Competition, Reliability and Hedge Developments in NZ Carl Hansen New Zealand Electricity Authority
Outline Overview of the NZ electricity system and markets The EA s policy framework Role and overall objective of the EA How the hedge market affects the physical market How the physical market affects the hedge market Recent hedge market initiatives (2010 now) Appendix Origins of the NZ hedge market and market developments (1994 2010) Initial policy focus on transparency and liquidity (2003 2009)
Overview of the NZ electricity system and markets
Demand North Island Auckland 40,000GWh per year 2% growth rate since the 1970s Peak demand has reached 7,400MW (during winter) South Island Wellington Christchurch Minimum demand is about 2,600MW (during summer) 1.7 million residential customers, accounting for 34% of demand 250,000 commercial and industrial customers Rio Tinto smelter accounts for 15% of NZ demand
Generation 9,000MW generation capacity 200 power stations, with 50 connected to the grid Average generation over 2008-2010 56% hydro 28% coal and gas (and 0.1% diesel) 10% geothermal 3.3% cogeneration 2.9% wind Hydro generation is heavily reliant on regular rainfall in South Island catchments Full hydro lakes = only 6 weeks electricity consumption
Demand Generation
Transmission 12,000km of transmission lines Mostly 220kV HVAC lines 350kV HVDC from BEN to HAY Otahuhu 64% of demand is in the North Island 60% of generation is in the South Island Haywards Losses from BEN to OTA approx. 5% Benmore
Overview of key electricity markets in NZ The NZ retail electricity market Has 18 retailers but six of them are just different brands The largest retailers are owned by the large generators There are no price controls over retail tariffs Retail
Retail electricity prices (cents per KWh) 30.00 Residential Commercial Industrial 25.00 20.00 c / KWh 15.00 10.00 5.00 0.00 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Source : MED Energy Data File (Residential prices include GST)
Monthly customer switches
Overview of key electricity markets in NZ NZ spot market Trading occurs at 250 nodes across the grid Half-hourly trading periods Final prices are based on marginal dispatched offer prices and metered demand Final prices published day-after trading Prices are forecast at 1pm the day before for next 24 hours and more accurate forecasts are published four hours ahead of each trading period Retail Spot
Overview of key electricity markets in NZ Consumers 10 directly connected consumers (DCCs) buy electricity from the spot market Several DCCs have embedded generation 10,000 commercial and industrial consumers pay retail tariffs that vary half-hourly based on the spot price Retail Spot In 2010 95% of generation capacity was from five generators 21% Contact Energy (listed) 25% Genesis Energy (SOE) 23% Meridian Energy (SOE) 19% Mighty River Power - MRP (SOE) 07% TrustPower (listed)
12000 Half-hourly Wholesale Prices 10000 8000 $/MWh 6000 4000 2000 0 1996 1998 2000 2002 2004 2006 2008 2010 2012
700 Daily Wholesale Prices 600 500 400 $/MWh 300 200 100 0 1996 1998 2000 2002 2004 2006 2008 2010 2012
Monthly average spot prices at OTA and BEN
Overview of key electricity markets in NZ The hedge market in NZ comprises An OTC market for forwards contracts, where large consumers typically seek competitive bids via open tenders A futures market, operated by the Australian Securities Exchange (ASX). Futures are offered at the Otahuhu and Benmore nodes Retail Spot OTC Futures The ASX futures market started in 2009 and is growing rapidly OTC CFD FPVV Options ASX Futures Total YE June 2010 58% 17% 24% 1% 100% YE June 2011 47% 18% 26% 9% 100% YE June 2011 (GWh) 11,277 4,277 6,190 2,112 23,857
Monthly futures volume traded on ASX 400 GWh 350 300 250 200 150 100 50 0 Sep-09 Oct-09 BEN Volume (GWh) OTA Volume (GWh) Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11
ASX forward price curve for three years ahead (Asking prices as at 17 October 2011) $130 $120 $110 $/MWh $100 $90 $80 $70 $60 $50 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Quarter Ending Dec-13 Feb-14 Apr-14 Jun-14 Aug-14 Oct-14 Dec-14 Otahuhu Benmore
