Energy in - IPART...Determination must result in prices that recover the efficient costs of...

AGL Energy limited ABN: 74 11 5061375

Level 22, 101 Miller St North Sydney NSW 2060

03 August 2009

Locked Bag 1837 St Leonards NSW 2065

T: 029921 2999 F: 02 9921 2552 www .agl.com.au Energy in

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Review of Regulated Retail Tariffs and Charges for Electricity 2010-2013 Independent Pricing and Regulatory Tribunal PO Box Q290, QVB Post Office Sydney NSW 2000

By email: ipart@ipart .nsw.qov.au

Review of Regulated Retail Tariffs and Charges for Electricity 2010 - 2013

AGL welcomes the opportunity to provide comments to the Independent Pricing and Regulatory Tribunal (IPART) on the 'Review of Regulated Retail Tariffs and Charges for Electricity 2010 - 2013 Issues Paper' (Issues Paper).

AGL looks forward to assisting IPART in the development of regulated retail tariffs that deliver a cost reflective electricity service to customers in NSW. Our detailed comments on the matters raised by the Tribunal in the Issues Paper are attached.

Please contact Carol Lydford on 02 9921 2511 if you wish to discuss any aspect of this submission or require any additional information.

Yours sincerely,

Beth Griggs

Head of Regulated Pricing

AGL Sub to IPART Issues Paper - Aug 09 Covering Letter_ 05.08.2009 AGL Confidential

AGL Is taking action toward creating a sustainable energy future for our Investors, communities and customers. Key actions are:

Being selected as a member of the COw lones Sustainability I ndex 2006/07

Gaining accreditation under the National GreenPower Accredi tation Program for AGL Green Energy®, AGL Green Uving® and AGL Green Spirit

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1 AGL Response to the Independent Pricing and Regulatory Tribunal Review of regulated retail tariffs and charges for electricity 2010-2013, Issues Paper

Date: 03 August 2009

Table of Contents

1. Executive Summary .......................................................... 3

2. The Review and Approach ................................................. 6

3. Policy, Market and Regulatory Changes ............................... 8

4 . Wholesale Electricity Cost Allowance ................................. 13

5. The effectiveness of retail market competition in NSW ........ 18

6. The form of regulation .................................................... 23

7. Analyse the costs that an efficient Standard Retailer will incur in supplying customers on regulated tariffs ............................... 26

8. Non-tariff fees and charges .............................................. 32

9. Customer Im pacts .......................................................... 33

AGL Submission to IPART Issues paper - 3 Aug 09 Flnal_ 2

1. Executive Summary

AGL welcomes the opportun ity to make this submission to the Independent Pricing and Regu latory Tribunal (IPART) in respect of the Review of regulated retail tariffs and charges for electricity 2010-2013 Issues paper (Issues Paper).

Competit ion and the impact of regulated tariffs

The Terms of Reference (TOR) released by the Minister make clear that the IPART 2010 Determination must result in prices that recover the efficient costs of supplying small retail customers, while ensuring that the 2010 Determination is consistent with the Government's policy of 'reducing customers' reliance on regulated pri ces'. This makes clear that IPART shou ld be focussed on ensuring that the regulated prices are set at a level which recovers efficient costs and facilitates competition. AGL is of the view that in order to comply with the direction of the TOR to reduce reliance on the regulated prices, IPART must seek to determine the costs incurred by a stand alone retailer supplying small customers in each relevant patch. In order for tariffs to be set at a level that wi ll encourage competition, then this assessment must be made without reference to government ownership, the Electricity Tariff Equa lisation Fund (ETEF) or vert ica l integration If the costs are to be assessed with reference to those actually incurred by the government owned retail businesses with the benefits of the ETEF, then they wi ll not reflect true market costs and competition wi ll be negatively impacted.

AGL suggests that the impact of setting tariffs at a level which does not facilitate competition was evidenced following the 2007 Determination. AGL and other retai lers ' contended at the time that the wholesa le costs were not adequately captured in IPART's decision. Fo llowing the 2007 Determination:

• There was an increase.in the number of customers returning to regulated tariffs. ,This increase in reversion suggests that it has been more commercially attractive for incumbent retailers to place customers on regu lated tariffs, so as to obtain the benefit of the ETEF; and

• customer churn in NSW continued to sit significantly below that observed in other National Electricity Market (HEM) regions.

AGL believes that if tariffs are set at a level which reflects the costs incurred by a standa lone retailer operating in a normal commercial environment, the NSW market will demonstrate very effective levels of competition, and reliance on the regulated tariff wil l be considerably reduced.

Wholesale energy cost

The TOR has instructed IPART to consider the energy purchase costs in accordance with a 'transparent and predictable methodology'. AGL is of the view this is essentia l to a credible process which delivers confidence to industry and consumers, and looks forward

AGL Submission to IPART Issues Paper 3

to an open, transparent process in which all assumptions, inputs and outputs of modelling are provided to stakeholders for analysis and comment.

Further, AGL understands there is considerable uncertainty in respect of the regulatory framework, particu larly in respect of the introduction of a Carbon Pollution Reduction Scheme (CPRS), and the ownership structure of NSW generation and retai l assets. AGL is of the view that the effective means of ensuring a 'transparent and predictable' outcome in these circumstances is to ensure that the various scenarios are openly consulted on, the impacts of those scenarios modelled, and the sensitiv ity of the Wholesale Energy Cost (WEC) results to these va riable scenarios clearly articulated . In th is way, all stakeholders will have a better understanding of the possible impacts of the development of the CPRS, the expanded Renewable Energy Target (RET) and any ownersh ip changes. This shou ld then form the basis of the consultation on the appropriate assumptions.

AGL is ve ry supportive of the requirement in the TOR that establishes the Long Run Marginal Cost (LRMC) as the 'floor ' to the energy purchase cost. AGL also broadly supports the LRMC approach taken by IPART in the past to the cost of Renewable Energy Certificates (RECs) .

AGL has sought to articulate its initial views on the manner in which the WEC should be considered by way of a separate section within th is submission (see Section 4).

Network cha rges

AGL is concerned to note that the TOR does not stipulate the network charges as a direct pass through, although is pleased to note that IPART has recommended no change to the full pass through provisions as considered appropriate from the 2007 Determination .

Should IPART deem it necessary to maintain price constra ints, AGL considers it essential that the constraints are applied after any pass through allowance attributable to network tariffs. This wi ll afford retailers the ability to ensure cost reflective tariffs with minimal cross subsidies.

Retail costs and margin

The allowance for retail operating costs should be established at a leve l that includes all costs in atta ining, retaining and servicing customers. Benchmark operating costs used in other jurisdictions allow a level of cost which permits a range of retailers to compete. AGL antiCipates a similar approach to be adopted in NSW, as it was in the 2007 Determination .

Ensuring the margin available is co rrelated with the risk faced by retai lers is essential for the long term viability of retailers, which in turn is necessary for there to be ongoing investment in upstream supply. Historica lly, energy retai lers have underwritten the majority of investment in upstream supply, either through direct investment or by way of entering into the necessary 'foundation' supply contracts.

Flexibility

AGL understands that IPART is being required to make this determination on retail tariffs for a 3 year period which will encompass all manner of regu latory and structural change. This wil l inevitably give rise to uncertainty, changes in market operation and behaviour and increased volati lity . Irrespective of the care taken in making projections, it must be assumed that IPART, its consultants and stakeholders wi ll not be capable of accurately predicting the impact these regulatory and structural changes will have on the costs incurred by retailers. AGL endorses the approach suggested by the Australian Energy

AGl Submission to IPART Issues Paper 4

Market Commission (AEMC), namely that in the absence of deregulation, there must be sufficient fl exibility permitted in regulatory arrangements so as to ensure retailers are at al l times able to recover market based costs.

Form of price control

AGL continues to support a WAPC approach, without any side constraints . This wi ll permit the flexibility necessary to transition to cost reflective tariffs. Should IPART recommend side constraints on individual tariffs or tariff classes, they must be limited to the retail component only and not the combined network/retail tariff.

AGl Submission to IPART Issues Paper s

2. The Review and Approach

Open and transparent consultation

AGL looks forward to working with IPART and its consultants in an open and transparent consultation .

AGL notes the important ro le played by consu ltants and their projections as to the costs likely to be incurred by retai lers in the coming years. It is essential for those consultants to provide comprehensive explanations of their economic models and the full data sets used in their modelling, and produced by their modelling, in order to ensure a meaningful process in wh ich all stakeholders can have confidence. In the context of a market which will be subject to significant regulatory and structu ral change over the cou rse of the price path, it is essentia l that all stakeholders full y understand the assu mptions used and the sensitivity of the outcomes to those assumptions.

AGL wi ll seek to engage IPART and its consu ltants further in respect of the manner in which information will be disclosed th roughout the process. AGL believes it has learned valuable lessons in other processes, and will seek to apply these lessons to the current IPART process.

A flexible approach

The nature of this price review requires IPART to make projections on the likely costs incurred by a reta iler for a period into the futu re, based on a given a set of assumptions. Thi s is an extremely complex task, rendered even more difficu lt for the next price path period, given the planned introduction of the CPRS in July 2011, the expansion of the RET and the potential restructu re of the ownersh ip of assets in NSW

AGL concu rs with the conclusions reached by the AEMC in its recent report' to the effect that the continued regulation of retail prices in t his context presents t here are significant risks to the energy industry . ..

I n the absence of deregulation, it will be vita l to the confidence and commercial security of retailers that the f inal determination permits sufficient flexibility to allow an adjustment to the price path where the projected cost allowance proves to be below cost. The need for this fl exibility has been supported in both the recent and the Farrier Swier Consulting paper commissioned for the Energy Retailers Association of Australi a (ERAA).

Timetable

The compacted timetable for undertaking the review may present diffi culties for IPART and stakeholders alike. However, it is important that the timeframes do not serve to constrain the consu ltation process. In order for a public, transparent and robust consu ltation process AGL recommends the following :

1 AEMC: "Review of Energy Market Frameworks in light of Climate Change Policies ~ 2nd Interim Report", 30 June 2009.

AGL Submission to IPART Issues Paper - 3 Aug 09 Final_ 6

• Stakeholders should be consulted frequently throughout the review process, including provision of the detail (data and assumptions) pertaining to the modelling of relevant costs;

• In light of the sale process, it is essential that all stakeholders (both incumbent and non-incumbent) are provided with the same information and consultation opportunities throughout the review process;

• A shortened stakeholder response time wou ld be preferable to not being given an opportun ity to provide feedback in the first instance. AGL notes that industry workshops have proved to be an effective means of exped iting discussion and consideration of stakeholders' issues; and

• In add it ion to t he consultation papers and public hearings, AGL suggests there shou ld be a number of comprehensive technical workshops whereby stakeholders, IPART and the expert consultants can discuss the methodology and data inputs in deta il. AGL believes there would be benefit in at least 3 techn ica l workshops:

• the first prior to the finalisation of the consultant's draft methodology report;

• another following the release of the consultant's draft methodology report; and

• another following the release of the consultant's draft report.


