, are fair and reasonable to the interests of the non associated holders of Securities and whether the proposed Recapitalisation as a whole is fair and reasonable to the EPS holders. A summary of the report will accompany the Notice of Meeting and Explanatory Memorandum (“the Explanatory Memorandum”) to be sent to Securityholders by BBI. The full report will be lodged with the ASX and available on BBI’s website at www.bbinfrastructure.com. This report is general financial product advice only and has been prepared without taking into account the objectives, financial situation or needs of individual BBI Securityholders. Accordingly, before acting in relation to their investment, Securityholders should consider the appropriateness of the advice having regard to their own objectives, financial situation or needs. Securityholders should read the Explanatory Memorandum issued by BBI in relation to the Recapitalisation. Voting for or against the Recapitalisation is a matter for individual holders of Securities and EPS based on their views as to value, their expectations about future market conditions and their particular circumstances including risk profile, liquidity preference, investment strategy, portfolio structure and tax position. Holders of Securities and EPS who are in doubt as to the action they should take in relation to the Recapitalisation should consult their own professional adviser. Similarly, it is a matter for individual holders of Securities and EPS as to whether to buy, hold or sell securities in BBI, including as to whether to participate in the SPP. This is an investment decision independent of a decision to vote for or against the Recapitalisation. Grant Samuel does not offer an opinion on this investment decision. Holders of Securities and EPS should consult their own professional adviser in this regard.

2.2 Basis of Evaluation

The Australian Securities & Investments Commission (“ASIC”) has issued Regulatory Guide 111 which establishes guidelines in respect of independent expert’s reports. ASIC Regulatory Guide 111 differentiates between the analysis required for control transactions and other

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transactions. It provides that a proposal under Item 7 of Section 611 involving the issue of securities should be analysed by an expert as if it were a takeover bid. In contrast, in relation to a proposal under Item 7 of Section 611 involving the sale of securities, ASIC Regulatory Guide 111 requires an expert to provide an opinion as to whether the advantages of the proposal outweigh the disadvantages. In this case, the Cornerstone Placement involves the issue of new Securities in BBI to Brookfield. The effect of this Cornerstone Placement is to increase Brookfield’s interest in BBI to 35-39.9% (depending on the take up under the SPP). Accordingly, the appropriate opinion should be evaluated as a control transaction and considered whether the proposal is “fair and reasonable”. The term “fair and reasonable” has no legal definition although over time a commonly accepted interpretation has evolved. In the context of a takeover, an offer is considered fair and reasonable if the price fully reflects the value of a company’s underlying businesses and assets. ASIC Regulatory Guide 111 continues earlier regulatory guidelines that create a distinction between “fair” and “reasonable”. Fairness is said to involve a comparison of the offer price with the value that may be attributed to the securities that are the subject of the offer based on the value of the underlying businesses and assets. In determining fairness any existing entitlement to shares by the offeror is to be ignored. Reasonableness is said to involve an analysis of other factors that shareholders might consider prior to accepting a takeover offer such as:

the offeror’s existing shareholding;

other significant shareholdings;

the probability of an alternative offer; and

the liquidity of the market for the target company’s shares. A takeover offer could be considered “reasonable” if there were valid reasons to accept the offer notwithstanding that it was not “fair”. Fairness is a more demanding criteria. A “fair” offer will always be “reasonable” but a “reasonable” offer will not necessarily be “fair”. A fair offer is one that reflects the full market value of a company’s businesses and assets. A takeover offer that is in excess of the pre-bid market prices but less than full value will not be fair but may be reasonable if shareholders are otherwise unlikely in the foreseeable future to realise an amount for their shares in excess of the bid price. This is commonly the case in takeover offers where the bidder already controls the target company. In that situation the minority shareholders have little prospect of receiving full value from a third party offeror unless the controlling shareholder is prepared to sell its controlling shareholding. In the context of a transaction requiring shareholder approval for the purposes of Section 611 of the Corporations Act, the meaning of “fair and reasonable” is less clear. Prior to the recent introduction of Regulatory Guide 111 by the Australian Securities and Investments Commission (“ASIC”), “fair and reasonable” in the context of a Section 611 proposal was a single concept, with the independent expert essentially required to form a view as to whether the proposal was, overall, in the best interests of non-associated shareholders. Regulatory Guide 111 requires that an independent expert approach a Section 611 analysis in a way analogous to a takeover transaction. On this basis, in forming an opinion as to whether a proposal is fair and reasonable having regard to the interests of the non associated shareholders, an expert would normally determined whether the proposal is fair by comparing the estimated underlying value range of the company on a per share basis with the price at which the shares are to be issued. The proposal will be fair if the price at which the shares are to be issued falls within or is greater than the underlying value range of the company on a per share basis. The expert would make an assessment of whether the proposal is reasonable by considering other benefits and disadvantages of the proposal and whether, having regard to fairness and other factors, non-associated shareholders would be better of if the proposal proceeded than if it did not.

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The application of this framework in analysing the Recapitalisation is problematic. The offer price under the Equity Raising has not yet been determined and will depend on the number of Securities upon completion of the Recapitalisation, which in turn will depend on the number of Securities into which EPS have converted and whether any SPARCS have been converted (although the conversion process of the EPS is to be amended such that the number of Securities to be issued, and therefore the offer price, will almost certainly fall within a range of values). In addition, there is considerable uncertainty as to what underlying value is attributable to holders of Securities. Grant Samuel’s analysis indicates that there is a strong prospect that the net asset value of BBI is less than the face value of EPS and SPARCS. In this circumstance, there is a need to determine an allocation of underlying value between holders of Securities, EPS and SPARCS, but there are no clear guidelines as to how this allocation should be made. On one view, it may be reasonable to attribute no underlying value to holders of Securities. Such an outcome would lead to a conclusion that the Cornerstone Placement was fair at any price. In addition, the conventional approach to assessing fairness would not take into account the value that holders of Securities will realise through the Capital Distribution, which is a direct consequence, and would not proceed in the absence, of the Cornerstone Placement and other elements of the Equity Raising. Grant Samuel’s assessment of fairness takes all these issues into account. In determining whether the Recapitalisation is reasonable, the factors that have been considered by Grant Samuel include:

the current financial position of BBI, with particular reference to the quantum and maturity profile of BBI’s borrowings;

alternatives available to BBI to address issues associated with the quantum and maturity profile of BBI’s borrowings;

potential consequences for BBI and the holders of BBI Securities and EPS in the event that BBI is unavailable to significantly reduce its gearing;

the terms of the proposed Cornerstone Placement and their impact on Securityholders;

the impact on BBI’s business, financial position and risk profile;

the impact on ownership and control of BBI; and

any other benefits and disadvantages of the Recapitalisation.

2.3 Sources of the Information

The following information was utilised and relied upon, without independent verification, in preparing this report: Publicly Available Information

the Prospectus and Explanatory Memorandum (including earlier drafts);

annual reports of BBI for the five years ended 30 June 2009;

press releases, public announcements, media and analyst presentation material and other public filings by BBI including information available on its website;

brokers’ reports and recent press articles on BBI and the energy and transport infrastructure sectors;

sharemarket data and related information on Australian and international listed companies engaged in the energy and transport infrastructure sectors and on acquisitions of companies and businesses in these sectors; and

information relating to the Australian and international energy and transport infrastructure sectors including supply/demand forecasts and regulatory decisions and pronouncements (as appropriate).

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Non Public Information provided by BBI

monthly management reports for all assets;

corporate and asset level budgets for BBI for the period ending 30 June 2010;

asset management plans and financial models for most assets; and

other confidential documents, certain board papers, presentations and working papers including relevant documents in relations to the sale of some of BBI’s assets.

In preparing this report, Grant Samuel held discussions with, and obtained information from, senior management of BBI and its advisers.

2.4 Limitations and Reliance on Information

Grant Samuel believes that its opinion must be considered as a whole and that selecting portions of the analysis or factors considered by it, without considering all factors and analyses together, could create a misleading view of the process underlying the opinion. The preparation of an opinion is a complex process and is not necessarily susceptible to partial analysis or summary. Grant Samuel’s opinion is based on economic, sharemarket, business trading, financial and other conditions and expectations prevailing at the date of this report. These conditions can change significantly over relatively short periods of time. If they did change materially, subsequent to the date of this report, the opinion could be different in these changed circumstances. This report is also based upon financial and other information provided by BBI and its advisers. Grant Samuel has considered and relied upon this information. BBI has represented in writing to Grant Samuel that to its knowledge the information provided by it was complete and not incorrect or misleading in any material aspect. Grant Samuel has no reason to believe that any material facts have been withheld. The information provided to Grant Samuel has been evaluated through analysis, inquiry and review to the extent that it considers necessary or appropriate for the purposes of forming an opinion as to whether the Recapitalisation is fair and reasonable to Securityholders. However, Grant Samuel does not warrant that its inquiries have identified or verified all of the matters that an audit, extensive examination or “due diligence” investigation might disclose. While Grant Samuel has made what it considers to be appropriate inquiries for the purposes of forming its opinion, “due diligence” of the type undertaken by companies and their advisers in relation to, for example, prospectuses or profit forecasts, is beyond the scope of an independent expert. In this context, Grant Samuel advises that:

it is not in a position nor is it practicable to undertake its own “due diligence” investigation of the type undertaken by accountants, lawyers or other advisers; and

it was not given access to non public information (including financial and operational information) for BBI’s minority investment in the Dampier to Bunbury Natural Gas Pipeline and was only provided with limited financial and operational information on BBI’s minority interest in NGPL.

Accordingly, this report and the opinions expressed in it should be considered more in the nature of an overall review of the anticipated commercial and financial implications rather than a comprehensive audit or investigation of detailed matters. An important part of the information used in forming an opinion of the kind expressed in this report is comprised of the opinions and judgement of management. This type of information was also evaluated through analysis, inquiry and review to the extent practical. However, such information is often not capable of external verification or validation.

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Preparation of this report does not imply that Grant Samuel has audited in any way the management accounts or other records of BBI. It is understood that the accounting information that was provided was prepared in accordance with generally accepted accounting principles and in a manner consistent with the method of accounting in previous years (except where noted). The information provided to Grant Samuel included:

the pro-forma forecasts for the year ending 30 June 2010 prepared by management and adopted by the directors of BBI;

the pro forma financial position as at 30 June 2009 for BBI;

net debt and marked-to-market swap values as at 31 August 2009; and

long term financial models for certain BBI assets. BBI is responsible for this financial information. Grant Samuel has used and relied on this financial information for the purposes of its analysis. Grant Samuel has spent considerable time investigating this financial information in terms of the reasonableness of the underlying assumptions, accuracy of compilation and application of assumptions. As a result, Grant Samuel considers that, based on the inquiries it has undertaken and only for the purposes of its analysis for this report (which do not constitute, and are not as extensive as, an audit or accountant’s examination), there are reasonable grounds to believe that the budgets and longer term forecasts have been prepared on a reasonable basis. In forming this view, Grant Samuel has taken the following factors, inter alia, into account that:

the BBI Forecast and the BBI Financial Position have been subject to comprehensive review by Deloitte Touche Tohmatsu (“Deloitte”) and its opinion is set out in the Prospectus; and

BBI has detailed budgeting processes in place for most of its assets which have been prepared by the various asset management teams and approved by the asset boards (which consist of BBI Executive Nominee Directors. In any event a number of BBI’s assets are well established and generate relatively predictable earnings and cash flows.

Grant Samuel has no reason to believe that the forecast financial information reflects any material bias, either positive or negative. However, the achievability of the forecast financial is not warranted or guaranteed by Grant Samuel. Future profits and cash flows are inherently uncertain. They are predictions by management of future events that cannot be assured and are necessarily based on assumptions, many of which are beyond the control of the company or its management. Actual results may be significantly more or less favourable. As part of its analysis, Grant Samuel has reviewed the sensitivity of net present values to changes in key variables. The sensitivity analysis isolates a limited number of assumptions and shows the impact of the expressed variations to those assumptions. No opinion is expressed as to the probability or otherwise of those expressed variations occurring. Actual variations may be greater or less than those modelled. In addition to not representing best and worst outcomes, the sensitivity analysis does not, and does not purport to, show the impact of all possible variations to the business model. The actual performance of the business may be negatively or positively impacted by a range of factors including, but not limited to:

changes to the assumptions other than those considered in the sensitivity analysis;

greater or lesser variations to the assumptions considered in the sensitivity analysis than those modelled; and

combinations of different variations to a number of different assumptions that may produce outcomes different to the combinations modelled.

In forming its opinion, Grant Samuel has also assumed that:

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matters such as title, compliance with laws and regulations and contracts in place are in good standing and will remain so and that there are no material legal proceedings, other than as publicly disclosed;

the information set out in the Prospectus and Explanatory Memorandum sent by BBI to its Securityholders is complete, accurate and fairly presented in all material respects;

the publicly available information relied on by Grant Samuel in its analysis was accurate and not misleading;

the Recapitalisation will be implemented in accordance with its terms; and

the legal mechanisms to implement the Recapitalisation are correct and will be effective. To the extent that there are legal issues relating to assets, properties, or business interests or issues relating to compliance with applicable laws, regulations, and policies, Grant Samuel assumes no responsibility and offers no legal opinion or interpretation on any issue.

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3 Industry Overview

3.1 Energy Industry

3.1.1 Australia

Overview

Energy consumption in Australia has grown at an average rate of 1.3% per annum over the last ten years7. This modest rate of growth reflects the impact of the global financial crisis on economic activity, particularly in 2008 (when energy consumption fell to 2005 levels). Average annual growth in energy consumption prior to 2008 had been in the range 1.5-2.0%. Since the early 1990s, growth in energy consumption has generally remained below the rate of economic growth, reflecting both greater efficiency (through technological improvement and fuel switching) and the higher growth rates of less energy intensive sectors (e.g. commercial and services) than those of energy intensive sectors (e.g. manufacturing). Trends in energy intensity are not uniform across Australia, with the growing resources sector in Western Australia having higher energy intensity than Victoria, which has a strong services sector. Although the major fuel sources in Australia continue to be coal and oil, natural gas and renewable resources have become increasingly important energy sources, primarily at the expense of oil. High prices for fossil fuels combined with a growing focus on minimising carbon emissions have increased demand for natural gas as an energy fuel source and encouraged the rapid growth of renewable energy sources. Energy consumption in Australia is expected to continue to grow in the foreseeable future. Natural gas is projected to be the fastest growing fossil fuel over the period to 2030, with an average growth rate of 2.6% per annum expected through to 2030, although a higher rate of 4.0% per annum is forecast in the shorter term to 2012. This rate of growth is expected to increase the natural gas share of total energy consumption from 19% to 24%. Growth in gas consumption will result from factors including general economic growth, population growth and growth in new housing, Segments and Services

In summary, the segments of, and services to, the energy industry can be depicted as follows:

Energy Industry Structure

Generation/Wholesale Transmission Distribution Retail

Power plants generate electricity for supply to the Australian electricity markets

Transmission networks transport electricity from generators to population centres

Low voltage electricity is distributed via a network of poles and wires to consumer sites

Residential, commercial and industrial consumers buy electricity from retailers

Ele

ctri

city

Onshore and offshore gas fields are drilled to access gas reserves

Large high pressure pipelines carry gas from the gas fields to key markets

Gas is distributed via a network of low pressure pipelines to consumer sites

Residential, commercial and industrial consumers buy gas from retailersG

as

Design, construct, operate, maintain and manage electricity and gas infrastructure

Services

Energy Industry Structure

Generation/Wholesale Transmission Distribution Retail

Power plants generate electricity for supply to the Australian electricity markets

Transmission networks transport electricity from generators to population centres

Low voltage electricity is distributed via a network of poles and wires to consumer sites

Residential, commercial and industrial consumers buy electricity from retailers

Ele

ctri

city

Onshore and offshore gas fields are drilled to access gas reserves

Large high pressure pipelines carry gas from the gas fields to key markets

Gas is distributed via a network of low pressure pipelines to consumer sites

Residential, commercial and industrial consumers buy gas from retailersG

as

Design, construct, operate, maintain and manage electricity and gas infrastructure

Services

Source: Grant Samuel

7 Information in this report on the Australian energy industry is from a wide range of sources. The major sources are BP Statistical

Review of World Energy June 2009, ABARE Research Report 07.24 “Australian Energy: National and State Projections to 2029-30” and State of the Energy Markets 2008, AER, November 2008.

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BBI predominantly operates in the gas transmission and distribution segment of the Australian energy industry. The remainder of this Section 3.1.1 provides an overview of the natural gas segment of the energy industry and the regulatory environment in Australia. Regulatory Environment

Historically, Australia’s energy sector comprised state based, government-owned enterprises. It is only in recent decades, as a consequence of economic and legislative changes, that the private sector has become increasingly involved in ownership and operation of energy assets. However, as the management of energy resources, production and supply of energy and stability of energy markets are critical to the economy, the energy sector has continued to be the subject of extensive regulation. The regulatory environment is currently undergoing reform. On 30 June 2004, the Australian Government and each of the states and territories agreed to redesign the regulatory functions for the energy sector and establish two new national regulatory bodies: the Australian Energy Market Commission (“AEMC”), responsible for rule making and market development, and the Australian Energy Regulator (“AER”), responsible for monitoring and regulating electricity and gas transmission and distribution networks and retail markets8. Western Australia has opted not to transfer regulatory responsibility for its energy markets to the AER (but is intending to adopt a modified version of the national gas law) and in the Northern Territory, the AER has not been empowered to perform functions relating to the electricity market. As a result, the AER is the sole economic regulator for all electricity and gas industries in the eastern and southern states and for the gas industry in the Northern Territory. Natural Gas Sector

Production and Wholesale Australia has extensive reserves of natural gas. The two main types of natural gas used in Australia are conventional natural gas and coal seam methane gas (“CSG”). At June 2008 total proved and probable conventional gas reserves were around 40,300 petrajoules (“PJ”) and proved and probable CSG reserves were approximately 12,400PJ. Total gas reserves increase to approximately 173,000PJ (natural gas and CSG) if contingent resources are included. All major gas producers/wholesalers supplying the Australian market are privately owned with Western Australia by far Australia’s largest producer and exporter of natural gas. In the year ended 30 June 2008 total natural gas production was estimated to be 1,833PJ of which around 60% was consumed domestically with the balance exported to markets in Asia from Western Australia in the form of Liquefied Natural Gas (“LNG”). Domestic consumption of natural gas is forecast to continue to grow, increasing from 21.6% to 24% of energy consumption by 2030 due to strong gas demand from electricity generation and the manufacturing and mining sectors, and steady residential and business demand growth. Wholesale gas prices are typically based on confidential fixed price contracts, normally including some adjustment for inflation or periodic price resets. Victoria operates a spot

8 Energy sector reform is continuing and from 1 July 2009, the industry funded Australian Energy Market Operator (“AEMO”) was

established to monitor the National Electricity Market (“NEM”) and the retail and wholesale gas markets of eastern and southern Australia and oversee system security of the NEM electricity grid and the Victorian gas transmission network. The AEMO is also responsible for national transmission planning and the establishment of a short term trading market for gas. The AEMO replaced a number of stated based entities including the National Electricity Market Management Company, Gas Market Company and Gas Retail Market Company. Moves are continuing for a transfer of non-price retail regulation.

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market in which approximately 5-10% of gas produced is traded. Wholesale gas supply and price are not subject to economic regulation.

Transmission and Distribution

Large scale commercial gas usage in Australia commenced in the early 1970s and, as most Australian production fields are located in areas remote from major retail load centres, high pressure pipelines have been developed to bring gas to market. Gas distribution networks connect with the transmission system to distribute gas to the premises of residential, commercial and industrial customers. Large industrial users and power generators typically connect directly to the high pressure transmission network. Initially the major gas markets were supplied from single production basins via sole purpose monopoly pipelines. However, in the last 20 years, expenditure on pipeline infrastructure and the discovery of new gas reserves has seen the development of an integrated natural gas market in eastern and southern Australia, and the extension of gas supply into Tasmania. The transmission network of the Northern Territory may eventually be connected to the eastern network via Queensland. Although Western Australia remains isolated from this integrated network, the development of its natural resources has led to its becoming the largest market for natural gas in Australia. As a result of industry reforms over the last decade, all major gas transmission pipelines and the majority of gas distribution networks in Australia are now owned by the private sector. As transmission and distribution networks generally have natural monopoly characteristics, they are subject to a regulatory regime to ensure non discriminatory third party access. The major owners of Australian gas transmission pipelines include APA Group (“APA”), Hastings Diversified Utilities Fund (“HDUF”), DUET Group (“DUET”) and Singapore Power. The major owners of Australian gas distribution networks include Singapore Power, DUET, APA and Envestra Limited (“Envestra”). The regulatory framework for natural gas transmission pipelines and distribution networks in Australia is detailed in the National Gas Law and Rules, which came into effect on 1 July 2008. The AER enforces the National Gas Law and Rules and regulates covered gas transmission and distribution pipelines in all states and territories (except for Western Australia). Gas pipelines and networks can be “covered” or “uncovered” under the National Gas Law and Rules. Owners of covered pipelines must submit access arrangements (i.e. the provisions under which access to a pipeline can be granted) and periodic revisions to their arrangements for approval by regulators. Access arrangements generally include reference tariffs for the services to be offered and are approved for a period of time (typically five years) after which they are reviewed. Uncovered pipelines are free to determine prices and other terms and conditions on a commercial basis (subject to the general anti-competitive provisions of the Trade Practices Act, 1974). Reference tariffs in access arrangements are based on a building blocks approach. Tariffs are based on estimated efficient costs of providing the services including operating and maintenance costs, depreciation and a return on assets calculated by reference to a weighted average cost of capital applied to a regulated asset base. Gas network owners are incentivised to improve cost efficiency and grow demand over each regulatory review period. Retailing Retailers purchase natural gas from suppliers (producers or wholesalers) and on sell it to residential, commercial and industrial customers. The retail price of gas represents the wholesale cost of gas, transmission and distribution tariffs, the retailer’s operating costs and a profit margin. Retail tariffs have historically been subject to a regulated cap

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reviewed at regular intervals (usually annually). In general, small consumers (residential and small business) are charged the standard tariff (which the retailer may set equal to or lower than the tariff cap), while larger consumers (commercial and industrial) negotiate tariffs with the retailer. In all states full retail contestability for gas has been implemented. To date no alternative retailer to the mass market has emerged in Western Australia. Although the state government owned electricity retailer, Synergy, applied for a gas licence in April 2007, it is restricted from supplying gas to customers who consume less than 0.18 terajoules (“TJ”) per annum. The state governments are committed to the removal of retail price caps for gas where effective competition can be demonstrated. It has been determined that competition in both electricity and gas retailing in Victoria and South Australia is effective and the Victorian government has legislated to remove all price caps on retail electricity prices and gas rates from 1 January 2009. At May 2008 there were 16 gas retailers (operating 30 licences) active in the mass market. In comparison, there were 25 electricity retailers to the mass market (operating 55 licences). The difference in activity reflects a range of factors including the market size, available profit margins and the barriers to entry created by finite pipeline capacity. Private retailers dominate the gas market in all states except Tasmania. Climate Change Initiatives

In recent years, the Commonwealth and State governments have developed and implemented a number of energy sector and environmental initiatives to address the implications of climate change. Of particular relevance is the Commonwealth Government’s National Greenhouse and Energy Reporting System (“NGERS”) and Carbon Pollution Reduction Scheme (“CPRS”). The National Greenhouse and Energy Reporting Act 2007 came into effect on 29 September 2007. It introduces a single national framework for reporting greenhouse gas and energy information. Corporations that meet an NGERS threshold must report their greenhouse gas emissions, energy production, energy consumption and other information specified under NGERS legislation. The first annual reporting period ran from 1 July 2008 to 30 June 2009. The NGERS underpins the CPRS, providing the emissions data on which obligations under the CPRS will be based. Not all corporations that report under existing NGERS legislation will be subject to CPRS liabilities. The CPRS is part of the Commonwealth Government’s strategy to reduce Australia’s greenhouse gas emissions by 60% of 2000 levels by 2050. Following its election in November 2007, the Commonwealth Government commissioned the Garnaut Climate Change Review (the draft report was released on 4 July 2008 and the final report was released on 30 September 2008) (“the Garnaut Report”). On 16 July 2008, the Commonwealth Government issued a Green Paper outlining its approach to the design of a national emissions trading scheme and a White Paper outlining the final design of the CPRS. The medium term target range for reducing carbon pollution was issued on 15 December 2008. The 11 Bills comprising the CPRS legislative package were introduced to the House of Representatives in May 2009 and passed by the House on 4 June 2009. On 13 August 2009, the Senate voted against the Bills. The Commonwealth Government has indicated that it intends to reintroduce the Bills before the end of 2009. If passed, the CPRS legislation will commence from 1 July 2011. Under the CRPS, carbon emitters will require a carbon pollution permit for every tonne of greenhouse gas they emit and at the end of the year will need to surrender a permit for every tonne of emissions produced during that year. The number of permits issued by the Government in each year would be limited to the total carbon cap for the Australian economy. Firms would compete to purchase the number of permits they require. Those which value the permits most highly will be prepared to pay the most for them either at

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the permit auctions or on a secondary trading market. For other firms it will be cheaper to reduce emissions than to buy permits. The key provisions of the legislation include:

the permit price is to be determined by supply and demand subject to:

• as a transitional measure, an unlimited number of permits will be available in 2011-12 at a fixed price of $10 per tonne. Permits issued at $10 per tonne will not be able to be banked for use in future years, but the Commonwealth Government will buy back any remaining permits at $10 per tonne;

• the first year of the flexible price phase (2012-13) will commence with a price cap based on $40 per tonne (in 2010-11 dollars), with 5% per annum (real) plus actual inflation over 2010-11 and 2011-12;

• the price cap for 2013-14 and subsequent years will increase by 5% per annum (real) plus actual inflation; and

• the price cap will remain in place for four years post 2012-2013;

a commitment to reduce greenhouse gas emissions by between 5% and up to 25% below 2000 levels by 2020. The 5% target is unconditional, a 15% target is conditional on an agreement whereby major developing countries commit to substantially restrain emissions and advanced economies take on commitments comparable to Australia’s and the 25% target is conditional on world economies agreeing to an ambitious global deal to stabilise levels of CO2 equivalent in the atmosphere at 450 parts per million or lower;

assistance will be provided to emissions-intensive, trade-exposed (“EITE”) industries and the coal-fired generation industry, with increased assistance for the first five years as a result of the impact of the global recession;

funding will be provided for eligible businesses to undertake energy efficiency measures from 1 July 2009; and

ASIC will have regulatory oversight of the carbon market to prevent market manipulation.

In addition, in July 2008 the Council of Australian Governments Working Group on Climate Change and Water released design options for the Expanded National Renewable Energy Target Scheme (“NRET”) based on a national mandatory renewable energy target of 20% by 2020. Legislation to implement the NRET was passed by the Commonwealth Parliament on 20 August 2009 and, following Royal Assent, is now in place. The NRET is designed to ensure that 20% of Australia’s electricity supply is generated from renewable sources by 2020 (i.e. an increase of approximately 45,000 Gigawatt Hours (“GWh”) to 60,000GWh). It is expected that NRET will be phased out between 2020 and 2030 as emissions trading matures.

3.1.2 New Zealand

Overview

In line with the trend in Australia, total energy consumption in New Zealand has grown over the last ten years9. However, as electricity generation is dominated by renewable

9 Information in this report on the New Zealand energy industry is from a wide range of sources. The major sources are About the

New Zealand Electricity Sector, Electricity Commission and New Zealand Energy Data File 2009, Ministry of Economic Development.

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fuel sources and hydrocarbon resources are limited, the trends in the types of energy consumed in New Zealand differ. Overall consumption of natural gas is also declining along with the consumption of oil and coal as a result of a reduction in demand by the two largest users, Methanex Corporation and Huntly Power Station. However, other sectors of the reticulated gas market have increased demand. Consumption of energy from renewable sources is growing in New Zealand and is strongly supported by government policy. Energy consumption is expected to continue to grow in the foreseeable future (e.g. electricity demand is expected to grow by around 2% per annum to 2025). Historically, the energy sector was managed as part of the New Zealand Government. It is only since the 1980s that the energy sector has been subject to corporatisation and (in the 1990s) some privatisation. However, the energy sector in New Zealand remains dominated by state owned enterprises and continues to be subject to extensive regulation. Electricity Sector

Deregulation of the New Zealand electricity sector began in 1987 with the corporatisation of The Electricity Corporation of New Zealand Ltd (“ECNZ”). Corporatisation of the locally owned retail utilities followed in 1993 and in 1994 the national grid operator, Transpower New Zealand Limited (“Transpower”), was separated from ECNZ. ECNZ was subsequently split into Contact Energy Limited (“Contact Energy”) and three state owned enterprises: Meridian Energy Limited (“Meridian”), Mighty River Power Limited (“Mighty River Power”) and Genesis Energy Limited (“Genesis”). For regulation purposes, the Reform Act divided the electricity sector into three operating segments: Generation/Retail, Transmission and Distribution. The Electricity Commission was established in March 2004 to assume responsibility for overseeing the electricity industry and for security of supply. Generation and Wholesale Electricity demand has grown at around 2% per annum over the last ten years despite significant increases in wholesale electricity prices. Electricity generation totalled approximately 42,246GWh in 2008 from approximately 9,100 megawatts (“MW”) of installed capacity. New Zealand generation is fuelled approximately 65% by renewable resources (hydro, geothermal, wind and biomass) but is dominated by hydro electricity. The major generators are Meridian, Genesis, Mighty River Power, Contact Energy and TrustPower. All have a significant retail customer base which provides a hedge against the price received by the generator for electricity produced. The wholesale market is currently subject to a government review of its effectiveness. Distributed generators that connect directly to local electricity networks supply around 5% of the electricity generated in New Zealand. These include small local hydro schemes, wind energy plants, small diesel and gas generators (including landfill gas), small geothermal power plants, cogeneration or combined cycle power plants and domestic or small commercial solar generation. TrustPower is the largest operator of distributed generation plants. The uncertainty around future gas supplies and the increasing cost of new generation has placed upward pressure on average wholesale electricity prices and a narrowing of the gap between peak demand and supply. Market commentators have estimated that New Zealand is facing a shortfall in peak generation capacity of around 170MW by 2012 (after allowing for a reserve margin of 18% to maintain system equilibrium) and, in the absence of new capacity build, substantially more by 2025 (3,700MW has been mentioned). The supply of new generation capacity will be largely determined by the New Zealand Government’s energy strategy, which is in the process of being updated (refer later in this section for more detail).

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The wholesale electricity market involves the sale and purchase of physical electricity at prices established half hourly at 244 different points of connection (nodes) to the national grid located across New Zealand. Generators offer electricity into the market and large users and retail electricity companies bid to purchase electricity. Subject to transmission constraints, generators offering the lowest prices get despatched to meet the demand of the users and retail electricity companies. Prices therefore depend on supply by generators (which depends on hydrology, station availability, transmission constraints, etc) and demand by retailers (which depends on ambient temperature, seasonality, time of day, etc). As there is no maximum price, generators are at times able to achieve very high spot wholesale prices for their generation output. However, wholesale prices can often be low providing little revenue for base load generation, which cannot be easily “turned off” for short periods. The wholesale electricity price is volatile primarily due to the reliance on hydro stations for electricity generation. Approximately 52% of electricity generated in New Zealand is from hydro stations, resulting in a strong correlation between water inflows into storage lakes and electricity prices. Due to New Zealand’s small hydro storage reservoirs (national storage is 3,500GWh or less than 10% of annual electricity consumption) wholesale prices tend to be lower when storage is high with regular inflows and tend to rise during periods of lower than average storage levels and low inflows. Recent periods of high electricity wholesale prices during the winters of 2001, 2003, 2006 and 2008 have coincided with periods of low rainfall. Transmission The state owned enterprise, Transpower, owns and operates the high voltage electricity transmission system in New Zealand. It contracts with generators and distributors to connect to the national system. The main transmission grid in the North Island comprises 220 kilovolt (“kV”) and 110kV lines connecting major load centres with generating stations. In the South Island the transmission grid consists of 220kV, 110kV and 66kV lines. While more than 60% of New Zealand’s electricity is produced in the South Island, the majority (70%) of electricity demand comes from the North Island. Transpower owns the high voltage direct current (“HVDC”) link between the North and South Islands, which is designed primarily to deliver electricity northward. A supply constraint currently exists in the North Island as the HVDC link has been downgraded to operate at only 700MW (a further 270MW is available for limited peak operation only). Transpower has commenced a project to raise the HVDC link capacity to 1,000MW from 2012 and to 1,200MW from 2014. Transpower expects the upgrades to reduce transmission losses and increase the number of potential sites for new generation projects. Distribution There are 29 electricity distribution businesses providing local area lines networks through which electricity is transmitted from the transmission grid exit points to end users. Most of the distribution businesses were formed by the New Zealand Government in 1992 when it corporatised the businesses under a number of ownership structures including local council owned, trust owned (with profit distributions being made back to the consumer or the community generally) and public ownership. The Commerce Commission regulates electricity distribution by setting price-quality paths, which set the maximum average price that suppliers of electricity lines services can charge. It also defines the standards for quality of services that they must provide to their customers. In October 2008, the Commerce Amendment Act introduced significant changes to the regulation of suppliers of electricity lines services. Under these changes,

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the Commerce Commission is required to make decisions on input methodologies, price-quality paths and information disclosure requirements. Input methodologies will provide increased certainty for regulated services on matters such as cost of capital, valuation of assets, allocation of common costs and treatment of taxation. The Commission is required to make determinations on input methodologies by 30 June 2010. The Commission will set default price-quality paths (“DPPs”), although from 2011 individual distributors may make proposals to the Commission for a customised price-quality path (“CPP”) and propose alternative price and/or quality paths. The Commission may set a CPP for the distributor that better meets the distributor’s particular circumstances. There are penalties for any breaches of price-quality paths. The thresholds that were in place under the prior legislation (under which Powerco is subject to a CPI-2% price and quality threshold) are to remain in force as DPPs for a transitional period from 1 April 2009 to 31 March 2010. The Commission is required to reset these DPPs by 1 April 2010, which requires the Commission to provide its determination by 1 December 2009. On 8 September 2009, the Commission released its draft decisions paper on the DPPs to apply to electricity distribution businesses from 1 April 2010. The draft decisions paper proposes allowing electricity distribution businesses to increase prices by inflation (i.e. CPI-X where X=0). The reset DPPs will apply for a regulatory period of five years (i.e. 1 April 2010 to 31 March 2015). Submissions on the draft decisions paper are due by 12 October 2009. Retailing Electricity retailers acquire electricity and use distribution networks to deliver electricity to end users. The major costs of an electricity retailer are energy costs, distribution costs and metering costs. Retail tariffs are not subject to price regulation and vary across New Zealand according to geographic location, local distribution network charges and the impact of nodal electricity pricing. Following a period of consolidation, the five largest electricity generators are also the largest electricity retailers. A number of small low cost, low margin electricity retailers have entered the market since 1998 with the objective of attracting customers away from incumbent retailers. The most successful, Empower and Energy Online, were subsequently acquired by a larger electricity generator. Since then, the market positions of the large electricity retailers have been reasonably stable. There continues to be price competition although recently retail prices have been rising and there has been greater emphasis on customer retention and maintenance of retail margins. Natural Gas Sector

The development of the natural gas sector in New Zealand was based around the discovery of the Kapuni field in 1959 and the Maui field in 1969. Unlike the electricity sector there is no legislation preventing ownership across each segment of the industry. Some industry participants are active across more than one segment with Todd Corporation Limited (“Todd”) participating in all segments. The New Zealand Government was directly involved in the development of the gas sector. However, since the 1980s the sector has largely been privatised although subject to some regulation, particularly in relation to the transmission and distribution of gas. Although the New Zealand gas sector is small by global standards it plays a large role in the economy as natural gas is primarily used to generate electricity. The New Zealand Government conducted a review of the sector in 2002 which resulted in a gas governance policy (which has been refined over the period to 2008) and the establishment of the Gas Industry Company Limited, a co-regulatory body to deliver industry led solutions for

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sector reform (e.g. an effective open access regime for transmission and distribution pipelines). Production and Wholesale At 1 January 2009 total proven and probable reserves of natural gas in New Zealand were 1,975PJ and production during 2008 was 174PJ. Maui has historically been the largest producing field, supplying approximately 75-80% of New Zealand’s annual gas requirements at its peak (although it currently supplies only approximately 30%). The Pohokura field is the first significant gas field developed since Maui and provides approximately 40% of New Zealand’s annual gas requirements. In recent years a number of gas fields have been developed (e.g. the Kupe field, which was discovered in 1988, is estimated to have 254PJ of proven and probable reserves and is scheduled to enter production by the end of 2009). While individually each of these fields is small in comparison to the original reserves of Maui, they extend the horizon of New Zealand’s gas supply. With the decline of the Maui field, the New Zealand energy market now faces significant uncertainty in relation to future gas availability and prices. Consequently, exploration levels have increased but the small size (in terms of available capital and resources) of the companies that hold exploration permits has affected exploration success levels. The Taranaki Basin is considered to have high potential (estimated at 5,300PJ) for the discovery of new gas reserves, although there is significant uncertainty as to the economic viability of recovering this gas. The price for Maui gas was set in 1975 based on an initial price adjusted annually by approximately half the rate of inflation for the preceding year. This adjustment mechanism led to a fall in the real price of gas year on year compared with other sources of energy, thereby encouraging the consumption of Maui gas. However, the low Maui gas price has been the benchmark for gas prices in New Zealand and has discouraged exploration and the development of alternative supplies. With Maui gas reserves declining and no new major discoveries the medium term outlook is for tight supply and for gas prices to increase. Major gas users have also been investigating the development of facilities to allow for the importation of LNG. This involves significant capital expenditure although Contact Energy’s proposed Ahuroa gas storage facility would assist with the project feasibility. The threat of LNG importation is likely to assist with domestic gas price negotiations and any LNG investment decision is likely to be deferred until the latest possible time. Transmission Natural gas transmission systems only exist on the North Island as New Zealand’s gas supplies are dominated by reserves from the Taranaki Basin. The two main gas transmission pipelines are:

the 313 kilometre Maui pipeline from Oaonui in Taranaki (where Maui gas comes onshore and is processed) to Rotowaro near Huntly. The pipeline is owned by Shell New Zealand Limited (“Shell”), OMV New Zealand Limited (“OMV”) and Todd and operated by Vector Limited (“Vector”). In October 2005 an open access regime was implemented for the pipeline; and

the Vector transmission network, which comprises approximately 2,200 kilometres of pipelines taking gas from Taranaki as far north as Kamo, east to Gisborne, southeast to Hastings and south to Wellington under an open access system.

There are also a number of smaller transmission pipelines in the Taranaki area.

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Distribution There are extensive low pressure gas reticulation networks in most cities in the North Island. There are three main gas distribution companies, Powerco Limited (“Powerco”), which operates in the Taranaki, Manawatu, Hawke’s Bay, Horowhenua and Wellington areas, Vector, which operates in the greater Auckland, Northland, Bay of Plenty and Gisborne areas and GasNet (owned by Wanganui Gas), which operates around Wanganui. In addition, Nova Energy (a subsidiary of Todd) has constructed a bypass network to deliver gas directly to customers in Wellington, Porirua, the Hutt Valley, Hastings, Hawera, Papakura, East Taranaki and Manakau City. In July 2005, the New Zealand Minister of Energy announced a decision to impose price control over the gas distribution services of Powerco and Vector. The Commission issued a provisional authorisation which took effect from 25 August 2005, reducing average prices by 9% for Powerco and 9.5% for Vector (with prices held constant in nominal terms since then). In its October 2007 draft authorisation for the price reset, the Commerce Commission proposed prices representing substantial reductions over current distribution prices (42% for Powerco and 15% for Vector). The Commission considered but did not accept offers of undertakings from Powerco and Vector and on 31 October 2008, released its final authorisation, which required average price reductions of 11.1% for Powerco and 3.7% for Vector from 1 January 2009. Prices will be held constant in real terms (i.e. increase by CPI-X where X=0) for the remainder of the control period to 1 July 2012. Gas retailers are expected to pass on the full amount of any reductions in distribution charges. After the current price reset period (i.e. from 1 July 2012), gas distribution companies will be subject to the same price controls as electricity distribution companies. Retailing Gas retailers purchase natural gas and on sell it to industrial, commercial and residential end use customers. In 2008 approximately 54% of natural gas produced in New Zealand was consumed by electricity generation and 19% by the petrochemical industry (for the production of methanol and ammonia-urea). The remaining 28% of gas produced was consumed in the retail market but only 3% was consumed by the residential market (the balance was consumed by industry and commercial customers). Gas is considered an elective fuel source in the retail market and therefore pricing of gas plays a large role in uptake by retail users. In recent years, as the price of gas has increased, the level of consumption in the residential and commercial segments has decreased. Eight retailers sell gas to industrial and commercial customers, but only five of these retailers supply gas to residential customers and three are also major electricity retailers to the residential market. Genesis and Contact Energy are considered the major gas retailers in New Zealand. Climate Change Initiatives

In October 2007, the New Zealand Government announced the New Zealand Energy Strategy (“NZES”) setting out a strategic direction for the New Zealand energy sector to provide sufficient energy to meet the needs of a growing economy, while maintaining security of supply and reducing greenhouse gas emissions. For the electricity sector there were three major policy initiatives:

introduction of a carbon emissions trading scheme from 1 January 2010 as the core price based measure for reducing greenhouse gas emissions and enhancing forest carbon sinks. The emissions trading scheme would result in increases in the cost of transport fuels, electricity and gas;

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a 10 year moratorium on the development of new base load fossil fuel thermal generation (except as required to maintain security of supply). This moratorium would require generators to adjust their plans for the type of new generation capacity developed to meet future demand; and

a target of 90% renewable generation by 2025. The significant increase in projected base load geothermal production should meet the growth in projected demand for approximately five years by which time additional wind farms and further geothermal plants were likely to have come on stream.

On the basis of this strategy and its emphasis on renewable generation, it was expected that wholesale electricity prices would trend towards the long run marginal costs of wind generation resulting in upward pressure on retail prices for electricity. In addition, as over 50% of natural gas production is consumed by electricity generation, there would also have been implications for the demand for gas. However, in February 2009, following the change in government, the new Minister of Energy and Resources announced his intention to update the strategy. It is proposed that the new strategy focus on security of supply, affordability and environmental responsibility, with the overriding goal of maximising economic growth. As a result, it is expected that there will be some watering down of the former government’s policy initiatives set out above.

3.1.3 North America

Regulatory Environment

Interstate transmission of gas, electricity and oil in the United States is regulated by the Federal Energy Regulatory Commission (“FERC”). Different offices within the FERC monitor, regulate and oversee elements of these markets such as reliability, policy and innovation. Rather than instituting a maximum rate regime, the FERC provides a regulated framework which allows commercial agreements to be reached. The FERC does not regulate retail markets and local distribution, which is dealt with by the relevant State Public Utility Commissions. Transmission and Distribution

Electricity Sector

BBI’s electricity sector exposure in the United States is limited to the New England and New York electricity markets. These markets are capacity constrained, and are linked by the Cross Sound Cable (“CSC”), 100% owned by BBI. CSC provides the Long Island Power Authority (“LIPA”) with a connection to the New England electric system where electricity is available at lower cost. Additionally, CSC has resulted in improved electric system reliability in New York and New England. CSC, in conjunction with the Neptune cable, located between New Jersey and New York, links the Midwest electricity markets to Long Island, New England and Canada. FERC approval has been obtained for both the capacity rate and long term contract of CSC. Gas Sector

The United States has an interstate grid for transmission of gas that is around 350,000 kilometres in length. In addition there are approximately 143,000 kilometres of intrastate pipeline. Around 77% of interstate gas pipeline length in 2008 was owned by the 30 largest interstate pipeline companies, equating to around 72% percent of the network 2008 capacity (183 billion cubic feet). The gas network can be categorized into 11 distinct corridors as illustrated on the map below.

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Source: Energy Information Australia, Office of Oil and Gas, Natural Gas Division, GasTran Gas Transportation Information System Notes: 1. Southwest-Southeast: from the area of East Texas, Louisiana, and the Gulf of Mexico, to the Southeastern

States. 2. Southwest-Northeast: from the area of East Texas, Louisiana, and the Gulf of Mexico, to the U.S.

Northeast (via the Southeast Region). 3. Southwest-Midwest: from the area of East Texas, Louisiana, Gulf of Mexico, and Arkansas to the

Midwest. 4. Southwest Panhandle-Midwest: from the area of southwestern Texas, the Texas and Oklahoma

panhandles, western Arkansas, and southwestern Kansas to the Midwest. 5. Southwest-Western: from the area of southwestern Texas (Permian Basin) and northern New Mexico

(San Juan Basin) to the Western States, primarily California. 6. Canada-Western: from the area of Western Canada to Western markets in the United States, principally

California, Oregon, and Washington State. 7. Canada-Midwest: from the area of Western Canada to Midwestern markets in the United States. 8. Canada-Northeast: from the area of Western Canada to Northeastern markets in the United States. 9. Eastern Offshore Canada-Northeast: from the area of offshore eastern Canada (Sable Island) to New

England markets in the United States. 10. Rocky Mountains-Western: from the Rocky Mountain area of Utah, Colorado, and Wyoming to the

Western States, primarily Nevada and California with support for markets in Oregon and Washington. 11. Rocky Mountains-Midwest: from the Rocky Mountain area to the Midwest, including markets in Iowa,

Missouri, and eastern Kansas. Due to the size of the United States natural gas market, there are a number of large participants involved in interstate gas transportation. Many of these companies both own and operate the interstate pipelines and storage systems that connect production basins, other pipelines, storage facilities and local distribution networks.

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Ten Largest United States Interstate Natural Gas Pipeline Systems in 2006 Ranking Company Market Regions Served System

Capacity (MMcf/d10)

1 Columbia Gas Transmission Co. Northeast 9,000 2 Transcontinental Gas Pipeline Co. Northeast, Southeast 8,161 3 Northern Natural Gas Co. Central, Midwest 7,200 4 ANR Pipeline Co. Midwest 7,129 5 Texas Eastern Transmission Corp. Northeast 6,672 6 Tennessee Gas Pipeline Co. Northeast, Midwest 6,329 7 El Paso Natural Gas Co. Western, Southwest 6,152 8 Dominion Transmission Co. Northeast 5,934 9 Natural Gas Pipeline Co. of America11 Midwest 4,508 10 Northwest Pipeline Corp. Western 4,500

Source: FERC Regulation of interstate gas players falls under the jurisdiction of the FERC, including rates charged in accordance with the Natural Gas Act. There is no obligation for periodic rate cases and parties are free to file for rate cases when they wish to alter their rates. The United States underground natural gas storage facilities provide pipelines, local distribution companies, producers, and pipeline shippers with an inventory management tool, seasonal supply backup, and access to natural gas needed to avoid imbalances between receipts and deliveries on a pipeline network. There are three principal types of underground storage sites used in the United States: depleted natural gas or oil fields, aquifers12 and salt caverns. Storage facilities generally reach close to full capacity in summer, when demand is weak, to meet higher consumption during winter months. As storage reaches maximum capacity, storage constraints may cause downward pricing pressure on gas supplies until the winter demand rebalances prices. The graph below illustrates the seasonality in storage capacity over five years to 11 September 2009. Storage peaks typically occur around November with the annual peak level typically increasing year on year.

10 Million cubic feet per day. 11 BBI owns a 26.4% interest in Natural Gas Pipeline Co. of America. 12 Aquifers are underground porous, permeable rock formations that act as natural water reservoirs, which in certain situations, may be

reconditioned and used as natural gas storage facilities.

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United States Natural Gas StorageSeptember 2004 - September 2009

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Sep-04 Mar-05 Sep-05 Mar-06 Sep-06 Mar-07 Sep-07 Mar-08 Sep-08 Mar-09 Sep-09

Stoc

ks in

Bill

ion

Cub

ic F

eet

Source: Energy Information Administration

3.1.4 United Kingdom, including Channel Islands and Isle of Man

Regulatory Environment

The United Kingdom’s gas and electricity markets are regulated by the Office of the Gas and Electricity Markets (“Ofgem”). Ofgem regulation of the United Kingdom electricity and gas markets includes price restrictions for the regional electricity networks and energy transmission network operators, as well as the local gas distribution network operators. Additionally, Ofgem regulates competition in the gas and electricity markets where possible by prohibiting incumbents from undue discrimination against competitors. In the Channel Islands and Isle of Man, operators are subject to monitoring only. The Office of Fair Trading (“OFT”) in the Isle of Man is currently researching an appropriate framework for the economic regulation of the energy market in the Isle of Man. There have been recent discussions around the possible regulation of Manx Gas Limited (a subsidiary of BBI and the sole gas provider in the Isle of Man) but no firm date has been set concerning this regulation. Transmission and Distribution

Electricity Sector

Electricity is transmitted throughout the United Kingdom from power stations to major substations by two high-voltage electricity transmission networks. England and Wales are serviced by a high-voltage network owned and operated by National Grid plc (“National Grid”). Scotland’s network is owned by Scottish Power Ltd and Scottish & Southern Energy plc, although the network is operated by National Grid. Three high-voltage undersea connections run out of these networks, two from the English network (to France and to the Isle of Man) and one from Scotland to Northern Island. In the United Kingdom a number of Distribution Network Operators (“DNOs”) are responsible for the transmission of power from the National Grid operated high-voltage networks to retail and commercial users. Fourteen DNOs are responsible for regions know as Distribution Service Areas. Independent Connection Providers (“ICPs”) compete with the incumbent DNO when new connections need to be installed. However, the operation of any new network falls under the jurisdiction of the relevant DNO.

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Independent Distribution Network Operators (“IDNOs”) install new infrastructure and then manage the relevant network, which would be embedded within an existing distribution network. This kind of operator is more common in the United Kingdom Gas Sector than the Electricity Sector. Gas Sector

Due to 1996 market reforms, wholesale gas in the United Kingdom can be traded like other commodities. Given the United Kingdom’s declining gas supplies and the increased reliance on gas as an energy source, the United Kingdom is becoming increasingly reliant on imported gas that arrives in the United Kingdom through pipeline links and LNG shipments. The United Kingdom’s own gas is sourced from sites including those in the North Sea and Irish Sea, whilst a number of pipelines import gas, giving the United Kingdom access to gas fields in the Netherlands, Belgium and Norway. Additionally, operational LNG terminals at the Isle of Grain and Dragon, a Gasport LNG facility at Teesside and a terminal under construction at South Hook provide facilities for the United Kingdom to receive LNG supplies, allowing imports from countries further afield. Once gas has arrived on the United Kingdom mainland, it is primarily distributed across the United Kingdom through the high pressure National Transmission System (“NTS”) and to retail users in twelve Local Distribution Zones (“LDZs”). The NTS is owned and administrated by National Grid. Gas is pumped across the United Kingdom via 26 compressor stations, transporting the gas from the costal ports and pipelines to areas of high demand (such as high population areas) and to large volume industrial users (e.g. power stations). Gas is transported from the NTS to retail customers (homes and businesses) via lower-pressure Gas Distribution Networks (“GDNs”). There are eight GDNs across the twelve LDZs. National Grid originally owned all eight GDNs, but sold four in June 2005. Independent Connection Providers (“ICPs”) compete with the GDN operators when new connections need to be installed, although the operation of any new network then falls under the jurisdiction of the relevant GDNs. In addition to the GDNs, several smaller independent networks exist, which are owned and managed by Independent Gas Transporters (“IGTs”). Five main IGTs exist in the United Kingdom: ES Pipelines Limited, Gas Transportation Company Limited (a subsidiary of BBI), Energetics Gas, Inexus Group (Holdings) Limited and Scottish and Southern Pipelines. GDN operators and IGTs are licensed to transport gas, meaning that both can operate networks as well as provide the connections to the GDNs. Gas on the Channel Islands and Isle of Man arrives on tankers in the form of Liquid Petroleum Gas (“LPG”) and is distributed by local providers. The Isle of Man also receives natural gas by the Scotland to Ireland sub-sea interconnection pipeline, and therefore has dual fuel natural gas in areas with access to the on shore reticulated system, and reticulated LPG-Air mix in the areas without pipeline access.

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Network Operator

Incumbent or Affiliate

(GCN/BNO) Independent (IGT/IDNO)

Network Operator or

Affiliate (GDN/IGT or DNO/IDNO)

Customer approaches incumbent for connection

Incumbent installs connection assets, charging customer upfront for cost of installing assets

Incumbent then operates and maintains assets for on-going transportation revenue

Customer approaches IGT/IDNO for connection

IGT/IDNO installs connection assets, charging customer upfront for capital cost of installing assets

IGT/IDNO then operates and maintains assets for on-going transportation revenue

No competition for incumbent Competition for incumbent in asset installation and operation

ICP

Customer approaches ICP for connection

ICP installs connection assets, charging customer upfront for capital cost of installing assets

ICP transfers assets to incumbent which operates and maintains assets for on-going transportation revenue

Customer approaches ICP for connection

ICP installs connection assets charging customer upfront for cost of installing assets

ICP transfers assets to IGT/IDNO which operates and maintains assets for on-going transportation revenue

Competition in asset installation Competition for incumbent in asset installation and operation

Source: Ofgem

3.2 Port and Rail Industry

3.2.1 Australia

Ports

Port freight activities can be split into a variety of general categories ranging from dry bulk and containers through to liquid bulk and general cargo (also called break bulk). Australian metropolitan base port facilities handle a mixed variety of cargo dominated by consumer goods handled in containers for easy access to population centres, whilst regional ports predominantly handle dry bulk commodities such as coal, grain and ore. BBI’s Australian port operations fall into the dry bulk port category, handling a wide variety of coal from the Bowen Basin in Queensland at the Dalrymple Coal Bay Terminal facility at Hay Point.

