National Energy Guaranteecoagenergycouncil.gov.au/sites/prod.energycouncil... · Next Business Energy Next Business Energy is a privately-owned electricity company operating in Queensland,

National Energy GuaranteeS U B M I SS I O N

PREPARED BY

ERM POWER, LPE, WIN CONNECT, BLUE NRG, 1ST ENERGY, ENERGY LOCALS, NEXT BUSINESS ENERGY, COVAU , CLICK ENERGY, GLOBIRD

8 MARCH 2018

Contents1. Introduction - 32. Executive Summary - 73. Market Facts - 144. Consultation Q&As - 205. NEG Proposals, Implications and

Recommendations for Detailed Design - 316. Appendix A: model proposal – measures of success - 43

Introduction1.

National Energy Guarantee SUBMISSION 4

1. Introduction

Purpose This submission supports the detailed design of the National Energy Guarantee (NEG). It provides insights and recommendations from a range of key industry participants including commercial and industrial energy users and energy retailers representing residential, business, commercial and industrial customers and more than 19TWh of electricity retailed in the market.

The co-signatories to this paper share the interests of many community, government and industry stakeholders in seeking enduring national energy policy, investment certainty for energy investors and investment certainty for the businesses which create jobs and underpin our economy.

The National Energy Guarantee (NEG) is the government’s preferred vehicle and policy to provide certainty for the energy industry and consumers. However, the well-considered and researched Finkel Report recommendations should not be lost. The NEG conception was developed quickly and requires detailed design to address obvious market disruption, competition and cost hurdles. It can be a workable solution if consultation is genuine and recommendations such as those outlined in this paper are addressed.

Who we are

ERM Power is an Australian energy company operating electricity sales, generation and energy solutions businesses. The Company is the second largest electricity provider to commercial and industrials (C&I) in Australia and third largest retailer in the market. ERM Power brought competition to the C&I market based on price and service. ERM Power also sells electricity in several markets in the United States. The Company operates 662 megawatts of low emission, gas-fired peaking power stations in Western Australia and Queensland. www.ermpower.com.au

Energy Locals was launched in January 2017 to challenge the traditional residential energy retail model, where customers are too often being let down by confusing tactics. The company retains a fixed fee for its service, meaning it doesn’t profit from customer usage, and it supports a wide range of Aussie charities and communities. Energy Locals proudly offers low, simple pricing and a high solar feed in tariff. It’s also partnered with technology-led disruptors to help them enter the market by bundling battery and peer-to-peer technology with grid power.


1. Introduction

Blue NRG is a 100% Australian owned energy retailer helping small to medium sized businesses (SMEs) minimise their energy bills.

The head office is in Mont Albert, Victoria. The company was established in May 2012 and has been operating in:

— Victoria since May 2012

— New South Wales and South Australia since February 2014

The Company has licences to retail electricity across most Australian states (all except WA & NT, which are not connected to the national market).

1st Energy Pty Ltd is a privately-owned electricity retailer currently supplying over 20,000 residential and small business customers across Victoria, New South Wales and Queensland. 1st Energy provides consumers with an alternative to the big 3 residential retailers, with competitive offers and personalised Australian-based service.

CovaU is a fast growing Australian energy retailer focused on delivering competitive energy cost to the small business and residential market segments. We are a thriving company looking to bring excellent value and innovative solutions to our energy customers. Having launched in 2014, we have an increasing footprint and scale in New South Wales and Victoria, providing electricity, gas and dual fuel solutions.

CovaU also has a sister company iGENO, which provides embedded electricity and gas network solutions designed to engage, operate, manage, service and support multi-tenant customers and large strata developments.

We pride ourselves in delivering superior customer service. With our own direct sales team, in-house business operations and 24/7 multi-lingual customer support centres, our customers can be assured of great service and support by CovaU in handling and resolving all their requirements expediently when they need it most. www.covau.com.au

LPE LPE was founded in 2012 with the goal of supporting strata and high density communities by saving the most amount of money for the most amount of people. Being dedicated to supporting people living and working in the strata communities through full-service market offers to residential occupants, common areas as well as through embedded networks. LPE set out to provide legitimacy and clarity to the overcrowded and often abused strata community space by taking financial and legal responsibilities away from Owners Corporations and Body Corporates.


Win Connect WINconnect is Australia’s largest and most trusted embedded network service provider, built on over a decade-long legacy. Committed to delivering excellence in all aspects of the Australian based company, WINconnect is a full service organisation with internal expertise in engineering, call centre management, customer service, regulatory compliance and information technology.

WINconnect hold electricity retailer authorisations in Vic, SA, NSW, Qld and an Australian Financial Services License and are members of the respective ombudsman schemes.

WINconnect’s best of breed approach to servicing the requirements of multi-tenanted premises (residential, commercial and industrial) sees the deliverance of electricity, centralised hot water, superior internet and renewable energy capabilities in solar and battery storage systems.

As WINconnect is the market leader in the creation and ongoing management of Embedded Networks in Australia, the company is regularly involved in highlighting the need for regulatory changes and reviews to protect customers and facilitate compliance within the sector. www.winconnect.com.au

Next Business Energy Next Business Energy is a privately-owned electricity company operating in Queensland, Victoria, South Australia, New South Wales and the Australian. Founded in 2014, it specialises in providing electricity services to small – medium businesses.

Click Click Energy is Australia’s largest independent energy retailer. Established in 2006, the company was the first energy retailer to operate completely online and is dedicated to delivering simple, great value energy with a strong customer-service focus. Click Energy received the Canstar Blue award for Value for Money 2015 & 2016 (QLD), Canstar Blue Award Most Satisfied Customer 2015 (QLD) and Canstar Blue Award for Most Satisfied Customers (Solar Providers National) and remains consistently one of the top rated energy retailers on productreview.com.au.

Globird Established in 2014, GloBird Energy is an award winning electricity retailer offering Victorian energy users more choice and better value. GloBird serve its growing customer base from its Melbourne call centre.

The company works harder and smarter to keep energy bills under control and provide generous feed-in tariff for solar customers.

Executive Summary

2.


2. Executive Summary

The problem to solve The problem policymakers are working to solve is the imbalance between electricity supply and demand, particularly diminishing reliable (firm or dispatchable) power over the next five years due to displacement of large dispatchable carbon-intensive power plants. This, and poor policy and planning, have led to market concentration in firm generation and price increases, exacerbated by gas availability and cost. The lack of visibility of renewables development (size, location and system impact) has also exacerbated investment uncertainty and lack of willingness to invest in firm, clean generation. The necessary and inevitable transition to renewables is enormously challenging.

The simplest answer is to build clean, dispatchable generation to support the transition, however, the construction timeframe can be three or more years and the investment cost relative to the asset life in a rapidly changing market makes such a long-term and large investment unattractive due to considerable economic risk. Policy to date has not created the environment to support the necessary investment. The NEG must be a policy designed to guarantee investment.

NEG Considerations

INVESTMENT WITHOUT EXACERBATING MARKET CONCENTRATION, COMPETITION AND COST ISSUES Wholesale and retail price transparency should be supported under the NEG in the interests of consumer choice and competition.

Wholesale price transparency exists today allowing the market to price today’s standardised products off an underlying reference point. A move to tailored, bundled, more complex products (energy, reliability and emissions) will lead to a reduction in energy price transparency, reduced liquidity, and higher prices for end-use customers. Spot price today is a key reference for the price of future-dated wholesale electricity contracts i.e. it drives customer price. Under the NEG proposal where a number of price inputs would exist (i.e opacity of bundled spot, reliability, emissions etc), spot prices would no longer be an analogue for the underlying price charged to customers which would pose a significant issue for the market, customers and investors.

Retail price transparency exists for Commercial and Industrial (C&I) consumers who constitute more than 60% of the electricity market in Australia. All aspects of C&I differ greatly to that of the residential electricity market. C&I customers can price compare easily between retailers and their bills are broken down so that network and wholesale power costs are clear. For business energy consumers, the growing wholesale component of price in recent years would have been exacerbated if it weren’t for modest C&I retail gross margins, flexible C&I retail contracting and C&I retail product innovation such as progressive

This paper proposes a detailed design solution for the NEG which delivers on the objectives by supporting development of the right resources in the right locations in a timely manner for the least cost with minimal disruption to the market. This solution proposed leverages mechanisms that are working effectively in other jurisdictions around the world and in Western Australia.


power purchasing. This will be lost if new energy policy entrenches the power of generators and vertically integrated players and reduces price transparency. It should be noted that the substantial additional risk proposed for retailers to manage could not be absorbed in the current C&I margin i.e. the NEG proposal requires retailers to over-contract to meet obligations so, for example, a $10 increase in costs cannot be absorbed in a $5/MWh C&I retail gross margin.


Efforts should be made to remember and address the root cause issues which are:

- investment in firm electricity supply;

- cost of electricity due to concentration of ownership of dispatchable generation; and

- planning and transparency of new energy infrastructure.

Enhance not undermine liquidity in electricity contracts market The market today relies heavily on financial contracts, not physically backed power contracts. A deep and liquid tradeable wholesale market must be preserved and enhanced under any policy change; this is crucial to retail competition and supply. Diminishing that market will threaten overall market price, service, and technology innovation by entrenching vertically integrated oligopolies and resulting in low levels of competition.

We understand the ESB believes the NEG will enhance liquidity but it is far from clear that this will be the outcome and there are enormous risks in making this assumption.


