Agl Energy Limited · ASX:AGL
Agl Energy — H1 FY2011 Earnings Presentation
57 slides from Agl Energy's earnings presentation, Feb 23, 2011
Slide 1: 2011 Interim Results
2011 Interim Results 6 Months to 31 December 2010 Michael Fraser, Managing Director and CEO Stephen Mikkelsen, Chief Financial Officer | 23 February 2011
Slide 2: Disclaimer
2 Disclaimer sc a e The information in this presentation: › IIs nott an offer ff or recommendation d ti to t purchase h or subscribe b ib forf securities iti ini AGL Energy E Limited or to retain any securities currently held. › Does not take into account the potential and current individual investm
Slide 3: Agenda
3 Agenda ge da › Result Highlights Michael Fraser › Group Financials Stephen Mikkelsen › Operational Review / Summary Michael Fraser › Supplementary Information IMPORTANT NOTE: This presentation should be read in conjunction with the AGL Energy Limited ASX Appendix 4D for the 6 months ended 31 Decem
Slide 4: Half Year 2011 Highlights
4 Half a Year ea 2011 0 Highlights g g ts Loy Yang and Merchant impact first half earnings. › Solid result from Retail Energy gy up p 5.6% › NSW electricity customer numbers up 42,000 › Service quality continues to improve › AGL customer churn further outperforms market › Merchant Energy down 4.6% ›
Slide 5: Interim 2011 Result
5 Interim te 2011 0 Result esu t Revenue increase primarily due to higher transmission/distribution costs. › Revenue: $3,488.0m 9.0% CIAL › Underlying Profit: $226.2m 3.7% › Statutory Profit: $239 6m $239.6m 30.4% 30 4% FINANC › Underlying EPS: 49.9 cps 4.8% › DPS: 0% franked (Dec 09: 100% f
Slide 6: Extreme weather events
6 Extreme t e e weather eat e events e e ts Impact of Jan/Feb weather events - $30m to $35m after tax. Key y events NSW - Maximum Temperature Anomaly (°C) › Sydney – Record heat wave 30/01/2011 to 6/02/2011 » 7 consecutive days over 30°C » 5 consecutive nights above 24 24°C C » Record electricity de
Slide 7: Group Financials
7 Group Financials Stephen Mikkelsen Chief Financial Officer » 2009 Final Results 12 months to 30 June 2009 » 20 August 2009 » AGL External
Slide 8: Profit & Loss
8 Profit & Loss ((excludingg significant g items & fair value movements)) Underlying profit declined by 3.7%. 6 months to 31 Dec 2010 31 Dec 2009 Change $m Revenue 3,488.0 3,200.8 9.0% Operating EBITDA 416 0 416.0 425 7 425.7 (2 3%) (2.3%) Operating EBIT Retail 193.8 183.5 5.6% Merchant 186.1 195.1
Slide 9: Group Underlying Profit
9 Group G oup U Underlying de y g Profit o t Core Retail/Merchant businesses in line with p.c.p. – Loy Yang down. Retail Merchant 260 13.9 250 13.1 (2.8) (7.0) 240 4.6 234.8 $ million n 230 (13.6) 6.2 226.2 220 (23.0) 210 200 YTD MM & C&I Retail Energy Merchant Upstream Gas Central Investments Inter
Slide 10: Retail – Key Financial Metrics
10 Retail eta – Key ey Financial a c a Metrics et cs Continued solid growth in Operating EBIT (+5.6%). 6 months th to t 31 Dec 2010 31 Dec 2009 Change $m Electricity Revenue 2,123.2 1,953.1 8.7% Gas Revenue 864 9 864.9 771 9 771.9 12 0% 12.0% Other Revenue (Fees & Charges) 34.4 31.1 10.6% Total Reve
Slide 11: Retail – EBIT Drivers
11 Retail eta – EBIT Drivers e s Continued improvement in gross margin. 210 2.1 3.3 200 12.7 0.4 (2.8) 193.8 (2.9) (2.5) 190 $ million n 183.5 180 170 160 YTD December MM Gross Margin C&I Gross Other Gross Campaigns & Labour & Bad & Doubtful Other Opex costs YTD December FY10 Margin Margin Advertisi
Slide 12: Retail – Key Operating Metrics
12 Retail eta – Key ey Operating Ope at g Metrics et cs Improvement in gross margin per customer. 6 months to 31 Dec 2010 31 Dec 2009 Change Mass Market gross margin ($m) 304.3 291.6 4.4% Avg Mass Market customer numbers (‘000) 3,245.2 3,190.0 1.7% Gross margin per Mass Market customer $93.77 $91.41