3. Policy, Market and Regulatory Changes

IPART has noted that there are a number of changes in government policy and market operations that will need to be taken into account when determining retail tariffs for the period commencing 1 July 2010. These include:

• the Federa l Government's climate change mitigation strategy, including the planned introduction of the Carbon Pollution Reduction Scheme (CPRS) and the expansion of the Renewable Energy Target (RET);

• NSW Government's planned reforms and restructuring of the energy sector and the changes to the planned phase out of the Electricity Tariff Equalisation Fund (ETEF);

• the Australian Energy Regu lator's final Determination on distribution network electricity tariffs; and

• the decision to delay the Australian Energy Market Commission 's (AEMC) review of the NSW retail electricity market's competitiveness to 2011 .

AGL fully supports the requirement of the Tribunal to consider policy and market changes that may have a bearing on the supp ly of electricity in NSW. AGL acknowledges that there may be limited data currently avai lable in respect of the post-CPRS environment. In these circumstances, where a projection is attempted on the basis of comparatively limited information, it is necessary to disclose and consult on all assumptions used in formu lating that projectio·n. In this way, stakeholders will be aware of the assumptions underpinning the results, and the sensitivity of the results to any changes in circumstances which deviate from the assumptions. Further, the regulated price path must be predicated on permitting a full recovery of market costs, and therefore permit a reopening where necessary to reflect the market costs in a changed environment.

Carbon Pollution Reduction Scheme

As recently highlighted by both the AEMC and Farrier Swier in its report commissioned by the ERAA, it is paramount that any methodology used to determine wholesa le energy costs post the introduction of the CPRS, permits sufficient f lexibility to account for the likely volatility and increase in wholesale electricity costs resu lting from the scheme.

Specifically, the AEMC concluded in its most recent report' :

2 Australian Energy Market Commission "Review of Energy Market Frameworks in Ught of Climate Change Policies H

, Second Interim Report, June 2009, pg. 49

AGL Submission to IPART Issues Paper - 3 Aug 09 Flnal_ 8

"Our draft recommendation proposes that increased flexibility to adjust regulated tariffs should be introduced into the frameworks in those jurisdictions that retain retail price regulation. The recommendation reflects our finding that increased uncertainty and volatility of carbon inclusive wholesale energy costs will follow the commencement of the ePRS. The risks this may pose to the viability of retailers and to the development of competitive retail energy markets will be exacerbated if financial instruments to allow effective hedging of the costs are slow to emerge."

Farrier Swier Consu lting was recently asked by the ERAA to assess the difficu lties and ri sks involved in retail electricity price regulation in the transition to the CPRS and a low ca rbon electricity industry. Farrier Swier's conclusion was that' ;

"It will take some time for the electricity industry to transition to a low carbon future with an effective liquid carbon market. The transition period will be characterised by:

• volatility and uncertainty in wholesale electricity prices, in part because of uncertainty in carbon prices; and

• an increased risk of unexpected generator failure, with potential flow on effects for retailers through failed hedging arrangements.

To maintain a financially viable and competitive retail sector, retail prices must reflect costs. During the more volatile transition period, there must be flexibility to adjust retail prices quickly. Such adjustments are at odds with current retail price regulation. "

AGL accepts that it will be difficult to proj ect the WEC across 3 yea rs, particularly given the increased volatility li kely to be introduced wi th the CPRS (and the expanded RET) . In addition to an annual WEC review, retailers should be provided the opportunity to request a review where they consider that wholesa le prices exceed the WEC allowance. This accords with the model suggested by the AEMC in its recent report.

Renewable Energy Target ,

In ca lcu lating the cost to a retailer of complying with the Mandatory Renewable Energy Target (MRET) , it is critica l that the assumed reta il obligations are those set out under the expanded RET policy. The expanded RET policy was agreed to by the Council of Australian Governments (COAG) on 30 April 2009, and included commitments to set the scheme targets at 12,500 GWh in 2010 to 45,000 GWh by 2020. The penalty charge for noncompliance with the scheme was revised up-wards to $65/ MWh.

AGL notes that as the target under the RET expands, so does its impact on the ' black' price. As noted in section 4 below, AGL suggests that this shou ld form the topic of further consu ltation with IPART and its consultants.

In terms of the best assessment of the 'compliance' cost to a ret ailer of meeting their target, AGL considers it appropriate to reference the Long Run Margin Cost (LRMC) of

3 Farrier Swier Consulting, "Managing CPRS transition: implications for electricity retail price regulation ", June 2009, pg. 1


renewable generation, rather than the published market price of RECs. This is because the open market for RECs is current ly thin and illiquid. The largest acquirers of RECs are retai l companies subject to compliance targets under the MRET. Retailers of any significant size cannot rely on securing the volume of RECs they are required to surrender on the open market, therefore there is insufficient security of supply.

Retailers therefore enter into contracts with renewable projects under long term Power Purchase Agreements (PPAs), to underwrite the development of renewable plant. It is this cost that must be considered in the LRMC analysis.

In the previous NSW price review, it appears that Frontier adopted a cost for RECs based on the LRMC of renewable generation using a Brownfields approach . However, the details of the methodology and data used in the model are unclear.

AGL broadly supports Frontier's Brownfields approach but would like to understand in more detail the inputs used in the model. For example: the way in which hydrogeneration was accounted for and the relevant drought scenario applied; and the capital cost assumed for of wind farms.


Planned Energy Sector Reforms and the Electricity Tariff Equalisation Fund

The models used to calculate the WEe shou ld assume:

• that the ETEF does not operate; and

• that the NSW generators will operate as private, commercial businesses, with the aim of maximising revenue and appropriately managing their risk exposure.

It will also be important for stakeholders to understand any sensitivities of the various assumptions made about generation bidding behaviour, for example:

• ownership and control;

• level of contracting; and

• level of debt exposure.

Given the uncertainty about t he ownership and structu re of the incumbent NSW generation and retail assets during the next price path period, understanding these sensitivities will be very important to understanding the modelling outcomes going forward.

Distribution Network Electricity Tariffs

AGL accepts that it is necessary to facilitate the continued improvement and reliability of electricity network services provided by distribution network service providers. AGL therefore supports in principle, the increases in network charges that have been evidenced in recent years and which may continue in the next regu latory period. AGL would expect that the approved expenditure would also deliver enhanced service standards between the network operator and retailer.

AGL notes with concern that the TOR does not require the full pass through of network costs. Whi le IPART has indicated its intention is to continue the practice of allowing a fu ll pass through of network charges, AGL notes the risk presented to retailers by the absence of a firm direction in the TOR. It is essentia l that regulated retail tariffs are cost reflective to promote competition in the electricity market and provide end users with appropriate pricing signa ls to promote efficient use of energy. There is the risk however that due to large network increases, there may be a tendency to minimise any increase in the retail and wholesale portion of the tariffs. AGL strongly recommends the IPART not let increased network charges sway its views on the overa ll change in retai l tariffs, as by doing so cou ld be detrimental to the long-term operation of the electricity market through reduced competition .

Any network related pass through amounts which are to be passed through to the customer by the retailer should be achieved outside of any price limits (on total revenue and customer 's bills) imposed on regulated retail tariffs. This wil l ensure that market offers by the non-standard retailers remain competitive .


AEMC - Effectiveness of Competition Review

AGL fully supports the agreement by the COAG to phase out retai l price regulation where effective competition has been demonstrated. AGL agrees that the AEMC is the appropriate body to undertake the effectiveness of competition reviews in each j urisd iction.

It is disappointing that the review has been postponed, however, AGL believes that in the period lead ing to the review which is now scheduled to commence in 2011, competition will continue t o develop and mature, therefore likely leading to a recommendation for the removal of price regulation by the AEMC. As such, AGL recommends that a provision be included in the price determination to al low for the phase out of price regulation should the AEMC f ind the NSW electricity market to be competitive.


4. Wholesale Electricity Cost Allowance

A transparent and robust methodology

AGL looks forward to a consultative review process with IPART. The TOR require that IPART:

use a transparent and predictable methodology to set the allowance at a level that would allow a Standard Retailer to recover the efficient costs of managing the risks associated with purchasing electricity from the National Electricity Market (including the CPRS) .

AGL believes that in order to meet the requirement for a transparent and predictable methodology it is vital that all modell ing undertaken, including a detailed description of the methodology, the data used and the outputs derived, be made ava ilable to stakeholders for analysis and comment.

This is particularly important in a price review process where retailers have material exposure to the market and are therefore financially impacted by IPART's decision. I n addition, IPART and its consultants will benefit from retai ler's understanding of such things as the operation of the NEM and the potential impacts of the up-coming introduction of the

·CPRS - both of which are complex issues.

'Consu ltation with industry on the detail of the assumptions and modelling will result in more robust outcomes as any potential errors or anomalies will be promptly identified and resolved . Without such consultation, retailers can not be confident in the ve racity of the outcomes of the modelling and may question the cred ibility of the resu lts:

, • The Australian Energy Market Operator (AEMO) (formerly NEMMCo) is an example

of a market operator which ru ns a very transparent process for all its modelling work. For example, during the National Transmission Planning process, stakeholders are provided with the model, including all data and inputs, all owing companies like AGL to full y appreciate how the outcomes were determined; and

• In contrast, AGL's recent experience in Queensland has highlighted the importance of proper consu ltation by regulators with industry, particularly in respect of the assumptions and data used by contracted consultants. AGL would be happy to discuss further detail of this experience with IPART.

In AGL's experience, the most effective means of achieving the obj ective of transparency and predictability is for I PART to instruct its consultants to provide the details of the methodology and the assumptions and inputs used, and to conduct public seminars with interested stake holders. This iterative approach establi shes a credible and transparent process.


Long run marginal cost

AGL supports the TOR requirement that IPART "ensure that the allowance for each year is not lower than the least cost mix of generating plant." While the LRMC of generation can be considered a proxy for the cost a generator will seek to recover over the long term, it does not capture the price a generator wil l seek to achieve over the short term during a price path period . By ensuring that electricity tariffs at least cove r the costs of the LRMC of generation, investment in new plant will be encouraged in NSW and the NSW market wi ll continue to develop.