Summary of recommendations Detail in sections 5 and 6

1. COMPETITION Protect and enhance competition through an enhanced market transparency and competition approach. This would take the form of a Procurement of Last Resort approach; a safety net to ensure investment only if the market does not respond to the clear forecast demand or gap. Our Procurement of Last Resort approach differs to that proposed in the NEG consultation paper as it replaces obligations on the retailer and is less market disruptive and costly, while still ensuring investment based on reliability and emission targets. See infographic page 13. Our proposal:

— will not exacerbate generator/gentailer market power issues by tilting the balance of power further in their favour;

— will not put all the risk on retailers who have no control over generation, dispatch and reliability;

— will not increase cost through economic withholding; and

— will not push out smaller retailers who build competitive tension and bring innovation to retailing.

2. RETAILER OBLIGATIONS Put in place an enhanced market transparency and competition model which includes centralised procurement of last resort (a safety net to ensure appropriate resources are built in appropriate locations):

— A government or COAG-appointed body identifies and communicates reliability resource requirements and emissions intensity (technology agnostic) for each jurisdiction, including timeframes they are required by.

— AEMO communicates the requirements to the market.

— Only if the market doesn’t underwrite (build) the necessary resources, centralised procurement of last resort is triggered.

— If triggered, AEMO requests formal proposals and awards contracts for lowest-cost solutions under centralised procurement of last resort.

— Checks and balances ensure that central procurement is a last resort mechanism, not a default, and this could take the form of ESB/AEMC/COAG approval of AEMO energy procurement to guard against conservatism (over-supply) and high-cost generation or gold plating of infrastructure.

— All other market mechanisms remain unchanged. That is, retailers continue to manage the financial risk on behalf of customers but are not confined to physical bilateral contracts with generators and are not required to build; instead this would be incentivised under the model proposed in this paper. Retailers would not have the perverse obligation to guarantee the reliability of a third party’s physical assets. This would therefore minimise market competition disruption, competition issues and the cost and time that accompanies major market change.

— As in WA and other jurisdictions, the very existence of centralised procurement of last resort motivates the market to solve the problem before the central body intervenes and a competitor or new entrant takes control of new build.

— Our proposed model, unlike a centralised capacity market, only proposes intervention for any gap and only in the unlikely event the market has not responded.



3. TRANSPARENCY Enhance contract transparency not detract from it. Enforcing bilateral physical contracts between retailers and generators risks the liquidity of the market and would subsequently increase prices given the tailored nature of the product. Further, transparency of future dated electricity contract prices (as readily observed on the ASX) would diminish, firstly because there would no longer be a strong need for generators and retailers to contract through a visible market platform and secondly because a raft of tailored products do not lend themselves to being traded through a market platform. Such an environment would reduce or remove the participation of market intermediaries (such as banks and insurers) who bring innovation, contract liquidity, price discovery and price efficiency that ultimately benefits end-use customers. A well designed NEG should lead to greater transparency in pricing across the industry, not a reduction as is likely under a bilateral physical contracting arrangement, as is currently proposed.

4. BUYING BEHAVIOUR C&I customers contract differently to residential consumers and their buying behaviour is not aligned to an approach in which retailers bear reliability obligations. Often C&I customers will not commit to a retailer until days or weeks before the contract period commences. There is a real risk that under the proposed NEG, C&I customers will be left stranded without a contract as retailers will be unable to rebalance their resources at short notice and will be unwilling to risk breaching reliability requirements. Physical, bilateral contracts can take many months to negotiate and often do not result in an outcome. Put simply, it will be more attractive for retailers to sell limited resources for higher margins than to take disproportionate investment risks on new build in order to secure long-term

supply. This is precisely what occurred in the gas markets (participants exiting and customers stranded) which needs to be actively avoided under the NEG.

The consultation paper suggests placing obligations on the customer. Careful consideration should be given to the diverse range of C&I customers and the impact of onerous obligations. If the NEG were to proceed down this path, the obligations must be generic and fungible and able to be aggregated and scaled for investment.

The serious implications above and detailed later in this document would be resolved under an enhanced market transparency and competition model with centralised procurement of last resort.

5. INVESTMENT Reliability obligations and emissions targets must be set using clear and transparent rules with a multi-year pathway in order to allow for businesses to plan and invest. Investors are seeking a reasonable return for what are large and long-term investments which require enduring policy. The risk of obligations changing over shorter periods of time relative to achievement of investment returns, will add significant costs and risk to the industry as a whole. Arguably new resource developments will be unbankable under such a policy. Further, the lack of transparency surrounding competing investments does not incentivise build.

An enhanced market transparency and competition approach in which reliability and emissions targets are coordinated and communicated would promote the best mix of plant in the optimal location. Policy must guard against outcomes such as that seen in South Australia where a concentration of the same generation resource (wind power) has resulted in AEMO frequently constraining off wind generation well below its aggregated capacity in order to maintain system stability.



6. COST A transparency and competition model with centralised infrastructure procurement of last resort (safety net only) is the recommended solution to align reliability and emissions obligations (energy resource build) with cost-effective and well-placed investment. This would ensure the benefits that liquid markets bring to price transparency and hedging efficiency remain. It would avoid the risks and costs associated with change in law complexities to existing retail and wholesale electricity contract arrangements.

The model proposed in this paper firstly allows the market to solve the problem economically without intervention, which is highly likely when the alternative is a mandated process which will result in new infrastructure anyway i.e. develop or have AEMO intervention and a competitor or new entrant do it. Current generator market concentration and lack of guiding policy has stopped key infrastructure investment - current participants won’t build as their existing assets will benefit from higher prices in a tightly supplied market but the policy push recommended in this paper breaks that nexus.

Addressing the above still leaves the risk that appropriate investments are not made. C&I retail customer contract tenors of 1-3 years leave considerable residual risk for an asset investment requiring a return over 20+ years. Residential retailing poses a similar issue. The model proposed in the paper provides a backstop investment guarantee in the unlikely event that the market has been unable to independently make the necessary investments.

If the obligation remains with the retailer and the major market changes proposed under the NEG do proceed in whole, significant industry structural changes would need to be mandated to underpin competition. Competition law will have to be significantly bolstered to provide the ACCC with greater power to act.


7. REGULATION AND COMPLIANCE An enhanced market transparency and competition model allows the underlying positive intent of the NEG to be met without adding complexity, cost and a host of unintended and undesirable outcomes, e.g. investigation of tens of thousands of electricity contracts annually.


Transition to renewables is challenging but essential.

Exit of baseload generation and growing intermittent generation has posed reliability issues and driven up cost. Market concentration and lack of enduring energy policy has stifled

investment in infrastructure that supports the transition

Enduring national energy policy that delivers the right infrastructure in the right place

SET TARGETS NATIONALLY: RELIABILITY

AND EMISSIONS

NETWORK PLANNING SUPPLY/DEMAND FORECASTING

ENERGY ASSET CLOSURES AND PLANNED NEW BUILD PUBLISHED

Statement of opportunity

Energy need or problem identified at location level. Oversight guards against gold-plating and unnecessary cost

Market responds and builds to solve the locational issues

SAFETY NET

If the market does not respond:Centralised procurement of last resort is enacted

THE

PRO

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MTH

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THE

SO

LUTI

ON

SUSTAINABILITYAFFORDABILITY

RELIABILITY

+

+ +

MARKET CONCENTRATION

National Energy Guarantee

{ {PROPOSED DETAILED DESIGN

Market Facts 3.


3. Market Facts

Electricity retailing is insurance and risk management

— Electricity retailers do not necessarily produce and deliver electricity. Retailers provide customers with fixed price, variable volume insurance and then they hedge to on-manage the price risk which shields energy consumers from the price volatility of electricity. The price in any five-minute period ranges from negative $1000 per MWh to $14,200 per MWh and consumers want a locked-in price rather than be exposed to such volatility on a daily basis. Retailers bear the price risk and load variability, and hedge to on-manage these risks. Given customer usage variability it’s common for retailers not to be perfectly hedged i.e. to be long or short in any half hour. Price volatility exists because electricity has to be used when produced; cannot currently be stored at scale economically; and it would be inefficient and unfeasible for cheap energy to be able available on standby at all times.

— Generators set the price every five minutes and retailers help customers manage the price risk and volatility. For a long period Australia’s electricity prices were low relative to other countries. The rapid onset of intermittent generation in concentrated areas and the closure of firm generation without adequate policy and planning has resulted in Australia’s wholesale prices more than doubling over the past decade, exacerbated by gas availability and price.

Electricity contracts are financial

— Electricity hedge contracts are not for energy to be delivered. They are financial contracts used to manage price risk. These contracts involve transactions between parties such as generators, retailers, large customers, insurers, banks, and market intermediaries. The electricity market relies on these contracts for risk management and price discovery purposes. To imply that all contracts can be traced back to physical generation is wrong and undermines the workings of the entire market, a disruption which would have dire consequences for the price consumers ultimately pay for electricity.


3. Market Facts

C&I and residential energy sectors differ greatly

— Commercial and industrial energy users constitute about 60% of electricity consumption in Australia. The sector is critical to jobs and the nation’s economic prosperity and it’s in all of our best interests to find ways to help them reduce costs and grow their businesses.

— The residential electricity market is significantly different to that of the C&I market in terms of the way electricity is contracted. It’s also vastly different in relation to the margin earnt by residential retailers versus commercial and industrial retailers, being significantly higher in residential retailing.