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Source: BBI Bulk ports in Australia are exposed to the demand for, and supply of, the commodities that they handle. Recent strong demand, particularly in developing countries, for natural resources and the rising demand for oil globally have seen an increase in the volumes through ports located in close proximity to natural resources, and accordingly an increase in demand for additional port facilities as capacity of existing facilities is absorbed. Ports in Australia are regulated at a federal, state and port authority level. On a federal level, the Australian Maritime Safety Authority provides services in relation to areas such as safety and the marine environment. Regulators at a state level oversee port pricing, as the nature and location of ports in Australia often means that there is little competition. In Queensland, for example, the Queensland Competition Authority is responsible for determining access terms that are considered fair and reasonable in relation to terminals in regions in which there is limited competition. Port authorities are responsible for the maintenance of port facilities such as channels and berths, and generally contract out services such as stevedoring to third parties. Asciano and Dubai Ports World (P&O) dominate the Australian container port market. Bulk ports are more diversified, with a number of energy, mining and infrastructure companies, as well as the various state governments, owning and operating facilities. Rail

Rail in Australia is utilised for transport of both people and freight, with freight being split into three main categories; bulk, unitised and general cargo (also called break-bulk). Bulk freight involves the transport of dry bulk commodities such as coal and iron ore, as well as grain, liquids and LPG. Unitised freight is the term used to describe any type of good which must be packaged onto pallets or in containers in order to be transported. Other items which may be heavy or large and unsuitable for standard shipping containers are considered general cargo freight. Logs, cars and steel beams are examples of general cargo freight. Rail networks in Australia are organised into two predominant networks, the East-West Corridor (Perth to Melbourne) and the North-South Corridor (Melbourne to Brisbane).

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Source: Australasian Railway Association Inc. Additionally, there are a number of networks that service intrastate markets, such as BBI’s WestNet Rail network in Western Australia, which includes part of the East-West Corridor as well as a number of other lines. Track in Australia is controlled by a number of parties, including the Australian Rail Track Corporation (Commonwealth owned), State Governments, and private owners with long-term leases such as BBI. Rail freight operators who pay fees to access the rail networks include Pacific National (Asciano), Queensland Rail, SCT Logistics and Genesee and Wyoming Australia. The level of Government regulation in the rail industry is high, with industry participants being held to safety and accessibility standards in addition to regulations designed to promote wider network coverage. State regulations require train operators to be accredited. The National Transport Commission is the federal body that deals with regulations regarding safety and compliance for the rail industry.

3.2.2 Europe

Ports

The port sector of Europe is an extremely diverse sector dominated by a series of ports most of which have been in their current locations for many hundreds of years and define the countries and communities in which they operate. The major port operations in Europe are shown on the map below:

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Source: Hamburgisches WeltWirtschafts Institut Over three billion tonnes of maritime cargo is handled in Europe annually. This sea-borne cargo arrives or is destined for either deep sea shipping routes (routes that cross oceans) or short sea shipping routes. Short sea shipping (routes that do not cross oceans) in Europe accounts for approximately 40% of all freight moved in Europe. There are four major corridors of European short sea shipping traffic, called “Motorways”: 1. Motorway of the Baltic Sea, which links Baltic Sea Member States with Central and

Western European Member States, and includes the route through the North Sea/Baltic Sea canal;

2. Motorway of the Sea of Western Europe, from Portugal and Spain to the North Sea and the Irish Sea via the Atlantic;

3. Motorway of the Sea of South-East Europe, which links the Adriatic Sea, Ionian Sea and the Eastern Mediterranean (including Cyprus);

4. Motorway of the Sea of South-West Europe, which includes the western Mediterranean, connecting Spain, France, Italy and Malta, and links with the Motorway of the Sea of South-East Europe and the Black Sea).

Whilst for deep sea traffic the most important entry point into Europe remains the HAR (Hamburg, Rotterdam, Antwerp) range of ports with these three ports alone accounting for approximately 20% of all maritime traffic handled in Europe. As in Australia, port facilities in Europe are generally categorised into dry bulk (speciality and heavy dry bulk), containers, liquid bulk (including gas) and general cargo (also called break bulk) facilities, reflecting the different types of cargo that they handle. Ports operators operating within a given port tend to specialise in terms of the types of cargo that they handle according to historical trends and their proximity to key markets, distribution networks, resources and manufacturing customers.

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Port facilities in the European market do not operate under the same regulatory restrictions as their Australian peers. European ports are largely unregulated. Port Authorities, all of which are government owned except for in the United Kingdom, generally have a freehold ownership over the port and lease port space to terminal operators under long term concessions. In the United Kingdom, some private ports operators such as PD Ports own the freehold land and the port facilities and also act as the port authority. Tariffs for stevedoring and storage (the two main revenue drivers for a port operator) are generally not restricted by national regulations, but market competition from the large number of operators in the market provides some level of theoretical price control. The following table details the demand drivers, historical growth rates and expected future growth rates for the various product categories transported through European port facilities:

European Port Growth Projections

Product Type Description Driver Euroports

Example

Historical Growth (Sources: HWWI& BMT)

Future Growth (Sources: HWWI & BMT)

Bulk Liquids

Crude oil, crude oil derivatives, LNG chemicals

Fuel and chemical consumption

Rostock (Germany)

Volume CAGR of c. 1% 2002 to 2006 through European ports

Volume CAGR 0.4% liquid bulk to 2030 through European ports

Heavy Dry Bulk

Ores, chemicals, wood chips, coal, minerals

Energy and metals trends

TRI (Italy) TPS (Spain)

Volume CAGR c. 2% 2002 to 2006 through European ports

Volume CAGR < 2.4% dry bulk to 2030 through European ports

Specialty Dry Bulk

Grains, agri products, cement

Growth in industrial production and agriculture

Rostock (Germany)

Volume CAGR c. 3% 2002 to 2006 through European ports

Volume CAGR > 2.4% dry bulk to 2030 through European ports

Containers

Any good that has been containerised, typically manufactured and finished goods ready for consumption

Hinterland consumption growth (no transhipment) Short sea and barge container traffic

WCT (Belgium)

Volume CAGR 11% 2002 to 2006 through European ports

Volume CAGR 7.9% containers to 2030 through European ports

General Cargo

Packed and bundled cargo that is not containerised such as steel, wood, paper

Growth in paper, steel and specialty general cargo that is resistant to containerisation

Rauma (Finland) Westerlund (Belgium)

Volume CAGR > 5% 2002 to 2006 for products through BBI’s ports

Volume CAGR c. 5% 2007 to 2017 for products through BBI’s ports

Logistics

Value added logistical services offered to customers

Growth in European trade volumes and trade through Euroports

Manuport (Belgium)

Freight traffic in Europe CAGR of 2.5% for last 35 yrs

Maritime freight traffic in Europe CAGR of 3.3% to 2030

Source: BBI

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4 Profile of BBI

4.1 Background

BBI is a specialist infrastructure entity that provides investors access to a diversified portfolio of quality infrastructure assets. It was listed on the ASX in June 2002 and immediately prior to announcement of the Recapitalisation had a market capitalisation of approximately $140 million. BBI comprises:

shares in BBIL, an Australian public company; and

units in BBIT, an Australian trust of which BBIS is the responsible entity. One share in BBIL and one unit in BBIT form a “stapled security” which cannot be separately traded. BBI was known as Prime Infrastructure when it listed. While BBIL had a majority independent board, subsidiaries of Babcock & Brown acted as its responsible entity and exclusive financial adviser and Babcock & Brown held 5% of the Securities on issue at listing. In July 2005, Prime Infrastructure was restructured and rebranded BBI. BBI’s portfolio of infrastructure assets has grown rapidly over the last five years. Starting with one seed asset, DBCT, at the time of listing, BBI’s initial growth strategy was to acquire assets across a range of infrastructure classes. This saw BBI acquire a range of assets including power generation assets. In 2005, BBI completed the divestment of Babcock & Brown Wind and also announced the sale of generation assets to Babcock & Brown Power. These two transactions enabled BBI to refocus on two asset classes: transport and energy transmission & distribution.

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A brief history of BBI is set out below:

BBI – History and Timeline Date Event 2002 Listed on ASX as Prime Infrastructure. The Dalrymple Bay Coal Terminal was the initial asset. 2003 Acquired a 50% interest in Ecogen, a gas-fired peaking power generation business in Victoria. 2003 Acquired a 50% interest in Redbank Power Station, a coal-fired baseload power station in the

Hunter Valley, NSW. 2003 Acquired a 50% interest in Global Wind Partners, a specialist wind energy generation asset fund. 2004 Acquired 100% of Powerco, a leading energy and gas distribution business based in New Zealand. 2005 Acquired 100% of International Energy Group, a leading independent gas transporter operating in

the Channel Islands13, the Isle of Man, Portugal and United Kingdom. 2005 Global Wind Partners went through an IPO and became a portfolio of separately wind farms in

Europe, United States and Australia into the separately listed ASX-listed vehicle, called Babcock & Brown Wind Partners (“BBW”). BBI’s 50% interest was diluted as part of this to c.16%.

2006 Acquired 100% of PD Ports. 2006 Acquired 100% of CSC. 2006 Acquired 51% of WestNet Rail, a rail infrastructure business based in Western Australia. 2006 Announced sale of its interest in generation assets to Babcock & Brown Power (“BBP”) and

completed the divestment of the balance of its interest in BBW. 2006/07 Acquired several interests in European ports and assembled them into a Luxembourg based portfolio

called Euroports. 2007 Acquired the AET&D portfolio via the Alinta Scheme Proposal. 2008 Acquired a 26.4% interest in Natural Gas Pipeline Company of America. 2008 Increased ownership interest in WestNet Rail to 76%. 2009 Divested a 58% stake in Powerco New Zealand, retaining 100% of Powerco’s Australian assets in

Tasmania. 2009 Increased ownership interest in WestNet Rail to 96%. 2009 Sold IEG’s operations in Portugal. 2009 Divested a 40% stake of the Euroports portfolio. 2009 Announced a Recapitalisation including a $1.5 billion Equity Raising (including a $625 million

placement to Brookfield) and the sale of certain assets to Brookfield. Source: BBI

4.2 Assets

BBI’s portfolio of assets reflects the fund's strategy to acquire, manage and operate quality infrastructure assets with geographic coverage on a global basis, primarily in OECD countries. BBI's portfolio is diversified across asset class segments, geographies and regulatory regimes. Asset class segments fall into two broad categories as illustrated below:

13 Guernsey and Jersey

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Energy Transmission & Distribution

Australia Other

Transport

Australia Europe

Dampier to BunburyNatural Gas Pipeline

(20%)

Multinet GasNetwork(20.1%)

Tas Gas(100%)

Tasmanian GasPipeline(100%)

WA GasNetwork(74.9%)

WestNet Energy(100%)

Powerco(42%)

InternationalEnergy Group

(100%)

Cross SoundCable

(100%)

Natural Gas PipelineCompany of America

(26.4%)

Dalrymple BayCoal Terminal

(100%)

WestNet Rail(96%)

Euroports(60%)

PD Ports(100%)

Transmission Distribution AssetManagement Transmission Distribution

Energy Transmission & Distribution

Australia Other

Transport

Australia Europe

Dampier to BunburyNatural Gas Pipeline

(20%)

Multinet GasNetwork(20.1%)

Tas Gas(100%)

Tasmanian GasPipeline(100%)

WA GasNetwork(74.9%)

WestNet Energy(100%)

Powerco(42%)

InternationalEnergy Group

(100%)

Cross SoundCable

(100%)

Natural Gas PipelineCompany of America

(26.4%)

Dalrymple BayCoal Terminal

(100%)

WestNet Rail(96%)

Euroports(60%)

PD Ports(100%)

Transmission Distribution AssetManagement Transmission Distribution

In August 2008, BBI announced an asset sale program and by July 2009 had completed the following sales:

in February 2009, BBI sold 58% of Powerco New Zealand to funds managed by Queensland Investment Corporation for an equity value of NZ$423 million;

in May 2009, BBI sold IEG’s operations in Portugal to Fundo Explorer II; and

in July 2009, BBI completed the sale of 40% of the Euroports portfolio to Arcus and Antin for a total value of €141.5 million.

The net proceeds from these assets sales have been used to reduce BBI’s corporate and asset level debt (amounting to approximately $390 million), increase ownership of WestNet Rail to 96% and to fund other commitments within the portfolio. BBI has undertaken formal sales processes for PD Ports and DBCT, with a view to selling either partial or 100% interests in the assets. Each asset is a standalone operating business with its own employees. Senior management of BBI, with expertise in the management of infrastructure assets in these two sectors, are active members of the boards of each business. BBI ensures that structured reporting and other processes are established for each business and seeks to leverage the expertise of business managers across the sectors. Each of the businesses benefits from BBI in:

management of assets (i.e. recognition of organic or acquisition growth opportunities);

risk management (i.e. BBI participates in the identification and management of material risks and brings asset portfolio diversification); and

centralised capital management (e.g. foreign exchange and interest rate risk management and the optimisation of gearing structures).

The following graphs analyse BBI’s proportionate revenue and proportionate EBITDA by asset class for the year ending 30 June 2009 (“FY09”). While the Euroports portfolio is the largest revenue contributor, Natural Gas Pipeline Company of America (“NGPL”) is the largest contributor to BBI’s EBITDA. However, given that NGPL is equity accounted, BBI only reports its share of NGPL’s net profit after tax. The reported revenue and EBITDA for Powerco during FY09 represents 100% of the Powerco NZ operations up until the date of the sale of 58% of Powerco to QIC and from that point on BBI equity accounts for its interest in Powerco.

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BBI Proportional FY09 Revenue by Asset

BBI Proportional FY09 EBITDA by Asset

DBCT9.9%

PD Ports9.8%

WestNet Rail6.0%

Euroports28.4%

IEG8.7%

CSC1.1%

NGPL12.2%

Powerco9.1%

AustralianET&D12.3%

TGN0.7%

TRANSPORT

ENERGY

T&D

DBCT14.9%

PD Ports6.9%

WestNet Rail8.4%

Euroports9.1%

IEG8.4%

CSC2.1%

NGPL23.3%

Powerco14.3%

AustralianET&D12.3%

TGN0.3%

TRANSPORT

ENERGY

T&D

Source: BBI14 Following the Recapitalisation, which includes the sale of a 49.9% economic interest in DBCT, the sale of PD Ports and the transfer of management controls combined with the option to acquire all of the equity in both CSC and AET&D, BBI’s pro forma proportional revenue and EBITDA is shown below. Please refer to Section 8 of the Prospectus for further details regarding the adjustments assumed in the pro forma numbers.

BBI Proportional Pro Forma FY09 Revenue by Asset

BBI Proportional Pro Forma FY09 EBITDA by Asset

DBCT8.4%

WestNet Rail13.3%

Euroports36.0%

NGPL20.6%

IEG12.8%

TGN1.2%

Powerco NZ7.7% T

RANSPORT

ENERGY

T&D

DBCT11.9%

WestNet Rail16.1%

Euroports11.3%

NGPL37.1%

IEG11.3%

TGN0.5%

Powerco NZ11.8%

TRANSPORT

ENERGY

T&D

Source: BBI15

4.3 Structure and Fees

BBI is a stapled security consisting of a share in an Australian public company, BBIL, and a unit in an Australian trust, BBIT. Most of the assets of BBI are predominantly held by the company, which conducts the operations of the group through its subsidiaries, while the trust predominantly acts as a financing vehicle16. This structure allows cash flow generated by the trust from its financing activities and cash flow in excess of accounting earnings to be distributed to securityholders on a tax deferred basis until the distributions received by a securityholder exceed the tax cost base of its unit in the trust.

14 The proportional revenue and EBITDA for Powerco represents 100% of the Powerco NZ operations for the period 1 July 2008 to 26

February 2009 and 42% of the Powerco NZ operations for the period 27 February 2009 to 30 June 2009. For the year ended 30 June 2009, Euroports was reported as discontinued operations as a result of the sale of the 40% interest. Percentages are before BBI corporate costs.

15 Percentages are before BBI corporate costs. 16 A proportion of DBCT and a proportion of the equity interest in NGPL is held by BBIT.

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Currently, BBIS is the responsible entity for the trust and BBIM is currently the manager of BBI. However, it is contemplated that contemporaneously with this Recapitalisation proposal (and consistent with BBI’s ASX announcement on 26 August 2009 BBI) these arrangements will be terminated. This termination is expected to become unconditional if the proposal proceeds. BBIS is currently a wholly owned subsidiary of Babcock & Brown, which as discussed in Section 1 is now in liquidation. Following the termination of the management agreement, BBI agreed with Babcock & Brown that it will only pay fees to the responsible entity, BBIS. These fees were set at $2 million per annum and apply until 2012 or for so long as Babcock & Brown owns BBIS. BBI has internalised the manager role and all BBIM employees dedicated to the management of BBI have been re-employed under the internalised management structure within BBI. In addition, following completion of the internalisation as currently proposed BBIT unitholders will have the sole right to appoint and remove BBIS directors. It is also proposed that the shares in BBIS will be acquired and held by the BBIS directors in their personal capacity or by their nominee. At the time that the shares in BBIS are transferred to the directors, the present value of the $2 million fee otherwise payable until 2012 will be paid to Babcock & Brown. Thereafter, no further responsible entity fees will be payable to BBIS.

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4.4 Financial Performance

The historical and pro forma forecast financial performance of BBI for the five years ended 30 June 2010 is summarised below:

BBI - Financial Performance17 ($ millions) Year ended 30 June

2006 actual AIFRS

2007 actualAIFRS

2008 actual AIFRS

2009 actual AIFRS

2010 forecast AIFRS

pro forma18 Total revenue 750.6 1,207.6 1,108.1 1,246.3 437.0 EBITDA19 344.3 504.7 389.5 470.4 153.0 Depreciation and amortisation (123.8) (180.9) (149.2) (177.6) (78.0)

EBIT20 220.5 323.8 240.3 292.8 75.0 Net interest expense (217.2) (301.7) (340.7) (436.4) (12.0) Net hedge gain / (expense) 4.9 (27.8) 20.3 (153.9) - Dividends received - - - - - Share of profit/(loss) of associates - - 6.8 9.0 18.0 Significant and non-recurring items 16.7 8.4 32.9 (716.0) -

Operating profit before tax 24.8 2.8 (40.3) (1,004.5) 81.0 Income tax expense 15.2 51.2 13.3 157.2

Operating profit after tax 40.1 54.0 (27.0) (847.3) Profit/(loss) from discontinued operations 19.0 59.0 (17.5) (129.8) Outside equity interests (2.0) (6.2) 5.4 23.2

Profit after tax attributable to BBI equity holders 57.1 106.8 (39.1) (953.9) Statistics Basic earnings per stapled security21 5.13¢ 7.03¢ (2.01) (40.69) Distributions per stapled security 13.25¢ 14.25¢ 10.0¢ -

EBITDA margin 45.9% 41.8% 35.2% 37.7% 34.8% EBIT margin 29.4% 26.8% 21.7% 20.5% 17.1%

Source: BBI and Grant Samuel analysis The significant number of acquisitions and divestments made by BBI in recent years makes it difficult to undertake year to year comparisons of BBI’s financial performance. Because Powerco and Euroports are reported as assets held for sale as at 30 June 2009, the FY09 net profit after tax of both these businesses is reported as profit/(loss) from discontinued operations. The FY08 financials have been restated to reflect this change so that the financial performance can be compared on a like for like basis. The FY06 and FY07 financials have not been restated to reflect these discontinued assets and as a result it is difficult to compare FY06 and FY07 with FY08 and FY09. Following completion of the sale of interests in both Powerco and Euroports, BBI’s 60% interest in Euroports (on a fully diluted basis) and 42% interest in Powerco will be reported using the equity accounting method for associates22.

17 Financial statements were prepared in accordance with the Australian equivalent to international financial reporting standards

(“AIFRS”). The financials represent the most recently reported restated financials. 18 Prepared for the purposes of the Prospectus. 19 EBITDA is earnings before net interest, tax, depreciation and amortisation, investment income, and significant and non-recurring

items. 20 EBIT is earnings before net interest, tax, investment income, and significant and non-recurring items. 21 Basic earnings per share includes earnings from both continued and discontinued operations. 22 Accounting treatment is based on control.

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Significant and non-recurring items in the year ending 30 June 2009 included the following writedowns: $232.0 million for AET&D; $50.9 million for WestNet Rail; $373.9 million for PD Ports and $38.9 million for TasGas Networks. An impairment charge relating to Euroports of $199.4 million is accounted for within the loss from discontinued operations. The BBI Pro Forma Forecast assumes a number of adjustments including assumptions regarding the sale of assets and use of funds to repay debt. Please refer to Section 8 of the Prospectus for further detail on the adjustments. The BBI Forecast has been prepared by BBI and reviewed by Deloitte. Report on Director’s Forecast is set out in Section 11 of the Prospectus. BBI has a number of assets that are equity accounted. The revenue and EBITDA for these assets are not reflected in BBI’s revenue and EBITDA above and are accounted for at a net profit after tax level in BBI’s share of profit/(loss) of associates. The following table illustrates BBI’s proportionally consolidated EBITDA (excluding corporate costs) for all assets for the five years ending 30 June 2010.

BBI – Proportionally Consolidated EBITDA ($ millions) Year ended 30 June

2006 actual AIFRS

2007 actual AIFRS

2008 actual AIFRS

2009 actual AIFRS

2010 forecastAIFRS

pro forma ET&D Powerco23 175.2 182.7 188.0 147.4 75.0 IEG 63.1 66.5 70.9 86.3 65.0 CSC 6.224 17.5 15.5 21.6 AET&D - - 157.6 126.5 NGPL - - 72.825 239.7 220.0 TGN26 2.6 3.0 7.0

Total ET&D EBITDA 244.5 266.7 507.4 624.5 367.0 Transport DBCT 79.7 82.4 97.1 153.7 111.0 PD Ports 40.127 106.2 127.8 71.4 WestNet Rail 3.528 53.0 71.4 86.9 108.0 Euroports - 6.8 27.6 94.2 79.0 Total Transport EBITDA 123.3 248.4 323.9 406.2 298.0 Total EBITDA 367.8 515.1 831.2 1,030.8 665.0

Source: BBI As part of the Recapitalisation, management of CSC and AET&D will be undertaken by Brookfield and Brookfield will be provided with options to acquire the equity of CSC and AET&D for nominal amounts. As such CSC and AET&D will be classified as “held for sale” and will not be included in EBITDA. In addition Brookfield will acquire a 49.9% economic

23 The proportionally consolidated EBITDA for Powerco in FY09 represents 100% of the Powerco New Zealand operations for the

period 1 July 2008 to 26 February 2009 and 42% of the Powerco New Zealand operations for the period 27 February 2009 to 30 June 2009. FY08 represents 100% of the Powerco New Zealand operations for the full year.

24 CSC FY06 EBITDA represents only four months’ contribution as CSC was acquired on 27 February 2006. 25 NGPL FY08 EBITDA represents only four months’ contribution as NGPL was acquired on 13 February 2008. 26 Prior to FY08, TGN was included in Powerco’s results. 27 PD Ports FY06 EBITDA represents only five months’ contribution as PD Ports was acquired on 27 January 2006. 28 WestNet Rail FY06 EBITDA represents only one month’s contribution as WestNet Rail was acquired on 1 June 2006.

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interest in DBCT, which results in BBI’s 50.1% interest being recognized as an equity accounted investment. Brookfield will also acquire 100% of PD Ports. Please refer to Section 8 of the Prospectus regarding further detail on the adjustments assumed in the pro forma financials above.

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4.5 Financial Position

The financial position of BBI as at 30 June 2009 is summarised below:

BBI - Financial Position ($ millions) As at 30 June 2009

Reported Pro forma29 Receivables and other current assets 199.9 67.8 Inventories 18.7 17.3 Financial assets (net) (49.5) 30.1 Creditors, provisions and other current liabilities (359.7) (120.8)

Net working capital (190.6) (5.6) Property, plant and equipment (net) 3,876.5 1,763.9 Equity accounted associates 650.5 737.4 Investment property 174.7 - Non-current assets held for sale (net) 316.6 (12.4) Goodwill 378.6 185.6 Other intangible assets (net) 3,045.5 7.5 Receivables and other assets 177.7 37.5 Financial assets (net) 498.4 943.1 Deferred tax liabilities (net) (209.8) 233.9 Provisions and other liabilities (275.9) (137.8) Total funds employed 8,442.2 3,753.1 Cash and deposits 257.9 193.9 Bank loans, other loans and finance leases (6,979.7) (1,219.4)

Net borrowings (6,721.8) (1,025.5) Net assets 1,720.4 2,727.6 Outside equity interests (102.8) -

Equity attributable to BBI Securityholders 1,617.5 2,727.6 Statistics Stapled Securities on issue at period end (million) 2,591.8 Net assets per share 0.66 NTA30 per share (0.66) Book gearing31 79.6% 27.3% Market gearing32 98.0%

Source: BBI reports, Prospectus and Grant Samuel analysis BBI is highly geared within each of its individual assets, with current market gearing of 98.0%. BBI enters into interest rate hedges and exchange rate hedges to manage its exposure to foreign currency denominated distributions and interest rate risk under its debt facilities. These hedges are reflected in net financial assets and as at 30 June 2009 had a mark to market loss of $243.2 million. Investment property refers to the freehold land within PD Ports. Intangible assets comprises conservancy right associated with PD Ports, the long term leasehold right for DBCT, concession

29 Prepared in accordance with the Prospectus. 30 NTA is net tangible assets, which is calculated as net assets less intangible assets. 31 Book gearing is net borrowings divided by net assets plus net borrowings. 32 Market gearing is net borrowings divided by market value plus net borrowings. Market value is based on BBI security price as 29

September 2009 (being the last trading day prior to announcement of the Equity Raising).

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arrangements associated with each of the European ports, permits associated with CSC and software and licences. BBI operates defined benefit superannuation plans within IEG and PD Ports and two minor defined benefit plans at Seehafen Rostock Umschlagsgeslellschaft (“Rostock”) and Terminal Rinfuse Italia SpA (“TRI”) (assets forming part of the Euroports portfolio). In the year ending 30 June 2009, BBI reported a defined benefit asset of $34.6 million which is included above in receivables and other assets. BBI has a number of contingent assets and liabilities outstanding, including disputes with taxation authorities. These disputes with taxation authorities are the most significant contingent liabilities outstanding, totalling $145 million as at 30 June 2009 and relate to the deductibility of certain payments made in relation to the long term lease of DBCT. The maturity profile of BBI’s senior secured corporate debt is illustrated below33. There is no outstanding corporate debt beyond June 2013.

BBI Corporate Debt Maturity Profileas at 30 June 2009

$169

$584

$479

$0

$100

$200

$300

$400

$500

$600

$700

Jun-2009 Jun-2010 Jun-2011 Jun-2012 Jun-2013

Cor

pora

te D

ebt (

mill

ion)

Source: BBI The detailed BBI Financial Position is set out in Section 7 of the Prospectus. The BBI Pro Forma Financial Position has been prepared by BBI and reviewed by Deloitte. Deloitte’s Investigating Accountant’s Report is set out in Section 10 of the Prospectus. BBI’s debt position as recognised in its balance sheet consists of debt held at both the corporate level and at an individual asset level, as analysed on a statutory basis in the following table.

33 £82.2 million or approximately $169 million is due in February 2010 although under the cash sweep mechanism agreed with the

BBI corporate lenders, BBI will be required to repay approximately $300 million in corporate debt to meet this debt maturity in February 2010.

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BBI – Statutory Net Debt ($ millions) As at 30 June 2009

Actual Pro forma34 BBI Corporate (includes SPARCS and EPS) 1,999.7 213.3 AET&D 1,199.0 Powerco NZ - Tas Gas - CSC 237.4 NGPL - IEG 550.6 520.9 DBCT 1,689.9 WestNet Rail 619.7 483.7 PD Ports 725.7 Euroports - 49.6 Finance leases 4.9 Less cash and capitalised borrowing costs (305.1) (242.0)

Total Net Debt 6,721.8 1,025.5 Source: BBI BBI consolidates the total debt relating to all assets in which BBI has a controlling interest, but does not recognise on its balance sheet the debt associated with those assets in which BBI has a minority interest. BBI’s proportional net debt position (ie its effective economic “interest” in debt at the corporate level and within each of its asset investments adjusted for cash) as at 30 June 2009 is illustrated below. Please refer to Section 7.5 of the Prospectus for further detail.

BBI – Proportional Net Debt ($ millions) As at 30 June 2009

Actual Pro forma34 BBI Corporate 1,173 (20) AET&D 1,661 Powerco NZ 410 376 Tas Gas - - CSC 237 NGPL35 1,229 1,229 IEG 519 490 DBCT 1,601 802 WestNet Rail 564 453 PD Ports 626 Euroports 432 432

Total Proportional Net Debt 8,452 3,762 Source: BBI The Recapitalisation is expected to result in the repayment of over $1,400 million in corporate and asset level debt and associated swaps, which is expected to decrease book gearing from 79.6% to just under 30% (based on the pro forma adjustments above).

34 Pro forma is after the Recapitalisation. 35 Includes debt at holding company level.

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4.6 Cash Flow

BBI’s cash flow for the two years ended 30 June 2009 is summarised below:

BBI - Cash Flow ($ millions) Year ended 30 June 2009

2008 actual AIFRS

2009 actual AIFRS

EBITDA 389.5 470.4 Changes in working capital and other adjustments 382.9 270.1 Capital expenditure (net) (933.4) (674.3)

Operating cash flow (161.0) 66.2 Tax paid (13.7) (19.1) Net interest paid (429.4) (489.6) Distributions and dividends paid (305.8) (65.6) Acquisition of businesses (1,118.0) (185.4) Disposal of businesses 47.3 415.9 Proceeds from share issues 80.1 - Other (737.9) 92.8 Proceeds / (repayment) of borrowings 2,733.9 251.8

Net cash generated (used) 95.6 67.0 Source: BBI and Grant Samuel analysis In November 2008, BBI suspended payments of stapled security distributions in light of the uncertainty in credit markets following the global financial crisis. BBI’s current focus is to use operating cash flows to reduce debt as opposed to paying distributions. However, as illustrated in the above cash flow, BBI has continued to use debt to part fund capital expenditure.

4.7 Taxation Position

If the dispute relating to the deductibility of certain long term lease payments of DBCT is resolved in favour of BBIL (refer to section 4.5), the BBIL tax consolidated group should have approximately $261.5 million of carried forward income tax losses at 30 June 2009. If the action is resolved in favour of the Australian Taxation Office, BBIL tax consolidated group’s carried forward income tax losses at 30 June 2009 should be approximately $110.3 million. In addition, the BBI Trust should have approximately $45.1 million in carried forward income tax losses at 30 June 2009. The carried forward income tax losses for the DBCT Trust at 30 June 2009 should be $43.8 million. Losses of $153.11 million relating to BBI Networks New Zealand (BBIN NZ) may not be carried forward following the Recapitalisation due to New Zealand change of ownership rules (i.e. there is a forfeit of losses if less than 50% of underlying owners in the loss years are carried over into the income years).

4.8 Capital Structure and Ownership

4.8.1 Capital Structure

As at 30 September 2009, BBI had the following securities on issue:

2,591,766,809 stapled Securities;

one “A” special share convertible loan note and one “B” special share convertible loan note held by BBIM and BBIS respectively. The loan notes were issued on the

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restructure of BBI in July 2005 and if converted would entitle Babcock & Brown to effectively appoint 75% of the directors of the BBI company including the right to appoint one of these directors as the managing director. The loan notes were issued on 1 July 2005, have a 25 year term, carry no rights to interest or distributions and can only be converted if the BBI company directors not associated with Babcock & Brown determine to do so. Following internalisation these convertible loan notes would be cancelled and BBIL directors would seek the approval of Security holders to amend the constitution of BBIL to remove the ability to issue A and B Special Shares;

119,041,816 SPARCS which are traded on the New Zealand Stock Exchange. SPARCS were issued as part of the consideration for the 2004 acquisition of Powerco. SPARCS are entitled to interest at a rate of 8.5% until the reset date, being 17 November 2009. In certain circumstances, including on the reset date, SPARCS may be converted at the option of BBI or the SPARC holder. In any event, BBI determines whether they are to be converted for BBI stapled securities, cash or a combination thereof. The conversion rate will be equal to the face value of the SPARCS (approximately NZ$119 million) divided by the relevant BBI VWAP (with a 2.5% discount applied) converted into Australian dollars at the relevant exchange rate; and

778,656,840 EPS. The EPS carry a dividend rate based on BBSW plus a margin of 1.15%. On the first reset date (1 July 2012) BBI may reset certain terms of the EPS including the dividend rate. BBI at certain times may issue an exchange notice whereby BBI may redeem the EPS for cash, convert the EPS to stapled securities or a combination of the two. The EPS holders may not request the redemption of the EPS but may choose to elect on a reset date to accept the reset terms or request for an exchange of the EPS. BBI on exchange may redeem for cash, resell or convert the EPS into stapled securities, or a combination of the above. Both the redemption and resale would occur at a premium of approximately 3.9% to face value. The conversion rate will be equal to the face value of the EPS (approximately $780 million) plus any accrued and deferred dividends divided by the relevant 20 day BBI VWAP (with a 7.5% discount applied).

The EPS suspended the payment of dividends on 5 November 2008.

4.8.2 Ownership

At 8 September 2009 there were 98,782 registered ordinary securityholders in BBI. The top 20 securityholders accounted for approximately 40.38% of the ordinary shares on issue. The majority of these securityholders (by value) are institutional nominee or publically listed investment companies. BBI has one substantial securityholder, B&B Group, which holds 141,208,025 stapled securities, representing 5.94% of total stapled securities on issue.

4.9 Security Price Performance

4.9.1 Security Price History

BBI stapled securities were issued at $1.00 per security on a partly paid basis. The first instalment was $0.70 paid on subscription with the final instalment of $0.30 paid on 1 July 2003. A summary of the price and trading history of BBI since 1 January 2005 is set out below:

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BBI - Security Price History

Security Price ($) High Low Close

Average Weekly Volume (000’s)

Average Weekly

Transactions

Year ended 31 December 2005 1.90 1.19 1.60 8,988 1,058 2006 1.89 1.46 1.86 19,262 1,821 2007 2.03 1.42 1.60 36,565 3,647 2008 1.61 0.02 0.11 85,014 6,832 Quarter ended 31 March 2009 0.15 0.03 0.06 74,928 2,628 30 June 2009 0.20 0.06 0.07 136,192 3,329 Month ended 31 July 2009 0.08 0.06 0.08 84,985 2,235 31 August 2009 0.14 0.06 0.08 233,430 4,455 30 September 2009 0.09 0.04 0.05 242,966 3,054

Source: IRESS The following graph illustrates the movement in BBI’s security price and trading volumes since 1 January 2006.

BBI Security Price & Trading Volume(1 January 2006 - 29 September 2009)

0.00

0.50

1.00

1.50

2.00

2.50

Jan-06

Mar-06

Jun-06

Sep-06

Dec-06

Mar-07

May-07

Aug-07

Nov-07

Feb-08

Apr-08

Jul-08

Oct-08

Jan-09

Mar-09

Jun-09

Sep-09

Shar

e Pr

ice

($)

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

Weekly V

olume (000's)

Source: IRESS During the 12 months to December 2006, BBI generally traded in the range $1.46 – 1.89, trending up towards the higher end of the range towards the end of the year. In 2006, BBI announced the 100% acquisition of PD Ports, the 100% acquisition of CSC and the purchase of 51% of WestNet Rail. In November and December 2006, BBI announced the sale of BBI’s remaining power generation assets and the sale of BBI’s interest in BBW, which helped support the security price. During the 12 months to December 2007, BBI traded in the range $1.42 - 2.03. In February 2007, BBI released its half year results and undertook a relatively large institutional placement of 234.5 million stapled securities at $1.80 per security raising $422 million. Subsequently, BBI traded around the placement price during March 2007. At the end of March, BBI participated in a consortium with Babcock & Brown and

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Singapore Power International Ltd, which announced the acquisition of all the shares in Alinta Limited, whereby BBI would acquire certain energy and transmission assets of Alinta. In May, a consortium led by Macquarie submitted a competing acquisition proposal for all the shares in Alinta, which was in late May rejected following a revised proposal from the BBI, Babcock & Brown and Singapore Power International Ltd consortium. This revised proposal from the BBI, Babcock & Brown and Singapore Power International Ltd consortium was approved in August. BBI’s share price fell significantly in 2008, from a high in January of $1.61 to a low in November of $0.02. In addition to acquiring the Alinta assets, in late 2007 to early 2008 BBI acquired an effective 26.4% interest in NGPL for approximately $2 billion and made a number of investments within the Euroports portfolio. A significant proportion of these acquisitions were funded via debt. As the global financial crisis worsened, highly geared companies came under significant bank pressure to reduce gearing levels and meet strict covenants. In common with many other highly geared companies, BBI’s security price fell significantly. In June 2008, BBI announced a capital management review in order to improve balance sheet strength and consider initiatives to close the gap between the underlying value of its assets and the market price of BBI securities. In August, BBI announced that it would look to sell 50% in each of Powerco and WestNet Rail, with the sale proceeds used to reduce debt. In November, when BBI shares hit $0.02, BBI announced the suspension of distributions and EPS dividends and was downgraded by Moody’s. For the nine months ended 29 September 2009, the last trading day prior to the announced Recapitalisation, BBI securities traded in the range $0.03 - 0.20. In February, BBI sold 58% of Powerco and completed the sale of 40% of Euroports. BBI also announced it was looking to sell part or all of both PD Ports and DBCT. BBI’s FY09 results announced in August included $895 million of asset impairments and also announced the termination of the management agreement between BBI and BBIM (as discussed in Section 4.3).

4.9.2 Liquidity

BBI has been a reasonably liquid security with average weekly volume over the twelve months prior to the announcement of the Recapitalisation representing approximately 5.5% of weighted average securities on issue, or annual turnover for FY09 of around 234% of weighted average securities on issue.

4.9.3 Relative Performance

BBI is a member of various indices including the S&P/ASX 200 Utilities Index and the S&P/ASX 200 Industrials Index. At 29 September 2009, its weighting in these indices was approximately 0.98% and 0.02% respectively. The following graph illustrates the performance of BBI securities since June 2002 relative to the S&P/ASX 200 Utilities Index and the S&P/ASX 200 Industrials Index:

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BBI vs S&P/ASX 200 Utilities Index vs S&P/ASX 200 Industrials Index

(1 June 2002 - 29 September 2009)

0

50

100

150

200

250

300

Jun-02

Dec-02

Jun-03

Dec-03

Jun-04

Dec-04

Jun-05

Dec-05

Jun-06

Dec-06

Jun-07

Dec-07

Jun-08

Dec-08

Jun-09

BBI 200 Utilities 200 Industrials

Source: IRESS BBI generally tracked both the S&P/ASX 200 Utilities Index and S&P/ASX 200 Industrials Index until around June 2008. However, from mid 2008 onwards, BBI units have significantly underperformed, as the BBI security price fell sharply reflecting a general fall in infrastructure asset values, BBI’s high level of gearing and uncertainty regarding BBI’s ability to continue to finance its operations.

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5 Description of BBI Assets

5.1 Energy Transmission and Distribution

5.1.1 AET&D

BBI acquired the AET&D assets from Alinta in August 2007, funding the acquisition through the issue to Alinta shareholders of BBI stapled securities and EPS and the assumption of $1.1 billion of limited recourse debt, including a committed, limited recourse debt bridging line of $518 million (which was refinanced in July 2008). The simplified corporate structure of AET&D is set out below:

Alinta DBNGPPty Ltd

ANetworksHoldings Pty Ltd

BBI

100%

100%

BBI AET&D Holdings

No. 1 Pty Ltd

BBI TGPPty Ltd

BBI AET&D Holdings

No. 2 Pty Ltd

100%

AET&D – Simplified Corporate Structure

Multinet GroupHoldings Pty Ltd

Westnet EnergyPty Ltd

WA NetworkHoldings Pty Ltd

WA Gas NetworksPty Ltd

Westnet EnergyServices Pty Ltd

DBNGPHoldings Pty Ltd DBNGP Trust

100% 100% 100%100%20.1%

20%20% 100%

100%

24%

50.1%

Source: BBI A brief description of the AET&D assets is set out below. Transmission Assets

Tasmanian Gas Pipeline (100%) The Tasmanian Gas Pipeline transports natural gas from Victoria across Bass Strait to Tasmania. Gas enters the pipeline at the Longford Compressor Station. The pipeline is a 734 kilometre subsea and onshore gas pipeline system and was commissioned in 2002. The Longford to Bell Bay mainline has a capacity of 47 PJ per annum (with a maximum compressed capacity of 57 PJ per annum). There are smaller capacity extensions from the pipeline to Port Latta in north west Tasmania and to the outskirts of Hobart in the south east. The Tasmanian Gas Pipeline had an original design life of 40 years. However, BBI management is confident that as a result of high levels of maintenance the pipeline will have a useful life of 70 years. The Tasmanian Gas Pipeline is the only supplier of natural gas to Tasmania and sources its gas from the Gippsland Basin in Victoria. The construction of the pipeline was underpinned by long term take or pay contracts (out to 2016-2018) to major users in Tasmania. As a consequence, close to 100% of 2010 forecast revenue is expected to come from existing contracts. Major end users of the pipeline include the Tamar Valley Power Station (which became operational in April 2009), mining and minerals processing operators (including Comalco and Australia Bulk Minerals), and small to medium

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residential and industrial customers supplied by the gas reticulation network being developed by Tas Gas Networks. The Tasmanian Gas Pipeline is currently “uncovered” and not regulated by the Gas Code. Tariffs on the pipeline are negotiated on a commercial basis on the basis of a non-discriminatory access policy. Currently, less than 50% of the Tasmanian Gas Pipeline’s capacity is utilised so there is significant ability to increase throughput without major capital expenditure. The drivers of growth are expected to be growing demand for gas-fired electricity and the continued roll-out of the gas reticulation system. On the other hand, throughput growth may be limited by the ability of Tasmania to attract new industrial development, the immaturity of the Tasmanian gas market and competition from other more traditional sources of power in Tasmania (including hydroelectricity, coal, LPG and wood).

Dampier to Bunbury Natural Gas Pipeline (20%) A consortium comprising BBI, Alcoa and DUET owns and operates the Dampier to Bunbury Natural Gas Pipeline. The 1,596 kilometre natural gas transmission pipeline runs from the Burrup Peninsula, near Dampier, to Bunbury in Western Australia and is the sole means of natural gas transmission from the North West Shelf gas fields to residential, industrial and commercial users in Western Australia’s south west. The main pipeline was built by the State Energy Commission of Western Australia (with the support of Alcoa) and commissioned in 1984, with the extension to Bunbury commissioned in 1985. Since December 2006 the pipeline has been interconnected with the Goldfields Gas Pipeline. The pipeline’s full haul capacity is fully contracted until at least 2019 with key customers including Alcoa, Verve Energy and Alinta. The pipeline has been internally managed since February 2009 although project management of major expansion projects and IT services are outsourced to WestNet Energy under a long term agreement. Following commissioning of the $660 million Stage 5A expansion project in April 2008, total pipeline capacity is approximately 785 TJ per day. Continued growth in demand, primarily from existing customers, has resulted in the commencement of the $690 million Stage 5B expansion project in January 2009, which will increase total capacity, principally via looping, by approximately 113 TJ per day. The Stage 5B expansion project is expected to be completed in the second half of 2010 with 100% of the increased capacity already contracted. At completion the pipeline will have been more than 80% duplicated. A Stage 5C expansion project is contemplated for the period after 2011, pending firm capacity requests from shippers. Pipeline tariffs are subject to regulation by the Western Australian Economic Regulatory Authority, with the most recent price determination in December 2005. However, all revenue contracts for the pipeline operate outside the regulatory regime at tariffs higher than the reference tariffs until 1 January 2016. From 2016 contract tariffs for all shippers except for Alcoa will revert to the regulated tariff. The next regulatory reset date is 1 January 2011. Based on the most recent determination the pipeline’s regulated asset base (in real dollars at 1 January 2005) at 30 June 2009 was $2.229 billion, although this makes no allowance for the Stage 5A expansion and excludes the forecast expenditure on the Stage 5B expansion. Management has calculated the regulated asset base of the pipeline at 30 June 2009 at $3.138 billion (including expenditure to date on the Stage 5B expansion). BBI holds a 20% interest in the Dampier to Bunbury Natural Gas Pipeline. DUET holds a 60% interest and Alcoa the remaining 20% interest. BBI’s interest in the pipeline is governed by a unitholders agreement with co-owners DUET and Alcoa.

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The Commonwealth Government’s CPRS is expected to have an impact on the Dampier to Bunbury Natural Gas Pipeline as a result of gas used for compressors. It is expected that any cost associated with acquiring carbon permits (estimated based on financial year 2009 volumes to be of the order of $0.2–1.0 million) will be passed through to customers via a regulatory mechanism.

Distribution Assets

WA Gas Networks (74.1%) WA Gas Networks is Western Australia’s largest distributor of natural gas with 12,773 kilometres of gas distribution pipes. It is 74.1% owned by BBI with DUET holding 25.9%. The business comprises three distribution networks:

Mid-West and South-West Gas Distribution Systems, which service customers in the greater metropolitan Perth area and a number of large regional centres;

Kalgoorlie Distribution Network, which services the Kalgoorlie-Boulder area; and

Albany Distribution Network, which distributes LPG to Albany. In total WA Gas Networks’ networks had 610,294 customer connections as at 30 June 2009 and carried a load of 27,977TJ during the year ended 30 June 2009. The majority of the load is distributed to commercial and industrial customers although residential premises represent the majority of connections. Gas is used in residential premises primarily for cooking and water heating (as a booster to solar heating). WA Gas Networks is the principal distributor in the areas in which it operates. While competing distribution networks could conceivably be developed for very large industrial customers, this outcome is considered unlikely. Tariff and access arrangements for WA Gas Networks are regulated by the Western Australian Economic Regulation Authority. Only the Mid-West and South-West Gas Distribution Systems are regulated (although these systems contribute approximately 93% of WA Gas Networks’ revenue). The current regulatory determination for WA Gas Networks was finalised in 2005, covering the period from 25 August 2005 to 31 December 2009. Under the determination the regulated asset base of WA Gas Networks at 31 December 2006 was $658.6 million (in December 2004 dollars). In February 2009, WA Gas Networks was granted a six month extension (to 30 September 2009) to submit revisions for the proposed access arrangement for the Mid-West and South-West Gas Distribution Systems to 30 September 2009. This extension will delay the anticipated date for commencement of the revised access arrangements to 1 July 2010 (rather than 1 January 2010). A further time extension (necessary to allow for the implementation of the new gas law) has now been granted until 31 January 2010. The ERA has indicated that this will delay the implementation of a revised access arrangement until at least 1 January 2011. WA Gas Networks receives its revenue from retailers who supply gas to customers over its network. Alinta Sales Pty Limited (owned by BBP) is the largest retailer using the network. The gas market in metropolitan Western Australia is relatively mature with penetration rates of approximately 80% (and 100% penetration in new land developments). WestNet Energy is the prime contractor for WA Gas Networks, although WA Gas Networks is proposing to internalise its asset management services from 1 July 2010. BBI’s interest in WA Gas Networks is subject to a shareholders agreement with co-owner DUET.

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The Commonwealth Government’s CPRS is expected to have an impact on WA Gas Networks as a result of gas ”loss” within the gas distribution network (meter error and leaks on pipes/meters). It is expected that any cost associated with acquiring carbon permits (estimated based on financial year 2009 volumes to be of the order of $1.0-4.0 million) will be passed through to customers via a regulatory mechanism.

Multinet Gas (20.1%)

Multinet Gas owns the natural gas distribution network servicing Melbourne’s eastern and south-eastern suburbs. Its licence area is predominantly urban in nature. The network had 660,191 customer connections at 30 June 2009 and carried a load of 58.5PJ in the year ended 20 June 2009. Multinet Gas’ network is one of three gas distribution networks servicing Victoria. Its revenue and access regime was regulated by the Victorian Essential Services Commission until 1 July 2008, when it was transferred to the AER. Multinet Gas’ last regulatory reset occurred in 2008, with revenues set until 31 December 2012. Multinet Gas reported revenue of $181 million, EBITDA of $138 million and EBIT of $105 million in the year ended 20 June 200936. The regulated asset base at 30 June 2009 (in July 2006 dollars) was $913.5 million based on the most recent determination. Multinet Gas derives its revenue from retailers who supply gas to customers over its network. Victoria’s retail gas market is fully contestable, with a large number of retailers competing for customers. Most of these retailers are active in Multinet Gas’ licence area. The gas market in Victoria is mature, with penetration rates exceeding 90% in Multinet Gas’ licence area. However, opportunities do exist to expand network coverage. In recent years Multinet Gas has successfully tendered for the right to reticulate gas in 12 rural and regional towns as part of the Victorian Government’s Natural Gas Extension Program. Multinet Gas has completed construction of the Yarra Ranges network which provides gas to approximately 6,000 properties and construction of the South Gippsland network to provide gas to approximately 10,000 properties is nearing completion. Multinet Gas expects to be an active participant in any future tender process. Jemena Asset Management (“Jemena”) is the prime contractor for the Multinet Gas network. BBI’s interest in Multinet Gas is governed by a shareholders agreement with co-owner DUET. The Commonwealth Government’s CPRS is expected to have an impact on Multinet Gas as a result of gas ”loss” within the gas distribution network (meter error and leaks on pipes/meters). It is expected that any cost associated with acquiring carbon permits (estimated based on financial year 2009 volumes to be of the order of $1.0-3.0 million) will be passed through to customers via a regulatory mechanism. Asset Management Services

WestNet Energy (100%) WestNet Energy is a specialist provider of infrastructure management and services to asset owners across the gas and electricity sectors. Its service offering includes design, engineering, construction, operation and maintenance of greenfield, brownfield and mature infrastructure assets. The business also provides sub-contracting services to other contractors on a short-term basis. The business employs approximately 350 staff across Australia.

36 As reported by DUET.

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WestNet Energy provides asset management services under operating services agreements (“OSAs”) with WA Gas Networks and the Dampier to Bunbury Natural Gas Pipeline. Under the Dampier to Bunbury Natural Gas Pipeline OSA, WestNet Energy provides project management services on major capital expenditure projects only. WestNet Energy also provides corporate services to WestNet Rail, WA Gas Networks, the Tasmanian Gas Pipeline and Tas Gas and provides IT services to the Dampier to Bunbury Natural Gas Pipeline. In addition to providing asset management services to other BBI owned assets, WestNet Energy provides services to external clients. External clients represent approximately 20% of revenue and are principally other gas and electricity infrastructure assets (including Western Power). External service agreements may be comprehensive or for a specific service or project, and may be limited in time or scope. Demand for WestNet Energy’s services is expected to fall in the short term as WA Gas Networks is considering internalising the provision of asset management services. To counteract the potential impact of loss of the WA Gas Networks asset management contract, WestNet Energy intends to seek other external asset management contracts as well as reduce its cost structure.

5.1.2 Other Transmission and Distribution Assets

Transmission Assets

Cross Sound Cable (100%) CSC is a 330 megawatt, 39 kilometre submarine transmission system linking the electricity grids of New England and New York in the United States as illustrated in the map below.

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Source: BBI A CSC converter station converts the Alternating Current (“AC”) received from the supplying power grid to Direct Current (“DC”). The DC power is transferred across Long Island Sound to the other identical converter station which then converts the DC back to AC for the receiving power grid. The conversion to DC allows for precise control of the power flow in either direction and reduces the required number of cables when compared to more commonly used AC transmission. Transmission capacity is contracted to LIPA through to June 2032. LIPA is a non-profit municipal electric utility company in New York State. Payments by LIPA to CSC are based on availability of the cable which is expected to be in excess of 98%. Contracted revenues escalate by a fixed percentage per annum over the life of the contract (subject to achieving availability criteria). CSC operates under FERC for transmission capacity rates and the long term contract with LIPA. In August 2007, BBI signed an Operations and Maintenance Agreement with Trans Bay Cable (“TBC”). TBC is a 400 megawatt, 85 kilometre long transmission system that will be installed under San Francisco Bay, connecting the generation in Pittsburgh, California to the city load in San Francisco. The project is currently under construction and has a commercial operation date of March 2010. CSC revenue for FY09 was $30.3 million, an increase of 34.7% on the previous year, and EBITDA increased 39.4% to $21.6 million. The increase in revenue and EBITDA was the result of contracted increases in the availability charge (from 1 July 2008) and an operational services contract signed with the owners of TBC in California. CSC’s 12 month rolling availability to LIPA for FY09 was 99.06%, ahead of the 98% contractual obligations.

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CSC - Rolling Availability99.99%

99.19% 99.06%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

FY07 FY08 FY09

Rol

ling

Ava

ilabi

lity

Rolling Availability Target

Source: BBI

Natural Gas Pipeline Company of America (26.4%) In February 2008, BBI in a consortium with Babcock & Brown and other co-investors agreed to acquire a combined interest of 80% in MidCon LLC (later renamed NGPL Pipeco) via Myria Holdings Inc (“Myria”). The following diagram represents BBI’s investment in NGPL, under which BBI holds an effective 26.4% interest in NGPL and is the largest single shareholder.