The objective of the LRMC analysis should be to develop a simple and transpa rent methodology which captures the theoretical cost a generator will seek to recover from supplying electricity to sma ll customers. AGL makes the following comments in respect of modelling the LRMC :

• AGL notes that in the previous price review, Frontier used the Whirlygig model which applied a NEM-wide approach using interconnected regions and NEM load, to determine the 'black' LRMC. While AGL believes the NEM-wide approach adopted in Whirlygig is appropriate when determining generator bidding strateg ies, it is not the most appropriate way for determining the LRMC for a particular Net System Load Profile (NSLP);

• I n compiling its input assumptions for t he LRMC, IPART and its consultants shou ld use as a 'base' the input data from the ACIL Tasman Report 20094

• These assumptions would require further analysis and consultation, but are the most sensible starting point. AGL does note that they should be considered subject to:

~ inclusion of ' interest during construction', which appears to have been omitted from the ACIL costing; and

. . ~ an assumption that new generation plant will be air-cooled / dry-cooled (as

opposed, to wet-cooled) given that it is no longer possible to securE: large sca le water supply for power stations.

• t he modelling should be conducted on a greenfields basis, assuming the generation plant will be built to supply the volume and shape of the NSLP for each patch. This is of paramount importance in the exercise, as the generation plant required to meet a peaky load is very different to that of a f lat load;

• No interconnection should be assumed between regions. Where the model is determining the most efficient greenfields technology to meet a sub-set of the total NEM load (ie the NSLP), interconnection assumptions will result in the interconnectors being able to meet a large proportion of the NSLP - a flawed outcome.

• There should not be any assumption that interconnection or demand-side abatement is an alternative to new plant:

• attempting to model interconnection as a substitute for new plant becomes very complex as it re lies on the assumption of cost recovery from more than one region;

-4 ACIL Tasman: "Fuel resource, new entry and generation costs in the NEM", April 2009.


• demand-side abatement is absent in the small customer market given there are currently no price signa ls to ill icit demand response;

• The exercise shou ld be pred icated on a financial year analysis for each year of the 3 years of the price path. It is important to note that in the financial years post 1 July 2011, the impact of the CPRS will need to be accounted for. For example the cost of fuel may rise post-CPRS implementation; and

• Consultation will need to be held on how to account for the impact of the CPRS, including the new efficient mix of generation plant, the relevant fuel costs and the risk that governm ent policy changes .

Determining the Energy Purchase Cost (EPC)

The 'actua l' energy purchase costs are the 'second limb' to any analysis of the WEC. The purpose of any price regulation methodology shou ld be to forecast the actua l costs a retailer wil l incur into the futu re period . Accordingly, it should be referable to the costs a retailer incurs to prudently manage the supply of electricity to its regulated customer base and to manage its risks .

Wholesale energy costs incurred by retai lers are a combination of the hedge contract prices paid to generators (swap, cap and other derivative costs) and the pool pri ce for energy purchases not covered by hedge contracts. These prices reflect the costs and returns for existing generating assets, the supply/demand balance, the peakiness of the load in a particular market and the volati lity of demand. Hedge contract prices inevitably include a risk premium attributable to such volatili ty. A retailer servicing a regulated load determines the amount of hedge and derivative contract cover based on the load and shape of t he NSLP. The actual WEC incurred by a retailer is determined when the contracts and pool costs are settled out against the NSLP on a day.

Accord ingly, the key inputs into any WEC model are:

• a forecast of the retail load for the relevant period. This should be the NSLP of the relevant retai ler. This is the most appropriate load given that AEMO settles out the NEM pool on this basis and retailers purchase energy to cover th is demand shape. In addition, given it is public information it complies with the requirement that the methodology be "transparent and predictable". AGL objects to the use of the load provided by the incumbent retailers unless that load is provided on an open basis;

• spot market outcomes matched to demand for each half hour of the day; and

• forward hedge contract prices.

AGL believes that idea lly, the above inputs would be based on actual data, that is historical load and spot price data and published forward contract prices . However, where the data is unavailable or lacking in robustness, AGL would be willing to explore an approach to projecting the data. Th is wou ld be most relevant to forward contract prices. As noted previously, any forecast ing or modelling exercise must be completely transparent, including that all inputs and outcomes of the modelling be provided to stakeholders for comment.

AGL Submission to IPART I ssues Paper 15

Allowance for wholesale risks

In setting a WEC allowance, the risks that are to be managed by retailers need to be accounted for. In the past regu lators have accounted for the most sign ificant wholesale market risks by assuming a conservative hedg ing strategy, whereby retailers purchase hedge contracts in advance of the relevant period to cover their forecast load.

Wh ile a conservative hedg ing strategy covers a large portion of a reta iler's risk, it does not account for it enti rely . Further risks wh ich need to be separately accounted for are:

• extreme weather events;

• unplanned supply outages;

• unexpected customer churn; and

• materia l change in the hedge contract prices compared to those assumed in the regulator's model.

These risks can be categorised as follows:

• volume risk, that is a retailer under or over hedges its load due to incorrect load forecasts and has to either buy or sell hedge contracts at the relevant market price. Load forecasts can prove to be incorrect due to churn being higher or lower than predicted;

• liquidity risk, that is the risk that there wi ll be insufficient liquidity in the market and the retailer can not purchase the load at the price assumed in the WEC model; and

• extreme events, for example weather or supply events. That is a retailer is left under hedged at times of extreme demand or curtailed supply which usually equates to extreme pool and contract pri ces.

In add it ion, there must be additional 're-openers' to account for significant changes to the Vl(EC, includ ing:

• the introduction of the CPRS; and

• any other sh ift in the market (for example, the drought in 2007 resu lted in a structura l break in wholesa le electricity costs).

AGL Submission to IPART I ssues Paper 16

Assessment criteria for the review

1. Are [PART's proposed assessment criteria appropriate to guide [PART's analysis and decision making?

The Tribunal has opted for the following assessment criteria to guide it in undertaking its analysis, testing options and making decisions for the 2010 Determination.

1. Protect small retail customers by:

(a) resulting in prices that are based on the efficient cost of supply in each year of the Determination

(b) developing a regulatory framework that facilitates the development of effective retail competition

2. Ensure that the framework covers all relevant risks and efficient costs without double counting

3. Be consistent with the aim of reducing customers' reliance on regulated retail tariffs

4. Provide advice to the Government regarding the impact of the Determination on small retail customers

5. Be consistent with principles of regulatory best practice by:

(a) ensuring that where pOSSible, decisions are made by parties in the best position to make those decisions (avoid micro-management)

(b) beit;g practical, pragmatic and feasible

(c) being simple and understandable

(d) being targeted at the regulatory objectives

(e) being proportionate with the problem

(f) being internally consistent ,

(g) being as transparent as possible.

AGL supports the stated assessment criteria, and notes that the success of the regu latory process in achieving the stated aims of ensuring prices reflect the efficient costs of supply while reducing the customers' reliance on regulated prices wi ll require a specific approach to the calcu lation of the costs. In AGL's view, the only way this can be achieved is for IPART to set tariffs by determining the costs incurred by a stand alone reta iler supplying small customers without the benefits of government ownersh ip or vertica l integration. This will result in tariffs being set at a level that promotes reta iler rivalry, and hence increase competition in NSW.


5. The effectiveness of retail market competition in NSW

AGL strong ly supports the removal of retail price regu lation . The promotion of efficient investment in power generation and upstream gas capacity, the efficient use of energy, product and service innovation and the consumers long term interests with respect to price, qual ity and reliability will best be achieved through cost reflective market based retail prices.

The AEMC has been granted the responsibility to review and provide an ' independent' assessment of the competitive state of the respective energy markets, including NSW, which is now scheduled to commence in 2011 . Any review of competition undertaken outside of the auspices of the AEMC review should, at a very minimum, use the same assessment criteria that has been deemed appropriate by the Ministerial Council of Energy (MCE) in its 2006 review of the criteria for assessing the effectiveness of competitionS The set of criteria to be used was extensively consu lted on by the MCE and wi ll provide consistency in the reviews in each jurisdiction .

However, caution shou ld be taken when measuring against predetermined criteria, with other factors/outcomes to be used to help support a finding of effectiveness of competition or to identify circumstances inhibiting effecting competition. For example, a low rate of churn does not necessarily reflect lack of competition, rather, it may be that customers are happy with the service or price they are receiv ing and do not wish to churn away from their retailer. Such a scenario could be interpreted from the results of the 2006 household survey conducted by IPART6, where approximately 92% of customers said they are aware that they have a choice of electricity retailer, yet the actua l level of churn is far below this level.

AGL's view of the necessary features to assess that a market exhibit effective or workable competition is consistent with those identified by KPMG, in its report on the Effectiveness of Competition and Retail Energy Price Regulation, which are7

:

• Customers are aware that they have a choice;

• Customer know how to exercise choice and it is easy to do; and

• Choices (ie. Offers) are being made avai lable to them.

5 Ministerial Council on Energy, "Criteria for Assessing the Effectiveness of Competition"r 2006

6 Independent Pricing and Regulatory Tribunal "Residential energy and water use in Sydney, the Blue Mountains and IIIawarra, Results from the 2006 household survey", Research Paper, November 2007, p. 5

7 KPMG "The Effectiveness of Competition and Retail Energy Price Regulation", A discussion paper prepared by KPMG for the Energy Retailers Association of Australia, December 2003, pA

AGL Submission to IPART Issues paper 18

In add ition, AGL expects that shou ld IPART determine that competit ion in the NSW electricity market is not yet effective then:

• IPART wil l also identify the barriers to effective competition (market failures), and recommend programs to address those failures; and

• Address the identified market failures, wh ich may involve ensuring prices are not kept artifi cially low by adopting a li ght-handed approach to retail price regulation in the transition to market based prices.

In June 2010 the electricity market in NSW wi ll have been open to competition for a period of 8 years. In NSW, the electricity market cu rrently demonstrates a number of the cha racteristics of a competitive market whilst not experiencing the same high leve l of chu rn activity as has occurred in Victoria and South Australia, specifi ca lly :

• The 2006 IPART household survey· identifi ed that there is a very large percentage of customers who are aware they can choose their electricity supp lier (92% and 93% respectively) - a considerabl e increase on from the 2003 survey which produced a resu lt of 76%.

• Customers have choice, in that there are around 23 licensed reta ilers in NSW of wh ich around 12 are current ly servicing the residential and/or business market9 .

• The NSW market is a 'warm active market' ranked 5th in the world for customer switch ing 'O; and

• There exists a broad range of market offers ava ilable for customers to choose from.

AGL considers that there is sufficient competi tion developing in NSW, and that an independent review by the AEMC in 2011 wi ll lead to the same conclusion. I f regulated retail .prices are set at appropriate levels, t he level of competition in NSW wil l move to levels evident in in South Australia and Victoria. Both Victoria and South Australia have been ranked as amongst the most competi tive markets in the world for customer switching". AGL suggests this is due in no small part to the regulatory success in estab lishing leve ls of regulated tariffs which permit competi t ion, and allow market forces to establish the efficient market price.

