Development of Regulatory guidelines and qualifying principles for co-generation projects
November 2006
FIELDSTONE
Confidential NERSA Co-generation Document
Important Notice
This document has been prepared by Fieldstone Africa (Pty) Ltd (“Fieldstone”) to assist the National Electricity Regulator of South Africa (“NERSA”) develop Regulatory guidelines and qualifying principles for co-generation projects.
None of the information contained in this document has been independently verified by Fieldstone or any of its connected persons. Neither Fieldstone nor any of their respective connected persons accept any liability or responsibility for the accuracy or completeness of, nor make any representation or warranty, express or implied, with respect to, the information contained in this document or on which this document is based or any other information or representations supplied or made in connection with any negotiations in respect of the Project or as to the reasonableness of any projections which this document contains.
No representation, warranty or undertaking, express or implied is made by Fieldstone or any of their respective connected parties with respect to the completeness, accuracy, or proper computational functioning of the financial model referred to in this memorandum. Fieldstone makes no representation as to the reasonableness of any assumptions made in preparing the financial model. Nothing contained in the financial model is or should be relied upon as a promise or representation as to future results or events.
The information contained in this document is confidential and the property of Fieldstone. It is made available to the Recipient strictly on the basis of the undertaking as to confidentiality given by the Recipient. It and any further confidential information made available to the Recipient must be held in complete confidence and documents containing such information may not be used or disclosed other than in accordance with the confidentiality undertaking without the prior written consent of Fieldstone.
Should any Recipient decline participation or not be selected to participate in the Project, the Recipient agrees that, at the request of Fieldstone, it will return this Document (regardless of the form in which it is maintained) and any notes, analyses and memoranda prepared by the Recipient or any of its advisors or representatives and all copies thereof to Fieldstone within any reasonable time stipulated by Fieldstone.
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Table of Contents
1. Executive summary ...... 5 1.1. Why cogeneration? ...... 5 1.2. Need for Support...... 6 1.3. Cogeneration Markets...... 6 1.4. What should be done in support of cogeneration? ...... 7 1.5. Implementation issues...... 8 1.6. Conclusion and recommendation...... 9 2. Introduction and scope of work ...... 12 3. Why cogeneration...... 14 3.1. Benefits from cogeneration...... 14 3.2. Need for support ...... 15 4. Cogeneration markets ...... 19 4.1. The international experience...... 19 4.1.1. The European Union ...... 20 4.1.2. The United States of America (“USA”)...... 23 4.1.3. Brazil...... 24 4.2. The South African market...... 24 4.2.1. The electricity market ...... 24 4.2.2. Cogeneration ...... 25 5. What should be done in support of cogeneration? ...... 26 5.1. Policy framework...... 26 5.2. Determination of Qualifying Cogeneration Technologies ...... 26 5.2.1. Projects Meeting Cogeneration Definition...... 27 5.2.2 Determining Project Eligibility for Proposed Financial Support Structures – Qualification Criteria ...... 29 6. Financial support mechanisms...... 36 6.1. Small Scale Projects...... 36 6.2. Large Scale Projects...... 36 6.2.1. Determining the supported price level ...... 36 6.2.2. Suggested structures...... 39 6.2.3. Contractual structures for price support ...... 41 7. Implementation issues...... 44 7.1. Regulatory issues ...... 44 7.2. Carbon credits...... 46 7.3. Project ownership...... 48 7.4. Applications, licensing and permitting ...... 50 7.5. Evaluation Methodology...... 52 8. Conclusions and recommendation ...... 53
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Glossary
Avoided cost The expected cost of providing new electricity at a particular point. This cost is based on the expected unit cost of the next power plant on the system and may also include the cost of transmission, distribution and losses up to that point.
