Market power issues in the NEM

Transcription

1 CEEM Specialised Training Program EI Restructuring in Australia Market power issues in the NEM Xinmin Hu Centre for Energy and Environmental Markets Australian Graduate School of Management The University of New South Wales

2 Network Loss factors calculated from data in the previous financial year, applied for the next financial year Distribution connection point (average loss factor) DLF Apply MW and MWAr data to calculate loss factors for each trading interval in the previous financial year Volume-weighted averaged over the financial year Transmission connection point (marginal) MLF Identify variables of determining inter-region losses (e.g generation, load, network factors) Regression analysis of the data in the previous financial year to fit the loss equation Typical loss in transmission network %, and in distribution network could be much higher than this, especially in rural area. Totally is around 1% Inter-regional Settlement Residual Auction

3 NSW: Sydney West 33KV, VIC: Thomastown 66KV, SA: Torrens Island 66KV, Snowy: Murray 33KV, QLD South Pine 275KV transmission connection point ~ MLF RRN (regional reference node) MLF ~ transmission line DLF distribution connection point distribution line DLF Generator bid price at RRN = Generator bid price at connection point/(mlf*dlf) Demand offer price at RRN = demand offer price at connection point/(mlf*dlf) Price at generator s connection point = RRN spot price/(mlf*dlf) Price at demand s connection point = RRN spot price/(mlf*dlf)

4 Impact of loss factors on market outcomes (From NEMMCO, Treatment of loss factors in the NEM, November 1999) Locational advantage Allocated loss factors Generators bids Price/MLF Generators bids after loss adjustment

5 System merit order Impact of loss factors on market outcomes (continued) Payment received from customers Payment made to generators Market settlement surplus = $ $4117 = $42 Settlement Residual Auction

6 Major regulators and functions NECA National Electricity Code Administrator ACCC Australian Competition and Consumer Commission ASIC Australian Securities and Investment Commission Code compliance Code change Market conduct Code authorisation Network access and transmission pricing Trading in electricity derivatives Functions of State and Territory Regulators Distribution access, licensing and compliance Distribution network charges Retail licensing and compliance

7 Market monitoring Compliance with Code Dispute resolution, code enforcement, code change NECA Market surveillance, monitoring and enforcement Effectiveness of market design Market transparency Market monitoring

8 Market power definition and some measurements Market power is defined as a capability of producers to maintain the market price above the marginal cost of production over a sustainable period Price-cost index (ex-post) = Actual price competitive price competitive price X 1% Herfindahl-Hirschman Index (HHI) = Σ (individual market share) 2 For example, National power (52%), PowerGen (33%), Nuclear Electric (15%). Then HHI = 52* * *15 = 418 in the England & Wales market Equilibrium models: Oligopolistic models (game theory models), simulation models, multi-agent models (Bunn&Oliveira 23)

9 Market concentration Gas 12% Hydro 12% Oil 2% Others 5% 4 2 Coal 69% NSW QLD VIC SA SNOWY Total Capacity Dispatchable Capacity NSW QLD VIC SA HHI Registration file version number The Herfindahl-Hirschman Index (HHI) for four NEM regions

10 Four Victorian base-load generators capacity offer at $4/MWh for the 18: trading intervals from April 12, 1999 to August 31, 24 capacity offer available capacity region demand capacity offer available capacity region demand /8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 Loy Yang 4X52MW Edison 2X5MW capacity offer available capacity region demand capacity offer available capacity region demand /8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 Hazelwood 8X2MW Yallourn 2X35MW + 2X375MW + 32MW (gas)

11 Three NSW base-load generators capacity offer at $4/MWh for the 18: trading intervals from April 12, 1999 to August 31, 24 region demand region price (secondary axis) capacity offer available capacity /8/ /1/2 28/5/2 2/1/2 6/2/21 13/6/21 17/11/21 25/3/22 2/8/22 1/12/22 22/4/23 3/8/23 7/1/24 16/5/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 NSW region demand and prices at 18: Delta 66MW X 4 + 5MW X 2+ 3MW X 2 = 424 MW capacity offer available capacity capacity offer available capacity /8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 Macquarie 66MW X4+ 5MW X 4+ 5 MW (gas) = 469 MW Eraring 66MW X 4 + gas units + hydro units = 3676 MW

12 Three generators dispatched generation and capacity factors in the NSW region for the 18: trading intervals from April 12, 1999 to August 31, 24 dispatched generaton capacity factor dispatched generation capacity factor /8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 Macquarie 66MW X4+ 5MW X 4+ 5 MW (gas) = 469 MW Eraring 66MW X 4 + gas units + hydro units = 3676 MW dispatched generation capacity factor /8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 Delta 66MW X 4 + 5MW X 2+ 3MW X 2 = 424 MW