8 ibid, p. 5

9 Information from IPART website: http://www.ipart.nsw.gov.au/electricityjlicensing.asp

10 VaasaETT Utility I "Customer Switching Research Project - World Energy Retail Market Ranking", Fourth Edition, October 2008

11 VaasaETT Utility, "Customer Switching Research Project - World Energy Retail Market Ranking", Fourth Edition, October 2008. Victoria and South Australia were ranked no. 1 and 2 respectively in the world for customer switching.


2. What are the relevant markets for the supply of electricity in NSW? Is there any evidence to suggest that there are separate sub-markets defined along consumption, income, residential/business or homeowner/ tenant lines for small retail customers?

AGL is of the view that there is a national market for the retail supply of electricity. Further, as outlined in IPART's 2007 determination, competition is developing in all regions of NSW12, albeit at varying pace.

AGL believes there is merit in considering the residential and business market segments separately with a view to a potential staged approach to price deregulation. If for example, IPART or the AEMC found that there is in fact effective competition in the business market, yet the residential market was still in the 'developing stage', then a recommendation for the removal of price regulation for the business market alone could be considered.

3. Has there been any significant change in the number of retailers supplying small retail customers in the metropolitan areas relative to the non-metropolitan areas?

From information readily available to AGL, there appears to be no significant change in the number of retailers supplying sma ll retai l customers in the metropolitan areas relative to the non-metropolitan areas.

4. Are there any barriers (or emerging barriers) to entry that may limit the potential for competition in the NSW retail electricity markets? .

AGL does not believe there to be any barriers to entry in the NSW electricity market. ' As noted elsewhere, AGL anticipates that if the regulatory process is successful in setting regulated tariffs at a level which is capable of encouraging competition, the level of competition in NSW will approach that observed in Victoria and South Australia.

5. What is driving the apparent reduction in retailer marketing activity? Is there sufficient information available to customers in NSW to allow them to exercise choice?

Retailers will change the nature of their marketing campaigns from time to time, and for those retailers that operate nationally, they may target different jurisdictions at different times for a number of reasons . The ability to recover the costs to service a customer in that specific jurisdiction, while making a commercially acceptable margin, is a key consideration in directing marketing activity. That being said, the results of the 2006

12 Independent Pricing and Regulatory Tribunal "Review of regulated retail tariffs and charges 2007-2010", Final Report and Determinat ion.

AGL Submission to IPART Issues paper 20

household survey13 identified that 92% of customers are aware they can choose their electricity retailer.

There is a vast array of information currently available to customers to enable exercise of choice of retailer and/or product, such as retailer websites and comparison and info sites (eg . Go Switch, Switchwise, Energy Watch, ChoiceSwitcg .com.au, shoparound .com.au, uswith to name a few). While many tools are computer and Internet based, customers are able to make contact with retailers via contact centres to obtain information from a contact centre representative.

6. While there appears to have been a reduction in the discounts offered to customers, has there been any innovation in the price/service pages offered to customers?

AGL suggests that a key reason for a reduction in the level of discounts offered to customers may be due to low margins which have existed in NSW.

7. Has there been any change in the types of customers being offered competitive contracts? Is there any evidence to suggest that there are particular groups of customers that have been more or less active in the competitive market, such as pensioners or tenants?

AGL is not aware of any changes in the types of customers being offered contracts. It is AGL's general policy to offer competitive contracts to any customer who seeks to use AGL as their energy supplier.

8. Is IPART's approach for analysing the effecti.veness of retail market competition appropriate for this review? Are there any other factors IPART should considers?

As outlined above, any review and analysis outside the AEMC directed reviews shou ld be undertaken using similar criteria as used by t~e AEMC to allow for greater consistency and comparison.

9. Are there any perSistent factors that may prevent the level of competition from developing over the medium term' How might IPART's 2010 Determination address these factors?

AGL anticipates that if the regulatory process is successful in setting regulated tariffs at a level which is capable of encouraging competition, the level of competition in NSW wi ll approach that observed in Victoria and South Austral ia

13 Ibid, pg 5

AGL Submission t o IPART Issues Paper 21

10, How should IPART take into account the NSW Government's strategy to restructure and reform the energy sector in NSW in assessing the future level of competition?

It is important that IPART, for the purposes of this review, assume that the incumbent retailers will be owned by private compan ies prior to the start of the price path period, and shou ld not take the ETEF into account when determining the WEe.

Any structural reform to the energy industry in NSW should be assumed to maintain or enhance the level of competition in the relevant markets ,


6. The form of regulation

11. Should IPART continue to regulate all the Standard Retailers' existing regulated retail tariffs and charges for small customers?

12. Where a customer on a regulated tariff elects to pay a premium for green energy, should !PART continue to leave the green premium component unregulated?

13. Should IPART continue to limit Standard Retailers' ability to establish new regulated tariffs to where there are exceptional circumstances, and where IPART's prior approval has been obtained? If not, why not?

14. Should IPART continue to provide Standard Retailers with the flexibility to rationalise their regulated retail tariffs and remove obsolete tariffs, as long as they continue to offer a regulated tariff to small retailer customers? If no, why not?

15. Should IPART continue to subject Country Energy to an additional condition such that if it seeks to remove a regulated tariff and transfer customers from that tariff to another tariff, it must obtain IPART's prior approval if the price applying to the two tariffs (including level and structure) is not the same? If not, why not?

AGL supports the removal of retail price regu lation when a market demonstrates effective competition, however, in the interim period prior to removal of price controls, a light handed approach to regu lation should be considered, with minimal side constraints. This wi ll provide retai lers with t he ability to ensure individual tariffs are cost reflective, which ' promotes a sim plification of existing tariff structures and provides the fl exib ili ty to support an active competitive market .' .

AGL strong ly supports the continuation of the cu rrent arrangement whereby any green prem ium component is unregulated . AGL suggests that:

• to initiate regulation of this component would be at odds with the stated aims of transitioning toward less reliance on regulated prices; and

• the complexities of attempting such an approach wou ld be considerable, and likely to outweigh any benefit.


16. Has the WAPC approach to regulating retail tariffs facilitated the rationalisation of regulated retail tariffs and the removal of obsolete tariffs over the 2007 Determination period?

17. Is there any evidence that a WAPC approach to regulating retail tariffs has allowed the Standard Retailers to segment certain customers and charge prices that significantly exceed the efficient costs of supply?

18. Does a WAPC based on a build-up of network charges approved by the AER and retail costs blocks estimated by IPART best meet the objectives for this review? Are there enhancements that can be made to the current approach?

19. Are there other approaches to determining retail tariffs that IPART should consider?

20. Would imposing additional price limits on individual tariffs or tariff components be consistent with the assessment criteria for the 2010 Determination? If so, what form should these price limits take?

21. How effective was the 'threshold price increase test' for Country Energy in providing additional protection to customers against prices that were significantly above costs without limiting Country Energy 's ability to rationalise tariffs?

A weighted average price cap on the 'retail component' only with full pass through of network charges (while permitting recovery of all market based costs referable to any regu latory changes such as the ePRS) should be adopted as the form of regulation for the next 3 years. AGL does not support the imposition of price limits as this would not allow retailers the appropriate flexibility to structure tariffs accordingly to ensure each individual tariff is cost reflective.

AGL agrees with IPART that there is not sufficient reason to warrant the introduction of additiona l price constraints.

22. If IPART's analysis of the effectiveness of retail competition in the non-metropolitan market indicates that a similar test is needed over the 2010 Determination period, what modifications or enhancements could be made to the current test to improve its consistency with the assessment criteria for this Determination?

AGL does not believe that a threshold price increase test is warranted, and considers that if tariffs are set at levels considerably higher that cost, competition is likely to surface, with competing retailers entering the market, resulting in customers transferring to another retailer who is able to provide a service at a discount to the regulated tariff.

While AGL understands that any transition away from price constraints may require initial management or price monitoring, it still remains that prices need to be cost reflective and that any cross subsidies need to be unwound. Retailers should be provided the ability to rebalance tariffs where required.


23. Is there any reason why IPART should not include a costs pass-through mechanism as part of the 2010 Determination?

24. What enhancement could be made to the current cost pass-through mechanism to make it more consistent with the assessment criteria for this Determination?

AGL strongly supports the inclusion of a pass-through mechanism which will allow material increases or decreases in costs associated with unanticipated regulatory or taxation events to be passed through to customers.

AGL's views in respect of mechanisms for ensuring full cost recovery in the light of significant regulatory change are articulated above.

25. Is there support for altering the price change date? What are the potential benefits and complications?

While AGL can empathise with the tight timeframes often imposed on retai lers to produce and publish tariffs each year, the cashflow ' mismatch' due to timing of price increases for networks and retailers may prove to be too great for retailers to absorb. This would be particu larly true for sma ller, new entrant reta ilers . AGL would be happy to explore a solution to thi s timing difference wi th network increases with IPART.


7. Analyse the costs that an efficient Standard Retailer will incur in supplying customers on regulated tariffs

26. [5 there any reason why [PART should not set a bundled 'black and green' (carboninclusive) energy purchase cost allowance and then add an allowance for the costs of complying with other green schemes including the MRET?

AGL agrees that the 'g reen' element of purchase costs will be intrinsically connected to the 'black' WEe. However, AGL also notes that as the targets increase under the expanded RET, the impact this policy will have on the 'black' price will also increase.

AGL suggests this issue is one that needs to be fully explored between stakeholders, IPART and its consultants. The assumptions used in, and sensitivities of, the consultant's models should be a significant topic of discussion at the earliest opportunity.

27. How would any IPART decision to set a carbon-inclusive energy purchase cost allowance relate to the scope and timing of any periodic review?

Given that the details of the CPRS are currently unknown, it will be difficult to determine a wholesale electriCity cost allowance that fully captures CPRS costs for the financial years from July 2011.

Accordingly, it is important that any review be completed with the objective of fully capturing the expected black and green energy costs as close to the relevant period as possible. As noted elsewhere, /ioGL is suggesting a process whereby:

• there is an annual review permitted so as to account for any significant departure from the regulated WEC; and

• a retailer instigated review also permitted to account for circumstances leading to likely retailer distress.

AGL Submission to IPART Issues Paper - 3 Aug 09 Flnal_ 26

28. Is there publicly available data on future electricity prices that could be used to estimate a market-based energy purchase cost allowance? What are some of the benefits and complications of using this data?

As stated, AGL believes that IPART's methodology for assessing the WEC should rely on transparent, available market data. This includes using publi shed forward hedge contract prices, from either AFMA or D-Cypha Trade14

•

The benefits of using AFMA or D-Cypha Trade data includes;

• that the information can be found from publi c sources and is therefore easily verifiable; and

• the outputs are more likely to reflect the actual costs retailers are likely to incur.

However, where the data is unavailable or lacking in robustness, AGL would be wi lling to explore an approach to forecasting/projecting the data. Any forecasting or modelling exercise must be completely transparent, with all inputs and outcomes of the modelling provided to stakeholders for comment and analysis.