BEE Black Economic Empowerment
CCL Climate Change Levy
CDM Clean Development Mechanism
CER Certified Emissions Reduction
CHCP Combined Heat Cooling and Power
CHP Combined Heat and Power
DEFRA The UK’s Department for Environment, Food & Rural Affairs
EIA Environmental Impact Assessment
EIUG Energy Intensive Users Group
EPC Engineer, Procure and Construct
ERPA Emission Reduction Purchase Agreement
Eskom The national regulated electricity utility in South Africa
EU The European Union
GHG Greenhouse Gas
IPP Independent Power Producer
LTSA Long Term Service Agreement
MWe Mega Watt electrical
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MWth Mega Watt thermal
NCS National Cogeneration Standard
NERSA The National Energy Regulator of South Africa
NIRP National Integrated Resource Plan
O&M Operations and Maintenance
PPA Power Purchase Agreement
PURPA Public Utility Regulatory Policy Act of 1978, enacted in the USA QI Quality Index
Type “I” Project A generation project meeting the definition supplied under section 5.2.1.2.a Type “II” Project A generation project meeting the definition supplied under section 5.2.1.2.b Type “III” Project A generation project meeting the definition supplied under section 5.2.1.2.c UK United Kingdom
USA United States of America
WHRS Waste Heat Recovery System
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1. Executive summary Following growing interest in increasing the amount of cogeneration on the South African system, the National Energy Regulator of South Africa (“NERSA”) has sought to develop guidelines for developing Regulatory policy which could allow for:
• Simplification of the process for developing, evaluating and implementing cogeneration projects
• Development of a workable financial structure for qualifying cogeneration projects
1.1. Why cogeneration? Given an increasing worldwide focus on conserving energy and diversifying the generation asset base, the development of a cogeneration sector in South Africa has been identified as a means of delivering potential energy efficiency, environmental and social benefits including:
• Energy efficiency gains through improvements in fuel conversion efficiency and the use of waste resources ;
• Environmental benefits from the possible mitigation of future environmental liabilities;
• Reductions in greenhouse gas emissions (CO2, NOX and SOX);
• Provision of effective additions to the South African electricity generation base;
• Decentralization of energy production;
• Environmentally beneficial technologies and project design could simplify Environmental Impact Assessment (“EIA”) permitting process;
• Supporting security of energy supply and the de-risking of existing generation asset base by broadening scope of fuels used in the supply of power;
• Mobilising private sector resources in the electricity generation sector;
• Possibility that cogeneration projects could act as means of mitigating the countrywide development and engineering skills shortage;
• Opportunities for creating employment and Black Economic Empowerment (“BEE”) in the industrial sector; and
• Encourage the uptake of new environmentally friendly technologies.
In South Africa the exploitation of potential cogeneration situations has been identified as a major opportunity to alleviate the growing capacity pressure on the electricity supply industry. In almost all cases the cogeneration solution can be brought to completion before any new base load plant.
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1.2. Need for Support Notwithstanding the benefits assumed to be available from cogeneration several obstacles have been identified as roadblocks that prevent projects from developing in the current market environment. The key variables, among others, cited in discussions with industry players include:
1. The current South African electricity market structure
The, de-facto, single buyer market model is seen as a limitation on private generation expansion generally given (i) the lack of an automatic route to market for generators, (ii) limitations on the ability of industrials to wheel electricity, (iii) no clear Regulatory framework under which Eskom could support cogeneration and (iv) the high cost of backup power
2. Current price of wholesale power
The current price of wholesale electricity in South African is cited as the single biggest factor inhibiting the growth of the cogeneration sector in South Africa. This is primarily a result of the wholesale price, (being the price which projects consuming power onsite would be prepared to pay for off-take from a cogeneration project), being below the level which would be required to make investment in generation economically viable.
Given however that the price of power supplied from Eskom is expected to rise significantly over the foreseeable future, one of the key recommendations in this report is that the focus on quantifying the ‘economic’ price of power be moved away from current prices and on to the cost of developing the next base load generating capacity in South Africa. In a single buyer model this effectively dictates the use of the avoided generation cost as determined by the latest NIRP, if available (as required by the Electricity Regulation Act of 2006) as the basis for determining the economic efficiency of future cogeneration projects
3 A historical lack of co-generation installations
Historically SA industry has relied on Eskom for electricity and the concept of co- generation is foreign to many South African industrial operations. The main reason for this attitude has been the cheap price of electricity.
1.3. Cogeneration Markets The level of Regulatory and market support for cogeneration is growing worldwide partly as a result of long acknowledged efficiency benefits, but also more recently as a consequence of:
• Emissions reduction laws and a consequent need to reduce dependence on carbon intensive generating capacity;
• Concerns over security of electricity supply and geopolitical concerns over fuel diversity.
The uptake of cogeneration technologies in the highly developed markets of the European Union (“EU”) and the United States of America has been varied and in some ways reflects the highly centralized nature of generation systems in these markets.
In the European Union cogeneration policies and support levels vary widely and this is reflected in the degrees of uptake from just under 50% in Denmark to under 2% in Greece. Recently however
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Within the USA, federal support measures in favour of cogeneration are formalised under the Public Utility Regulatory Policy Act (“PURPA”), and the uptake of cogeneration has been nearer 7.9% of total installed capacity and 4.1% of total electricity generated.