Hedge prices vs. spot market prices Nominal $/MWh 200 180 160 140 120 100 80 Contract - (EnergyHedge/ASX) year ahead Spot - weekly ave. (Haywards) Actual - pulp & paper sector Actual - all industry 60 40 20 0 Sep-98 Sep-00 Sep-02 Sep-04 Sep-06 Sep-08 Sep-10 Sep-12 Sep-14
Hedge prices vs. LRMC of lowest cost entrants 120 100 Geothermal LRMC CCGT - LRMC Contract - (EnergyHedge/ASX) year ahead Actual - pulp & paper sector 80 Actual - all industry Nominal $/MWh 60 40 20 0 Sep-98 Sep-00 Sep-02 Sep-04 Sep-06 Sep-08 Sep-10 Sep-12 Sep-14
Hedge volume and seller concentration 1000 100% 900 90% 800 700 Hedge Volume (MW) HHI % 80% 70% Hedge Volume (MW) 600 500 400 60% 50% 40% HHI % 300 30% 200 20% 100 10% 0 2011 2012 2013 2014 2015 2016 2017 2018 0%
2011 survey view of hedge market competition Prices for these contracts reflect the outcomes expected in a workably competitive market OTC 3-Year ASX contracts 6-Month ASX contracts
Purchaser responses in previous surveys Do you believe a competitive electricity hedge market currently exists in NZ? 2009 2007 2005 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Yes No Don't Know
EA policy framework
Scope and core functions of the Authority The Authority began on 1 November 2010 The Authority replaced the Electricity Commission, and has narrower set of functions It is independent of Minister of Energy and Resources The Authority makes the Code, not the Minister Core functions of the Authority Develop the Code Enforce the Code Contract for market operation services Pro-actively monitor and report on market performance
Statutory Objective (s15 of the Act) Promote competition in, reliable supply by, and the efficient operation of, the electricity industry for the long-term benefit of consumers
Interpretation of our Objective For the LT Benefit of Consumers Promote Competition Investment & innovation Promote Reliability of Supply Robust to large adverse events Promote Efficient Operation Transaction & regulatory costs Efficiency Efficiency Efficiency
Hedge market impact on the physical market Physical Hedge More durable electricity market determines whether VI is best More contestable generation market Better security of supply More defendable spot pricing at top of supply curve More competitive spot pricing generally Futures facilitate entry of indep. retailers & generators Useful price signals for investors in long-term assets Strong incentives for a wider range of parties to acquire and assess information on long-term supply risks Greater revenue surety for investors in last-resort plant Provides effective escape from spot market power plays The greater the level of retail and hedge contracts the smaller the incentive for spot market power plays Long-dated contracts Long-dated cap/options contracts Any hedge contracts
Physical market impact on the hedge market Physical Hedge 2010 Competitiveness of spot market power in spot market transfers to ST hedge market Non-competitive ST hedge pricing X Spot market design Large number of nodes or zones complicates hedge market development Price collapse occurs when serious scarcity occurs Reduces hedge liquidity Reduces hedge demand XX X Poor integration of hedges in spot prudential regime Increases hedging costs X Wider market structure Limited or poor information on future supply risks Regionally balanced VI of generation and retailing Reduces signalling value of hedge prices Reduces hedge demand X XX Government ownership and control Risk of ad hoc intervention during supply shortages Undermines hedge market XX
