Management discussion of financial results for the 6 months ended 31 December 2013

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1 Management discussion of financial results for the 6 months ended 31 December 2013 Financial results for the 6 months ended 31 December 2013 Key financial information 6 months ended 6 months ended Variance 31 December December 2012 $m $m $m % Revenue and other income 1,148 1,213 (65) (5%) Operating expenses (1) (884) (960) 76 8% EBITDAF (2) % Depreciation and amortisation (93) (95) 2 2% Change in fair value of financial instruments 16 (1) % Other significant items 5 (4) 9 225% Earnings before net interest expense and tax (EBIT) % Net interest expense (37) (33) (4) (12%) Tax expense (43) (32) (11) (34%) Profit for the period % Earnings per share (cents) % Underlying earnings after tax (3) % Underlying earnings per share (cents) % Shareholders' equity 3,539 3, % (1) Includes electricity purchases (2) EBITDAF is a non-gaap profit measure calculated as reported profit for the period before net interest expense, tax, depreciation, amortisation, change in fair value of financial instruments and other significant items. Management and Directors monitor EBITDAF as a key indicator of Contact s performance at segment and Group levels and believe it assists investors in understanding the performance of the core operations of the business (3) Underlying earnings after tax represents profit for the period after tax and adjusted for significant items that do not reflect the ongoing performance of the Group Profit for the period Contact s performance improvement has continued with profit for the six months ended 31 December 2013 (1H14) of $112 million, up $24 million (27 per cent) compared with the corresponding prior half year (1H13). This is primarily due to a reduction in the net purchase cost within the Integrated Energy segment and favourable fair value adjustments. Distributions to shareholders The Contact Board of Directors declared a stable interim cash distribution to shareholders of 11 cents per share. The distribution represents a payout ratio of 83 per cent of underlying earnings after tax for the period. Cash flow Free cash flow in 1H14 was $123 million (4 per cent) down on 1H13 of $128 million. An $11 million improvement in EBITDAF and lower stay in business capital expenditure was offset by an unfavourable working capital movement, due to increased injections into Ahuroa gas storage ($33 million). Free cash flow including the purchase or sale of fixed assets in 1H14 was $85 million compared with ($24 million) in 1H13.

2 EBITDAF Contact s EBITDAF for 1H14 was $264 million, $11 million (4 per cent) higher than 1H13. The Integrated Energy segment grew strongly, with EBITDAF up $13 million (6 per cent), while the Other segment decreased by $2 million to $20 million. Retail netback 1 decreased by $2 per megawatt hour (MWh), the equivalent of $9 million less recovered from customers to cover Contact s costs and returns, primarily due to continued generation oversupply and the retail competition that this drives. Contact has successfully held market share in the most competitive retail electricity market in the world despite New Zealand s electricity demand decreasing in 1H14, primarily as a result of warmer than average winter temperatures reducing mass market demand. Contact s electricity sales volumes increased by 2 per cent or 74 gigawatt hours (GWh) to 4,334 gigawatt hours (GWh) with commercial and industrial sales offsetting lower residential sales. Net purchase cost 2 reduced by $5 per MWh, predominantly as a result of increased hydro generation displacing more expensive thermal generation. Lower take-or-pay gas obligations enabled thermal generation to be reduced in-line with increasing hydro generation. With average wholesale prices down $9 per MWh to $47 per MWh, reflecting high national hydro storage levels, Contact was able to run without any combined-cycle gas-fired power stations for longer periods and instead purchased electricity from the spot market at lower prices. Commissioning of the inter-island HVDC link continued throughout most of 1H14, causing periods of price separation and increased contracting of generation volumes. The link was fully commissioned in late November and as expected, with both links operating throughout December, high South Island generation volumes were able to make it to North Island markets with reduced price separation. The EBITDAF contribution from the Other business segment was down $2 million at $20 million reflecting the sale of the gas metering assets, partially offset by a reduction in LPG purchase costs following increased imports and field interruptions in 1H13. Depreciation and amortisation Depreciation and amortisation costs of $93 million were $2 million lower than 1H13 reflecting the sale of the gas meters assets and an extension in the useful life of the Enterprise Transformation assets to align with the estimated useful life of the Retail Transformation of 15 years. Change in fair value of financial instruments The reported profit for 1H14 included a favourable non-cash pre-tax movement of $17 million in the fair value of financial instruments. The movement was predominantly driven by 1 Netback is calculated by deducting the network, levy, meter and cost-to-serve costs from the customer tariffs. 2 Net purchase cost reflects the total operational costs of supplying the energy sold and is calculated as the sum of the total cost of generation and the trading margin between wholesale electricity sales and purchases. / 2