— Residential customers are billed using bundled tariffs, where the various costs that make up an electricity bill are put together resulting in a daily charge and a cents per kilowatt hour (kWh) charge. C&I customers often have unbundled tariffs where the different input costs to an electricity bill – wholesale energy costs, transmission network charges, distribution network charges, the cost of renewable energy certificates etc – are separated out to provide greater transparency.

— C&I customers tend to contract for less than three year periods, with many electing to take one year or shorter contract terms with retailers. Contract terms are varied, but are almost always based on the prevailing forward contract market price with a risk premium attached.

— There is a natural mismatch between the duration and price a C&I customer currently contracts to a retailer for (one or two years), and the duration and price required to underwrite new generation developments (ten or more years).

— C&I retailing margins are modest relative to residential retailing, highlighting the improbability of C&I retail margins absorbing additional risk as is currently proposed under the NEG. If risk increases under significant new and onerous obligations for retailers, then C&I prices will reflect this additional risk and the cost of managing it. The higher residential retail margins may absorb additional cost of risk management but that may be undermined by a lessening of competition as outlined further in this document.

— C&I contracts are traded several years into the future and many contracts have already been exchanged for the period through 2019 when the NEG is set to begin operation. The cost of changing these contracts could be high.

— C&I customers have varying degrees of sophistication when it comes to the complexity of energy procurement which has great bearing on the allocation of the reliability obligation.


Other 6%Other 1% Other 5% Other 16%

Hydro Tasmania 100%

InterGen 16%Sunset Power

13%

Snowy 4%

Snowy 6%

Stanwell 37%

CS Energy 34%

Engie 31%

Engie 13%

EnergyAustralia 15%

EnergyAustralia 23%

Origin 6%

Origin 27%

Origin 2%

Origin 26%

AGL 2%

AGL 40%

AGL 34%

AGL 41%

0

10

20

30

40

50

60

70

QLD NSW VIC SA TAS

TWh

FIGURE 1 – MARKET SHARE BY GENERATION DISPATCHED, 2016-17

3. Market Facts

Source: ACCC calculations, AEMO market dispatch data *The Engie figure includes Hazelwood’s output from 1 July 2016 until its closure in March 2017. Engie’s generation output in Victoria will be significantly lower in 2017–18.

Market power is concentrated and generators set the spot price

— The electricity generation market in Australia is dominated by two or three generators in each major market. Together, they make up about 70 per cent of annual electricity generation. In individual states, the two or three largest generators tend to generate around 70 per cent or more of total electricity generation (see Figure 1). These companies tend to be vertically integrated, with significant volumes of retail customers as well. This means they can rely on their own generation to manage spot price risk and under the NEG, could rely on their own resources to meet the proposed retailer obligations, which would further entrench an imbalance in the competitive landscape.

— Retailers that are not vertically integrated use a variety of sources to manage wholesale price risk including other generators, banks, market intermediaries and insurers. If the size of these markets reduces or access is made more difficult under the NEG, more power will be handed to the existing large generators resulting in less competition in retail markets. These large generators currently have electricity pricing power, and they will have more pricing power as well as control over scarce reliability resources for which retailers need to contract.

— In short, as evidenced in escalating prices in 2017, the wholesale price of electricity is driven by the expectation or anticipation of generators exercising their market power, regardless of whether that happens or not i.e. fear of economic withholding.


Infrastructure development takes several years

— In reality, any asset would take at least 10 months to develop, after the NEG is in place for those with already-approved development application and network access agreements, and an additional 12 months without those.

— Different types of generation take different timeframes to build and install. Tesla was able to install a battery storage facility in South Australia in a very short period thanks to government support and having the batteries located alongside an existing wind farm.

— Larger-scale facilities take far longer to develop and build. The proposed Snowy 2.0 development is slated to take around six years to start generating electricity once the go-ahead is given.

— Energy policy certainty is urgent and essential. Asset infrastructure development has long lead times and a NEG that proposes to change every aspect of the market will only contribute to a delay in resolving the core problem of a need for well-placed dispatchable electricity supply.

3. Market Facts


Infrastructure planning and visibility is highly problematic

— Virtually all committed and proposed additional capacity in the NEM is for solar or wind generation although the reliability of the available information is questionable and the likelihood of all of this stated additional capacity being built is slim. The closure of coal and gas-fired capacity is also on the horizon. See Figure 2 below.

— Transparency around the timing and location (and probability of actual construction) of new renewable capacity is opaque, adding significant risk of inefficient investment.

— The Finkel Report recommended greater oversight of power station developments to help improve the timing and planning of new builds and retirements.

— A policy that requires a multitude of parties to simultaneously procure new resources (i.e. retailers contract or build, as proposed under the NEG), where those parties are not afforded the transparency of other/competing resource development is destined to add risk to the industry and ultimately higher costs to end-use customers.

FIGURE 2 – INSTALLED, PROPOSED AND COMMITTED CAPACITY IN THE NEM

Source: AEMO

3. Market Facts

20,000

10,000

5,000

Coal CCGT OCGT Gas other Solar Wind Water Biomass Storage Other

0

15,000

Gen

erat

ion

capa

city

(MW

) StatusAnnounced Withdrawal

Committed

Existing less Announced Withdrawal

Proposed

Withdrawn

Lorem ipsum

Status Coal CCGT OCGT Gas other Solar* Wind Water Biomass Storage Other Total

Existing 22,916 3,013 6,434 2,159 323 4,462 7,941 579 100 142 48,070Announced Withdrawal 2,000 208 34 30 - - - - - - 2,272Committed 78 - 4 - 1,812 1,867 4 31 2 29 3,828Existing less Announced Withdrawal 20,916 2,805 6,400 2,129 323 4,462 7,941 579 100 142 45,798

Proposed - 500 2,950 - 12,735 16,956 4,784 214 110 1,758 40,007Withdrawn 1,600 62 - - - - - - - - 1,662

Note: Existing includes Announced Withdrawal. This data is current as at 04 Jan 2018 * Excludes rooftop PV Installations

Consultation Q&As4.


4. Consultation Q&As

General CommentsOur submission sets out our views as a range of key industry participants representing residential, business, commercial and industrial customers and more than 19TWh of electricity retailed in the market. We believe there is a better way forward for the development of the NEG that provides a transparent mechanism that supports competition and contract market liquidity at lower cost.The procurer of last resort model we propose shares some similarities with the ESB’s draft approach as set out in the discussion paper. The ESB sets out an eight-step approach involving: forecasting; updating; triggering; qualifying instruments; allocating; compliance; procurer of last resort; and penalties.Our model is a simpler five-step approach involving: forecasting; updating; triggering; market response; procurer of last resort. Our proposed model does not rely on tracking contracts, allocating the gap across retailers (and potentially large users) or a penalty mechanism but it does ensure the primary issue of investment in the right resources in the right locations, based on emissions and reliability, is addressed at the lowest cost. We encourage the ESB to adopt our suggested mechanism as we firmly consider that this will lead to better outcomes for consumers.We also highlight that our proposed procurement of last resort mechanism is an ultimate market safety net, and strongly believe the risk of such intervention will motivate industry to build adequate resources, thus facilitating a market-based solution. In recent months, we have seen a fractured approach to reliability concerns, with the announcement of Snowy 2.0, the Queensland Government’s directive to Stanwell to change its bidding behaviour, the South Australian Government’s installation of diesel generators and support for the Tesla battery and state government intervention in Victoria. The lack of a common and standardised response to reliability concerns increases costs and risks. It is far more difficult for the market to invest in such an environment with the potential for government to come in over the top of private investors. Our preferred model provides a standardised response that allows the market the opportunity to invest first, with intervention only if necessary.Furthermore, imposing reliability and emissions obligations on retailers would be misplaced, resulting in a range of risk, price, liquidity, competition and market power issues as outlined throughout this paper. Obligations are best placed with the part of the sector that owns and controls the assets and the risks. To hold retailers liable for generator reliability and emissions would lead to inefficient outcomes.

Should the ESB persist with such a path, the following issues need to be carefully addressed:

— The design must support existing financial markets and allow any new obligations to be met through generic, fungible, traded products. This will be critical to ensuring liquidity, price discovery, market transparency and competition. Policy must not remain silent on the role of financial markets, and must instead be designed specifically to facilitate the use of generic obligations that enable risk to be managed financially, not physically;

— Generator market concentration poses added risk under NEG policy which places high value on the resource of reliability i.e. firm generation. This hands more market and pricing power to large, incumbent generators so there will have to be mechanisms to ensure generators and gentailers provide access to reliability products and don’t undertake discriminatory pricing;

— Emissions calculations would have to be aggregated quarterly or annually at generator level and allocated to retailers due to the fact that electrons cannot be tagged and traced on a contract without imposing prohibitive costs on the market and consumers, particularly in a five-minute settlement market; and

— Forecasting the shortfall or gap should target real periods of system shortfall to guard against over-build and mass over-investment i.e. gold plating which drives up cost for energy users.

Nonetheless, it is incumbent on us to respond to the ESB’s proposed approach. Our responses are made in this context. The following section provides answers where it has been relevant or possible to do so given the information provided in the consultation paper.


4. Consultation Q&As - Emissions Requirement

What are stakeholders’ views on whether the compliance year should be a calendar year or a financial year, noting that EITE exemption processes under the RET use calendar years, whereas emissions reporting obligations relate to financial years?We support a financial year obligation for the emissions requirement. We believe that it will be simpler to adjust the EITE exemption process than to change the NGERS reporting requirements.