Brazil is currently seen as one of the most promising growth markets for cogeneration given its sugar resources and scope for biomass driven CHP. Recent auctions for cogenerated capacity in Brazil, and a law guaranteeing off-take produced bids for 1099MW of cogenerated power.
A survey of support measures in favour of generation employed globally include:
• Preferential feed-in tariffs for qualifying generation;
• Priority despatch and guaranteed off-take in non-competitive, regulated markets;
• Portfolio standards – legislating that a portion of all electricity supplied come from cogenerated sources; and
• Tax and Regulatory exemptions – especially in deregulated markets.
Within the South African market context the adoption of cogeneration technologies has been more modest at approximately 3.1% of total installed capacity1. Most of this capacity was also installed many years ago and as part of the industrial process constructed at the time. Discussions with industrial parties suggest that scope exists to move this up to as high as 10% of installed capacity from a wide variety of fuel sources including, waste flue gas recovery, waste heat recovery and waste fibre projects as the initially most promising technologies.
1.4. What should be done in support of cogeneration? The table below summarises the key suggestions contained in the guidelines as to the method for providing support measures to qualifying cogeneration projects in South Africa:
Component Suggested Approach
Underlying National Cogeneration Standard: Specify minimum portion of Regulatory Eskom total supply to come from cogenerated sources support
Qualifying plant 1) Determine cogenerator 2) Determine qualifying output: criteria status: • Geographic location • Economic efficiency • Project age – new project? • Size Refurbishment? • Energy efficiency (Minimum • Technology Type I, II or efficiency or QI for Type II III projects) • Reliability requirements
1 The 3.1 % is an estimation by Fieldstone: Total installed capacity in South Africa is 37000 MW. Cogeneration activity is 1150 MW, at Mondi, Sappi, Illovo, TSB, Tongaat Huelett, Samancor, Highveld, Mittel Steel, RB Minerals, Refineries, Sasol.
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Financial • A PPA with ESKOM Support Structure
Determination of • Based on qualifying output • In the short-term either: Financial level 1. Qualifying output priced at Support Level defined % of NIRP avoided cost or, failing that; 2. Modified auction with the avoided cost as a benchmark to be bettered
Contract All Plants structure • Bankable, long-term PPA with Eskom encapsulating supported price • Application of two-way metering for projects consuming power onsite
1.5. Implementation issues The Regulator will need to address the following issues, arising from the guidelines, in order to achieve a successful implementation of the cogeneration programme:
• Clarification of Regulatory framework – confirmation of the extent of NERSA’s Regulatory reach • Agreement on key unresolved principles from the guidelines: o Choice of energy efficiency measure for Type II projects o Agreeing a pricing structure for supported large-scale cogeneration projects o Delivering a draft standardised PPA contract • Determination on the roll-out of the cogeneration standard • Determination of the pricing scheme and benchmark o Methodology for calculating the avoided generation cost in the NIRP (current methodology is listed in the NIRP2 documentation and accepted as adequate for calculation of the NIRP3 avoided costs by the international experts contracted to develop NIRP3) The avoided cost consist of three elements: o Avoided generation cost o Avoided Transmission cost o Avoided Distribution cost o Choice of defined cost, modified auction or some other scheme • Consideration of the effects of a support scheme on the ability of cogeneration projects to source carbon credits through the Clean Development Mechanism (“CDM”) • Project ownership o Standalone IPP-type ownership to be encouraged
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o Given the opportunity for genuine skills transfer and the broadening of ownership of the industrial base, BEE opportunities in the sector should be promoted • Application, licensing and permitting - the possible process for developing cogeneration plants following on from the guidelines is detailed in the diagram below: Developing cogeneration projects (or any generation project for that matter) takes substantial development effort. This effort translates into substantial costs amounting to up to 3-5% of project costs. This includes various technical studies and even the EIA. In the case of large industrial companies the availability of development resources normally is not a problem, but will still have to be justified. BEE groups typically however do not have such resources either. There may therefore be a need to develop a financial support structure to further stimulate the initiation of projects in addition to the guidelines proposed above
Guidelines Guidelines Design project in Relative certainty of from project approval from lineDesign with guidelines project in NERSA before design NERSA line with guidelines
Known parameters Clearly define range of Determine project from guidelines: Project Design permissible projects Determine project financing and 1. Modified auction and Pricing requiredfinancing tariff and required tariff 2. Defined cost
Clarification Project submission Decision within on project Projectto NERSA submission defined timeframe specifics to NERSA
Approval by NERSA Approvalon cogenerator by NERSA statuson cogenerator qualifying statusoutput qualifying output Execution Clarification on project Execute contract specifics Project execution Project execution under agreed by ESKOM structures from by ESKOM guidelines
Ongoing contract Monitoring and Ongoing contract Cogeneration performance and Cogeneration Evaluation performance and oversight: NERSA monitoring: Eskom oversight: NERSA monitoring: Eskom
1.6. Conclusion and recommendation It is clear from the international experience and the above analysis that cogeneration can be quite complicated and technical. Generation is also not a core business of industry. Low electricity prices provide very little incentive for investment in the industry despite energy efficiency and significant environmental advantages. The uncertainty, bureaucracy and relative small benefits of utilising carbon credits are not enough incentive for industry to invest in cogeneration. See section 7.2.