Slide 13: Retail – Key Operating Metrics
13 Retail eta – Key ey Operating Ope at g Metrics et cs Operating expenditure to gross margin trending towards low 40s. 6 months to 31 Dec 2010 31 Dec 2009 Change g $m Operating costs (175.0) (169.4) 3.3% Depreciation and amortisation (20.9) (20.4) 2.5% Less fees and charges 34.4 31.1 10.6% Net oper
Slide 14: Merchant – Key Financial Metrics
14 Merchant – Key y Financial Metrics Operating EBIT down 4.6%. 6 months to 31 Dec De 2010 31 Dec De 2009 Ch Change e $m Operating EBITDA 220.3 225.4 (2.3%) D&A (34.2) (30.3) 12.9% EBIT Energy Portfolio Management (EPM) Wholesale Electricity Gross Margin 149.9 179.7 (16.6%) Wholesale Gas Gross Margi
Slide 15: Merchant – EBIT Drivers
15 Merchant e c a t – EBIT Drivers e s Strong result from gas portfolio offset by Wholesale electricity. 200 195.1 190 11.4 0.6 186.1 15.7 180 (13.0) (0.8) 1.0 170 (7 1) (7.1) $ million (16.8) 160 150 140 130 YTD December Hedging Costs Wholesale Wholesale Gas Eco-markets Merchant HC Extractions Powe
Slide 16: Operating Cash Flow
16 Operating Ope at g Cas Cash Flow o Banking RECs for the future. 6 months to 3 Dec 2010 31 20 0 3 Dec 2009 31 Movement $m Operating EBITDA 416.0 425.7 (9.7) Equity accounted income (net of dividend received) 2.9 (19.1) 22.0 Accounting for onerous gas contract (10.4) (10.4) - Working capital moveme
Slide 17: Debt Position
17 Debt ebt Position os t o Diversifying funding sources and lengthening maturity profile. › US$300m raised in United States Private Placement » Two tranches of 12 year and 15 year maturities › Refinancing of $886m syndicated bank loan to be completed prior to September 2011 Facilities @ 31 Dec 2010
Slide 18: Capital Expenditure
18 Capital Cap ta Expenditure pe d tu e Wind farm developments drive 2H expenditure. LEGEND 700 St Stay In I Business B i Upstream Gas 600 Oaklands Hallett 5 500 Macarthur Retail Other $ million 400 300 200 100 0 Jul-Dec 10 Jan-Jun 10 Forecast FY11 Forecast » 2011 Interim Results 6 months to 31 Dece
Slide 19: Debt Capacity
19 Debt ebt Capacity Capac ty Approximately $800m headroom to fund growth. LEGEND 1,800 S&P Adjustment 1 600 1,600 Capex Forecast 1,400 Closing 1H11 Debt 1,200 Operating cash flow after dividends $ milliion 1,000 Tax Refund Oaklands Sale 800 Headroom 600 400 200 0 1H11 Actual FY11 Forecast » 2011 In
Slide 20: Operational Review
20 Operational Review Michael Fraser Managing Director & CEO
Slide 21: People & Safety
21 People eop e & Safety Sa ety Good safety performance trend. Our three people initiatives: 1. Attract, retain and develop talent 2. Enable a high performance culture 3 3. Safe and sustainable Lost Time Injury Frequency Rate 6.0 5.2 5.0 40 4.0 3.6 3.0 2.7 2.5 2.0 2.0 1.2 1.0 1.0 0.0 Dec-07 Jun-08 D
Slide 22: Retail – Delivering Customer Growth
22 Retail eta – Delivering e e g Customer Custo e Growth G o t Strong growth in dual fuel customers. › Dual fuel accounts, up 68,444 (+5.0%) › Customer numbers up 32,676 (+1.0%) to 3.27 million › Strong growth in NSW electricity customer numbers (+42,000) Incremental Customer Numbers Dual Fuel Accou
Slide 23: Retail – Improving Core Operations
23 Retail eta – Improving p o g Core Co e Ope Operations at o s Strong working capital management. Aged Unbilled Accounts – improving across all categories 3,500 › Aged g unbilled customers at historically y low 3,000 mber of accountts levels 2,500 2,000 » Zero unbilled mass market customers over 90
Slide 24: Retail – Improving customer service
