AGL ENERGY LIMITED. — Call Transcript 2008

Sep 4, 2008

Attention ASX Company Announcements Platform Lodgement of Open Briefing[®]

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AGL Energy Limited ABN 74 115 061 375 Level 22 101 Miller Street North Sydney, NSW 2060

Date of lodgement: 05-Sep-2008

Title: Open Briefing[®] . AGL. MD & CFO on FY08 Results Follow-Up

Record of interview:

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AGL Energy Limited recently reported underlying net profit after tax (NPAT) of $355.5 million for the year ended June 2008, up 8 percent from the pro forma result for the previous year. This reflected a 22 percent increase in operating EBIT to $703.2 million, offset by a 78 percent increase in net finance costs. You’ve reaffirmed your NPAT guidance of $360 million to $390 million for the current year ending June 2009. What factors could push NPAT to the upper or lower points of the range?

MD Michael Fraser

Weather will be a key factor. We’ve had a solid start to the year with the recent cold winter, but weather can have an impact on retail volumes and the volatility of wholesale electricity prices. That said, our hedge book and generation portfolio are well set up for most market conditions.

Our guidance assumes a continuation of the same high level of competition we’ve seen across all our retail markets over the last number of years. But we also expect an improvement in our equity accounted income from Loy Yang this year.

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In 2008 the Retail Energy business booked operating EBIT of $271.7 million, up 41 percent. The business saw a drop of 4.5 percent in net operating costs per customer account to $70.90. What were the drivers of the efficiency improvement

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given the Phoenix program was not expected to contribute significantly until it’s completed at the end of this calendar year?

MD Michael Fraser

The two major drivers were the full-year contribution from the Powerdirect and Sun Gas Retail businesses in Queensland, which we acquired in 2007, and the demonstrable economies of scale we’ve been able to achieve. We also had a change in our marketing channel mix. We increased our use of aggregators and decreased our use of out-bound telemarketing, and that helped us manage costs. We also have an ongoing focus on cost management within the retail business.

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The Phoenix program accounted for $82.3 million of capex in 2008 and your presentation materials for 2007 implied Phoenix capex of $54.1 million for that year. Given your earlier cost estimate for the program of $80 million to $100 million, this implies actual cost has been higher than estimated. What has driven the cost increase and will you incur further costs in the current year?

CFO Stephen Mikkelsen

Following our recent road show it became obvious that there was some confusion as to what the original capex estimate for Phoenix included and that people were not doing a like-for-like comparison. The original estimate naturally didn’t include two very important items – the acquisition of Powerdirect, which brought in 390,000 additional customers that we had to put onto the SAP system, and the impact of the AlintaAGL merger and subsequent demerger. All our prior Phoenix disclosures have been on a like-for-like basis; Powerdirect and the AGLAlinta disengagement from shared systems are add-ons.

The Queensland acquisitions added about $30 million to the program: $20 million in direct costs to put the additional 390,000 customers onto the system, and around $10 million in indirect costs attributable to the delays caused by adding those extra customers in the middle of the project. The AlintaAGL disengagement added about $20 million to the direct and indirect costs of the program in terms of disentangling ourselves from the legacy systems that supported that business. This has proven to be more complex and time consuming than originally anticipated.

So, we’d invested $136 million capex in the program as at June 2008, compared with an enhanced scope cost estimate of around $150 million. Therefore, we still have further budgeted capital expenditure in the current year, but I’m expecting the total capex to be within 10 percent of our enhanced scope estimate.

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The Retail business saw net customer growth of 33,600 in 2008. After a net loss of 22,000 customers in the first half, customer numbers grew 55,600 in the second half. What’s been the trend in customer numbers since the end of the June and is the momentum of the second half sustainable?

MD Michael Fraser

We’ve had a positive start to the year in terms of net customer gains. But it’s very early days and as I said earlier, we’re expecting a continuation of the same high

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level of competition we’ve seen over the last few years. At the end of the day, our focus is on margins rather than absolute customer numbers. We’re a lot better off getting the right mix of customers than necessarily getting an out-right gain in numbers.