What are stakeholders’ views on the process to calculate a retailer’s load?We do not support the imposition of an emissions requirement on retailers. We believe that placing the obligation on the retailer is misplaced, inappropriate and will not deliver least cost, most efficient outcomes.Nonetheless, we recognise that the ESB has developed the emissions requirement on the basis of a retailer obligation. Therefore, while we oppose the requirement sitting with retailers, our answers are made in the context of the ESB’s proposed position.The ESB’s proposed method for calculating a retailer’s load, using the number of MWh purchased by the retailer as recorded by AEMO and adjusted for any EITE exemption, is a simple method as it’s already clear and available in market.

What are stakeholders’ views on how a retailer’s emissions should be determined?We have major concerns over the way that a retailer’s emissions would be built up based on the various types of contracts that they hold. Our concerns primarily relate to how emissions are allocated to different types of contracts and what this means for the existing contracts market. In the answers that follow, we outline these concerns in greater detail. Calculating and allocating emissions based on contracts is too complicated and arguably impossible to measure given the shift towards a five minute market, where contracts may only apply for five minute intervals. A more workable solution would be to have quarterly or annual aggregation where an ex-post obligation linked to served MWh over a quarter or year is supported by a generic, transferable obligation (such as those under RET). We consider such an approach would be relatively simple and efficient to implement. We have serious concerns around how the ESB’s proposed approach would affect cost transparency. Commercial and industrial (C&I) users require detailed costings when sourcing electricity contracts. As such they will insist on the cost of meeting the emissions requirement being explicitly set out when they contract. Attempting to construct a system which bundles electricity and emissions costs together and makes the cost of carbon opaque will be unacceptable to large users. It is crucial that the design of this emission requirement allows for retailers

to transparently determine and explain what the price impact of emissions reduction is. Allowing for the use of ACCUs or international permits will result in the carbon price being revealed. Further, extending the emissions obligation to Western Australia and the Northern Territory through a different mechanism is also likely to reveal the underlying cost of carbon. A complexity will also arise over how the emissions benefits associated with small-scale generation exports from rooftop solar are shared. Owners of the assets will rightfully expect that they receive the emissions benefits for this energy. In practice, these exports would reduce emissions in the spot market. There is a therefore a complex risk of double-counting. A similar risk on a much larger scale exists for large energy users who may have invested in a renewable Power Purchase Agreement (PPA) separately from their electricity retailer.

What are stakeholders’ views on the methods for determining the emissions to assign to contracts where the generation source is specified? If the contract specifies a portfolio of plants and the plants have differing emissions profiles (e.g. some are zero-emissions plants and some are gas plants, used for firming the variable renewable energy), how should the emissions per MWh under the contract be determined?The ESB proposes a system whereby contracts may specify a generation source and an emissions quantum. This would make sense for only a limited number of contracts such as a PPA. For other forms of contracts this appears to imprudently support developing contracts for physical delivery. In the current market, contracts are used to manage financial risk rather than the physical delivery of energy. A system that drives retailers towards contracts for physical delivery would represent a fundamental shift in the operation of the contract market and may imperil liquidity. All market participants, especially smaller retailers, rely on contract markets to manage the financial risk of the wholesale energy market where prices change every five minutes from a range of -$1000/MWh to $14,200/MWh. Generators also use these to manage the uncertainty of their revenue stream.If participants wish to buy and sell contracts of this type there is also a question of how to assess any emissions that are under or over the specified level. This creates an informational asymmetry which could lead to retailers being in breach of their emissions obligation. It is for reasons such as this that an emissions obligation should be placed on generators rather than retailers.It may be possible for such contracts to function, while managing the risk of variances in emission intensity, by setting the compliance date for the emissions



obligation after the publication of NGERS data. This would allow retailers to understand the emissions of generators with which they have contracted on an annual average emissions basis, however not on an individual contract basis nor where contracts do not apply for a full NGERS reporting period.There is a clear drawback to this approach in that by waiting until after NGERS data are published, seven months after the end of the financial year, participants will find it harder to manage their liability over the course of the year. This could lead to over-contracting which will entail higher costs which inevitably will be passed on to energy users.

What are stakeholders’ views on how to determine the emissions per MWh to assign to contracts that specify an emissions level but do not specify a generation source?What are stakeholders’ views on how the contract market may evolve to support this type of compliance with the emissions requirement?Contracts that specify an emissions intensity but not a generation source pose a similar risk to those described above. The ESB’s proposed method would seemingly require a complex method of tracing contracts back to who sold them to ensure that a generator does not sell too many contracts. That said, a market for such contracts could develop that allows a retailer to secure generation at a particular emissions level and a generator to manage its portfolio to achieve that outcome. While contracts between the two parties can manage some of the risks, we argue that the ESB should be mindful that the retailer is not in a position to control or observe the emissions of generating units underpinning the contract.

What are stakeholders’ views on the appropriate emissions level to assign to contracts that do not specify an emissions level or generation source?What (if any) impact would these approaches to determining the deemed emissions level have on the liquidity and availability of those types of contracts?Assigning emissions levels to contracts that currently don’t specify an emissions level or generation source has the greatest potential to create perverse outcomes for both retailers and generators.These kinds of contracts are analogous to contracts traded on the ASX where both the buyer and the seller are anonymous. These contracts are essential for the efficient management of risk by both retailers and generators. Further, exchange traded contracts are crucial to the viability of small retailers who are unable to meet the more onerous credit standards often required to trade in the OTC markets. Such contracts enable small retailers and new entrants to compete with larger incumbents, and are therefore crucial for the viability of retail competition.

We consider there are two chief risks with assigning an emissions level to such contracts. The ESB suggests that emissions levels could be set at an average level, such as “calculated based on the emissions of those generators that sold that type of contract in that region in the previous year” or “all types of contracts sold in a particular region could be deemed to have the same emissions level”. In both cases, generators with emissions levels above this average would face a strong incentive to sell contracts of this type to take advantage of the lower, deemed emissions level. This would result in a scenario where there is a mismatch between reported emissions via NGERS and those reported by retailers. Based on this theory, a higher emissions level should be set to manage this risk. Unfortunately, this is likely to result in any generator below this level refusing to sell such contracts as their value would be reduced. This would lead to a severe reduction in liquidity which would threaten competition in the retail market. This is an unacceptable outcome.Even if an emissions level was determined following the publication of NGERS data it would still require generators and retailers to inform a regulator of the number of non-emissions, non-source specific contracts bought and sold over the course of the year. A retailer would also be unable to assess its cumulative emissions over the course of the year as the level would not be set until after the publication of NGERS data.Again, for this reason, it makes more sense for the emissions requirement to sit with the generator rather than the retailer.

What are stakeholders’ views on how to determine the emissions level to assign to unhedged loads?The decision not to hedge all load is one that is done for a number of reasons. Chiefly, it is almost impossible for load to be 100 per cent hedged at all times due to variations in customer load. Overhedging load also comes at a cost leading to higher prices. Similarly, generators will rarely completely hedge their generation book due to the risk of outages and the ability to respond if spot prices do rise. Retailers already bear significant financial risk from unhedged load due to the possibility of the spot price rising to $14,200/MWh. Imposing a high deemed emission level for unhedged load as flagged by the ESB would create a significant emissions ‘penalty’ disproportionate to the risks involved.A design that forces retailers to choose between either over-hedging (reliability obligation), or paying the highest rate of generator emission intensity for unhedged MWh (emission obligation) clearly forces cost inefficiencies that will flow through to customers. This complexity highlights why the two obligations need to be de-linked.



Should the emissions requirement allow for unlimited carry-over of overachievement or specify limits on the carry-over of overachievement? What are stakeholders’ views on the deferral of compliance?We firmly believe that a range of flexible compliance options including carry-over of overachievement, deferral of compliance and offsets should be available for participants to manage their emissions liability. This is particularly important given the potential interaction with the reliability requirement which may result in retailers contracting with higher emissions generators. We consider that it would be a perverse system that effectively penalises retailers who have been unable to meet the emissions requirement because they have complied with the reliability requirement as proposed by the ESB.Allowing for a series of compliance options also provides a ‘safety valve’ if prices climb too high to be reasonably managed or passed through. In the early years higher limits may be beneficial to manage potential shortfalls in supply.

What are stakeholder views on the interaction between the emissions requirement of the Guarantee and voluntary programs such as GreenPower?We agree with the ESB’s stated preference for adjusting a retailer’s emissions obligation to factor in the voluntary and additional action from programs such as GreenPower. The method proposed in the draft design consultation paper is a sensible method that accurately recognises the emissions impact of GreenPower. We note that as GreenPower is currently based on the voluntary surrender of LGCs, a new method may be needed once the RET finishes in 2030.

What are stakeholders’ views on the need for a compliance registry? What are stakeholders’ views on its design?Are there alternative schemes that would allow retailers to monitor and verify compliance with the emissions requirement? How could these alternative schemes work?Are there any additional features which the registry should have?Should any of the data in the registry be made publicly available?The mechanism for assigning and tracking emissions based on contracts between retailers and generators would require a compliance registry of sorts. Based on our understanding of the ESB’s proposed methodology, the registry would appear to need to be complex in order to track contracts and trace them back to the generation source. Seemingly, retailers would also be required to outline their hedging strategy in order to determine how much load they have hedged. This would entail a significant

compliance cost in order to ensure that contracts for each type are reported to the regulator.One important feature of the registry should be to allow retailers to monitor their emission levels over the course of a compliance year. Yet, as we have already discussed in our previous answers, the proposed method for determining emissions means that it may be virtually impossible for emissions levels to be continually monitored.Given the commercially-sensitive nature of the information that would seemingly be required, we do not consider that the registry should be made publicly available. The only information that could justifiably be publicly released should be overall compliance such as emissions requirement and reported emissions under the scheme.