24 Retail eta – Improving p o g customer custo e service se ce Industry outperformance. AGL churn much lower than industry 21 › AGL market churn continues to outperform p 19 industry arket churn (%) 17 » AGL churn 4.5 ppts below industry average 15 » Victoria Vi t i confirmed fi d as the th mostt co
Slide 25: Renewable Energy Certificates (REC) obligations
25 Renewable e e ab e Energy e gy Certificates Ce t cates (REC) ( C) obligations ob gat o s Large surplus continues to suppress REC prices. › AGL’s REC obligations covered to 2014/15 F Forecast t Industry I d t LRET B Balance l › Future wind farm development timing subject to recovery of REC prices
Slide 26: Upstream Gas – Creating long-term value
26 Upstream Upst ea Gas – C Creating eat g long-term o g te value a ue Total 2P reserves entitlement increased by 451 PJ. › Initial Hunter gas reserves booked (2P: 142 PJ) › Total Bowen Basin 2P reserves up 312 PJ despite 129 PJ decline at Moranbah AGL share of CSG reserves As at 31 Dec 10 As at 30
Slide 27: Upstream Gas growth opportunities
27 Upstream Upst ea Gas growth g o t opportunities oppo tu t es Emerging gas storage business provides new platform for growth. Silver Springs underground gas storage project › Underpinned by QGC gas storage services agreement for first 7 years › First injection of gas targeted for June 2011 › Plans
Slide 28: NSW growth
28 NSW S growth g o t Up to 10,000 MW unaligned NSW generation. › Unaligned NSW generation available to Entity Capacity % of Region Macquarie Generation 4,839 28.8 support AGL’s retail growth strategy Snowy Hydro 2,516 15 Delta Coastal 2,588 15.4 › NSW/ACT already AGL’s largest market Total 9,943 59
Slide 29: Summary
29 Su Summary a y Retail/Merchant in line with expectation: Loy Yang disappoints. › Retail Energy continues to perform well » Ongoing improvement in customer service » Good growth in NSW electricity customer numbers › Merchant Energy impacted by lower contribution from Torrens Island power station a
Slide 30: Outlook 2011
30 Outlook Out oo 2011 0 Solid 2H result expected despite weather events. › Underlying Profit guidance of $415 million to $440 million maintained › Strong growth in Retail contribution in 2H11 expected › Accelerated growth in NSW electricity customers expected › Wholesale Electricity 2H11 performanc
Slide 31: Further Information / Contacts
31 Further u t e Information o at o / Contacts Co tacts A range of information on AGL Energy Limited including ASX & Media Releases, Presentations, Financial Results, Annual Reports and Sustainability Reports is available from our website: www.agl.com.au Alternatively, contact: INVESTORS MEDIA John
Slide 32: Supplementary Information
32 Supplementary Information
Slide 33: Electricity Sales Volume
33 Electricity ect c ty Sales Sa es Volume ou e 6 months to 31 Dec 2010 31 Dec 2009 Change GWh Mass Market VIC 2,476 2,595 (4.6%) SA 1 764 1,764 1 704 1,704 3 5% 3.5% NSW 1,859 1,566 18.7% QLD 1,577 1,713 (7.9%) Mass Market Total , 7,676 7,578 , 1.3% C&I VIC 3,147 3,011 4.5% SA 1,731 1,517 14.1% NSW
Slide 34: Gas Sales Volume
34 Gas Sa Sales es Volume ou e 6 months to 31 Dec 2010 31 Dec 2009 Change PJ Mass Market VIC 17.7 15.9 11.3% SA 1.5 1.1 36.4% NSW 14.6 13.4 9.0% QLD 1.6 1.5 6.7% Mass Market Total 35.4 31.9 11.0% C&I VIC 13.6 13.3 2.3% SA 4.0 1.9 110.5% NSW 20 5 20.5 20 0 20.0 2 5% 2.5% QLD 7.2 7.6 (5.3%) C & I Tota
Slide 35: Retail – Mass Market Key Indicators
35 Retail eta – Mass ass Market a et Key ey Indicators d cato s ((includes SME)) 6 months to 31 Dec 2010 31 Dec 2009 Change Electricity Volume (GWh) 7,677 7,578 1.3% Avg. Mass Market Accounts ('000) 1,877 1,806 3.9% Revenue ($m) 1,217.9 1,084.2 12.3% Gross Margin ($m) 200.0 185.9 7.6% Gross Margin 1
Slide 36: Retail – C & I Key Indicators