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The Merchant Energy business booked EBIT of $300.8 million, up 7 percent. This mainly reflected a strong performance in Wholesale Electricity, particularly from the Torrens Island Power Station (TIPS), offset by a sharp reduction in contribution from GEAC, the owner of Loy Yang A coal-fired power station. Given TIPS benefited from an unusually hot summer, what level of turnaround in GEAC’s contribution is assumed in your current year guidance?

MD Michael Fraser,

While TIPS performed very well in keeping the lights on during unprecedented consecutive extreme demand days in South Australia, it was only one part of an excellent EBIT performance from the integrated Merchant Energy portfolio.

We don’t provide specific guidance on particular areas of the business, but suffice to say we’re expecting an improved contribution from Loy Yang versus last year although not a return to the level of 2007. We’re not expecting maintenance costs to be at the same level as last year and even though we don’t get to see Loy Yang’s hedge book, we’d expect a better revenue performance too.

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Given AGL’s increased focus on renewable energy and gas-fired generation capacity, how does retaining your 32.5 percent holding in GEAC fit with your strategy going forward? Is Loy Yang A a “core” asset?

MD Michael Fraser

We have a balanced portfolio and coal is very important in Australia’s electricity supply, with about 85 percent of electricity being generated by coal-fired assets. That said, there’s clearly uncertainty around the future of coal generation assets in a scenario where the cost of carbon has to be factored in. There are also other issues in the sector such as the roll-off over the next few years of black coal supply contracts at the black coal generators, which are likely to mean an increase in their cost structures. That may see a benefit flow through to brown coal generators like Loy Yang that have their own mines and control over the cost of production as a result.

At the moment there’s a lack of clarity around the government’s carbon pollution reduction scheme but we should see draft legislation introduced later this year and by this time next year we’d expect to have a much clearer picture of what the future of Loy Yang looks like under those arrangements. At that time we’ll review whether it’s appropriate to continue to hold our interest in Loy Yang. At this point we’ve made no decision as to whether it will remain in the portfolio or not.

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Southern Hydro’s earnings contribution has been impacted in recent years by low dam levels as a result of the drought. With dam levels at the end of June higher

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than a year earlier, what’s the outlook for Southern Hydro? What scope is there to mitigate the impact of drought on Southern Hydro going forward?

MD Michael Fraser

The Kiewa Scheme is in very good condition and is effectively drought proof because the yearly snow melt normally fills it three times per year. Since June we’ve been running down the dam levels at Rocky Valley to make way for what will be a very significant snow melt given we’ve had the best snow fall in the catchment area since 2000. The Bogong Power Development, which is under construction, will add 140 megawatts of capacity to the Keiwa Scheme. This will take Kiewa’s capacity to approximately 400 megawatts, the largest component of Southern Hydro’s capacity and very importantly, it’s fully discretionary.

Our Dartmouth catchment is below the minimum operating level but we can still operate the Eildon Power Station, generating about 35 megawatts, even though the catchment is at relatively low levels. Clearly, the snow melt will help replenish both these catchments. But we don’t plan on Darmouth coming back into operation in the medium term given that would require significant rainfalls across the region and downstream from the dam. We’re currently exploring some technical options in relation to using the storage capacity that sits below Dartmouth’s current minimum operating level and supplementing our generation capability.

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Compared with indicative demand, the headroom in AGL’s contracted wholesale gas supply appears to tighten significantly from around 2012. How are you seeking to manage supply over the medium term, particularly given the potential impact on demand of the proposed development of LNG terminals on the east coast?

MD Michael Fraser

We believe our wholesale gas portfolio is in good shape, and we’re well contracted out to 2016/2017. Some volumes will be required in certain parts of the portfolio earlier than that, but they’re manageable given the projected supply and demand balance. For instance, we still have an option with QGC for 100 petajoules of gas that we haven’t exercised yet because we haven’t got a market for that gas. That option doesn’t expire until the end of 2011. We’re also of the view there’s likely to be surplus gas in the market by around 2012.