Is there a need for retailers or generators to report contract pricing information as part of the input into the registry?We are strongly opposed to reporting contract pricing information as part of the input to the registry. This is commercially-sensitive information which has no relevance to compliance with the emissions requirement.

What are stakeholder views on the proposed approach to compliance with the emissions requirement and particular:- Whether this approach provides the appropriate

drivers of compliance.- The type of information the AER will need to access

to ensure compliance.- Other possible enforcement tools, such as increased

prudential requirements or restrictions on accepting new customers while emissions requirements remain outstanding.

We held significant concerns with the ESB’s original position set out in the overview of the NEG released in October 2017 that set out deregistration as seemingly the only option for parties which did not meet their emissions requirement. We are therefore relieved to see that the ESB has recognised the serious and potentially devastating impact this arrangement could have had, and is now proposing a more reasonable and standard set of compliance options.

What are stakeholder views on how the Guarantee may impact on competitive markets?What are stakeholder views on the operation of the emissions requirement in particular jurisdictions?Reducing Australia’s greenhouse gas emissions needs to be managed at a national level. As such, it is unclear why the emissions requirement is evidently restricted to the NEM states. Western Australia and the Northern Territory can certainly play a role in helping to reduce emissions given their strong solar energy resources and access to lower emissions gas-fired generation.



Investment in these jurisdictions and technologies should be encouraged by the NEG rather than being potentially ignored.Because emissions must be treated at a national level, with an emissions intensity target set based on the national requirement, we believe that there will be risks to competitive markets due to the differing emissions intensities of generation in each state. As such, retailers with a large customer base in one state may find it difficult to source low emissions generation within the state in order to meet the targeted emissions intensity. This risk will be particularly acute in Victoria which has the highest electricity emissions intensity of any state in Australia. Small and new entrant retailers tend to try to establish themselves within the Victorian market first due to the highly competitive nature of electricity retailing within the state. Small retailers may therefore be unable to compete with larger retailers who retail across states and therefore have more geographically balanced portfolios. This may lead to retailers being unwilling to make offers to new customers in Victoria due to the higher emissions intensity within the state. Alternatively, a significant cost premium may be applied to new customers in Victoria if retailers perceive that bringing Victorian customers into their portfolio will make meeting their emissions obligation more difficult.

Stakeholder views are sought on options for setting the emissions targets under the Guarantee.We agree with the Commonwealth Government’s proposed approach of using an emissions intensity target for the emissions obligation. However we wish to better understand the Government’s intention for how this target will be set. The consultation paper states that the “target for the electricity sector for 2030 under the Guarantee is a 26 per cent emissions reduction on 2005 levels”. It is not clear whether this refers to the national emission reduction target of 26-28 per cent below 2005 levels, or is imposing a target of a 26 per cent reduction on the electricity sector’s emissions in 2005 or even the sector’s emissions intensity in 2005. These represent very different approaches which will have large implications for the targets themselves and thus the obligation and investment requirement.

Stakeholder views are sought on the proposed timing for updating the electricity emissions targets, including a five-year notice period.The Government’s proposed approach is to set targets for 2021-2030 prior to the commencement of the Paris Agreement and to set a further five years of targets each and every five years. Additionally, targets would be locked in and only able to be changed with five years’ notice.

We believe that this approach will provide a strong signal for long-term investment in lower emissions generation technology while also avoiding the risks associated with constant reviews of schemes.We do consider that the Australian Government should investigate the possibility of providing a longer term signal by providing a non-binding range of potential targets beyond 10 years.

Stakeholder views are sought on the proposed approach to setting the electricity emissions targets under the Guarantee and interaction with state renewable energy schemes.A number of state governments have set emissions reduction or renewable energy targets over the past few years due to the absence of a stable, national emissions policy. Although we understand the rationale behind doing so, we hope that the development of a national, bipartisan emission reduction policy will end this fragmentation of emissions policy. Reducing emissions is best dealt with consistently at a national level. Given this, allowing state-based targets to impact the national target risks destabilising the market. It undermines the purpose and clarity of a single national target. If state-based targets influenced the setting of national targets, we consider it is highly probably that the current policy uncertainty would continue as targets shift with each state election. For this reason, we support the Government’s preference not to increase the national target based on state-based targets.

Stakeholder views are sought on whether retailers should be allowed to use external offsets to meet a proportion of their emissions requirement. In particular, views are sought on:- Whether there is a strong rationale for the use for

offsets within the Guarantee- The impact allowing offsets would have on

investment under the Guarantee- If offsets were to be used to help achieve

compliance with the emissions requirement, what would be an appropriate limit for their use?

Access to offsets including ACCUs and international units is an important tool for retailers to have flexibility to meet their targets. Allowing for the use of offsets could also help lower the costs of meeting emissions targets, particularly in the early years where supply may be tight, thus placing high costs on end users. Consideration should be given to allowing for a greater volume of offsets in early years before scaling down over time.


4. Consultation Q&As - Reliability Requirements

What are stakeholder views on the length of the forecasting period?Should the existing ESoO and MTPASA forecasting processes be adapted for determining the gap, or should a separate bespoke process be developed?What elements of the current MTPASA and EsoO processes should be reviewed in light of the potential for the process to lead to a compliance obligation? E.g. how should AEMO treat inputs from generators such as their forced outage rate or summer capacity if these assumptions could lead to a triggering of an obligation?Should AEMO be able to determine assumptions independently or should responsibility for the accuracy of assumptions be placed on the market participant?How should the forecasting methodology and assumptions be consulted on?The existing Electricity Statement of Opportunities (ESOO) and Medium Term Projected Assessment of System Adequacy (MTPASA) processes provide a valuable template to use for forecasting. The ten-year window of ESOO, combined with the two-year window for MTPASA gives a guide as to the time length that the market already uses as an input to investment decisions.We note that the ESB has proposed increasing the MTPASA window to three years to reflect the Finkel Review’s proposed three year minimum notice of closure. Without commenting on the notice of closure, a three year window for MTPASA would help to provide an increased level of detail in the medium term compared to existing arrangements.Consequently, we suggest that at a minimum a three-year trigger point be established whereby AEMO seeks a response from the market if at this time a shortfall has been identified. There is too much uncertainty with triggering a reliability obligation earlier than this.Given the importance that these forecasting processes would then have on investment, we strongly urge there be increased resources given to AEMO to allow for regular updates and improved consultation with the market on the assumptions used in modelling. It will be in everyone’s interests – customers, AEMO, retailers, generators and potential investors – that forecasts continually improve and can be seen as a reliable source of estimates of future supply and demand.

The forecasting methodology and assumptions should be widely and regularly consulted on to give market participants the opportunity to review and assess the inputs that will shape the possibility of a reliability obligation being triggered. We believe consideration should also be given to allow for an independent panel to review the methodology and assumption, or to commission independent modelling.In considering these issues, we believe the ESB must also turn its mind to the risk of generators gaming forecasts to trigger artificial reliability gaps and therefore trigger a response from the market. For example, a generator could propose to have units unavailable for maintenance in order to trigger a gap. They could then ‘defer’ this outage in order to take advantage of the higher demand (and therefore higher cost) for reliability. The strategy could be repeated by multiple generators, time and time again. One potential way for the behaviour of generators to become more transparent would be to require AEMO to publish individual generator units in the MTPASA reports rather than simply overall nodal availability.

How frequently should the forecast be updated?We consider that the forecasts should be updated on an as-needs basis depending on how far away this is – updates could be less frequent the further away and more frequent as the forecast is closer to the present time. At present, the ESOO can be updated when major new information is released that would shift the forecasts. This could include announcements of generation investment or retirement or significant changes in demand forecasts (such as the closure of a major energy user or a shift in consumer trends). This process should continue, with more regular updates as the potential for a trigger point to arrive draws closer.The existing MTPASA is updated weekly which is likely to provide participants with sufficient information on the likelihood of the reliability obligation being triggered. As such, we believe that no change should be necessary.Additional information regarding the proposed construction of new generation and storage facilities should be made available on a monthly basis. Information should include the type of technology, the specific location and detailed project status. This information is vital for potential investors to forecast likely supply shortages and to respond with the most suitable new investments.



What trigger point would be most appropriate and proportionate to the identification of the reliability gap?Should a multi-year gap trigger a compliance requirement in only the first year of the gap or over the full duration of the gap?What is the minimum feasible time period for the market to alleviate a potential shortfall? If the length of the trigger period is such that the market is not given this minimum feasible time, is it appropriate for the Guarantee to contain the flexibility to have a shorter term trigger to provide sufficient time for the market to have an opportunity to respond to the shortfall?If the ESB is wedded to its proposed eight-step approach and of basing the reliability obligation on the 10 per cent probability of exceedance forecasts, then the ESB needs to recognise that peak demand is a specific and time sensitive occurrence. A trigger must only apply to the specific period of shortfall. For example, between 4-7pm in New South Wales in Q1 2022. Imposing a reliability obligation more broadly would lead to costly over-investment, including at times where there may be no threat at all to reliability. A range of timeframes could be used to signal the reliability gap to the market, as evidenced in overseas markets.A practical example is the period between Liddell Power Station’s proposed closure in 2022 and the completion of the proposed Snowy 2.0 project in 2024. Should a gap be identified in this period for a very limited amount of hours, an interim solution such as portable generation, or a targeted demand side response program may be the most cost effective approach to filling the gap.We consider that a reasonable approach would be that if a shortfall is apparent three years in advance then the market is given a warning period to respond. Under our proposed model, at this point AEMO would set about seeking potential sources of supply for the procurer of last resort. If, following a 12-month warning period, the market has failed to respond, then we consider it is reasonable for a shortfall period to be triggered. This would then allow AEMO to sign a contract with the last-resort supplier.