36 Retail eta – C & I Key ey Indicators d cato s 6 months to 31 Dec 2010 31 Dec 2009 Change El Electricity i i Volume (GWh) 9,159 10,010 (8.5%) C & I Accounts ('000) 17.9 15.4 16.2% R Revenue ($ ($m)) 905 3 905.3 868 9 868.9 4 2% 4.2% Gross Margin ($m) 30.9 27.7 11.6% $ / MWh $3.37 $2.77 21.7% 6 mon
Slide 37: Retail – Market Churn
37 Retail eta – Market a et Churn C u AGL churn lower than market ((AGL 15.9% vs market 20.4%)) Dec-08 to Dec-10 35.0% 30.0% 25.0% 20.0% 15 0% 15.0% 10.0% 5.0% 0.0% Dec-08 Sep-09 Dec-09 Sep-10 Dec-10 Apr-09 Apr-10 Aug-09 Nov-09 Aug-10 Nov-10 Feb-09 Feb-10 May-09 May-10 Mar-09 Mar-10 Jan-09 Jan-10 Oc
Slide 38: Retail – Delivering customer growth
38 Retail eta – Delivering e e g customer custo e growth g o t State Period Gas Electricity y Total Victoria 1H11 473,934 645,618 1,119,552 FY10 468,190 642,588 1,110,778 South Australia 1H11 102,212 475,329 577,541 FY10 96 788 96,788 477 879 477,879 574 667 574,667 New South Wales 1H11 717,399 422,
Slide 39: Retail – Cost to Serve
39 Retail eta – Cost to Se Serve e 6 months to 31 Dec 2010 31 Dec 20093 Change Net operating expenditure 161.5m 158.7m 1.8% Net operating cost per customer account $49.49 $49.51 0.0% Cost to grow/retain 38.5m 38.6m (0.3%) Cost to grow per account acquired/retained1 $81.21 $84.82 (4.3%) Cost to serve
Slide 40: Retail – EBIT / Sales Analysis
40 Retail eta – EBIT / Sa Sales es Analysis a ys s 6 months to 31 Dec 2010 31 Dec 2009 Change $m Total revenue 3,022.5 2,756.1 9.7% Cost of sales (2,632.8) (2,382.8) 10.5% Gross margin 389.7 373.3 4.4% Operating costs (excl D & A) (175.0) (169.4) 3.3% Operating EBITDA 214.7 203.9 5.3% Depreciation a
Slide 41: Retail – Weather
41 Retail eta – Weather eat e Cool summer impacts electricity volumes. › Winter months Heating Degree Days » Victoria Vi t i experienced i d 6th wettest tt t August A t on record d with ith 1000 900 exceptionally low daytime temperatures 800 Heating Degree Days » South Australia July and August 2010
Slide 42: Merchant – EBIT Analysis
42 Merchant e c a t – EBIT Analysis a ys s 6 months to 31 Dec 2010 31 Dec 2009 Change $m Revenue from Retail Business 1. Generation revenue is pool revenue - Electricity (COGS transfer price) 1,149.2 1,144.1 0.4% from owned generation assets. 2. ActewAGL Dec 10: Electricity sales - Gas (COGS transfe
Slide 43: Merchant – Generation: Operational performance
43 Merchant e c a t – Ge Generation: e at o Operational Ope at o a performance pe o a ce Operational performance of Commercial Availability / Start Reliability (%) generation assets continues to meet and exceed international 100 benchmarks. 98 %) Availability / Startt Reliability (% 96 94 92 1. Comm
Slide 44: Merchant – Generation: Wind Farm
44 Merchant e c a t – Ge Generation: e at o Wind d Farm a › Hallett 2 commissioned 17 May 2010 › High operational availability continued across portfolio Six months to 31 Dec 2010 Unit Wattle Point Hallett 1 Hallett 2 Total Capacity MW 90.8 94.5 71.4 256.7 Availability % 94.5 94.3 95.1 94.6 Generate
Slide 45: Merchant – Hydrology
45 Merchant e c a t – Hydrology yd o ogy › 52.6% of hydro capacity is linked to drought resistant Kiewa Scheme › Dartmouth returned to operation in Q4 2010. Re Re-commissioning commissioning works were completed and with good inflows, the current capacity is 135 MW. Irrigation releases are expected
Slide 46: Merchant – Electricity Hedging: Policy
46 Merchant e c a t – Electricity ect c ty Hedging: edg g Policy o cy › AGL Risk Management Policy is set by the Board and establishes the requirements for the management of wholesale risk › Clearly defined and approved commodity and transaction limits › Counter p party y credit limit tier allocatio
Slide 47: Merchant – Electricity Hedging: Position