South Africa is however running out of generation capacity and cogeneration has the additional the following advantages ( in addition to energy and environmental efficiency);
• Stations can generally be built quicker than a large base load plant;
• Stations can be constructed close to load avoiding transmission losses as well.
This makes the need for incentives to encourage cogeneration different to places where there is a over capacity. The main burden to overcome is the low historical electricity tariff. There is also a need to make the process simple and not bureaucratic and avoiding undue inference in the normal business of the industrial hosts.
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Although the original scope was to consider the use of the DSM fund to assist cogeneration projects or even suggest a separate fund this report has moved away from that type of approach due high administrative work load and perceived lack of independence and bureaucracy. This “subsidy” approach has been replaced by getting Eskom as a credit worthy off-taker to sign a standard PPA with aspiring cogeneration developers at an economic tariff that will be determined independently from time to time by the Regulator.
Based on the discussion in previous chapters the following guidelines are proposed:
Parameter Requirement
Definition of qualifying plant Type I, II and III as defined in section 5.2.1.
Energy efficiency Calculated energy efficiency in the case of type II plant. Type II plant will have to prove basic 2 efficiency as opposed to primary generation.
Green House Gases Plant should have demonstrable advantage over a base load coal fired plant that will be considered the base line reference plant
Allocation of capacity The Regulator to decide from time to time in accordance with the NIRP
Size of individual plant No minimum size but restricted in principle to 500MW where after specific approval may be sought
Location of plant Plant to be located in South Africa, but consideration may be given to plant in the region. Preference may be given to a plant that is located further away from traditional generation base in order to avoid transmission losses and increase quality of supply
Support Mechanism offered A PPA with Eskom. Terms of the PPA as set out in section 8.
BEE requirement The development to afford BEE equity and other participation opportunities in line with the appropriate BEE charters.
2 There is a strong suggestion that economics rather than energy efficiency should be the driving parameter qualifying the project.
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The salient features of the proposed PPA are discussed in Section 8. Pricing of the PPA to be determined by NERSA utilising avoided cost principles.
It is suggested that ESKOM, NERSA and the EIUG draft a standard PPA that can be used as a template for most if not all cases. This document will be the bedrock on which the support for new cogeneration is founded.
The pricing will be one of the critical items of the PPA. It is suggested that NERSA will determine the appropriate cogeneration pricing on a regular and independent basis as part of its normal pricing activities. Pricing will be based on the actual appropriate avoided cost of new generation in South Africa plus taking into account where the proposed plant is located as well as availability factors. It will also receive input from Eskom and industry in this regard before determining the applicable pricing. It is thought that this method will be more appropriate than an auction as most plants will come on line at different times and may have availability constraints that may affect pricing.
Implementation is discussed in detail in Section 7 below. It is anticipated that ownership will vest in either the industrial host or more likely in a separate project company that can be owned by an independent owner. Transfer and approval of ownership will be subject to normal license applications with NEWSA in terms of the Act.
It is further suggested that NERSA make funds available from the DSM fund to assist with the development costs of cogeneration plant. These costs will be refundable at commercial operation of the plant. It is suggested that a maximum amount of R5m be made available per project and that provision should be made for not more than 10 projects i.e. a fund of R50m. Applications to be made with NERSA when the application is made for the project and once the project is approved in principle funds can be released.
The proposed guidelines and their successful implementation based on a robust commercial PPA to the economic benefit of all parties should go a long way to alleviate the current need for new capacity in the country while at the same time utilising available scarce energy resources and sequestrating dangerous greenhouse gases. The establishment of a series of smaller plant should further stimulate the economy and also create substantial BEE opportunities.