NGPL Pipeco(Previously MicCon)

NGPL

Knight Inc. Myria

BBIOther

ConsortiumPartners

20% 80%

BBI effective26% ownership

BBI effective26% ownership

BBI effective33% ownership

33% 67%

NGPL Simplified Corporate Structure

NGPL Pipeco(Previously MicCon)

NGPL

Knight Inc. Myria

BBIOther

ConsortiumPartners

20% 80%

BBI effective26% ownership

BBI effective26% ownership

BBI effective33% ownership

33% 67%

NGPL Simplified Corporate Structure

Source: BBI NGPL is one of the largest natural gas transmission pipeline and storage systems in the United States. NGPL assets extend over 15,600 kilometres and deliver approximately

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2,244 petajoules of gas per annum to end users via 217 compressors at 61 stations. NGPL serves a large part of the Chicago residential, commercial and industrial natural gas customer base. The large network provides a means for producers to access national markets and NPGL has a substantial storage capability allowing local distribution companies, gas-fired electric generators and gas producers the ability to store gas, ensuring that they can meet volatile loads and take advantage of peak pricing periods. The top 10 customers make up over 60% of the transmission and storage revenues. The average contract terms are 3.3 years for transport and 4.1 years for storage customers respectively. The four major transmission lines are the Amarillo Line, A/G Line, Louisiana Line and the Gulf Coast Line, as illustrated on the map below.

Source: BBI FERC regulates the performance of interstate transportation and storage services provided by NGPL, including rates charged as per the Natural Gas Act. FERC provides a regulated framework for shippers and transmission pipeline owners to reach commercial agreement with direct intervention under a maximum rate regime and there is no periodic rate case obligation.

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Distribution Assets

Tas Gas (100%) Tas Gas (formerly Powerco Tasmania) owns and operates a natural gas distribution network (“Tas Gas Networks”) and gas retailing business (“Tas Gas Retail”) that services Tasmania. Tas Gas Networks is the primary business of Tas Gas and is the sole gas distributor in Tasmania with 6,839 connections as at 31 July 2009 delivering a load of approximately 2PJ per annum to customers. The distribution network currently spans 730 kilometres throughout Hobart, Launceston, Longford, Westbury, Bell Bay, Burnie, Wynyard and Devonport. Tas Gas Retail was Tasmania’s first gas retailer and was established to encourage market competition and the uptake of gas as an energy source. Tas Gas Retail is currently one of two natural gas retailers in Tasmania (the other being Aurora Energy Pty Ltd). Tas Gas Networks derives its revenue from gas retailers and large industrial customers for the use of its distribution network, and small amounts of revenue from gas fitting services and the sale of gas appliances. End users of gas are predominantly industrial (i.e. more than 5TJ per annum), with residential and commercial end users responsible for the balance of demand. The natural gas market in Tasmania is in a relatively early stage. The gas network was commissioned in April 2007. As at 31 July 2009, it had only 6,839 connections out of a possible 43,000 customers that the network currently passes. As such there is potential to greatly increase penetration rates. The price of natural gas in Tasmania is not currently regulated because it is not classified as an essential service given the early stage of development of the Tasmanian natural gas market. Therefore natural gas must be priced competitively with electricity (an established energy alternative) to gain customers.

Powerco (42.0%) Powerco is New Zealand’s second largest gas and electricity distribution business, providing connections for approximately 103,000 gas customers (representing 40% of the market) and 312,000 electricity customers (representing 16% of the market) through gas and electricity distribution networks across the upper-central, central and lower areas of New Zealand’s North Island37. Powerco has over 28,000 kilometres of overhead and underground electricity lines and over 5,800 kilometres of gas distribution networks. Gas is drawn from the transmission system owned and operated by the Natural Gas Corporation. Electricity networks connect to 25 grid exit points or sub-stations on Transpower’s transmission network. Powerco also injects electricity back into the national grid from generation plants operated by large industries and from renewable generators (e.g. wind farms). Powerco’s gas and electricity customers are generally large gas and electricity retailers (as well as a small number of large commercial customers) and are diversified by region and retailer. Powerco’s end customers (who are generally contracted via retail energy

37 Powerco’s gas networks are in the Taranaki, Manawatu, Hutt Valley, Porirua, Wellington City, Horowhenua and Hawke’s Bay

regions in North Island and its electricity networks are in the Taranaki, Wanganui, Rangitikei, Manawatu and Wairarapa regions, including the urban centres of New Plymouth, Wanganui, Palmerston North and Masterton as well as Tauranga and surrounding rural areas and the eastern and southern Waikato, Thames and Coromandel regions.

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companies) are largely residential and a significant proportion are in regional (rather than urban) areas. The gas and electricity distribution businesses are subject to economic regulation in New Zealand. The electricity distribution business operates under a price and quality threshold where prices are escalated by CPI-X. Powerco’s current electricity price path has an X factor of 2 and is due for renewal on 1 April 2010. On 8 September 2009, the New Zealand Commerce Commission published a draft decision that provides for an X factor of 0 for the next reset period through to 31 March 2015. The escalation factor does not apply to transmission costs which are pass through costs. The gas distribution business also operates under price control which resulted in Powerco being required to reduce its prices by 11.1% from 1 January 2009. Powerco has recently established two transmission businesses that invest in assets upstream of Powerco’s traditional connection point (as a competitive alternative to Transpower). Powerco Transmission Services (“PTS”) connects renewable generators to the national grid and Independent Transmission Services (“ITS”) transports electricity from new or existing points of connection to the national grid to major users or to Powerco’s distribution networks. PTS and ITS are not regulated assets and are seen as potential growth opportunities for Powerco. In February 2009, following a competitive sales process, BBI completed the sale of a 58% interest in Powerco to funds managed by QIC for NZ$423 million. BBI’s remaining 42.0% interest in Powerco is governed by a shareholders agreement with QIC, under which BBI and QIC each have the right to appoint three directors (although one appointment by each of BBI and QIC must be independent and the BBI nominee must be approved by an ordinary resolution of shareholders), voting rights are such that all decisions (whether by ordinary resolution or special resolution) require the support of BBI nominated directors and there are pre-emptive rights.

International Energy Group (100%) IEG is a leading natural gas and LPG distribution and supply business located in the United Kingdom, the Channel Islands38 and Isle of Man. In the United Kingdom, IEG provides gas distribution services and entered the electricity distribution market in 2006. In 2008, IEG acquired Power On Connections, a specialist electricity connections provider to the commercial market. IEG has more than 400,000 customers connected to its networks and has been supplying gas in the Channel Islands and the Isle of Man for over 170 years. IEG operates the following companies as illustrated in the map below:

Gas Transport Company (“GTC”) (provider of energy infrastructure to the gas and electricity market in the United Kingdom);

Guernsey Gas (retail LPG gas provider to residential and commercial customers in Guernsey);

Jersey Gas (retail LPG gas provider to residential and commercial customers in Jersey); and

Manx Gas (retail LPG and natural gas provider to residential and commercial customers in the Isle of Man).

38 Guernsey and Jersey

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Source: BBI In March 2008 GTC acquired Power on Communications, an independent electricity connections provider based in the United Kingdom, for $53 million. In May 2009, IEG sold its Portugal business (Gascan) to Fundo Explorer II and the net proceeds of the sale ($83 million) were used to reduce IEG debt. A loss of $20.6 million was recognised on this disposal. GTC operates both gas and electricity assets under regulated regimes, while the assets in the Channel Islands and Isle of Man are monitored. GTC is regulated under Ofgem in the United Kingdom, which regulates both the gas and electricity charges giving fixed revenue per connection. There have been recent discussions in the Isle of Man to bring Manx Gas under regulation given its monopoly position. The OFT is currently researching an appropriate framework for the economic regulation of the energy market in the Isle of Man. The OFT analysed Manx Gas' prices between February 2006 and January 2007 and did not find that Manx Gas had made excessive profits during this period, but was concerned that Manx Gas did have the power to pass on to customers high prices paid for gas.

5.2 Transport

5.2.1 Australia

Dalrymple Bay Coal Terminal (100%)

DBCT is a port facility that exports metallurgical and thermal coal mined in the Bowen Basin region of Queensland, Australia. The Bowen Basin region contains the largest coal reserve in Australia and extends over approximately 60,000 square kilometres of central Queensland. DBCT handles approximately 21% of global metallurgical coal seaborne trade and 8% of total global seaborne coal trade. DBCT is located at the Port of Hay Point, approximately 38 kilometres south of Mackay in Queensland. It was established in 1983 by the Queensland Government as a common user coal export facility. DBCT is part of the Goonyella coal supply chain and is linked to the Bowen Basin coalfields by an electrified rail system operated by Queensland Rail.

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In September 2001, BBI (formerly Prime Infrastructure Group) was awarded a long-term lease for DBCT (50 year term with a 49 year renewal option). BBI is responsible for the management and expansion of the facility for the benefit of Bowen Basin coal mines. DBCT was BBI’s foundation asset when it listed on the ASX in June 2002. DBCT is one of the largest export coal terminals in the world, having completed with effect from 30 June 2009 a project (“DBCT 7X Project”) to expand the export capacity of the facility to 85 million tonnes per annum, an increase of around 40%. The expansion cost approximately $1.3 billion (excluding financing costs) over a three year period and was in response to increasing coal production in the Bowen Basin region. The facility comprises rail inloading systems, large stockyards with stackers and reclaimers, off-shore jetty outloading systems and a marine structure for berthing and loading multiple vessels. Indications of future demand above DBCT’s current capacity have been received from existing and potential new customers, and studies are underway to assess the viability of a further expansion of DBCT. DBCT’s revenues are underpinned by long-term, 100% take-or-pay user agreements with some of the largest global resources companies including Rio Tinto, BHP Billiton, Anglo American, Peabody and Xstrata. These user agreements run off progressively over the next 14 years. However, there is a high degree of confidence that DBCT will maintain or grow throughput in the longer term given:

all of DBCT’s customers have significant coal reserves and potential new customers are seeking access to DBCT;

the market demand for metallurgical coal is expected to remain strong moving forward; and

DBCT is uniquely placed to remain the key coal export terminal for the Bowen Basin given its location, common user status and ability to offer multiple loading berths to third parties.

While there are other coal export facilities in Queensland, these are smaller facilities that are either privately owned, further from the major mining areas or currently inaccessible due to missing rail links. Terms and conditions for access by customers to the services provided at DBCT (including tariffs that are charged to customers) are regulated by the Queensland Competition Authority (“QCA”) and are encapsulated in an Access Undertaking that is agreed between DBCT management and the QCA. The current Access Undertaking has a term of five and a half years and is scheduled to expire on 31 December 2009. DBCT has applied to the QCA for a 12 month extension of the Access Undertaking to 31 December 2010, with any changes to apply prospectively. Under the Access Undertaking, DBCT’s revenues are capped, which provides certainty of returns for DBCT and to a large extent insulates the manager from any potential variations in terminal throughput. The components of the regulated tariff charged by DBCT to customers (on a per tonne of committed throughput basis) are:

a capacity charge based an agreed return on DBCT’s asset base (including changes in working capital);

a return on capital component in the form of a depreciation charge; and

a fixed and variable handling charge, associated with operating and maintaining the port (including DBCT’s corporate costs) plus a tax recovery.

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The fixed and variable handling charge represents a complete pass through of the costs charged to BBI for operating and maintaining the port. The operation and maintenance of the port is outsourced to a company (DBCT Pty Ltd) that is owned by five of the terminal’s customers. This aligns the interest of BBI and the customers of the port, as the customers benefit directly from the lower operating costs of a more efficient port. DBCT reported revenue of $265.2 million (36% up on the prior year) and EBITDA of $153.7 million (59% up on the prior year) in the year ended 30 June 2009. The increase related to a full year contribution from the first phase of the DBCT 7X Project (increase in capacity from 59Mtpa to 68Mtpa) and a six month contribution from phase 2/3 stage (a) (increase in capacity to 72Mtpa). A full year contribution for the entire project will be received in the 2010 financial year with capacity having increased to 85Mtpa from July 2009. WestNet Rail (96.0%)

WestNet Rail is a rail infrastructure owner and rail access provider operating in Western Australia with a 49 year arrangement (40 years remaining) to lease track from the Western Australian Government. WestNet Rail operates approximately 5,100 kilometres of standard, narrow and dual gauge network in the south-west of Western Australia, of which 2,500 kilometres are dedicated to the transport of grain. The business is responsible for access management, signalling, communications and controls, network safety and rail construction and maintenance of the network under the terms of the lease with the Western Australian Government. BBI completed the acquisition of a 51% interest in WestNet Rail in June 2006 and was given a call option to purchase the remaining 49% on pre-agreed terms and conditions. The call option arrangements were restructured in March 2008, resulting in BBI increasing its interest in WestNet Rail to 76%, and following a subsequent extension to the arrangements, BBI purchased an additional 20% from the minority investors, increasing its interest to 96%. BBI expects to pay $5 million for the remaining 4% interest in WestNet Rail as part of the Recapitalisation. WestNet Rail is regulated by the Western Australian Economic Regulation Authority. Regulation is based on revenue floors and ceilings for line segments. The next floor and ceiling review is due in June 2012. However, to date the regulation has had little direct impact as all customers have negotiated contracts outside the regime and gross revenues by line have been, in the majority, significantly below regulated revenue ceilings. Approximately 50 million tonnes are hauled on the WestNet Rail network each year and there are around 267,000 train movements per year on the network. Iron ore, bauxite, alumina and grain make up the majority of materials travelling on WestNet Rail. The annual grain load is relatively small, averaging approximately 6.4 million tonnes per annum over the last 10 years but is subject to a high degree of seasonality. Revenues of the business are largely stable, underpinned by long term access agreements with its customer base. WestNet Rail’s revenue is generated from access charges paid by above-rail operators or directly by underlying customers. WestNet Rail has access agreements with major corporate customers (including a long term access agreement with Queensland Rail). The key users of the WestNet Rail network for mineral transportation include Portman, Alcoa, Worsley Alumina, BHP Billiton and Minara Resources.

5.2.2 Europe

Euroports (various investments)

Euroports is one of the largest port operators in continental Europe and handles over 60 million tons of various commodities with a strong focus on bulk cargoes. The

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company has port operations in 16 locations across seven European Union countries and across three main freight corridors, operating in an unregulated environment with a mixture of long and short term contracts.

Euroports controls approximately 485 hectares of long term port concessions with an average EBITDA weighted length of 35 years (including extensions) and over 31 kilometres of quay length. There are no other port operators in Europe with such a wide span of geographical and multi-cargo operations as most port operators either provide their services in a single port or within a single cargo sector (e.g. containers, coal, steel, fertilisers, etc). An outline of the various businesses is set out below:

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39 TEUs meaning ‘twenty foot equivalent units’, are the measure used for capacity in container transportation.

Euroports – Operations Operation Description Finnish Ports (Rauma & Botnia)

Purchased in October 2007

100% interest held

Operates the Port of Rauma located 240km northwest of Helsinki (Finland) and the Port of Pietersaari in North West Finland

Rauma is the largest port in Finland for paper products. It is the forth largest port in Finland and third largest container port in Finland

Predominantly handles forest products and paper under a long term service contract with UPM Kymmene

Also handles dry bulks and general cargo for local industry and power stations

Handles approximately 7.5 million tonnes per annum (“Mtpa”)

Seehafen Rostock Unschlagsgesellschaft (Rostock)

Purchased in December 2007

50% interest held

Located in Rostock, the third largest port in Germany

Handles over 95% of all product through the port of Rostock excluding low value ferry traffic

Operates from 85 hectares of long term concession port land

Principal activities include, oil terminal and tank farm, grain and fertilizer terminals, dry bulks (mainly coal), general cargo and steel, paper terminal, ro/ro operations and intermodal terminal

Handles approximately 14 Mtpa

Westerlund Purchased in 57% in December 2007 and 43% in May 2008

100% interest held

Leading forest products terminal in Europe with a specific focus on finished paper

The company operates two terminals in Antwerp (Belgium) as well as in Rouen (France) and Changsu (China)

Main terminal consists of 85 ha on the left bank of the Port of Antwerp

Westerlund owns and operates 33 warehouses covering 25 hectares

Principal traffic includes paper in all its forms, forestry products, general cargo (steel pipes, ingots, granite blocs, etc), minor bulks, containers and trailers and ro/ro operations

Handles approximately 8 Mtpa

Manuport Purchased in July 2007

100% interest held

Operates in Antwerp, Ghent and Liege in Belgium, Le Havre (France) and Varna (Bulgaria)

Provides the largest covered storage facility for specialty bulk products in Northern Europe (over 1 million tonnes capacity) and is the leading speciality bulk port operator in Antwerp, which in turn is the leading speciality bulk port in Europe

Principal cargoes include sugar, fertiliser and industrial minerals

Operates 2 barge container terminals in Antwerp handling over 150,000 TEU39 per annum

Manuport’s Liege operations represent the third largest inland port operations in Europe

Owns a wide ranging logistics business in Belgium, France and Germany which help capture cargo and extend the hinterland of its Antwerp based operations

Handles over 15 Mtpa

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Euroports – Operations Country Operations

Belgium Purchased in euSouSource: BBI Euroports also has a rapidly growing network of logistics businesses supporting its port activities. The logistics arm provides port and terminal customers with essential value-added services such as barging (container, dry bulk and liquid bulk), trucking, warehousing, freight forwarding, customs, chartering of vessels, ships agency, and bagging, palletizing, screening, blending, etc thereby helping to tie volumes to the various ports and extend the overall hinterland of each port. The Euroports portfolio was acquired and developed pursuant to a strategy to develop a pan-European, multi-product ports business with a diverse base, thereby balancing growth and risk in terms of location, customer exposure and product stream exposure. During the acquisition and development phase, BBI recognised that there would be a period of immaturity characterised by high gearing at the individual business level, coupled with a series of joint ventures. The intention was eventually to buy out the joint venture parties (thereby moving to 100% ownership of the individual businesses) while at the same time refinancing the debt within the portfolio into a single debt package across all the assets at long term sustainable gearing. In July 2009, BBI announced that it has closed a transaction pursuant to which a consortium of investors comprising Antin and Arcus (formally known as the Babcock & Brown European Infrastructure Fund) agreed to acquire a 34% interest in Euroports. In addition, Antin will hold a convertible bond in Euroports, which if converted, would convert to a further 5.97% of the equity of Euroports. Further, as part of the transaction:

40 TEUs, meaning ‘twenty-foot equivalent units’, are the measure used for capacity in container transportation.

Water container transport NV (WCT)

Purchased in July 2006

100% interest held

Second largest barge container terminal in Europe, based terminal in Meerhout (Belgium). The terminal is tri-modal with direct rail and barge connections into Europe

Handles over 240,000 TEU40 per annum

Tarragona Port Services (TPS)

Purchased in March 2007

100% interest held

Located in Tarragona (Spain)

Operates the deepest and largest coal terminal in the Mediterranean

Products handled include coal, clinker, animal feed, cereals, steel and minerals

Increasing presence in forest products and general cargo sector

Handles approximately 6 Mtpa

Terminal Rinfuse Italia (TRI)

Purchased in August 2007

80% interest held

Operates three terminals located in northern Italy – Genoa, Venice and Savona (Vado)

Operates from 60 hectares of port concession land

Handles approximately 7.5 Mtpa, principally dry bulks (coal, clinker, grain and animal feed)

Long term contracts with energy producers and conveyors directly feeding existing power stations from the port

Also handles a variety of steel and ro/ro ferries

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the shareholders have agreed to further capitalise the company;

a significant capital reserve at Euroports level was created to meet any future Euroports liabilities/ obligations in the short to medium term; and

there will be a share equalisation process in 2012 and 2013 based on the performance of Euroports through to that time. Depending on the performance of Euroports, the new shareholders could move from a potential initial holding of 40% (assuming the Antin IP convertible bond is converted) to an amended holding of between 34% and 65%.

The agreed price under the transaction for 40% of the equity in Euroports (on a fully diluted basis with the Antin convertible bond converted) is €141.5 million (equating to a 100% post investment equity value for the Euroports business of €353 million). As part of the revised transaction, Euroports has:

moved to 100% ownership of a number of its key joint venture assets, being the holding companies of its Manuport, Westerlund, TPS, and WCT assets;

completed debt refinancings associated with its TPS, WCT and Finnish Ports assets; and

settled residual liabilities with the holding company of the Westerlund and Magemon assets.

PD Ports BBI purchased PD Ports in January 2006 for approximately $1.4 billion. PD Ports is a diversified port services group operating in the United Kingdom. PD Ports owns and operates (and is the statutory harbour authority for) the Port of Tees and Hartlepool (“Teesport”), the third largest ports business in the United Kingdom (by volume), and also operates a number of other ports and logistics businesses elsewhere in the United Kingdom. PD Ports’ asset base also includes a large portfolio of freehold property at its ports (of over 2,285 acres), which generates a regular rental income. An overview of PD Ports’ principle operations is set out below:

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PD Ports – Operations Operation Description Port of Tees and Hartlepool

Located in the North East of England on the River Tees and at Hartlepool

PD Ports is the Statutory Harbour Authority for Tees and Hartlepool port and is responsible for 11 nautical miles of the River Tees

The Teesport estate is rail-connected and close to major arterials and trunk roads

Tees Dock is the principal facility at Teesport – a deep water facility offering access to four general cargo berths, three ro/ro berths and two lo/lo terminals. In addition there are numerous third party operators operating at Teesport

Handles approximately 40 Mtpa. PD Ports operates a wide range of facilities including ro/ro, bulk handling, cars, steel, forest imports and also offers cargo handling facilities from two container terminals at Teesport

Hull

Operated by PD Ports since 1990

Leased container terminal with approximately five years to expiry (with an option to extend for a further two years)

Capacity of 300,000 TEU per annum with 1,300 available ground spaces

Immingham

Located on the south bank of the Humber Estuary and operated by PD Ports under a stevedoring licence

300,000 square feet of warehousing (freehold) which offers stevedoring and general handling services at the port

Cowes Located on the River Medina on the Isle of Wight

Only commercial port facility on Isle of Wight

Offers two berths capable of handling vessels up to 3,000 DWT41 each

Specialises in the handling of dry bulk cargoes

Keadby Short sea port on the River Trent

Site operated under two long term leases expiring in 2035

From its single berth, provides specialist cargo handling services for a wide range of commodities including coal, aggregates, steel, paper and timber

Capable of handling vessels up to 3,000 DWT41

Howden Short sea port located on the River Ouse

Offers four berths, over 194,000 square feet of undercover warehousing and can accommodate vessels up to 3,000 DWT41

Handles a variety of cargoes of smaller sizes, including agricultural products, fertilisers and timber products from short sea mainland European and Baltic locations

PD Ports’ logistics arm offers supply chain services, including warehousing, distribution and logistics, to a variety of customers from bases in Felixstowe, Scunthorpe, Teesport and Billingham. PD Ports’ main revenues comprise income from port operations, conservancy (which are toll-like dues for ships using Teesport), pilotage, tug services and long term property leases. The PD Ports business is unregulated. Given its Statutory Harbour Authority status for the Tees, it has a statutory right to collect conservancy for all vessels using the Tees. It also has an obligation to provide a number of services including operating the harbour office to manage traffic and provide safe navigation, maintaining waterways to allocated depths (dredging) and providing environmental management to the river.

41 Deadweight tonnage, which refers to a ship’s carrying capacity.

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PD Ports has a range of long term contracts with strong, established counterparties. Energy, steel and chemical companies have traditionally been its major customers, most of which have major infrastructure facilities constructed on the banks of the Tees. The business is however in the process of transitioning its business focus across to retail customers, which have smaller volume, higher value requirements. This should provide a better balance of industry exposure. In recent times PD Ports has experienced overall volume declines on the back of a very weak United Kingdom economic climate. PD Ports’ major customer, Corus (Europe’s second largest steel producer), announced in May 2009 that it was considering shutting production down at its Redcar Teesside steel facility as a result of the economic situation. Following the announcement, PD Ports undertook a significant review of its cost base and expects to partially mitigate any effect of a Corus’ closure (if it was to occur) through a reduction in costs. For the financial year ending 30 June 2009, Corus accounted for approximately 25% of PD Ports earnings across all its sectors, however not all of this is associated with the Redcar steel facility. Recognising potential weakness in its exposure to the steel and bulk liquids sector, PD Ports recently embarked on a strategy which pioneered a concept to focus on attracting port centric distribution centre developments to Teesport, with the ultimate objective of expanding significantly unitised cargo traffic moving through Teesport. The concept aims to avoid the transport and distribution inefficiencies inherent in using traditional southern entry and distribution routes in the United Kingdom, thereby positioning Teesport as a northern gateway entry point for unitised cargo servicing the consumer base of the north of the United Kingdom. To date PD Ports has successfully attracted two major retailers, ASDA and Tesco, and expects to secure further clients as Teesport gains critical mass as a major import facility. This is resulting in a significant growth in container traffic through Teesport providing balance against recent North Sea oil volume decline and the potential for Corus’ Redcar steel facility to shut down.

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6 Valuation of BBI

6.1 Valuation Summary

The equity in BBI has been valued in the range $668-1,242 million. The valuation represents the full underlying value of BBI assuming that 100% of the company was available to be acquired and includes a premium for control. The estimated underlying value exceeds the value that Grant Samuel expects would be attributed to BBI by market trading, in terms of share market prices for BBI Securities, EPS and SPARCS, based on current market conditions and in the absence of the Recapitalisation:

BBI - Valuation Summary ($ millions) Value Range

Asset Section Reference Low High

AET&D 6.3 48 148 Other transmission and distribution assets 6.4 1,116 1,310 Transport assets 6.5 916 1,146

Value of equity in business operations 2,080 2,604 Capitalised value of corporate costs 6.6 (150) (100) Corporate net borrowings at 31 August 2009 6.7 (1,165) (1,165) Other liabilities 6.8 (97) (97) Value of BBI equity 668 1,242

Grant Samuel has valued BBI by valuing each of its assets and investments, deducting corporate net debt and the mark to market value of hedge instruments at a corporate level, and adjusting for the capitalised value of corporate costs. Where appropriate, the values attributed to individual assets and investments take into account debt and hedge instruments held at the asset level. The values attributed to individual assets and investments represent overall judgements having regard to a number of valuation methodologies and parameters, including capitalisation of earnings (multiples of EBITDA), discounted cash flow and, where available, recent transactions or the results of various asset sales processes conducted by BBI over the last 12 months. Where relevant, multiples of regulated asset base (“RAB”) have also been considered. The value ranges selected are judgements derived through an iterative process. The objective is to determine a value that is consistent both with recent transactions and the market evidence as to multiples and with the output of the discounted cash flow analysis, having regard to a range of valuation scenarios and the risks associated with their achievement. It should be understood that valuation of BBI is problematic. BBI’s extreme gearing means that there is a significant “margin for error” in the valuation. Given total debt within BBI of approximately $9.2 billion (including BBI’s share of off-balance sheet non-recourse debt, which is not shown in the table above), the valuation implies a total enterprise value of approximately $9.9-10.5 billion. Valuations are inherently imprecise. A relatively small shift in estimated enterprise value could result in the estimated value of BBI’s net assets falling to zero. A significant proportion of BBI’s value is contributed by assets held outside Australia. Grant Samuel has valued these assets on a local currency basis and translated the estimated values into Australian dollar equivalents using spot exchange rates. Movements in exchange rates could have a significant impact on the estimated underlying value of BBI. Moreover, there have been few recent transactions involving assets similar to those of BBI. BBI’s experience based on its recent asset divestment program has been that there have been very few parties interested in asset acquisitions, and pricing has been at levels well below historical pricing. While some of this may have reflected BBI’s status as a distressed seller, it is almost certainly the case that values of infrastructure assets have declined substantially, given that there are no longer the volumes of debt available to support highly geared acquisitions.

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However, in the absence of significant numbers of transactions to provide evidence as to current market values, the extent of this decline is not clear. In this context valuations are subjective. The valuation reflects estimates of the value that could be realised for the assets of BBI on the basis of an orderly realisation. The reality is that such values could almost certainly not be realised by BBI in the short term, given its current financial position and a market perception that it is a forced seller. In the case of some of its assets, high levels of debt at an asset level also mean that it would be difficult to realise full underlying value. In the event that BBI was forced to realise its assets in an accelerated time frame (for example, as part of a formal or informal insolvency process), it is possible that the values actually realised could be materially lower than those estimated above.

6.2 Methodology

6.2.1 Overview

Grant Samuel’s valuation of BBI has been estimated by aggregating the estimated market value of its assets and investments and deducting external borrowings and non-trading liabilities as at 31 August 2009. The value of the assets and investments has been estimated on the basis of fair market value as a going concern, defined as the maximum price that could be realised in an open market over a reasonable period of time assuming that potential buyers have full information. The most reliable evidence as to the value of an asset is the price at which the asset or a comparable asset has been bought and sold in an arm’s length transaction. In the absence of direct market evidence of value, estimates of value are made using methodologies that infer value from other available evidence. There are four primary valuation methodologies that are commonly used for valuing businesses:

capitalisation of earnings or cash flows;

discounting of projected cash flows;

industry rules of thumb; and

estimation of the aggregate proceeds from an orderly realisation of assets. Each of these valuation methodologies has application in different circumstances. The primary criterion for determining which methodology is appropriate is the actual practice adopted by purchasers of the type of asset involved. Nevertheless, valuations are generally based on either or both discounted cash flow or multiples of earnings and Grant Samuel has had regard to both methodologies in the valuation of BBI. In addition, for the Australian regulated transmission and distribution assets and DBCT, some weight has also been given to the implied multiples of RAB, which is the value of the fixed assets set by the relevant regulator as the basis for determining tariffs.

6.2.2 Discounted Cash Flow

Discounting of projected cash flows has a strong theoretical basis. It is the most commonly used method for valuation in a number of industries, including resources, and for the valuation of start-up projects where earnings during the first few years can be negative but it is also widely used in the valuation of established industrial businesses. Discounted cash flow valuations involve calculating the net present value of projected cash flows. This methodology is able to explicitly capture depleting resources, development projects and fixed terms contracts (which are typical in the resources sector), the effect of a turnaround in the business, the ramp up to maturity or significant changes

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expected in capital expenditure patterns. The cash flows are discounted using a discount rate which reflects the risk associated with the cash flow stream. Considerable judgement is required in estimating future cash flows and it is generally necessary to place great reliance on medium to long term projections prepared by management. The discount rate is also not an observable number and must be inferred from other data (usually only historical). None of this data is particularly reliable so estimates of the discount rate necessarily involve a substantial element of judgement. In addition, even where cash flow forecasts are available, the terminal or continuing value is usually a high proportion of value. Accordingly, the multiple used in assessing this terminal value becomes the critical determinant in the valuation (i.e. it is a “de facto” cash flow capitalisation valuation). The net present value is typically extremely sensitive to relatively small changes in underlying assumptions, few of which are capable of being predicted with accuracy, particularly beyond the first two or three years. The arbitrary assumptions that need to be made and the width of any value range mean the results are often not meaningful or reliable. Notwithstanding these limitations, discounted cash flow valuations are commonly used and can at least play a role in providing a check on alternative methodologies, not least because explicit and relatively detailed assumptions as to expected future performance need to be made. DCF models for some of the assets and investments have been developed by Grant Samuel from long term financial models prepared by BBI. These models allowed the key drivers of revenues, costs and capital expenditure to be modelled. Grant Samuel has made adjustments to the financial models to reflect its judgement on certain matters. The models are based on a large number of assumptions and are subject to significant uncertainty and contingencies, many of which are outside the control of BBI. Where relevant, a number of different scenarios have been developed and analysed to reflect the impact on value of various key assumptions relating to pricing, capital expenditure and other factors. The models incorporate assumptions about future events for time periods in the longer term. As with any long term projections, there are inherent uncertainties about future events and outcomes. Small changes in certain assumptions can have disproportionate impacts on the calculated values. Accordingly, Grant Samuel has undertaken an analysis of the sensitivity of calculated net present values to movements in key assumptions. However, it should be noted that the sensitivities examined do not, and do not purport to, represent the range of potential value outcomes for the relevant assets. They are simply theoretical indicators of the sensitivity of the net present values derived from the DCF analysis. The financial models are discussed in more detail in the following sections of this report. Appendix 1 sets out a detailed analysis of the selection of the discount rates assumed in the DCF analysis. The key general and specific operational and asset assumptions underlying the DCF models are set out in Appendix 2.

6.2.3 Capitalisation of Earnings or Cash Flows

Capitalisation of earnings or cash flows is the most commonly used method for valuation of industrial businesses. This methodology is most appropriate for industrial businesses with a substantial operating history and a consistent earnings trend that is sufficiently stable to be indicative of ongoing earnings potential. This methodology is not particularly suitable for start-up businesses, businesses with an erratic earnings pattern or businesses that have unusual capital expenditure requirements. This methodology involves capitalising the earnings or cash flows of a business at a multiple that reflects the risks of the business and the stream of income that it generates. These multiples can be applied to a number of different earnings or cash flow measures including EBITDA, EBIT or net profit after tax. These are referred to respectively as EBITDA multiples, EBIT multiples and price earnings multiples. Price earnings multiples are commonly used in the context of the sharemarket. EBITDA and EBIT multiples are more commonly used in valuing

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whole businesses for acquisition purposes where gearing is in the control of the acquirer but are also used extensively in sharemarket analysis. Where an ongoing business with relatively stable and predictable cash flows is being valued, Grant Samuel uses capitalised earnings or operating cash flows as a primary reference point. Application of this valuation methodology involves:

estimation of earnings or cash flow levels that a purchaser would utilise for valuation purposes having regard to historical and forecast operating results, non-recurring items of income and expenditure and known factors likely to impact on operating performance; and

consideration of an appropriate capitalisation multiple having regard to the market rating of comparable businesses, the extent and nature of competition, the time period of earnings used, the quality of earnings, growth prospects and relative business risk.

The choice between parameters is usually not critical and should give a similar result. All are commonly used in the valuation of industrial businesses. EBITDA can be preferable to EBIT if depreciation or non-cash charges distort earnings or make comparisons between companies difficult. On the other hand, EBIT can better adjust for differences in relative capital expenditure intensity. Determination of the appropriate earnings multiple is usually the most judgemental element of a valuation. Definitive or even indicative offers for a particular asset or business can provide the most reliable support for selection of an appropriate earnings multiple. In the absence of meaningful offers it is necessary to infer the appropriate multiple from other evidence. The usual approach used by valuers is to determine the multiple that other buyers have been prepared to pay for similar businesses in the recent past. A pattern may emerge from transactions involving similar businesses with sales typically taking place at prices corresponding to earnings multiples within a particular range. This range will generally reflect the growth prospects and risks of those businesses. Mature, low growth businesses will, in the absence of other factors, attract lower multiples than those businesses with potential for significant growth in earnings. An alternative approach in valuing businesses is to review the multiples at which shares in listed companies in the same industry sector trade on the sharemarket. This gives an indication of the price levels at which portfolio investors are prepared to invest in these businesses. However, share prices reflect trades in small parcels of shares (portfolio interests) rather than whole companies and it is necessary to adjust for this factor. In interpreting and evaluating such data it is necessary to recognise that:

multiples based on listed company share prices do not include a premium for control and are therefore often (but not always) less than multiples that would apply to acquisitions of similar companies. However, while the premium paid to obtain control in takeovers is observable (typically in the range 20-35%) it is inappropriate to simply add a premium to listed multiples. The premium for control is an outcome of the valuation process, not a determinant of value. Premiums are paid for reasons that vary from case to case and may be substantial due to synergy or other benefits available to the acquirer. In other situations premiums may be minimal or even zero. There are transactions where no corporate buyer is prepared to pay a price in excess of the prices paid by sharemarket investors;

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acquisition multiples from comparable transactions are therefore usually seen as a better guide when valuing 100% of a business but the data tends to be less transparent and information on forecast earnings is often unavailable;

the analysis will give a range of outcomes from which averages or medians can be determined but it is not appropriate to simply apply such measures to the company being valued. The most important part of valuation is to evaluate the attributes of the specific company being valued and to distinguish it from its peers so as to form a judgement as to where on the spectrum it appropriately belongs;

acquisition multiples are a product of the economic and other circumstances at the time of the transaction. However, each transaction will be the product of a unique combination of factors, including:

• economic factors (e.g. economic growth, inflation, interest rates) affecting the markets in which the company operates;

• strategic attractions of the business - its particular strengths and weaknesses, market position of the business, strength of competition and barriers to entry;

• the company’s own performance and growth trajectory;

• rationalisation or synergy benefits available to the acquirer;

• the structural and regulatory framework;

• investment and sharemarket conditions at the time; and

• the number of competing buyers for a business;

acquisitions and listed companies in different countries can be analysed for comparative purposes, but it is necessary to give consideration to differences in overall sharemarket levels and ratings between countries, economic factors (economic growth, inflation, interest rates) and market structures (competition etc) and the regulatory framework. It is not appropriate to adjust multiples in a mechanistic way for differences in interest rates or sharemarket levels;

acquisition multiples are based on the target’s earnings but the price paid normally reflects the fact that there were synergies available to the acquirer (at least if the acquirer is a “trade buyer” with existing businesses in the same or a related industry). If the target’s earnings were adjusted for these synergies, the effective multiple paid by the acquirer would be lower than that calculated on the target’s earnings; and

while EBITDA multiples are commonly used benchmarks they are an incomplete measure of cash flow. The appropriate multiple is affected by, among other things, the level of capital expenditure (and working capital investment) relative to EBITDA. In this respect:

• EBIT multiples can in some circumstances be a better guide because (assuming depreciation is a reasonable proxy for capital expenditure) they effectively adjust for relative capital intensity and present a better approximation of free cash flow. However, capital expenditure is lumpy and depreciation expense may not be a reliable guide. In addition, there can be differences between companies in the basis of calculation of depreciation; and

• businesses that generate higher EBITDA margins than their peer group companies will, all other things being equal, warrant higher EBITDA multiples because free cash flow will, in relative terms, be higher (as capital expenditure is a smaller proportion of earnings).

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The analysis of comparable transactions and sharemarket prices for comparable companies will not always lead to an obvious conclusion as to which multiple or range of multiples will apply. There will often be a wide spread of multiples and the application of judgement becomes critical. Moreover, it is necessary to consider the particular attributes of the business being valued and decide whether it warrants a higher or lower multiple than the comparable companies. This assessment is essentially a judgement. In determining values for BBI’s assets and investments, Grant Samuel has placed particular reliance on the EBITDA multiples implied by the valuation range compared to the EBITDA multiples derived form an analysis of comparable listed companies and transactions involving comparable businesses.

6.2.4 Industry Rules of Thumb

Industry rules of thumb are commonly used in some industries. These are generally used as a “cross check” of the result determined by a capitalised earnings valuation or by discounting cash flows. While they are only used as a cross check in most cases, industry rules of thumb can be the primary basis on which buyers determine prices in some industries. In the case of regulated infrastructure businesses in Australia a common rule of thumb is the multiple of RAB which is the value of the fixed assets set by the relevant regulator as the basis for determining tariffs. In any event, it should be recognised that rules of thumb are usually relatively crude and prone to misinterpretation.

6.2.5 Net Assets/Realisation of Assets

Valuations based on an estimate of the aggregate proceeds from an orderly realisation of assets are commonly applied to businesses that are not going concerns. They effectively reflect liquidation values and typically attribute no value to any goodwill associated with ongoing trading. Such an approach is not appropriate in BBI’s case.

6.3 Valuation of AET&D

6.3.1 Overview

Grant Samuel has valued the equity in AET&D in the range $48-148 million:

AET&D - Valuation Summary ($ millions) Value Range

Asset Section Reference Low High

WA Gas Networks (74.1%) 6.3.3 670.0 700.0 Tasmanian Gas Pipeline 6.3.4 225.0 235.0 WestNet Energy 6.3.5 40.0 45.0 AET&D corporate costs 6.3.7 (100.0) (95.0)

Value of business operations 835.0 885.0 Investments42 6.3.6 180.0 215.0 Net borrowings 6.3.8 (946.2) (946.2) Other assets and liabilities 6.3.9 (20.4) (5.4) Value of equity in AET&D 48.4 148.4

In determining these values, Grant Samuel had regard to multiples of EBITDA, multiples of RAB (as appropriate) and DCF analysis.

42 Investments represent AET&D’s interests in the Dampier to Bunbury Natural Gas Pipeline and Multinet.

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6.3.2 Market Valuation Parameters

The most common valuation metric for energy infrastructure businesses, other than distribution yield, is EBITDA multiples (rather than EBIT). In more recent years, the multiples paid for energy infrastructure assets either in the public listed market or in private treaty acquisitions have been relatively high, particularly having regard to the modest growth profile of these businesses. The majority of the assets are regulated and long run growth is generally limited to population growth and inflation (with potential for increased utilisation or penetration in some assets). However, cash flows of the assets are very stable and predictable and therefore the entities are able to use high degrees of leverage to produce attractive returns to equity investors. Coupled with tax efficient structures, this combination results in relatively high EBITDA multiples for listed companies which is also reflected in acquisitions (see below). In addition, infrastructure assets are reasonably transparent, with a considerable level of publicly available information on revenues, volumes, operating costs and capital investment. Moreover, the assets are “ring fenced” with little opportunity for integration with other assets (particularly in revenue terms). There are some operating cost synergies available for acquirers but, in the long term, these will be shared with the infrastructure customers. In this respect, it is Grant Samuel’s view that listed infrastructure assets trade on the ASX at close to their full underlying value. Accordingly, there is unlikely to be a material premium for control of the extent often seen in takeover transactions. This is broadly confirmed by historical transaction evidence, although, since 2004 there has been a greater propensity to pay premiums above listed company multiples (possibly due to the increased market interest in this investment class). There has been limited transaction evidence in the last two years (and none in Australia). On the basis of the view set out above, it could be argued that as trading multiples are lower today than they were at the time of the most recent transaction evidence, then transaction multiples should also be lower. However, the sale by BBI of a 58% interest in Powerco completed in February 2009 occurred at the same forecast EBITDA multiple as the acquisition of Powerco by BBI in August 2004 (i.e. a forecast EBITDA multiple of around 9.0 times). This implies that transaction multiples have held up in current market conditions, at least in New Zealand (although transaction multiples in New Zealand did not increase in the period post 2005 as they did in Australia so a conservative approach may still be justified in relation to Australian transactions). The market valuation parameters relevant for an assessment of BBI’s Australian and New Zealand transmission and distribution assets are summarised below. Current Market Conditions Grant Samuel has placed more emphasis on earnings multiple analysis and RAB multiples than it has on DCF analysis in forming its views on value. Grant Samuel considers this to be appropriate in current market conditions where there is anecdotal evidence that providers of equity capital are seeking higher returns than those generated using theoretical models such as CAPM and, consequently, acquirers of assets will pay less for assets than the outcomes of DCF analysis would suggest. As a result, Grant Samuel’s assessments of value are at the low end, or below the low end of the DCF analyses undertaken. However, the valuation ranges are supported by earnings multiple analysis (particularly, in the absence of recent transactions, the current trading multiples of comparable companies) and RAB multiples, which Grant Samuel considers to be a more reliable indicator of value in current market conditions.

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Sharemarket Evidence The following table sets out the implied EBITDA multiples for a range of listed energy infrastructure entities based on share prices as at 29 September 2009:

Sharemarket Ratings of Selected Listed Energy Infrastructure Entities EBITDA Multiple44 (times)

Entity Type43 Market

Capitalisation($ millions) Historical Forecast

Year 1 Forecast Year 2

Transmission Infrastructure

APA G/E 1,591 10.7 10.6 10.0 HDUF E/G/W/H 479 10.1 7.4 7.2

Distribution Infrastructure SP AusNet E/G 2,303 9.4 8.5 7.9 Vector E/G NZ$1,882 7.8 7.8 7.4 DUET E/G 1,439 9.8 8.9 8.5 Spark E 1,165 10.5 9.7 9.6 Envestra G 765 10.4 10.4 10.2

Source: Grant Samuel analysis (see Appendix 3) A detailed analysis of these entities is set out in Appendix 3. The following factors are relevant to consideration of these multiples:

the multiples for the listed entities are based on share prices and therefore do not include a premium for control;

the selected entities generally exhibit characteristics and value drivers similar to BBI’s Australian and New Zealand transmission and distribution assets. The least comparable entity is HDUF (with a substantial interest in a regulated United Kingdom water asset in addition to Epic, an Australian gas transmission business). Vector (a New Zealand company with non energy activities), is relevant to BBI’s interest in Powerco rather than its Australian assets. In relation to the remaining entities the following should be noted:

• APA owns over 12,000 kilometres of gas transmission pipelines in Australia as well as electricity transmission assets and a gas distribution network;

• SP AusNet owns electricity and gas distribution assets in Victoria as well as electricity transmission in Victoria;

• DUET owns majority interests in gas distribution in Victoria (Multinet Gas), gas transmission in Western Australia (the Dampier to Bunbury Natural Gas Pipeline) and electricity distribution in Victoria and a minority interest in gas distribution in Western Australia (WA Gas Networks). It also owns a minority interest in a United States electricity distribution and transmission company;

• Spark owns 49% interests in electricity distribution networks in Victoria and South Australia. The calculation of underlying multiples for Spark is complex because of the minority holdings and form of investment. Caution should be applied in relying on them; and

43 E = Electricity; G = Gas; W = Wind; H = Water 44 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at

the latest balance date) divided by EBITDA.

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• Envestra owns over 19,000 kilometres of gas distribution networks throughout Australia and over 1,000 kilometres of gas transmission pipelines. APA owns 30.6% of Envestra and its share price has rallied in the last month on the back of speculation that APA would make an offer for Envestra. Its trading multiples have been impacted by this speculation. Based on its share price a month ago, Envestra was trading at a forecast EBITDA multiple of 9.8 times;

the three listed distribution infrastructure entities that are predominantly electricity distributors trade at forecast EBITDA multiples of 8.5-9.7 times. EBITDA multiples are influenced by capital expenditure requirements (relative to EBITDA). Electricity distributors are generally capital intensive and, accordingly, their EBITDA multiples are lower than, say, those of predominantly gas transmission pipelines (such as APA) and gas distributors (such as Envestra). Equally, albeit to a lesser extent, gas distribution is relatively more capital intensive than gas transmission and this is reflected in APA’s higher EBITDA multiples (10.6 times forecast EBITDA compared to 10.4 times (or 9.8 times prior to takeover speculation) forecast EBITDA for Envestra;

HDUF’s multiples are considerably lower than those of other comparable companies, possibly because of the requirement to find more funding for a substantial expansion of the Epic pipeline and because of the release of an unfavourable draft determination for pricing for the United Kingdom water sector from April 2010;

a number of the entities (APA, Vector and Envestra) are trading at flat forecast Year 1 EBITDA multiples reflecting the mature markets in which these entities operate and the impact of current soft economic conditions on earning growth;

most of the listed entities are passive in nature with external parties (often related) providing infrastructure, operation and management services to the entity (although APA has been growing its internal management capabilities). A number of the entities are also administratively managed by external parties; and

the implied multiples for BBI’s Australian and New Zealand assets have been calculated on 30 June year end earnings. With the exception of HDUF and Spark (which have a 31 December year end) and SP AusNet (which has a 31 March year end) each of the comparable entities has a 30 June year end. The forecast Year 1 multiples for these entities are based on forecasts for the year ending 30 June 2010 and Year 2 multiples are based on forecast for the year ending 30 June 2011. HDUF’s and Spark’s forecasts are for the years ending 31 December 2009 and 2010, respectively and SP AusNet’s forecasts are for the years ending 31 March 2010 and 2011, respectively. The peer group forecasts have not been realigned to a June year end basis because of a lack of reliable half year forecasts. However, in general terms, it would make relatively little difference (approximately 0.2 downward adjustment to the multiple for SP AusNet, and minimal for the others).

RAB Multiples45 A common rule of thumb parameter used in the valuation of energy infrastructure businesses is RAB multiples. The RAB (or regulated asset base) is determined by the relevant regulator using concepts such as depreciated optimised replacement cost to determine an appropriate investment value for the asset (for its current and forecast workload). This investment base is then combined with a determination of the

45 Represents enterprise value (i.e. business value before debt) divided by RAB. RAB means regulated asset base and is the value of

the fixed assets set by the relevant regulator as the basis for determining tariffs.

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appropriate return on capital (usually a weighted average cost of capital) to develop a tariff structure designed to deliver that return over the regulatory period. Theoretically, listed infrastructure entities should trade at, and assets should be acquired at, 1.0 times RAB. However, that does not occur and, in fact, most assets generally trade at a premium to RAB. The precise reasons for this are uncertain but contributing factors probably include:

expectations of volume growth above the levels used by regulators (at least until the next regulatory reset);

expectations of savings relative to the level of operating and capital costs assumed by regulators;

a cost of capital less than that assumed by regulators. Reasons for this might include:

• benefits from tax efficient structuring;

• the benefits of diversification. Most of the listed entities own a number of different assets which dilutes the exposure to any one asset in terms of operating and regulatory risks. Regulators only calculate the cost of capital for individual assets rather than a portfolio of assets (although theoretically there should be no difference); and

• use of higher levels of gearing than regulators assume (of around 60%). There is some evidence that the energy infrastructure sector has been utilising higher debt levels than previously (exacerbated by the fall in equity values over the last two years). The analysis in Appendix 1 indicates that the majority of entities have current gearing levels well over 60%;

the valuable growth options that may be available to the listed entity (e.g. potential acquisitions) and reflected in its market capitalisation; and

profit streams from other businesses (although these should be backed out in any analysis).

Summarised below are RAB multiples for those Australian listed entities which have a relatively high proportion of regulated revenue and for which meaningful RAB multiples can be calculated from publicly available information:

Selected Listed Entities – RAB Multiples46 Average RAB as at 30 June

Entity Type 2009 2010

SP AusNet E/G 1.50 1.40 Spark E 1.81 1.73 DUET E/G 1.21 1.15 Envestra G 1.28 1.21

Source: Grant Samuel analysis Some caution is necessary in relying on this data as it is difficult to isolate the full effects of other activities and to determine what adjustments may be necessary. In particular, the calculation of RAB multiples for Spark are subject to considerable uncertainty.

46 Based on share prices at 29 September 2009 and average nominal RAB for relevant year. RAB is based on the respective regulatory

determinations except for DUET which allows for the $908 million expenditure on the Stage 5A and 5B expansion of the Dampier to Bunbury Natural Gas Pipeline.

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The RAB multiples implied by recent acquisitions of regulated energy infrastructure assets in Australia are set out below. This data should also be treated with caution:

Selected Acquisitions – RAB Multiples

Date Acquirer Entity/Asset Acquired RAB

Multiple47

(times) Dec 06 APA DirectLink 1.45 Oct 06 APA Allgas 1.64 Aug 06 APA GasNet 2.1948 Apr 06 Alinta AGL Infrastructure assets 1.41-1.5249

Mar 06 APA Murraylink 1.47 Aug 04 DUET/Alinta/Alcoa Dampier to Bunbury Natural Gas Pipeline 1.20 Aug 04 APA Southern Cross Pipeline and Parmelia Gas 1.47 Apr 03 Alinta/AMP/Aquila AlintaGas Networks 1.35 Apr 03 Alinta/AMP/Aquila Multinet Gas 1.44 Apr 03 Alinta/AMP/Aquila United Energy 1.52 Aug 02 CKI/HEH Citipower 1.69 Oct 00 Consortium ElectraNet 1.37 Sep 00 CKI/HEH Powercor 1.71 Jun 00 Singapore Power PowerNet 1.49 Dec 99 CKI/HEH ETSA Utilities 1.26 Jul 99 CKI 19.97% of Envestra 1.49 Jun 99 GPU GasNet 1.72 Mar 99 Envestra/Boral Stratus Networks 1.99 Jan 99 Texas Utilities Westar 1.86

Source: Grant Samuel analysis The transactions show a diversity of RAB multiples and demonstrate a downward trend from the peak levels of 1.5-2.0 times during the restructuring of the Victorian electricity industry in 1999 (although recent transactions have generally been at RAB multiples in excess of 1.4 times). In any event, the evidence is supportive of RAB multiples of at least 1.3 times. Transaction Evidence The table below sets out the EBITDA multiples implied by selected transactions involving the acquisition of energy transmission and distribution infrastructure assets in Australia and New Zealand since 2002:

47 Calculated by reference to total price announced (i.e. no adjustment has been made for any unregulated assets or other activities). 48 RAB multiple is 1.64 times if adjusted for unregulated assets which are assumed to represent approximately 25% of total enterprise

value. 49 Based on valuation attributed to gas and electricity networks by independent expert in its report dated 28 August 2006.