3 favourable movements in interest rates since 30 June This compares to an unfavourable pre-tax balance of $1 million in 1H13. Net interest expense Net interest expense increased $4 million (12 per cent) to $37 million in 1H14. This is due to increased deferred financing costs on redemption of the capital bond ($3 million) and additional interest costs from increased average debt levels due to pre-funding of 2014 maturities ($3 million). These were partially offset by higher interest income ($1 million) as short term deposits were higher. Tax expense Tax expense for 1H14 was $43 million, up $11 million (34 per cent). This represents an effective tax rate of 28 per cent, which is in line with the statutory rate. The effective tax rate in 1H13 was 26 per cent, principally due to the release of part of the deferred tax liability recognised in relation to the held for sale New Plymouth Power Station site. Underlying earnings after tax Management and directors monitor underlying earnings after tax as a basis for determining dividends and believe it assists investors in understanding the ongoing performance of the business. Underlying earnings after tax is a non-gaap profit measure and is calculated by adjusting profit for the period for significant items that do not reflect the ongoing performance of the Group 3. Underlying earnings after tax was $97 million, up $5 million (5 per cent) from 1H13. The underlying adjustments in the current period are the change in fair value of financial instruments, land sales following the FY12 decision to halt Clutha hydro development, impairment charges on land classified as held for sale, transition costs from the Retail Transformation project and associated activities in the Retail business, and the gain on restructure of gas storage operations, along with the associated tax on these items. 3 Significant items are determined in accordance with the principles of consistency, relevance and clarity. Transactions considered for classification as significant items include impairment or reversal of impairment of assets, fair value movements in financial instruments, business integration, restructure and acquisition and disposal costs, and transactions or events outside of Contact s ongoing operations that have a significant impact on reported profit. / 3

4 6 months ended 6 months ended 31 December December 2012 $m $m Profit for the period Change in fair value of financial instruments (16) 1 Clutha land sales (3) (2) Asset impairments 3 3 Transition costs 2 3 Gain on restructure of gas storage operations (7) - Tax on items excluded from underlying earnings 6 (1) Underlying earnings after tax Financial performance and liquidity Net debt exclusive of fair value adjustments at 31 December 2013 was $1,385 million, compared with $1,415 million at 30 June During 1H14, Contact redeemed the $200 million capital bond as a result of a change in rating agency treatment and issued $301 million (US$240 million) of United States Private Placements (USPP) notes as part of the 2014 refinancing programme. As at 31 December 2013, Contact had short-term deposits of $196 million compared to $80 million at 30 June 2013 with the difference predominantly due to receiving the proceeds of the USPP issuance and gas meters assets sale. The balance sheet gearing ratio at 31 December 2013 was 28 per cent. Existing term debt comprises $751 million (US$408 million) of USPP of various maturities, $533 million of fixed rate retail bonds maturing in May 2014, $100 million of fixed rate wholesale bonds maturing in April 2017, two tranches of $50 million wholesale bonds maturing in May 2018 and 2020 respectively, and $83 million drawn down from the export credit agency facility. $648 million of term debt is due to be repaid in the next 12 months and is classified as a current liability. The current portion is comprised of the retail bonds, one tranche of USPP notes ($108 million) and scheduled repayments of the export credit agency facility ($7 million). Contact has additional liquidity from $450 million of committed bank facilities (of which none was drawn at December) and a further $13 million available to be drawn from the export credit agency facility (maximum facility of $105 million). Another $150 million of committed facilities becomes available in May 2014 to coincide with the retail bond redemption. / 4