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2. Introduction and scope of work The objective of the cogeneration policy of NERSA is to develop the cogeneration market in South Africa and contribute to the achievement of the energy efficiency targets of the government. Fieldstone has been retained by the National Energy Regulator of South Africa (“NERSA” or the “Regulator”) to provide assistance in the development of guidelines to support the development of a cogeneration sector in South Africa. The engagement of consultants in the development of cogeneration guidelines originates from the NER decision of 2004 to provide financial support for CHP and WHRS from the DSM fund currently administered by Eskom. The scope of the assignment was defined as: • Define the cogeneration technologies, classified as combined heat and power and waste heat recovery systems (WHRS), eligible for funding from DSM fund, in the context of the South African environment; • Provide qualification criteria (benchmarks) for approval of qualifying projects including, but not limited to maximum plant sizes, plant efficiencies, minimum power to heat ratios and environmental considerations such as GHG emissions; • Provide measures of efficiency for CHP and WHRS based on best international practice, with recommendations on relevant measurement and verification; • Recommend methods and tools, other than commercial generation expansion planning software, required for economical and financial evaluation of proposed projects as well as evaluation of the energy efficiency and GHG emissions; • Provide recommendations on ownership and transfer of ownership of cogeneration plants; • Provide recommendations on power purchase agreements including power purchaser, term and conditions of contract as well as the role of Eskom; • Establish the optimum portion of the capital expenditure for CHP and WHRS cogeneration projects that should be funded from DSM fund • Provide recommendations on specific licensing requirements of qualifying plants; • Provide considerations on performance monitoring of the plant (measurement and verification to ensure that the required performance of the plant is achieved); • Provide specific regulatory reporting requirements for cogeneration plant.
To this end presentations and meetings in respect of issues surrounding sector development have been held with key stakeholders, including NERSA, Eskom and the Energy Intensive Users Group (“EIUG”). In addition Fieldstone did primary desk top research on international best practice. Fieldstone and NERSA arranged three open meetings with the EIUG as well as Fieldstone meeting most of the members of the EIUG in separate one on one meetings.
Following on from this consultative and research process, this document has been drafted to enumerate principles and present ideas which can be used to guide the development of policy by NERSA to assist the growth of a cogeneration industry in South Africa. The adoption of suitable guidelines should allow for:
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• Simplification of the process for developing, evaluating and implementing cogeneration projects; and
• Development of a workable financial structure for qualifying cogeneration projects.
The document looks at the following issues considered to be relevant to the development of cogeneration guidelines in South Africa:
• Why cogeneration?
I. Benefits from cogeneration
II. Need for support
• Cogeneration Markets
I. The international experience
II. The South African market
• What should be done in support of cogeneration?
I. Policy framework
II. Determination of qualifying projects
• Financial support mechanisms
• Implementation issues
The guidelines have also been developed given the current situation in South Africa where existing oversupply in capacity has diminished and new capacity is being constructed following substantial and expected increased economic growth. As a result both the Regulator and Eskom are interested to harness all aspects of the economy that can contribute to improving the electricity supply security. The supply of electricity from cogeneration has been identified as a small but significant potential contributor. Eskom has set a target of achieving at least 900MW from cogeneration over the next five years if not more.
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3. Why cogeneration
3.1. Benefits from cogeneration The importance of energy efficiency
One of the key determining features of the social value of mechanical processes is the extent to which energy is fully utilised and wastage controlled. With this in mind, managing the efficiency of energy conversion, and controlling the loss of waste heat can have socially and environmentally beneficial consequences including:
o Using less fuel per unit of utilised energy product – increased productivity
o Producing fewer Greenhouse Gas (“GHG”) Emissions per unit of utilised energy product – decreased atmospheric pollution
o Potentially produce less environmentally damaging waste per unit of utilised energy product – decreased general pollution such as effluents and wastewater
The key feature of the above benefits, however, is that they are largely external to the party utilising or producing energy and as such the benefits of efficient energy conversion tend to accrue primarily to society and the economy at large rather than to individual producers.
This is especially true given primary motivations, such as the production of industrial goods at lowest cost, in which many industrial processes will tend to emit either usable heat or waste as there may not be any other economically feasible way of disposing of the waste.
Similarly centralized power generation, motivated by the production of electrical energy at the lowest cost, is often an inefficient converter of fuel into electrical energy with much of the initial potential energy being lost as heat either through the generation process or as transmission losses.