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Recent Transaction Evidence EBITDA Multiple51

(times) Date Target Transaction Consid- eration50 (millions) Historical Forecast

Electricity – Australia Dec 06 DirectLink Acquisition by APA $170 na52 15.3 Mar 06 Murraylink Acquisition by APA $153 na 15.8 Dec 05 SP AusNet IPO $2,888 13.3 13.1 Nov 05 Spark IPO $2,017 9.9 10.7 Apr 04 TXU Australia Acquisition by

Singapore Power $5,100 9.2 8.6

Jul 03 United Energy Scheme with Alinta $1,340 8.1 7.5

Gas – Australia Apr 07 Envestra Acquisition of 17.2% by

APA $990 12.7 13.1

Apr 07 SEA Gas Pipeline Acquisition of 33.3% by APA

$400 na 14.5

Nov 06 AIH Acquisition by Alinta $956 14.3 14.5 Oct 06 Allgas Acquisition by APA $521 na 18.1 Aug 06 GasNet Takeover by APA $452 13.9 13.3 Apr 06 AGL Infrastructure Acquisition by Alinta $6,500 13.0 12.6 Sep 05 AIH IPO $926 17.4 14.2 Feb 05 Carpentaria Gas Pipeline Acquisition of 30% by APA $327 na na Aug 04 Dampier to Bunbury

Natural Gas Pipeline Acquisition by DUET/Alinta/Alcoa

$1,860 na 11.1

Aug 04 45% of Southern Cross Pipelines/100% of Parmelia Gas

Acquisition by APA $206 8.3 na

Mar 04 Duke Energy Australian and New Zealand assets

Acquisition by Alinta $1,690 17.0 15.5

Electricity – New Zealand Nov 08 Powerco Acquisition of 58% interest

by QIC NZ$726 9.1 9.1

Apr 08 Wellington Electricity Network

Acquisition by CKI NZ$785 na 9.8

Aug 04 Powerco Acquisition by BBI NZ$680 9.4 9.0 Sep 02 UnitedNetworks Acquisition by Vector NZ$1,500 8.7 8.4 Sep 02 UnitedNetworks’

electricity distribution networks

Acquisition by Powerco NZ$590 9.0 8.9

Gas – New Zealand Apr 07 Rockgas Acquisition by Contact

Energy NZ$156 8.0 7.8

Jun 05 NGC Holdings Acquisition of 32.8% interest by Vector

NZ$1,506 10.7 10.1

Oct 04 NGC Holdings Acquisition of 67.2% interest by Vector

NZ$866 9.6 9.2

Source: Grant Samuel analysis (see Appendix 4)

50 Implied equity value if 100% of the company or business had been acquired. 51 Represents gross consideration divided by EBITDA. 52 na = not available

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Further details on these transactions are set out in Appendix 4. The following factors are relevant to consideration of the transaction evidence:

since 2005 there has been an increase in the multiples paid for energy infrastructure assets in Australia, possibly due to the scarcity of assets available for acquisition. Furthermore, APA has been the most prominent and aggressive acquirer during the period. However, there have been no transactions in Australia in the last two years, post the global financial crisis;

transactions involving entities with both transmission and distribution assets (e.g. SP AusNet) or transmission and generation assets (e.g. Alinta Infrastructure Holdings Limited (“AIH”)) will have multiples that represent a blend of these two businesses;

the gas transactions involve predominantly transmission pipelines rather than distribution assets. The only transactions involving gas distribution assets are the acquisitions of Envestra, Allgas Energy Pty Limited (“Allgas”) and AGL Infrastructure. The Allgas transaction is at higher multiples than other recent gas transmission and distribution transactions, although this may reflect the fact that APA owned the transmission network that supplied the Allgas distribution network which may have resulted in synergies not usually available in infrastructure acquisitions;

while APA’s acquisition of a 17.2% interest in Envestra and a 33.3% interest in SEA Gas Pipeline are for minority interests, they are both strategic interests;

the IPOs of AIH, SP AusNet and Spark Infrastructure Group (“Spark”) reflect portfolio interests and therefore the implied multiples, theoretically, do not include a premium for control. The forecast EBITDA multiples for the AIH and SP AusNet listings are nevertheless relatively high. In comparison, the Spark listing multiples are low which could reflect its minority holdings in infrastructure assets and the complexity of its corporate structure; and

the multiples implied by transactions involving gas and electricity entities in New Zealand have not increased in recent years as they have in Australia, and have consistently been at around 8-10 times forecast EBITDA.

Interpretation Prior to 2005 transaction multiples for transmission and distribution assets were generally less than 10 times forecast EBITDA with little discernible difference between the type of asset or sector. More recently, Australian transaction multiples have risen as investor interest in the energy infrastructure asset class has increased. Moreover, recent market evidence indicates that some difference is emerging in the market pricing for the electricity and gas sectors and there is some evidence to indicate that pricing differs between transmission and distribution assets (possibly reflecting lower capital intensity for transmission assets compared to a distribution network). To this extent:

Australian electricity transmission and distribution assets trade at multiples of around 8.5-9.5 times forecast EBITDA and forecast RAB multiples in the range 1.2-1.7 times. Although recent transaction evidence in the electricity sector is limited, historically, transactions imply multiples in excess of 11 times forecast EBITDA and RAB multiples in the range 1.3-1.7 times;

Australian gas transmission and distribution entities trade at multiples of between 9.8 and 10.6 times forecast EBITDA and forecast RAB multiples in the range 1.2-1.4 times. Transaction evidence in the gas sector is reasonably extensive, particularly for transmission assets, although there have been no transactions in the last two years. Transmission assets have historically been acquired at multiples in

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the range 13.0-14.5 times forecast EBITDA and RAB multiples generally in the range 1.2-1.7 times. Distribution assets (on more limited evidence) have historically been acquired at slightly lower multiples in the range 12.5-13.0 times forecast EBITDA and RAB multiples generally in the range 1.4-1.6 times (i.e. there is no material difference in the RAB multiples for gas transmission and distribution acquisitions). The Allgas gas distribution network acquisition is a transaction outlier (at 18 times EBITDA) which may reflect APA’s willingness to pay higher prices to strategically redirect its asset base and business; and

New Zealand gas and electricity distribution entities trade at lower multiples (i.e. Vector trades at a forecast EBITDA multiple of 7.8 times) and transactions also occur at lower multiples (in the range 8-10 times forecast EBITDA).

Given the lack of recent transaction evidence in Australia, and the decline in trading multiples of comparable companies compared to multiples at the time of the most recent transaction evidence, in Grant Samuel’s view appropriate Australian transaction multiples in today’s market will be towards the low end and arguably, even lower, than the range of transaction multiples set out above.

6.3.3 WA Gas Networks

Summary Grant Samuel has estimated the value of BBI’s 74.1% interest in WA Gas Networks to be in the range $670-700 million. This value is based on a value for 100% of WA Gas Networks of $900-950 million. Grant Samuel has valued WA Gas Networks having regard to multiples of EBITDA and multiples of RAB and DCF analysis. Earnings Multiple Analysis The valuation of $900-950 million implies the following multiples:

WA Gas Networks – Implied EBITDA Multiples Value Range

Parameter ($ millions) Low High

Enterprise value range (100%) ($ millions) 900 950 Multiple of EBITDA Year ended 30 June 2009 (actual) 91.553 9.8 10.4 Year ending 30 June 2010 (forecast) 95.5 9.4 9.9 Year ending 30 June 2011 (forecast) 92.3 9.8 10.3 RAB Multiple Regulated asset base at 30 June 2009 (nominal) 754.1 1.19 1.26

Grant Samuel has reviewed these implied multiples having regard primarily to current trading EBITDA multiples for comparable listed entities and has also considered transactions involving energy infrastructure entities or assets in Australia (after taking into account the impact of current market conditions).

53 Note that EBITDA for the year ended 30 June 2009 was impacted by the gas explosion at the Varanus Island gas processing facility

on 3 June 2008 that cut Western Australia’s domestic gas supply by 30%. While partial gas production was restored on 6 August 2008, full capacity was not restored until June 2009.

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The implied multiples for WA Gas Networks are below the transaction multiples for gas distribution entities (at 12.5-13.0 times forecast EBITDA), although this reflects Grant Samuel’s view that appropriate transaction multiples have declined in current market conditions. The implied multiples for the year ending 30 June 2011 are considered to be more relevant as they reflect the higher cost base associated with the internalisation of asset management services from 1 July 2010. In Grant Samuel’s opinion implied forecast EBITDA multiples of 9.8-10.3 times are reasonable as:

the trading multiples of the most comparable listed company, Envestra, have been impacted by recent speculation of a takeover by its major shareholder, APA. Its forecast 2010 EBITDA multiple would be lower than 10.4 times in the absence of takeover speculation (and was 9.8 times a month ago);

after several years of strong connection growth and rising earnings, connection growth has fallen, reflecting a combination of deteriorating economic conditions and increasing maturity of the market. While connections growth is expected to recover over the next five years, earlier rates of connection growth are not sustainable and it is expected that in the long term, connection growth will stabilise at approximately 20,000 new connections per year (average growth per annum of 2.5%);

there is some uncertainty about the next tariff reset on which submissions are expected to be made by 31 January 2010 and that is expected to become effective from 1 January 2011; and

notwithstanding population growth, the gas market in Western Australia is relatively mature and performance in the short term is likely to be impacted by the slowing Western Australian economy.

RAB Multiples The valuation range for WA Gas Networks implies multiples of RAB at 30 June 2009 of 1.19-1.26 times, which are consistent with market evidence. DCF Analysis The DCF model for WA Gas Networks is a long term model commencing on 1 September 2009 and extending for 19 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 6.75-7.25%. The outcome of the Base Base DCF analysis is net present values in the range $1,003-1,129 billion. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions:

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WA Gas Networks – NPV Sensitivity Analysis ($ millions) Discount Rate

Sensitivity 7.25% 6.75%

Base Case 1,003 1,129

Revenues 2% higher than Base Case (throughout forecast period) Revenues 2% lower than Base Case (throughout forecast period)

1,050 955

1,182 1,075

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

988 1,017

1,112 1,145

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

985 1,020

1,109 1,148

Perpetual growth rate 0.25% higher than Base Case Perpetual growth rate 0.25% lower than Base Case

1,030 978

1,165 1,096

Under the current regulatory framework, changes in market dynamics or operating characteristics of the regulated assets are reflected in revised tariffs at each “reset”. Accordingly, the impact of any such changes on returns should be limited to the regulatory period in which they occur (that is, prior to the next “reset”). A sensitivity analysis of these impacts would require a series of highly specific assumptions regarding size, nature, timing and duration. Grant Samuel has undertaken its analysis on the basis that long run returns should tend towards the regulators’ target returns. This is reflected in the relatively narrow sensitivity ranges selected, which are designed to illustrate a general trend of under or over performance relative to the regulators’ determinations, rather than one off events. The results of the sensitivity analysis indicate that:

the NPV is sensitive to movements in revenue. The operating cost base of the network is largely fixed such that any increase or decrease in revenues will flow almost directly to the bottom line. However, the sensitivity analysis overstates the impact as it is likely that any over or under performance is “captured” and adjusted for at the next tariff reset date (i.e. it could only occur for, at most, a five year period);

the NPV is also sensitive to the perpetual growth rate assumption. While it is not possible to precisely forecast growth rates in perpetuity, the selected ranges appear reasonable in light of forecast growth in cash flows prior to calculation of terminal value and given that industry regulators will be required to provide owners of critical infrastructure with sufficient returns to justify ongoing investment; and

the NPV is not particularly sensitive to movements in operating costs or capital expenditure. The value impact of capital expenditure is potentially overstated in the models as greater than forecast capital expenditure should increase the RAB, allowing higher regulated returns to compensate the asset owner. On the other hand, lower capital expenditure will, in the long term, be offset by reduced regulated returns.

Grant Samuel’s valuation range of $900-950 million is below the low end of the value outcomes from the DCF analysis. Grant Samuel considers this to be appropriate in current market conditions (as discussed above).

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6.3.4 Tasmanian Gas Pipeline

Summary Grant Samuel has estimated the value of the Tasmanian Gas Pipeline to be in the range $225-235 million. This value range is an overall judgement having regard to multiples of EBITDA and DCF analysis. Earnings Multiple Analysis

The valuation of the Tasmanian Gas Pipeline of $225-235 million implies the following multiples of EBITDA:

Tasmanian Gas Pipeline – Implied EBITDA Multiples Value Range

Parameter54 ($ millions) Low High

Enterprise value range ($ millions) 225 235 Multiple of EBITDA Year ended 30 June 2009 (actual) 15.1 14.9 15.6 Year ending 30 June 2010 (forecast) 13.4 16.8 17.6 Year ending 30 June 2011 (forecast) 17.7 12.7 13.2

Earnings for the Tasmanian Gas Pipeline are lumpy as a result of irregular and cyclical expenses associated with maintaining the pipeline (e.g. pigging and sub-sea surveys). This is the case in the year ending 30 June 2010, where EBITDA falls by 11% despite revenue increasing 6%. The implied multiples are relatively high in comparison to the market evidence (gas transmission entities trade at forecast multiples of around 10.5 times EBITDA and acquirers have historically been willing to pay forecast multiples of 13.0-14.5 times EBITDA). This reflects the fact that the multiples for the Tasmanian Gas Pipeline are calculated by reference to earnings which do not include the impact of significant increases in consumption forecast over the 2010-2012 period, particularly under take or pay contracts, as a result of the ramp up of the Tas Gas business. The implied multiples beyond 2011 are well below the market evidence for comparable listed companies. Grant Samuel considers this to be reasonable given the risk associated with achieving the growth in gas volumes and earnings. DCF Analysis The DCF model for the Tasmanian Gas Pipeline is long term commencing on 1 September 2009 and extends to the expected design life of the pipeline (i.e. to 2072). Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate range 7.00-7.50%. A number of different scenarios have been developed and analysed to reflect the impact on value of selected key assumptions, particularly expansion and growth opportunities, the potential useful life of the assets and discount rates:

54 EBITDA is net of settlement payments from BBP (which have been valued separately) and any customer contributions to the

construction of new connections (which have been deducted from capital expenditure in the DCF analysis).

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Tasmanian Gas Pipeline – Summary of DCF scenarios Scenario Description

Scenario A Base Case with full allowance for growth options (see Appendix 2). Assets decommissioned at end of design life, with no terminal value.

Scenario B Scenario A with no allowance for growth options.

Scenario C Scenario A with risk weighted allowance for growth options.

Scenario D Scenario A with a terminal value55 and no decommissioning.

Scenario E Scenario B with a terminal value55 and no decommissioning.

Scenario F Scenario C with a terminal value55 and no decommissioning.

The outputs of the model are summarised below:

Tasmanian Gas Pipeline – Net Present Value Outcomes ($ millions) Discount Rate

Scenario 7.50% 7.00%

Scenario A 405 438 Scenario B 258 277 Scenario C 330 356

Scenario D 428 469 Scenario E 275 299 Scenario F 350 383

As discussed above, net present values from DCF analysis are subject to significant limitations and should always be treated with considerable caution. The net present values show a relatively wide range across the different scenarios, highlighting the sensitivity to relatively small changes in assumptions. The following factors are relevant to consideration of the net present value outcomes:

assuming decommissioning of the pipeline at the end of its useful life (Scenarios A, B and C) is reasonable. Although the original design life of the pipeline was 40 years, it is subject to rigorous long term asset management plans and is reasonably expected to operate in excess of its design life. Evidence from overseas indicates that pipeline assets may have useful lives of up to 70 years;

assuming no growth is inherently conservative (Scenarios B and E) given the planned roll out of the gas distribution network; and

only growth opportunities currently identified by BBI with a high probability of proceeding have been incorporated in the analysis (i.e. no allowance has been made for unspecified growth).

Grant Samuel’s valuation range of $225-235 million is below the low end of the ranges suggested by the various scenarios set out in the above table. Grant Samuel considers this to be appropriate in current market conditions (as discussed above).

6.3.5 WestNet Energy

Grant Samuel has estimated the value of WestNet Energy to be in the range $40-45 million. This value range is an overall judgement having regard to multiples of EBITDA and DCF analysis.

55 Terminal values have been calculated based on an EBITDA multiple of 9.0 times.

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Earnings Multiple Analysis

The valuation of WestNet Energy of $40-45 million implies the following multiples of EBITDA:

WestNet Energy – Implied EBITDA Multiples Value Range

Parameter ($ millions) Low High

Enterprise value range ($ millions) 40 45 Multiple of EBITDA Year ended 30 June 2009 (actual) 17.8 2.2 2.5 Year ending 30 June 2010 (forecast) 12.2 3.3 3.7 Year ending 30 June 2011 (forecast) 3.7 10.7 12.1

The implied EBITDA multiples for the year ending 30 June 2011 are the most appropriate multiples to consider as WA Gas Networks is considering the internalisation of its asset management from 1 July 2010, which would result in WestNet Energy losing its largest customer. In Grant Samuel’s opinion, the multiples are appropriate having regard to:

the growth potential and outlook for the remaining business. WestNet Energy’s primary revenue streams from 1 July 2010 are from third party contracts and project management services performed on major capital programmes undertaken on the Dampier to Bunbury Natural Gas Pipeline. Management of WestNet Energy is forecasting only a moderate rate of growth in third party contracts (4% per annum in real terms) and revenue from services provided to the Dampier to Bunbury Natural Gas Pipeline is lumpy and dependent on external factors;

the earnings multiples for listed companies that can be compared to WestNet Energy based on share prices at 29 September 2009 are:

Share Market Ratings of Selected Listed Service Companies

EBITDA Multiples (times) Entity

Market Capitalisation

($ millions) Historical Forecast Year 1 Forecast Year 2

WorleyParsons 7,208 11.7 12.6 11.2 United Group 2,520 10.3 10.0 9.4 Transfield Services 1,885 12.3 12.3 11.8 Monadelphous Group 1,176 9.1 8.9 7.8 WDS 237 5.3 4.5 4.1 Norfolk Group 92 7.1 4.9 4.5

Source: Grant Samuel analysis (see Appendix 3) The sharemarket ratings of listed service companies indicate that higher multiples are appropriate for larger entities and for those with greater growth opportunities. The most comparable listed companies to WestNet Energy in terms of activities are United Group Limited (“United Group”) and Transfield Services Limited (“Transfield Services”), however, each of these companies are much larger than WestNet Energy and provide services to a wide range of sectors outside infrastructure (e.g. more than 75% of United Group’s revenue for the year ended 30 June 2009 was generated from sectors other than infrastructure). Transfield Services generates a proportion of its earnings from

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“internal” contracts to manage the assets of Transfield Services Infrastructure Fund (which WestNet Energy will not have from 1 July 2010). Worley Parsons Limited is focussed on the hydrocarbons industry and generates more than 70% of its revenue outside of Australia. The remaining infrastructure service companies operate predominantly in resource construction and general asset services and are considered to be less directly comparable. Taking into account the particular characteristics of WestNet Energy, the sharemarket ratings of these listed companies support the implied forecast 2011 EBITDA multiples of 10.7-12.1 times for WestNet Energy; and

recent transaction evidence for infrastructure services providers:

Recent Transaction Evidence EBITDA Multiple

(times) Date Target Transaction Consid- eration

($ millions) Historical Forecast

Apr 07 Origin Energy Asset Management

Acquisition by APA 253 na 13.1

Apr 06 Agility Acquisition by Alinta 1,05056 13.8 12.3 Source: Grant Samuel analysis (see Appendix 4)

The multiples implied by the value range are below those paid in recent transactions. However, in Grant Samuel’s opinion, a discount to these benchmarks is reasonable as WestNet Energy is a much smaller business with more limited growth opportunities (particularly from 1 July 2010). DCF Analysis The DCF model for WestNet Energy is long term commencing on 1 September 2009 and extends for 17 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 11.5-12.0%. The outcome of the Base Case DCF analysis is net present values in the range $42-44 million. This range is broadly consistent with Grant Samuel’s valuation range for WestNet Energy. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions:

56 Based on the standalone valuation by the independent expert for the Alinta/AGL Transaction of $1,000-1,100 million and EBITDA

excluding any of the cost savings previously identified by AGL. If AGL’s forecast cost savings are allowed for then the EBITDA multiples fall to 11.3 and 10.8 times respectively.

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WestNet Energy – NPV Sensitivity Analysis ($ millions) Discount Rate

Sensitivity 12.0% 11.5%

Base Case 42 44

Revenues 2% higher than Base Case (throughout forecast period) Revenues 2% lower than Base Case (throughout forecast period)

54 30

57 32

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

32 53

33 56

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

42 43

44 45

Perpetual growth rate 0.25% higher than Base Case Perpetual growth rate 0.25% lower than Base Case

43 42

45 44

The results of the sensitivity analysis indicate that:

the NPV is sensitive to movements in revenue and operating costs. However, the sensitivity analysis overstates the impact as any increase in revenue is likely to be accompanied with an increase in operating costs and vice versa; and

the NPV is not particularly sensitive to movements in capital expenditure or the perpetual growth rate. This is due in large part to the relatively small size of the capital expenditure payments.

6.3.6 Investments

BBI’s investments in Multinet Gas and Dampier to Bunbury Natural Gas Pipeline have been valued in the range $180-215 million. Multinet Gas (20.1%) BBI’s 20.1% interest in the equity of Multinet Gas has been valued in the range $20-30 million. The value range implies the following multiples of RAB and earnings:

Multinet Gas – Implied Multiples Value Range

Parameter ($ millions) Low High

Value range for 100% of equity ($ millions) 57 155 225 Multiple of EBITDA Year ended 30 June 2009 (actual) 137.058 8.8 9.1

RAB Multiple Regulated asset base at 30 June 2009 (nominal) 995.7 1.21 1.26

The implied EBITDA multiples are relatively low compared to market evidence reflecting the low growth expectations for Multinet Gas in the mature Victorian gas market. BBI holds a 20.1% minority interest in Multinet Gas which is also subject to pre-emptive rights under the shareholders agreement with DUET. For this reason, the value attributed

57 After allowing for external net debt at 30 June 2009 of $1,001.5 million as reported by DUET (after adjusting for capitalised

borrowing costs) and net surplus liabilities in the range $(42)-(22) million (representing the mark to market value of hedges at 30 June 2009 and the value attributed to tax losses). Net debt is based on the latest publicly released information (i.e. 30 June 2009) rather than 31 August 2009 given the confidentiality requirements of the Multinet Gas shareholders’ agreement.

58 As reported by DUET.

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to BBI’s 20.1% interest represents a 30% discount to Grant Samuel’s estimate of the full underlying value of the equity in Multinet Gas. Dampier to Bunbury Natural Gas Pipeline (20%) BBI’s 20.0% interest in the equity of the Dampier to Bunbury Natural Gas Pipeline has been valued in the range $160-185 million. The value range implies the following multiples of RAB and earnings:

Dampier to Bunbury Natural Gas Pipeline – Implied Multiples Value Range

Parameter ($ millions) Low High

Value range for 100% equity ($ millions) 59 1,260 1,460 Multiple of EBITDA Year ended 30 June 2009 (actual) 274.158 14.4 14.8 RAB Multiple Regulated asset base at 30 June 2009 (nominal) (adjusted) 3,508.060 1.13 1.15

The implied valuation multiples are reasonable relative to market evidence:

the EBITDA for the year ended 30 June 2009 does not include any contribution from the Stage 5B expansion which is fully reflected in the regulated asset base. Implied forecast EBITDA multiples for the years following completion of Stage 5B are lower and reasonable in comparison to market evidence;

all revenue contracts for the pipeline are higher than the regulatory reference tariffs until 1 January 2016; and

the valuation reflects the pipeline’s growth potential beyond the Stage 5B expansion. BBI holds a 20% minority interest which is also subject to pre-emptive rights under the unitholders agreement with DUET and Alcoa. For this reason, the value attributed to BBI’s 20% interest represents a 30% discount to Grant Samuel’s estimate of the full underlying value of the equity in the Dampier to Bunbury Natural Gas Pipeline. The value of $160-185 million is also after allowing for BBI’s equity contribution to Stage 5B.

6.3.7 Corporate Costs

In the year ended 30 June 2009, AET&D reported unallocated corporate costs of $24.8 million. These corporate costs were incurred on the basis that AET&D did not recover the cost of providing corporate services to a number of its assets. This basis has changed for the year ending 30 June 2010 onwards such that AET&D incurs unallocated corporate costs of approximately $10 million per annum. These corporate costs are net of:

59 The enterprise value assessed for Dampier to Bunbury Natural Gas Pipeline allows for the Stage 5B expansion project. Therefore,

external net debt comprises debt at 30 June 2009 of $2,453 million as reported by DUET (after adjusting for capitalised borrowing costs) plus an allowance of $225 million in additional debt for the Stage 5B expansion. Net debt is based on the latest publicly released information (i.e. 30 June 2009) rather than 31 August 2009 given the confidentiality requirements of the Dampier to Bunbury Natural Gas Pipeline shareholders’ agreement. The equity value shown above also allows for net surplus assets and liabilities in the range $(14)-86 million (representing the mark to market value of hedges at 30 June 2009 and the value attributed to tax losses).

60 Nominal RAB at 30 June 2009 per the latest regulatory determination is $2.6 billion but this excludes any allowance for Stage 5A and 5B (to date) expansion which increases the RAB to $3,138 million (as reported by DUET). The RAB used to calculate multiples is based on the DUET reported RAB adjusted for $370 million expenditure remaining for the Stage 5B expansion.

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internal recoveries from Dampier to Bunbury Natural Gas Pipeline, WA Gas Networks and Tasmanian Gas Pipeline, primarily for the provision of corporate services (but also for IT capital expenditure for Dampier to Bunbury Natural Gas Pipeline in the year ending 30 June 2010 and IT usage recovery of recharged BBI corporate costs for WA Gas Networks from the year ending 30 June 2011, following the internalisation of its asset management services); and

external recoveries from WestNet Rail and, in the year ending 30 June 2010 only, BBP (for rent).

Grant Samuel has allowed $95-100 million for the capitalised value of the AET&D unallocated corporate costs in its valuation of AET&D’s business operations. This represents 9.5-10.0 times forecast unallocated corporate costs of approximately $10 million. A DCF analysis of AET&D’s corporate costs (including corporate capital expenditure of approximately $0.5 million per annum) supports the value range of $95-100 million that Grant Samuel has attributed to AET&D’s corporate costs.

6.3.8 Net Borrowings

AET&D’s net borrowings at 31 August 2009 were:

AET&D – Net Borrowings ($ millions)

Total borrowings Cash Net

borrowings Ownership

interest

Proportionate net

borrowings WA Gas Networks 674.8 (9.4) 665.4 74.1% 493.1 Tasmanian Gas Pipeline - (23.3) (23.3) 100.0% (23.3) WestNet Energy - (12.2) (12.2) 100.0% (12.2) AET&D Corporate 518.0 (29.4) 488.6 100.0% 488.6

Total 1,192.8 (74.3) 1,118.5 946.2 Source: BBI The cash balances at 31 August 2009 include restricted cash which is set aside for debt servicing and/or capital expenditure and is required under a number of asset level facilities. This is considered appropriate as the necessary capital expenditure has been reflected in the cash flows used in the DCF analysis and the valuations have been prepared on an ungeared basis so the way that they are financed (and therefore the need to hold a debt servicing reserve) should not be taken into account in determining value. Net borrowings excludes the proportionate net borrowings of AET&D’s minority interests in the Dampier to Bunbury Natural Gas Pipeline and Multinet Gas, which have been taken into account in valuing AET&D’s equity interests in these entities (refer to Section 6.3.6).

6.3.9 Other Assets and Liabilities

AET&D’s other assets and liabilities have been valued in the range $5.4-20.4 million (liability) and represent:

the mark to market value of interest rate hedges at 31 August 2009 for WA Gas Networks and the AET&D holding company; and

the value attributed to the payment due from BBP’s subsidiary ‘AEATM’ to Tasmanian Gas Pipeline in relation to settlement of certain outstanding matters associated with the Alinta acquisition in August 2007. BBI provided for the full

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amount outstanding at 30 June 2009 of $36.5 million. While there is no certainty that AEATM will pay the full amount owing given its financial position, AEATM continues to make payments and some value has been attributed to this payment at the high end of the valuation.

6.4 Valuation of Other Energy Transmission and Distribution Assets

6.4.1 Overview

Grant Samuel has valued BBI’s other energy transmission and distribution interests in the range $1,116-1,310 million:

Other Energy Transmission and Distribution - Valuation Summary ($ millions)

Value Range Region Section

Reference Low High Cross Sound Cable 6.4.2 - - Natural Gas Pipeline Company of America (26.4%) 6.4.3 660 742 Tas Gas 6.4.4 162 182 Powerco (42.0%) 6.4.5 246 283 International Energy Group 6.4.6 48 103 Total 1,116 1,310

In determining these values, Grant Samuel had regard to DCF analysis, multiples of EBITDA and multiples of RAB (as appropriate). All three approaches give results that are broadly consistent with the selected value ranges.

6.4.2 Cross Sound Cable

Summary Grant Samuel has concluded that the equity in CSC has no value. Although CSC generates stable and predicable cash flows, CSC is a highly geared asset with book gearing of 120% as at 30 June 2009. Grant Samuel’s valuation of CSC is summarised below:

CSC - Valuation Summary (US$ millions) Value Range

Asset Low High

Value of CSC 160.0 170.0 CSC net borrowings (183.9) (183.9) Other liabilities (35.2) (35.2)

Value of CSC equity - -

Grant Samuel’s valuation is an overall judgement having regard to multiples of EBITDA and DCF analysis. The estimated enterprise value of US$160-170 million is slightly below the range implied by the DCF analysis but appears consistent with the limited recent transaction evidence available. The estimated enterprise value takes into account CSC’s stable contracted revenues with LIPA to 2032.

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Earning Multiple Analysis Grant Samuel’s estimate of the enterprise value CSC in the range US$160-170 million implies the following multiples of EBITDA:

CSC – Implied EBITDA Multiples Value Range

Parameter

(US$ millions) Low High

Enterprise value range (US$ millions) 160 170 Multiple of EBITDA Year ended 31 December 2008 (actual) 14.9 10.7 11.4 Year ended 31 December 2009 (forecast) 15.6 10.2 10.9 Year ended 31 December 2010 (forecast) 16.0 10.0 10.6

Grant Samuel considers that these multiples are reasonable, having regard to the low risk nature of the cash flows generated by CSC. The reality, however, is that there is very limited directly comparable evidence as to the appropriate multiples, and the valuation inevitably involves some judgement. Transaction Evidence There are very few transactions involving electricity transmission assets. Accordingly, the table below sets out the EBITDA multiples implied by selected transactions involving both electricity and gas transmission assets since 2005:

Recent Transaction Evidence EBITDA Multiple62

(times) Date Target Transaction

Consid- eration61

(US$ millions) Historical Forecast

Gas Transmission – United States May 09 North Baja Pipeline Acquisition by TC Pipelines 270 9.6 na Apr 09 Ozark Gas Gathering Acquisition by Spectra

Energy Partners 300 6.5 na

Dec 07 NGPL Acquisition of 80% by consortium including BBI

7,237 10.5 na

Dec 06 ANR Pipelines Acquisition by TransCanada Corporation

2,943 10.6 na

Electricity Transmission – United States Nov 05 CSC Acquisition by BBI 213 na 15.163 Electricity Transmission - Australia Jul 07 Basslink Acquisition by CitySpring 1,001 16.4 12.8

Source: Grant Samuel analysis (see Appendix 4) CitySpring acquired Basslink in July 2007. Basslink is a 370 kilometre high voltage electricity interconnector between the electricity grids of Victoria and Tasmania in Australia. The acquisition price represented 12.8 times forecast earnings. Grant Samuel’s valuation of CSC represents multiples of 10.2-10.9 times forecast EBITDA,

61 Implied equity value if 100% of the company or business had been acquired. 62 Represents gross consideration divided by EBITDA. 63 Based on four months of earnings annualised.

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reflecting the considerable decline in the values of infrastructure assets over the last two years. Sharemarket Evidence There are no publicly listed companies that have activities directly comparable to those of CSC. Those cables that are comparable to CSC (Path 15, TBC, Neptune and the SunZia project) are generally owned by infrastructure funds and energy-focused private equity funds. Natural gas pipelines as an asset class are broadly comparable to CSC. In the United States, pipelines are owned by energy corporations (El Paso Corporation and Williams Corp are the largest) and, increasingly, by master limited partnerships (“MLPs”). MLPs are partnerships that are obliged to distribute a high percentage of cash flows each year to investors. They are pass-through vehicles for tax. A regulated transmission asset with stable cash flow is the perfect asset class for an MLP, but electricity transmission does not currently qualify for MLP status. Analysis of listed companies and MLPs that operate gas transmission pipelines show that they generally trade at prices representing a broad range of 8.1-16.3 times forecast EBITDA. DCF Analysis The DCF model for CSC is a long term model, commencing at 1 September 2009 and extending to 2043. The model assumes contracted revenues from LIPA escalate by 1% per annum over the life of the contract, which expires in 2032. CSC’s asset life continues until 2043 and the model assumes there will still be a requirement for the transmission capacity between 2032 and 2043, with revenues assumed to escalate at the inflation rate for the period from 2033-2043. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 5.75-6.25%. The aggregate outcome of the Base Case DCF analysis is net present values in the range of US$180-195 million. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions. Given CSC’s revenue is contracted to increase by 1% (assuming CSC meets the availability target of 98%) over the life of the contract until 2032, Grant Samuel has not modelled a change in this assumption. The revenue received from TBC accounts for less than 3% of total revenue and as such does not significantly impact the sensitivity analysis. The outcomes of the sensitivity analysis are summarised below:

CSC – NPV Sensitivity Analysis (US$ millions) Discount Rate

Sensitivity 6.25% 5.75%

Base Case 182 193

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

165 194

174 206

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

182 182

193 193

The analysis illustrates the sensitivity of CSC’s net present values to changes in operating costs. The fluctuations are less volatile for capital expenditure given the limited capital expenditure requirements on this asset. Net Borrowings As at 31 August 2009, CSC had net borrowings of US$183.9 million, comprising gross borrowings of US$192.7 million and cash of US$8.8 million.

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Other Liabilities

The mark to market value of CSC’s interest rate hedges as at 31 August 2009 of US$35.2 million (loss) has been included in the valuation.

6.4.3 Natural Gas Pipeline Company of America

Grant Samuel has valued BBI’s 26.4% effective interest in the equity of NGPL, via BBI’s 33% interest in Myria, in the range US$574-645 million, which equates to $660-742 million at an exchange rate of A$1.00 = US$0.87. This value range is an overall judgement having regard to EBITDA multiples analysis. The valuation is summarised as follows:

NGPL - Valuation Summary (US$ millions) Value Range

Asset Low High

Value of NGPL 6,250.0 6,550.0 NGPL net borrowings (3,000.0) (3,000.0) Other adjustments64 (20.1) (20.1)

Equity value of NGPL 3,229.9 3,529.9 Value of Myria (80% of NGPL) 2,583.9 2,823.9 Myria net borrowings (600.0) (600.0) Other liabilities (51.9) (51.9)

Equity value of Myria 1,932.1 2,172.1 Minority interest discount 10% 10% Value of BBI’s 33% interest in Myria 573.8 645.1

Earning Multiple Analysis Grant Samuel’s valuation of US$6,250-6,550 million for 100% of the enterprise value of NGPL implies the following multiples:

NGPL – Implied Values Value Range

Parameter

(US$ millions)65 Low High

Enterprise value of NGPL (US$ millions) 6,250 6,550 Multiple of EBITDA Year ended 31 December 2008 (actual) 656.7 9.5 10.0 Year ended 31 December 2009 (forecast) 665.1 9.4 9.8 Year ended 31 December 2010 (forecast) 681.8 9.2 9.6

The implied EBITDA multiples appear reasonable and reflect the following characteristics of NGPL:

its extensive pipeline system;

access to major supply basins, including growing shale gas production;

64 Includes present value of asset retirement obligation and interests in associates. 65 EBITDA excludes income from other equity investments.

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significant storage assets which are in high demand given the volatile gas price;

strong customer loyalty; and

ability to compete as a low-cost provider. Although BBI holds a minority interest, it is the largest single shareholder of NGPL. It is entitled to appoint two of the seven directors on the NGPL Pipeco Board and three of the nine directors on the Myria Board. On the other hand, BBI’s interests are subject to pre-emptive rights and BBI has entered into various standstill arrangements that prohibit BBI from selling its interest in NGPL in the short term. Having regard to these factors, Grant Samuel has discounted the full underlying value of NGPL by 10% in assessing the value of BBI’s equity interest in NGPL. Transaction Evidence The table below sets out the EBITDA multiples implied by selected transactions involving gas transmission assets in the United States since 2006:

Recent Transaction Evidence EBITDA Multiple67

(times) Date Target Transaction

Consid- eration66

(US$ millions) Historical Forecast

Gas Transmission – United States May 09 North Baja Pipeline Acquisition by TC Pipelines 270 9.6 na Apr 09 Ozark Gas Transmission

and Ozark Gas Gathering Acquisition by Spectra Energy Partners

300 6.5 na

Dec 07 NGPL Acquisition of 80% by consortium including BBI

7,237 10.5 na

Dec 06 ANR Pipelines Acquisition by TransCanada Corporation

2,943 10.6 na

Source: Grant Samuel analysis (see Appendix 4) Further details on these transactions are set out in Appendix 4. The transaction evidence suggests that the multiplies paid for gas transmission assets in the United States have fallen since the onset of the global financial crisis, although the lower multiples for the 2009 transactions set out above could also reflect the smaller size of the relevant assets. Ozark Gas Transmission and Ozark Gas Gathering and North Baja Pipeline are very small assets with pipelines of 910 kilometres and 129 kilometres respectively, by comparison with NGPL and ANR Pipelines which have pipeline assets of 15,600 kilometres and 17,000 kilometres respectively. The price at which BBI acquired its 26.4% interest in NGPL implied a multiple of 10.5 times historical earnings. Having regard to the fall in infrastructure asset values since that time, Grant Samuel believes that the multiples of historical earnings of 9.5-10.0 times implied by its valuation of NGPL are reasonable.

66 Implied equity value if 100% of the company or business had been acquired. 67 Represents gross consideration divided by EBITDA.

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Sharemarket Evidence The following table sets out the implied EBITDA multiples for a range of listed United States gas transmission assets based on share prices as at 29 September 2009:

Sharemarket Ratings of Selected Listed Entities68

EBITDA Multiple69 (times) Entity

Market Capital- isation

(US$ millions) Historical Forecast Year 1

Forecast Year 2

TC Pipelines 1,658 na70 28.6 20.7

Williams Pipeline Partners 641 12.2 12.2 12.4

Energy Transfer Partners 7,173 9.0 8.0 7.2

ONEOK Partners 5,069 9.1 10.6 10.2

El Paso Pipeline Partners 2,674 24.2 11.1 7.3

Spectra Energy Partners 1,999 23.5 11.5 9.6

Boardwalk Pipeline Partners 4,524 15.7 14.6 10.4 Source: Grant Samuel analysis (see Appendix 3) A detailed analysis of these entities is set out in Appendix 3. The two companies most comparable to NGPL are TC Pipelines and Williams Pipeline Partners. They are trading on higher multiples than those implied by the valuation of NGPL. The following factors are relevant to consideration of the comparable companies:

TC Pipelines, which is closely comparable to NGPL, derives a significant portion of its earnings and cash flows from interests in interstate natural gas pipelines. TC Pipeline’s notional share of EBITDA from these investments is not included in the EBITDA of TC Pipeline as the earnings are equity accounted, although they are reflected in market values. Accordingly, the EBITDA multiples are effectively overstated; and

Williams Pipeline generates close to 100% of its revenue from its 35% interest in North West Pipeline, a 3,900 mile interstate natural gas pipeline system that extends from Mexico to northwestern United States. Williams Pipeline equity accounts its earnings. EBITDA multiples have been adjusted to reflect these equity accounted earnings. The higher multiples of earnings on which Williams is trading are likely to be explained, at least in part, by its tax advantaged status.

Net Borrowings As at 31 August 2009, NGPL had borrowings of US$3,000.0 million at the asset level and borrowings of US$600.0 million at the Myria holding company level. Other Liabilities

The mark to market value of NGPL’s interest rate hedges as at 31 August 2009 of US$51.9 million (loss) has been included in the valuation.

68 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 69 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at

the latest balance date) divided by EBITDA. 70 Due to TC Pipelines 100% acquisition of North Baja for an initial total purchase price of US$271.3 million on 1 July 2009,

historical multiples for TC Pipelines are not meaningful.

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6.4.4 Tas Gas

Summary Grant Samuel has estimated the value of the equity in Tas Gas to be in the range $162-182 million.

Tas Gas - Valuation Summary ($ millions) Value Range

Asset Low High

Value of Tas Gas business operations 160.0 180.0 Net cash 2.3 2.3

Value of equity in Tas Gas 162.3 182.3

Grant Samuel has valued Tas Gas having regard to multiples of EBITDA and DCF analysis. Earnings Multiple Analysis The valuation of $160-180 million implies the following multiples:

Tas Gas – Implied EBITDA Multiples Value Range

Parameter ($ millions) Low High

Enterprise Value range ($ millions) 160 180 Multiple of EBITDA Year ended 30 June 2009 (actual) 3.0 53.3 60.0 Year ending 30 June 2010 (forecast) 7.0 22.9 25.7 Year ending 30 June 2011 (forecast) 9.3 17.2 19.4

The implied multiples for Tas Gas are very high compared to trading multiples for gas distribution businesses (of 8.5-10 times forecast EBITDA) and transaction multiples (of 12.5-13.0 times forecast EBITDA) but this reflects the fact that significant growth in EBITDA is expected over the next four years (with average annual growth in EBITDA of more than 50%) as a result of contracts with new, high volume industrial customers. The implied forecast EBITDA multiples for the year ending 30 June 2014 (after all of the new contracts are in place) are lower than the forecast EBITDA multiples implied by transactions involving gas distribution businesses and the forecast EBITDA multiples of comparable listed gas distribution businesses. This is reasonable given that:

there is risk associated with achieving the growth in gas volumes and earnings;

these multiples are five years into the future and reflect growth in the existing business over this period; and

Tas Gas also has a retail business and retail businesses generally change hands at lower multiples in comparison to distributors because they are more vulnerable to changes in gas costs.

DCF Analysis The DCF model for Tas Gas is long term commencing on 1 September 2009 and extending for 20 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 7.00-7.50%.

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The outcome of the Base Case DCF analysis is net present values in the range $184-218 million. As with any long term projections, especially for an early stage business like Tas Gas, there are inherent uncertainties about future events and outcomes. The key driver of NPVs for Tas Gas is the number of prospective industrial end gas users (i.e. users that consume more than 5 TJ per annum) and consumption secured from these users over the next three to four years. Accordingly, Grant Samuel has considered a number of scenarios:

Tas Gas – Summary of DCF scenarios Scenario Description

Scenario A Represents the “Base Case”. It assumes that prospective industrial gas consumption reaches a steady state of 5,750 TJ per annum by 30 June 2014.

Scenario B Assumes a higher level of prospective industrial gas consumption compared to Scenario A, reaching a steady state of 6,256 TJ per annum by 30 June 2014. Compared to Scenario A, this implies a 9% increase in prospective industrial gas consumption and an 8% increase in total gas consumption for the year ended 30 June 2014. Additional capital expenditure associated with the increased consumption is required.

Scenario C Assumes lower level of prospective industrial consumption compared to Scenario A, reaching a steady state of 5,243 TJ per annum by 2014. Compared to Scenario A, this implies a 9% decrease in prospective industrial gas consumption and an 8% decrease in total gas consumption for the year ended 30 June 2014. Capital expenditure associated with the reduced consumption reduction is excluded.

The output of the DCF analysis is summarised below:

Tas Gas – DCF Analysis ($ millions) Discount rate 7.50% 7.00% Scenario A 184 218 Scenario B 200 236 Scenario C 168 200

The value range of $160-180 million falls within the range of NPVs produced by Scenario C. While this may appear conservative, Grant Samuel considers this to be appropriate in current market conditions (refer to Section 6.3.2), particularly taking into account the risk associated with achieving the growth in gas volumes and earnings. Net Borrowings

At 31 August 2009, Tas Gas had no borrowings and cash of $2.3 million.

6.4.5 Powerco

Summary Grant Samuel has estimated the value of BBI’s 42.0% interest in the equity in Powerco to be in the range NZ$300-345 million, which equates to $246-283 million at an exchange rate of A$1.00 = NZ$1.22.

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Powerco - Valuation Summary (NZ$ millions) Value Range

Asset Low High

Value of Powerco business operations 1,900.0 2,000.0 Powerco net borrowings (1,210.0) (1,210.0) Other assets and liabilities 23.4 30.9 Value of 100% of equity in Powerco 713.4 820.8 Value of 42% of equity in Powerco 299.6 344.7

Grant Samuel has not allowed for any minority discount for BBI’s 42.0% interest on the basis that, despite there being pre-emptive rights, BBI has equal representation with QIC on the Powerco board and voting rights are such that all decisions (whether by ordinary resolution or special resolution) require the support of BBI nominated directors. Grant Samuel has valued Powerco having regard to multiples of EBITDA, multiples of RAB and DCF analysis. Earnings Multiple Analysis The estimated enterprise value of NZ$1,900-2,000 million implies the following multiples:

Powerco – Implied EBITDA Multiples Value Range

Parameter (NZ$ millions) Low High

Enterprise Value range (100%) (NZ$ millions) 1,900 2,000 Multiple of EBITDA Year ended 30 June 2009 (actual) 220.4 8.6 9.1 Year ending 30 June 2010 (forecast) 217.5 8.7 9.2 Year ending 30 June 2011 (forecast) 219.8 8.6 9.1

RAB Multiple Regulated asset base at 30 June 2009 (nominal)71 1,456.9 1.30 1.37

The best evidence of the value of an asset is the multiple that other buyers have been prepared to pay for similar (or the same) asset in the recent past. There have been two recent transactions involving Powerco, the acquisition by BBI in August 2004 and the sale of a 58% interest to QIC which was completed in February 2009. Both of these transactions occurred at a forecast EBITDA multiple of around 9 times. The Powerco transactions also show that infrastructure transactions in New Zealand are taking place at a premium to trading multiples i.e. at 9 times forecast EBITDA compared to trading multiples of 7.8 times (for Vector). The implied multiples for Powerco are supported by transaction multiples implied by transactions involving Powerco. These multiples are generally lower than the implied multiples for the valuation of BBI’s Australian gas transmission and distribution businesses. In Grant Samuel’s opinion these multiples are reasonable as:

71 Note that the regulatory asset base is as calculated by Powerco and is based on 2004 optimised deprival value (“ODV”) for the

electricity distribution business and 2002 ODV for the gas distribution business. The Commerce Commission does not currently determine a regulatory asset base for electricity and gas distribution businesses.

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Powerco is predominantly an electricity business, with approximately 90% of revenue generated from electricity. Electricity businesses are more capital intensive than gas businesses and this is reflected in lower EBITDA multiples;

the recession in New Zealand is likely to impact short and medium term growth rates; and

there is uncertainty as to the future regulation of Powerco’s electricity and gas businesses which is a significant risk. While Powerco continues to be actively engaged in influencing regulatory development, the outcomes are unknown at this point. Input methodologies are not expected to be finalised until 2010 and if unfavourable, will have a significant impact on Powerco’s electricity and gas revenue in future years.

RAB Multiples The valuation range for Powerco implies multiples of RAB at 30 June 2009 of 1.30-1.37 times, which is consistent with market evidence. DCF Analysis The DCF model for Powerco is long term commencing at 1 July 2009 and extending for 19 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 7.25-7.75%. The aggregate outcome of the Base Case DCF analysis is net present values in the range NZ$1,945-2,143 million. While this range is not inconsistent with Grant Samuel’s valuation range for Powerco, the financial model assumes a neutral regulatory environment. There is considerable uncertainty associated with the future regulatory environment that could have a significant negative impact on Powerco’s electricity and gas distribution businesses. The development of the regulatory environment is insufficiently advanced to allow the possible outcomes to be modelled with any certainty. As a result, more emphasis has been placed on earnings multiple analysis. Net Borrowings Powerco’s net borrowings at 31 August 2009 were NZ$1,210.0 million, comprising gross borrowings of NZ$1,210.7 million and cash of NZ$0.7 million. Other Assets and Liabilities Powerco’s other assets and liabilities have been valued in the range NZ$23.4-30.9 million and represent:

the mark to market value of interest rate and currency hedges at 31 August 2009; and

proceeds from the sale of non-core assets (Hawkes Bay Gas Network and gas meters in Hutt Valley and Taranaki) in the year ending 30 June 2011.

6.4.6 International Energy Group

Summary Grant Samuel has valued the equity in IEG in the range £27-57 million, which equates to $48-103 million at an exchange rate of A$1.00 = £0.55.

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IEG - Valuation Summary (£ millions) Value Range

Asset Low High

Value of IEG business operations 290.0 320.0 IEG net borrowings (244.1) (244.1) Other assets and liabilities (19.3) (19.3)

Value of 100% of equity in IEG 26.6 56.6

Grant Samuel has valued IEG having regard to DCF analysis and multiples of EBITDA. The historical EBITDA multiples include revenue from IEG’s Portugal business (Gascan), which was sold in May 2009. Earnings Multiple Analysis The multiples of EBITDA implied by the valuation are set out below:

IEG – Implied Values Value Range

Parameter (£ millions)72 Low High

Enterprise value range (£ millions) 290 320 Multiple of EBITDA Year ended 30 June 2009 (actual) 39.5 7.3 8.1 Year ended 30 June 2010 (forecast) 32.8 8.8 9.8 Year ended 30 June 2011 (forecast) 35.0 8.3 9.2

There are very few companies directly comparable to IEG. The company perhaps most comparable to IEG is Inexus, which has gas and electricity networks throughout the United Kingdom. However, Inexus is owned by Challenger Infrastructure Fund (“CIF”), an infrastructure fund listed in Australia, and earnings multiple information for Inexus is accordingly not available. As a result Grant Samuel has also considered valuation evidence based on the trading prices of listed United Kingdom utility and distribution companies. These are summarised as follows:

Sharemarket Ratings of Selected Listed Entities73 EBITDA Multiple74

(times) Entity

Market Capital- isation

(£ millions) Historical Forecast Year 1

Forecast Year 2

United Kingdom Utility and Distribution

Severn Trent Plc 2,288.6 10.7 8.2 8.6 Pennon Group Plc 1,656.8 9.3 8.9 9.1 Northumbrian Water Group 1,287.2 9.9 10.7 10.8 United utilities Group Plc 3,117.5 7.9 7.8 9.0 Scottish and Southern Energy Plc 10,768.7 8.5 7.8 7.0

Source: Grant Samuel analysis (see Appendix 3)

72 EBITDA excludes income from other equity investments. 73 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 74 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at

the latest balance date) divided by EBITDA.

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The multiples implied by the valuation of IEG are generally consistent with the earnings multiples implied by the share prices of listed United Kingdom distribution and utility companies. The last two relevant transactions in the United Kingdom, which took place in 2006, implied multiples of 7.7-8.4 times forecast EBITDA. Given the movement in market values since that time, it is not clear that these transactions remain relevant. In Grant Samuel’s opinion the multiples implied by the IEG valuation are reasonable:

although IEG has been exposed to the downturn in the United Kingdom housing market, it has still able to increase underlying revenue and earnings;

while the United Kingdom utility companies are not directly comparable, they do provide reasonable evidence as to value given that they operate under a similar regulatory regime in the United Kingdom; and

Scottish & Southern Energy Plc, amongst other activities, provides electricity and gas distribution throughout the United Kingdom, albeit on a much larger scale than IEG.

A detailed analysis of these entities is set out in Appendix 3. DCF Analysis Grant Samuel has prepared a DCF analysis for IEG. The DCF model has been developed by Grant Samuel with reference to the projections and longer term financial models prepared by BBI. Grant Samuel has made adjustments to the projections to reflect its judgement on certain matters. The DCF Model is a long term model, commencing at 1 September 2009 and extending for 15 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 7.75-8.25%. The aggregate outcome of the Base Case DCF analysis is net present values in the range of £305-335 million. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions.

IEG – NPV Sensitivity Analysis (£ millions) Discount Rate

Sensitivity 8.25% 7.75%

Base Case 305 335

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

295 314

325 346

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

277 328

304 362

Perpetual growth rate 0.25% higher than Base Case (throughout forecast period) Perpetual growth rate 0.25% lower than Base Case (throughout forecast period)

311 299

343 328

The valuation range adopted by Grant Samuel represents a small discount to the calculated NPVs. IEG’s United Kingdom business accounts for close to 50% of revenue. The model assumes double digit growth in the United Kingdom business over the next four years, which is consistent with the growth experienced in FY09 and takes into account the housing slump experienced in the United Kingdom. Any further deterioration in the United Kingdom housing market or unexpectedly slow recovery rates will impact IEG’s United Kingdom business. Revenue in the Isle of Man (via Manx Gas) accounts for approximately 25% of IEG’s revenue. The model assumes modest growth, which is consistent with the mature market in the Isle of Man. The operations of Manx Gas are currently unregulated. If

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they become subject to regulation by the relevant authority, actual future revenues may be less than assumed in the DCF model. Net Borrowings As at 31 August 2009, IEG had £244.1 million of net debt outstanding, comprising gross borrowings of £266.8 million and cash of £22.7 million. Other Assets and Liabilities

IEG’s other assets and liabilities have been valued at £$19.3 million (liability) and represent the mark to market value of interest rate swaps of £22.8 million (loss) as at 31 August 2009 and a defined benefit plan asset of £3.5 million as at 31 August 2009.

6.5 Valuation of Transport Assets

6.5.1 Overview

Grant Samuel has valued BBI’s transport assets in the range $916-1,146 million:

Transport Assets - Valuation Summary ($ millions) Value Range

Region Section Reference Low High

Dalrymple Bay Coal Terminal 6.5.3 581 681 WestNet Rail (96%) 6.5.4 88 146 Euroports (various) 6.5.5 247 298 PD Ports 6.5.6 - 21 Total 916 1,146

In determining these values, Grant Samuel had regard to transaction evidence, DCF analysis, capitalisation of EBITDA, and in the case of DBCT, multiples of RAB. For some of BBI’s transport assets, recent transactions or the results of recent sales processes provide the best information as to value. The DCF and capitalisation of earnings analysis gives results that are broadly consistent with the selected value ranges.

