Contact Energy Limited · NZX:CEN
Contact Energy — H1 FY2011 Earnings Presentation
41 slides from Contact Energy's earnings presentation, Feb 22, 2011
Slide 1: Results Presentation
Results Presentation Six month period ended 31 December 2010 22 February 2011
Slide 2: Disclaimer
Disclaimer This presentation may contain projections or forward looking statements regarding a variety of items. Such forward-looking statements are based upon current expectations and involve risks and uncertainties. Actual results may differ materially from those stated in any forward-looking stat
Slide 3: Outline
Outline Results 4 Segmental analysis 15 Supporting materials 30 © Contact Energy Limited 22 February 2011 Results for the six month period ended 31 December 2010 3
Slide 4: EBITDAF $225m, and Underlying Earnings $79m
EBITDAF $225m, and Underlying Earnings $79m Consistent with 1H10 • Good result given challenging Key financial information 1H11 1H10 Variance operating environment $ % – Wet conditions EBITDAF ($m) 225.5 225.0 0.5 0% – Gas, network, carbon cost Profit for the Period ($m) 83.7 87.1 (3.4) (4%) increas
Slide 5: EBITDAF: $225m, consistent with 1H10
EBITDAF: $225m, consistent with 1H10 Price increases absorbed by increasing costs Electricity segment EBITDAF up $5m (2%) to $204m Electricity Segment EBITDAF EBITDAF 1H10 199 • Retail electricity revenue up $84m (13%) due to higher Net wholesale revenue (3) sales volumes (+9%) and tariff increases
Slide 6: Underlying earnings: $79m, consistent with 1H10
Underlying earnings: $79m, consistent with 1H10 Distribution of 11 cents per share, consistent with 1H10 1H11 1H10 Variance $m $m $m % EBITDAF 225.5 225.0 0.5 0% Depreciation and amortisation (85.5) (86.7) 1.2 1% Equity accounted earnings of associates 1.8 1.5 0.3 20% Net interest expense (30.1) (29
Slide 7: Statutory profit: $84m, down 4% relative to 1H10
Statutory profit: $84m, down 4% relative to 1H10 lower benefit from the movement in value of interest rate swaps 1H11 1H10 Variance $m $m $m % Underlying earnings after tax 78.8 79.0 (0.2) (0%) Change in fair value of financial instruments 1.3 8.1 (6.8) (84%) (after tax) Impact of change in corporat
Slide 8: Strategy – (i) – Increase portfolio flexibility
Strategy – (i) – Increase portfolio flexibility • Ahuroa Gas Storage – 3.3 PJ injected during the half (mitigating $25m of additional gas costs) – At 31 December 2010, total gas and LPG in the reservoir: 14.6 PJ (8.3 PJ of which is inventory gas) – Extraction facilities commissioned Ahuroa gas stora
Slide 9: Strategy – (ii) – Lower average cost of generation
Strategy – (ii) – Lower average cost of generation • 23 MW Te Huka geothermal power plant – Completed in May 2010 – Operating performance above expectations • 166 MW Te Mihi geothermal power project (net 159 MW) – Engineering, procurement and construction (EPC) contract executed today – Project cost
Slide 10: Strategy – (iii) – Generation market share growth
Strategy – (iii) – Generation market share growth • Geothermal – 250 MW Tauhara 2 project: Consented – Likely to follow Te Mihi – Taheke – three exploration wells drilled; positive preliminary results • Wind – 156 MW Waitahora project: Consented – 504 MW Hauāuru mā raki project: Consent decision pen
Slide 11: Capital expenditure – reflects Contact’s strategy
Capital expenditure – reflects Contact’s strategy • Stay in business capital expenditure increased marginally to $34m in 1H11, up from $30m in 1H10 • Growth capital expenditure was $168m, (including capitalised interest) compared with $185m in 1H10 • Committed capex includes: – Ahuroa gas storage –
Slide 12: Enterprise Transformation Programme
Enterprise Transformation Programme Successfully accomplished two major milestones on schedule and on budget • Phased replacement of Contact’s business and procurement, generation and retail systems • New finance and procurement systems completed on schedule and on budget in October 2010 • New gener
Slide 13: Health, safety and environmental performance
Health, safety and environmental performance Modest improvement in safety performance in the six months to 31 December 2010. Continues to be a priority focus • The safety of our employees, contractors and Total recordable injury frequency rate (12 month rolling average) visitors to any Contact site
Slide 14: Outline
Outline Results 4 Segmental analysis 15 Supporting materials 30 © Contact Energy Limited 22 February 2011 Results for the six month period ended 31 December 2010 14
Slide 15: Segment overview