29. Should the approach to estimating the market-based energy purchase cost allowance be based on a particular 'point in time' or rolling estimate? What are the implications for the other cost components?

AGL believes that the methodology shou ld assume a prudent hedging strategy which is consistent with a 'rolling estimate' approach. .

Regulators, and their expert consultants, have supported this view in the past. For example, in the 2007 South Australian Price Review, the Alien Consulting Group stated:

the most appropriate way to manage the risks in changing forward contract prices is to use a rolling hedging policy, that is, to commence purchasing contracts for a particular period some time in advance of that period. Regulators have tended to assume that contracts are purchased over a two or three year rolling period. 15

By assuming that a retailer hedges an equal proportion of its load each month starting 2-3 years in advance, the model wi ll more closely reflect the reality that retailers are exposed to the highs and lows of the market. In addition, it will avoid an assumption of perfect hindsight which is often associated with flawed models.

14 Either D-cypha Trade or AFMA would be adequate sources of information on the actual and forecast hedge contract costs. The data from both sources are highly correlated and have the depth of information to provide a realistic view of hedge contract prices.

lSThe Alien Consulting Group: "Wholesale Electricity Costs for Standing Contract Customers in South Australia: Report to Essential Services Commission of South Australia", August 2007, page 19.


30. Is a volatility allowance an efficient and reasonable means of addressing the risk of wholesale electricity price volatility in the context of the ePRS? Or should this risk be managed and compensated elsewhere?

As discussed earlier, there are three risks that must be accounted for in the WEC allowance. These risks can be categorised as follows:

• volume risk, that is a retailer under or over hedges its load due to incorrect load forecasts and has to either buy or sell hedge contracts at the relevant market price. Load forecasts can prove to be incorrect due to churn being higher or lower than predicted;

• liquidity risk, that is the risk that there will be insufficient liquidity in the market and the retailer can not purchase the load at the price assumed in the WEC model; and

• extreme events, for example weather or supply events. That is a retailer is left under hedged at times of extreme demand or curtailed supply which usually equates to extreme pool and contract prices.

AGL does not believe the volatility allowance as calcu lated in the previous price review, is adequate to cover all of the above risks.

In regards to the CPRS, AGL reiterates the importance of the annual reviews and retailer initiated reviews, which shou ld ensure that any incorrect forecast of the WEC (including CPRS costs) is corrected as soon as possible .

31. What is the appropriate scope of IPART's periodic review and how should it be conducted? . .

The purpose of the annua l WEC review should be to remove the risk to retailers of being locked into a 3 year regulated price path which inadequately covers wholesale costs and risks. This is particularly important during the next price path period whiGh will overlap with the introduction of the CPRS.

AGL suggests that IPART's review shou ld be limited to the WEe. In particular it shou ld focus on ensuring that the WEC allowance reflects the full cost of the CPRS and any other regulatory change.

32. What is the appropriate frequency and timing of the periodic review?

Reviews should be annual, and otherwise as requested by a retailer.

33. I s there any reason to adopt a threshold for change of more or less than 10 per cent?

AGL suggests that this question will best be answered after an analysis of the sensitivities of the model to the changes to assumptions (i.e. circumstances).


34. Is there any reason that the periodic review should not be symmetrical such that both material increases and decreases are reflected in regulated retail tariffs?

There is a greater risk to the long term development of the NSW electricity market if prices are set at below cost reflective levels than if they are set at above cost reflective levels. This is because if costs are set below cost reflective levels then competition and investments are likely to be stifled. Whereas if costs are set above realistic levels then any benefit is likely to be competed away as retailers seek to attract customers away from regulated contracts.

Accordingly, the emphasis must be on avoiding below cost reflective tariffs.

35. Have there been any significant changes to retail business activities? Are previous retail operating cost analyses and benchmarks a valid starting point? If not what are the alternative approaches?

In its last price determination (2007 Determination), IPART sought expert advice from Frontier/SFG Consulting to assist in determining an appropriate retail operating cost allowance. Frontier used the information from the standard retailers and then compared this information to industry benchmarks. In addition, within the same review, Frontier/SFG acknowledged that operating costs for stapled retailer/distributors are likely to be lower than that for a stand alone mass market new entrant. Given that the operating cost was to be based on a mass market new entrant it was therefore disappointing that the eventual allowance for retail costs was set considerably lower than the amounts allowed in other jurisdictions.

AGL also notes that the 2007 allowance for operating costs is not sufficient to cover the costs associated with events that wo~ld normally resu lt in the recovery of miscellaneous fees and charges in other jurisdictions due to restrictions in the Electricity Supply Act 1995 which limits what retailers in NSW can charge in the way of miscellaneous fees and charges. Retai lers in NSW will need to recover these costs from alternate revenue source, being actual retail tariffs.

AGL strongly recommends the use of industry bench marking to determine the appropriate retail operating cost allowance. Benchmarking is a widely accepted practice in regulatory pricing determinations.

As with AGL's recommendation for workshops relating to the calcu lation of wholesa le energy costs, we suggest a workshop focusing on retail operating costs wou ld be a sensible approach.

With regards to significant changes to business activities, the inclusion of costs related to the start up and ongoing maintenance of operations and systems dedicated to the CPRS.


36. What is an appropriate basis for assessing the customer acquisition costs of an efficient Standard Retailer?

AGL is pleased the customer acquisition costs are to be incorporated into the regulated retail tariffs to assist in the development of competition in NSW.

In determining an appropriate amount for customer acquisition costs, AGL general supports the manor in which IPART determined these costs for the 2007 determination, with the exception of the retention periods used by IPART. In the 2007 Determination IPART recommended the view of Frontier that the retention period for customers to be 8 years for residential customers and 6 years for business customers.

AGL does not agree with the retention periods previously used by IPART and would consider a more appropriate retention period to more in the line of 5 years for residential customers and 3 to 4 years for business customers.

37. Is IPART's proposed approach for determining the retail margin for the 2010 Determination appropriate? If not, what are the alternative approaches?

38. Have there been any significant changes to retail business activities' And if so, what are the implications for the retail margin?

The margin earned by a business is, in effect, a return on the risk to its revenue/capital outlay the business is required to undertake in its operations. In order for other energy retailing businesses to enter the market and compete, the margin available must be one which shareholders and debt and equity providers consid 'er commercially acceptable to warrant the risk.

Ensuring the margin available is correlated with the risk faced by retailers is essential for the long term viability of retailers, which in turn is necessary for there to be ongoing investment in upstream supply. Historically, energy retailers have underwritten the majority of investment in upstream supply, either through direct investment or by way of entering into the necessary 'foundation' supply contracts. Detailed in Annexure 1 is a list of the upstream projects that AGL has effectively underwritten.

It is also important to note that benchmark retail margins exhibit an asymmetric risk. If the benchmark costs and margins are set below realistic levels then competition and investment are likely to be stifled. However, if margins are set above realistic levels then any benefit is likely to be competed away as other retailers seek to attract regulated customers.

In order for there to be effective competitive markets and ongoing security of supply, it is critical that the retail margin reflects a commercially realistic reward for the risks faced by retailers supplying electricity to small customers in NSW.


39. Are there any reasons why [PART should alter the approach it used for the 2007 Determination to incorporate energy losses into regulated retail prices?

AGL does not see any reason to alter the existing approach for the incorporation of energy losses into regu lated retail prices.

40. Are NEM fees and anciffary charges likely to significantly change from their current levels over the 2010 Determination period?

AGL supports the decision of IPART to seek Frontiers' advice on likely movements in NEM fees and anci llary charges, and will provide feedback accordingly on the proposed cha rges during the review. However, AGL stresses that in order to provide meaningfu l feedback, it is essential that when undertaking anal ysis and/or modelling, Frontier use data that is readily available in the market to which retai lers can also obtain make use of t o simulate results.


8. Non-tariff fees and charges

AGL notes that the Electricity Supply Act 1995 (ESA) defines regulated retail charges as a security deposit, late payment fee or dishonoured bank cheque fee of an amount specified in a determination that is in force.

Wh ile AGL recognises the current limitations on IPART in considering miscellaneous charges it may be appropriate for IPART to provide for within the determination the capability for consideration of the type and quantum of non-tariff fees and charges should there be an amendment to the ESA or re levant regulations in the future. We suggest that IPART consider making a recommendat ion to the Minister for an amendment to the ESA to promote greater national consistency for retai l charges, especially given that a large number of retailers that, since the introduction of full retail competition, operate on a national basis. Legislation should be amended to allow national consistency, which would likely lead to cost savings due to the ability for operating system standardisation.

41. Is there any reason to change the level of the security deposit or the circumstances surrounding the charging of security deposits?

AGL considers that the actua l collection or otherwise of security deposits for residential and business customers shou ld be left to the retailer to determine, and does not see any reason to change existing arrangements.

42. Is there any reason to change the level of the late payment fee or the circumstances surrounding the charging of the late payment fee?

Late payment fees should be applied on a cost reflective basis and should be applied to those customers who have, through their own actions, caused additional costs to be incurred by the retailer. Late payment fees are designed to encourage customers to meet their obligation to pay their accounts by the due date.

Currently, AGL charges $14 for those customers on electricity market contracts in NSW that make a late payment. This amount is cost reflective and calculated and charged to the customer on a fair and reasonable basis.

The late payment fee applicable to residentia l customers should be applied to the energy accounting following late payment of the initial invoice. This practice is consistent with other jurisdictions, as well as with other consumer goods, such as telecommunications.

43 Is there any reason to change the level of the dishonoured cheque fee or the circumstances surrounding the charging of the dishonoured cheque fee'

The dishonoured payment process generally requires manual intervention by the retailers and thus can result in considerable administration costs being incurred by the retailer. Therefore, the retailer shou ld be able to recover these costs where payments are dishonoured by financial institutions in addition to any fee charged by external parties.

AGl Submission to IPART Issues Paper - 3 Aug 09 Flnal_ 32

9. Customer Impacts

44. What are the likely impacts of higher electricity prices on different types of customers?

AGL expects that customers in different socia l economic groups wi ll be impacted to varying degrees, depending on their personal financial status and their ability to manage their energy usage. Retailers provide an array of programs and assistance packages to those customers having difficu lty paying their energy bi ll. There are also regulations in place to ensure that customers are provided with additional protection .

The underlying cost of many goods and services has increased substantially in recent years. While energy prices increased substantially in 2009/10, this required increase was purely to recovery the actual costs of supplying electricity.