6.5.2 Market Valuation Parameters

Sharemarket Evidence Grant Samuel has reviewed share market ratings of selected overseas listed companies which operate in the port industry. The following table sets out the multiples implied by the share prices of selected listed companies based on share prices as at 29 September 2009:

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Sharemarket Ratings of Selected Listed Entities75 EBITDA Multiple76

(times) Port operator Country

Market Capitalisation(A$ millions) Historical Forecast

Year 1 ForecastYear 2

Shanghai International Port (Group) Co China 17,690 10.8 14.6 13.4

Shenzhen Chiwan Wharf Holdings Limited China 1,074 5.6 8.8 8.3

Tianjin Port Holdings Company Limited China 2,985 11.1 10.2 9.5 China Merchants Holdings (International) Co Ltd China 9,265 14.8 16.1 14.7 Cosco Pacific Ltd China 3,824 10.8 16.1 13.0 Bintulu Port Holdings Berhard Malaysia 829 9.8 10.9 9.8 Dalian Port (PDA) Company Limited China 1,374 11.9 10.4 9.4 Forth Ports PLC UK 1,011 11.1 12.9 12.2 Lyttelton Port Company Limited New Zealand 201 10.5 9.9 9.5 South Port New Zealand Ltd New Zealand 54 9.5 10.7 10.1

DP World Limited United Arab Emirates 10,194 9.4 10.7 10.1

Port of Tauranga Limited New Zealand 709 13.2 12.5 11.7 Hamburger Hafen und Logistik AG Germany 3,736 6.4 8.3 7.3

Source: Grant Samuel analysis (see Appendix 3) A detailed analysis of these entities is set out in Appendix 3. The following factors are relevant to consideration of these multiples:

the multiples for the listed entities are based on share prices and therefore do not include a premium for control;

all of the companies have a 31 December year end with the exception of Lyttelton Port Company Limited, South Port New Zealand Ltd and Port of Tauranga Limited which have 30 June year ends. The multiples of earnings implied by the valuations of BBI’s transport assets have been calculated on 30 June year end earnings;

the historical EBITDA multiples tend to be in the range of 9-13 times, with forecast year 1 EBITDA multiples ranging from 10-16 times. Market expectations for many of the port entities are for declining earnings in the short term (as evidenced by the increasing multiples for forecast year 1 EBITDA), as a result of lower shipping volumes. Some earnings recovery is generally expected thereafter (reflected in lower multiples for forecast year 2 EBITDA); and

a number of the above companies have government controlled entities as major shareholders. These include the China-based port entities, DP World Limited (controlled by the government of Dubai) and Lyttelton Port Company Limited (65% shareholding by the City of Christchurch).

Transaction Evidence The table below sets out the EBITDA multiples implied by selected transactions involving the acquisition of various ports businesses internationally since 2005:

75 The companies selected have a variety of year ends and therefore the data presented for each entity is the most recent annual

historical result plus the subsequent two forecast years. 76 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at

the latest balance date) divided by EBITDA.

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Recent Transaction Evidence EBITDA

Multiple78 (times) Date Target Target Consideration77

(millions) Historical Forecast

Aug 09 Euroports Acquisition of up to 40% interest by Antin Infrastructure & Arcus European Infrastructure

€811 12.4 10.7

Oct 07 Rauma & Botnia

Acquisition of 100% interest by BBI €90 na 10.6

Jul 07 Various European Ports

Acquisition of combined proportionate ownership of approximately 65.4% by BBI

€402 na 10.8

May 07 Tarragona Port Services

Acquisition of 51% interest by BBI A$220 12.3 na

Mar 07 Maher Terminals

Acquisition of 100% interest by RREEF Infrastructure US$2,10079 30-35 na

Feb 07 Montreal Gateway Terminals

Acquisition of 80% interest by Morgan Stanley Infrastructure €37579 24.7 na

Nov 06 OOIL terminals division

Acquisition of 100% of terminals division by Ontario Teachers Pension Plan

US$2,410 23.5 na

Nov 06 Peel Ports Acquisition of 49.9% of by RREEF Infrastructure £1,55079 15.5 na

Mar 06 Associated British Ports

Acquisition of 100% interest by Admiral Acquisition £2,577 12.5 na

Dec 05 PD Ports Acquisition of 100% interest by BBI £562 13.2 na

Source: Grant Samuel analysis (see Appendix 4). Further details on these transactions are set out in Appendix 4. The following factors are relevant to consideration of the transaction evidence:

a large number of transactions in the port industry over the last few years have involved BBI and other global infrastructure players (such as RREEF Infrastructure). Prior to 2008, BBI was an acquirer of ports and generally paid high multiples for businesses in an environment where there was high demand for infrastructure assets and relatively cheap and easy access to debt and equity;

most of the ports involved in transactions were originally either privately held or divisions of public companies. Consequently, in many cases relatively little financial information was disclosed in relation to earnings of the relevant assets; and

with the exception of the Euroports business, the OOIL (Orient Overseas International Limited) terminal division, PEEL Ports and PD Ports transactions, all of the transactions disclosed above involve single port assets. This contrasts with BBI’s port investments in Euroports and PD Ports, which are multi-port and terminal holdings.

77 Implied enterprise value if 100% of the company or business had been acquired. 78 Represents gross consideration divided by EBITDA. 79 Based on broker estimate.

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Interpretation Prior to 2008 transaction multiples for port assets were generally over 10 times forecast EBITDA, with higher implied historical multiples. Port assets were generally considered to be relatively attractive, stable infrastructure assets with reliable income streams. Consequently, there was strong demand from global infrastructure and private equity players as well as United States pension funds and other institutions to directly hold this type of asset, underpinned by access to large volumes of relatively cheap debt and equity capital. Following the onset of the global financial crisis in 2008, and the near-closure of many international debt markets, the transaction flow in the port industry has virtually stopped. Potential transactions are likely to be affected by the following factors:

as a result of falling volumes, particularly in the bulk sector, earnings in the ports sector have fallen and are expected to continue to fall for the next 6-12 months; and

prospective purchasers are seeking value opportunities and higher rates of return, driving down asset values and making it difficult to complete transactions.

Given the above factors, in Grant Samuel’s view appropriate valuation multiples in today’s market are likely to be well below the transaction multiples evident in the period 2005-2007.

6.5.3 Dalrymple Bay Coal Terminal

Grant Samuel has estimated that the enterprise value of DBCT is in the range $2,200-2,300 million. This implies a value of the equity in DBCT of $581-681 million:

Dalrymple Bay Coal Terminal – Valuation Summary ($ millions)

Value Range

Low High Value of DBCT business operations 2,200.0 2,300.0 DBCT net borrowings (1,601.6) (1,601.6) Other liabilities (17.4) (17.4) Value of equity in DBCT 581.0 681.0

Grant Samuel has valued DBCT having regard to DCF analysis, multiples of EBITDA and multiples of RAB. Grant Samuel has also considered the valuation range of $2,200-2,300 million in the context of the sale process for DBCT that was recently conducted by BBI and its advisers. BBI commenced a sale process for 100% of DBCT in the first quarter of 2009. The process was designed to be extensive and a large number of potential industry participants, asset management groups and financial buyers were contacted. Confidential sale materials, including a detailed explanatory memorandum and financial model for DBCT, were provided to numerous parties. BBI received indicative offers for DBCT in July 2009. The low end of Grant Samuel’s equity value range for DBCT is consistent with the indicative offers received for 100% of DBCT through the sale process, although it is likely that the net proceeds received from the sale process would have been considerably less after transaction costs and escrows required. In addition, BBI did receive an expression of interest for less than 100% at a value greater than the high end of Grant Samuel’s equity value range for DBCT. However, the potential investor did not pursue due diligence and the expression of interest was inherently uncertain and subject to a high degree of execution risk.

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Earnings Multiple Analysis The value attributed to DBCT of $2,200-2,300 million implies the following multiples:

Dalrymple Bay Coal Terminal – Implied Multiples ($ millions) Value Range

Parameter Low High

Enterprise value range ($ millions) 2,200 2,300 Multiple of EBITDA Year ended 30 June 2009 (actual) 153.7 14.3 15.0 Year ending 30 June 2010 (forecast) 221.6 9.9 10.4 Year ending 30 June 2011 (forecast) 228.8 9.6 10.1 RAB Multiple Regulated asset base post Project 7X expansion (nominal) 2,345.0 0.94 0.98

The first year in which the benefits of DBCT’s 7X expansion project are fully captured is 2010 and therefore Grant Samuel has focussed on the implied multiples of 2010 and 2011 earnings. Multiples based on 2009 earnings are less relevant, given that they reflect earnings levels that pre-dated DBCT’s expansion. Grant Samuel has reviewed the multiples implied by its valuation of DBCT having regard to EBITDA multiples for listed entities involved in port operations (refer Section 6.5.2). These multiples are generally in the range 9-13 times historical EBITDA, 10-16 times forecast year 1 EBITDA and 9-13 times forecast year 2 EBITDA. Grant Samuel’s valuation of DBCT implies forecast EBITDA multiples that are broadly consistent with the available market evidence for port assets. However, many of the selected overseas port businesses have very different business dynamics from those of DBCT. Many are unregulated and subject to competition, and are accordingly exposed to far more variability in terms of future earnings and cash flows than DBCT. Sharemarket trading and transaction multiples for these businesses are therefore of only limited relevance to the valuation of a regulated asset such as DBCT. Grant Samuel has also compared the earnings multiples implied by its valuation of DBCT with trading and transaction multiples for regulated assets in the Australian energy distribution segment (set out in Appendices 3 and 4). These assets are similar to DBCT, in that their revenue streams are very stable and their returns are regulated. The trading multiples for these assets are generally in the range of 9-11 times historical EBITDA and 8-10 times forecast EBITDA. In Grant Samuel’s view they provide general support for the valuation of DBCT. DBCT is a key coal export gateway to the Bowen Basin coalfields and Grant Samuel believes that in an unregulated environment the facility could have a higher value due to its proximity to the mines, direct rail linkages and potential for future growth. However, having regard to the regulation of DBCT’s earnings, valuation upside (and downside) is limited for BBI or any hypothetical acquirer of the facility. RAB Multiples Given the regulated nature of DBCT’s asset base and that the terminal infrastructure charge is calculated with reference to that asset base, a multiple of around 1 times RAB would typically be considered a reasonable reference point for fair value. Grant Samuel’s value range implies a multiple of enterprise value to DBCT’s regulated asset base of approximately $2.3 billion (adjusted to reflect all Project 7X inclusions) of 0.94 to 0.98 times.

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DCF Analysis The DCF model for DBCT commences on 1 September 2009 and projects quarterly cash flows to the period ending 30 June 2054. Forecast cashflows in the DCF model are based on a steady state capacity throughput for DBCT of 85 Mtpa. While there are expansion opportunities beyond this capacity, DBCT is still in the early stages of planning for its next potential expansion phase. DBCT has received indications from customers of interest in an expansion, but throughput commitments to support an expansion are yet to be secured. Consequently, given the uncertainties surrounding the timing, cost and financial impact of potential future expansions, these scenarios were not modelled as part of the DCF analysis. Net present values were calculated on an ungeared after tax basis using nominal after tax discount rates of 7.25-7.75%. The results of the NPV analysis for DBCT are set out below:

DBCT – NPV Outcomes ($ millions) Discount Rate NPV 7.25% 2,318 7.50% 2,257 7.75% 2,199

The NPV range in the above table is consistent with Grant Samuel’s valuation range for DBCT. Grant Samuel has not undertaken sensitivity analysis on the operating cash flows of DBCT. The 100% take or pay nature of DBCT’s customer contracts means that DBCT has no exposure to potential fluctuations in customer throughput or volumes through the terminal during the contract period. Other than corporate costs that are provided for in the regulated revenue return, all other operating costs of DBCT (which are incurred by the contracted terminal operator) are wholly passed through to customers via the terminal handling charge. Essentially, the net cash flows from DBCT should be largely fixed. Moreover, the regulatory framework for DBCT means that changes in costs of capital or the expected life of the asset should be reflected in tariff adjustments, such that the economic value of the asset is essentially preserved. Net Borrowings Grant Samuel has assumed net borrowings of $1,601.6 million for DBCT for the purpose of the valuation, comprising gross borrowings of $1,689.9 million and cash of $88.3 million. Other Liabilities The mark to market value of DBCT’s interest rate hedges as at 31 August 2009 of $17.4 million (loss) has been included in the valuation.

6.5.4 WestNet Rail

Summary Grant Samuel has valued BBI’s 96% interest in WestNet Rail in the range $88-146 million. This value is based on an estimate of the equity value for 100% of WestNet Rail in the range $92-152 million.

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WestNet Rail - Valuation Summary ($ millions) Value Range

Asset Low High

Value of WestNet Rail business operations 700.0 760.0 WestNet Rail net borrowings (598.8) (598.8) Other liabilities (9.1) (9.1)

Value of 100% of equity in WestNet Rail 92.1 152.1 Value of 96% of equity in WestNet Rail 88.4 146.0

Grant Samuel has valued WestNet Rail having regard to DCF analysis and multiples of EBITDA. Earnings Multiple Analysis Grant Samuel’s estimate of the enterprise value of WestNet Rail in the range $700-760 million implies the following multiples of earnings:

WestNet Rail – Implied EBITDA Multiples Value Range

Parameter ($ millions) Low High

Enterprise value range (100%) ($ millions) 700 760 Multiple of EBITDA Year ended 30 June 2009 (actual) 103.6 6.8 7.3 Year ending 30 June 2010 (forecast) 107.0 6.5 7.1 Year ending 30 June 2011 (forecast) 115.0 6.1 6.6

Grant Samuel has reviewed these implied multiples having regard to the EBITDA multiples implied by the share market values of comparable listed entities and transaction values involving rail transport and infrastructure entities or assets.

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Sharemarket Ratings of Selected Listed Entities80 EBITDA Multiple81

(times) Entity

Market Capital- isation

($ millions) Historical Forecast Year 1

Forecast Year 2

Transport - Rail Australia

Asciano Limited $4,784.2 14.1 12.9 10.4 International

Canadian National Railway Co C$25,079.1 8.9 10.2 9.1

Canadian Pacific Railway Ltd C$8,563.9 8.4 8.8 8.2

Burlington Northern Santa Fe Corp US$27,725.5 7.0 7.5 7.1

Union Pacific Corp US$30,404.5 7.1 8.0 7.2

CSX Corp US$17,162.2 6.6 7.5 7.0

Norfolk Southern Corp US$16,345.1 5.3 7.2 6.4

Genesee & Wyoming Inc US$1,289.7 10.8 11.2 10.2

Kansas City Southern US$2,519.9 8.4 11.1 8.6 Source: Grant Samuel analysis (see Appendix 3)

A selection of relevant rail transactions since 2006 is set out below:

Recent Transaction Evidence

EBITDA Multiple83

(times) Date Target Transaction Consid- eration82 (millions)

Historical Forecast

June 2008 Freightliner Group Limited

Acquisition by Arcapita Bank BSC £200 5.9 na

September 2007

Dakota, Minnesota and Eastern Railroad Corporation Limited

Acquisition by Canadian Pacific Railway Limited US$1,480 na na

June 2007

English Welsh and Scottish Railway Holdings Limited

Acquisition by Deutsche Bahn AG £300 14.0 na

May 2007 Florida East Coast Industries, Inc.

Acquisition by Fortress Investment Group LLC US$3,500 33.8 na

November 2006 RailAmerica, Inc. Acquisition by Fortress Investment Group LLC US$1,100 18.1 na

March 2006

“Below Rail84” business of Australian Railroad Group Pty Ltd Acquisition by BBI $854 7.7 na

Source: Grant Samuel analysis (Refer Appendix 4) The implied multiples for WestNet Rail are generally consistent with the low end of the earnings multiples implied by the share market values of listed rail entities. They are low relative to the transaction multiples (multiples of 5.9-33.8 times forecast EBITDA). However, in Grant Samuel’s opinion the multiples implied by the valuation are reasonable as:

80 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 81 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at

the latest balance date) divided by EBITDA. 82 Implied enterprise value if 100% of the company or business had been acquired. 83 Represents gross consideration divided by EBITDA. 84 “Below rail” refers to track management whereas ‘above’ rail which refers to operators of train and rollingstock.

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WestNet Rail is subject to demand risk for its direct and indirect (through QR) customers. Haulage volumes are highly leveraged to grain production and demand for commodities. After strong growth in 2007 and early 2008, demand for commodities fell sharply. While there are signs of demand recovery in 2009, global economic growth prospects and expected growth in demand for commodities are subject to substantial uncertainty. WestNet Rail’s grain freight volumes will remain subject to a high degree of seasonality and to uncertain weather conditions;

while the development of new mines and the expansion of existing mines are expected to underpin growth in West Australian resources output, growth in rail volumes will also be dependent on the development of port and other transport infrastructure;

some caution must be exercised in comparing the earnings multiples implied by the market values of North American rail company multiples with those for an Australian below rail track operator. The majority of the North American entities are owners of both above and below rail operators. Companies with below rail operations typically trade on lower EBITDA multiples than pure above rail operators due to the larger capital expenditures required to support track networks. While the multiples for Asciano are higher than those implied by the valuation of WestNet Rail, Asciano is both an above rail operator and a port owner. Earnings multiples for above rail operators and port owners are typically higher than for below rail operators; and

a sales process for WestNet Rail was undertaken during the year ending 30 June 2009. While there was some indicative interest from potential bidders for the asset, the process did not result in a transaction. The indicative values received from interested parties are broadly consistent with the aggregate outcome of the base case DCF analysis.

DCF Analysis The DCF model for WestNet Rail is long term commencing at 1 September 2009 and extending for 40 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 10.00-10.50%. The aggregate outcome of the Base Case DCF analysis is net present values in the range of $642-678 million. This range is broadly consistent with Grant Samuel’s valuation range for WestNet Rail. The key drivers of NPV for WestNet Rail are tonnage transported, which is principally dependent on demand for grain and commodities out of Western Australia, movements in CPI and capital expenditure. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions:

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WestNet Rail – NPV Sensitivity Analysis ($ millions)

Discount Rate Sensitivity

10.50% 10.00%

Base case 642 678

Tonnage volume growth 1%pa higher for grain and freight and tonnage volume for commodities 1% higher than Base Case (throughout forecast period) Tonnage volume growth 1%pa lower for grain and freight and tonnage volume for commodities 1% lower than Base Case (throughout forecast period)

691

596

730

629

CPI 1% higher than Base Case (throughout forecast period) CPI 0.5% lower than Base Case (throughout forecast period)

690 620

731 654

Operating expenditure 2% higher than Base Case (throughout forecast period) Operating expenditure 2% lower than Base Case (throughout forecast period)

625 658

660 695

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

634 650

670 686

Perpetual growth rate 0.25% higher than Base Case Perpetual growth rate 0.25% lower than Base Case

642 642

678 678

The results of the sensitivity analysis indicate that:

the NPV is sensitive to volume changes. Revenues are protected to a limited extent with certain take or pay payments in several of the end customer contracts and flagfall charges in the access arrangements. However, the majority of contracts contain no such protection. In addition, the majority of costs in the business are fixed in nature. EBITDA margins will only improve as volume increase;

the NPV is sensitive to the growth in CPI. Under customer access agreements tariffs are charged on tonnage hauled with rates escalated at 100% or a proportion of CPI increases. As a result, a lower or higher CPI growth rate will increase or decrease the rate of growth in revenue due to the contractual pass through of CPI;

the NPV is sensitive to movements in capital expenditure. Maintenance and renewal obligations are mandated under the terms of the lease with the West Australian government. Expansionary or growth capital expenditure will be required to meet opportunities arising from mine expansions of current and new users, (although some capital expenditure may be recovered from the customer). If all capital expenditure on network upgrades is eliminated, NPVs in excess of $800 million are generated. This scenario is considered unlikely. Based on current negotiations with the Federal and WA State Government, capital expenditure required on the grain lines is expected to be substantially government funded or lines wound back; and

the NPV is not sensitive to movements in the perpetual growth rate. The model is a long term model therefore the terminal value represents a small proportion of the NPV.

Net Borrowings As at 31 August 2009 WestNet Rail had net borrowings of $598.8 million, comprising gross borrowings of $619.5 million and cash of $20.7 million. Other Assets and Liabilities The mark to market value of WestNet Rail’s interest rate hedges as at 31 August 2009 of $9.1 million (loss) has been included in the valuation.

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6.5.5 Euroports

Summary Grant Samuel has valued BBI’s various interests in Euroports in the range €146-176 million, which equates to a value of $247-298 million, based on an exchange rate of A$1.00 = €0.59:

Euroports - Valuation Summary (€ millions)

Value Range Asset

Low High Value of Euroports business operations (60% interest) 465.6 495.6 Attributable Euroports net borrowings (256.2) (256.2) Other liabilities (19.4) (19.4)

Value of 60.03% of equity in Euroports 190.0 220.0

Holding company net borrowings (43.8) (43.8)

Value of 60.03% interest in Euroports 146.2 176.2

The Euroports portfolio was acquired and developed over recent years pursuant to a strategy to develop a pan-European, multi-product ports business. To date, Euroports has had limited opportunity to achieve any synergies and each of the businesses within its portfolio has been operated autonomously. Further, the business has been burdened by significant gearing. On this basis, it is difficult to make judgements regarding the medium to longer term future for the business as a whole with any confidence. A broad range of credible scenarios for Europort’s longer term prospects can be developed, with widely varying implications for the value of Europort’s business. In this context, the recent sale of up to 40% of Euroports to Antin and Arcus provides extremely useful market-based evidence as to value. The valuation of Euroports has been prepared on the assumption that the convertible note held by Antin will be converted, thus reducing BBI’s interest in Euroports to 60.03%. Grant Samuel’s valuation of Euroports also takes into account valuation evidence from EBITDA multiples analysis and discounted cash flow analysis. Earnings Multiple Analysis Grant Samuel’s estimate of the enterprise value of Euroports in the range €466-496 million implies the following multiples of earnings:

Euroports – Implied EBITDA Multiples Value Range

Parameter (€ millions) Low High

Enterprise value range (60%) (€ millions) 466 496 Multiple of EBITDA Year ended 30 June 2009 (actual) 39.4 11.8 12.6 Year ending 30 June 2010 (forecast) 45.4 10.3 10.9 Year ending 30 June 2011 (forecast) 50.6 9.2 9.8

Grant Samuel has reviewed these implied multiples having regard to EBITDA multiples for comparable listed entities and transactions involving port entities or assets in Europe (refer to Section 6.5.2).

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The implied multiples for Euroports are generally consistent with trading of port entities, but low in comparison to comparable transactions. In Grant Samuel’s opinion these multiples are reasonable as:

the most recent transaction for Euroports with Antin and Arcus implied a value for 100% of the equity of Euroports of €353 million and a forecast 2010 EBITDA multiple of 10.7 times;

while the transaction evidence shows that significantly higher multiples were paid for ports businesses in the past, these transactions were completed in a very different market environment, characterised by easy access to cheap debt and equity. Asset values have declined significantly over the last two years;

the structure of the Euroports business, which includes two joint venture structures and multiple debt packages at the level of subsidiary assets, is likely to be a deterrent to potential acquirers of the business;

the Euroports business is essentially a portfolio of medium sized port operators, generally with dominant market positions. Its earnings and cash flows are however less predictable than those of regulated port assets with long term take or pay contracts. On the other hand, the Euroports business does have some upside, as the forecast earnings do not reflect any potential synergies or other benefits that could be derived from stabilising and integrating the disparate operations. Management attention to date has focussed on material corporate issues rather than on operations; and

there are no listed companies directly comparable to Euroports in terms of geographic spread and diversity of customer base and cargo.

DCF Analysis The DCF models for Euroports are long term models, commencing at 1 September 2009 and extending for 20 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 9.25-9.75%. The aggregate outcome of the DCF analysis is net present values in the range of €535-586 million. This represents the sum of the individual net present values calculated for each of the Euroports businesses. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions:

Euroports – NPV Sensitivity Analysis (€ millions) Discount Rate

Sensitivity 9.75% 9.25%

Base Case 535 586

Revenues 2% higher than Base Case (throughout forecast period) Revenues 2% lower than Base Case (throughout forecast period)

609 460

666 506

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

480 590

527 645

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

530 539

581 591

Perpetual growth rate 0.25% higher than Base Case Perpetual growth rate 0.25% lower than Base Case

540 530

593 580

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The results of the sensitivity analysis indicate that:

the NPV is highly sensitive to movements in revenue and operating costs. The largest operating cost of the business is labour (which is variable). Further, fixed costs tend to comprise a relatively small proportion of revenue, particularly concession costs; and

the NPV is not particularly sensitive to movements in capital expenditure or the perpetual growth rate. In respect of capital expenditure, this is because the projections only assume a minimum level of growth capital expenditure within each of the Euroports businesses, given the financial position of the business and the desire to stabilise and integrate the existing operations before embarking on new projects. The nature of the port operations means there are relatively low levels maintenance capital expenditure required and any significant maintenance capital works which is undertaken tends to be lumpy as certain assets (such as cranes) are replaced.

Grant Samuel’s estimate of the enterprise value of Euroports in the range €466-496 million represents a significant discount to the calculated NPVs. The DCF analysis essentially ignores the complex structure of Euroports, including risks associated with the potential dilution of BBI ownership, and any negative effect it may have on the value of the business. The valuation reflects a judgement that in the current market environment there are few potential acquirers of Euroports, and that potential acquirers or investors would require higher returns than assumed in the DCF analysis. This is consistent with the value realised through BBI’s recent sale of an effective 40% interest in Euroports. Net Borrowings As at 31 August 2009, the various Euroports businesses had net borrowings of €443.7 million (on a proportionate basis). Based on an equity holding of 60.03%, net borrowings of €256.2 million are attributable to BBI, comprising gross borrowings of €322.0 million and cash of €65.8 million. In addition, at the Euroports holding company level there are further borrowings of €43.8 million. Other liabilities The mark to market value of Europort’s interest rate hedges as at 31 August 2009 of €19.4 million (loss) has been included in the valuation.

6.5.6 PD Ports

Summary Grant Samuel has valued BBI’s equity interest in PD Ports in the range £0-12 million, which equates to a value of A$0-21 million, based on an exchange rate of A$1.00 = £0.55:

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PD Ports - Valuation Summary (£ millions) Value Range

Asset Low High

Value of PD Ports business operations 300.0 330.0 PD Ports net borrowings (315.0) (315.0) Other liabilities (2.6) (2.6) Value of equity in PD Ports - 12.4

BBI undertook a comprehensive sales process during 2009 to identify a purchaser for its PD Ports business, given the short term maturity of certain tranches of debt in the business and an inability of BBI to provide funding to meet these maturities. A very wide array of parties were approached to undertake due diligence and submit indicative proposals. The indicative proposals received in the first phase of the process all implied reasonable equity values. However, following the announcement by major customer Corus that it was considering closing its plant, BBI prepared a revised set of financial projections to take account of the potential impact on the earnings of PD Ports, and asked prospective purchasers to resubmit bids. No bids higher than PD Ports’ net borrowings were received, implying zero value for the equity in PD Ports. This sale process provides the most reliable evidence as to the current market value of PD Ports. In addition, Grant Samuel has assessed the value of PD Ports having regard to capitalisation of earnings and by reference to the results of discounted cash flow analysis. Earnings Multiple Analysis The estimated enterprise value for PD Ports of £300-330 million implies the following multiples:

PD Ports – Implied EBITDA Multiples Value Range

Parameters (£ millions) Low High

Enterprise value range (£ millions) 300 330 Multiple of EBITDA Year ended 30 June 2009 (actual) 32.6 9.2 10.1 Year ending 30 June 2010 (forecast) 35.5 8.5 9.3 Year ending 30 June 2011 (forecast) 40.9 7.3 8.1

Grant Samuel has reviewed these implied multiples having regard to EBITDA multiples for comparable listed entities and transactions involving port entities or assets in Europe (refer Section 6.5.2). The implied multiples of prospective earnings for PD Ports are low when compared with the earnings multiples implied by the share market values of port operators and the prices at which comparable transactions have completed. However, in Grant Samuel’s opinion these multiples are reasonable as:

the sales process undertaken by BBI provides the most reliable valuation measure for PD Ports. On the basis of indicative offers received for the business, PD Ports has no equity value. Grant Samuel’s valuation range, and the multiples implied by Grant Samuel’s range, are consistent with bids received through this process;

while significantly higher multiples were paid for ports businesses in the past, this was in a different market environment when there was relatively easy access to debt and capital markets to fund transactions;

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PD Ports is forecasting earnings growth for 2010 and 2011. However, analysis of listed port operators suggests that for many ports the market expects earnings to decline. Arguably, a market based assessment of value for PD Ports would assume as a starting point that PD Ports is at risk of a decline in earnings;

in particular, the earnings forecasts for PD Ports assume that PD Ports will be able to substantially mitigate the loss of major business volumes from Corus. In part, this is based on generating replacement business through the development of port-based retail distribution facilities. To date PD Ports has had some success with this strategy, attracting major retailers ASDA and Tesco. The continued success of this strategy will be dependent upon attracting other large retailers and the associated multiplier effect created by having ships delivering goods into port for multiple customers. However, given the uncertainties associated with the British economy and the inherent risks associated with developing what is effectively a new business, in Grant Samuel’s view potential acquirers of PD Ports are unlikely to factor any material earnings growth into their assessments of value; and

there are no listed companies that have operations directly comparable to those of PD Ports. Forth Ports Plc, operating predominantly in Scotland, is perhaps the company most comparable to PD Ports.

DCF Analysis The DCF model for PD Ports is a long term model commencing at 1 September 2009 and extending for 20 years. Net present values were calculated on an ungeared after tax basis using a nominal after tax discount rate of 9.75-10.25%. The aggregate outcome of the DCF analysis is net present values in the range of £404-434 million. Grant Samuel has undertaken an analysis of the sensitivity of the net present value to movements in key assumptions:

PD Ports – NPV Sensitivity Analysis (£ millions) Discount Rate

Sensitivity 10.25% 9.75%

Base ase 404 434

Revenues 2% higher than Base Case (throughout forecast period) Revenues 2% lower than Base Case (throughout forecast period)

427 381

459 409

Operating costs 2% higher than Base Case (throughout forecast period) Operating costs 2% lower than Base Case (throughout forecast period)

390 418

419 449

Capital expenditure 2% higher than Base Case (throughout forecast period) Capital expenditure 2% lower than Base Case (throughout forecast period)

402 406

432 436

Perpetual growth rate 0.25% higher than Base Case Perpetual growth rate 0.25% lower than Base Case

406 402

436 431

The results of the sensitivity analysis indicate that:

the NPV is highly sensitive to movements in revenue and operating costs. The largest operating cost of the business is labour (which is variable); and

the NPV is not particularly sensitive to movements in capital expenditure or the perpetual growth rate. In respect of capital expenditure, this is because the projections only assume a minimum level of growth capital expenditure, particularly if it is not underwritten through new contracted revenue streams. The nature of the

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port operations means there are relatively low levels of maintenance capital expenditure required.

Grant Samuel’s estimate of the enterprise value of PD Ports in the range £300-330 million represents a significant discount to the calculated NPVs. The DCF analysis essentially assumes that PD Ports will achieve strong growth in earnings over the next two years, notwithstanding the loss of a significant volume of business from Corus. For the reasons set out above, there are clear risks associated with the achievement of this earnings growth. The valuation reflects a judgement that in the current market environment potential acquirers of PD Ports would be likely to attribute only limited value to the expectations of earnings growth. The recent sales processes for PD Ports conducted by BBI effectively demonstrated that potential acquirers of the business applied significant discounts to theoretical DCF values. Net Borrowings As at 31 August 2009, PD Ports had borrowings of £315.0 million and no cash. Other Liabilities The mark to market value of PD Port’s interest rate hedges as at 31 August 2009 of £2.6 million (loss) has been included in the valuation.

6.6 Corporate Costs

BBI’s unallocated corporate costs are budgeted at around $28 million per annum. These costs represent costs associated with running BBI’s head office and include:

the BBI executive office (such as costs associated with the offices of the Managing Director and Chief Financial Officer, company secretarial and legal, planning and development, corporate affairs, treasury, tax etc.);

being a listed company and trust (such as director fees, annual reports and shareholder communications, share registry and listing fees, distribution processing and fees to the responsible entity of the trust etc.); and

certain group shared services (such as human resources, information technology etc.) not fully recharged to the business operations during the year.

The valuations of BBI’s assets do not reflect corporate costs. Therefore, separate allowance has been made for corporate costs. The values of BBI’s assets have been estimated on the basis of full underlying value, that is the value that could be realised through a takeover of BBI or through the orderly sale of the assets. An acquirer of BBI could potentially realise very significant savings of corporate costs. However, some level of costs would remain and would need to be assumed by the acquirer. Alternatively, if BBI’s assets were realised in an orderly fashion over a period of some years, it is likely that some of the corporate costs would effectively need to be assumed by acquirers of the individual assets, while other corporate costs would run down over time as the asset portfolio was liquidated. It is difficult to estimate with any precision what the likely level and rate of cost savings would be in this scenario. Grant Samuel has incorporated in its valuation of BBI a provision of $100-150 million in respect of corporate costs, representing the capitalised value of corporate costs that might remain following the acquisition of BBI, or, alternatively, the costs that might be incurred in an orderly realisation of the assets of BBI, including those that might be assumed by acquirers of BBI’s assets. This is a relatively wide range but reflects the uncertainty inherent in any assumption as to how BBI’s assets might be realised.

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6.7 Corporate Net Borrowings

BBI’s net borrowings for valuation purposes are $1,165 million as at 31 August 2009:

BBI – Corporate Net Borrowings for Valuation Purposes $ millions

Borrowings (1,201.1) Cash 36.2

Net borrowings 1,164.9

6.8 Other Liabilities

BBI has mark to market losses on swaps of $97 million as at 31 August 2009, which relate to interest rate swaps on BBI’s corporate debt.

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7 Evaluation of the Recapitalisation

7.1 Conclusion

BBI needs to take urgent action to address its financial position. BBI has very high levels of debt, both at a corporate level and at a subsidiary asset level. Its most pressing need is to finance the repayment of approximately $300 million85 of corporate debt that matures in February 2010. BBI has pursued asset sales as a way of reducing debt and, in the short term, addressing its February 2010 corporate debt maturity obligations. However, it has become apparent that asset sales will not achieve the values required. BBI has no choice but to raise new equity. The Recapitalisation will provide a comprehensive solution to BBI’s financial position. It will allow the repayment of all of BBI’s corporate debt (excluding approximately NZ$119 million of New Zealand corporate bonds) and the resumption of distribution payments to holders of Securities. The Recapitalisation will also crystallise (at least to some extent) the uncertain values currently attributable to holders of Securities, EPS and SPARCS. Holders of Securities will receive a Capital Distribution of 4 cents per Security, totalling approximately $104 million. Following the conversion of EPS into Securities, current holders of Securities will be heavily diluted. They will hold a trivial percentage of the expanded Securities on issue and will have only very limited exposure to any future upside in BBI. Holders of EPS will receive their accrued dividends totalling $48 million and will hold the vast majority of the 16% of Securities (post the Recapitalisation) attributable to current holders of Securities and EPS. Based on the equity values implied by the terms of the Recapitalisation, these Securities should have value of around $285 million. Holders of EPS (along with new investors, including the Cornerstone Investor) will be exposed to any future upside in BBI. Holders of SPARCS will enjoy a significant improvement in their position, as the value of their interests (which have a total face value of around $100 million) will effectively be supported by the $1.5 billion of new equity to be injected under the Recapitalisation. Analysis of the Recapitalisation from the perspective of current holders of Securities is relatively straight-forward. BBI needs to raise significant new amounts equity. In the absence of the Recapitalisation or some similar equity raising, it is conceivable (but by no means certain) that BBI could raise sufficient funds through asset sales to meet its February 2010 maturity commitments. However, BBI would continue to be financially vulnerable, and there could be no assurance that equity markets would continue to provide an opportunity to raise significant amounts of new equity. At worst, in the absence of the Recapitalisation or other equity raising, BBI could enter some form of insolvency administration. This would almost certainly result in holders of Securities realising zero value for their interests in BBI. The directors of BBI have considered an alternative proposal (“RBS Proposal”) from a consortium headed by Royal Bank of Scotland (“RBS”) and concluded that the RBS Proposal is inferior to the Recapitalisation. Given BBI’s requirement for new equity, and the absence of any superior alternative, holders of Securities will be better off if the Recapitalisation proceeds than if it does not. Evaluation of the Cornerstone Placement and Sub-underwriting requires an assessment of the underlying value attributable to holders of Securities. However, attribution of underlying value to holders of Securities is not straightforward. Grant Samuel’s valuation suggests that there is a real risk that no underlying value would be available for holders of Securities after taking into account the face value of EPS and SPARCS. In this context, allocation of underlying value

85 £82.2 million or approximately $169 million is due in February 2010 although under the cash sweep mechanism agreed with the

BBI corporate lenders, BBI will be required to repay approximately $300 million in corporate debt to meet this debt maturity in February 2010.

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between holders of Securities, EPS and SPARCS is to some extent judgemental. Grant Samuel has considered two bases for this allocation. On the basis that the value allocation assumes that holders of EPS and SPARCS have absolute priority to value, the underlying value attributable to holders of Securities would be 0-14 cents. On the basis that EPS and SPARCS were assumed to convert into Securities assuming a volume weighted average price of Securities of 5 cents, the underlying value attributable to holders of Securities would be 3-6 cents. The value to be realised by holders of Securities through the Capital Distribution of 4 cents per Security falls within the ranges of value attributed to the Securities (depending on the basis of assessment, either 0-14 cents or 3-6 cents per Security). Accordingly, in Grant Samuel’s view the Cornerstone Placement and Sub-underwriting are fair. Because they are fair, they are also reasonable to the holders of Securities. Given the valuation analysis set out above, in Grant Samuel’s opinion the Recapitalisation is fair. The terms of the Asset Acquisitions are generally consistent with terms that might be concluded with third parties. In the absence of the Recapitalisation, there would be a real risk that BBI would ultimately be placed in some form of insolvency administration, in which case holders of Securities would almost certainly realise no value. Accordingly, in Grant Samuel’s view the Recapitalisation is fair and reasonable having regard to the interests of holders of Securities, in the absence of a superior alternative proposal. Analysis of the Recapitalisation from the perspective of current holders of EPS is more complex. If the Recapitalisation (or some similar equity raising) did not proceed and BBI consequently entered some form of insolvency administration, it appears likely that holders of EPS would recover no value (although, given that they have priority relative to the holders of Securities, the prospect of their realising at least some value cannot be absolutely ruled out). Based on the values implied by the Recapitalisation, holders of EPS will collectively realise value of approximately $333 million (through the payment of accrued dividends and their holdings of Securities). This is clearly a better outcome than the potential alternative of ranking behind corporate debt providers in an insolvency administration. It represents a substantial premium to the market value of the EPS, which was approximately $150 million when BBI went into trading halt prior to the announcement of the Recapitalisation. On the other hand, the Recapitalisation also crystallises a significant loss for holders of the EPS relative to their face value of $779 million (although holders of EPS will retain some exposure to upside in BBI’s asset base through their holding of Securities). Holders of EPS have to compare the relatively certain value that they will receive if the Recapitalisation proceeds (notwithstanding that it is a significant discount to the face value of the EPS) with the potential loss of all of their investment value if the Recapitalisation does not proceed. In Grant Samuel’s view holders of EPS are likely to be better off if the Recapitalisation proceeds than if it does not. A secondary question for holders of EPS is whether the Recapitalisation is equitable in the sense of fairly sharing the residual equity value between holders of Securities, EPS and SPARCS. There are no clear guidelines as to what constitutes “fairness” in this context. Arguably, given that they would rank last in any form of insolvency value realisation process and would almost certainly realise no value, holders of Securities have the weakest claim to any equity value. In this context it could be argued that holders of Securities are receiving a disproportionate share of value. However, holders of Securities will need to realise some non-trivial value for any restructuring to proceed. It appears that holders of SPARCS have a good prospect of realising the face value of their investments, and on that basis will achieve a better outcome than holders of EPS. In an absolute sense, on the other hand, given the modest total face value of the SPARCS, any value transfer is limited. In addition, any attempt to limit the amount of value that accrues for the benefit of the holders of SPARCS would effectively need their approval, increasing transaction risk. The reality is that there is a need to balance the competing interests of the different sets of security holders with the practical imperative of minimising transaction risk and delivering at least some value to the holders of Securities, EPS and SPARCS. On balance (and having regard to the consequences if the Recapitalisation does not proceed), Grant Samuel believes that the

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allocation of value as between holders of Securities, EPS and SPARCS is broadly fair. Grant Samuel has therefore concluded that the Recapitalisation is fair and reasonable having regard to the interests of holders of EPS.

7.2 BBI’s Financial Position

BBI’s rapid growth during the 2006 to 2008 period involved the assumption of significant debt. With the onset of the global financial crisis, BBI’s asset values have fallen. In some cases underlying asset performance has declined. Debt providers have become far more risk averse and are seeking to reduce debt exposures wherever possible. At 31 August 2009, BBI had $8.0 billion in total proportionate non-recourse debt at the asset level and a further $1.2 billion in corporate debt facilities. In the case of a number of asset level debt facilities, lenders have commenced to “sweep” all available free cash flows or subsidiary companies have decided to devote all free cash flows to debt reduction. The result for these assets is that surplus cash flows are no longer available to BBI to service its corporate debt facilities. At the corporate level, BBI faces debt maturities of $731 million over the two years ending 30 June 2011, of which approximately $300 million is due in February 2010. BBI does not have the cash resources to fund this payment and its forecasts show that it will generate essentially no free cash at a corporate level over the period to February 2010. Accordingly, BBI needs to take urgent action to raise the cash required to meet its February 2010 maturity commitments. There is a very real risk that a failure to meet these commitments would result in some form of insolvency appointment.

7.3 Effect of the Recapitalisation

The Recapitalisation will provide a comprehensive solution to BBI’s financial position. All of BBI’s corporate debt (excluding the New Zealand corporate bonds) will be repaid and some pressing asset level debt will also be repaid. BBI will effectively be able to cut free subsidiary assets that have nil or limited value (such as PD Ports, CSC and AET&D) and it will be clear that BBI will not provide any further support to the relevant entities. BBI expects that it will be able to resume payment of income distributions (although there can be no guarantees in this regard). BBI’s structure will be simplified and BBI’s operations and prospects should be considerably easier to understand from the perspective of investors and analysts. The stabilisation of BBI’s financial position, the simplification of the capital structure and the issue of new shares under the Institutional Placement and SPP should improve BBI’s trading liquidity and attract new investor interest. On the other hand, BBI will have lost exposure to any upside associated with the 49.9% economic interest in DBCT that is to be transferred to Brookfield. It will not participate in any recovery in the value of AET&D or PD Ports. BBI will still have substantial debt at a subsidiary asset level, although it will be free of the assets that currently have unsustainable debt levels.

7.4 Alternatives to the Recapitalisation

BBI has pursued a strategy of asset sales over the past 12 months, including the sale of a 58% stake in Powerco New Zealand and a 40% stake in the Euroports portfolio. However, it has become apparent that further asset sales are not a viable strategy for addressing BBI’s financial position:

BBI’s experience is that it is very difficult to realise reasonable values in the current market environment, especially when BBI is perceived as a distressed seller. Asset divestment costs are in some cases significant. For assets that are heavily geared, BBI would generally realise little or no value on divestment;

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in certain cases shareholder agreements preclude asset sales or are likely to significantly hamper sales processes and therefore reduce the amounts realisable; and

BBI has run a sale process for DBCT, which is BBI’s most valuable “unencumbered” asset available for sale. The value indications received through that process are such that the reduction in debt achievable by the sale would not be sufficient to offset the loss of earnings from the asset. In fact, the loss of earnings would be such that BBI would immediately become in breach of forward looking interest cover covenants on its corporate debt facilities. This situation is likely to apply to other assets theoretically available for sale.

It is conceivable (although probably unlikely) that BBI could raise sufficient proceeds through asset sales to meet its February 2010 maturity commitments, without in that process breaching corporate debt covenants. However, that would leave BBI in a highly vulnerable financial position, with further corporate debt maturities due later in 2010 and early in 2011 and a diminished stock of assets available for sale. While deferral by a further twelve months of a comprehensive solution to its financial position could provide some opportunity for a recovery of asset values and an improvement in credit markets, BBI would also be exposed to the risk that current favourable equity market conditions would not persist. In any event, given the impending corporate debt maturities facing BBI in February 2010, there is real doubt as to whether material asset sales could be completed within the limited time available. There is presumably at least some possibility that BBI could negotiate some form of debt moratorium with its bankers. However, such a course of action would be inevitably risky and there could be no certainty of success. The reality is that BBI will need to raise significant new equity over the next twelve months. Given the risks associated with the deferral of an equity raising, it is clear that BBI has no realistic choice but to pursue a substantial equity raising as soon as possible. BBI has had various informal approaches regarding potential equity injections, but has received only one formal proposal other than the Recapitalisation proposal. On 17 September 2009, BBI received a refinancing proposal from The Royal Bank of Scotland (“RBS”), acting on behalf of an investor group comprising primarily international hedge funds. BBI and its advisers engaged with RBS to seek further clarification and received an updated proposal (the “RBS Proposal”) on 28 September 2009. The RBS Proposal provided for the repayment of BBI’s corporate debt through: the issue of $300 million of senior notes. These notes were to be repaid at a substantial

premium to face value, such that the holders of the notes would achieve internal rates of return of 20-25%;

the issue of $450 million of convertible bonds, which would have a five year term and

conversion rights at around recent Securities prices (i.e. 5-6 cents);

the raising of $500 million of new equity, of which half was to be provided from the investor group and the balance was to be sourced from existing holders of Securities;

a new $250 million corporate debt facility, which was to be only partially drawn.

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On 30 September 2009 BBI announced that it would not proceed with the RBS Proposal, on the basis that it had formed the view that the RBS Proposal is less attractive than the Recapitalisation. Assessment of the RBS Proposal involves the consideration of a number of factors, including: the RBS Proposal would achieve a deferral of BBI’s short term debt maturity obligations.

However, it would result in the injection of relatively little new equity (particularly after taking transaction costs into account) and would not meaningfully improve BBI’s overall financial position;

the new senior and convertible notes that formed part of the RBS Proposal would be

relatively costly;

there could be no guarantee of any re-rating of BBI listed securities, given that there would be no capacity to resume distributions and potential further dilution of Securities;

there would be risks associated with the raising of the additional $250 million of new equity

from existing holders of Securities. Given the limited amount of new equity to be introduced, the cost of the debt and convertible note funding and the potential further dilution of holders of Securities through the ultimate conversion of the convertible notes, there could be no certainty that it would be possible to raise $250 million from existing holders of Securities; and

the RBS Proposal would entail substantial execution risks. Agreements would need to be

reached with all of the members of the RBS investor group, all of whom would need to satisfactorily complete due diligence within a limited timeframe.

For these reasons, in Grant Samuel’s view the Recapitalisation is significantly more attractive than the RBS Proposal. Given BBI’s extensive asset portfolio, the likely complexity of any recapitalisation proposal and the limited time now available to BBI, it appears unlikely that any proposal superior to the Recapitalisation will become available to BBI.

7.5 Impact of the Conversion of EPS

If the Recapitalisation proceeds, EPS will be converted into Securities. The number of Securities to be issued will be calculated by dividing the face value of the EPS ($779 million) by the volume weighted average price (“VWAP”) of Securities for the 20 trading days ending on 10 November 2009, after adjusting the VWAP for a 7.5% discount. The VWAP will also be adjusted by subtracting the amount of the Capital Distribution ($0.04 per Security). The terms of the EPS are proposed to be amended to include a cap and collar for the conversion process, such that the maximum and minimum adjusted VWAPs for the purposes of the conversion (after adjusting for the Capital Distribution) will be 0.2 cents and 0.1 cents, to exclude the risk of manipulative outcomes and also reflecting the minimum price at which securities can trade on ASX. The terms of the Recapitalisation (in which Brookfield will inject $625 million for a 35% interest, excluding the Sub-underwriting of the SPP) imply a value of $286 million for the 16% of the Securities after the Recapitalisation that will be held collectively by current holders of Securities and EPS. The following table shows the number of Securities to be held by current holders of EPS after the conversion, and the sharing of the $286 million between holders of EPS and current holders of Securities:

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Impact of EPS Conversion VWAP (cents) 0.2 0.1 Securities issued on conversion of EPS (billions) ($779 million ÷ (VWAP x 92.5%))

421.081 99.4%

842.162 99.7%

Securities currently on issue (billions) 2.592 0.6%

2.592 0.3%

Value attributable to holders of EPS ($ millions) 284 285 Value attributable to current holders of Securities ($ millions)

2 1

Total implied value of 16% Securities 286 286

The result will be that the holders of EPS will capture almost all the value attributable to the 16% of the Securities after the Recapitalisation that will be held collectively by current holders of Securities and EPS. Grant Samuel has assumed for the purpose of its analysis that of the total implied value of $286 million available to holders of Securities and EPS, the value attributable to the holders of EPS will be approximately $285 million.

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7.6 Underlying Value Attributable to Securities

There is no clear basis for determining the underlying value attributable to Securities. The EPS and SPARCS, which have an aggregate face value of $879 million, rank ahead of the Securities on a winding up of BBI. Arguably, for estimates of underlying value of less than $879 million, no underlying value should be attributed to the Securities. Valuing the Securities on the basis that they rank for value behind the EPS and SPARCS would suggest a range of underlying values for the Securities of 0-14 cents per Security:

Underlying Value Attributable to Securities Assuming Securities rank behind EPS and SPARCS ($ millions)

Low High Estimated net asset value of BBI 668 1,242 Face value of EPS (779) (779) Face value of SPARCS (100) (100) (Deficiency)/Surplus (211) 363 Underlying value attributable to Securities - 363 Underlying value per Security ($) - 0.14

The mid-point of Grant Samuel’s valuation range for BBI would imply an underlying value attributable to holders of Securities of $76 million (i.e. the mid-point of $(211) million and $353 million), which equates to 3 cents per Security. The assumption that the EPS and SPARCS should rank ahead of Securities is appropriate for a winding-up. However, the reality is that BBI is not being wound up. It is by no means clear that EPS and SPARCS should have absolute priority and potentially capture all value in circumstances in which BBI is not wound up but will continue. An alternative approach to estimating the underlying value attributable to the Securities is to assume the conversion of all EPS and SPARCS into Securities and the sharing of underlying value on a pro-rata basis. The following table assumes conversion on the basis of a VWAP of 5 cents (approximating recent Security prices):

Underlying Volume Attributable to Securities Assuming Conversion of EPS and SPARCS

Low High No of Securities issued on conversion of EPS ($779 million ÷ ($0.05 x 92.5%)) (billions)

16.843 16.843

No of Securities issued on conversion of SPARCS ($100 million ÷ ($0.05 x 97.5%)) (billions)

2.051 2.051

Securities currently on issue (billions) 2.592 2.592 Total Securities on issue post-conversion (billions) 21.486 21.486 Proportion attributable to current Securities 12.1% 12.1% Estimated net asset value ($ millions) 668 1,242 Underlying value attributable to current holders of Securities ($ millions)

81 150

Underlying value per Security ($) 0.03 0.06

This analysis suggests underlying values in the range 3-6 cents per Security. The attribution of underlying value to holders of Securities on the basis of an assumed conversion of EPS and SPARCS is somewhat circular. It is arguable that Securities have only traded at prices around 5 cents in expectation of some form of restructuring that would deliver at least some value to holders of Securities. This essentially represents the optionality of the position of holders of Securities. In Grant Samuel’s view there would be a risk that the

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Securities would trade lower if it became apparent that no restructuring opportunity was available. Moreover, given the conversion dynamics, in which conversion at current prices would result in further dilution of the value attributable to holders of Securities, Securities would theoretically trade towards zero if holders of Securities were aware of an impending conversion. These arguments are broadly in favour of a conclusion that very little underlying value should be attributed to holders of Securities. On the other hand, holders of Securities do have legal rights in their capacity as holders of Securities. These legal rights are in some sense valuable. They include rights that flow from corporate regulatory requirements. For example, the approval of holders of Securities is required for the issue to Brookfield of Securities representing more than 20% of total Securities on issue. Holders of Securities have an effective right of veto in relation to the Recapitalisation. While the analogy is not perfect, there are precedents from the corporatisation of mutual organisations in which real economic value was delivered to members in satisfaction of the extinguishment of their rights. These precedents suggest that at least some value should be attributed to holders of Securities. In Grant Samuel’s view, while the exercise is largely theoretical, some underlying value should be attributed to holders of Securities. At least for the purpose of assessing the impact of the Cornerstone Placement and Sub-Underwriting on holders of Securities, the attribution of underlying value in the range 3-6 cents appears on balance reasonable.

7.7 Evaluation of the Cornerstone Placement and Sub-underwriting

A conventional analysis of whether a proposal is “fair and reasonable” for the purposes of Section 611 (7) (where a party acquires a shareholding of more than 20% without making a takeover offer) involves two separate elements: an assessment as to whether the proposal is “fair”, based on a comparison of the price at

which the new shareholder is acquiring or subscribing for shares with the estimated underlying value of existing shares; and

an assessment as to whether the proposal is “reasonable” , which can involve a judgement as

to whether it is in shareholders’ best interests to vote in favour of a proposal notwithstanding that it is not “fair”.