Segment overview Electricity segment EBITDAF: up $5m (2%) at $204m: EBITDAF by segment • Hedged generation: Up $9m (5%) due to higher volumes and transfer price offset by carbon costs 250 225 225 and higher gas costs 22 26 • Exposed generation: Up $10m (92%) due to 200 13 21 27 higher sales volumes
Slide 16: Electricity segment operational performance data
Electricity segment operational performance data (1H10 in parentheses) Note: line losses in hedged generation are based on an expected annual level of line losses; actual line losses are reflected in retail © Contact Energy Limited 22 February 2011 Results for the six month period ended 31 December
Slide 17: Hedged Generation - Up $9m (5%)
Hedged Generation - Up $9m (5%) Due to higher transfer price and volumes offset by higher costs • Hedged generation volume increased 98 GWh Breakdown of hedged generation costs – Renewable and thermal mix was similar to the prior 60 4 period at 65% renewable (66% in the prior period) 1 Hedged genera
Slide 18: Exposed Generation - Up $10m (92%)
Exposed Generation - Up $10m (92%) Due to higher average wholesale prices and increased volumes • Exposed volume up 178 GWh (33%) to 725 GWh Breakdown of exposed generation contributionper MWh • Average price earned by exposed generation up 70 $12/MWh (21%) to $66/MWh Exposed generation GWAP compone
Slide 19: Predominantly wet conditions through the period
Predominantly wet conditions through the period Wholesale prices averaged $54/MWh, up $11/MWh from 1H10 Storage levels started and remained high over the first six months 500 5,000 400 4,000 Storage (GWh) Price ($/MWh) 300 3,000 200 2,000 100 1,000 - - Nov Dec Oct Jul Aug Sep Jan Price increase as H
Slide 20: Effective gas costs for generation increased
Effective gas costs for generation increased from $8.86/GJ in 1H10 to $9.64/GJ • Underlying gas costs increased $0.75/GJ Gas used in generation • Gas length during 1H11 was 9.3 PJ (6.3 PJ in 1H10) 30 10 $8.86 • Injections into storage mitigated 3.3 PJ (avoiding $25m in $9.64 additional costs) 25 8 $
Slide 21: If Stratford, Ahuroa and 2H11 gas take-or-pay volumes were in place for 1H11
If Stratford, Ahuroa and the 2H11 gas take-or-pay volumes were in place for 1H11 - EBITDAF would have been up to $35-45m higher • Gas length costs of ~$25m would have been avoided • The Stratford peakers would have covered for CCGT outages and operated during peak periods – CCGTs would have been shu
Slide 22: Net revenue improvements from lower CCGT operation and use of peakers
Net revenue improvements would have resulted from lower CCGT operation and use of peakers • The addition of peakers and storage allow Contact to minimise gas use in periods where gas and other costs exceed the spot price Margin captured during peak-price periods Generation at negative spark-spread r
Slide 23: Retail Electricity - Down $14m (52%)
Retail Electricity - Down $14m (52%) Due to higher energy and mass market network costs more than offsetting the impact of tariff increases and growth in Time of Use sales Load split by customer type and island (sales) 5,000 • Sales volume up 9% to 4,250 GWh 4,250 3,911 4,000 – Time of Use sales up
Slide 24: Mass Market Electricity
Mass Market Electricity External costs (wholesale electricity, networks) continue to rise Breakdown of mass market retail margin • Wholesale electricity up $7/MWh to $88/MWh 220 11 • Mass market network costs up $8/MWh 200 17 14 Hedged generation price components ($/MWh) 7 • Other operating expenses
Slide 25: Wholesale and retail prices will continue to adjust to costs of supply security
Wholesale and retail prices will continue to adjust to reflect the costs of supply security • Wholesale prices will continue to adjust to reflect the costs of thermal generation ($98- $107/MWh) Example of competitor margins on current residential tariffs – Thermal generation is critical for security
Slide 26: Total electricity segment operating expenses are up $7m
Total electricity segment operating expenses are up $7m Primarily due to investment in capability • Operational excellence and risk focus to create competitive advantage – Centralised risk management group, supported by a newly appointed Chief Risk Officer, to align and bolster risk management capab
Slide 27: “Other” segment contribution down $4m (16%) to $22m
“Other” segment contribution down $4m (16%) to $22m Due to decreasing volumes and carbon costs • LPG EBITDAF down $1m to $6.3m Other Segment EBITDAF – Volumes down 2,005 tonnes to 36,127 EBITDAF 1H10 26 – Purchase and sales price down $68/T and $69/T respectively due to favourable CP and fx rates LP
Slide 28: Summary