5 Looking forward Contact s strategy is focused on developing, owning and operating lower cost baseload and flexible energy supplies to cost effectively meet the requirements of its customers and the market. Contact seeks to secure a range of development options across various fuel types to be in a position to execute them as market opportunities arise. The Te Mihi power station is in the final stages of commissioning and ran successfully at 159 MW during its four week reliability test in December Commissioning tests revealed an issue with the hot well pumps. Solutions are being developed, which should see the plant operating at full capacity in the final quarter of the 2014 financial year. In the event that further modifications to the hot well pumps are required, the production impacts will be reduced by diverting steam to the existing Wairakei units. The associated commercial matters are in the process of being resolved with the contractor. In response to the expiry of cheaper gas contracts, Contact has invested over $2 billion in the past six years to lead the transition away from baseload gas to renewable geothermal generation. The reduction in baseload gas generation has resulted in an increased need for flexible thermal generation and fuel supply to support the variability in hydro and wind generation. Contact is well positioned to provide this flexibility through its thermal power stations and gas storage facility. In the retail business, competition is expected to continue with demand remaining reasonably flat as increased economic activity offsets efficiency savings and a continuation of low wholesale prices reflecting market over supply. This environment will require continued focus on operational efficiencies and a move towards lower cost ways of acquiring customers to maintain and improve margins. This objective will be supported by the completion of a new SAP customer management and billing system which will provide Contact with new capabilities to offer products and solutions that better meet customer needs. Contact welcomes the more stable competitive environment that should result from the partial privatisation of previously state-owned enterprises. While this will mean that the industry, including Contact, will be in the full glare of scrutiny from investors, customers and the community to maintain a reliable and competitive supply of energy, it is also expected this will ultimately be for the benefit of the customer with a lower cost industry driven by efficiency and innovation. / 5

6 7 day average price ($/MWh) National storage (GWh) Overview of performance for the period National demand 6 months ended 6 months ended Variance 31 December December 2012 GWh GWh GWh % North Island 11,823 12,170 (347) (2.9%) South Island ex Tiwai 4,485 4,526 (41) (0.9%) Tiwai 2,508 2, % Total national demand 18,816 19,123 (307) (1.6%) National demand fell in 1H14 with total demand of 18,816 GWh, 307 GWh (1.6 per cent) below 1H13. Norske Skog s reduction of 50 MW from January 2013 after shutting one of two paper machines reduced North Island demand by 211 GWh Offsetting this reduction was an increase from Tiwai of 81 GWh (3 per cent) and other large industrials of 43 GWh (4 per cent). Residential and commercial demand was down 1.4 per cent, predominantly due to average temperatures during the first six months being 0.7 degrees Celsius above the prior corresponding period. Electricity market conditions The average wholesale spot price for 1H14 was $47 per MWh compared with $56 per MWh for 1H13. National storage levels remained above mean throughout the majority of 1H14, peaking at 167% of mean at the end of October. Price and national storage levels $200 4,000 $180 $160 $140 3,500 3,000 $120 2,500 $100 2,000 $80 $60 $40 $20 1,500 1, $- Jul Aug Sep Oct Nov Dec 0 HAY price 1H13 HAY price 1H14 Historical average storage 1H13 national storage 1H14 national storage Commissioning of the inter-island HVDC link throughout most of 1H14 caused periods of price separation and contracting of generation volumes by Transpower to support testing. The link was fully commissioned in late November and as expected, with both links operating, high South Island generation volumes were able to make it to North Island markets with reduced price separation. / 6