Application of this framework to analysing the Cornerstone Placement and Sub-underwriting is problematic. The price at which Securities are to be issued to Brookfield has yet to be determined. The number of Securities to be issued on conversion of the EPS will be in the range 421,081-842,162 million Securities (for VWAPs in the range 0.2 cents to 0.1 cents.) If it is assumed that no SPARCS are converted in the interim, then 926,785-1,847,900 million new Securities will need to be issued to Brookfield to lift its holding to 35%. This will imply issue prices of (roughly) 0.03-0.07 cents per Security. It is not meaningful to compare this issue price with a pre-Recapitalisation estimate of underlying value for the Securities. The large number of Securities to be issued to Brookfield (and therefore the very low issue price) is a direct result of the amended terms for the conversion of EPS into Securities. This in turn reflects the structuring of the Recapitalisation to deliver value to holders of Securities by way of the Capital Distribution but also to ensure that holders of Securities do not realise any significant value in excess of the amount of the Capital Distribution. More generally, it is not meaningful to compare the issue price with an estimate of the underlying value for the Securities without taking into account the Capital Distribution of 4 cents per Security. The conventional Section 611 (7) analysis essentially seeks to determine whether shareholders are in some way compensated for a loss of control through the payment by the new substantial shareholder of a price corresponding to full underlying value. In the case of the

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Recapitalisation, however, holders of Securities will receive the Capital Distribution as their principal compensation for their “loss of control”. This Capital Distribution will be paid out of proceeds from (and could not be paid in the absence of) the Cornerstone Placement and other elements of the Equity Raising. In Grant Samuel’s view in these circumstances it is not meaningful to assess the Cornerstone Placement and Sub-underwriting without taking into account the Capital Distribution. Holders of Securities are receiving value of 4 cents per Security, by comparison with estimates of underlying value for the Securities of 0-14 cents (on the basis that EPS and SPARCS take priority in terms of the realisation of value) or 3-6 cents (on the basis of notional conversion of the EPS and SPARCS at a VWAP for the Securities of 5 cents). On either basis holders of Securities are realising value within the estimated range of underlying values for the Securities. Grant Samuel believes the concept of “fairness” in the context of the Recapitalisation is of limited utility. However, to the extent that the concept is meaningful, in Grant Samuel’s view the Cornerstone Placement and Sub-underwriting are fair having regard to the interests of holders of Securities. In any event, whatever judgements are made regarding fairness, the Cornerstone Placement and Sub-underwriting are clearly reasonable. BBI urgently needs to raise substantial amounts of new equity. The Cornerstone Placement is a key part of the Equity Raising, which is likely to be substantially more difficult to achieve in its absence. In the absence of the Equity Raising there is at least some risk that BBI will face some insolvency event, which would almost certainly result in holders of Securities losing all value. Under the Recapitalisation current holders of Securities will in aggregate realise $104 million through the Capital Distribution and some very modest further value on account of their diluted holding of Securities. Holders of Securities will be better off if the Cornerstone Placement proceeds than if it does not. Overall, Grant Samuel has concluded that the Cornerstone Placement and Sub-underwriting are fair and reasonable having regard to the interests of holders of Securities.

7.8 Evaluation of the Asset Acquisitions

Pursuant to the proposed Asset Acquisitions, Brookfield will be acquiring: a 49.9% economic interest in DBCT for $295 million; and

all of BBI’s interests in PD Ports, for nominal consideration.

In addition, Brookfield will provide management services to the AET&D and CSC assets subject to supervision of the boards of the relevant entities and have the right to acquire BBI’s interest in these assets for nominal consideration. Grant Samuel has valued a 100% interest in DBCT in the range $581-681 million. This reflects, amongst other valuation evidence, the results of the sale process that BBI ran for DBCT during 2009. The price to be paid by Brookfield for a 49.9% economic interest in DBCT is consistent with this valuation range. Moreover, the proposals that BBI received through its sale process for DBCT would have resulted in BBI realising significantly less than the face value of the offers and significantly less than Brookfield will pay for its 49.9% economic interest, given transaction costs and various retention amounts. On the other hand, under the arrangements whereby BBI will sell a 49.9% economic interest to Brookfield, BBI will remain liable for various contingent liabilities and for stamp duty if Brookfield converts its economic interests into shares and units in the relevant DBCT entities. In certain circumstances either Brookfield or BBI will be entitled to procure the sale of 100% of DBCT (or if the other party proposes to sell, the option to acquire 100% of DBCT). These arrangements are set out in more detail in section 13.6.4 of the Prospectus. While these arrangements are on balance disadvantageous for BBI, the reality is that the creation of an

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effective joint venture over DBCT would always involve some diminution in BBI’s rights to deal with DBCT on an unfettered basis. Overall, the arrangements in relation to DBCT will result in BBI realising value equal to current market value and receiving significantly more cash than if DBCT was to be sold to a third party. In Grant Samuel’s view the terms of the transaction are, overall, no less advantageous than those that would apply to a sale to an arm’s length third party. Grant Samuel has estimated that the full underlying value of BBI’s interest in AET&D is in the range $48-148 million. This represents the estimated value that could be realised for the underlying assets of AET&D on a “willing buyer/willing seller” basis”, less the debt in the AET&D structure. It essentially assumes away the financing risk in the AET&D structure. However, the reality is that AET&D is financially distressed, with surplus cash flow being retained at an individual asset level to service asset level debt facilities, and insufficient free cash flow available to support a re-financing of the AET&D corporate debt facility of $518 million. In these circumstances BBI is unlikely to be able to realise the theoretical full underlying value of its interest in AET&D. Moreover, Grant Samuel’s valuation of the AET&D assets does not take into account potential transaction costs, which in the case of some of the assets could result in a significant reduction in net realisations. In Grant Samuel’s view there would be at least some prospect that BBI would realise zero value for its interest in AET&D in the current market. BBI’s interest in AET&D may have some positive value for Brookfield, given that the debt is limited recourse and that Brookfield will have exposure to any asset value recovery. However, in the absence of the Recapitalisation or some other restructuring, this optionality is unlikely to have any value for BBI: instead values are more likely to be crystallised such that all value is captured by the relevant lenders and there is no residual value for BBI. BBI will provide an indemnity to Brookfield in respect of the management fees payable by AET&D to Brookfield. Even in a worst case outcome in which the indemnity was called upon in full, the liability would not be material in the context of the overall Recapitalisation. Grant Samuel’s assessment is that BBI’s interests in PD Ports and CSC have values of around zero, with asset level debt matching or exceeding current market values for the relevant assets. In Grant Samuel’s view BBI is unlikely to be able to achieve any significant value for its interests in PD Ports and CSC through transactions with arm’s length third parties. In Grant Samuel’s view the terms of the Asset Acquisitions are, overall, consistent with those that would be concluded with third parties, although arguably there is the prospect that some value may be transferred to Brookfield through the arrangements relating to AET&D. However, any value transfer is not likely to be material. In any event, the Asset Acquisitions are an integral part of the Recapitalisation, which is urgently required to address BBI’s pressing financial position.

7.9 Impact of the Restructuring on Holders of Securities

Grant Samuel has concluded that the Cornerstone Placement and Sub-underwriting are fair and reasonable to holders of BBI Securities. The terms of the Asset Acquisitions are generally consistent with terms that might be concluded with third parties. Under the Recapitalisation, holders of Securities will realise cash value totalling $104 million, although their future exposure to any recovery in the value of BBI will be minimal. Given the extent of the dilution of current holders of Securities through the conversion of the EPS and the Equity Raising, the Recapitalisation will result in current holders of Securities having no more than a trivial ongoing interest in BBI. In Grant Samuel’s view there would be a real risk, if the Recapitalisation did not proceed, that BBI would end up in some form of insolvency administration. Accordingly, while the value of Securities in the absence of the Recapitalisation is uncertain, it could well be zero. On this basis, holders of Securities will be better off if the Recapitalisation proceeds than if it does not.

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Control of BBI will pass to Brookfield, at least in part. Brookfield will have a minimum holding of 35% and up to 39.9%, which will effectively prevent any change of control transaction without Brookfield’s approval. On the other hand Brookfield will have only limited day to day influence over the operation of BBI. It will have three non-executive directors on the Board of directors, but will not appoint the Chairman or Chief Executive. Given that current holders of Securities will have limited exposure to BBI following the Recapitalisation (as a result of the wholesale dilution of their interests following the conversion of EPS), other advantages and disadvantages of the Recapitalisation are not material. BBI would be liable to pay Brookfield up to $7.5 million (in relation to external costs incurred by Brookfield) if the Recapitalisation was not approved. Overall, Grant Samuel believes that holders of Securities will be better off if the Recapitalisation proceeds than if it does not. In Grant Samuel’s view the Recapitalisation is fair and reasonable to holders of Securities.

7.10 Impact of the Recapitalisation on Holders of EPS

Given BBI’s financial position, BBI urgently needs to raise fresh equity. As a practical matter any equity raising is likely to seek to circumscribe the value attributable to holders of EPS, because the alternative would be a significant value transfer from the providers of new equity to holders of EPS. A threshold issue for holders of EPS is whether the value attributable to the EPS under the Recapitalisation exceeds the value likely to be available under the most likely alternative. In Grant Samuel’s view, in the absence of the Recapitalisation there is a meaningful risk that BBI will end up in some form of insolvency administration. It is difficult to estimate with any confidence what values might accrue for the benefit of holders of EPS in this circumstance. However, in Grant Samuel’s view it is highly likely that the values realised for BBI’s assets would be well below the full underlying values estimated in Grant Samuel’s valuation of BBI. In Grant Samuel’s view there would be a real prospect that holders of EPS would realise no value for their securities (although it is conceivable that they could realise at least some value). Based on the values implied by the terms of the Recapitalisation, holders of EPS will receive value of around $333 million (consisting of Securities with an implied value of $285 million and cash dividends of $48 million). This is significantly less than the face value of the EPS of $779 million. However, it represents a substantial premium to the market value of the EPS, which was approximately $150 million when BBI went into trading halt prior to the announcement of the Recapitalisation. In addition, holders of EPS will get the benefit of any re-rating of Securities after the Recapitalisation. Holders of EPS effectively have to compare the delivery of relatively certain value if the Recapitalisation proceeds, albeit at a substantial discount to the face value of the EPS, with the potential loss of all of their investment value if the Recapitalisation does not proceed. This comparison is essentially judgemental, because the future value of Securities following the Recapitalisation is not certain, and because there is a wide range of outcomes for holders of EPS if the Recapitalisation does not proceed and BBI enters some form of insolvency administration. In Grant Samuel’s view, the relative certainty provided by the Recapitalisation, notwithstanding that it does crystallise a loss of value, is preferable to the risk of more substantial value destruction for holders of EPS if the Recapitalisation does not proceed. A secondary question for holders of EPS is whether the Recapitalisation is equitable in the sense of fairly sharing the residual equity value between holders of Securities, EPS and SPARCS. There are no clear guidelines as to what constitutes “fairness” in this context. In the ordinary course the claims of holders of EPS and SPARCS against the asset values of BBI are clearly defined. The value entitlement of EPS and SPARCS is limited to their face value, and rank ahead of the Securities in the context of a winding up. However, value allocation on that basis in

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the current circumstance is not practical, given the limited total value available and the need to deliver at least some value to holders of Securities, EPS and SPARCS if any recapitalisation is to proceed. Arguably, given that they would rank last in any form of insolvency value realisation process and would almost certainly realise no value, holders of Securities have the weakest claim to any equity value. In this context it could be argued that holders of Securities are receiving a disproportionate share of value. However, holders of Securities do have a range of legal rights in their capacity as holders of Securities. These rights cannot simply be expropriated or extinguished for no compensation. At a practical level, holders of Securities could not be expected to vote in favour of a restructuring that delivered nil or only trivial value to them. Similarly, the BBI directors, given their fiduciary duties, could not be expected to put forward a proposal that delivered nil or trivial value to holders of Securities. It appears that holders of SPARCS have a good prospect of realising the face value of their investments, and on that basis will achieve a better outcome than holders of EPS. In an absolute sense, on the other hand, given the modest total face value of the SPARCS, any value transfer is limited. Moreover, any attempt to limit the amount of value delivered to holders of the SPARCS would require an amendment to the rights of the holders of the SPARCS, which would in turn require that the Recapitalisation be made subject to the approval of the holders of SPARCS. This would increase the level of transaction risk with only relatively modest potential benefits for holders of EPS. Holders of SPARCS could also argue that in any scenario for BBI (including an insolvency event) they would have a reasonable prospect of realising the face value of their securities, the value of which is supported by the equity value in Powerco. The reality is that there is a need to balance the competing interests of the different sets of security holders with the practical imperative of minimising transaction risk and delivering at least some value to the holders of Securities, EPS and SPARCS. On balance (and having regard to the consequences if the Recapitalisation does not proceed), Grant Samuel believes that the allocation of value as between holders of Securities, EPS and SPARCS is broadly fair. The majority of the value to be realised by holders of EPS through the Recapitalisation will be by way of the conversion of their EPS into Securities. Holders of EPS will collectively hold almost all of the 16% of BBI Securities not held by new investors. At the values implied by the terms of the Equity Raising, these Securities will have a face value of around $285 million. Accordingly, the structure and prospects of BBI following the Recapitalisation are also a relevant factor in assessing the benefits of the Recapitalisation for holders of EPS. The Recapitalisation will provide a comprehensive solution to BBI’s financial position. All of BBI’s corporate debt (excluding the New Zealand corporate bonds) will be repaid and some pressing asset level debt will also be repaid. BBI will effectively be able to cut free subsidiary assets that clearly have no value (such as PD Ports and CSC) and the effective deconsolidation of AET&D will simplify the group, including from the perspective of investors. Holders of BBI Securities, including current holders of EPS, will be exposed to any upside in the BBI asset base that might result from an improvement in debt and equity markets or underlying economic conditions. BBI will be a substantially more attractive investment, given: BBI’s capital structure will be simplified and stabilised as a result of the conversion of the

EPS and the injection of substantial new equity; it is expected that BBI will have the capacity to recommence income distributions (although

there are no guarantees in this regard); and

the issue of new Securities through the Equity Raising should improve trading liquidity. For these reasons there is at least some prospect of a market re-rating of Securities following the Recapitalisation.

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On the other hand, holders of EPS (as holders of Securities after the Recapitalisation) will have lost their exposure to any potential recovery in value in the AET&D asset portfolio. Their investment exposure to DBCT will be reduced and may be further affected if Brookfield exercises its right to trigger a 100% sale in the future and BBI is not in a position to purchase their interest. At a corporate level, Brookfield’s position on the register, with a holding of Securities of at least 35% and up to 39.9%, will mean that there can be no takeover of BBI without Brookfield’s approval and will limit trading liquidity (although there is currently limited trading liquidity in BBI securities). While it will not have outright control, with only three non-executive directors on the board and no right to appoint the Chairman or senior executives, Brookfield will clearly be in a position to influence the future direction of BBI. BBI will still have substantial debt at the underlying asset level, although this debt is non-recourse to BBI. BBI will continue be exposed to the underlying performance of its asset portfolio, currency and interest rate risk, re-financing risk and other risks. The future trading price of BBI Securities could be affected by these and numerous other factors, including broader economic conditions and equity and debt market performance. Accordingly, there can be no assurance regarding the future trading price of Securities. The price of Securities could fall as well as rise. Total transaction costs associated with the Recapitalisation (including the Equity Raising) are estimated at $105 million. Of these, costs in the approximate range of $25-35 million will be incurred regardless of whether the Recapitalisation proceeds. BBI will incur the remaining costs only if the Recapitalisation proceeds. In Grant Samuel’s view holders of EPS are likely to be better off if the Recapitalisation proceeds than if it does not. Grant Samuel has therefore concluded that the Recapitalisation is fair and reasonable having regard to the interests of holders of EPS.

7.11 Decisions for Holders of Securities and EPS

The decision whether to vote for or against the Recapitalisation is a matter for individual holders of BBI Securities and EPS, based on each holder’s views as to value, their expectations about future market conditions and their particular circumstances including risk profile, liquidity preference, investment strategy, portfolio structure and tax position. In particular, taxation consequences may vary from holder to holder. If in any doubt as to the action they should take in relation to the Recapitalisation, holders of Securities and EPS should consult their own professional adviser. Similarly, it is a matter for individual investors as to whether to buy, hold or sell Securities or EPS in BBI or whether to participate in the Equity Raising. This is an investment decision independent of a decision on whether to vote for or against the Recapitalisation. Grant Samuel does not offer any opinion in relation to this investment decision. Holders of Securities and EPS should consult their own professional adviser in this regard.

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8 Qualifications, Declarations and Consents

8.1 Qualifications

The Grant Samuel group of companies provide corporate advisory services (in relation to mergers and acquisitions, capital raisings, debt raisings, corporate restructurings and financial matters generally), property advisory services, manages specialist funds and provides marketing and distribution services to fund managers. The primary activity of Grant Samuel & Associates Pty Limited is the preparation of corporate and business valuations and the provision of independent advice and expert’s reports in connection with mergers and acquisitions, takeovers and capital reconstructions. Since inception in 1988, Grant Samuel and its related companies have prepared more than 415 public independent expert and appraisal reports. The person responsible for preparing this report on behalf of Grant Samuel is Stephen Cooper. The persons responsible for the relevant asset descriptions and valuations on behalf of Grant Samuel are Jaye Gardner, Marisa Leone, Melinda Snowden, Dan Gerber and Tina De Young. Each has a significant number of years of experience in relevant corporate advisory matters. Hannah Crawford, Nooshin Valmadre, Melinda Robertson, Shakeel Mohammed and Chapman Li assisted in the preparation of the report. Each of the above persons is an authorised representative of Grant Samuel pursuant to its Australian Financial Services Licence under Part 7.6 of the Corporations Act.

8.2 Disclaimers

It is not intended that this report should be used or relied upon for any purpose other than as an expression of Grant Samuel’s opinion as to whether the Recapitalisation and the Cornerstone Placement and sub-underwriting, are fair and reasonable to the Securityholders. Grant Samuel expressly disclaims any liability to any BBI Securityholder who relies or purports to rely on the report for any other purpose and to any other party who relies or purports to rely on the report for any purpose whatsoever. This report has been prepared by Grant Samuel with care and diligence and the statements and opinions given by Grant Samuel in this report are given in good faith and in the belief on reasonable grounds that such statements and opinions are correct and not misleading. However, no responsibility is accepted by Grant Samuel or any of its officers or employees for errors or omissions however arising in the preparation of this report, provided that this shall not absolve Grant Samuel from liability arising from an opinion expressed recklessly or in bad faith. Grant Samuel has had no involvement in the preparation of the Prospectus or Explanatory Memorandum issued by BBI and has not verified or approved any of the contents of BBI’s Prospectus or Explanatory Memorandum. Grant Samuel does not accept any responsibility for the contents of the Prospectus or Explanatory Memorandum (except for this report).

8.3 Independence

Grant Samuel and its related entities do not have at the date of this report, and have not had within the previous two years, any shareholding in or other relationship with BBI or Brookfield that could reasonably be regarded as capable of affecting its ability to provide an unbiased opinion in relation to the Recapitalisation. Grant Samuel advises that:

Grant Samuel was appointed by Alinta in July 2007 to prepare an independent expert’s report in relation to the proposal by a consortium comprising Babcock & Brown International Pty Ltd (a wholly owned subsidiary of Babcock and Brown Limited) and Singapore Power International Pte Ltd to acquire Alinta; and

a Grant Samuel executive holds a parcel of around 160,000 shares in BBI. Grant Samuel commenced analysis for the purposes of this report in September 2009 prior to the announcement of the Recapitalisation on 8 October 2009. This work did not involve Grant

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Samuel participating in the setting the terms of, or any negotiations leading to, the Recapitalisation. Grant Samuel had no part in the formulation of the Recapitalisation. Its only role has been the preparation of this report. Grant Samuel will receive a fixed fee of $1,800,000 for the preparation of this report. This fee is not contingent on the outcome of the Recapitalisation. Grant Samuel’s out of pocket expenses in relation to the preparation of the report will be reimbursed. Grant Samuel will receive no other benefit for the preparation of this report. Grant Samuel considers itself to be independent in terms of Regulatory Guide 112 issued by the ASIC on 30 October 2007.

8.4 Declarations

BBI has agreed that it will indemnify Grant Samuel and its employees and officers in respect of any liability suffered or incurred as a result of or in connection with the preparation of the report. This indemnity will not apply in respect of the proportion of any liability found by a court to be primarily caused by any conduct involving gross negligence or wilful misconduct by Grant Samuel. BBI has also agreed to indemnify Grant Samuel and its employees and officers for time spent and reasonable legal costs and expenses incurred in relation to any inquiry or proceeding initiated by any person. Any claims by BBI are limited to an amount equal to the fees paid to Grant Samuel. Where Grant Samuel or its employees and officers are found to have been grossly negligent or engaged in wilful misconduct Grant Samuel shall bear the proportion of such costs caused by its action. Advance drafts of this report were provided to BBI and its advisers. Certain changes were made to the drafting of the report as a result of the circulation of the draft report. There was no alteration to the methodology, evaluation or conclusions as a result of issuing the drafts.

8.5 Consents

Grant Samuel consents to the issuing of this report in the form and context in which it is to be lodged with the ASX. Neither the whole nor any part of this report nor any reference thereto may be included in any other document without the prior written consent of Grant Samuel as to the form and context in which it appears.

8.6 Other

The accompanying letter dated 9 October 2009 and the Appendices form part of this report. Grant Samuel has prepared a Financial Services Guide as required by the Corporations Act. The Financial Services Guide is set out at the beginning of this report.

GRANT SAMUEL & ASSOCIATES PTY LIMITED 9 October 2009

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Appendix 1

Selection of Discount Rates 1 Overview

The following discount rates have been selected by Grant Samuel to apply to the forecast nominal ungeared after tax cash flows of the major businesses of Babcock and Brown Infrastructure Limited (“BBI”):

Discount Rates Business Operation Discount Rate Australian gas transmission assets 7.00-7.50% Australian gas distribution assets1 6.75-7.25% New Zealand gas and electricity distribution assets 7.25-7.75% Australian asset management services 11.50-12.00% United States transmission assets 5.75-6.25% United Kingdom distribution assets 7.75-8.25% Australian port 7.25-7.75% Australian rail 10.00-10.50% United Kingdom ports 9.75-10.25% European ports 9.25-9.75%

Different discount rates have been selected for each business unit because they have differing risk profiles. Selection of the appropriate discount rate to apply to the forecast cash flows of any business enterprise is fundamentally a matter of judgement. The valuation of an asset or business involves judgements about the discount rates that may be utilised by potential acquirers of that asset. There is a body of theory which can be used to support that judgement. However, a mechanistic application of formulae derived from that theory can obscure the reality that there is no “correct” discount rate. Despite the growing acceptance and application of various theoretical models, it is Grant Samuel’s experience that many companies rely on less sophisticated approaches. Many businesses use relatively arbitrary “hurdle rates” which do not vary significantly from investment to investment or change significantly over time despite interest rate movements. Valuation is an estimate of what real world buyers and sellers of assets would pay and must therefore reflect criteria that will be applied in practice even if they are not theoretically correct. Nevertheless, the starting point in determining discount rates is usually to analyse the cost of capital for participants in the relevant industry based on theoretical models. The discount rates that Grant Samuel has adopted are reasonable relative to the rates derived from theoretical models. The discount rates represent an estimate of the weighted average cost of capital (“WACC”) appropriate for these assets. Grant Samuel has calculated a WACC based on a weighted average of the cost of equity and the cost of debt. This is the relevant rate to apply to ungeared cash flows. There are three main elements to the determination of an appropriate WACC. These are:

cost of equity;

cost of debt; and

debt/equity mix. WACC is a commonly used basis but it should be recognised that it has shortcomings in that it:

1 Except for Tas Gas, for which Grant Samuel has selected a discount rate of 7.00-7.50% to reflect its mix of gas distribution and retail

business operations.

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represents a simplification of what are usually much more complex financial structures; and

assumes a constant degree of leverage which is seldom correct. The cost of equity has principally been derived from application of the Capital Asset Pricing Model (“CAPM”) methodology. However, regard was also had to other methods such as the implied cost of equity based on the Gordon Growth Model (or perpetuity formula). The CAPM is probably the most widely accepted and used methodology for determining the cost of equity capital. There are more sophisticated multivariate models which utilise additional risk factors but these models have not achieved any significant degree of usage or acceptance in practice. However, while the theory underlying the CAPM is rigorous the practical application is subject to shortcomings and limitations and the results of applying the CAPM model should only be regarded as providing a general guide. There is a tendency to regard the rates calculated using CAPM as inviolate. To do so is to misunderstand the limitations of the model. For example:

the CAPM theory is based on expectations but uses historical data as a proxy. The future is not necessarily the same as the past;

the measurement of historical data such as risk premia and beta factors is subject to very high levels of statistical error. Measurements vary widely depending on factors such as source, time period and sampling frequency;

the measurement of beta is often based on comparisons with other companies. None of these companies is likely to be directly comparable to the entity for which the discount rate is being calculated and may operate in widely varying markets;

parameters such as the debt/equity ratio and risk premium are based on subjective judgements; and

there is not unanimous agreement as to how the model should adjust for factors such as taxation. The CAPM was developed in the context of a “classical” tax system. Australia’s system of dividend imputation has a significant impact on the measurement of net returns to investors.

In this context, regulators undertake extremely detailed analysis of discount rate calculations and each of the relevant variables. Grant Samuel has had regard to this analysis (particularly in relation to BBI’s businesses) but in Grant Samuel’s view it can give a misleading impression of the precision about what is, in reality, a relatively crude tool of unproven accuracy that gives, at best, a broad approximation of the cost of capital. In addition, the market upheaval of the last 18 months has seen a repricing of risk by investors as evidenced by lower earnings multiples implied for both listed companies and acquisitions. The CAPM methodology does not readily allow for these types of events. The addition of further premiums (sometimes referred to as alpha factors), while a practical approach, is inconsistent with the CAPM methodology. An alternative is to consider the cost of equity under the Gordon Growth Model (where the cost of equity equals the forecast dividend yield plus long term growth). The cost of debt has been determined by reference to the pricing implied by the debt markets in Australia, United States, United Kingdom and Europe. The cost of debt represents an estimate of the expected future returns required by debt providers. In determining the appropriate cost of debt over this forecast period, regard was had to debt ratings of comparable companies. Selection of an appropriate debt/equity mix is a matter of judgement. The debt/equity mix represents an appropriate level of gearing, stated in market value terms, for the business over the forecast period. The relevant proportions of debt and equity have been determined having regard to the financial gearing of the industry in general and comparable companies, and judgements as to the appropriate level of gearing considering the nature and quality of the cash flow stream.

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The following sections set out the basis for Grant Samuel’s determination of the discount rates for BBI’s businesses and the factors which limit the accuracy and reliability of the estimates.

2 Definition and Limitations of the CAPM and WACC

The CAPM provides a theoretical basis for determining a discount rate that reflects the returns required by diversified investors in equities. The rate of return required by equity investors represents the cost of equity of a company and is therefore the relevant measure for estimating a company’s weighted average cost of capital. CAPM is based on the assumption that investors require a premium for investing in equities rather than in risk free investments (such as government bonds). The premium is commonly known as the market risk premium and notionally represents the premium required to compensate for investment in the equity market in general. The risks relating to a company or business may be divided into specific risks and systematic risks. Specific risks are risks that are specific to a particular company or business and are unrelated to movements in equity markets generally. While specific risks will result in actual returns varying from expected returns, it is assumed that diversified investors require no additional returns to compensate for specific risk, because the net effect of specific risks across a diversified portfolio will, on average, be zero. Portfolio investors can diversify away all specific risk. However, investors cannot diversify away the systematic risk of a particular investment or business operation. Systematic risk is the risk that the return from an investment or business operation will vary with the market return in general. If the return on an investment was expected to be completely correlated with the return from the market in general, then the return required on the investment would be equal to the return required from the market in general (i.e. the risk free rate plus the market risk premium). Systematic risk is affected by the following factors:

financial leverage: additional debt will increase the impact of changes in returns on underlying assets and therefore increase systematic risk;

cyclicality of revenue: projects and companies with cyclical revenues will generally be subject to greater systematic risk than those with non-cyclical revenues; and

operating leverage: projects and companies with greater proportions of fixed costs in their cost structure will generally be subject to more systematic risk than those with lesser proportions of fixed costs.

CAPM postulates that the return required on an investment or asset can be estimated by applying to the market risk premium a measure of systematic risk described as the beta factor. The beta for an investment reflects the covariance of the return from that investment with the return from the market as a whole. Covariance is a measure of relative volatility and correlation. The beta of an investment represents its systematic risk only. It is not a measure of the total risk of a particular investment. An investment with a beta of more than one is riskier than the market and an investment with a beta of less than one is less risky. The discount rate appropriate for an investment which involves zero systematic risk would be equal to the risk free rate. The formula for deriving the cost of equity using CAPM is as follows: Re = Rf + Beta (Rm – Rf) where: Re = the cost of equity capital; Rf = the risk free rate; Beta = the beta factor; Rm = the expected market return; and Rm - Rf = the market risk premium.

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The beta for a company or business operation is normally estimated by observing the historical relationship between returns from the company or comparable companies and returns from the market in general. The market risk premium is estimated by reference to the actual long run premium earned on equity investments by comparison with the return on risk free investments. The formula conventionally used to calculate a WACC under a classical tax system is as follows: WACC = (Re x E/V) + (Rd x (1-t) x D/V) where: E/V = the proportion of equity to total value (where V = D + E); D/V = the proportion of debt to total value; Re = the cost of equity capital; Rd = the cost of debt capital; and t = the corporate tax rate. The models, while simple, are based on a sophisticated and rigorous theoretical analysis. Nevertheless, application of the theory is not straightforward and the discount rate calculated should be treated as no more than a general guide. The reliability of any estimate derived from the model is limited. Some of the issues are discussed below:

Risk Free Rate Theoretically, the risk free rate used should be an estimate of the risk free rate in each future period (i.e. the one year spot rate in that year if annual cash flows are used). There is no official “risk free” rate but rates on government securities are typically used as an acceptable substitute. More importantly, forecast rates for each future period are not readily available. In practice, the long term Commonwealth Government Bond rate is used as a substitute in Australia and medium to long term Treasury Bond rates are used in the United States. It should be recognised that the yield to maturity of a long term bond is only an average rate and where the yield curve is strongly positive (i.e. longer term rates are significantly above short term rates) the adoption of a single long term bond rate has the effect of reducing the net present value where the major positive cash flows are in the initial years. The long term bond rate is therefore only an approximation. The ten year bond rate is a widely used and accepted benchmark for the risk free rate. Where the forecast period exceeds ten years, an issue arises as to the appropriate bond to use. While longer term bond rates are available, the ten year bond market is the deepest long term bond market in Australia and is a widely used and recognised benchmark. There is a very limited market for bonds of more than ten years. In the United States, there are deeper markets for longer term bonds. The 30 year bond rate is a widely used benchmark. However, long term rates accentuate the distortions of the yield curve on cash flows in early years. In any event, a single long term bond rate matching the term of the cash flows is no more theoretically correct than using a ten year rate. More importantly, the ten year rate is the standard benchmark used in practice. Where cash flows are less than ten years in duration the opposite issue arises. An argument could be made that shorter term, and therefore lower, bond rates should be used in determining the discount rate for there assets. While Grant Samuel believes this is a legitimate argument, an adjustment may give a misleading impression of precision for the whole methodology. In any event, the impact on valuation would usually be trivial. In practice, Grant Samuel believes acquirers would use a common rate. The ten year bond rate can be regarded as an acceptable standard risk free rate for medium to long term cash flows, particularly given its wide use.

Market Risk Premium The market risk premium (Rm - Rf) represents the “extra” return that investors require to invest in equity securities as a whole over risk free investments. This is an “ex-ante” concept. It is the

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expected premium and as such it is not an observable phenomenon. The historical premium is therefore used as a proxy measure. The premium earned historically by equity investments is calculated over a time period of many years, typically at least 30 years. This long time frame is used on the basis that short term numbers are highly volatile and that a long term average return would be a fair indication of what most investors would expect to earn in the future from an investment in equities with a 5-10 year time frame. In the United States it is generally believed that the premium is in the range of 5-6% but there are widely varying assessments (from 3% to 9%). Australian studies have been more limited but indicate that the long run average premium has been in the order of 6% using a geometric average (and is in the order of 8% using an arithmetic average) measured over more than 100 years of data2. Even an estimate based over a very long period such as 100 years is subject to significant statistical error. Given the volatility of equity market returns it is only possible to state that the “true” figure lies within a range of approximately 2-10% at a 95% confidence level (using the geometric average). In addition, the market risk premium is not constant and changes over time. At various stages of the market cycle investors perceive that equities are more risky than at other times and will increase or decrease their expected premium. Indeed, there are arguments being put forward at the present time that the risk premium is now lower than it has been historically. This view is reflected in the recent update of the Officer Study 3 which indicates that (based on the addition of 17 years of data to 2004) the long term arithmetic average has declined to 7.17% from 7.94%. In the absence of controls over capital flows, differences in taxation and other regulatory and institutional differences, it is reasonable to assume that the market risk premium should be approximately equal across markets which exhibit similar risk characteristics after adjusting for the effects of expected inflation differentials. Accordingly, it is reasonable to assume similar market risk premiums for first world countries enjoying political economic stability, such as Australia, New Zealand, the United States, Japan, the United Kingdom and various western European countries. In practice, market risk premiums of 5-7% are typically adopted in Australia.

Beta Factor The beta factor is a measure of the expected covariance (i.e. volatility and correlation of returns) between the return on an investment and the return from the market as a whole. The expected beta factor cannot be observed. The conventional practice is to calculate an historical beta from past share price data and use it as a proxy for the future but it must be recognised that the expected beta is not necessarily the same as the historical beta. A company’s relative risk does change over time. The appropriate beta is the beta of the company being acquired rather than the beta of the acquirer (which may be in a different business with different risks). Betas for the particular subject company may be utilised. However, it is also appropriate (and may be necessary if the investment is not listed) to utilise betas for comparable companies and sector averages (particularly as those may be more reliable). However, there are very significant measurement issues with betas which mean that only limited reliance can be placed on such statistics. Even measurement of historical betas is subject to considerable variation. There is no “correct” beta. For example:

• over the last three years BBI’s beta as measured by the Australian Graduate School of Management (“AGSM”) has varied between 0.08 and 2.67, and has increased considerably

2 See, for example, R.R. Officer in Ball, R., Brown, P., Finn, F. J. & Officer, R. R., “Share Market and Portfolio Theory: Readings and

Australian Evidence” (second edition), University of Queensland Press, 1989 (“Officer Study”) which was based on data for the period 1883 to 1987 and therefore was undertaken prior to the introduction of dividend imputation in Australia.

3 Gray, S. and Officer, R.R., “A Review of the Market Risk Premium and Commentary on Two Recent Papers: A Report prepared for the Energy Networks Association”, August 2005.

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over the last 12 months as BBI’s market capitalisation has declined (and its gearing has correspondingly increased); and

• the standard error of the AGSM’s estimate of BBI’s beta has generally been in the order of 0.35 meaning that for a beta of, say, 0.8, even at a 68% confidence level, the range is 0.45 to 1.15.

Debt/Equity Mix The tax deductibility of the cost of debt means that the higher the proportion of debt the lower the WACC, although this would be offset, at least in part, by an increase in the beta factor as leverage increases. The debt/equity mix assumed in calculating the discount rate should be consistent with the level implicit in the measurement of the beta factor. Typically, the debt/equity mix changes over time and there is significant diversity in the levels of leverage across companies in a sector. There is a tendency to calculate leverage at a point in time whereas the leverage should represent the average over the period the beta was measured. This can be difficult to assess with a meaningful degree of accuracy. The measured beta factors for listed companies are “equity” betas and reflect the financial leverage of the individual companies. It is possible to unleverage beta factors to derive asset betas and releverage betas to reflect a more appropriate or comparable financial structure. In Grant Samuel’s view this technique is subject to considerable estimation error. Deleveraging and releveraging betas exacerbates the estimation errors in the original beta calculation and gives a misleading impression as to the precision of the methodology. Deleveraging and releveraging is also incorrectly calculated based on debt levels at a single point in time. In addition, the actual debt and equity structures of most companies are typically relatively complex. It is necessary to simplify this for practical purposes in this kind of analysis. Finally, it should be noted that, for this purpose, the relevant measure of the debt/equity mix is based on market values not book values.

Specific Risk The WACC is designed to be applied to “expected cash flows” which are effectively a weighted average of the likely scenarios. To the extent that a business is perceived as being particularly risky, this specific risk should be dealt with by adjusting the cash flow scenarios. This avoids the need to make arbitrary adjustments to the discount rate which can dramatically affect estimated values, particularly when the cash flows are of extended duration or much of the business value reflects future growth in cash flows. In addition, risk adjusting the cash flows requires a more disciplined analysis of the risks that the valuer is trying to reflect in the valuation. However, it is also common in practice to allow for certain classes of specific risk (particularly sovereign and other country specific risks) in a different way by adjusting the discount rate applied to forecast cash flows.

3 Calculation of WACC

3.1 Cost of Equity Capital

The cost of equity capital has been estimated by reference to the CAPM. Grant Samuel has adopted a cost of capital of:

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Cost of Equity Capital Business Operation Cost of Equity Capital Australian gas transmission assets 10.2-10.8% Australian gas distribution assets 10.2-10.8% New Zealand gas and electricity distribution assets 10.7-11.3% Australian asset management services 12.6-13.2% United States transmission assets 7.5-8.1% United Kingdom distribution assets 8.8-9.4% Australian port 11.4-12.0% Australian rail 11.4-12.6% United Kingdom ports 10.2-11.4% European ports 9.9-11.1%

The assumptions, judgements and estimates upon which the costs of equity were based are as follows:

Risk-Free Rate Grant Samuel has adopted a risk free rate of 5.4% for the Australian assets, 5.9% for the New Zealand assets, 3.6% for United Kingdom assets, 3.3% for other European assets and 3.3% for United States assets. The risk free rates approximate the current yield to maturity on ten year Australian Government bonds and ten year New Zealand Government bonds, ten year United Kingdom Government bonds, ten year German Government bonds, and ten year United States Government bonds respectively. For the United Kingdom distribution assets, which record earnings from the United Kingdom, Isle of Man and offshore islands, a 50:50 blended risk free rate of 4.6% was calculated, approximating the current yield to maturity on ten year United Kingdom government bonds and Isle of Man Government bonds. The forecast period for the cash flow models exceed ten years. However, ten year bonds are the accepted market benchmarks globally and are typically used as a proxy for the long term risk free rate even where the forecast period exceeds ten years.

Market Risk Premium Grant Samuel has consistently adopted a market risk premium of 6.0% for Australia, New Zealand, Europe, United Kingdom and United States and believes that, particularly in view of the general uncertainty, this continues to be a reasonable estimate. It is:

• not statistically significantly different to the premium suggested by the historical data;

• similar to that used by a wide variety of analysts and practitioners (typically in the range 5-7%); and

• the same as that adopted by most regulatory authorities in Australia. Some research analysts and other valuers may use even lower premiums. Overall, Grant Samuel believes 6.0% to be a reasonable, if not conservative, estimate.

Beta Factor Grant Samuel has adopted the beta factors in the following ranges for the purposes of valuing BBI’s business operations:

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Equity Beta Factors Business Operation Beta Factor Australian gas transmission assets 0.8-0.9 Australian gas distribution assets 0.8-0.9 New Zealand gas and electricity distribution assets 0.8-0.9 Australian asset management services 1.2-1.3 United States transmission assets 0.7-0.8 United Kingdom distribution assets 0.7-0.8 Australian port 1.0-1.1 Australian rail 1.0-1.2 United Kingdom ports 1.1-1.3 European ports 1.1-1.3

Grant Samuel has considered the beta factors for a wide range of companies in determining an appropriate beta. The betas have been calculated on two bases, relative to the entity’s local index and relative to the Morgan Stanley Capital International Developed World Index (“MSCI”), an international equities market index that is widely used as a proxy for the global stockmarket as a whole.

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A summary of betas for selected comparable listed entities is set out in the table below:

Equity Beta Factors for Selected Listed Entities

Monthly Observations over 4 years

Weekly Observations over 2 years

Bloomberg6 Bloomberg Entity

Market Capital- isation4

(A$ millions) AGSM5 Local

Index MSCI7 Local Index MSCI

BBI 137..4 2.67 1.84 2.04 2.74 2.55 Australian Transmission APA 1,590.7 0.70 0.81 0.79 0.74 0.59 Hastings Diversified Utilities Fund 478.9 0.33 0.57 0.91 0.98 0.90 Australian Distribution SP AusNet 2303.4 0.05 na na 0.40 0.33 Vector 1,544.8 na na na 0.73 0.50 DUET 1,439.1 0.93 0.86 0.87 0.69 0.53 Spark 1,165.0 0.42 na na 0.62 0.52 Envestra 764.6 0.80 0.95 0.99 0.63 0.66

Australian Services Worley Parsons 7207.7 2.19 1.61 1.41 1.60 1.17 United Group 2,520.0 1.38 1.27 1.16 1.07 0.83 Transfield Services 1,885.3 1.94 1.55 1.43 1.30 1.10 Monadelphous Group 1,165.0 1.85 1.52 1.37 1.08 0.92 WDS 236.7 1.93 na na 0.91 0.62 Norfolk Group 92.3 2.57 na na na na

United States Transmission TC Pipelines 1,905.5 na 0.60 0.61 0.81 0.93 Williams Pipeline Partners 737.0 na 0.25 0.36 0.84 0.99 Energy Transfer Partners 8,242.3 na 0.52 0.57 1.03 1.18 ONEOK Partners 5,824.5 na 0.47 0.52 0.84 0.98 El Paso Pipeline Partners 3,073.0 na 0.10 0.20 0.86 0.94 Spectra Energy Partners 2,296.3 na na 0.06 0.76 0.88 Boardwalk Pipeline Partners 5,197.7 na 0.05 0.07 0.84 0.94 United Kingdom Distribution Severn Trent PLC 4,193.9 na 0.39 0.39 0.75 0.80 Pennon Group PLC 3,036.1 na 0.38 0.50 0.71 0.75 Northumbrian Water Group PLC 2,358.9 na 0.09 0.17 0.64 0.67 United Utilities Group PLC 5,712.8 na 0.45 0.45 0.71 0.76

4 Based on share prices as at 29 September 2009 and in Australian dollars. Foreign exchange: AUDUSD: 0.8703, AUDGBP: 0.5457,

AUDCAD: 0.9441, AUDNZD: 1.2183, AUDCNY:6.004, AUDHKD: 6.8154, AUDMYR:3.057, AUDEUR: 0.6012 5 The Australian beta factors calculated by the Australian Graduate School of Management (“AGSM”) are as at 30 June 2009, over a

period of 48 months using ordinary least squares regression or the Scholes-Williams technique where the stock is thinly traded. AGSM betas are not available for United States or Canadian listed companies.

6 Bloomberg’s betas have been calculated up to 30 June 2009. Grant Samuel understands that betas estimated by Bloomberg are not calculated strictly in conformity with accepted theoretical approaches to the estimation of betas (i.e. they are based on regressing total returns rather than the excess return over the risk free rate). However, in Grant Samuel’s view the Bloomberg beta estimates can still provide a useful insight into the systematic risks associated with companies and industries. The figures used are the Bloomberg “adjusted” betas.

7 MSCI is calculated using local currency so that there is no impact of currency changes in the performance of the index.

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Scottish & Southern Energy 19,733.7 na 0.50 0.52 0.69 0.69

Australian Rail Asciano Group 4,784.2 na 3.81 3.78 1.64 1.18 Canadian National Railway 26,564.0 na 0.52 0.54 0.62 0.73 Canadian Pacific Railway 9,070.9 na 0.75 0.83 0.91 1.01 Burlington Northern Santa Fe 31,857.4 na 0.97 0.99 0.86 0.86 Union Pacific 34,935.7 na 1.13 1.12 0.92 0.95 CSX Corp 19,719.9 na 1.12 1.07 1.15 1.16 Norfolk Southern 18,781.0 na 1.09 1.06 1.12 1.16 Genesee & Wyoming 1,481.8 na 1.29 1.25 1.44 1.46 Kansas City Southern 2,895.4 na 1.32 1.41 1.59 1.68 Ports Shanghai International Port 18,220.7 na 1.06 1.06 0.95 -0.07 Shenzhen Chiwan Wharf Hldgs 1,073.6 na 0.71 0.92 0.73 0.17 Tianjin Port Company 3,148.9 na 0.82 0.91 0.87 -0.31 China Merchant Holdings (International) Company 9,516.1 na 1.27 1.80 1.55 1.62 Cosco Pacific Ltd 3,896.3 na 1.35 2.02 1.77 1.75 Bintulu Port Holdings Berhard 829.0 na 0.40 0.38 0.44 0.20 Dalian Port (PDA) Company Ltd 1,600.7 na 1.25 1.79 1.41 1.56 Forth Ports PLC 1,003.1 na 1.32 1.26 1.24 1.27 Lyttelton Port of Christchurch 201.6 na 0.20 0.10 0.13 0.14 South Port New Zealand Ltd 53.9 na 0.32 0.25 0.27 0.12 DP World Limited 10,578.0 na 0.76 2.52 0.59 1.46 Hamburger Hafen 3,680.9 na 1.66 1.93 1.10 1.28 Port of Tauranga Ltd 698.8 na 0.75 0.68 0.71 0.33

Source: AGSM, Bloomberg, IRESS The evidence suggests relatively low betas are appropriate for infrastructure assets. However, considerable caution is warranted in selecting a beta for BBI’s businesses:

• all of the data is subject to significant statistical error. For example, DUET Group’s (“DUET”) June 2009 AGSM beta has a standard error of 0.31 (i.e. even at a 68% confidence level it lies somewhere between 0.62 and 1.24) and BBI’s has a standard error of 0.35;

• in some cases there is a substantial difference between the beta measured by AGSM and the beta measured by using Bloomberg. There can also be substantial variations depending on the index used (Local or MSCI); and

• some of the entities involved in energy transmission and distribution infrastructure are relatively recently listed (three within the last four years) and, accordingly, limited reliable data is available for these entities.

Grant Samuel has selected a range for beta of 0.8-0.9 for BBI’s gas and electricity transmission and distribution infrastructure assets in Australia and New Zealand. A range of 0.8-0.9 is:

• is higher than the beta of 0.7 adopted by the Essential Services Commission (“ESC”), the Victorian regulator responsible for BBI’s interests in Multinet Gas in May 2008;

• is at the top end of or higher than the range of betas of 0.5-0.8 adopted by the Economic Regulation Authority (“ERA”) (the Western Australian regulator responsible for WA Gas Networks) in its draft decision in relation to Western Power (released in July 2009);

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• is consistent with the beta of 0.8 adopted by the Australian Energy Regulator (“AER”) in its May 2009 decision in relation to east coast electricity networks. While not directly comparable to BBI’s infrastructure assets, this decision is likely to set a benchmark for future AER decisions (the AER regulates the Dampier to Bunbury Natural Gas Pipeline and Multinet Gas);

• is lower than the betas of 0.98 and 1.2 adopted by the ERA in relation to its decisions in relation to the Dampier to Bunbury Natural Gas Pipeline and WA Gas Networks, although these decisions were in January and August 2005 respectively and are unlikely to represent current views on equity betas (refer to the ERA’s more recent decision above);

• is higher than the 0.7 level derived from empirical information by Allen Consulting Group (“Allens”) in its extensive studies on the gas industry betas8 and the electricity industry betas9 in Australia; and

• is consistent or higher than the majority of the evidence in the above table. To this extent the range of 0.8–0.9 for the gas and electricity transmission and distribution infrastructure assets in Australia and New Zealand can be considered conservative. For BBI’s Australian asset management business Grant Samuel has selected a beta in the range 1.2-1.3. This is lower than the betas of the listed peer group over the last four years, however it is conservative when compared to the data over the most recent two years. For BBI’s Australian rail assets Grant Samuel has selected a beta in the range of 1.0–1.2. This is relatively consistent with the average beta estimates of comparable rail operators around the world. Grant Samuel has selected a range for beta of 1.1 to 1.3 for BBI’s United Kingdom and other European port assets. The range of 1.1-1.3 adopted appears consistent with the weighed average beta estimates of comparable listed port operators around the world. For BBI’s United States transmission and United Kingdom distribution assets Grant Samuel has selected a range for beta of 0.7 to 0.8, which appears consistent with the weighted average beta estimates of comparable listed United States transmission assets around the world.

Cost of equity capital Using the estimates set out above, the cost of equity capital for each of the business operations can be calculated as follows:

Costs of Equity Capital

Business Operation Low High Formula Re = Rf + Beta(Rm-Rf) Re = Rf + Beta(Rm-Rf) Australian gas transmission assets = 5.4% + (0.9 x 6%)

= 10.8% = 5.4% + (0.8 x 6%) = 10.2%

Australian gas distribution assets = 5.4% + (0.9 x 6%)

= 10.8% = 5.4% + (0.8 x 6%) = 10.2%

8 Allen Consulting Group, “Empirical Evidence on Proxy Beta Values for Regulated Gas Transmissions Activities”, Final report for the

ACCC, July 2002, p.43. 9 Allen Consulting Group, “Electricity Networks Access Code 2004: Advance Determination of a WACC Methodology”, Report to the

Economic Regulation Authority Western Australia, January 2005, p.38.

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Costs of Equity Capital Business Operation Low High Formula Re = Rf + Beta(Rm-Rf) Re = Rf + Beta(Rm-Rf) New Zealand gas and electricity distribution assets = 5.4% + (0.9 x 6%)

= 10.8% = 5.4% + (0.8 x 6%) = 10.2%

Australian asset management services = 5.4% + (1.3 x 6%)

= 13.2% = 5.4% + (1.2 x 6%) = 12.6%

United States transmission = 3.3% + (0.8 x 6%)

= 8.1% = 3.3% + (0.7 x 6%) = 7.5%

United Kingdom distribution = ((3.62% x 50%) +

(5.63% x 50%))10 + (0.8 x 6%) = 9.4%

= ((3.62% x 50%) + (5.63% x 50%)) + (0.7 x 6%) = 8.8%

Australian port = 5.4% + (1.1 x 6%)

= 12.0% = 5.4% + (1.0 x 6%) = 11.4%

Australian rail = 5.4% + (1.2 x 6%)

= 12.6% = 5.4% + (1.0 x 6%) = 11.4%

United Kingdom ports = 3.6% + (1.3 x 6%)

= 11.4% = 3.6% + (1.1 x 6%) = 10.2%

European ports = 3.3% + (1.3 x 6%)

= 11.1% = 3.3% + (1.1 x 6%) = 9.9%

In addition, Grant Samuel considered the cost of capital relative to the implied cost of equity based on the Gordon Growth Model for the gas and electricity distribution networks and gas transmission assets. Essentially, Present Value = Dividends (Year 1) (or Price) Re - g where Re = cost of equity capital g = perpetual growth rate Turning this formula around: Re = Dividends + g Price In other words, the cost of equity capital is the current forecast yield plus the expected long term growth rate.

10 Reflects the 50:50 blended risk free rate, based on 10 year Government bond yields from the United Kingdom and Isle of Man

Government bond, used for United Kingdom distribution assets.

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Analysis of entities comparable to BBI’s gas and electricity distribution and transmission assets in Australia and New Zealand would suggest costs of capital in the range 13-14% (based on a median yield of 10.9% (with yields ranging from 9.7% to 12.4%) and growth of 2-3%. This analysis gives a cost of equity that is higher than the cost of equity calculated using CAPM (of 10-11%). However, considerable caution is warranted because of the difficulties of putting all the yields on a comparable basis (because of differing tax treatments).

3.2 Cost of Debt

A cost of debt of 7.4% has been adopted for the Australian assets, 7.9% for the New Zealand assets, 5.6% for United Kingdom assets, 5.3% for other European assets, 5.3% for United States transmission assets and 6.6% for United Kingdom distribution assets11. These figures represent the expected future cost of borrowing over the duration of the cash flow model. Grant Samuel believes that this would be a reasonable estimate of an average interest rate, including margin, that would match the duration of the cash flows assuming that the operations were funded with a mixture of short term and long term debt. The costs of debt represent a margin of 2.0% over the risk free rate which allows for the margin over bank rates that owners of gas, electricity, rail and port infrastructure assets would expect to pay together with an allowance for the difference between bank rates and government bonds.

3.3 Debt/Equity Mix

The selection of the appropriate debt/equity ratio involves perhaps the most subjectivity of discount rate selection analysis. In determining an appropriate debt/equity mix, regard was had to gearing levels of selected comparable listed entities and the nature and quality of the cash flow stream of the relevant businesses. Gearing levels for selected listed entities over the past four years are set out below:

Gearing Levels for Selected Listed Entities Net Debt/(Net Debt + Market Capitalisation)

Financial Year Ended12 13 Company Historical 4 Historial 3 Historial 2 Historial 1

Current14 4 Year Average

Australian Transmission APA 50.1% 58.3% 71.1% 68.8% 66.6% 62.1%

HDUF 40.6% 36.3% 45.2% na 28.4% 40.7%

Minimum 40.6% 36.3% 45.2% 68.8% 28.4% 40.7%

Maximum 50.1% 58.3% 71.1% 68.8% 66.6% 62.1%

Median 45.3% 47.3% 58.1% 68.8% 47.5% 51.4%

11 Debt premium adjusted to reflect the 50:50 blended risk free rate, based on 10 year United Kingdom Government bond yields and Isle

of Man Government bond, used for United Kingdom distribution assets. 12 All Australian and New Zealand companies have 30 June year ends except for Spark Infrastructure Group (“Spark”) and Hastings

Diversified Utilities Fund (“HDUF”) which have a 31 December year end and SP Ausnet and Norfolk Group Limited (“Norfolk Group”) which have a 31 March year end.