Cogeneration
Cogeneration, involving either the (i) decentralized production of both electricity and usable heat from primary fuel (CHP) or (ii) the production of decentralized electricity from waste heat or unutilised industrial waste fuel offers a logical means of mitigating wasted energy and harnessing the environmental benefits of optimised industrial production and electricity generation
As such the Regulator has identified the development of cogeneration projects as one of the best possible means of meeting the aim of increased energy efficiency. The development of a cogeneration sector could provide the following benefits among others:
• Energy efficiency gains through improvements in fuel conversion efficiency and the use of waste resources ;
• Environmental benefits from the possible mitigation of future environmental liabilities;
• Reductions in greenhouse gas emissions (CO2, NOX and SOX);
• Provision of effective additions to the South African electricity generation base:
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o Modular, decentralized nature of cogeneration allows for capacity to be added in step with demand rather than in the ‘lumpy’ form of large power stations;
o Bring capacity online in reduced time frame versus large utility-scale power plants;
o Localised inside the fence generation – mitigating demand;
o Increased reliability (by risk diversification) and quality to the end user – decreased dependence on centralized power system;
o Roll-out of projects can ease peak demand allowing for the reduction of reserve margins;
• Decentralization of energy production:
o Easing of grid congestion at the transmission level with a reduced and deferred need for transmission and distribution investment;
o Ability to serve customers better than centralized production given location close to source of demand and ability to tailor output;
• Environmentally beneficial technologies could simplify Environmental Impact Assessment (“EIA”) permitting process;
• Mobilising private sector resources in the electricity generation sector;
• Supports security of energy supply and the de-risking of existing generation asset base by broadening scope of fuels used in the supply of power;
• Possibility that cogeneration projects could act as a means of mitigating the countrywide development and engineering skills shortage;
• Opportunities for creating employment and Black Economic Empowerment (“BEE”) in the industrial sector.
• Encourage the uptake of new environmentally friendly technologies
The rationale for these guidelines is to find practical means of accessing the benefits described above by supporting the development of the cogeneration sector in South Africa.
3.2. Need for support Given the benefits which could be delivered from the development of a cogeneration sector in South Africa the obvious questions arises as to why the sector has not developed significantly to date. The following reasons have been suggested from discussion with stakeholders as possible current limitations on the development of the sector:
• Electricity market structure;
• Current (low) price of wholesale power;
• Lack of transparency in the application and implementation process for project developers;
• Perception that current process is overly bureaucratic;
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• Initial project development costs coupled with no ultimate certainty of a route to market tend to drive away scarce corporate capital;
• Variations in cost of capital amongst project developers are a seen a key feature of the current means of determining the required offtake price;
• Required payback period for industrials typically shorter than that of power generator increasing upward pressure on required prices;
• Development of cogeneration projects seen as non-core by industrials.
Of the above, the biggest reason cited as limiting the growth of cogeneration is the current electricity market structure and the accompanying low level of wholesale electricity prices. Even though electricity prices are set to rise in real terms over time from current low levels it will still take substantial time for this happen given the large installed existing low cost base. These issues are examined in more detail below.
Market structure
South Africa has a de facto single buyer model for the electricity market. Eskom generates about 93% of all electricity. The remainder is generated by historically installed municipal and industrial plant, most of which is older than twenty years and in many cases as old as forty years. No new entrant is likely to enter and produce electricity at lower prices than Eskom. Access to the grid is also an issue as wheeling tariffs are not transparently available.
Within the current single buyer model the following challenges exist for cogenerators seeking to develop projects:
• Only one, non-automatic route to market for grid-exported electricity;
• Limited ability for large industrial consumers to wheel power between load centres;
• Commercial and negotiating framework. At present no clear framework exists, which outlines the ability and parameters under which Eskom can contract for cogenerated power. In particular this means that Eskom has no clear means of determining whether and what level the Regulator will support recovery of its cost of sourcing cogenerated power. This has necessitated a lengthy and costly process of negotiation between project developers and Eskom and between Eskom and NERSA
• High price of backup power based on maximum demand formula seen as being onerous to on-site distributed generators
Prices
For potential cogenerators the limiting factor as to whether they develop projects will be whether they are able to earn sufficient return on their invested capital. For cogenerators there are ultimately two possible means of generating returns on project capital:
1. Sales revenue from electricity generated and on-sold or costs saved from energy not bought from Eskom or local authorities; and
2. Sale of co-products such as steam for CHP projects, or the reduction of co-product costs from alternative sources
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Of these factors, electricity sales3 (or avoided purchases) are far and away the biggest factor determining the economic viability of a new cogeneration project. As such, available prices, both for electricity sales and internal consumption, are seen as the key single determinant of project success.