Recent physical market initiatives Physical Initiative Hedge 2011+ Competitiveness of spot market Introducing power dispatchable in spot market demand, transfers nationwide to ST hedge FK market, and proactive market monitoring Non-competitive Improve ST ST hedge hedge pricing pricing X Spot market design VAS Large agreements number of nodes and introducing or zones complicates FTR market hedge market development Price Introduced collapse scarcity occurs pricing/ccs/stress when serious scarcity testing occurs regimes Poor Reviewing integration integration of hedges of spot in spot prudentials & margining regime Improve Reduces ST hedge liquidity pricing Increases Reduces hedge demand Increases Reduces hedging hedge costs XX X X Wider market structure Limited Reviewing or poor quality information & provision on of future supply supply risk info risks Regionally ASX futures balanced market may VI of progressively generation and reduce retailing VI Improves Reduces signalling value of hedge prices X Reduces Increase XX hedge demand? Government ownership and control EA established Abolished reserve Partial sale as Risk independent of ad hoc intervention energy during scheme supply & shortages of SOE Crown entity sold WHI generators Undermines Bolsters hedge market XX
-making and robust forward price curves
2009 ASX enters the NZ market, offering futures contracts at Benmore and Otahuhu nodes But almost no trading occurs OTC Govt requires five largest generators to put in place by 1 June 2010 a hedge market with: Standardised tradable contracts A clearing house to act as counterparty Low barriers to participation and low transaction costs -makers to provide liquidity ASX Govt also sets a 3,000 GWh target for UOI by 1 June 2011
2010 The generators choose ASX to provide NZ futures market They begin market-making on the ASX market OTC The Electricity Authority is established on 1 November 2010 under a new Electricity Industry Act ASX The Act requires the Authority to amend the Code within its first year of operation To facilitate, or provide for, an active hedge market But it doesn t set targets and doesn t define active
2011 ASX market performance needs to improve Bid-ask spreads typically 7 8% -making is only on offer volumes of 1 MW at Benmore and Otahuhu OTC ASX The Authority encourages generators to adopt new market-making agreements with ASX, comprising Maximum bid-ask spread of 5% for each market-maker Larger offer volumes: 3 x 1 MW offers for each market-maker The objective is a robust and efficient forward price curve We expect robust futures pricing to flow through to OTC market negotiations New market-making agreements adopted in October 2011 by three of the largest generators and by a fourth generator in November 2011
Average bid-ask spread on ASX futures 8.00% 7.00% BENMORE OTAHUHU 6.00% 5.00% 4.00% 3.00% 2.00% 1.00% 0.00% Mar 11 Apr 11 May 11 Jun 11 Jul 11 Aug 11Sep 11 Oct 11 Mar 11 Apr 11 May 11 Jun 11 Jul 11 Aug 11Sep 11 Oct 11
ASX Financial s Otahuhu - as at 17 October 2011 $/MWh $130 $120 $110 $100 $90 $80 $70 $60 $50 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Product End Month Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Feb-14 Apr-14 Jun-14 Aug-14 Oct-14 Dec-14 Bid Offer
Unmatched open interest (UOI) in 2011 Performance of the ASX market in regard to UOI is more difficult to assess UOI only reached 600 GWh by 1 June 2011 But the SOE generators link their VAS agreements to the ASX price In effect, they have largely achieved the 3,000 target ASX But the Authority wants transparency on UOI
ASX open interest (cumulative) 900 800 700 600 GWh 500 400 300 200 100 0 Sep-09 Oct-09 Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Month Otahuhu Benmore
Open Interest by Platform 20000 19000 18000 17000 16000 ASX EnergyHedge OTC Target 15000 14000 13000 12000 11000 GWh 10000 9000 8000 7000 6000 5000 4000 3000 2000 1000 0 01 Jul 2009 01 Aug 2009 01 Sep 2009 01 Oct 2009 01 Nov 2009 01 Dec 2009 01 Jan 2010 01 Feb 2010 01 Mar 2010 01 Apr 2010 01 May 2010 01 Jun 2010 01 Jul 2010 01 Aug 2010 01 Sep 2010 01 Oct 2010 01 Nov 2010 01 Dec 2010 01 Jan 2011 01 Feb 2011 01 Mar 2011 01 Apr 2011 01 May 2011 01 Jun 2011 01 Jul 2011 01 Aug 2011 01 Sep 2011 01 Oct 2011
Hedge market policy focus going forward Achieving new UOI targets 1,000 GWh by 1 Dec 2011 2,000 GWh by 1 Mar 2012 3,000 GWh by 1 Jun 2012 ASX -making on caps or options Clear forward price signals for last-resort resources Should make it easier to avoid ad-hoc policy interventions during supply shortages Ongoing education and training on electricity risks, risk management tools, governance of risk management