13 All UK companies have a 31 March year end, except Forth Ports PLC which has a 31 December year end. All other companies have a 31 December year end.

14 Current gearing levels are based on the most recent balance sheet information and on sharemarket prices as at 29 September 2009.

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Gearing Levels for Selected Listed Entities Net Debt/(Net Debt + Market Capitalisation)

Financial Year Ended12 13 Company Historical 4 Historial 3 Historial 2 Historial 1

Current14 4 Year Average

Australian Distribution

SP AusNet 56.2% 54.4% 59.1% 69.9% 69.0% 59.9%

Vector 55.8% 52.0% 61.8% 56.0% 48.9% 56.4%

DUET 77.8% 65.9% 74.4% 78.3% 77.1% 74.1%

Spark 57.1% 44.4% 56.0% na 82.3% 52.5%

Envestra 67.8% 66.3% 77.4% 75.0% 74.6% 71.6%

Minimum 55.8% 44.4% 56.0% 56.0% 48.9% 52.5%

Maximum 77.8% 66.3% 77.4% 78.3% 82.3% 74.1%

Median 57.1% 54.4% 61.8% 72.5% 74.6% 59.9%

Australian Services

Worley Parsons 1.3% 4.6% 6.4% 8.6% 7.2% 5.2%

United Group 8.0% 10.4% 12.1% 23.6% 9.2% 13.5%

Transfield Services 27.7% 13.3% 28.5% 29.2% 13.2% 24.7%

Monadelphous Group (7.5%) (6.5%) (10.1%) (14.2)% (12.5)% (9.6%)

WDS15 na (4.6%) (3.4%) 23.0% 17.0% 5.0%

Norfolk Group16 na na na na 30.7% 50.7%

Minimum (7.5%) (6.5%) (10.1%) (14.2%) (12.5%) (9.6%)

Maximum 27.7% 13.3% 28.5% 29.2% 30.7% 50.7%

Median 4.6% 4.6% 6.4% 23.3% 11.2% 9.4%

United States Transmission

TC Pipelines 4.9% 1.9% 42.4% 31.0% 39.4% 23.9% Williams Pipeline Partners na na na na -1.7% -1.7% Energy Transfer Partners 35.3% 29.9% 28.5% 38.5% 52.0% 36.8% ONEOK Partners 33.9% 37.1% 27.7% 34.8% 44.3% 35.6% El Paso Pipeline Partners na na na na 30.4% 30.4% Spectra Energy Partners na na na 21.2% 22.3% 21.8% Boardwalk Pipeline Partners na na 29.1% 35.2% 48.3% 37.5%

Minimum 4.9% 1.9% 27.7% 21.2% -1.7% -1.7% Maximum 35.3% 37.1% 42.4% 38.5% 52.0% 37.5% Median 33.9% 29.9% 28.8% 34.8% 39.4% 30.4%

United Kingdom Distribution

Severn Trent PLC 47.7% 43.2% 48.3% 50.7% 61.9% 50.4% Pennon Group PLC 47.2% 47.3% 42.8% 43.8% 57.2% 47.7% Northumbrian Water Group PLC 67.3% 62.1% 56.6% 54.5% 68.0% 61.7% United Utilities Group PLC 54.6% 40.8% 37.4% 32.0% 53.8% 43.7% Scottish & Southern Energy 16.1% 18.2% 14.3% 23.1% 33.3% 21.0%

Minimum 16.1% 18.2% 14.3% 23.1% 33.3% 21.0% Maximum 67.3% 62.1% 56.6% 54.5% 68.0% 61.7% Median 47.7% 43.2% 42.8% 43.8% 57.2% 47.7% Australian Rail

Asciano Group17 na na na 74.8% 47.4% 61.1% 15 WDS Limited (“WDS”) was first listed in December 2006. 16 Norfolk Group was first listed in July 2007. 17 Asciano was first listed in June 2007

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Gearing Levels for Selected Listed Entities Net Debt/(Net Debt + Market Capitalisation)

Financial Year Ended12 13 Company Historical 4 Historial 3 Historial 2 Historial 1

Current14 4 Year Average

Canadian National Railway 16.7% 17.5% 19.0% 26.3% 21.7% 21.1% Canadian Pacific Railway 27.2% 23.2% 29.0% 43.0% 31.1% 31.6% Burlington Northern Santa Fe 21.2% 21.0% 21.3% 25.8% 24.6% 23.1% Union Pacific 23.6% 19.3% 17.2% 24.2% 20.6% 20.3% CSX Corp 30.2% 24.7% 25.1% 24.5% 27.8% 25.5% Norfolk Southern 23.6% 22.1% 24.4% 26.0% 26.2% 24.7% Genesee & Wyoming 23.9% 0.5% 20.9% 32.5% 23.0% 19.2% Kansas City Southern 48.1% 40.9% 37.0% 47.9% 42.8% 42.1%

Minimum 16.7% 0.5% 17.2% 24.2% 20.6% 19.2% Maximum 48.1% 40.9% 37.0% 74.8% 47.4% 61.1% Median 23.8% 21.6% 22.8% 26.3% 26.2% 24.7%

Ports Shanghai International Port (Group) Co. na na na (1.2%) 5.7% (1.2%) Shenzhen Chiwan Wharf Hldgs 10.3% 7.9% 4.4% 9.0% na 8.9% Tianjin Port Company (4.5%) (1.8%) 6.5% 18.8% 14.4% 5.7% China Merchants Holdings (International) Company Ltd 16.0% 9.4% 6.4% 21.5% 13.6% 10.6% Cosco Pacific Ltd 14.4% 5.5% 7.8% 31.0% 28.0% 13.9% Bintulu Port Holdings Berhard (43.4%) (37.8%) na (25.4%) na (37.0%) Dalian Port (DPA) Company Limited na 9.1% 9.3% 22.9% 18.2% 13.8% Forth Ports PLC 19.6% 15.2% 18.8% 33.2% 31.3% 21.5% Lyttelton Port of Christchurch 22.7% 19.9% na 19.5% 19.5% 20.1% South Port New Zealand Ltd 3.4% 0.7% na (3.4%) (3.4%) 0.2% DP World Limited na na 12.0% 36.9% na 24.4% Hamburger Hafen na na 2.7% 6.5% na 4.6% Port of Tauranga Limited 21.7% 16.1% 18.6% 20.1% 20.1% 20.0%

Minimum (43.4%) (37.8%) 2.7% (25.4%) (3.4%) (37.0%) Maximum 22.7% 19.9% 18.8% 36.9% 31.3% 24.4% Median 14.4% 8.5% 7.8% 19.5% 18.2% 10.6%

Source: Entity Reports, IRESS, Bloomberg The table shows a very wide range of gearing levels, even within different asset classes. Moreover, the gearing levels do not always bear any relationship to the betas of the individual companies. In some cases highly geared companies have equity betas towards the lower end of the range (e.g. Spark). In this case the selection of gearing levels is highly judgemental. Further, the debt levels should actually be the weighted average measured over the same period as the beta factor rather than just at the current point in time. Having regard to this data, Grant Samuel has adopted the following debt/value ratios:

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Debt/Value Ratios Business Operation Debt/Value Ratio Australian gas transmission assets 55-65% Australian gas distribution assets 60-70% New Zealand gas and electricity distribution assets 60-70% Australian asset management services 10-20% United States transmission 40-45% United Kingdom distribution 25-30% Australian port 55-65% Australian rail 20-25% United Kingdom ports 10-15% European ports 10-15%

The gearing levels adopted for BBI’s various assets are consistent with the gearing levels of comparable listed companies within each asset class.

The debt/value ratios adopted for BBI’s gas and electricity distribution and transmission networks in Australia and New Zealand are consistent with the 60% typically allowed for by regulators. However, the average gearing of DUET and Envestra Limited (“Envestra”) over the last four years has exceeded 70% while the average gearing of all other comparable entities except HDUF has exceeded 50%. In addition, due to BBI’s United Kingdom distribution assets having no direct listed comparables, whilst taking into account the debt/value ratios of other UK listed utilities, Grant Samuel has primarily based its debt/value ratios on Scottish & Southern Energy, and therefore adopted a gearing level of 25-30%. Lower gearing is appropriate for service providers and the 10-20% range adopted for BBI’s Australian asset management business is consistent with its listed peer group.

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3.4 WACC

On the basis of the parameters outlined above and assuming corporate tax rates of 30% for Australian, New Zealand, European assets, 28% for United Kingdom assets and 35% for United States assets (adjusted for relevant State taxes), the nominal WACC for BBI’s businesses are calculated as follows:

Calculated WACCs

Business Operation Low High Formula = Ke(E/V)+Kd(1-t)(D/V) = Ke(E/V)+Kd(1-t)(D/V) Australian gas transmission assets = (10.8% x 45%) + (7.4% x

0.7 x 55%) = 7.71%

= (10.2% x 35%) + (7.4% x 0.7 x 65%) = 6.94%

Australian gas distribution assets = (10.8% x 40%) + (7.4% x

0.7 x 60%) = 7.43%

= (10.2% x 30%) + (7.4% x 0.7 x 70%) = 6.69%

New Zealand gas and electricity distribution assets = (11.3% x 40%) + (7.9% x

0.7 x 60%) = 7.87%

= (10.7% x 30%) + (7.9% x 0.7 x 70%) = 7.11%

Australian asset management services = (13.2% x 90%) + (7.4% x

0.7 x 10%) = 12.40%

= (12.6% x 80%) + (7.4% x 0.7 x 20%) = 11.12%

United States transmission = (8.1% x 60%) + (5.3% x

0.61 x 40%) = 6.2%

= (7.5% x 55%) + (5.3% x 0.61 x 45%) = 5.59%

United Kingdom distribution = (9.4% x 75%) + (6.6% x

0.7 x 25%) = 8.3%

= (8.8% x 70%) + (6.6% x 0.7 x 30%) = 7.6%

Australian port = (12.0% x 45%) + (7.4% x

0.7 x 55%) = 8.2%

= (11.4% x 35%) + (7.4% x 0.7 x 65%) = 7.4%

Australian rail = (12.6% x 80%) + (7.4% x

0.7 x 20%) = 11.1%

= (11.4% x 75%) + (7.4% x 0.7 x 25%) = 9.8%

United Kingdom ports = (11.4% x 90%) + (5.6% x

0.72 x 10%) = 10.7%

= (10.2% x 85%) + (5.6% x 0.72 x 15%) = 9.3%

European ports = (11.1% x 90%) + (5.3% x

0.7 x 10%) = 10.3%

= (9.9% x 85%) + (5.3% x 0.7 x 15%) = 8.9%

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These are after tax discount rates to be applied to nominal ungeared after tax cash flows. However, it must be recognised that this is a very crude calculation based on statistics of limited reliability and involving a multitude of assumptions. Having regard to these matters and the calculations and data set out above, Grant Samuel has concluded that reasonable discount rates for the purposes of the valuation of BBI are:

Discount Rates

Business Operation Discount Rate Australian gas transmission assets 7.00-7.50% Australian gas distribution assets18 6.75-7.25% New Zealand gas and electricity distribution assets 7.25-7.75% Australian asset management services 11.50-12.00% United States transmission 5.75-6.25% United Kingdom distribution 7.75-8.25% Australian port 7.25-7.75% Australian rail 10.00-10.50% United Kingdom ports 9.75-10.25% European ports 9.25-9.75%

4 Dividend Imputation

The conventional WACC formula set out above was formulated under a “classical” tax system. The CAPM model is constructed to derive returns to investors after corporate taxes but before personal taxes. Under a classical tax system, interest expense is deductible to a company but dividends are not. Investors are also taxed on dividends received. Accordingly, there is a benefit to equity investors from increased gearing. Under Australia’s dividend imputation system, domestic equity investors now receive a taxation credit (franking credit) for any tax paid by a company. The franking credit attaches to any dividends paid out by a company and the franking credit offsets personal tax. To the extent the investor can utilise the franking credit to offset personal tax, then the corporate tax is not a real impost. It is best considered as a withholding tax for personal taxes. It can therefore be argued that the benefit of dividend imputation should be added into any analysis of value. There is no generally accepted method of allowing for dividend imputation. In fact, there is considerable debate within the academic community as to the appropriate adjustment or even whether any adjustment is required at all. Some suggest that it is appropriate to discount pre tax cash flows, with an increase in the discount rate to “gross up” the market risk premium for the benefit of franking credits that are on average received by shareholders. On this basis, the discount rate might increase by approximately 2% but it would be applied to pre tax cash flows. However, not all of the necessary conditions for this approach exist in practice:

not all shareholders can use franking credits. In particular, foreign investors gain no benefit from franking credits. If foreign investors are the marginal price setters in the Australian market there should be no adjustment for dividend imputation;

not all franking credits are distributed to shareholders; and

capital gains tax operates on a different basis to income tax. Investors with high marginal personal tax rates will prefer cash to be retained and returns to be generated by way of a capital gain.

18 Except for Tas Gas, for which Grant Samuel has selected a discount rate of 7.00-7.50% to reflect its mix of gas distribution and retail

business operations.

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Other have proposed a different approach involving an adjustment to the tax rate in the discount rate by a factor reflecting the effective use or value of franking credits. If the credits can be used, the tax rate is reduced towards zero. The proponents of this approach have in the past suggested a factor of up to 50% as representing the appropriate adjustment (gamma). Alternatively, the tax charge in the forecast cash flows can be decreased to incorporate the expected value of franking credits distributed. There is undoubtedly merit in the proposition that dividend imputation affects value. Over time dividend imputation will become factored into the determination of discount rates by corporations and investors. In Grant Samuel’s view, however, the evidence gathered to date as to the value the market attributes to franking credits is insufficient to rely on for valuation purposes. More importantly, Grant Samuel does not believe that such adjustments are widely used by acquirers of assets at present. While acquirers are undoubtedly attracted by franking credits there is no clear evidence that they will actually pay extra for them or build it into values based on long term cash flows. The studies that measure the value attributed to franking credits are based on the immediate value of franking credits distributed and do not address the risk and other issues associated with the ability to utilise them over the longer term. Accordingly it is Grant Samuel’s opinion that it is not appropriate to make any such adjustments in the valuation methodology. This is a conservative approach.

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Appendix 2

DCF Model Assumptions 1 General Assumptions

The following general assumptions have been made in the DCF Models developed to value BBI’s assets:

inflation rate of:

• 2.5% per annum for Australian assets;

• 2.2% per annum for New Zealand assets;

• 2.0% per annum for North American assets;

• 2.0% per annum for United Kingdom assets; and

• 2.0% per annum for European assets.

corporate tax rates of:

• 30% for Australian assets;

• 30% for New Zealand assets;

• 35% for North American assets, adjusted for relevant State taxes;

• 28% for UK assets adjusted for relevant tax rates for Offshore Islands assets; and

• 25-35% tax rates for various jurisdictions for European assets.

There is no change in taxation legislation that has a material impact on BBI’s operations; and

no significant changes in legislation, or in the policies or procedures of the various regulatory bodies.

2 AET&D Assets

2.1 Tasmanian Gas Pipeline

a discount rate of 7.00-7.50% has been applied to the nominal after tax cash flows;

sufficient gas supplies will be available from either existing or new suppliers to meet the forecast demand for pipeline transportation services;

tariffs escalate annually at inflation;

all contracts are renewed on expiry;

maintenance and investment costs are based on asset management plans, escalated at inflation including:

• diagnostic assessment of undersea pipelines at approximately $2.3 million every two years; and

• pigging every ten years commencing in 2010;

tax depreciation is based on the asset tax cost bases as at 1 July 2009 depreciated on a straight line basis for a period of 20 years;

new capital expenditure is depreciated for tax purposes on a straight line basis for a period of 20 years;

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decommissioning costs (where applicable) are based on independent advice received by BBI; and

expansion opportunities represent growth in gas reticulation demand from the roll-out of the Tas Gas network.

2.2 WA Gas Networks

a discount rate of 6.75-7.25% has been applied to the nominal after tax cash flows;

average revenue growth of 3.7% per annum over the whole forecast period reflecting:

• new connections increasing from approximately 15,000 per year in 2010 to approximately 20,000 per year from 2015 onwards as a result of the impact of, and recovery from, the economic slowdown;

• a reduction in consumption of approximately 1.0% per annum as gas appliances become more energy efficient and there is increased use of solar hot water systems with gas boosters; and

• the impact of five yearly regulatory price resets;

operating expenses of approximately $38 million in 2010, increasing to approximately $50 million in 2011 following the internalisation of asset management services from 1 July 2010, and then growing in line with inflation. While there is a reduction in direct operating costs (as margins under the Operating Services Agreement are no longer paid), additional WestNet Energy costs and BBI/DUET overheads are assumed to be passed through to WA Gas Networks from 2011 onwards;

average capital expenditure of approximately $45-50 million per annum through to 2014, then average capital expenditure over this period of $45 million in 2015, then growing by inflation; and

perpetual growth rate of 2.5% for the purposes of calculating terminal value.

2.3 WestNet Energy

a discount rate of 11.5 - 12.0% has been applied to the nominal after tax cash flows;

the Operating Services Agreement with WA Gas Networks is not renewed at its renewal date in June 2010;

growth in revenue from external contracts of 6.6% per annum;

operating expenses escalated at inflation; and

perpetual growth rate of 2.5% for the purposes of calculating the terminal value. 3 Other Transmission and Distribution Assets

3.1 Cross Sound Cable

a discount rate of 5.75-6.25% has been applied to the nominal after tax cash flows;

contracted revenues from LIPA escalate by 1% per annum over the life of the contract which expires in 2032;

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assumes requirement for transmission capacity beyond 2032, escalating at inflation until the end of the assets life in 2043;

the TBC agreement is for five years, however there is an option to extend and the model assumes revenue derived from TBC is continues over the life of the asset, growing at inflation;

majority of expenses assumed to escalate at inflation;

capital expenditure based on management forecasts escalating at inflation;

tax depreciation based on acquired asset in 2006 depreciating 1.5 times diminishing value over 20 years;

assumes outstanding costs from 2009 to 2013 of US$4 million relating to costs associated with the settlement of litigation with three shellfish companies in 2000; and

asset retirement obligation of US$17.7 million is assumed in 2043 based on independent audit.

3.2 Tas Gas

a discount rate of 7.00-7.50% has been applied to the nominal after tax cash flows;

average revenue growth of 17.7% per annum over the four years ending 30 June 2013 primarily reflecting a rapid increase in gas consumption from new industrial customers and a price increase for residential and commercial customers. Revenue growth gradually decreases to long term growth of 3.3% per annum thereafter (i.e. inflation and new business volume growth);

average operating expenditure growth of 6.3% over the four years ending 30 June 2013, gradually decreasing to long term growth of 2.5% thereafter (i.e. inflation growth);

capital expenditure over the four years ending 30 June 2013 of approximately $13.9 million per annum of which $8.7 million per annum is expansionary in nature. No major replacement or expansionary capital expenditure is assumed thereafter; and

perpetual growth rate of 3.5% for the purposes of calculating the terminal value.

3.3 Powerco

a discount rate of 7.25-7.75% has been applied to the nominal after tax cash flows;

total revenue grows by an average of 8% per annum from 2010 to 2015 and is thereafter assumed to grow by approximately 2.6% per annum (i.e. marginal real growth):

• growth in electricity revenue (which represents approximately 90% of revenue) is based on a default price path (price x volume + pass through costs) from 2010 to 2015 and thereafter is based on a customised price path using a building blocks approach (WACC x RAB + costs + pass through costs); and

• growth in gas revenue is based on growth in price (where X is currently 0) and growth in volume/demand.

• Powerco operates in a mature market. The higher level of growth in the earlier years reflects:

• the increase in transmission costs over this period (which is a pass through cost and therefore has no impact on EBITDA). A significant increase in transmission costs is expected through to 2015 as Transpower makes major investments in its network; and

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• the proposed X = 0 for the electricity distribution business from 2010 to 2015;

• offset by the expected impact of the recession in 2010 and 2011;

average operating expenses growth of 6% per annum from 2010 to 2015 and 2.7% thereafter. The higher growth in operating expenses in the early years reflects an increase in transmission costs over this period of approximately 10% per annum. Average growth in operating expenses is greater than inflation reflecting the impact of assumed efficiency gains;

capital expenditure based on the asset management plan for 2010 to 2018 in the range NZ$100-130 million per annum, and thereafter assumed to increase by inflation, with 2010 and 2011 adjusted for the expected impact of the recession; and

perpetual growth rate of 2.5% for the purposes of calculating the terminal value.

3.4 International Energy Group

a discount rate of 7.75-8.25% has been applied to the nominal after tax cash flows;

revenue in the UK business assumes double digit growth over the next four years, which is consistent with the growth experienced in FY09 and takes into account the housing slump experienced in the UK;

modest growth in the Isle of Man, Jersey and Guernsey which is consistent with the mature market in these locations;

longer term growth and costs assumed at inflation;

significant capital expenditure growth over the next four years associated with the growth assumed in the UK business; and

perpetual growth rate of 2% for the purposes of calculating the terminal value.

4 Transport Assets

4.1 Dalrymple Bay Coal Terminal

a discount rate of 7.25-7.75% has been applied to the nominal after tax cash flows;

the terminal continues to operate at current capacity of 85mtpa, and there is no expansion of the capacity;

the terminal has a life ending 30 June 2054;

the next regulatory price reset date is 31 December 2010, with a further reset date in June 2016;

fixed and variable handling charges (including all operating costs) amount to approximately $124 million in the 2010 financial year and escalate annually according to inflation. These services are outsourced to DBCT Pty Ltd and are fully passed through to customers for the life of the terminal;

corporate costs are approximately $6 million in the 2010 financial year, and escalate annually at inflation;

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expansion capital expenditure of $40 million in the 2010 financial year relating to deferred payments for completion of phase 2/3 of Project 7X expansion. There is no further expansion capital expenditure for the remainder of the life of the terminal; and

non expansionary capital expenditure of $22 million in the 2010 financial year, $18 million in the 2011 financial year, and nil thereafter.

4.2 WestNet Rail

the model discounts cash flows for the period from 1 September 2009 out to 30 June 2039.

assumes a perpetual growth rate of 2% for cash flows from 1 July 2039;

a discount rate of 10.0-10.5% has been applied to the nominal after tax cash flows;

the base case volume assumptions for haulage have been based on:

• 2009-2019 – WNR corporate plans, current end user negotiations, existing volumes and contracts, and announced customer expansion plans for certain customers. For the grain task, interstate freight and intrastate freight, tonnage is assume to grow at 3% per annum;

• 2019-2039 – revenues grow at CPI.

all rail access agreements are renewed on expiry;

access pricing (including flagfall revenue) is based on existing customer arrangements. Tariffs escalate annually at inflation in accordance with the relevant contract;

as historically has been the case, regulated revenue ceilings remain above the actual revenues per line, customer contracts continue to be negotiated outside the access regime, no adverse decisions or reviews of the access regime occur and there are no disputes with customers;

average operating expenditure increases by 24.5% from current levels in FY 2010 and then declines in 2010 by 20% and thereafter remains constant in real terms;

Maintenance capital expenditure remains at current levels in real terms until 2015 when it declines by 23%, then by 37% in 2019 and remains constant in real terms thereafter, totaling $263 million in real terms;

Network upgrade capital expenditure of $264 million in real terms is spent between 2011 and 2024;

new capital expenditure on existing assets and network upgrades is depreciated for tax purposes on a diminishing value basis at applicable rates.

4.3 Euroports

a discount rate of 9.25-9.75% has been applied to the nominal after tax cash flows;

the DCF models are long term commencing at 1 September 2009 and extending for 20 years;

a summary the base case earnings and free cash flow projections for the aggregate business are set out below:

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Euroports - DCF Analysis (€ millions) Year Ending 30 June

A$000’s 2010 2011 2012 2030 Revenue 311.5 392.7 418.0 877.4 EBITDA 70.9 92.0 99.5 272.0 Capital Expenditure (26.9) (27.6) (26.5) (31.6)

Free Cash Flow1 33.7 48.8 55.1 179.2

corporate costs of approximately €1.8 million and growing at 3% per annum have been assumed. No synergies have been assumed in the model; and

perpetual growth rate of 2% for the purposes of calculating the terminal value.

4.4 PD Ports

a discount rate of 9.75-10.25% has been applied to the nominal after tax cash flows;

the DCF models are long term commencing at 1 September 2009 and extending for 20 years;

a summary the base case earnings and free cash flow projections for the aggregate business are set out below:

PD Ports - DCF Analysis (£ millions)

Year Ending 30 June A$000’s 2010 2011 2012 2030 Revenue 89.6 116.2 127.3 222.4 EBITDA 29.6 43.1 48.3 93.9 Capital Expenditure (6.9) (13.3) (15.6) (8.9)

Free Cash Flow¹ 17.3 19.9 21.8 63.1

perpetual growth rate of 2% for the purposes of calculating the terminal value.

1 EBITDA less capital expenditure, working capital movements and tax (calculated on a notional ungeared basis)

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Appendix 3

Market Evidence - Listed Entities 1 Energy Transmission and Distribution

1.1 Australia and New Zealand

The trading multiples of selected listed energy transmission and distribution companies and asset service providers are set out below:

Sharemarket Ratings of Selected Listed Entities1 EBITDA Multiple2

(times) Entity

Market Capitalisation

(millions) Historical Forecast Year 1

Forecast Year 2

Transmission APA A$1,590.7 10.7 10.6 10.0

HDUF A$478.9 10.1 7.4 7.2

Minimum 10.1 7.4 7.2

Maximum 10.7 10.6 10.0

Median 10.4 9.0 8.6

Distribution SP AusNet A$2,303.4 9.4 8.5 7.9

Vector NZ$1,882.0 7.8 7.8 7.4

DUET A$1,439.1 9.8 8.9 8.5

Spark A$1,165.0 10.5 9.7 9.6

Envestra A$764.6 10.4 10.4 10.2

Minimum 7.8 7.8 7.4

Maximum 10.5 10.4 10.2

Median 9.8 8.9 8.5

Services WorleyParsons A$7,207.7 11.7 12.6 11.2

United Group A$2,520.0 10.3 10.0 9.4

Transfield Services A$1,885.3 12.3 12.3 11.8

Monadelphous Group A$1,175.8 9.1 8.9 7.8

WDS A$236.7 5.3 4.5 4.1

Norfolk Group A$92.3 7.1 4.9 4.5

Minimum 5.3 4.5 4.1

Maximum 12.3 12.6 11.8

Median 9.7 9.4 8.6

Source: Grant Samuel analysis3

1 The companies selected have a variety of year ends and therefore the data presented for each entity is the most recent annual historical

result plus the subsequent two forecast years. 2 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at the

latest balance date) divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation, investment income and significant and non-recurring items.

3 Grant Samuel analysis based on data obtained from IRESS, company announcements and, in the absence of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each company depends on analyst coverage, availability and recent corporate activity.

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The multiples shown above are based on sharemarket prices as at 29 September 2009 and do not reflect a premium for control. All of the companies have a 30 June year end with the exception of Spark Infrastructure Trust (“Spark”) and Hastings Diversified Utilities Fund (“HDUF”) which have a 31 December year end and SP AusNet and Norfolk Group Limited (“Norfolk Group”) which have a 31 March year end. A brief description of each company is set out below: Transmission Infrastructure APA Group APA Group (“APA”) (formerly known as Australian Pipeline Trust) has interests in over 12,000 kilometres of gas transmission pipelines, transporting around 40% of Australia’s natural gas consumption, as well as gas processing and storage facilities, gas fired power generation and electricity transmission. The largest asset in APA’s portfolio is the Moomba to Sydney pipeline, which contributes approximately 60% of EBITDA. APA Group was formed in mid 2000 through the spin-off and public listing of AGL’s gas pipeline assets. It was established as a single taxpaying trust, which was required to pay tax on its profits. In January 2007, the trust was restructured from a single unit trust to a stapled unit structure with the aim of making returns to security holders more tax effective. APA was highly acquisitive during the 2006 and 2007 financial years (e.g. it acquired Murraylink, GasNet, Allgas and Origin Energy Networks) and has now shifted its focus to organic growth of its portfolio. Hastings Diversified Utilities Fund Hastings Diversified Utilities Fund (“HDUF”) is a listed, utility focussed infrastructure fund which owns a 100% interest in Epic Energy Holdings (“Epic”) and a 50% voting interest in water utility South East Water in the United Kingdom. Despite a 50% voting interest, HDUF’s economic interest in South East Water is 38.7% and it also holds 100% of the preferred notes of the company. Epic is an Australian gas transmission business which holds pipeline assets in South Australia, Queensland and Western Australia. In July 2009, HDUF completed a fully underwritten $250m equity capital raising and used the proceeds to repay debt with the remainder being applied towards the Stage 3 expansion of the South West Queensland Pipeline. Distribution Infrastructure SP AusNet SP AusNet is a utility infrastructure asset vehicle whose assets comprise 100% ownership of Victoria’s primary electricity transmission network, an electricity distribution network located in eastern Victoria and a gas distribution network located in western Victoria. Singapore Power Limited has a 51% controlling interest in the entity. SPI Management Services Pty Ltd, a wholly-owned subsidiary of Singapore Power Limited, manages the transmission and distribution networks, business and finances of SP AusNet under a Management Services Agreement. SP AusNet has a first chance to consider any electricity and gas transmission investment opportunity in Australia and New Zealand identified by Singapore Power. In June 2009 SP AusNet completed a $408m capital raising which was primarily used to repay debt with the remainder available to fund organic growth opportunities.

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Vector Limited Vector Limited (“Vector”) owns and manages a portfolio of energy infrastructure networks in New Zealand including electricity distribution (which accounted for more than 45% of 2009 revenues), gas transmission and distribution, electricity and gas metering installations, natural gas and LPG distribution (including a 60.25% interest in bulk LPG distributor Liquigas). In addition, Vector owns a 19.99% share of NZ Windfarms Limited, fibre-optic networks in Auckland and Wellington, a utilities training business and a 50% share in New Zealand’s largest arboriculture and vegetation management company. The Auckland Energy Consumer Trust is Vector’s majority shareholder with a 75.1% interest. In April 2008, Vector announced the sale of the Wellington electricity network to Cheung Kong Infrastructure for $785 million and used the proceeds to repay a portion of its corporate debt. DUET Group DUET Group (“DUET”) is an owner of energy utility assets with predictable cash flows. Management is provided by a 50:50 joint venture between AMP Capital Investors and Macquarie Bank Limited. DUET’s current investments comprise transmission and distribution assets in Australia and the United States. Its interests include a 66% interest in United Energy (electricity distribution in Victoria), a 79.9% interest in Multinet Gas (gas distribution in Victoria), a 25.9% interest in WA Gas Networks (gas distribution in Western Australia), a 60% interest in the Dampier to Bunbury Natural Gas Pipeline (gas transmission in Western Australia) and a 29% interest in Duquesne Light Holdings Inc (a publicly listed energy business based in Pittsburgh, providing electricity distribution and transmission to more than 587,000 customers in and around Pittsburgh). Spark Infrastructure Trust Spark Infrastructure Trust (“Spark”) was established to develop a diversified portfolio of regulated utility infrastructure assets and listed on the ASX in December 2005. It holds a 49% interest in each of Citipower and Powercor (whose principal activities are electricity distribution in Victoria) and ETSA (whose principal activity is electricity distribution in South Australia). The remaining 51% interests are held by Cheung Kong Infrastructure (CKI) and Hongkong Electric Holdings. This portfolio of Australian electricity distribution assets provides the company with stable and predictable cash flows. The group plans to grow through the acquisition of additional Australian and international regulated utility infrastructure assets. The manager and responsible entity of Spark is jointly owned by CKI and RREEF Infrastructure (RREEF). The calculation of underlying multiples for Spark is complex because of the minority holdings and form of investment. Envestra Limited Envestra Limited (“Envestra”) was listed on the ASX in 1997 following Boral Limited’s decision to spin off its energy assets. It owns and operates approximately 1,029 kilometres of gas transmission pipelines and 19,100 kilometres of gas distribution networks throughout Australia. Envestra derives its revenue by charging energy retailers to transport natural gas through these networks. Each Envestra security is comprised of a share and a loan note. Interest and principal are paid on the loan notes and therefore net profit after tax is relatively low (if not negative). Envestra has outsourced operation and maintenance of all its assets to APA which owns 17% of Envestra. Cheung Kong Infrastructure also owns 17% of the company. Services WorleyParsons Limited WorleyParsons Limited (“WorleyParsons”) provides professional services to the hydrocarbons, minerals and metals, infrastructure and power industries globally. The hydrocarbons business is the largest contributor generating 75% of the Group’s EBITDA in 2009, followed by the minerals and metals business (which accounts for 12% of EBITDA). WorleyParsons is a major global

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operation with over 70% of revenue derived outside of Australia. The 30 June 2009 year reflects the first full year contributions from a number of bolt-on acquisitions completed during 2008. WorleyParsons’s earnings are expected to decline in 2010 as a consequence of margin pressure and a strong Australian dollar. United Group Limited United Group Limited (“United Group”) is a diversified infrastructure services group with operations in Australia, New Zealand, Asia, America and Europe. The company has four operating businesses, United Group Infrastructure (23% of 2009 revenue), United Group Rail (30%), United Group Resources (15%) and United Group Services (33%). Transfield Services Limited Transfield Services Limited (“Transfield Services”) is a provider of specialized operations, maintenance and asset management services within domestic and international markets. The company operates across a number of industries including mining and process, hydrocarbons, roads, rail and public transport, water, power, telecommunications, facilities management and defense. Transfield Services also manages and owns a shareholding in Transfield Services Infrastructure Fund which owns a portfolio of power stations and water filtration plants. The multiples calculated for Transfield Services are after excluding the market value and earnings of the infrastructure assets in which the company still retains a minority interest, resulting in multiples for the services and asset management activities of Transfield Services only. Monadelphous Group Limited Monadelphous Group Limited (“Monadelphous”) is an engineering group providing project management, construction, asset management and maintenance services to the resources, energy and infrastructure industry sectors. The company operates through three primary divisions – engineering and construction (which generated 59% of 2009 revenues), electrical and instrumentation services (9%) and maintenance and industrial services (31%). WDS Limited WDS Limited (“WDS”) was floated on the ASX is December 2006 and provides pipeline construction and maintenance services across Australia, as well as specialist services to the coal mining industry. The company has two primary operating divisions, construction and maintenance services (72% of 2009 revenues) and mining services (28%). Norfolk Group Norfolk Group was floated on the ASX in July 2007 and is a provider of integrated electrical, communications, heating, ventilation and air conditioning and fire protection and property services. The company operates through three divisions, electrical and communications (50% of 2009 revenues), mechanical (38%) and fire and property services (12%).

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1.2 United States

The trading multiples of selected listed transmission companies are set out below:

Sharemarket Ratings of Selected Listed Entities4 EBITDA Multiple5

(times) Entity

Market Capitalisation (US$ millions) Historical Forecast

Year 1 Forecast Year 2

Transmission

Energy Transfer Partners 7,173.3 9.0 8.0 7.2

ONEOK Partners 5,069.1 9.1 10.6 10.2

Boardwalk Pipeline Partners 4,523.6 15.7 14.6 10.4

El Paso Pipeline Partners 2,674.4 24.2 11.1 7.3

Spectra Energy Partners 1,998.5 23.5 11.5 9.6 TC Pipelines 1,658.4 na6 28.6 20.7

Williams Pipeline Partners 641.4 12.2 12.2 12.4

Minimum 9.0 8.0 7.2

Maximum 47.0 28.6 20.7 Median 15.7 11.5 10.2

Source: Grant Samuel analysis7 The multiples shown above are based on sharemarket prices as at 29 September 2009 and do not reflect a premium for control. All of the companies have a 31 December year end. A brief description of each company is set out below: Energy Transfer Partners L.P. Energy Transfer Partners L.P. owns and operates a diversified portfolio of energy assets and is the third largest domestic retail propane marketer in the United States. In addition, the partnership owns natural gas assets including intrastate pipelines, gathering systems and processing and treating plants situated in Texas, and the recently acquired Transwestern pipeline, which is a bi-directional pipeline that extends to markets from Texas and the west to the California border. The partnership is managed by its general partners, Energy Transfer Partners GP, L.P, and recorded operating income for the financial year ending 31 December 2008 of approximately US$1,124 million. Reporting segments and their approximate contributions to operating income in 2008 were as follows: Midstream (15%), Transportation & Storage (64%), Transportation (11%) and Retail Propane (10%). ONEOK Partners L.P. ONEOK Partners, L.P. (“ONEOK Partners”) is engaged in the gathering, processing, storage and transportation of natural gas in the United States. The company owns premier natural gas liquids systems, connecting natural gas liquid supply in the Mid-Continent and Rocky Mountain regions

4 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 5 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at the

latest balance date) divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation, investment income and significant and non-recurring items.

6 Due to TC Pipelines 100% acquisition of North Baja for an initial total purchase price of US$271.3 million on 1 July 2009, historical multiples for TC Pipelines are not meaningful.

7 Grant Samuel analysis based on data obtained from IRESS, company announcements and, in the absence of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each company depends on analyst coverage, availability and recent corporate activity.

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with key market centers, and a 50% equity interest in a leading transporter of natural gas imported from Canada into the United States. In the financial year ending 31 December 2008, ONEOK Partners recorded operating income of approximately US$644 million. The company’s operating segments and their approximate contributions to operating income were as follows: Natural Gas Gathering and Processing (38%), Natural Gas Pipelines (21%), Natural Gas Liquids Gathering and Fractionation (32%), Natural Gas Liquid Pipelines (9%). Boardwalk Pipeline Partners L.P. Boardwalk Pipeline Partners, L.P. (“BWP”) was structured as a master limited partnership in 2005. The company owns and operates three interstate natural gas pipeline systems and associated storage facilities that include Gulf Crossing System, Gulf South System, and Texas Gas System. The company’s operating system owns approximately 14,000 miles of pipeline, directly serving customers in 12 states. The company’s natural gas storage facilities include eleven underground storage files located in four states with aggregate working gas capacity of approximately 160 billion cubic feet. The principal sources of BWP's natural gas supply are located in the Gulf Coast region, and the Mid-Continent. Loews Corp. is BWP’s general partner. The partnership operates through one reporting segment, and in the financial year ending 31 December 2008 recorded revenues of approximately US$785 million. El Paso Pipeline L.P. El Paso Pipeline Partners L.P. was structured as a master limited partnership by El Paso Corp. in 2007 and generates all of its cash flow from long-haul natural gas pipeline and storage assets. The partnership has ownership interests in three separate FERC regulated interstate pipeline systems including a 100% ownership interest of the Wyoming Interstate Gas Company Ltd, a 58% interest in the Colorado Interstate Gas Company and a 25% ownership interest in the Southern Natural Gas Company. For the year ending 31 December 2008, the company recorded revenues of approximately US$141 million. Spectra Energy Partners L.P. Spectra Energy Partners L.P. (“SEP”) is a master limited partnership formed by Spectra Energy Corp. to own and operate natural gas transportation and storage assets. SEP's assets consist of interests in two interstate natural gas pipeline systems located in the southeastern United States, interests in two natural gas storage facilities in Texas and Louisiana, a liquefied natural gas storage facility in Tennessee, and a 5.5 billion cubic feet salt cavern storage facility in Virginia. In April 2009, SEP acquired the 565 mile NOARK natural gas pipeline from Atlas Pipeline Partners allowing the partnership to expand its footprint in the Mid-Continent. The high historical EBITDA multiple of 23.5 times is reflective of the fact that earnings for this transaction have not been included in the full year 2008 results. The partnership recorded revenues for the year ending 31 December 2008 of approximately US$125 million. TC Pipelines L.P. TC PipeLines L.P was formed in 1998 by TransCanada PipeLines Limited, to acquire, own and participate in the management of North American energy infrastructure businesses. The partnership's cash flows are primarily derived from its ownership interests in interstate natural gas pipelines. The partnership owns a 50% interest in Northern Border Pipeline Company, a 100% interest in the Tuscarora Gas Transmission Company, a 46.45% interest in Great Lakes Gas Transmission and a 100% interest in the North Baja Pipeline System. The partnership recorded transmission revenues of approximately US$32 million and equity income from investments of approximately US$123 million for the financial year ending 31 December 2008, most of which was derived from its interests in the Northern Border Pipeline and Great Lakes investments. TC Pipeline’s notional share of EBITDA from these investments is not included in the EBITDA of TC Pipeline as the earnings are equity accounted, although they are reflected in market values. Accordingly, the EBITDA multiples are effectively overstated. TransCanada Corp. is the MLP's general partner.

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Williams Pipeline Partners L.P. Williams Pipeline Partners (“WPP”) owns and operates natural gas transportation and storage assets, and is managed and operated by its general partner, Williams Pipeline GP LLC. WPP’s primary asset is a 35% interest in Northwest Pipeline, a 3,900 mile interstate natural gas pipeline system that extends from the San Juan Basin in New Mexico, through the Rocky Mountains and to the Northwestern United States. The majority of the partnerships income is derived from its investment in the Northwest Pipeline, of which equity earnings from the investment for the year ending 31 December 2008 were approximately US$54 million. Williams Pipeline equity accounts these earnings, and EBITDA multiples have been adjusted to reflect these equity accounted earnings. The higher multiples of earnings on which Williams is trading are likely to be explained, at least in part, by its tax advantaged status.

1.3 United Kingdom

The trading multiples of selected listed distribution and utility companies are set out below:

Sharemarket Ratings of Selected Listed Entities8 EBITDA Multiple9

(times) Entity

Market Capitalisation

(£ millions) Historical Forecast Year 1

Forecast Year 2

Utility and Distribution

Scottish and Southern Energy Plc 10,768.7 8.5 7.8 7.0 United utilities Group Plc 3,117.5 7.9 7.8 9.0 Severn Trent Plc 2,288.6 10.7 8.2 8.6 Pennon Group Plc 1,656.8 9.3 8.9 9.1 Northumbrian Water Group 1,287.2 9.9 10.7 10.8

Minimum 1.1 1.5 1.3

Maximum 10.7 10.7 10.8 Median 8.2 7.8 8.6

Source: Grant Samuel analysis10 The multiples shown above are based on sharemarket prices as at 29 September 2009 and do not reflect a premium for control. All of the companies have a 31 March year end. A brief description of each company is set out below:

. Scottish and Southern Energy Plc Scottish and Southern Energy Plc is a holding company. The company and its subsidiaries are organized into the main businesses of electricity generation, transmission, distribution and supply; gas storage, electrical and contracting, home services, and supplying a range of electrical and gas appliances. The group’s primary segments for reporting purposes are the distribution and transmission of electricity in the north of Scotland, the distribution of electricity in the south of England (together referred to as Power Systems) and the generation and supply of electricity and

8 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 9 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at the

latest balance date) divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation, investment income and significant and non-recurring items.

10 Grant Samuel analysis based on data obtained from IRESS, company announcements and, in the absence of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each company depends on analyst coverage, availability and recent corporate activity.

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sale of gas in Great Britain and Ireland (Generation and Supply). The group‘s 50% equity share in Scotia Gas Networks Limited, a business which distributes gas in Scotland and the south of England is reported as a separate business segment due to its significance, however for the purpose of these multiples the earnings were not adjusted. For the full year ending 31 March 2009 segment contributions to revenue were as follows: Power Systems (1%), Generation and Supply (48%), and Other businesses (51%). United Utilities Group Plc United Utilities Group PLC (“United Utilities”), formerly United Utilities PLC, is a provider of water and waste water services in north-west England. The company is organized in two divisions, regulated and non-regulated activities. The regulated activities segment includes the regulated results of United Utilities Water PLC and the non-regulated activities segment includes the company’s utility outsourcing contracts in the United Kingdom and overseas. In addition, the other activities segment includes the results of United Utilities Property Solutions Limited, United Utilities Group PLC and other group holding companies. For the full year ending 31 March 2009 segment contributions to operating profit were as follows: Regulated activities (91%), Non regulated activities (9%). Severn Trent Plc Severn Trent Plc is engaged in the supply of water and the treatment and disposal of sewage. The company is organized into two reporting segments: Severn Trent Water and Severn Trent Services. Severn Trent Water is engaged in providing water and sewerage services to domestic and commercial customers in England and Wales. Severn Trent Services is engaged in providing services and products associated with water, waste water and contaminated land principally in the United States, United Kingdom and Europe. For the full year ending 31 March 2009 Severn Trent Water and Severn Trent Services contributed 95% and 5% to EBITDA respectively. Pennon Group Plc Pennon Group Plc is engaged in the provision of water and sewerage services, waste management and renewable energy. The company’s business is operated through two main subsidiaries. South West Water Limited holds the water and sewerage appointments for Devon, Cornwall and parts of Dorset and Somerset, and Viridor Limited’s business is waste treatment and disposal. For the full year ending 31 March 2009 segment contributions to EBITDA from Water and Sewerage, and Waste management were 72% and 28% respectively. Northumbrian Water Group Northumbrian Water Group (“Northumbrian”) is a United Kingdom regulated water utility with two discrete service areas. In the north east of England, it supplies water and wastewater services, and in the east of England, it supplies water only. It also has small water-related unregulated business. For the full year ending 31 March 2009 Northumbrians two reportable segments, Northumbrian Water Limited and Water/Waste Water contracts, contributed 96% and 4% to EBITDA respectively.

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2 Transport

2.1 Ports

The trading multiples of selected listed port operators are set out below:

Sharemarket Ratings of Selected Listed Entities11 EBITDA Multiple13

(times) Entity Country

Market Capitalisation (A$ millions)12 Historical Forecast

Year 1 ForecastYear 2

Port Operator Shanghai International Port (Group) Co China 17,690 10.8 14.6 13.4 Shenzhen Chiwan Wharf Holdings Limited China 1,074 5.6 8.8 8.3 Tianjin Port Holdings Company Limited China 2,985 11.1 10.2 9.5 China Merchants Holdings (International) Co Ltd China 9,265 14.8 16.1 14.7 Cosco Pacific Ltd China 3,824 10.8 16.1 13.0 Bintulu Port Holdings Berhard Malaysia 829 9.8 10.9 9.8 Dalian Port (PDA) Company Limited China 1,374 11.9 10.4 9.4 Forth Ports PLC UK 1,011 11.1 12.9 12.2 Lyttelton Port Company Limited New Zealand 201 10.5 9.9 9.5 South Port New Zealand Ltd New Zealand 54 9.5 10.7 10.1

DP World Limited United Arab Emirates 10,194 9.4 10.7 10.1

Port of Tauranga Limited New Zealand 709 13.2 12.5 11.7 Hamburger Hafen und Logistik AG Germany 3,736 6.4 8.3 7.3

Minimum 5.6 8.3 7.3 Maximum 14.8 16.1 14.7 Median 10.8 10.7 9.8

Source: Grant Samuel analysis14 The multiples shown above are based on sharemarket prices as at 29 September 2009 and do not reflect a premium for control. All of the companies have a 31 December year end with the exception of Lyttelton Port Company, South Port New Zealand Ltd and Port of Tauranga Ltd which have 30 June year end.

Shanghai International Port (Group) Co

Shanghai International Port (Group) Co (“SIPC”) is the sole operator of Shanghai Port, one of the world’s largest container and cargo ports. Operation of the container terminal is SIPC’s main business but the company also undertakes bulk handling and port-related logistics and services. For the year ended 31 December 2008, SIPC reported revenues of approximately CNY18 billion and EBITDA of

11 The companies selected have a variety of year ends and therefore the data presented for each entity is the most recent annual historical

result plus the subsequent two forecast years. 12 Based on share prices as at 29 September 2009 and spot exchange rates of AUDCNY: 6.004, AUDMYR: 3.0569, AUDGBP:0.5457,

AUDUSD: 0.8703, AUDNZD: 1.2183, AUD:EUR: 0.6012 13 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at the

latest balance date) divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation, investment income and significant and non-recurring items.

14 Grant Samuel analysis based on data obtained from IRESS, company announcements and, in the absence of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each company depends on analyst coverage, availability and recent corporate activity.

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approximately CNY10.4 billion. Key shareholders of SIPC include the municipal government of Shanghai (44.23%), China Merchants International Terminals (Shanghai) Co Ltd. (26.54%) and Shanghai Tongsheng Investment (Group) Corp. (16.81%). Shenzhen Chiwan Wharf Holdings Limited

Shenzhen Chiwan Wharf Holdings Limited (“Shenzhen Chiwan”) is listed on the Shanghai Stock Exchange and is principally engaged in the handling, storage and transportation of containers and bulk cargos at the terminals of Chiwan Port in Shenzhen, Guangdong Province, China. Shenzhen Chiwan also provides land transportation, pilotage and shipping brokerage services. Bulk and general cargo handled by Shenzhen Chiwan includes foodstuffs and fertilizers. For the year ended 31 December 2008, the company reported revenue of HK$1.8 billion and EBITDA of approximately HK$1.5 billion. Tianjin Port Holdings Company Limited

Tianjin Port Holdings Company Limited (“Tianjin Port Co”) is based in Tianjin, China. Tianjin Port Co is listed on the Shanghai Stock Exchange and is primarily engaged in the loading, splitting, and unloading of containers. It is also involved in warehousing and storage of cargo, and the provision of integrated transportation, freight forwarding, and shipping brokerage services. The company primarily handles charcoal, coal, ore, and other bulk cargo. About 60% of its revenue comes from energy-related coal and metal ores, with a further 25% from containers. For the year ended 31 December 2008, Tianjin Port Co reported revenues of approximately RMB11.2 billion and EBITDA of RMB2.2 billion. In March 2009, Tianjin Port Development Holdings Limited announced the acquisition of a 56.8% stake in Tianjin Port Co for a total consideration of approximately HK$10.96 billion. The transaction is expected to complete before end of 2009. Tianjin Port Development Holdings Limited is the other major terminal operator at the port of Tianjin and is focused on container terminal operations. China Merchants Holdings (International) Co Ltd

China Merchants Holdings (International) Co Ltd (“CMHI”) is an investment holding company listed on the Hong Kong Stock Exchange. Through its subsidiaries, CMHI is the largest port operator in China with interests in seven of the top eight ports which account for 70% of China’s container throughput. For the year ended 31 December 2008, CMHI through its various ports handled a total of 50.4 million TEU and 211 million tonnes of bulk cargo. CMHI recorded revenues (including its share from associates and jointly controlled entities) of HK$28 billion with port and port related operations accounting for more than 90% (HK$2.7 billion). The total reported EBITDA of HK$7.5 billion included HK$6.3 billion contribution from the port operations. The major shareholder of CMHI is China Merchants Group Limited with a 55.8% interest. Cosco Pacific Ltd

Cosco Pacific Ltd (“Cosco Pacific”) is an investment holding company listed on the Hong Kong Stock Exchange. Cosco Pacific ,along with its subsidiaries, is amongst the five largest terminal operators in the world. China Ocean Shipping Company, the largest state-owned shipping conglomerate in China and the second largest in the world, holds 50.96% of Cosco Pacific. Cosco Pacific’s principal activities are managing and operating container terminals, container leasing, management and sale, logistics and other related businesses. For the year ended 31 December 2008, Cosco Pacific reported revenue of US$338 million with container leasing, management and sale accounting for approximately 75% of the total revenue. Container terminal operations contributed to the remaining 25% (US$85 million) of revenue. During this period, Cosco Pacific handled 45.9 million TEU through its port terminals with Chinese ports accounting for approximately 90% of the volume. The EBITDA for the year was approximately US$391 million and the reported net profit after tax was US$280 million. Since the end of the financial year, Cosco Pacific has divested its equity interests in its logistics and container manufacturing businesses to focus on its port operations. The share of profits from these divested businesses had been approximately US$64 million for the financial year ended December 2008. Bintulu Port Holdings Berhad

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Bintulu Port Holdings Berhad (“Bintulu Ports”) is a Malaysia-based investment holding company listed on the main board of Bursa Malaysia Securities Berhad. The Group is engaged in the provision of port services at Bintulu Port, Sarawak, and the provision of bulking installation facilities for palm oil, edible oils, vegetable oils, fats and its by-products. For the year ended 31 December 2008, the group handled cargo throughput of about 40 million tonnes with LNG accounting for more than 56% of the total cargo throughput. The Group recorded operating revenue of RM449 million and EBITDA of RM214 million. There are three major shareholders of Bintulu Ports accounting for 75.3% of equity being Petroliam Nasional Berhad (32.8%), State Financial Secretary Sarawak (30.7%) and Diperbadankan (11.8%). Dalian Port (PDA) Company Limited

Dalian Port (PDA) Company Limited (“Dalian”) is listed on the Hong Kong Stock Exchange and is an oil and container terminal operator in China. The Dalian port is one of China’s four strategic oil reserve bases and Dalian is the largest oil/liquified chemicals, container and automobile terminal operator in northwestern China. For the year ended 31 December 2008, Dalian handled 5.5 million TEUs of container boxes, 34.9 million tonnes of oil/chemicals cargo and 16,143 vehicles, and recorded revenues of RMB1,587 million and underlying EBITDA of RMB756 million. The net profit of RMB780 however included gains of approximately RMB400 million related to the disposal of various assets. The oil/chemicals terminal provision and related logistics services were the major business contributors and accounted for 42% of the total revenue and 54% of the gross profit of the company. The container terminal and logistics division contributed to 36% of the total revenue and 23% of the gross profit and the automobile terminal division accounted for the remaining. Dalian Port Corporation is the major shareholder in the group with a 62.09% interest. Forth Ports PLC

Forth Ports PLC (“FPT”) is the largest port company listed on the London Stock Exchange. FPT operates seven ports – six ports in Scotland and the port of Tilbury in London. In addition, FPT also provides marine services, controlling navigation in the Firths of Forth and Tay and operates towage fleet. FPT is also involved in real estate activities mainly related to the regeneration of the coastline at Leith-Edinburgh and has 400 acres of development land near the port of Leith. During the year ended 31 December 2008, FPT handled 48.7 million tonnes of cargo through its ports. Liquid cargo tonnages accounted for 34.4 million tonnes and dry cargo tonnage accounted for the balance. FPT reported total revenue of £186 million for the year, almost exclusively from its port operations and underlying EBITDA of £69 million. Primarily as a result of write down (£27.7 million) of property investments and its share of revaluation loss (£19.7 million) from joint ventures, FPT however reported a net loss of £51.2 million for the year. At 16 March 2009, Babcock and Brown Ltd was the largest investor in FPT with a 23.5% shareholding. Lyttelton Port Company Limited

Lyttelton Port Company Limited (“LPC”) is responsible for the overall management of the port of Lyttelton in Christchurch, New Zealand. LPC’s principal activities include the provision of port facilities, marine services and the cargo handling of coal and containers. For the year ended 30 June 2009, LPC handled 9.5 million tonnes of cargo including over 2 million tonnes of coal through the coal facility that is the largest in New Zealand. Bulk fuel and dry bulk were the other main commodities handled at the port. The company’s container terminal also recorded throughput volume of 238,651 TEUs. For the 2009 financial year, LPC reported total revenue of NZ$84 million and EBITDA of approximately NZ$30 million. Christchurch City Council is the major shareholder in LPC with a 65% shareholding. South Port New Zealand Ltd

South Port New Zealand Ltd (“SPN”) is listed on the New Zealand Stock Exchange with a majority shareholding being held by Environment South (66.5%). SPN conducts its primary port operations business on a 40-hectare island harbour situated at Bluff and offers full-container, general and bulk cargo capability. The company handles in excess two million tons of cargo each year and the cargo includes alumina, petroleum products, fertilizer, acid, fish, timber, medium density fiber (MDF), logs, dairy, meat by-products and woodchips. For the 2009 financial year, LPC reported total revenue of NZ$19 million

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and EBITDA of NZ$6.7 million. The net profit after tax of NZ$4 million however included one-off gains about NZ$0.8 million. DP World Limited

DP World Limited (“DP World”) is one of the world’s largest container port terminal operators with operations in more than 26 countries. DP World is a subsidiary of Dubai World (Port & Free Zone World FZE) (“Dubai World”) which has 80.45% interest in the company. Dubai World is an investment holding company that manages and supervises a portfolio of businesses and projects for the Dubai Government and its shares are listed on the Nasdaq Dubai stock exchange. As at 31 December 2008, DP World terminals had a total capacity of 56 million TEUs. For the year ended 31 December 2008, DP World handled 46.8 million TEUs through its portfolio of port terminals from the Americas to Asia. The company reported consolidated revenues of US$3.2 billion and EBITDA of US$1.3 billion. Net profit after tax was US$621 million (excluding $90 million of separately disclosable items). During the financial year, DP World completed the acquisition of a 90% stake in Egyptian Container Terminal Handling Company for US$659 million. Port of Tauranga Limited

Port of Tauranga Limited (“POT”) is the largest port in New Zealand and is listed on the New Zealand Stock Exchange. The port currently handles more than 13 million tonnes of cargo per annum and with the recently increased land holding of 185 hectares, plans are under review to increase the port capacity. The principle commodities handled at the port include forestry, kiwi fruit and dairy products (exports) and petroleum, fertilizers and coal (imports). Work is being undertaken to facilitate port access to larger ships which will increase the volume of business through the port. Through joint ventures, the company also provides marine services, a range of container handling services and national log marshalling, stevedoring and inventory management services. For the year ended 30 June 2009, POT reported total revenue of NZ$144 million and EBITDA of approximately NZ$81 million. Hamburger Hafen und Logistik AG

Hamburger Hafen und Logistik AG (“HHLA”) is a Germany based company involved in the European seaport transportation industry. The company offers vertically integrated services, from container terminals management to hinterland transport systems and logistics services, to create a connection between the international port and the customer. For the year ended 31 December 2008, HHLA reported revenues of €1.3 billion and EBITDA of €457 million. During the year, the container division of HHLA handled 7.3 million TEUs and contributed to more than 60% of HHLA’s total revenue.