Alternatively, we envisage a separate model that would work within the ESB’s proposed eight-step approach. Under this model we see a workable solution as follows:

— A gap is identified on an ex ante basis by AEMO

— Retailers are required to manage their obligation during the gap period by procuring eligible reliability instruments.

— Eligible reliability hedging instruments will include generic electricity derivatives (i.e. ASX futures, swaps, caps, Asian call options, etc.) as will physical assets such as batteries and stand-by generation

— AER will have the powers to test retailer compliance on an ex post basis, with the ability to impose appropriate penalties for non-compliance

— A well-designed policy will also encourage demand response and innovative product offerings such as critical peak tariffs

— Policy design will ensure any eligible reliability hedging instruments can be bought and sold either via OTC or exchange-traded markets

— Policy will also recognise the risks of “tight markets” and consider design features that oblige holders of large volumes of reliability capacity to make quotas available through auctions or via market making requirements – price caps on such markets may also be a design feature in order to prevent windfall gains and protect consumers



What are stakeholder views on the types of contracts that should be considered eligible for the purposes of the requirement?Do stakeholders consider eligible contracts should be financial, or have a link to physical capacity?What do stakeholders think of the approach to certify financial contracts back to a physical asset?To what extent does the design choice about eligible contracts influence different types of retailers, and so market structure?What are stakeholder views on the proposed approach of determining the generation source in a vertically integrated business?The reliability obligation must be designed in such a way that supports existing financial markets. In order to minimise cost and maximise flexibility, reliability obligations need to be traded in a generic, fungible manner. Rules should facilitate the industry to satisfy their reliability obligation with financial instruments.Contracts such as swaps, caps and Asian call options, including OTC and ASX-traded products, that imply an underlying incentive for a generator to generate should be eligible including financial contracts. Due to the existing high Market Price Cap, these contracts already impose potentially severe financial risks on sellers if there was no link at all back to a generator. Given the financial risks at play, we consider there to be no need to consider certifying contracts back to specific generators. Demand response contracts and critical peak tariffs should also be eligible to contribute to meeting a retailer’s obligation. This will be particularly important if an ex ante system is adopted. Any failure to deliver reliability should result in penalties to the party who has failed to deliver – the generator if they have failed to generate (through exposure to high spot prices) and the retailer if they have failed to purchase a sufficient volume of qualifying reliability instruments. Consideration should also be given to putting a ceiling price on the cost of the reliability obligation as part of the transition. It must be set at a level that avoids windfall gains for incumbents and incentivises new investment where required.Market power poses a real risk under the NEG. Enforceable undertakings and other market mechanisms will have to be in place under a policy where the obligation to buy reliability products is much higher and therefore the risk of market power is even greater. Consideration needs to be given to mechanisms that ensure generators and gentailers over a certain size do not undertake discriminatory pricing and that they provide open access to third parties. A competitive auction process could be one such method to avoid generators economic withholding and making windfall gains. We contend that the ESB should consider compelling parties with potential to exercise market power such as large

generators and gentailers to offer reliability products into the market. This would help to address concerns over market power and increase competition. There is precedent in the form of the ACCC’s enforceable undertaking for AGL to offer a particular volume of hedging contracts into the market following their takeover of Macquarie Generation. While a relatively small undertaking was applied in the Macquarie Generation example, the NEG would exacerbate market power issues, and consideration would be needed to assess measures impacting all available reliability products available from large generators.These are crucial aspects to the design of the reliability requirement. If designed poorly, the reliability requirement could just increase risk for small retailers and large energy users. Requiring a physical link back to generation may destroy volumes in the contract market and therefore make it far more difficult and costly for non-vertically integrated retailers to compete in the electricity retail market. This would have serious impacts on competition and prices for end users. We also recommend caution given that these changes will occur against the background of a major change to market operation in the form of five minute settlement which will be introduced on 1 July 2021.

What are stakeholder views on the proposed method of allocating the gap to retailers?Should the gap be allocated based on AEMO’s forecasts or on the retailers’ own view of their hedge positions?How should C&I load be treated?How should load met by interconnectors be treated?The reliability obligation should only apply to a retailer’s proportion of load at the time of the system peak, rather than a retailer’s peak load over the course of the day. The latter scenario would result in over procurement of capacity which would result in significant costs that would be passed on to end users. As such, a retailer’s actual obligations must be applied on an ex-post basis.Using forecasts to determine requirement poses a number of difficulties, particularly for C&I users and retailers with large volumes of C&I load. For instance, just one or two large users switching retailers will significantly change a retailer’s forecasts or AEMO’s forecasts. One of the chief benefits of relying on actual data (ex post) rather than forecasts (ex ante) is that the latter would create incentives for retailers to underestimate load, or for AEMO to overestimate load if it was more risk averse. We believe that to develop more accurate forecasts, AEMO would also have to forecast the load of individual C&I customers, particularly if there is a requirement for retailers to meet their own reliability requirement as is raised as an option in the discussion paper. C&I load changes in a very different fashion to residential load. Some C&I customers have very flat



load profiles that do not vary much between system 50 PoE and 10 PoE conditions. These complexities would need to be well considered under an ex ante allocation model.Such that forecasts are used to allocate the gap to retailers, AEMO will have to take the difference between different types of C&I load and residential load into account. This would inevitably lead to a more costly, slow and complicated process. The potential for interconnectors to meet load in other states must be factored into the assessment of any reliability gap. Failure to do so could lead to costly over procurement. AEMO forecasts already consider the role of interconnectors and this should continue to occur under NEG.

Should a different level of compliance and/or reporting requirement be required for large energy users who are registered Customers?What are stakeholder views on extending the reliability requirement to large energy users that are not market customers?If the reliability requirement should be extended to large energy users that are not market customers, what would be an appropriate definition of ‘large energy user’?Symmetry will be an important aspect of how large energy users who are and aren’t market customers are treated. A system that encourages large energy users to become registered customers in order to avoid certain obligations would be counter-productive. As such, there will need to be consistency in how these different users are treated. If the ESB were to continue on a path with an obligation on large energy users it needs to consider the nature of the C&I sector. The buying behaviour of C&I customers is supportive of the highly competitive nature of running their businesses and consistent with them not wanting to make large investments in non-core energy infrastructure. Additional cost threatens the international competitiveness of Australian business. If the prevailing view was to assign the obligation to large energy users, the obligations must be generic and fungible so they could aggregated and scaled to achieve investment based on emissions and reliability i.e. 50 businesses individually looking to invest in 10MW each would be inefficient but that could be more easily aggregated to deliver 500MW.

What are stakeholder views on an ex ante or ex post approach to compliance?What are stakeholder views on the implications for the assignment of the gap, given an ex ante or ex post approach?What parameters should be taken into account when deciding between these two options?Does an ex post or ex ante approach impact different retailer types?Could an ex post approach be effectively implemented while retaining a credible procurer of last resort function?We prefer an ex post approach to compliance. We have already outlined some of the challenges of relying on ex ante forecasts such as recognising the differences between different types of customer load. Retailer forecasts of load will change from day to day based on their assessment of their customers’ behaviour and any customers gained or lost. An ex ante obligation will inevitably be wrong and could lead to retailers over-procuring costly reliability measures.In contrast, an ex post approach gives retailers a definite target based on what actually occurred at the time of system peak. We note that various capacity markets internationally and in Western Australia use an ex post approach which assigns retailer obligations based on their actual usage during system peak times.We recognise the ESB’s concerns over how to implement a procurer of last resort mechanism in conjunction with an ex post approach. Our preferred procurer of last resort model outlined in this submission would allow for any gap to be managed without the need for either ex post or ex ante allocations and thus avoids this problem.

What are stakeholder views on the including a procurer of last resort function in the reliability requirement?When should the last resort function be triggered?How should a significant and enduring gap be resolved?If implemented in the manner described in our submission, we would strongly support a procurer of last resort mechanism, but only if this did not result in severe penalties to retailers who may have been willing, but not able to access reliable generation due to market power issues. Procurement of last resort should be a more central safety net which replaces the retailer reliability obligations and act as an incentive for the market to step up.The model we outline would allow for a significant and enduring gap to be resolved by AEMO by sourcing a multi-year contract. We firmly believe that our model provides sufficient incentives for the market to tackle any projected shortfalls up front and well in advance of any intervention by AEMO.Our proposal recognises that the loss of market liquidity and abuse of market power are far greater risks than the potential for over-build.