47 Merchant e c a t – Electricity ect c ty Hedging: edg g Position os t o Physical Financial AGL Energy Hedge Position - All States Satisfying Financial Risk Limits Contingent Gas Fired Generation 125% Expected Generation Derivatives (Swaps Only) Unhedged load must be limited Range of profit outcome
Slide 48: Merchant – Wholesale Electricity Prices
48 Merchant e c a t – Wholesale o esa e Electricity ect c ty Prices ces CAL 12 Forward Contract Prices › The delay in CPRS to 2013 (announced April 70 NSW QLD SA VIC 2010) and declining spot prices across the NEM 65 resulted in the forward curve falling in all states 60 › Forward prices then remaine
Slide 49: Upstream Gas – Key Financial Metrics
49 Upstream Upst ea Gas – Key ey Financial a c a Metrics et cs 6 months to 31 Dec 2010 31 Dec 2009 Change $m Operating EBITDA 27.2 13.8 97.1% D&A (10.3) (10.8) (4.6%) EBIT Upstream Gas Queensland / South Australia 17.5 3.4 414.7% New South Wales 3.1 2.0 55.0% E i IInvestments Equity (0 1) (0.1) (0 1
Slide 50: Upstream Gas Interests – Permit Details
50 Upstream Upst ea Gas Interests te ests – Permit e t Details eta s Permits Working Basin Project Exploration Production Interest (Area km2) (Area km2) PEL 2 (6,708) - 100% PEL 5 (401) - 100% - PPL 1 (48) 100% Camden Gas Project - PPL 2 (1) 100% Sydney - PPL 4 (55) 100% - PPL 5 (103) 100% - PPL 6 (
Slide 51: Upstream Gas Interests – Permit Details
51 Upstream Upst ea Gas Interests te ests – Permit e t Details eta s Permits Working Basin Project Exploration Production Interest (Area km2) (Area km2) ATP 471P (703)* - 28.71-100% ATP 709P (146) - 100% - PL 1 (55) 15% - PL 15 (259) 75% - PL 16 (259) 100% - PL 30 (37) 100% - PL 46 (33)* 100% - PL 4
Slide 52: Energy Investments
52 Energy e gy Investments est e ts 6 months to 31 Dec 2010 31 Dec 2009 Change g $m EBIT ActewAGL 17.6 17.5 0.6% Loy Yang 0.4 22.8 (98.2%) Investments Other 2.4 3.1 (22.6%) Total EBIT 20.4 43.4 (53.0%) » 2011 Interim Results 6 months to 31 December 2010 » 23 February 2011 » AGL External
Slide 53: Significant Items
53 Significant S g ca t Items te s1 6 months to 31 Dec 2010 Pre Tax Tax After Tax $ $m Merger and acquisition related costs (16.1) 3.8 (12.3) Redundancy, y termination and restructuring g costs (6.5) ( ) 2.0 (4.5) ( ) Total significant items (22.6) 5.8 (16.8) 1. Full detail in Appendix 4D, Section 1
Slide 54: Capital Expenditure
54 Capital Cap ta Expenditure pe d tu e 6 months to 31 Dec 2010 SIB Discretionary Total $m Merchant Energy 30.8 74.5 105.3 Upstream Gas - 41.5 41.5 Retail Energy - 41.3 41.3 Corporate Other 11.6 - 11.6 Total 42.4 157.3 199.7 » 2011 Interim Results 6 months to 31 December 2010 » 23 February 2011 » AG
Slide 55: Balance Sheet
55 Balance a a ce Sheet S eet As at 31 Dec 2010 30 Jun 2010 $m Current assets 2,418.1 2,208.5 PPE, E&E and oil & gas assets 3,274.9 2,997.1 Other non current assets 3 560 6 3,560.6 3 485 3 3,485.3 Total Assets 9,253.6 8,690.9 Current liabilities 1,495.7 1,532.5 Total debt 1 184 4 1,184.4 900 8 900.8
Slide 56: Fair Value Reconciliation
56 Fair a Value a ue Reconciliation eco c at o Net Assets (Liabilities) As at $m 31 Dec 2010 30 Jun 2010 Change Electricity derivative contracts (348.1) (474.3) 126.2 I t Interest t rate t swap & foreign f i currency derivative d i ti contracts t t (135 8) (135.8) (7 2) (7.2) (128 6) (128.6) Total n
Slide 57: Loy Yang A: Financial Performance
57 Loy oy Yang a g A: Financial a c a Performance e o a ce 6 months to 31 Dec 2010 31 Dec 2009 Change $m G Generation i V Volume l (GWh) 7,677 7,775 (1.3%) 1 Average Price ($/MWh) $36.60 $42.68 (14.2%) Sales Revenue2 307 9 307.9 359 0 359.0 (14 2%) (14.2%) Other Revenue 14.9 14.2 4.9% Expenses (146.