7 Integrated Energy segment EBITDAF contribution from the Integrated Energy segment increased $13 million (6 per cent) with pressures on electricity sales volumes and margins more than offset by an improved fuel mix and unit generation costs. Integrated Energy Segment 6 months ended 6 months ended Variance 31 December December 2012 $m $m $m % Mass market electricity (19) (4%) Commercial and industrial electricity % Retail gas (4) (10%) Steam % Total Revenue (2) (0%) Net purchase cost (199) (221) 22 10% Electricity networks, levies & meter costs (305) (295) (10) (3%) Gas networks, levies & meter costs (18) (24) 6 25% Total cost of goods sold (522) (540) 18 3% Electricity and gas cost to serve (55) (52) (3) (6%) EBITDAF % Mass market electricity sales (GWh) 2,029 2,207 (178) (8%) Commercial & industrial electricity sales (GWh) 2,305 2, % Retail gas sales (GWh) (31) (8%) Steam sales (GWh) (9) (2%) Total retail sales (GWh) 5,047 5, % Average electricity sales price ($/MWh) (2.78) (2%) Electricity direct pass through costs ($/MWh) % Electricity and gas cost to serve ($/MWh) (11.55) (11.27) (0.28) (3%) Netback ($/MWh) (2.36) (3%) Actual electricity line losses (%) 4% 4% 0% 2% Retail gas sales (PJ) (0.1) (6%) Electricity customer numbers (closing) 438, ,500 (4,000) (1%) Retail gas customer numbers (closing) 63,000 63,000-0% / 7

8 GWh Customers Volume and customer numbers Total retail electricity sales increased marginally in 1H14 to 4,334 GWh with mass market sales reducing by 178 GWh (8 per cent) and commercial and industrial sales increasing by 252 GWh (12 per cent). Competition for retail customers among New Zealand s 18 retailers remains intense with New Zealand rated as having one of the most active retail energy markets in the world. An average of 33,500 customers per month switched electricity provider in 1H14, compared to 29,000 per month in 1H13. Contact s electricity customer numbers were 438,500 at 31 December 2013, down 4,000 from 31 December 2012, while gas customer numbers were stable. Electricity customer numbers decreased by 1,000 from 30 June 2013, with gas customer numbers increasing by 1,500. Commercial and industrial sales volumes increased 12 per cent to 2,305 GWh, predominantly as a result of strong sales in the second half of the 2013 financial year. Resign rates have remained strong during 1H14 reflecting Contact s competitiveness in this market. Mass market electricity sales for 1H14 were 2,029 GWh, 8 per cent lower than 1H13. Average usage per customer was 4,700 GWh in 1H14, 7 per cent lower than 1H13, predominantly as a result of average temperatures being 0.7 degrees Celsius (6 per cent) warmer than 1H13. Following four years of actively reducing South Island exposure and repositioning load closer to generation, the proportion of North Island and South Island load has largely stabilised over the past two years with a continued trend of commercial and industrial sales offsetting decreases in residential volumes. Load split by customer type and island (sales) 5,000 4,000 3,000 2,000 1,000 4,333 4,260 4, % % 381 1,232 1,390 1,352 70% 71% 1,821 1,642 1,683 29% 71% 0 1H14 1H13 1H12 SI mass market SI C&I NI mass market NI C&I Retail gas volumes were down 6 per cent or 0.1 petajoules (PJ) to 1.3 PJ. / 8

9 Netback Performance of the retail channels is measured using a netback calculation. Netback is calculated by deducting the network, meter, levy and cost to serve costs from the customer tariffs. This enables the performance of the retail channels to be measured without using an energy cost. The netback is meant to cover, inter alia, the net purchase cost, capital return, risk margin and a retail margin. Netback decreased by 3 per cent from 1H13 to $88 per MWh reflecting the competitiveness of the current retail and commercial markets. Retail margins remain under pressure with limited returns available for the costs and risks of supplying residential and business customers. Mass market netbacks remained stable with a 5 per cent increase in average tariffs being offset by higher network costs and increased costs to acquire, service and retain customers. Take-up of the higher prompt payment discount for residential customers who receive their bills online and pay on time has slowed although continues to grow with an additional 5,000 customers now utilising the service. The market is also seeing increased offers of fixed price, fixed term contracts with Contact s PowerSure4 product popular in this segment. At 31 December 2013, 51 per cent of Contact s residential customers were on a substantially discounted product. The average commercial and industrial sales revenue decreased by $5 per MWh (4 per cent) to $121 per MWh reflecting current wholesale forward contract prices. Retail gas sales decreased by 8 per cent to 357 GWh with the average margin remaining stable. Cost to serve increased by $1 per MWh to $12 per MWh or $54 million. The combined increase in costs of churn including processing, debt management and marketing combined to offset the savings as a result of the company restructuring completed in FY13. The Retail Transformation programme was delayed from its planned go-live to ensure the business is fully prepared to provide customers with a seamless experience. Customer satisfaction ratings remain strong for front line customer service. The deployment of smart meters continues to build momentum with approximately 28,000 installed over the past six months, bringing the total number of customers now with smart meters to over 155,000. / 9