What are stakeholder views on how the Guarantee may impact on competitive markets?As we have outlined, maintaining competitive markets is key to the design of the Guarantee. There are major implications if competition is lessened. Australia’s energy users cannot afford a mechanism that inadvertently increases energy prices and reduces choice and competition.There are several key elements to designing the Guarantee to enable competition to thrive. Retailers must be able to access deep and liquid markets, and any prices for reliability and emissions must be transparent and open to the market. Ultimately we contend the Guarantee must be designed in such a way that:

— will not exacerbate generator market power issues by tilting the balance of power further in their favour;

— will not put all the risk on retailers who have no control over generation, dispatch and reliability;

— will not increase cost through economic withholding;

— will not push out smaller retailers who build competitive tension and bring innovation to retailing; and

— will not add further compliance costs which are disproportionately felt by smaller market participants.

We firmly believe that the enhanced market transparency and competition approach we have outlined will achieve these goals successfully.


NEG Proposals, Implications and Recommendations for Detailed Design

5.


5. NEG Proposals, Implications and Recommendations for Detailed Design

This section explores the NEG proposals, the benefits and implications and provides recommendations on how those proposals could be practically designed to achieve reliability and emissions goals while minimising market disruption and cost.

1. Competition

ENHANCE COMPETITION AND INNOVATION FOR EFFICIENCY AND AFFORDABILITY

IMPLICATIONS — It is implied that the NEG would

ideally enhance competition and incentivise new entrants and investment in retailing, generation and storage.

— Under the NEG, retailers must contract while generators may contract. This has significant implications and is a major change to the way the market operates. There is significant risk and cost associated with dominant generators withholding contract supply. This is an issue in the current market but under the NEG as currently proposed, the risk escalates significantly. The balance of obligations shifts to retailers having to do something or face penalties, while generators have the option to do something. The concentration of generation ownership will make any policy designed to reduce wholesale price very difficult to achieve without intervention on asset owners i.e. regulatory obligations to provide adequate capacity to retailers, industry structural change, compulsory auctions, or similar mechanisms are warranted, in recognition of the fact that the NEG

shifts market power to generation owners, particularly those with retail businesses. Unreasonable and inflexible contracts, as seen recently in the east Australian gas market, are likely under the NEG.

— Without a mechanism to reduce economic withholding, this is likely to add an imbalance of costs to non-vertically integrated residential retailers, and increase the delivered costs to all commercial and industrial (C&I) customers.

— Credit is the other practical issue, which will have a very big impact on smaller retailers, calling into question their viability. The challenge for them will be to establish credit lines and put commercial arrangements in place with large generation companies when there is nothing to compel the vertically integrated generator to enter an agreement with a competing retailer. Even more simply, a generator may just not have the credit risk appetite to enter an agreement with a small retailer whereas in the current market those small retailers can procure hedge contracts from a number of sources. Furthermore, smaller retailers are likely to be “unbankable” for the establishment of new projects to meet obligations i.e. they will be unable to write PPAs due to their lower credit standing.


— Increasing obligations and costs for retailers will change the industry. The current market has supported an increasing diversity of retailer commercial models driven by the falling cost of renewable energy, storage technologies and access to technology agnostic electricity contracts. Policy makers are now challenged to increase obligations on retailers without eroding the appetite for innovation and competition in the sector.

RECOMMENDATIONSAn enhanced market transparency and competition approach would avoid major market disruption and not diminish competition because it would:

— not exacerbate generator market power issues by tilting the balance of power further in their favour;

— not put all the risk on retailers who have no control over generation dispatch and reliability;

— not increase cost through economic withholding; and

— not push out smaller retailers who are building competitive tension in retailing;

Under the model proposed in this paper, more certainty in the demand/supply balance would lead to greater liquidity and price transparency which is favourable to competition and consumer outcomes.



2. Retailer Obligations

RELIABILITY AND EMISSIONS TARGETS TO BE MET THROUGH BILATERAL CONTRACTS BETWEEN RETAILERS AND GENERATORS

IMPLICATIONS — The NEG clearly aims to increase

physical supply, leading to wholesale price relief. The NEG assumes a significant increase in the amount of contracting between retailers and generators. However it’s not clear – taking into account the ASX and other markets – that overall market liquidity will be increased. Spot prices will likely reduce as new resources come online but customers are priced off wholesale contract prices, and there are no clear components of the proposed policy that will drive contract prices lower, as the reliability and emissions cost component of the electricity contract will not be directly related to spot prices.

— A key factor in the historical liquidity of the electricity derivatives markets, generally trading at multiples of the underlying electricity demand, is the use of highly standardised products based predominately on the underlying electricity regional reference price. Requiring retailers to purchase a complex basket of products including electricity, reliability and emissions obligations will reduce the standardisation of the traded products. This is likely to result in information asymmetry, difficulties in price discovery with more opaque pricing, resulting in a move from higher to lower liquidity. This

reduction in transparency, reduced liquidity and higher risk management costs will result in higher prices for end-use customers.

— The reduction in hedge contract liquidity due to the bilateral or bespoke nature of retail procurement requirements in the NEG is not just generator-retailer contract liquidity. There will be a reduction in retailer contracting flexibility, i.e. reduced ability to draw on financial risk management products such as weather insurance etc, noting weather is a direct risk contributor.

— Transacting standard OTC and ASX-traded products can occur in a matter of seconds, where negotiating bespoke contracts will be complex and therefore involve protracted time periods to reach agreement. Retailers will need to develop their resource plans well ahead of customer contracting periods. The implications of this will be:

— retailers will have heightened price risk, as they have agreed the fixed purchase price, but are yet to secure a customer sales contract, therefore the retailer will have to charge higher premiums.

— similar to the recent C&I gas experience, once retailers match customer sales contracts to their procured resource plan, they will refuse to contract additional customers (risk of penalties being too great), therefore customers will be left without a supply contract or receive ‘supplier of last resort’ uncompetitive pricing.



— Customers will receive less flexible contract terms, for example provisions such as ‘take or pay obligations’, and stringent load flex clauses will be required by retailers to protect against their added risks.

— Furthermore, when the theory translates into real world scenarios, how this obligation is managed in times of unplanned generator outages, which themselves may often be the trigger for lack of reserve scenarios, needs to be understood. While the parties may hold contractual agreements for the energy fuel source, the reality is that dispatchable generation may not always deliver energy in real time. Given the dominance of asset owners, a risk exists that market power could be used (via non delivery of reliable capacity) to, at minimum, frustrate or ultimately force penalties on a competing retailer. The punitive nature of this penalty will mean generators won’t accept liability clauses for non-delivery.

— Since the NEG announcement, one large vertically-integrated entity has already moved to an OTC price adjustment clause that enables them to recover carbon on 100% of MWh deliverable under the contract for the calendar 2020 period, and have also advised that they will no longer sell base contracts via the ASX futures market for the same period. These are an early signal that either costs or risks to retailers (and therefore end users) have already increased, liquidity has reduced, and the vertically-integrated entity can leverage its dominant supply position.

— Retailers of all sizes buy energy contracts to manage price risk. However, some small retailers and/or end users do not have the credit quality to deal directly with generators and often source their cover from the ASX Energy Futures Market, or banks and intermediaries that provide integrated hedging and financing services. It’s unlikely smaller retailers could continue to participate in a market in which physical bilateral contracts with generators are mandated.

If all retailers contract to or above their peak, and load shifts between retailers year on year, there will be a risk of gross over investment that will ultimately be funded by consumers.



RECOMMENDATIONSTo fully address the implications raised above, an enhanced market transparency and competition model is proposed based on the following:

— The appointed body determines reliability resource requirements and emissions intensity for each jurisdiction (at state or intra-state for reliability, and nationally for emissions) consistent with the intent of the Energy Security Board proposal. It is envisaged that only the reliability and emissions objectives, not the technology will be stipulated. For example, in Queensland it could be fast response technology that deals with solar output decreasing while concurrently demand is increasing, whereas in Victoria is may be technology that can provide longer duration synchronous supply of electricity, i.e. during prolonged low wind and low solar generation periods.

— AEMO notifies the market of these requirements.

— Where the market hasn’t underwritten the necessary reliability resources to achieve these targets AEMO advises the market of the shortfall and requests that participants respond, advising of any plans to address the identified requirements.

— If a shortfall remains after a set period of time, the safety net is triggered and AEMO requests formal proposals from the market, in accordance with the resource and emissions requirements.

— Based on those market responses AEMO awards contracts to one or multiple parties that in combination achieves the lowest cost solution to meet the reliability and emissions objectives.

— AEMO pays a fixed payment to those solution providers and passes that cost through to the retailers based on load (on a $/MWh basis) as per the way market charges are currently levied on retailers. The reliability resource providers are awarded contracts through this process and must bid their plant or resource into the market as directed by AEMO. Economic return is through the fixed payments from AEMO rather than other market revenue and arbitrage.

— There would be in-built checks and balances to ensure that central procurement is a last resort mechanism, not a default, and this could take the form of ESB approval of AEMO energy procurement to ensure reserve conservatism does not results in high cost of supply or gold plating of infrastructure.

— Under this centralised procurement of last resort scenario, all other market mechanisms remain unchanged, allowing rapid implementation while minimising market disruption and the cost that accompanies major market change.

— Importantly, the market still has the opportunity to remedy the shortfall before procurement of last resort is triggered.