AGL notes that the tota l average weekly expenditure on energy (fuel and power combined - as determined by the ABS in 2003-04) comprises around 3% of the total household expenditure'·. For this reason, AGL believes that a holistic approach will provide the best outcome to deal with the overall financial hardship that a customer may be experiencing at that time. AGL considers that a 'shared responsibility' model is the most effective and efficient arrangement to deal with issues of financial hardship. Assistance to customers in financial hardship is a mutual socia l obligation to be shared between retailers, governments, customers and welfare and community groups.

45. Given NSW and Federal Government customer assistance measures, are there any aaditional measures, including better targeting of existing measures, that may alleviate thf' impacts of higher prices?

AGL believes that in order to target vulnerable customers, concessions must be based on a percentage deduction, without an annua l cap, are best. This targets those people who need the money the most and applies the funding directly to a non-essential service. A cap on concessions is discriminatory against those people who have a higher consumption usage and is harder to manage

16 Australian Bureau of Statistics, "Household Expenditure Survey", Australia, Summary of Results, 2003-04 (Reissue), pg .10


Annexure 1

List of Generation Projects Underwritten by AGL

New South Wales

• Hydro - 62.2 MW

Queensland

• Yabula - 121 MW (50% dispatch rights)

• Oakey - 282 MW (100% dispatch rights)

• Moranbah - 12 MW

South Australia

• Torrens Island - 1,280 MW

• Hallet 1 - 94.5 MW (off-take)

• Hallet 2 - 71.4 MW (construction)

• Hallet 4 - 132 MW (construction)

• Watt le Point - 90.8 MW (off-take)

• Angaston - 49 MW (off-take)

Victoria

• Hydro - 583 .3 MW

• Bogong / McKay Expansion - 150 MW (construction)

• Somerton - 150 MW

• Loy Yang A - 689 MW (32.5% equity)


Annexure 2

Swier report - provided separately.

AGl Submission to IPART Issue s Paper 35

Managing CPRS transition: implications for electricity retail price regulation p1

June 2009

Managing CPRS transition: implications for electricity retail price regulation

Report for the Energy Retailers Association of Australia by Farrier

Swier Consultingi

Summary

It will take some time for the electricity industry to transition to a low carbon

future with an effective liquid carbon market. The transition period will be

characterised by:

volatility and uncertainty in wholesale electricity prices, in part because

of uncertainty in carbon prices, and

an increased risk of unexpected generator failure, with potential flow

on effects for retailers through failed hedging arrangements.

To maintain a financially viable and competitive retail sector, retail prices must

reflect costs. During the more volatile transition period, there must be flexibility

to adjust retail prices quickly. Such adjustments are at odds with current retail

price regulation.

Therefore, governments need to remove or change retail price regulation.

Introduction and overview

The federal government proposes to introduce the Carbon Pollution Reduction Scheme

(CPRS). The CPRS and other policies aim to bring about a transition to a low carbon

electricity industry in Australia (the transition). The changes required to physical,

commercial and risk management arrangements as the result of the CPRS are the most

profound since the creation of the modern electricity industry.

The federal government has stated that competition and consumer choice in retail energy

markets are the best ways to protect consumer from being overcharged for the costs

imposed by the CPRS.ii State governments are progressively reviewing the need for retail

Transitioning to a low carbon electricity industry requires profound changes to physical, commercial and risk management arrangements


June 2009

price cap regulationiii, however so far, only Victoria has removed retail price controls. The

Australian Energy Market Commission (AEMC) considers that regulation of retail energy

prices, in its current forms, may not be flexible enough to deal with potentially large and

volatile changes in retailer costs driven by the CPRS and the Extended Renewable Energy

Target scheme eRETiv.

The Energy Retailers Association of Australia (ERAA) asked Farrier Swier Consulting to

assess the difficulties and risks involved in retail electricity price regulation in the transition to

the CPRS and a low carbon electricity industry, noting that the analysis is most relevant to

NSW, Queensland and South Australia.

Our analysis highlights that the risk and uncertainty associated with the transitionv is due to

a combination of CPRS affecting inputs to electricity prices, and the trend to increased

internationalisation of Australia’s energy markets.

Over time, we would expect some of the initial CPRS uncertainties to reduce as government

climate change policies (hopefully) stabilise, and as forward carbon hedging financial

markets develop that enable parties to manage their carbon price related risks. However, it

is likely that some medium and longer term effects will continue to impact prices for some

time.

The transition will create problems for retail price regulation because of the inevitable higher

level of risk and uncertainty in wholesale electricity prices, and the relative immaturity of the

carbon market during that time. Immaturity means a lack of proven mechanisms to address

uncertainty.

Until recently, retail price regulation has been undertaken within an environment of relatively

certain and stable wholesale electricity prices; since 2007, the environment has become far

more volatile (refer figure 1).

AEMC has reservations that existing retail price regulatory arrangements may not cope

This paper explores the difficulties and risks with electricity retail price regulation and CPRS

Current retail price regulation evolved in a certain, stable wholesale electricity market environment


June 2009

Figure 1- Forward Electricity Prices

Source : ERAA

In contrast, in the transition to effective carbon pricing under the CPRS, regulators involved

in retail price regulation need to make decisions about single point electricity cost

allowances, faced with arguably unprecedented variability and no history. This is a problem

because the option of being conservative - adopting the extreme high of the range – is at

odds with the objective of retail price regulation, being to guard against incumbent electricity

retailers exercising market power.

The variability and uncertainty created in the transition will make it extremely difficult for

regulators to determine a wholesale cost allowance that is competitive, but still allows a

retail business to manage its risk. If the regulator makes an errorvi, retail competition could

be diminished, or worse still, a retailer could suffer financial distress, or fail.

CPRS may challenge the robustness of retailer risk management arrangements by

increasing the risk of unexpected defaults by emissions intensive generators. A retailer may

fail because unexpected generator failure undermines the retailer’s financial hedging

arrangements. Moreover, the retailer’s ability to access risk management tools, and the

associated costs, will fluctuate.

Constraining retailer revenue and flexibility through retail price regulation could limit the

rapid adjustment in prices needed to cope with an unexpected generator default.

Moving forward, CPRS introduces new risks and uncertainties for the wholesale electricity market

That in turn makes a price regulator’s job even harder, with flow on risks to retailers that could result in retailer failure

CPRS could increase the likelihood of unexpected generator failure – affecting hedging arrangements

If that occurs, the overlay of retail price regulation could increase the risk of a retailer failing

Flexibility is necessary to enable rapid price adjustments for sudden unexpected changes


June 2009

It will take some time for the electricity industry to transition to a low carbon future with an

effective liquid carbon market. To support an effective transition, governments need to

remove or change retail price regulation.

Background and assumptions

To assess possible impacts of, and interactions between, the transition and retail price

regulation, we have assumed:

CPRS will impact the NEM spot prices and hedging arrangements in similar ways to other uncertainties (for example, the recent drought), that is:

– Directly – through tangible factors. Tangible factors are the fundamental engineering and economic forces of supply and demand that are capable of measurement and estimation and can be incorporated in economic models.

– Indirectly - through intangible factors. Intangible factors include behaviours, risk preferences, beliefs and cultures that affect business judgments, particularly in the face of uncertainty. These factors cannot be readily captured in models and are difficult to assess in times of transition and new information.

No fundamental changes to the approach to retail price regulation, so that:

– The objective of retail price regulation is to guard against incumbent electricity retailers exercising market power and charging non competitive prices in the transition to a fully competitive market.

– The regulator needs to make ex ante decisions about the costs that are to be recovered through retail prices for the relevant period. These costs include wholesale electricity costs, network charges, the cost of serving and acquiring customers, and a retail margin.

– In setting the allowance for the forecast wholesale electricity cost, regulators generally consider models that estimate the long run marginal cost of electricity, forecast spot market outcomes, and the observed cost of forward contracts.

Effect of CPRS on the wholesale electricity market

Competitive electricity markets have been operating in South Eastern Australia for nearly 15

years. The National Electricity Market (NEM) commenced in 1998 and absorbed the state

markets established in the mid 1990’s. The NEM is widely considered amongst the most

successful competitive electricity markets in the world.

The NEM spot market is an energy only “gross pool” where prices are volatile and can be

set as high as $10,000/MWh. The spot market is supported by a financial contract market

To support an effective transition, governments need to remove or change retail price regulation

CPRS can be viewed as just another uncertainty in the market

Retail price regulation exists to protect customers from non competitive prices

CPRS changes the market in several material ways, including changes to:

merit order

fuel costs

investment, disinvestment, and investment confidence

reliability

short term bidding behaviour


June 2009

which retailers, generators and customers use to manage risks. If risk is not managed

appropriately, or risk management arrangements fail, spot market payments can very

quickly exceed a retailer’s financial capacity.

The proposed CPRS requires coal and gas fired electricity generators to acquit Australian

Emission Units (AEUs) annually against assessed carbon emissions. The supply of permits

will gradually be reduced causing their price to rise. Generators will acquire permits through

grants of free permits, a monthly auction, or secondary and derivative markets. The

Government has announced a fixed price for AEUs of $10 per tonne for the first year of the

CPRS from July 2011, but (assuming the scheme is implemented as planned) AEU prices in

subsequent years will be market determined subject to a cap price of $40 per tonne.

The CPRS will have tangible impacts on the investment in and operation of generation plant

in the NEM, the main ones being:

Changed merit order operation of existing generation plant - Coal and gas

fired generators will need to factor the cost of AEUs (or the value of free AEUs) into

their bidding in the spot electricity market, the determination of target generation

volumes and the pricing of hedge contracts. As the emissions intensity of different

generation technologies varies, this is expected to cause changes in the merit

order for generation.

Fuel costs - The CPRS is expected to impact significantly on the demand for gas

within Australia. Rising international energy demand and international climate

change policies are driving the potential export of gas from Eastern Australia. If

proposed LNG projects proceed, domestic gas prices are expected to rise towards

international levels.

Investment - The CPRS and extended RET scheme will change the economic

drivers for new generation plant towards low emission technologies and encourage

investment in cost effective actions to reduce emissions for existing plants. Gas

power station technology and wind turbines are considered the only currently

mature technology options capable of expansion on a large scale. Other

technologies (geothermal, wave power, solar, carbon capture and storage, etc)

may become competitive over time.


June 2009

Disinvestment - As AEU prices rise, and investment in new low emissions plant

increases, then this is expected to cause retirement of high emissions generation

plant.

Reliability - Reliability in the NEM will be affected by the changes in plant required

to move to a low carbon industry, specifically disinvestment in high emissions

generation plant, replacement with lower emissions plant; and the significant

increase in intermittent wind generation in some regions.

Also, during the transition, the wholesale electricity market will be affected by intangible

factors including:

Commercial judgments on short term bidding behaviour – As the pricing of

carbon emission starts affecting the merit order, each generator will need to make

commercial judgments on its bidding and contract strategies, including its

competitors’ behaviour and its own price / volume tradeoffs.