10 Net purchase cost The net purchase cost reflects the total cash operational costs of supplying the energy sold. It is calculated as the sum of the total cost of generation and the trading margin between wholesale electricity sales and purchases. It does not include any capital return. Net purchase cost decreased by $22 million (10 per cent) as increased hydro generation displaced more expensive thermal generation resulting in lower gas volumes and carbon costs. Net Purchase Cost 6 months ended 6 months ended Variance 31 December December 2012 $m $m $m % Wholesale electricity revenue (50) (17%) Wholesale gas revenue (2) (13%) Total wholesale revenue (52) (17%) Electricity purchases (233) (274) 41 15% Other purchase costs (6) (15) 9 60% Electricity transmission & levies (23) (20) (3) (15%) Gas purchases (122) (141) 19 13% Gas transmission & levies (13) (15) 2 13% Carbon 1 (2) 3 150% Total direct costs (396) (467) 71 15% Generation operating costs (64) (67) 3 4% Net purchase cost (199) (221) 22 10% Thermal generation (GWh) 1,522 1,768 (246) (14%) Geothermal generation (GWh) 1,087 1,144 (58) (5%) Hydro generation (GWh) 2,129 1, % Spot market generation (GWh) 4,738 4,761 (23) (0%) Swaption (GWh) (198) (100%) Spot electricity purchases (GWh) 4,462 4, % CfD sales (GWh) (55) 269 (324) (120%) GWAP ($/MWh) (8.55) (15%) LWAP ($/MWh) (10.52) (17%) LWAP/GWAP (%) 111% 113% (2%) (2%) Gas used in internal generation (PJ) (2.3) (15%) Wholesale gas sales (PJ) (0.1) (9%) Gas storage net movement (PJ) 1.7 (1.7) % Unit generation cost ($MWh) (4.36) (9%) Net purchase cost ($MWh) (4.58) (10%) / 10

11 Generation Contact s total generation in 1H14 was 4,738 GWh, 23 GWh less than 1H13. Hydro generation was up 281 GWh (15 per cent) as higher rainfall resulted in increased tributary flows and storage levels. Hydro spill increased by 96 GWh in 1H13 compared to 1H14, primarily as a result of managing lower south island and HVDC transmission constraints. Contact s geothermal generation was down 58 GWh to 1,087 GWh largely due to outages relating to Te Mihi commissioning. Generation from the combined-cycle gas-fired power stations decreased 150 GWh to 1,424 GWh, a capacity factor of 41 per cent. Lower wholesale prices and a reduction in gas takeor-pay constraints meant that it was often cheaper to purchase electricity off the spot market than it was to generate it. The Stratford peaker plant generated 97 GWh during 1H14, 95 GWh less than 1H13, and had a capacity factor of 11 per cent. Overall capacity utilisation was consistent with 1H13 as increased hydro generation was offset by reductions across other fuel types. Pool revenue averaged $47 per MWh with hydro prices impacted by HVDC constraints and commissioning activity throughout most of 1H14 while the peaker revenues were lower than the previous year as they were predominantly used to manage portfolio costs. Performance of the generation portfolio is summarised below. Nameplate capacity (MW) Plant availability 1 Capacity factor Electricity output (GWh) Pool revenue ($m) Pool revenue ($/MWh) Hydro % 65% 2, Geothermal % 86% 1, CCGTs % 40% 1, Peakers % 6% Total 2,218 92% 49% 4, Measures the reliability of our generation plants. The availability factor calculates the total availability of the generation portfolio over a 39-month historical time period. The time period selected removes the effect of seasonality and known standard maintenance cycles to provide a comparable measure of performance across the years. Wholesale price and volume In 1H14, the volumes used by Contact customers, including contracts for difference (CfDs), decreased by 244 GWh to 4,407 GWh. Purchases for commercial and industrial and mass market customers were up 80 GWh (2 per cent). Contact was a net buyer of CfDs in 1H14 as purchases were made on the Australian Securities Exchange to hedge sales positions and reduce procurement costs by not having to run the combined-cycle gas-fired power stations. Increased CfD purchases offset the reduction in swaption volumes at a reduced cost. / 11