3. Transparency

BUILD CONTRACT AND PRICE TRANSPARENCY

IMPLICATIONSWholesale price transparency exists today allowing the market to price today’s standardised products off an underlying reference point. A move to tailored, bundled, more complex products (energy, reliability and emissions) will lead to a reduction in energy price transparency, reduced liquidity, and higher prices for end-use customers. Spot price today is a key reference for the price of future-dated wholesale electricity contracts i.e. it drives customer price. Under the NEG proposal where a number of price inputs would exist (i.e opacity of bundled spot, reliability, emissions etc), spot prices would no longer be an analogue for the underlying price charged to customers which would pose a significant issue for the market, customers and investors.

The recommendations outlined in section 2 on retailer obligations will help to build transparency into the NEG as the cost of meeting any additional reliability requirements would be allocated in the same way as market fees currently are. This ensures that all participants face the same cost per MWh.

RECOMMENDATIONSThat the NEG enhance contract transparency not detract from it. Bilateral physical contracts between retailers and generators risk the liquidity of the market and would subsequently increase prices given the tailored nature of the product and fewer market participants i.e. the exclusion of intermediaries. The NEG should therefore confirm the role of these market intermediaries in order to further deepen the liquidity and transparency of contracting.



4. Buying behaviour

FACTOR IN THE VASTLY DIFFERENT NATURE OF BUSINESS V RESIDENTIAL ELECTRICITY MARKETS

— It’s critical that the C&I market, vastly different to that of residential electricity retailing, is modelled and considered at every stage of planning for the NEG.

— C&I energy users constitute about 60% of electricity consumption in Australia. The sector is critical to jobs and the nation’s economic prosperity and it’s in all of our best interests to find ways to help them reduce costs and grow their businesses. The residential electricity market is significantly different to that of the C&I market in terms of the way electricity is contracted. It’s also vastly different in relation to the margin earnt by residential retailers versus commercial and industrial retailers, being significantly higher in residential retailing.

— Business and industry have a specific buying behaviour (the terms and duration of contract) which is somewhat aligned to current energy market operations. If there is an assumption that C&I customers will change their buying behaviours in line with changes brought about by the NEG then those assumptions should be made clear to both C&I retailers and customers and carefully modelled.

— C&I customers tend to contract for less than three year periods, with many electing to take contract terms of one year or less with retailers. Often C&I customers will not commit to a retailer until days or weeks before the

contract period commences. Under the proposed design of the NEG, retailers will require many months’ notice to procure an adequate balance and volume of resources.

— Bilateral contracts can take many months to negotiate and often do not result in an outcome. However, as customers don’t often contract that far in advance, the quantum of resource purchases a retailer requires will be difficult to predict, with the consequences of over and under contracting being extreme.

— There is a real risk that under the proposed NEG, C&I customers will be left stranded without a contract as retailers will be unable to rebalance their resources at short notice and will be unwilling to risk breaching their obligations due to the risk of penalties if under-contracted. This occurred in the east coast gas market and should be a clear warning signal for design of the NEG.

— Based on the proposed design, retailers will effectively face a choice between signing a customer for three years while also making a 20+ year new build investment decision to procure additional resources or declining to sign the customer and having a smaller retail business, relying instead on the retailer’s existing resources.

— Put simply, it will be more attractive for retailers to sell limited resources for higher margins than to take disproportionate investment risks in order to secure long-term supply.



RECOMMENDATIONS — Detailed modelling on the NEG should

be conducted which should take into account even a small increase in hedge contract prices, driven by the increased imbalance of power toward generators, which would have material cost impacts to customers. This is particularly relevant to C&I retailers, who would be unable to absorb those increases in their ~$5/MWh C&I margins.

— Modelling should also have to take into account competition impacts with the likely exit of many smaller retailers who will not have the scale or credit quality to operate in this fundamentally different market.

— Modelling should also consider the added costs of more onerous contractual terms on C&I customers.

— The implications raised above would be in section five above would be resolved under an enhanced market transparency and competition model.



5. Investment

ENCOURAGE AND INCENTIVISE INVESTMENT AT LOWEST COST

— There is a risk that rather than retailers building new resources they’ll reduce the size of their existing book to manage risk if retailers own the reliability and emissions obligations i.e. fit within their existing resource capacity rather than take the risk of a long-term investment.

— Any new mechanisms should guard against economically inefficient development which addresses artificial constraints. This would lead to higher costs that would need to be recovered through higher energy user charges.

— If emission and reliability targets change regularly, it’s difficult to envisage an environment of reliable and appropriate investment signals (potentially unbankable projects). The cost risks associated with (annually) changing emissions and reliability obligations are likely to make it hard to commit to long-term agreements when the procurement mix obligations will change regularly on a state by state basis.

— Even without regularly changing obligations good policy would recognise that there remains a fundamental mismatch between the length of price certainty offered by customers (less than 3 years) and the investment horizon for a project meaning there is no guarantee that investments will be made.

— Good policy will ensure a safety net mechanism is in place to bring on new supply resource. Note the WA safety net has never been triggered.

— Financial hedging decisions are already being taken three to five years into the future. A rapid change (i.e. by 2019) will be more costly, as new capacity will be difficult to negotiate, bank and build in such short time frames.

RECOMMENDATIONS — Reliability obligations and emissions

targets must be set using clear and transparent rules with a multi-year pathway in order to allow for businesses to plan and invest.

— A coordinated approach by AEMC to identify the best mix of plant in the optimal locations will be economically more efficient than a multitude of individual retailers procuring a multitude of resources placed in an inefficient manner throughout the grid.

— AEMO’s procurement process should be designed to ensure that the lowest cost solution is built in order to meet any reliability or emissions constraint. Centralised procurement of last resort by AEMO will, if triggered, attract low cost debt (as asset builders will have an implied government credit rated offtake), thus an ultimately lower cost to end users.

— A centralised procurement of last resort approach would ensure that, where the market is unable to make an investment decision without some longer term certainty, that the necessary investment is made.



6. Cost

ENSURE LOWEST COST INFRASTRUCTURE IS BUILT TO MEET OBLIGATIONS

— Any NEG detailed design needs to carefully consider the cost to end users. Over-build, complex regulatory and compliance mechanisms, less contract liquidity, more tailored and complex products, diminished competition all lead to additional cost which is ultimately borne by energy consumers.

— It’s critical that new policy guards against gold plating or over-build which is a risk in this politically-charged environment.

— Network costs increased significantly from 2009 as the impact of increased reliability standards and new investments made for projected increases in peak demand which, to this stage, have yet to materialise. As a result consumers have paid substantially for network costs for investments that look questionable in hindsight.

— Similarly, the inefficiencies from building common intermittent assets, such as the wind generation example in South Australia must be avoided.

RECOMMENDATIONThe model in this paper firstly relies on a co-ordinated view by an independent body (the NEG suggests the AEMC for such a role) on what resource is actually needed, without specifying the technology i.e. efficiency in planning; then allows the market to solve the problem economically without intervention while also ensuring that, in the absence of a market-led solution, the required investment in reliability and sustainability will be made.

A centralised infrastructure procurement of last resort model is the recommended solution to align reliability and emissions obligations (energy build) with cost-effective and well-placed investment. This would ensure the benefits that deep and liquid markets bring to price transparency and hedging efficiency remain. It would avoid the risks and costs associated with change in law complexities to existing retail and wholesale electricity contract arrangements.



7. Regulation and compliance monitoring

MINIMISE MARKET DISRUPTION AND REGULATORY BURDEN

IMPLICATIONSThe NEG, as it’s currently understood, would require an entirely new industry of regulatory experts in engineering and accounting capable of analysing tens of thousands of bespoke electricity contracts annually to ensure compliance with reliability and emissions obligations. The practicality, cost and timeframe for establishing all of this is questionable.

RECOMMENDATIONMaintain the intent of the NEG around the market meeting reliability and emissions obligations but do this with minimal disruption. An enhanced market transparency and competition model allows the underlying positive intent of the NEG to be met without adding complexity, cost and a host of unintended and undesirable outcomes.


Appendix A: model proposal – measures of success

6.


Appendix A: Model proposal – measures of success

Measure of Success

Model proposed in this paperEnhanced market transparency and competition model with centralised procurement of last resort

Achieves Reliability Targets Yes

Achieves Emissions Targets Yes

Tax on Carbon No

Creates New Certificates No

Is technology agnostic Yes

Promotes best mix of plant to achieve that Yes and also enables optimal location of assets within the network

Increases Market Power of Generators/Gentailers No

Creates barriers to independent retailers No

Reduces Wholesale PricesYes – new plant built under procurement of last resort must bid according to AEMO’s requirements (no opportunistic bidding)

Increases incentives to contract (therefore reducing volatility) No

Maintains market transparency Yes

Places reliability risk with those best able to manage it Yes

Addresses the mismatch between long term investment certainty needs and customer contracting Yes

Potentially has retailers retreating into their capacity leaving customers stranded No

Promotes lowest cost new technologyYes. (1) Improved planning (2) safety net will deliver long term certainty if triggered and govt offtake reduces WACCs

Requires far reaching changes to NEM market mechanisms No

Serious risk increase / disruption to existing market participants / risks of reduced retail competition No

Government owns/subsidises plant No

Minimise regulatory and compliance cost and burden on government and market Yes

Consistent with proven frameworks in international jurisdictions and WA

Yes, centralised procurement mechanisms currently exist in a number of energy markets, for example:UK – Capacity Market auction and the Contracts for Difference programUSA (ERCOT) – Reliability must-run (RMR) agreement and Emergency Response ServicesAustralia (Western Australia) – Reserve Capacity Auction

National Energy GuaranteeW H I T E PA P E R

Contact [email protected] 07 3020 5100

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