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2.2 Rail

The trading multiples of selected listed rail transport companies are set out below:

Sharemarket Ratings of Selected Listed Entities15 EBITDA Multiple16

(times)

Market Capitalisation

(millions) Historical Forecast Year 1

Forecast Year 2

Transport - Rail Australia

Asciano Limited A$4,784.2 14.1 12.9 10.4 International

Canadian National Railway Co C$25,079.1 8.9 10.2 9.1

Canadian Pacific Railway Ltd C$8,563.9 8.4 8.8 8.2

Union Pacific Corp US$30,404.5 7.1 8.0 7.2

Burlington Northern Santa Fe Corp US$27,725.5 7.0 7.5 7.1

CSX Corp US$17,162.2 6.6 7.5 7.0

Norfolk Southern Corp US$16,345.1 5.3 7.2 6.4

Kansas City Southern US$2,519.9 8.4 11.1 8.6

Genesee & Wyoming Inc US$1,289.7 10.8 11.2 10.2

Minimum 5.3 7.2 6.4

Maximum 14.1 12.9 10.4 Median 8.4 8.8 8.2

Source: Grant Samuel analysis17 The multiples shown above are based on sharemarket prices as at 29 September 2009 and do not reflect a premium for control. All of the companies have a 31 December year end except for Asciano and CSX Corp which have a 30 June and 26 December year end respectively. A brief description of each company is set out below: Asciano Limited Asciano Limited (“Asciano”) is one of Australia's largest listed infrastructure owners, with a primary focus on transport infrastructure, including ports and rail assets, and associated operations and services. There is an approximate 50:50 split in earnings between the ports and rail business. It is Australia's leading lessee operator of container terminals and the largest stevedoring provider and has operations in Australia's four largest container ports. The rail business comprises Pacific National, Australia's leading provider of bulk haulage services for coal, grain, bulk industrial products and intermodal services. For the financial year ending 30 June 2009 Asciano recorded revenues of approximately A$2,797 million. The company’s operating segments and their respective contributions to 2009 revenues were as follows: Coal (19%), Intermodal (31%), Container Ports (26%) and Auto Bulk & General (24%). Canadian National Railway Company

15 The data presented for each entity is the most recent annual historical result plus the subsequent two forecast years. 16 Represents gross capitalisation (that is, the sum of the market capitalisation adjusted for minorities, plus borrowings less cash as at the

latest balance date) divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation, investment income and significant and non-recurring items.

17 Grant Samuel analysis based on data obtained from IRESS, company announcements and, in the absence of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each company depends on analyst coverage, availability and recent corporate activity.

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Canadian National Railway Company (“CN”) is a nationwide railroad in Canada with a network that stretches from Halifax on the east coast to Vancouver and Prince Rupert on the west coast of Canada and south into New Orleans in the United States. The company has alliances with other carriers which has extended its reach into Mexico. In the financial year ending 31 December 2008 CN generated revenues of approximately CA$8.5 million, to which Canadian and United States operations contributed approximately 66% and 34% respectively. Canadian Pacific Railway Company Canadian Pacific Railway Company (“Canadian Pacific”) provides rail and intermodal freight transport services throughout North America. Its 13,800-mile rail network serves the principal centers of Canada, from Montreal to Vancouver, and the US Northeast and Midwest regions. Agreements with other carriers extend its market reach throughout the US and into Mexico. In the financial year ending 31 December 2008 Canadian Pacific recorded revenue of approximately CA$4,932 million. Union Pacific Corporation Union Pacific Corporation (“Union Pacific”) owns one of America’s leading transportation companies. Its principal operating company, Union Pacific Railroad Company, links 23 states in the western two-thirds of the country and offers competitive long-haul routes from all major West Coast and Gulf Coast ports to eastern gateways. Union Pacific operates through one business segment, rail freight, which for the financial year ending 31 December 2008 recorded freight revenues of approximately US$17,970 million. Commodity group contributions to revenue for the 2008 financial year were as follows: Intermodal (18%), Industrial products (19%), Energy (22%), Chemicals (15%), Automotive (8%), and Agricultural (18%). Burlington Northern Santa Fe Corporation Burlington Northern Santa Fe Corporation (“BNSF”) operates over a railroad system consisting of approximately 32,000 route miles of track (approximately 24,000 miles of which are owned route miles including easements) in 28 states and two Canadian provinces. The Company recorded revenues for the full year ending 31 December 2008 of approximately US$18,018 million. Operating segments and their contribution to 2008 financial year revenue was as follows: Consumer products (35%), Industrial products (23%), Coal (23%) and Agricultural products (20%). CSX Corporation CSX Corporation (“CSX”) operates approximately 21,000 route miles of track across a network in the eastern United States that links East Coast and Gulf Coast ports with the eastern US and the Midwest, including Chicago. CSX recorded revenues of approximately US$11,255 million for the financial year ending 31 December 2008. The company’s primary operating segments and their respective contributions to full year 2008 revenue are Rail (87%) and Intermodal (13%). CSX’s top commodity segments by approximate revenue share are coal (29%), intermodal (13%), chemicals (13%), and agricultural products (9%). Norfolk Southern Corporation Norfolk Southern Corporation (“Norfolk Southern”) controls the Norfolk Southern Railway and offers intermodal services through subsidiaries Triple Crown Services and Thoroughbred Direct Intermodal Services. The railway operates a 21,300 route mile network in 22 eastern states of the US, District of Columbia, and Ontario, Canada. It provides comprehensive logistics services and serves 20 seaports and lake ports in the US and Canada. For the financial year ending 31 December 2008 the company recorded revenue of approximately US$10,661 million. Approximate revenue contribution by commodity group was as follows: Coal (29%), General merchandise (52%) and Intermodal (19%).

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Kansas City Southern Kansas City Southern (“KCS”) operates a nearly 6,000-track mile network, serving 10 states in the central and south central United States and Mexico. The company's Mexican operating subsidiary, Kansas Southern de Mexico, is the largest primary Mexican rail carrier. For the financial year ending 31 December 2008 the company recorded revenues of approximately US$1,852 million. Approximately 56% of this was derived from United States operations, and 44% from operations within Mexico. Genesee & Wyoming Inc Genesee & Wyoming Inc (“G&W”) owns and operates short line and regional freight railroads. The majority of G&W’s properties are in the US, with additional rail assets in Canada, Australia, the Netherlands, as well as a minority interest in a Bolivian railroad. In total Genesee & Wyoming owns or leases 63 railroads with a total of 9,900 miles of track (6,800 miles owned/leased and the other 3,100 under access arrangements). For the financial year ending 31 December 2008 the company recorded revenues of approximately US$600 million. Geographic contributions to revenue were as follows: United States (70%), Australia (19%), Canada (9%) and Netherlands (2%).

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Appendix 4

Market Evidence – Transactions

1 Energy Transmission and Distribution

1.1 Australia and New Zealand

A selection of relevant energy transmission and distribution infrastructure and infrastructure services transactions since 2002 is set out below:

Recent Transaction Evidence

EBITDA Multiple2 (times) Date Target Transaction

Consid- eration1

(millions) Historical Forecast

Electricity – Australia

Dec 06 DirectLink Acquisition by APA A$170 na 15.3

Mar 06 Murraylink Acquisition by APA A$153 na 15.8

Dec 05 SP AusNet IPO A$2,888 13.3 13.1

Nov 05 Spark IPO A$2,017 9.9 10.7

Apr 04 TXU Australia Acquisition by Singapore Power A$5,100 9.2 8.6

Jul 03 United Energy Scheme of arrangement with Alinta A$1,340 8.1 7.5

Gas – Australia

Apr 07 Envestra Acquisition of 17.2% by APA A$990 12.7 13.1

Apr 07

SEA Gas Pipeline Acquisition of 33.3% by APA A$400 na 14.5

Nov 06 AIH Acquisition by Alinta A$956 14.3 14.5

Oct 06 Allgas Acquisition by APA A$521 na 18.1

Aug 06 GasNet Takeover by APA A$452 13.9 13.3

Apr 06 AGL Infrastructure Acquisition by Alinta A$6,500 13.0 12.6

Sep 05 AIH IPO A$926 17.4 14.2

Feb 05 Carpentaria Gas Pipeline

Acquisition of 30% by APA A$327 na na

Aug 04 Dampier to Bunbury Natural Gas Pipeline

Acquisition by DUET/Alinta/Alcoa Consortium

A$1,860 na 11.1

Aug 04 45% of Southern Cross Pipelines and 100% of Parmelia Gas

Acquisition by APA A$206 8.3 na

Mar 04 Duke Energy Australian and New Zealand assets

Acquisition by Alinta A$1,690 17.0 15.5

1 Implied equity value if 100% of the company or business had been acquired. 2 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items.

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Recent Transaction Evidence Date Target Consid-

eration3 (millions)

EBITDA Multiple4 (times)

Electricity – New Zealand Historical Forecast Nov 08 Powerco Acquisition of 58% by QIC NZ$726 9.1 9.1 Apr 08 Wellington

Electricity Network Acquisition by CKI NZ$785 na 9.8

Aug 04 Powerco Acquisition by Prime Infrastructure NZ$680 9.4 9.0 Sep 02 UnitedNetworks Acquisition by Vector NZ$1,500 8.7 8.4 Sep 02 UnitedNetworks’

electricity distribution networks

Acquisition by Powerco NZ$590 9.0 8.9

Gas – New Zealand Apr 07 Rockgas Limited Acquisition by Contact Energy NZ$156 8.0 7.8 Jun 05 NGC Holdings Acquisition of 32.8% interest by Vector NZ$1,506 10.7 10.1 Oct 04 NGC Holdings Acquisition of 67.2% interest by Vector NZ$866 9.6 9.2 Infrastructure Services – Australia Apr 07 Origin Energy Asset

Management Acquisition by APA A$253 na 13.1

Apr 06 Agility Acquisition by Alinta A$1,050 13.8 12.3

Source: Grant Samuel analysis5 A brief summary of each transaction is set out below. Electricity - Australia DirectLink / APA Group In February 2007, APA Group (“APA”) (formerly known as Australian Pipeline Trust) acquired the DirectLink electricity transmission asset linking the New South Wales and Queensland power grids for $170 million. APA acquired DirectLink from the DirectLink joint venture, which comprised Country Energy, Hydro Quebec International Group and Fonds de Solidarite des Travailleurs de Quebec. The acquisition price represented a regulated asset base (“RAB”) multiple of 1.44 times based on the 31 December 2006 forecast RAB. Murraylink / APA Group In March 2006, APA announced it would acquire the Murraylink electricity transmission assets (“Murraylink”) for $153 million. Murraylink is a 180 kilometre underground high voltage direct current cable interconnector between South Australia and Victoria with a capacity of 220MW. APA had interests in approximately 7,500 kilometres of gas transmission pipelines throughout Australia but was pursuing a strategy of making value-accretive acquisitions in complementary asset classes. Murraylink was APA’s first significant acquisition of a non-gas transmission asset. This acquisition represented a RAB multiple of 1.47 times.

3 Implied equity value if 100% of the company or business had been acquired. 4 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items. 5 Grant Samuel analysis based on data obtained from IRESS, company announcements, transaction documentation and, in the absence

of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each transaction depends on analyst coverage, availability and corporate activity.

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SP AusNet SP AusNet was formed to house the Australasian assets of Singapore Power Limited (“Singapore Power”). The company was listed on the Australian Stock Exchange (“ASX”) on 14 December 2005. SP AusNet is the primary electricity transmission provider and electricity and gas distribution business in Victoria. In 2005, 87% of revenues were regulated. Singapore Power has retained a 51% interest in SP AusNet. Spark Infrastructure Spark Infrastructure (“Spark”) was formed to hold a diversified portfolio of regulated utility infrastructure assets in Australia. Spark was listed on the ASX on 16 December 2005 with a market capitalisation of approximately $2.0 billion. It is managed by a company owned jointly by Cheung Kong Infrastructure Holdings Limited (“CKI”), a listed company in Hong Kong with a portfolio of over $33 billion in utility and infrastructure investments, and RREEF Infrastructure (“RREEF”), the infrastructure investment business of Deutsche Asset Management. Spark’s initial portfolio comprises a 49% interest in each of CitiPower, Powercor and ETSA, with the remaining 51% interest being held by CKI and its affiliate, Hongkong Electric (“HKE”). CitiPower and Powercor are electricity distributors operating in Victoria and ETSA is an electricity distributor in South Australia. The calculation of underlying multiples for Spark is complex because of the minority holdings and form of investment. Texas Utilities’ Australian Assets / Singapore Power In April 2004 Singapore Power acquired Texas Utilities’ Australian assets (“TXU Australia”) for $5.1 billion. These assets included significant electricity and gas networks in Victoria and a retail business supplying approximately one million customers in Victoria and South Australia. United Energy Limited / Alinta Limited United Energy Limited (“United Energy”) owned and operated an electricity distribution network in the south eastern suburbs of Melbourne and the Mornington Peninsula in Victoria. It also had investments in a number of other Australian utility businesses including the listed companies Alinta Limited (“Alinta”) and Uecomm Limited. On 23 April 2003, Alinta announced that through a complex series of transactions, it would acquire a 34% interest in United Energy’s distribution assets and a 100% interest in its non-distribution assets. To complete the transaction, Alinta and AMP Henderson Global Investors acquired the 43% of United Energy held by the public through a scheme of arrangement. Gas - Australia Envestra Limited / APA Group In April 2007, APA announced it had entered into a conditional agreement with Origin Energy to acquire its 17.2% stake in Envestra Limited (“Envestra”) for $170.4 million. This represented a 4.4% discount to the closing price at 3 April 2007. At the time of the acquisition, Envestra was Australia’s largest natural gas distributor, with 19,100 kilometres of natural gas distribution networks and 1,029 kilometres of natural gas transmission pipelines, and over 95% of Envestra’s revenue was regulated. APA became Envestra’s largest shareholder on completion of the acquisition. As the transaction involved a minority interest the implied multiples do not include a premium for control. However, the interest acquired was strategic. SEA Gas Pipeline / APA Group In April 2007, APA announced it had entered into a conditional agreement with Origin Energy Limited (“Origin Energy”) to acquire Origin Energy’s 33.3% interest in SEA Gas Pipeline for $133.2 million. The SEA Gas Pipeline is a 114 PJ per annum capacity, 680 kilometres pipeline

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linking the Victorian gas fields to South Australian markets. APA was responsible for operating and maintaining the pipeline. Alinta Infrastructure Holdings Limited / Alinta Limited On 15 November 2006, Alinta announced an unconditional cash takeover offer for the 80% of securities in Alinta Infrastructure Holdings Limited (“AIH”) that Alinta did not already own. Alinta formed AIH in August 2005 from a portfolio of nine gas transmission infrastructure and power generation assets. The initial public offering of AIH in October 2005 took the form of a partly paid issue, with $2.00 per stapled security payable on application and $1.20 per stapled security payable on 29 December 2006 (“the second instalment”). Alinta retained a 20% interest in AIH at listing, with an agreement to maintain an interest of at least 15%. Alinta’s offer was $2.06 cash per partly paid security (pre second instalment) or $3.26 post the second instalment. Alinta completed the acquisition of AIH in February 2007. Allgas Energy Pty Ltd / APA Group In October 2006, APA announced it would acquire Allgas Energy Pty Ltd (“Allgas”) from ENERGEX Limited for $521 million. Allgas was one of two gas distribution businesses in South East Queensland and had a 2,300 kilometres regulated gas network spanning Brisbane, the Gold Coast, Northern New South Wales, Toowoomba and Oakey that supplied approximately 65,000 customers. The Allgas network was supplied by APA’s Roma to Brisbane Pipeline and was a complementary infrastructure to APA’s gas transmission businesses. APA planned to expand the Allgas distribution network and increase network utilisation. GasNet Australia Group / APA Group In June 2006, Babcock & Brown Infrastructure Group (“BBI”) announced, in association with APA, it would make a scrip takeover offer for GasNet Australia Group (“GasNet”). The consideration offered was 1.545 BBI stapled securities for each GasNet stapled security not already owned by BBI and APA (together 14.2%). The offer represented $2.45 per GasNet stapled security, excluding the estimated 6.75 cents final distribution announced by BBI ($2.55 cum dividend). GasNet directors rejected the offer on the basis that it materially undervalued the company and was highly conditional. On 15 August 2006, Colonial First State Global Asset Management announced a recommended counter offer of $2.88 cash per stapled security ($2.77 after adjusting for the proposed 11 cent distribution for the six months to 30 June 2006). On 22 August 2006, BBI and APA announced the termination of their joint bidding agreement and their bid lapsed. In addition, APA announced an offer of $3.10 cash per stapled security valuing GasNet at $452 million. GasNet owned and operated 1,930 kilometres of pipelines and a LNG storage facility in Victoria as well as a 450 kilometres pipeline in Western Australia. The APA offer represented a RAB multiple of 1.64 times assuming regulated assets represented 75% of total assets. AGL Infrastructure Assets / Alinta Limited On 26 April 2006, The Australian Gas Light Company (“AGL”) and Alinta announced an agreement to merge and restructure their respective businesses to create two separated listed companies, Alinta Limited (“New Alinta”) (focused on the ownership and management of energy infrastructure assets) and AGL Energy Limited (focused on energy retailing, trading and generation). One component of the transaction involved the acquisition of AGL’s infrastructure and asset management businesses for $6.5 billion. The businesses acquired included a gas network in New South Wales, an electricity network in Victoria and 50% of the ActewAGL Distribution Partnership, the Agility infrastructure management and services business, Wattle Point Wind Farm in South Australia, the Cawse Cogeneration facility in Western Australia, Gas Valpo (a regional gas distribution and retailing business in Chile) and a 30% interest in APA. The gas and electricity networks (including ActewAGL) represented 65-70% of the value attributed to the AGL Infrastructure Assets and the New South Wales gas network was the major component of those assets.

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The multiples calculated for the transaction reflect the blend of businesses (including a substantial asset management business), that the network assets were substantial, high quality assets and that the AGL Infrastructure business on a standalone basis had a lower relative tax cost base than its peers. Alinta Infrastructure Holdings In September 2005, Alinta announced that it would spin off infrastructure assets into a separately listed stapled entity, Alinta Infrastructure Holdings (“Alinta Infrastructure”). Alinta Infrastructure’s initial assets consisted of the gas pipeline and electricity generation assets acquired by Alinta from Duke Energy in March 2004 (see below). The multiples calculated are based on the application price of $3.20 per stapled security. As the offering reflects sharemarket prices for gas transmission and electricity generation assets the implied multiples do not include a premium for control. The earnings have been adjusted to reverse the impact of accounting for Glenbrook Power Station as a finance lease. Carpentaria Gas Pipeline / APA Group In February 2005, APA purchased the remaining 30% of Carpentaria Gas Pipeline that it did not already own from Santos Limited, Origin Energy and Delhi Petroleum for $98 million cash. Carpentaria Gas Pipeline was an 840 kilometres gas pipeline which connected the Ballera gas fields in south west Queensland to Mt Isa in north west Queensland. The customers at Mt Isa were WMC, BHP Billiton, Xstrata and CS Energy. Dampier to Bunbury Natural Gas Pipeline / DUET / Alinta / Alcoa Consortium In August 2004, the receivers and managers of the Dampier to Bunbury Natural Gas Pipeline (“DBNGP”) announced that a consortium comprising Diversified Utility and Energy Trusts (“DUET”) (60%), Alinta (20%) and Alcoa of Australia Limited (“Alcoa”) (20%) had been named as the preferred bidder for the purchase of 100% of DBNGP and its associated assets. The consortium’s bidding price was approximately $1.86 billion (excluding transaction costs and proposed capital expenditure). The acquisition further diversified DUET’s portfolio of regulated energy utility businesses and added a strategic gas transmission asset. Southern Cross Pipelines and Parmelia Gas Business / APA Group In August 2004, APA purchased the remaining 45% of Southern Cross Pipelines (“SCP”) that it did not already own and 100% of the Parmelia Gas business (“Parmelia”) from CMS Energy. SCP was the 88.2% owner of the 1,380 kilometre Goldfield Gas Transmission Pipeline in Western Australia. Parmelia owned and operated a transmission pipeline, a gas processing facility and storage facilities in Western Australia. The assets were purchased for $206 million and included the assumption of 45% of SCP’s $250 million of debt. Duke Energy’s Australian and New Zealand Assets / Alinta Limited In March 2004, Alinta announced that it had reached an agreement to purchase the Australian and New Zealand gas assets of Duke Energy, following Duke Energy’s decision to exit the Asia-Pacific region. The assets acquired were three gas transmission pipelines and three gas-fired power stations in Australia and one gas-fired power station in New Zealand. The pipelines had a combined length of 2,156 kilometres and the power plants had a combined capacity of 686MW. The acquisition provided Alinta with a stable and secure income stream and strong potential for volume growth, particularly from the pipeline assets on Australia’s east coast.

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Electricity – New Zealand Powerco Limited / QIC In November 2008, BBI announced the proposed sale of 50% of its Powerco New Zealand operations to QIC for NZ$400 million following a competitive sale process. The Tasmanian gas distribution network was excluded from the sale. At completion of the transaction in February 2009, BBI announced that the transaction had been restructured such that QIC would acquire a 58% in Powerco for NZ$421.2 million. Powerco is New Zealand’s second largest electricity and gas distribution business with over 400,000 customers covering 39,000 square kilometres in the North Island of New Zealand. Vector Limited’s Wellington electricity network / Cheung Hong Infrastructure Holdings (CKI) In April 2008, Vector Limited (“Vector”) announced the sale of its Wellington electricity network to CKI for NZ$785 million after reviewing a number of approaches. The average age of the network assets was 32 years and the network had averaged demand growth of 1.2% per annum over the last five years. Vector continued to hold the Auckland electricity networks and its interests in the fibre-optic telecommunications network in Wellington. Powerco Limited / Prime Infrastructure Networks (New Zealand) Limited In September 2004, Prime Infrastructure Networks (New Zealand) Limited (“Prime Infrastructure”) made an offer to acquire all of the ordinary shares and capital bonds of Powerco Limited (“Powerco”) at NZ$2.15 per share, to be paid using a mix of cash and a subordinated debt security. The structure of the offer was highly complex and significant uncertainty surrounded the volume and underlying value of the subordinated debt securities to be issued under the offer. Powerco was New Zealand’s second largest electricity and gas distribution company. It had a network servicing approximately 400,000 consumers in the North Island, representing 46% of the gas connections and 16% of the electricity connections in New Zealand. UnitedNetworks Limited / Vector Limited In October 2002, Vector completed the acquisition of all of the shares in UnitedNetworks Limited (“UnitedNetworks”) at a price of NZ$9.90 per share. The offer was the result of a formal sale process involving a number of competing bidders. UnitedNetworks received a number of bids for the shares and assets of UnitedNetworks and the offer by Vector was selected by the independent directors of UnitedNetworks as affording the best value outcome for UnitedNetworks’ shareholders. UnitedNetworks was an electricity distribution business operating electricity networks in Auckland and in the Wellington City, Lower Hutt, Upper Hutt and Porirua districts. UnitedNetworks Limited / Powerco Limited In September 2002, Powerco acquired UnitedNetworks’ electricity distribution networks in the Tauranga, eastern and southern Waikato, Thames and Coromandel regions. The transaction almost doubled the size of Powerco’s electricity lines business, making it the second largest in New Zealand. Gas – New Zealand Rockgas Limited / Contact Energy In April 2007, Contact Energy acquired Rockgas Limited from Origin Energy for NZ$156 million. Rockgas was a distributor and retailer of liquefied petroleum gas in New Zealand, supplying over 50% of the New Zealand LPG market.

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NGC Holdings Limited / Vector Limited On 27 June 2005, Vector announced a takeover offer for the 32.8% of the shares that it did not already own in NGC Holdings Limited (“NGC”) and provided details of its proposed initial public offering. Vector had previously acquired a 67.2% shareholding in NGC following a takeover offer made in December 2004. The consideration offered for NGC was NZ$2.62 worth of Vector shares and NZ$0.78 cash for each share in NGC. NGC’s operations comprised gas transmission and distribution services, energy sales and processing of natural gas, LPG and gas liquids, ownership and management of electricity and gas meters and the provision of related metering services. Vector also operated businesses that delivered high-speed voice and data communications. It was the largest owner and manager of electricity infrastructure networks in New Zealand with electricity networks in Auckland and Wellington serving over 644,000 customers. NGC’s business activities were complementary to Vector’s own electricity, gas, metering and telecommunications assets in terms of location, market position and scale. NGC Holdings Limited / Vector Limited On 11 October 2004, Vector announced that it had entered into an agreement to acquire AGL’s 66.05% stake in NGC at a price of NZ$3.00 per share. Completion of the sale was subject to an exemption being granted by the Takeovers’ Panel which would allow AGL to sell its New Zealand holding company, AGL NZ Limited, to Vector rather than the shares in NGC. The exemption was not granted and on 19 November 2004 Vector issued a notice of intention to make a takeover offer for all of the shares in NGC. The takeover offer closed on 4 February 2005 with Vector having gained acceptances for a further 1.2% of NGC shares on top of the 66.05% acquired from AGL. The cash consideration paid to AGL under the takeover offer was reduced from NZ$3.00 to NZ$2.91 due to the payment of a NZ$0.09 special dividend on 3 November 2004. Infrastructure Services – Australia Origin Energy Asset Management / APA Group In April 2007, APA announced it had entered into a conditional agreement with Origin Energy to purchase Origin Energy Asset Management and associated businesses (“OEAM”) for $252.9 million. OEAM provided a full range of services to operate and manage gas and other energy and water infrastructure in Australia. Over 90% of OEAM’s revenue was derived from its operating and management agreements with Envestra. Agility / Alinta Limited In April 2006, Alinta and AGL announced an agreement to merge and restructure their businesses to create two separate listed companies, Alinta and AGL Energy. As part of the restructure Alinta acquired AGL’s infrastructure management and services business, Agility. The independent expert valued Agility at $1.0-1.1 billion on a standalone basis. Multiples shown in the table exclude any allowance for costs savings previously identified by AGL. If AGL’s forecast cost savings are included the EBITDA multiples fall to 11.3 and 10.8 times respectively.

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1.2 United States

Recent Transaction Evidence EBITDA Multiple8

(times) Date Target Type6 Transaction Consideration7 (millions) Historical Forecast

Energy Transmission – United States

May 09 North Baja Pipeline G Acquisition by TC

Pipelines US$270 9.6 na

Apr 09

Ozark Gas Transmission and Ozark Gas Gathering

G Acquisition by Spectra Energy Partners US$300 6.5 na

Dec 07

Natural Gas Pipeline of America

G Acquisition by Babcock & Brown led consortium US$7,237 10.5 na

Dec 06 ANR Pipelines G Acquisition by TransCanada US$2,943 10.6 na

Nov 05 Cross Sound Cable E Acquisition by BBI US$213 na 15.19 Energy Transmission - Australia Jul 07 Basslink E Acquisition by CitySpring US$1,001 16.410 12.811

Source: Grant Samuel analysis12 A brief summary of each transaction is set out below. Energy Transmission and Distribution – United States TC Pipelines/North Baja Pipeline On 20 May 2009, TC Pipelines announced it had entered into an agreement to acquire North Baja Pipeline LLC (“North Baja”) from TransCanada Corporation (“TransCanada”) for approximately US$270 million. The North Baja Pipeline was 100% owned by TransCanada and extends 129 kilometre from Ehrenberg in southwestern Arizona to a point near Ogilby, California on the Californian/Mexico border and connects with the Gasoducto Bajanorte natural gas pipeline system in Mexico. The acquisition price represented a historical EV/EBITDA multiple of 9.6 times. Spectra Energy Partners/Ozark Gas Transmission and Ozark Gas Gathering On 8 April 2009 Spectar Energy Partners LP announced that it had entered into a definitive agreement to acquire Ozark Gas Transmission and Ozark Gas Gathering from Atlas Pipeline Partners for US$300 million. Ozark Gas Transmission is a 565 mile FERC-regulated natural gas interstate pipeline which transports natural gas from receipt points in eastern Oklahoma, to Arkansas and Missouri, and interstate pipelines in Arkansas. Ozark Gas Gathering owns 370 miles of intrastate natural gas gathering pipeline located in eastern Oklahoma and western Arkansas, providing access to both the well-established Arkoma Basin and the newly-exploited Fayetteville and Woodford Shales. The transaction completed on 4 May 2009 and represents a historical EBITDA multiple of 6.5 times.

6 G = Gas; E=Electricity, W=Water. 7 Implied equity value if 100% of the company or business had been acquired. 8 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items. 9 Based on 4 months of Cross Sound Cable earnings annualized. 10 Based on Basslink earnings for the 12 months ending 31 March 2007. 11 Multiple sourced from CitySpring Infrastructure Trust Investor presentation dated 15 December 2007. 12 Grant Samuel analysis based on data obtained from IRESS, company announcements, transaction documentation and, in the absence

of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each transaction depends on analyst coverage, availability and corporate activity.

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Babcock and Brown/National Gas Pipeline of America (“NGPL”) In December 2007 Myria Acquisition Inc (“Myria”) agreed to acquire 80% of Kinder Morgan Inc (formerly MidCon LLC) which was the 100% owner of NGPL for approximately US$7,237 million. Myria was comprised of a syndicate of investors led by Babcock & Brown (including Babcock & Brown Infrastructure who acquired 32% of NGPL), with the remaining 20% of NGPL remaining with Knight Inc, who continued to operate and maintain NGPL under contract. The acquisition price represented a historical EV/EBITDA multiple of 10.5 times. The transaction closed on 15 February 2008. TransCanada/ANR Group On 22 December 2006 TransCanada announced plans to acquire ANR Pipeline Company and ANR Storage Company (collectively “ANR”) from El Paso for US$3,400 million. ANR operates one of the largest interstate natural gas pipeline systems in the United States, providing transportation, storage, and various capacity-related services to a variety of customers in both the United States and Canada. The system consists of approximately 17,000 kilometre of pipeline with a peak-day capacity of 6.8 Bcf/d. The pipeline system also connects with numerous other pipelines providing customers with access to diverse sources of supply from western Canada and the Rocky Mountain region and access to a variety of end-user markets in the midwestern and northeastern United States. Based on ANR segment earnings for the full year ending 31 December 2005, the transaction represents an EBITDA multiple of 10.6 times. The transaction completed on 22 February 2007. Babcock & Brown Infrastructure/Cross Sound Cable In November 2005 BBI entered into a purchase agreement with TransEnergie HQ Inc and UIL Holdings to acquire the membership interest in the Cross Sound Cable Company LLC for US$213 million. The Cross Sound Cable Company LLC has 100% ownership of the Cross Sound Cable Project (“CSC”). The CSC project was commissioned in 2002 and is a 39 kilometre, 330MW submarine cable system connecting the electricity grids of New England and Long Island (New York). The cable entered into continuous operation in early 2005. The transaction was completed on 28 February 2006 and represented a forecast full year (based on annualized CSC earnings for a period of four months) EV/EBITDA multiple of 15.1 times. CitySpring Infrastructure Management/Basslink Electricity Connector In July 2007 CitySpring Infrastructure Management (“CitySpring”) agreed to acquire Basslink Electricity Interconnector (“Basslink”) from National Grid Plc (“National Grid”) for a transaction value of US$1,001 million. Based on Basslink financials for the full year to 31 March 2007 the transaction represented a historical EV/EBITDA multiple of 16.4 times and a forecast EV/EBITDA multiple of 12.8 times. Commissioned in April 2006, at the time of acquisition Basslink was a 360 kilometre link connecting Tasmania with mainland Australia.

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1.3 United Kingdom and Europe

Recent Transaction Evidence EBITDA Multiple15

(times) Date Target Type13 Transaction Consideration14

(millions) Historical Forecast

United Kingdom and Europe Distribution and Utilities

Feb 09 ItalGas G Acquistion by Snam Rete Gas

€4,20016 9.1 na

Sep 05 Inexus Group Holdings

G/E Acquisition by Challenger Infrastructure Fund led consortium

£456 na na

Nov 06 United Utilities Electricity

E Acquisition by Colonial First State led consortium

£1,640 6.917 na

Oct 06 Viridian Plc E Acquisition by Arcapita Bank

£1,620 8.618 7.719

Apr 06 Bristol Water Group W Acquisition by Agbar £165 8.2 8.4

Source: Grant Samuel analysis20 A brief summary of each transaction is set out below. Snam Rete Gas / Italgas On 12 February 2009 Snam Rete Gas (“Snam”) announced the acquisition of 100% of ItalGas from ENI (it’s parent company) for approximately €4,200 million. Italgas is a regulated business, and operates the largest Italian gas distribution network, operating approximately 40,000 kilometres of distribution pipelines throughout the country. For the full year ending 31 December 2008, the transaction represents an EV/EBITDA multiple of 9.1 times. Challenger Infrastructure Fund/Inexus On 1 September 2005, the Challenger Infrastructure Fund (“CIF”) led a consortium to acquire a majority interest in Inexus Group Holdings Limited (“Inexus”) from STAR Capital Partners. The enterprise value for the transaction was £465 million. Following the transaction CIF held approximately 80%, entities managed by Colonial First State Global Asset Management (the Colonial First State Wholesale Infrastructure Income Fund and Colonial First State Private Capital Limited) held 13% and Inexus management 7%. At the time of acquisition Inexus was the largest independent gas transporter in the United Kingdom with a 47% share of total existing connections and more than 450,000 gas and electricity connections and contracts. Due to Inexus reporting negative earnings for the full year ending 31 December 2004, transaction multiples are meaningless.

13 G = Gas; E=Electricity, W=Water 14 Implied equity value if 100% of the company or business had been acquired. 15 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items. 16 Implied transaction value 17 Earnings for the United Utilities Electricity Limited were not disclosed. Multiples were therefore sourced from Colonial First State

Global Asset Managements press release dated 26 November 2007 18 Based on Viridian Plc earnings to 31 March 2006 19 Based on Viridian Plc earnings to 31 March 2007 20 Grant Samuel analysis based on data obtained from IRESS, company announcements, transaction documentation and, in the absence

of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each transaction depends on analyst coverage, availability and corporate activity.

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Colonial First State consortium/United Utilities Electricity Limited In November 2007 Colonial First State Global Asset Management (“Colonial”) led a consortium (including JPMorgan Asset management) to acquire United Utilities Electricity Limited (“UUE”) for a total enterprise value of £1,640 million. The acquisition represented a full year 2007 EV/EBITDA multiple of 6.9 times, and a Regulated Asset Value multiple of 1.32 times21. At the time of acquisition, UUE comprised an electricity distribution network of approximately 56,000 kilometres of underground and overhead cables in the North West of England. The distribution area covered around 2.3 million customers in the Greater Manchester region, the counties of Lancashire and Cumbria, and parts of Cheshire. Following the acquisition, the UUE continued to be operated by United Utilities Plc through an arms length operating agreement with its Contract Solutions division. Arcapita Bank/ Viridian Plc In October 2006 Arcapita Bank, Asset Based Investment Arm, a subsidiary of Arcapita Bank B.S.C made an offer to acquire Viridian Group plc for a consideration of approximately £1,624 million. Based on earnings for the financial year ending 31 March 2006 the transaction represents a historical EV/EBITDA multiple of 8.6 times. Viridian Group plc and its subsidiaries engage in the generation, procurement, transmission and distribution of electricity in the United Kingdom and Republic of Ireland. Agbar/Bristol Water Group Plc On 1 May 2006 Sociedad General de Aguas de Barcelona SA (“Agbar”) acquired Bristol Water Group Plc (“Bristol”) for a consideration of approximately £165 million. Based on Bristol’s earnings for the full year ending 31 March 2006 the transaction represents an EV/EBITDA multiple of 8.2 times. At the time of acquisition Bristol was an appointed water undertaker, regulated by Ofwat (Water Services Regulation Authority in England and Wales), which supplied drinking water to one million customers centred in Bristol (United Kingdom). Agbar has operations in Spain, Chile, Colombia, Mexico and Dubai, and as at December 2005 it provided water services to approximately 22 million people world-wide.

21 As earnings for UUE were not disclosed, the stated multiples are sourced from Colonial First States press release dated 26 November

2007.

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2 Transport

2.1 Ports

A selection of relevant port/terminal transactions are set out below:

Recent Transaction Evidence EBITDA Multiple23

(times) Date Target Target Consideration

22 (millions) Historical Forecast

Aug 09 Euroports Acquisition of up to 40% interest by Antin Infrastructure & Arcus European Infrastructure

€811 12.3 10.2

Oct 07 Rauma & Botnia Acquisition of 100% interest by BBI €90 na 10.6

Jul 07 Various European Ports

Acquisition of combined proportionate ownership of approximately 65.4% by BBI

€402 na 10.8

May 07 Tarragona Port Services Acquisition of 51% interest by BBI A$220 12.3 na

Mar 07 Maher Terminals

Acquisition of 100% interest by RREEF Infrastructure

US$2,10024 30-35 na

Feb 07 Montreal Gateway Terminals

Acquisition of 80% interest by Morgan Stanley Infrastructure €37525 24.7 na

Nov 06 OOIL terminals division

Acquisition of 100% of terminals division by Ontario Teachers Pension Plan

US$2,410 23.5 na

Nov 06 Peel Ports Acquisition of 49.9% of by RREEF Infrastructure £1,55026 15.5 na

Mar 06 Associated British Ports

Acquisition of 100% interest by Admiral Acquisition £2,577 12.5 na

Dec 05 PD Ports Acquisition of 100% interest by BBI £562 13.2 na Source: Grant Samuel analysis27 A brief summary of each transaction is set out below.

22 Implied enterprise value if 100% of the company or business had been acquired. 23 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items. 24 Based on broker estimate 25 Based on broker estimate 26 Based on broker estimate 27 Grant Samuel analysis based on data obtained from IRESS, company announcements, transaction documentation and, in the absence

of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each transaction depends on analyst coverage, availability and corporate activity.

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Euroports/Antin and Arcus

On 24 December 2008, BBI announced that it had entered into a subscription agreement with a consortium of investors including Antin IP and Babcock and Brown European Infrastructure Fund (“BBIF”) to subscribe for new shares in Euroports. The terms of the agreement were later revised and on 30 July 2009, BBI announced the closing of the revised agreement. As per the revised agreement, Antin IP and Arcus (formerly BBEIF) have acquired a 40% interest (on a fully diluted basis) in Euroports. The agreed price of €141.5 million for the 40% equity interest equates to a 100% post investment equity value for the Euroports business of €353 million. Based on historical EBITDA, the equity subscription was priced at an EV/EBITDA multiple of 12.9 times. BBI/Rauma & Botnia

On 12 October 2007, BBI announced the acquisition of 100% of two Finnish concession port operators, Oy Rauma Stevedoring and Oy Botnia Shipping (“Rauma & Botnia”) from UPM for a combined enterprise value of A$144 million (€90 million). Rauma & Botnia on a combined basis comprise the largest paper port operator and third largest container port operator in Finland and together handle over seven million tonnes per annum of containers, forestry and dry bulk products. Based on forecast calendar year 2007 combined EBITDA of €8.5 million, the acquisition price implied a forecast EV/EBITDA multiple of 10.6 times.

BBI/various European Ports

On 18 July 2007, BBI reported that it had acquired controlling interests in three port companies with concessions in six western European ports for a combined enterprise value of €402 million (100% basis). BBI retained a combined proportionate ownership of approximately 65.4% with pre-emptive rights and/or call options over the remaining 34.6%. Based on forecast EBITDA of €37.1 million, the implied EV/EBITDA multiple was 10.8 times. BBI/Tarragona Port Services

On 30 May 2007, BBI announced that it had acquired a 51% interest in Tarragona Port Services (“TPS”) with a call option over the remaining 49% interest exercisable within 18 months. TPS provides port terminal and maritime freight transport services at Port of Tarragona, the second largest port in Spain by total tonnage and the largest coal port in the Mediterranean. TPS via its five dry bulk concessions at the port handles over 7.5 million tonnes of dry bulk stevedore and controls over 50% of total port traffic (by tonnage). BBI’s proportionate 51% share equated to an enterprise value of approximately A$112 million implying a historical EV/ EBITDA multiple of 12.3 times. RREEF Infrastructure/Maher Terminals

On 20 March 2007 RREEF Infrastructure (“RREEF”) announced that it had entered into an agreement to acquire Maher Terminals, a privately held company that operates the world's largest independent multi-user container terminal at Port Elizabeth in New York/New Jersey. RREEF is the real estate and infrastructure investment management arm of Deutsche Asset Management, the global investment management business of Deutsche Bank. The acquisition was completed in July 2007 but the terms were not disclosed as it was a private transaction. However, brokers have estimated that the acquisition was completed at historical EBITDA multiples of between 30-35 times implying an enterprise value of approximately US$2,100 million. The relatively high transaction multiple reflected the competition at the time of the transaction from financial investors such as pension funds, private equity concerns and infrastructure funds for low risk, stable cash flow assets. Morgan Stanley/Montreal Gateway Terminals

On 22 February 2007, Morgan Stanley announced that its infrastructure investment group had entered into an agreement to acquire an 80% interest in Montreal Gateway Terminals. Montreal Gateway Terminals operates the Racine and the Cast terminals on the St. Lawrence River in Montreal, Québec. In 2005, Montreal Gateway Terminals handled 1.1 million TEU, representing 89% of all containers handled

Page 14

in Montreal, the third largest North Atlantic container port. The acquisition price and the implied historical EV/EBITDA multiple are believed to have been around €300 million and 24.7 times respectively. OOIL Terminal/Ontario Teachers

On 24 November 2006, Orient Overseas International Limited (“OOIL”) announced the sale of its terminals division to Ontario Teachers’ Pension Plan Board (“OTPP”) for US$2,350 million in cash for 100% of the equity. As part of the transaction, OTPP also assumed a net debt of US$60 million implying an enterprise value of US$2,410 for the terminals division which comprised four container terminals located in North America. For the 12 month period ending June 2006, OOIL's terminals division recorded a total throughput of 2.6 million TEU with a sales turnover of US$444.3 million and EBITDA of US$99.8 million. Based on the reported EBITDA the acquisition price implied a historical EV/EBITDA multiple of 23.5 times. The sale was completed in June 2007. Peel Ports/RREEF

On 6 November 2006, Peel Holdings announced that RREEF had acquired a 49.9% stake in Peel Ports. Peel Ports is UK and Ireland’s second largest port operating company and principally operates ports on the Mersey and Manchester Ship Canal in the North West, on the Clyde in Scotland, on the Medway in the South East and in Dublin and Belfast. Based on proforma EBITDA of £100 million for the year ending 31 March 2006, the acquisition price that brokers believe was around £775 million (£1,550 on 100% basis) represents an historical EV/EBITDA multiple of 15.5 times. Associated British Ports/Admiral Acquisitions

In March 2006, the board of Associated British Ports Holdings (“ABP”) announced that it had received a takeover offer from Admiral Acquisitions, a consortium which included subsidiaries of Ontario Municipal Employees Retirement System, GIC, Goldman Sachs and Prudential Group. ABP was UK’s leading ports business, providing port facilities and services to shippers and cargo owners. ABP owned 21 ports in the UK and handled nearly 135 million tonnes of cargo in 2005. The initial cash offer of 730 pence per ordinary share was later revised to 810 pence per share in May 2006 and again to 840 pence in June 2006. The 840 pence per share cash offer represented a 54.8 percent premium to the closing price before the initial offer. The offer valued ABP at approximately £2,577 million and based on its historical EBITDA of £207 million, represented an EV/EBITDA multiple of 12.5 times.

BBI/PD Ports

On 11 December 2005, BBI announced a recommended cash offer to acquire 100% of the issued capital in PD Ports PLC (“PD Ports”) valuing the company at approximately £562 million (A$1.4 billion) including net debt of £226.4 million. The share offer price of 148.5 pence per ordinary share represented a premium of 33.3 percent over the last closing middle price. PD Ports core business is the operation of the Port of Tees and Hartlepool, UK’s second busiest sea port (by volume). The bulk of the revenue (approximately 72.5%) was generated from the port operations. The offer price represented a historical EV/EBITDA multiple of 13.2 times. The transaction completed February 2006.

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2.2 Rail

A selection of relevant rail transactions since 2006 is set out below:

Recent Transaction Evidence EBITDA Multiple29

(times) Date Target Type Transaction Consid- eration28 (millions) Historical Forecast

June 2008 Freightliner Group Limited

Acquisition by Arcapita Bank BSC £200 5.9 na

September 2007

Dakota, Minnesota and Eastern Railroad Corporation Limited

Acquisition by Canadian Pacific Railway Limited US$1,480 na na

June 2007

English Welsh and Scottish Railway Holdings Limited

Acquisition by Deutsche Bahn AG £300 14.0 na

May 2007 Florida East Coast Industries, Inc.

Acquisition by Fortress Investment Group LLC US$3,500 33.8 na

November 2006 RailAmerica, Inc.

Acquisition by Fortress Investment Group LLC US$1,100 18.1 na

March 2006

“Below Rail” business of Australian Railroad Group Pty Ltd

Acquisition by BBI A$854 7.7 na

Source: Grant Samuel analysis30 A brief summary of each transaction is set out below. Arcapita Bank BSC (“Arcapita”)/Freightliner Group Limited (“Freightliner”) On 13 June 2008, Arcapita, an international investment firm based in Bahrain, announced the acquisition of Freightliner from 3i Group plc, Electra Partners LLC and Freightliner management and staff for £200 million. Completion of the transaction took place on 24 July 2008, after clearance from the European Commission. Freightliner is the parent company of Freightliner Limited (the container business), Freightliner Heavy Haul Limited (the bulk rail freight business), Freightliner Maintenance Limited (a separate entity dedicated to the repair and maintenance of traction and rolling stock) and their European subsidiary, Freightliner PL Sp. Zo.o. Canadian Pacific Railway Limited (“Canadian Pacific”)/Dakota, Minnesota and Eastern Railway Corporation Limited (“DM&E”)

28 Implied enterprise value if 100% of the company or business had been acquired. 29 Represents gross consideration divided by EBITDA. EBITDA is earnings before net interest, tax, depreciation, amortisation,

investment income and significant items. 30 Grant Samuel analysis based on data obtained from IRESS, company announcements, transaction documentation and, in the absence

of company published financial forecasts, brokers’ reports. Where company financial forecasts are not available, the median of the financial forecasts prepared by a range of brokers has generally been used to derive relevant forecast value parameters. The source, date and number of broker reports utilised for each transaction depends on analyst coverage, availability and corporate activity.

Page 16

On 5 September 2007, Canadian Pacific announced the acquisition of all of the issued and outstanding shares in DM&E and its subsidiaries, a Class II railroad with approximately 2,500 miles of track in the US Midwest, for US$1.48 billion. Upon approval of the Surface Transportation Board and the US Department of Transportation, the merger was completed on 4 October 2008, with Canadian Pacific assuming operational control on 31 October 2008. Deutsche Bahn AG (“Deutsche Bahn”)/English Welsh and Scottish Railway Holdings Limited (“EWS”) On 28 June 2007, Deutsche Bahn’s Supervisory Board approved the takeover of all the shares in EWS, the United Kingdom’s biggest rail freight operator, for £300 million. EWS operates a rail freight business within Great Britain and mainland Europe. Through its subsidiaries, EWS also offers rail engineering and IT consultancy services, maintenance and leasing services for rolling stock and freight services in France through the Channel Tunnel. Fortress Investment Group LLC (“Fortress”)/Florida East Coast Industries, Inc. (“FECI”) On 8 May 2007, Fortress entered into a definitive agreement to acquire FECI for US$62.50 per share plus a special dividend of US$21.50 per share. The total US$84 per share represented a premium of 13.3% over FECI’s closing price prior to the deal announcement and a 31.0% premium to its average closing price over the 60 days prior to the deal announcement. Under the transaction, Fortress assumed certain FECI debt, bringing the total deal value to approximately US$3.5 billion. The transaction received regulatory approval in September 2007. Fortress/RailAmerica, Inc. (“RailAmerica”) On 15 November 2006, RailAmerica announced that it had entered into a definitive merger agreement with an affiliate of Fortress under which RailAmerica’s shareholders received US$16.35 per share, which represented a 32.0% premium to its closing price prior to the deal announcement and a 49.0% premium to its average closing price over the 60 days prior to the deal announcement. The total value of the transaction, including the refinancing of RailAmerica’s existing debt, was approximately US$1.1 billion. The transaction completed in February 2007. BBI/ “Below Rail” business of Australian Railroad Group Pty Ltd (“ARG”) On 14 February 2006, BBI announced the acquisition of the “below rail” business of ARG for A$853.5 million. The ARG “below rail” business leases track from the Western Australian (approximately 5,000 kms) and South Australian Governments under long term leases (expiring 49 years and 50 years from commencement in December 2000 and October 1997 respectively) and provides access to that track to railway operators and end customers. The acquisition related solely to the Western Australian “below rail” business, WestNet Rail, which offers track access to both the ARG “above rail” operations and third party rail operators. It is responsible for maintaining track infrastructure, supply of the train control function and determination of track access fees and overall access management. The transaction completed in March 2006 following approval of the Australian Consumer and Competition Commission (“ACCC”).