Appendix: Origins of the NZ hedge market
Pre-market arrangements Electricity Corporation of New Zealand (ECNZ) Established in 1987 with virtually all of NZ s generation and transmission assets 1 retailer & DCCs Retailing undertaken by 67 distributors, but that means only 1 retailer at each node Directly connected consumers (DCCs) pay wholesale prices to ECNZ Administered week-ahead prices ECNZ OTC contracts
Formation of the spot market 1991: Prolonged droughts led to power black outs 1992: Government inquiry recommended formation of electricity market 1 retailer & DCCs 1994 Retail choice introduced for large consumers Transpower (grid owner) separated from ECNZ ECNZ started providing week-ahead prices based on estimated marginal cost of supply ECNZ also offered fixed price hedge contracts Spot ECNZ CON OTC 1996 Contact Energy (CON) created from subset of ECNZ generation assets Voluntary spot market introduced, comprising only two generation companies (ECNZ and Contact)
Development of the hedge market to 1998 The spot market created significant energy price volatility OTC contracts increasingly used to manage energy price volatility Electricity futures introduced by the NZ Futures and Options Exchange (NZFOE) Spot 1 retailer & DCCs NZFOE OTC ECNZ CON With 244 nodes, the spot market created significant locational price volatility 1996: Transpower offers transmission hedge products 1998: Transpower withdraws them due to concerns about generator pricing behaviour when grid constraints became binding Transpower announces intention to introduce financial transmission rights (FTRs)
Development of the hedge market in 1998 The Electricity Industry Reform Act 1998 Privatisation of Contact Energy (CON) 1 retailer & DCCs ECNZ split into three more SOEs: Genesis Energy (GEN) Spot NZFOE OTC Meridian Energy (MER) Mighty River Power (MRP) CON MRP GEN MER Cross-hedging between the four major generatorretailers reputedly very limited
Development of the hedge market in 1999 The 1998 Act also introduced full retail competition, starting in 1999 DCCs Retailer-distributors required to divest either retail or distribution They all sell their retail businesses to generators, except for TrustPower which sold its distribution business Spot CON GEN MER MRP TrustPower OTC Vertical integration sucked volume and liquidity from the fledgling OTC market NZFOE withdrew its electricity futures product
Development of the hedge market in 1999 & 2000 1999 DCCs Government holds inquiry into electricity market Two independent retailers enter the market. On Energy becomes largest retailer Spot CON GEN MER MRP TrustPower On Energy Empower OTC Independent retailers obtain hedge cover for 2000 Todds TUA 2000 Two small independent generators, Tuaropaki and Todd Energy, enter the market On Energy fails to obtain hedge cover for 2001
developments in 2001 2001: Drought leads to very high spot prices for prolonged period but no black outs DCCs New retailers, and many DCCs, poorly hedged Intense lobbying for government intervention. Spot CON GEN MER MRP TrustPower On Energy Empower OTC Government instigates a public conservation campaign (PCC) Todds TUA On Energy bankrupted and Empower sells its business to Contact Energy No transparency on why On Energy didn t obtain hedges
developments in 2003 Another drought leads to very high spot prices for prolonged period but again no black outs Intense lobbying for PCCs again Govt contracts for a diesel-fired reserve power station at Whirinaki Whirinaki to be offered into the market at its short run marginal cost (SRMC) when droughts occur Spot CON GEN DCCs MER EH Prospect of loss-making Whirinaki power station undermines hedging incentives Under general pressure from Government the four largest generator-retailers establish EnergyHedge MRP TrustPower WHI Todds TUA OTC