Investment confidence – The CPRS may affect willingness to make long term

investments in the face of significant uncertainty, and may affect the required return

on capital.

Counterparty credit risk – At different times, the CPRS combined with other

factors may affect the willingness to take counterparty credit risk when there is

uncertainty as to the counterparty’s financial stability.

CPRS transition and forecast wholesale electricity prices

In the initial stages of the NEM, the commercial behaviour of market participants was

uncertain, but over time the market has matured and these uncertainties have reduced.

In addition, until recently, the factors that determine expectations of the forward wholesale

price path - generator costs (including cost of new investment, fuel costs), generation and

transmission failure rates, and demand risk – have been reasonably well understood, and

able to be incorporated in models.

However, the drought and the global financial crisis have created uncertainties, as has

speculation about the timing and nature of the CPRS. Transitioning to a reduced carbon

future brings new uncertainties.

The NEM has moved from a relatively stable environment, to one of considerable uncertainty


June 2009

During the transition, any forecast of wholesale electricity prices – whether derived for

valuation, accounting, regulatory or business price setting, risk management or some other

purpose – needs to take account of new uncertainties and new impacts on existing factors.

CPRS introduces new uncertainties

Wholesale electricity cost forecasts are already being affected by uncertainties associated

with CPRS regulation, carbon pricing, CPRS-driven change in the merit order and electricity

pricing, and with gas pricing. Over time (arguably at least 5 to 10 years), these uncertainties

should diminish as CPRS policies stabilise and effective carbon hedging markets develop.

Currently, uncertainty caused by plant retirement related to CPRS probably is not affecting

forward wholesale electricity costs, but it is expected to become important in the medium

term.

Uncertainty on the policy parameters and timing for the CPRS is a typical regulatory risk.

Following the recent deferral of the CPRS and the announcement of a $10 per tonne price

for the first year, CPRS related electricity price uncertainty has been shifted out to the period

starting July 2012. Eventually, a liquid forward hedging market for AEUs should develop

enabling this regulatory risk to be managed at a low cost, but this will take time. In the

meantime, there is significant uncertainty as to the policy parameters for the final CPRS

legislation, when (and if) it will be passed by Parliament, and the details of supporting

regulations. These uncertainties already are having an intangible impact on forward

electricity prices. This is illustrated by the current lack of forward trading in electricity

contracts for 2010/11 and 2011/12 compared to good liquidity observed up until as recently

as March 2009.

Carbon pricing uncertainty - The need for electricity generators to forecast and manage

the price risk for AEUs – is also new. Electricity generators must allow for the cost (or value)

of carbon permits in determining their spot price bidding and their target generation volumes.

The CPRS has been designed to link with international carbon marketsvii. Most analysts

expect that, in part, compliance obligations will be met through importation of eligible

international permits. Australia will be a small part of the international carbon trading market

and so the price of AEUs will be set by international carbon prices, which in turn are affected

by international policy decisions. Policy making processes in each country are highly

political and therefore complex to understand and inherently uncertain.

New uncertainties include those associated with CPRS regulatory risk, carbon pricing, generation merit order, gas pricing, and plant retirement


June 2009

So far European carbon permit prices (figure 2) and implied Australian permit prices (figure

3) have been volatile. If the United States moves towards implementing a cap and trade

system as proposed by the Obama administration, then AEU pricing is likely to be strongly

affected by US policy decisions.

Once liquid forward hedging markets for carbon develop, then international policy risks can

be hedged by participants (generators and retailers) - but these international markets will

also take to time to develop and could lag behind Australia’s carbon markets. Alternatively,

AEU price risk may be decreased by the government effecting policy changes to provide

greater certainty during the transition period for example by introducing carbon prices collars

(minimum price limits) and / or lower price caps.

Figure 2 – European EUA experience

Source Point Carbon http://www.pointcarbon.com/news/historicprices/

Supply and demand in the European carbon market operate within constraints set by governments which creates a level of political risk not present in traditional markets. The primary source of political risk is the setting of emissions caps (the supply of EUAs) in relation to actual emissions. For example, setting emissions caps too high creates an oversupply of EUA s and will result in a very low carbon price. This prevents the scheme from working effectively, as the carbon price needs to be sufficiently high to encourage companies to reduce carbon dioxide emissions internally and encourage investment in alternate energy sources.

To date, the European carbon market has experienced two distinct supply disruptions. The first occurred with the release of 2005 emissions data in April/May 2006. The market for allowances was long by 44 MtCO2 in 2005, implying that emissions caps for Phase I were too high (i.e. an oversupply of EUA s). The second supply disruption occurred at the end of Phase I, as the European Commission had previously decided that Phase I EUA s were not fungible with Phase II EUA s. This created discontinuity in the supply of EUA s between phases.

Source: The effects of EUA supply disruptions on market quality in the European carbon market. Professor Alex Frino, Jennifer Kruk and Dr. Andrew Lepone University of Sydney, Australia


June 2009

Figure 3 – Australian implied carbon permit prices

Also, the CPRS will affect the merit order for generation, which in turn will flow through to

spot and forward electricity prices, with different pricing patterns likely to emerge.

While in general terms, the prices bid by an emissions-intensive generators will need to rise,

generators will not mechanistically add the carbon price to their previous bid prices.

Each generator will assess the behaviours of its competitors, make commercial decisions on

the most profitable trade-off between price and generation volumes, and consider impacts

such as maintenance practices and fuel pricing. It is difficult to forecast the exact

implications of carbon pricing for the change in the merit order, as shown by the wide range

of modelled outcomes for loss of volume of coal fired power (see figure 4).

Source: D-Cypha


June 2009

Figure 4 - Wide variation in volume lost by Coal fired Power Stations

Consistent with economic theoryviii, the price and volume adjustment in response to the

CPRS will involve a continuous process of actions and competitive responses, and

consequential changes in price and volumes sought by each generator.

This process occurred in the early stages of competitive electricity markets in the mid to late

1990’s where there was strong competition for volumes amongst generators within an

environment of excess capacity. As excess capacity was reduced and the market matured,

a relatively stable merit order and pricing structure was established.

However, if carbon prices (and therefore the amounts to be recovered through wholesale

prices) are volatile, then a stable equilibrium position will not be reached.

The CPRS is expected to result in a step change in gas utilisation for power generation

and uncertainty in gas pricing. Government bodies and analysts expect that gas power

generation in the NEM will expand significantly given its lower emission intensity than coal,

and the fact that, together with wind, gas is currently one of two mature technologies

capable of expansion on a large scale. Gas pricing and availability are therefore expected

to be important determinants of wholesale electricity prices.

Historically, gas pricing in Southern and Eastern Australia has been stable (due to long term

contracts) and gas prices have been low by international standards.

However, internationally, demand for gas is expected to expand significantly, as many

countries implement policies to shift to lower emission technologies. LNG export proposals

in Queensland are based on meeting this demand; these projects would strengthen the link

between domestic gas prices and international energy pricesix. However there is no

The following table from the government White Paper outlines the number of coal-fired generators that lose more than 25 per cent of their cumulative generation volume over the first decade of the Scheme when compared to modelled business-as-usual generation.

Modelled Loss of generation volume Scenario McLennan Magasanik

Associates ACIL Tasman Roam Consulting

CPRS – 5 Three brown coal generators Six black coal generators

One brown coal generator Two black coal generators

One brown coal generator Three black coal generators

CPRS – 15

Four brown coal generators Six black coal generators

Three brown coal generator Five black coal generators

Two brown coal generator Three black coal generators

Source Table 13.1, White Paper. Estimates based on modelling commissioned from MMA, ACIL Tasman and Roam Consulting


June 2009

certainty if, or on what time-frames, these proposals will proceed; and if they do proceed,

how the projects will affect domestic gas prices.

The CPRS and expanded RET scheme are also creating new peak electricity pricing

risks. Traditionally NEM reliability requirements have been determined by the reliability of

thermal plant, transmission and demand peaks. The effect of intermittent generation (wind)

on generation reserves is already affecting South Australia, and over time is likely to impact

on other regions. The AEMC is proposing to expand options for NEMMCO to contract for

reserve to manage this issue.

An important new medium term factor is uncertainty over plant retirement. The CPRS is

anticipated to trigger plant retirements for high emission brown coal plants and possibly

black coal generators, as carbon prices rise. (See figure 5.)

However, the timing and extent of plant retirement is highly uncertain. The following table

indicates the range of possible outcomes for generators that may exit the market. Plant

retirements for those generators with a significant share of the market in a region such as

Victoria could have a significant, though temporary, impact on prices in the period leading up

to and during the retirement process.

Figure 5 – Plant retirement assumptions

Generators that will exit the market (other than exit under business as usual)

Consultant

None in period to 2020 Roam

One generator MMA

Two brown coal generators and one black coal generator will retire in their entirety (CPRS -5 scenario)

ACIL Tasman

Three brown coal and four black coal generators to retire in their entirety (CPRS -15 scenario).

ACIL Tasman

Source: Page 13-17 White Paper

Ideally, plants would retire on a phased basis, and coincide with new lower emissions plant

coming on line, so that prices would adjust relatively smoothly. Conditions imposed for

assistance to coal generators under the CPRS are designed to encourage a smooth

transitionx. It is possible that a coal-fired station that wants to retire (but does not want to

lose its remaining compensation payments due to lack of reserve margin) could effectively

be mothballed, but remain registered as a backup unit. Arguably, large retailers will have an


June 2009

interest in working closely through their contracting processes with various generators to

ensure a coordinated transition.

However, if for whatever reason the timing of plant retirements and new plant start up is not

managed smoothly, then short term changes to the demand supply balance could cause

significant price volatility. Factors that could lead to price volatility include:

lower reliability due to running down of maintenance and capital expenditure towards the end of the plant life

change in ownership (including operation by bankers or administrators) of a plant that is about to be retired

commissioning problems and delays in new plant start-ups.

To date there has been little experience in the NEM with significant plant retirements, and

therefore there is limited information to assess the impacts on prices. The MCE recently

suggested increasing VoLL to increase incentives for reliability in the transition to CPRS and

a low carbon electricity industry in Australia. Increasing VoLL should increase incentives for

participants to contract against the risks of high prices and promote reliability, but it would

increase volatility in spot prices. In addition, increasing VoLL increases the impact if

financial risk management arrangements fail.

Another medium term factor is transmission congestion. The capacity of the existing

transmission system was designed to accommodate power flows reflecting the operating

regime for the current portfolio of generators. Decisions on operating existing generation

plant and building new generation plant in response to the CPRS and expanded RET

scheme are expected to cause changes in power flows, and may cause transmission

congestion problems resulting in higher peak electricity prices in regions behind constraints.

The AEMC is considering possible rule changes to encourage more efficient provision and

utilisation of the transmission network.