12 PJ / year The average price received for generation was $47 per MWh, down $9 per MWh due to increased hydro generation. The average price paid for purchases was $52 per MWh, $11 per MWh below 1H13. The LWAP/GWAP spread reduced by $2 per MWh ($6 million) with further improvements expected due to the resumption in bi-pole operation on the HVDC inter-island link from the end of November. Unit generation costs Average unit generation costs for the generation portfolio decreased 9 per cent to $44 per MWh as increased hydro generation displaced more expensive thermal generation. Gas costs An increase in hydro generation and lower take-or-pay volumes reduced gas usage in the thermal power stations to 13.4 PJ, a reduction of 2.3 PJ from 1H13 and 4.6 PJ less than used in 1H12. Wholesale and retail gas was largely stable at 1.4 PJ and 1.3 PJ respectively. Natural gas held in the Ahuroa gas storage facility increased by 1.7 PJ in 1H14 to 11.6 PJ as injections were made to manage surplus contracted gas and to increase flexibility in the timing of new gas contracting decisions. The average cost of gas was stable in 1H14 predominantly due to gas storage extractions falling from 1.67 PJ in 1H13 to 0.11 PJ in 1H14 offsetting inflationary increases to existing contracts. Contact s current take-or-pay gas supply contracts are scheduled to expire at the end of 2014, and, as a result of the current oversupply of generation, Contact has sought not to contract for further gas at this time to ensure a range of options remain available Contact's Contracted Quantity ROFR (Take-or-pay) OMV (Take-or-pay) Todd Swap ROFR (max) Take-orpay 33 PJ* CY13 CY14 CY15 * Includes Todd gas sale and repurchase arrangement of 5 PJ in CY13 Take-orpay 24 PJ In November Contact completed the construction of a 9-kilometre pipeline providing a direct link between the Ahuroa gas storage facility and the Taranaki generation assets. The new pipeline enables Contact to extract gas from Ahuroa without processing it through the Waihapa Production Station, reducing costs as well as improving the portfolio flexibility and control of performance. 3 / 12

13 Carbon costs The Integrated Energy segment incurs carbon costs based on the amount of gas purchased for generation and sale to wholesale and retail customers, as well as the amount of steam extracted for use in geothermal power stations. Due to the purchase of lower cost units in 1H14 to meet Contact s 2013 calendar year obligations and a 3 per cent reduction in carbon emissions, 1H14 carbon costs resulted in a $1 million credit compared to a $2 million cost in 1H13. Other segment The Other segment includes the LPG and meter businesses. Other segment EBITDAF was down $2 million to $20 million. Other Segment 6 months ended 6 months ended Variance 31 December December 2012 $m $m $m % LPG revenue (4) (6%) Meter leases revenue 3 7 (4) (57%) Meter leases revenue - internal % Other revenue 2 5 (3) (60%) Total other segment revenue (8) (9%) LPG purchases (39) (46) 7 15% Meter lease costs (16) (13) (3) (23%) Carbon emissions (1) (2) 1 50% Total direct costs (56) (61) 5 8% Other operating expenses (10) (11) 1 9% EBITDAF (2) (9%) LPG sales (tonnes) 34,153 36,809 (2,656) (7%) LPG customer numbers (closing) 66,000 63,000 3,000 5% LPG contributions increased by $5 million to $12 million. LPG sales decreased 7 per cent compared with 1H13, driven by reduced bulk load and warmer temperatures reducing LPG used in home heating. Domestic oversupply meant that intense price pressure is still being experienced for commercial customers. LPG sales in the Christchurch area continue to grow with parts of the reticulated network being re-laid and rebuilt houses connecting to LPG instead of traditional log burners. Purchase costs decreased by 17 per cent due to lower volumes and a reduction in product imports, while average sales price remained stable. Contribution from the metering business was down $4 million due to the sale of the gas metering assets. / 13

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