As a result of the lack of a clear framework, the wholesale price (defined as the tariff which industrials pay for their electricity supply from Eskom) is seen to be the current comparator against which supply from cogenerators could be considered economic to Eskom. Critically this price (around 16 cents/kwh) is currently substantially below the per-unit charge required to develop, finance and operate any new generation plant, whether cogenerated, or otherwise.
As the wholesale tariff is essentially determined as a return on Eskom’s approved cost base the current pricing level is consistent with past investment decisions and the highly depreciated nature of Eskom’s generation asset base. The effect of this feature, however, is that any new generator, including Eskom, is faced with the prospect of having to recover per-unit costs which are substantially above current wholesale prices when the next investment in new capacity takes place.
Given the expected levels of investment in new capacity which are understood to be required the general industry expectation is that wholesale prices in South Africa will have to rise to include the un-depreciated capital cost of developing new generation units by Eskom and others.
The question of the economic viability of adding cogeneration capacity needs to be understood in the above context. Adding cogeneration will therefore, in addition to the social benefits mentioned previously, make economic sense, if the cogeneration capacity can be added at a per-unit cost which is lower than that which could be achieved by the next new units added to the system.
This concept is illustrated graphically below :
c/kWh Cost of wholesale power – SA system (Line B)
Net avoided cost of Eskom next best alternative plant (Line A) C.
Potential economic B. benefit versus next best option A.
Time Figure 2 – Project long-run marginal costs comparison Given the above analysis and an understood need for new generation (without considering energy efficiency and environmental benefits) it would make economic sense to provide support to prospective generators, such as project B, in the yellow zone of figure 2 as these projects have per- unit costs which are lower than the next best alternative base-load plant.
3 Especially as the initial roll-out of plants is expected to be from primarily non CHP plant types
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It would not make pure economic sense to support a project such as Project C given its high per- unit costs. Such projects however could possibly be justified as supportable given other non-priced benefits such as energy efficiency, GHG reductions, technological innovation, security of supply, asset base diversification.
Additionally there are already projects, like Project A above, which have significantly valuable co- products (such as steam), which are economically viable in the current environment.
The initial purpose of the proposed guidelines is only to discuss support for projects which are already economically viable (Projects A and B above) when compared to the next best alternative project available to Eskom as the incumbent generator although this will need to be reviewed in the light of the chosen support mechanism.
It should be noted that the above analysis is predicated on the assumption that a single buyer model is in place in the South African electricity sector and that, for the foreseeable future, Eskom remains the developer of preference for new baseload generation capacity. In making this assumption it will be appropriate to use Eskom’s avoided cost and not the market equivalent price as the hurdle rate for economically efficient cogeneration.
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4. Cogeneration markets
4.1. The international experience Additional drivers for cogeneration
The potential benefits from developing cogeneration have, for several years, been an acknowledged focus of electricity Regulators and market developers around the world. In addition to the normal benefits of cogeneration interest in developing this technology type has increased in recent years and, especially in highly industrialised countries, as a result of:
a. Emissions reduction laws and the creation of environmental markets
Following the Kyoto protocol, developed countries, which have ratified the agreement, are being forced to reduce emissions to 1990 levels. Given the proportion of overall emissions attributable to power generation, focusing on forcing this sector to reduce emissions has resulted in governments looking at measures to internalise the cost of greenhouse gas emissions. This has been achieved primarily by rationing the amount of emissions that generators can emit in a given period, with rights to emit become tradable instruments to encourage technology shifts from highly emissions intensive technology to less emissions intensive technologies. Cogeneration proves an excellent candidate technology option in this environment, given (i) its overall energy efficiency features, (ii) ability to be quickly deployed and (iii) short-term costs and limitations on shifting between existing larges-scale generation types.
b. Concerns over fuel diversity and security of supply
With the increasing globalisation of commodity markets, strong economic growth from China and India, and increasing socio-political volatility in the Middle East, the geopolitical risks in the fuel market have increased. This has brought with it an increasing risk of supply crunches, price spikes and the concomitant risk of blackouts, higher electricity prices and decreased economic performance. This coupled with the environmental limitations of basing future generation investment around emission intensive coal is forcing Regulators to seek alternatives to overdependence on one type of fuel source for generation. Cogeneration with its multi-technology, multi-location and multi-fuel options is seen an ideal candidate for mitigating this risk.