CPRS affects existing inputs to wholesale electricity price forecasts

Capital cost assumptions for new generation plant are an important input to all wholesale

electricity price forecasting models. Recent factors that have affected capital costs and

price forecasts include increased prices for inputs (steel and labour), full order books for

manufacturers of key equipment and plant, and exchange rate changes. Though present in

the past, in recent years these factors have been subject to quicker and larger changes, with

consequent effects on price forecasts.

International and domestic climate policies affect capital costs for generation plant


June 2009

Climate change polices followed by other governments internationally (and to a lesser

extent, the CPRS) could have a significant impact on the costs for generation equipment.

For example, aggressive policies internationally to increase renewable energy investment

could lead to shortages and higher equipment prices for wind and gas turbines. The timing

and nature of such government policies, and their impact on renewable energy costs, are a

source of uncertainty.

CPRS affects the risk of generator default and hedging arrangements failing

A number of generators have stated that the compensation offered by the government under

the Electricity Sector Adjustment Scheme is inadequate and increases the risk of default

once the scheme expires.

Where the generator’s financial position is signalled well in advance, retailers can manage

the risk of their generator counterparties defaulting on hedging arrangements. . However,

coal fired generators could unexpectedly default on their hedging arrangements due to any

or all of:

impairment losses (for example, triggered by CPRS legislation or changes in

regulations) which precipitate breaches of loan covenants and failure to secure

debt or equity refinancing

a sudden unexpected increase in carbon prices before liquid carbon hedging

markets have developed

the combination of a CPRS driven merit order change combined with some other

unexpected shock(s) (for example plant breakdown, strikes, drought, unavailability

of debt finance, etc).

If a generator defaults on hedging arrangements, in the absence of alternative risk

management arrangements, a retailer’s wholesale costs could increase rapidly and its

profits could be impacted materially, possibly to the extent of financial failure. Failure is

more likely if the retailer is unable to adjust retail prices quickly to reflect the change in costs.

This scenario could apply to a major generator and major retailers, in which case there is

potential for “knock on” retailer failures. Major retailer failures would test the adequacy of

Coal fired generators could default unexpectedly on their hedging arrangements

A retailer’s wholesale costs could increase rapidly, materially affecting its profits, and potentially causing financial failure

If this scenario applied to a major generator and major retailers, there could be “knock on” retailer failures

Major retailer failures would test the adequacy of ROLR arrangements


June 2009

Retailer of Last Resort (ROLR) arrangements, which were designed in contemplation of less

significant failures.

Even if the risk of unexpected defaults is considered low -- the impact of default could be

severe – as evidenced by the Californian electricity crisis of 2000 and 2001xi.

Evidence of the CPRS uncertainty on wholesale prices forecasts

While not all uncertainties discussed above currently affect NEM spot and contract prices,

recent pricing trends suggest that CPRS policy uncertainty has had a significant effect.

Figure 6 shows responses to the White paper, and the 4 May announcement delaying the

CPRS.

Figure 6 –Changes in NEM prices in vicinity of ETS announcements

Source: AGL Energy Ltd

Figure 7 shows that volatility in base electricity contracts (for calendar year 2010) has been

as high as 30 to 35% (annualised, 20 day rolling average) with volatility peaking in early

2008 and again in late 2008 / early 2009.

This illustrates the difficulty for regulators attempting to rely on forward market prices to

make decisions at a time when prices are at either a low or high point in the cycle.

CPRS uncertainty has been a major factor in recent pricing trends


June 2009

Figure 7 - Volatility in base electricity contracts (Victoria)

Source : ERAA,; D-Cyphaxii

Finally, studies of the impact of the CPRS on wholesale electricity prices (figure 8) show the

wide range of assessments on the extent to which the carbon cost will be passed through.

The differing assessments reflect different assumptions about the market dynamics of

bidding behaviours and trade-offs made by generators. These studies focus on determining

the marginal generators and the bid costs that set spot electricity prices in each period. For

example with a high enough carbon price, gas fired CCGT plants will set base load power

prices more of the time, displacing black coal generators that set these prices.

In a recent study, Frontier Economicsxiii adopted three scenarios for CPRS pass through

rates: 60%; 80% and 100%. They estimated an impact on total retailer costs (and therefore

prices) of between 10 to 30% depending on the pass through rate scenario, the carbon price

and the retailer cost base. Frontier note that this level and range of cost increases is

material compared to average retailer margins of around 5%.

Volatility in base electricity contracts has been as high as 30 to 35% indicating the difficulties for regulators attempting to rely on forward market prices

Published studies indicate a wide range of views on the extent carbon costs will be passed through


June 2009

Figure 8 –Range of outcomes in studies of carbon pass through

Estimates are approximate only since many reports do not include an explicit estimate of cost pass-through.

Source: Impacts of climate change policies on electricity retailers,

Frontier Economics report prepared for the AEMC, May 2009

Implications for retail price regulation

The higher level of risk and uncertainty about wholesale electricity prices that will inevitably

accompany the transition and the associated increased risk of generator –retailer hedging

arrangements failing will create problems for retail price regulation.

Firstly, all approaches to retail price regulation in Australia require the regulator to make ex

ante estimates of the costs to be recovered through retail prices for a relevant period. While

CPRS influences all input costs, this paper is concerned with the wholesale electricity cost

component.

The variability and uncertainty created in the CPRS transition will make it extremely difficult

for regulators to determine a wholesale cost allowance that is deemed “competitive”, but still

allows a retail business to manage its risk (including carbon risk) for the duration of the

regulatory period. This is particularly problematic because the option of erring on a high

allowance and adopting the extreme high of any forecast range, is at odds with the objective

of retail price regulation, being to guard against incumbent electricity retailers exercising

market power and setting non competitive retail prices.

Current retail price regulation involves an ex ante decision about wholesale electricity costs

Until recently, decisions have been made in a relatively certain, stable wholesale electricity market environment

CPRS changes that environment, and therefore makes the regulator’s job harder

It also increases the chances of regulatory error, with flow on risks to retailers – and potentially retailer failure

Customer protection will depend on the efficacy of ROLR


June 2009

If a regulator errs and sets the cost allowance too low, then the regulated retail prices will

make some customers less profitable, or loss making. These customers are less likely to

receive competitive offers and, therefore, are more likely to remain on regulated tariffs. The

main adverse impacts of the error will be on retail competition and on the profits of those

retailers with obligations to offer regulated prices.

If the regulator makes a serious error, or the retailer’s costs or access to risk management

products change quickly, then some retailers (that are marginally profitable or not managing

their risk effectively) could suffer financial distress or fail. This situation is allocatively

inefficient and disrupts the effective operation of the market, which would otherwise deal

with changes in costs through price changes. However, the regulatory framework

contemplates such events (albeit not necessarily at a significant scale) through Retailer of

Last Resort arrangements.

Secondly, a new and potentially more concerning problem, is the possible effect of the

CPRS on the robustness and availability of risk management arrangements which could

result in significant retailer failure, particularly if retailers are unable to adjust prices quickly..

When policy makers and regulators set retail prices, they assume that retailers act prudently

and that their risk management arrangements will operate effectively throughout the period.

However, as discussed a retailer’s risk management arrangements could fail during a

regulatory period due to an unexpected generator default. This is particularly the case in the

absence of a liquid forward carbon hedging market, and while CPRS uncertainty restricts the

supply of long term hedge contracts.

Even if the risk of unexpected defaults is considered low, the impact of default could be

severe, as evidenced by the Californian electricity crisis of 2000 and 2001xiv.

CPRS could increase the likelihood of generator failure – perhaps because of unexpected changes in carbon prices, or CPRS driven merit order change

Generator failure affects retailer hedging arrangements

If hedging arrangements fail, affected retailers could also fail

That likelihood increases if a retailer cannot adjust its prices quickly because of regulated price constraints


June 2009

Observations relevant to policy makers

Increased volatility in wholesale electricity pricing is a natural market response; it is a

logical consequence of the underlying uncertainties accompanying the transition to a stable,

predictable CPRS and a low carbon electricity industry, and in the absence of liquid forward

carbon hedging markets. Over time, any short term volatility should self correct.

However, the commonly accepted approaches to and concepts of retail price regulation

were developed in a relatively stable wholesale electricity pricing environment, with low

probability of significant business default. These approaches are likely to be too inflexible

and slow to deal with the scale and pace of uncertainty during the transition.

i While this paper draws on information provided by the ERAA and its members, it represents our own views.

ii Australian Government, Carbon Pollution Reduction Scheme: Australia's Low Pollution Future ‐ White Paper,

15 December 2008 (the White Paper)

iii Clause 14.11 Australian Energy Markets Agreement

iv Review of Energy Markets Frameworks in light of climate change policies, Australian Energy Market

Commission, Discussion Paper, 1 May 2009

v This paper does not focus on longer term uncertainties associated with CPRS and climate change policies more

generally.

vi If prices were set too high, then to the extent there is effective retail competition, such competition should

erode any excess returns. The risks to competition and the financial viability of retailers arise if prices are set too

low.

vii The White Paper states that eligible Kyoto units can be used for compliance in the scheme without quantitative

limits.

viii Economic theory suggests electricity markets operate to seek out a competitive equilibrium where no

participant can make itself better off by changing its bids.

ix If Queensland CSG producers could achieve high netback prices by directing production into LNG manufacture,

they are less likely to discount prices to attract local customers, either locally or in southern states. Fuel and

Capital Costs in the NEM, Greenfield cost data for the calculation of the 2009/10 BRCI, Report by ACIL Tasman for

the Queensland Competition Authority (October 2008)

x Under the arrangements, recipient generators must remain registered with NEMMCO (and follow NEMMCO

market directions) at the same actual or planned capacity as at 3 June 2007, unless there is adequate reserve

plant margin to allow a reduction in capacity without breaching reliability standards.

xi The Californian electricity crisis resulted from factors including price controls set so that public utility

companies were paying more for electricity than they were allowed to charge customers, thus forcing the

bankruptcy of Pacific Gas and Electric and the public bailout of Southern California Edison. These failures in turn

Volatility in the wholesale electricity market will self correct over time – the market will work

However, current retail price regulation is premised on stability, rather than volatility

There will be uncertainty during the transition to CPRS – and until a liquid forward carbon hedging market develops

Generators and retailers will be exposed to a carbon price risk that is difficult to manage

Current regulatory approaches will not cope with these uncertainties


June 2009

led to energy shortages and blackouts.

xii Volatility calculated on 20 day rolling average

xiii See Table 3, Impacts of climate change policies on electricity retailers, Frontier Economics report prepared for

the AEMC, May 2009

xiv The Californian electricity crisis resulted from factors including price controls set so that public utility

companies were paying more for electricity than they were allowed to charge customers, thus forcing the

bankruptcy of Pacific Gas and Electric and the public bailout of Southern California Edison. These failures in turn

led to energy shortages and blackouts.

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