In addition, we’re focusing on the development of our own reserves in the Hunter Valley with Sydney Gas, in the Galilee Basin in Queensland where we recently announced a farm-in agreement with Galilee Energy, and in the Moranbah area where our joint venture partner Arrow Energy is running an extensive development and exploration program.

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AGL has a medium-term target of holding equity in 2,000 petajoules of upstream gas. At present you have equity ownership of 799 petajoules of 2P reserves, including your 24.9 percent stake in QGC and 50 percent stake in Moranbah.

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What’s your strategy with regard to these stakes and to attaining the equity gas target? Without majority control of QGC do you intend to retain your holding?

MD Michael Fraser

Our investment in QGC has been an excellent proxy for the recent rise in values in the coal seam methane (CSM) sector. We’ll also get a lot of value in future years as a result of the gas supply agreement we entered into when we made the investment. But ultimately, we’d like to convert our QGC holding into direct ownership of gas resources, be that with QGC or through other opportunities. We want to be in a position to realise the best returns, whether it’s from directing the gas into an LNG market or into power generation or other domestic markets.

At Moranbah, we have a very active exploration and development program underway with Arrow Energy. Once we’ve proved up those reserves, we have a number of opportunities including further power generation projects, supply to industrial customers in the region, or potentially supplying an LNG plant if Arrow proceeded with its proposed LNG project at Gladstone.

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The Gas & Power Development business booked operating EBIT of $155.1 million, up 19 percent, partly reflecting a 98 percent increase in Wind Farm Development Fees to $40.0 million. Can you comment on the wind farm development pipeline and the sustainability of this income stream?

MD Michael Fraser

The federal government has been unwavering in its commitment to increasing the mandatory renewable energy target (MRET) to 20 percent of total electricity supply by 2020. That means very significant volumes of renewable megawatts need to be put into the market between now and 2020. We’re a very big part of the market, and we’ve established an extensive portfolio of development opportunities, particularly in relation to wind farms, in hydro as I mentioned before, and more recently in geothermal.

We see great opportunity to sustain our wind farm development income stream. We’ve commenced construction of the Hallett 2 wind farm and recently announced its sale, which should realise approximately $59 million in development fees over this financial year and next. We’re also close to making an investment decision on the proposed Macarthur wind farm in Victoria, which will be a joint venture with Meridian, and should be in a position to make an investment decision on the Hallett 4 wind farm in the first half of next calendar year. Both Macarthur and Hallett 4 are substantially larger than Hallett 1 and Hallett 2. Going forward we expect to transact a wind farm every 18 months. And while we take the construction risk, we’ve already built up considerable internal expertise in managing this risk.

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AGL recently announced the acquisition of Allco Finance Group’s seven wind farm development projects for $12.5 million. Are all seven sites viable? What’s the expected investment to bring the projects on line and what’s the time line?

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MD Michael Fraser

Ultimately all seven sites will be viable, although we attributed most of the value in that transaction to three of the sites. They’re projects in Queensland, New South Wales and South Australia that could be brought on line within the next five years. The other projects are probably in the five to ten year time frame. The total investment will depend on the size of the projects and that comes back to getting final planning approvals so it’s too early to put a number on that.

CFO Stephen Mikkelsen

We’d expect most new wind farm developments to be funded in the same way as Hallett 1 and 2, that is through somebody else’s balance sheet.

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To what extent does your commitment to renewables, particularly wind power, depend on the government’s proposed increase in the MRET going ahead? In light of your investment to date, how would you be impacted if it doesn’t?

MD Michael Fraser

To date, all the projects we’ve committed to are required for the existing MRET, and a number of our future developments are also required to meet our future needs under the existing arrangements.