13 Four generators dispatched generation and capacity factors in the VIC region for the 18: trading intervals from April 12, 1999 to August 31, 24 dispatched generation capacity factors dispatched generation capacity factor /8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 Loy Yang 4X52MW Edison 2X52MW dispatched generation capacity factor dispatched generation capacity factor /8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 15/8/ /1/2 22/5/2 24/9/2 27/1/21 1/6/21 3/11/21 9/3/22 14/7/22 2/11/22 3/3/23 6/8/23 12/12/23 17/4/24 21/8/24 Hazelwood 8X2MW Yallourn 2X35MW + 2X375MW + 32MW (gas)

14 Capacity availability of three generators in the NSW region for the 18: trading intervals from April 12, 1999 to August 31, 24 availability availability /8/1999 1/1/2 1/5/2 8/9/2 7/1/21 8/5/21 6/1/21 5/2/22 6/6/22 1/1/22 13/2/23 16/6/23 2/1/23 19/2/24 22/6/24 13/8/ /1/2 16/5/2 16/9/2 17/1/21 2/5/21 2/1/21 21/2/22 25/6/22 3/1/22 7/3/23 11/7/23 16/11/23 2/3/24 22/7/24 Macquarie 66MW X4+ 5MW X 4+ 5 MW (gas) = 469 MW Eraring 66MW X 4 + gas units + hydro units = 3676 MW Only considering 32 MW due to pumps availability /8/ /1/2 16/5/2 16/9/2 17/1/21 2/5/21 2/1/21 21/2/22 25/6/22 3/1/22 7/3/23 11/7/23 16/11/23 2/3/24 22/7/24 Delta 66MW X 4 + 5MW X 2+ 3MW X 2 = 424 MW

15 Capacity availability of four generators in the VIC region for the 18: trading intervals from April 12, 1999 to August 31, 24 availability availability /8/1999 1/1/2 1/5/2 8/9/2 7/1/21 8/5/21 6/1/21 5/2/22 6/6/22 1/1/22 13/2/23 16/6/23 2/1/23 19/2/24 22/6/24 11/8/1999 1/1/2 1/5/2 8/9/2 7/1/21 8/5/21 6/1/21 5/2/22 6/6/22 1/1/22 13/2/23 16/6/23 2/1/23 19/2/24 22/6/24 Loy Yang 4X52MW Edison 2X52MW availability availability /8/1999 1/1/2 1/5/2 8/9/2 7/1/21 8/5/21 6/1/21 5/2/22 6/6/22 1/1/22 13/2/23 16/6/23 2/1/23 19/2/24 22/6/24 11/8/1999 1/1/2 1/5/2 8/9/2 7/1/21 8/5/21 6/1/21 5/2/22 6/6/22 1/1/22 13/2/23 16/6/23 2/1/23 19/2/24 22/6/24 Hazelwood 8X2MW Yallourn 2X35MW + 2X375MW + 32MW (gas) [~148MW)

16 MW Price spikes and bidding/rebidding behavior (case study: June 29-3, 22 in NSW) load curve price curve 1 29/6/22 NSW $/MWh Index of five minute dispatch intervals

17 NSW regional supply, demand, and prices for trade day 29/6/22 3/6/22 Dispatched gen/demand price / :3 1 22: 1 1 4:3am 17:45 :3am next day / :3am / / / /

18 Dispatch offers from Macquarie Generation for 29-3/6/22 (no rebids made by this company in this period) 1 : :3 4:3 18: 9:3 22: Total baseload capacity 464 MW (black coal) and peak-load capacity 5MW (fueloil) $/MWh MW : : : 31 14: : :3

19 Bidding and rebidding strategies : 29/6/22 11:3 29/6/ Blue for daily bid, red for rebid (VP 5) 16: 29/6/22 18: 29/6/22

20 Economic capacity withholding strategy used occasionally, comparing offers for the same trading interval one week before 4: (total 1752 counts) 18: (total 1751 counts) C < C C < C MW /1/24 2/1/24 Demand MW, price Demand MW, price $17/MWh $27.68/MWh Capacity offer reduction Generation down Price up Revenue up $/MWh Revenue up and demand up C is the change of available capacity comparing to the same trading interval in previous week

21 Peaking generators and contracts to run 9 Victoria gas generation from12/4/99-2/3/ MW $/MWh (-6 only) Loy Ya ng A Haze lw oo Yallo um W LoyYang B An glesea En ergybrix New Port(gas 5M Ba irn sd ale(gas-92m Jeerala ng A (g as-2 4 M Jeeralang B(g as-228m Va lley Power(gas-3M Somerton(g as-1 6M Prices at which gas units were dispatched do not match the short term marginal cost of the units for a significant number of incidences