Summary • Good financial performance in challenging conditions – Higher revenues – Offset by increasing external costs • Significant achievements – Ahuroa Gas Storage commissioned – Stratford peakers close to completion – Te Mihi committed – Tauhara 2 consented – Wind projects consented • Focus on n
Slide 29: Outline
Outline Results 4 Segmental analysis 15 Supporting materials 30 © Contact Energy Limited 22 February 2011 Results for the six month period ended 31 December 2010 29
Slide 30: Te Mihi and Tauhara are low-cost geothermal projects
Te Mihi and Tauhara 2 are low-cost geothermal projects To meet demand growth, or replace higher-cost thermal generation Long-run costs 180 160 • Assuming no demand growth, Te Mihi will 140 $ / MWh substitute for higher-cost thermal generation 120 • With maintenance costs, the price of 100 flexible g
Slide 31: Total demand from 2005 to 2009 is flat but composition has changed
Total demand from 2005 to 2009 is flat but the composition has changed • National demand in 2009 was within 0.3% of that in 2005 (Energy data file); however the composition has changed National demand 40,000 – Annual average industrial demand growth rate from 35,000 2005 to 2009 was -3.7% while comm
Slide 32: Wholesale electricity market conditions expected to become increasingly volatile
Wholesale electricity market conditions are expected to become increasingly volatile with higher peak demand, transmission constraints and the changing nature of New Zealand’s generation base • Four key drivers of increased wholesale market volatility: – More volatile and higher peak demand levels w
Slide 33: Location costs have increased for Retail and decreased for Hedged Generation
Location costs have increased by $17m for Retail and decreased by $8.3m for Hedged Generation – Net $8.7m increase for the company • LWAP-HAY costs for Retail have increased from $1.01/MWh to $4.90/MWh. With purchase volumes increasing by 413 GWh this has resulted in a total LWAP-HAY cost increase o
Slide 34: Financial Results Summary
Financial Results Summary 6 Months Ended 6 Months Ended Variance 31 December 2010 31 December 2009* $m $m $m % Revenue and Other Income 1,198.6 1,070.2 128.4 12% Operating Expenses (1) (973.1) (845.2) (127.9) (15%) EBITDAF (2) 225.5 225.0 0.5 0% Depreciation and Amortisation (85.5) (86.7) 1.2 1% Equ
Slide 35: Electricity segment result
Electricity segment result Electricity Segment 6 Months Ended 6 Months Ended Variance 31 December 2010 31 December 2009 $m $m $m % Wholesale Electricity Revenue 288.2 232.6 55.6 24% Retail Electricity Revenue 740.9 657.0 83.9 13% Steam revenue 11.1 11.5 (0.4) (3% ) Total Electricity Revenue 1,040.2
Slide 36: Other segment result
Other segment result Other Segment 6 Months Ended 6 Months Ended Variance 31 December 2010 31 December 2009 $m $m $m % Wholesale Gas Revenue 43.4 43.3 0.1 0% Retail Gas Revenue 39.6 43.8 (4.2) (10% ) LPG Revenue 65.0 71.3 (6.3) (9% ) Meter Leases Revenue 6.3 5.8 0.5 9% (1) Meter Leases Revenue - Int
Slide 37: Hedged - Up $9m (5%)
Hedged - Up $9m (5%) due to higher transfer price and hedged volumes offset by carbon costs and higher gas costs Hedged segment contribution Units 1H11 1H10 Var Var (%) Hedged generation GWh 4,757 4,659 98 2% Transfer price $ / MWh 88.21 81.11 7.10 9% Hedged generation at GWAP transfer price$ 'm 419
Slide 38: Exposed Generation - Up $10m (92%)
Exposed Generation - Up $10m (92%) due to a 21% increase in average price earned by exposed generation and 33% increase in volumes Exposed segment contribution Units 1H11 1H10 Var Var (%) Exposed generation volume GWh 725 547 178 33% Exposed GWAP $ / MWh 65.90 54.40 11.5 21% Revenue $ 'm 47.8 29.8 1
Slide 39: Retail - Down $14m (52%)
Retail - Down $14m (52%) due to increasing unit energy and mass market network costs more than offsetting the impact of tariff increases and growth in Time of Use sales Retail electricity contribution Units 1H11 1H10 Var Var (%) Sales GWh (ICP) 4,250 3,911 339 9% Revenue $'m 745.8 660.6 85.2 13% Cos
Slide 40: Carbon costs
Carbon costs Carbon costs Volume Average Tonnes Unit cost Carbon factor expense Gas purchases 26.0 PJ 53,500 T/PJ 1,390,230 $21.07 $14.6m Geothermal generation 11m T* 0.0132 145,200 $21.07 $1.5m LPG 36,127T 3.0 107,470 $23.72 $1.3m Swaption 202 GWh 970 T/GWh 196,060 $21.07 $2.1m * Geothermal volume
Slide 41: Operating expenses by segment
Operating expenses by segment (excluding electricity purchases) Electricity segment - operating expenses by type 583 600 507 • Electricity segment expenses up $76m (15%) 99 500 15 14 92 – Electricity transmission costs increased by $18m 16 400 174 139 – Gas purchases increased by $35m – higher volum