A point to make here is that the Victorian government has also introduced its own mandatory renewable target, which it intends to roll into the federal government’s scheme. But absent a federal government scheme, the Victorian scheme will remain in place. Projects like Macarthur and Bogong qualify under the Victorian scheme and there are other projects in our pipeline that will be required under that scheme as well.

The federal government remains committed to an expanded MRET, but even if it decided to reduce the target by say 25 percent, this would still provide us with an enormous growth opportunity.

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Operating cash flow was $354.7 million in 2008, up 23 percent from the previous year. Given EBITDA before significant items of $871.8 million, up 17 percent, cash conversion remained relatively weak, albeit improved. What scope is there to improve cash conversion given your integrated business structure?

CFO Stephen Mikkelsen

To make the operating cash flow directly comparable with the EBITDA number, you’d have to exclude significant items of $60 million, net interest expense of $158 million and tax payments of $105 million. Taking those out, cash flow was $678 million, which was a 78 percent conversion. It is also important to note that there was cash outflow of $47 million relating to futures margin calls, and excluding that lifts the conversion to 83 percent.

That still needs to improve. Particularly around our debtors management where we’ve had to scale back our normal collection processes as we migrated customers to the Phoenix SAP system. So, a big push for us in the coming year is get all our

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processes back up and running correctly with the new SAP system. The final customer migration will happen later this calendar year, so I’d anticipate that by the June year end we’ll be reducing that working capital drag.

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AGL’s capex totalled $324.6 million in 2008, down from $357.8 million in the previous year. The 2008 capex included $174.6 million invested in Gas & Power Development and $87.6 million in Retail Energy. What’s the expected capex in the current year and what will be the focus of current-year investment?

CFO Stephen Mikkelsen

We expect capex for the current year to be in the $300 million to $350 million range depending on the final growth capex associated with the proving up of reserves. Breaking it down to its main component parts, the completion of Bogong and other generating activities will require about $100 million. In upstream gas we’ll be investing between $100 million and $150 million in our projects at Moranbah, Hunter Valley, etc. Our maintenance capex will be around $50 million.

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As at the end of June 2008, AGL had net debt of $2.0 billion, down from $2.3 billion six months earlier, and gearing excluding derivatives balances in equity reserves stood at 31.3 percent down from 34.8 percent. You expect non-core asset sales to further strengthen the balance sheet and believe you’re on track to return to a BBB stable credit rating from BBB negative currently. Can you provide a time line for the proposed asset sales?

CFO Stephen Mikkelsen

We completed the sale of the North Queensland Gas Pipeline on 30 June, and settlement was in August, when we received $100 million in cash. We’ve stated that Elgas is an asset held for sale but obviously our most significant asset for sale, in terms of the proceeds we’ll receive from it, is our stake in the PNG Gas Project. We’re due to receive final binding bids for the stake mid September, then the preemptive process will run for 30 to 45 days after that, depending on how complex it is. We’d expect a sale between late October and the end of November with settlement before 31 December.

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What might this mean for your ability to participate in the New South Wales privatisation and how attractive to AGL is the amended privatisation structure, under which the government plans to sell its retail assets but retain its generation assets?

MD Michael Fraser

We’re going to be in a position of strength, both from a balance sheet perspective and from an operational capability perspective. The attractiveness or not of the privatised businesses will ultimately depend on what we see as their future profitability, and one of the specific issues we see is that the regulated price caps in New South Wales are too low. Going forward we see upward pressure on costs from coal generators having to recontract their coal supplies at higher prices and

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from carbon reduction legislation. How the government deals with those issues, particularly around the future regulatory settings, is going to be a key issue.

While it’s not selling the generation assets, the government is now talking about selling the development sites. Whatever form the privatisation takes, one issue around future investment in generation in New South Wales will be what certainty private sector players have that the government will sit out of the market and not build over the top of any privately owned generation capacity.

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Thank you Michael and Stephen.

For more information about AGL, visit www.agl.com.au or call Graeme Thompson, Head of Investor Relations, on +61 2 9921 2789

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