22 Two Victorian peaking units (gas-turbines) dispatch offers in June JLA1-June 24, 18: trading intervals JLA1-June 9, 24, 4:3am-4:am trading intervals VPGS1-June 24, 18: trading intervals VPGS1-June 17, 24, 4:3am-4:am trading intervals

23 Contract and bidding strategies Suppose you hold a bilateral contract with a retailer having a contract volume Q at a strike price F The spot market price is p, your dispatched generation level is q with a generation cost c(q) Your spot market profit is Your net profit from the contract is pq c(q) ( F p) Q Your total profit is p( q Q) + F * Q c( q) Do you want the spot price higher or lower?

24 Source: ACIL Consulting Oct 21 Off-peak peak

25 Market interactions between network, ancillary service and generators strategic behavior an incidence analysis December 12, 22 islanded 3:43pm line down 6:57pm restored 11:55pm back to normal Raise5min $1,/MWh Raise6sec $9,235/MWh Raise6sec $1,/MWh AS prices surged from 18:-19:3 Raise5min $1,/MWh Raise6sec $9,235/MWh

26 Effects on AS payment and generators behavior (during the high AS price periods) VIC and SA energy regional prices 5-5 4:3 6:3 8:3 1:3 12:3 14:3 16:3 18:3 2:3 22:3 :3 2:3 FCAS payment, normally around $5, a week for the entire NEM >$19,, for VIC and SA only for this single day Pelican: rebid 3MW from $5-/MWh bands to $3-9,/MWh 19MW shifted to higher price bands by rebidding Yallourn: 25MW -> $9,/MWh Hazelwood: 18MW -> $25+/MWh Rebid from $5-/MWh bands to

27 Forecast (STPASA, MTPASA, SOO), network constraints and market efficiency (constrained-on/off) QNI and DLINK combined to NSW from QLD Snowy transmission lines to NSW from SNOWY MW Record demand = 12,35MW $/MWh demand price 8:2am 5pm NSW regional demand and prices for 3/1/23 QLD regional demand and prices for 3/1/ MW $/MWh

28 Physical withholding capacity (NEM event on 22/1/21) (event: summer day, from 11:3 to 17:, reduction of capacity) Victorian demand and prices from 4:3am 22/1/21 to 4: 23/1/21(price cap at $5/MWh) Victorian demand and price from : 21/1 to : 24/ price 1999 Demand 1999 price 2 Demand $/MWh $ Loy Yang s generation and revenue from 4:3am Comparison of revenue of Vic generators and Loy Yang 22/1/21 CEEM to 4: Training 23/1/21 Program EI Restructuring in Australia $million VIC 22/2/21 normally LoyYang

29 Dispatch offers by Loy Yang for 11:3-17: on 22/1/ :3am 17: Capacity reduction

30 Concerns over Mergers and acquisitions Spot market price risks force retailers to hedge the risks by seeking more broad portfolios Build new generators AGL Loy Yang (VIC) Generators Retailer Generators AGL, Origin generators in VIC, SA Buy existing generators

31 Loy Yang Power: purchase by a consortium including AGL (since 2, the former owners of Loy Yang Power were trying to sell the power station which has a debt of AUD3.2 Billions, AGL was vigorously seeking to buy it. GEAC (Great Energy Alliance Corporation) was formed in the early of 23 by AGL (35%), the Tokyo Electric Power Company Incorporated (TEPCO, 35%) and a group of financial investors led by the Commonwealth Bank (3%) to acquire Loy Yang.) Former owners of Loy Yang: Loy Yang is 5 per cent-owned by CMS Energy and 25 per cent-owned by Xcel Energy unit, NRG Energy, which are eager to sell the debt-laden power plant. The remaining 25 per cent is owned by Horizon Energy Investments. This consortium bought Loy Yang at a cost of $4.5billion in May 1997 from Victorian government. On December 19, 23, Federal Court supports the acquisition of GEAC of Loy Yang.

32 Concerns about regulation industry regulators potential biased regulations OECD (Organisation for Economic Cooperation and Development) (1999) study shows tendency of sector-specific agencies to be biased in decision-making in favor of industry over consumers and other interested parties so called regulatory capture. This is a particular concern by an economic regulator like ACCC

33 Mitigating market power ACC and Energy Review Committee Increase trading between regions enhancing power transfer capability between regions Increase number of competing generators in each states New entry Increase efficiency of inter-markets Financial or contract markets Improving market design and regulation