and policy developments 2006-2009 TrustPower enters the EnergyHedge market in January 2006 Retail OTC Another drought develops in winter 2006 but it is not so severe as 2001 and 2003 No retailers fail but intense pressure for PCC Spot EH Whirinaki operated at its SRMC but it fails to cap spot market prices 2008: A severe drought develops in winter 2008, resulting in very high prices and significant price separation between North and South Islands No retailers fail but intense pressure for initiatives to suppress spot prices Under considerable pressure, the Electricity Commission reduces Whirinaki offer price below its SRMC
Policy developments 2008 2010 2008: Electricity Commission launches winter review and identifies price suppression from Retail OTC Whirinaki being offered into the market at prices below its SRMC Maximum thermal generation not achieved, potentially due to pricing strategies of hydro generators Spot EH Both matters undermine commercial hedging 2009: Capacity shortages start to occur as operation of Whirinaki creates unit commitment risks for Genesis Energy s old coal-fired units 2009/10: Newly elected government holds Ministerial Review of Electricity Performance. Among other initiatives the Government decides to: Abolish reserve energy scheme and Whirinaki to be sold to Meridian Mandate the transfer of Tekapo A and B stations from Meridian to Genesis
Policy developments 2008 2010, continued (Continued) The Government Requires the three SOE generators to agree virtual asset swaps (VAS) Request the five largest generators to establish a NZ electricity futures market Retail Spot OTC EH Electricity Commission to be replaced by an independent Crown entity, (originally) entitled the Electricity Authority March 2010: the Electricity Commission Increases Whirinaki offers from $1,000 to $5,000/MWh when hydro risks are normal or on security watch, to address unit commitment issues spot price volatility increases substantially over the rest of 2010 Alters methodology for calculation of final spot IR prices during capacity scarcity situations to reduce IR price collapses when reserve requirements reduced to free up capacity for the spot energy market
Initial HM development initiatives: Transparency and liquidity
Formation of the EnergyHedge (EH) market 2003: Under pressure from the Govt the four largest generators establish energyhedge.co.nz Retail OTC A web platform for price discovery, open 11am 12 noon Standardised derivatives Spot EH Referenced to Haywards spot price Quarterly contracts, up to 27 months ahead Bilateral settlement of trades, bilateral credit risk Only open to parties able to meet credit requirements and willing to marketmake at a maximum of 10% bid-ask spread
Price transparency from EnergyHedge EnergyHedge (EH) provided much needed transparency on forward prices Retail OTC Consumers increasingly reference EH prices when negotiating OTC contracts But robustness of prices was questioned as volumes were less than 0.5% of spot market volume Spot EH TrustPower enters the EnergyHedge market in January 2006 but suspends market-making (and trading) during 2008 when spot prices escalate sharply ANZ Bank enters EnergyHedge in 2007 and exits in 2009
EnergyHedge bid-ask spread 10 9 Monthly average spread % 8 7 6 5 4 3 2 1 0 Energy Hedge 4 parties TrustPower enters ANZ Bank Enters ANZ Bank Exits
2006 hedge market report The Electricity Commission identified the following problems with the hedge market A. Lack of robust information on OTC prices and volumes and on supply risks B. Lack of confidence in the competitiveness of the hedge market C. Lack of suitable mechanism to manage locational price risk D. High participation and transaction costs on the OTC market E. Lack of understanding of electricity risk management
2006 policy on hedge markets The Electricity Commission adopted the following solutions Policy initiatives Addresses problems 1. Require publication of OTC contracts A, B, D and E 2. Further develop EnergyHedge A, B, and D 3. Introduce locational rental allocations (LRAs), not FTRs A, B, C and D 4. Develop a master ISDA agreement A, B, and D 5. Make outage and fuel information easier to understand A, B, D and E 6. Promote risk management training and advisors A, B and E 7. Undertake an annual survey of hedge market participants A, B and E