The key feature of the above drivers is that they are by and large external supply constraints on energy markets, which Regulators have limited power to influence. For this reason demand side management, such as encouraging industry to use electricity more efficiently and produce power on-site are seen as the best tools currently available to Regulators.
In light of additional, pressing, benefits from cogeneration many countries around the world have chosen to introduce and strengthen measures to support cogeneration and distributed energy technologies with significant variation in the levels of success achieved.
In terms of discussing support measures and the degree of uptake of technology, the following markets have been analysed4:
4 Much of the market summary analysis comes from www.localpower.org, the website of the World Association for Decentralized Energy in its 2006 world survey.
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a. The European Union
b. The United States
c. Brazil
4.1.1. The European Union The uptake of cogenerated and decentralized electricity generation in the European Union (“EU”) varies5 widely from just under 50% in Denmark to under 2% in Greece.
The share of total capacity from cogeneration in the EU member states is shown below:
60 49.1 50 37.5 38 40 29.9 30 21.5 16 17.1 17.5 20 13.6 11 7.9 9.7 9.8 10 5.9 6.8 7.4 7.5 7.8 10 4 5.4 1.9 2.5 0 UK Italy Spain Czech Latvia Greece France Ireland Poland Estonia Austria Finland Sweden Belgium Portugal Slovakia Slovenia Denmark Germany Hungary Lithuania Netherlands Luxembourg
Cogeneration % Share of Total Generation
Figure 3 – Share of electricity from cogenerated sources in the EU In part the above range represents differences in (i) the applicability of heating technology between the northern and southern countries, (ii) the support given by Regulatory bodies and (iii) the openness of electricity markets.
Summaries of some of current and past policies applied in support of cogeneration in EU are shown below6: Country Cogeneration support policies Austria • Transmission System Operator required to give dispatch priority to CHP supplying the heat network Belgium • Fixed minimum prices for electricity from CHP • Grid operators should strive to deliver green and CHP electricity • CHP has priority grid access • Distribution tariffs to be transparent and
5 Sourced from Eurostat – http://epp.eurostat.cec.eu.int : “Statistics in Focus” 3/2006 6 Primarily sourced from “An Examination of the Future Potential of CHP in Ireland, A Report for Public Consultation, Prepared by Irish Energy Centre” www.irish-energy.ie/uploadedfiles/InfoCentre/chpreport.pdf
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Country Cogeneration support policies reasonable • Emergency back up electricity tariffs to be moderate • Funding for CHP associations • Fiscal abatement for investment in energy efficiency including CHP projects Czech Republic • Mandatory application of CHP when cost- effectiveness is proven in combination with a stipulated energy audit • preferential interest rate loans Denmark • Compulsory purchase of electricity from CHP • Obligation on municipalities to ensure CHP projects are developed • Planning guidelines for CHP • Priority of dispatch for CHP electricity • Financial subsidies for electricity production • Grants for district heating networks • Green tax on trade and industry which is returned in the form of grants and subsidies France • Long term power purchase agreements • Compulsory purchase of electricity from CHP up to 12MWe Germany • CHP exemption from fuel taxes • Grid operator required to purchase electricity from CHP at a fixed bonus • Favourable use of system rates Italy • Compulsory purchase of electricity from CHP • Industrial gas prices lower than domestic prices • Taxation for CHP gas is reduced in proportion to electric efficiency • CHP exempt from carbon tax • Priority of dispatch Luxembourg • Favourable price paid to CHP electricity
Netherlands • Favourable rates for CHP electricity • Special tariffs for natural gas for CHP
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Country Cogeneration support policies users • Financial support Portugal • Government financial support for new CHP plants consisting of reimbursable loans, interest-free up to 20% of investment costs • CHP plants can receive assistance of between 15% and 25% of the capital investment Spain • Spilled electricity is paid a premium • Promotion of third party financing • Legislative adaptations • Provision of technical advice • RTD programmes UK • Enhanced Capital Allowances • Exemption from Climate Change levy • Level at which generation license is required has been raised to 100 MWe. • Level at which supply license is required has been raised to 500 kWe. • Capital grants for small-scale CHP (<1MWe) • The CHP Feasibility Programme provides grants up to 75% of the cost of a detailed • feasibility study grants for projects of 1-20 MW
Given the desire to promote cogeneration technology, and to harmonise the support of cogeneration within the EU, the European Parliament has also enacted a CHP directive7. The directive provides for:
a. The Establishment of EU wide efficiency values for cogeneration;
b. Member states to establish a guarantee of origin system for CHP generated electricity;
c. Member states to analyse and report on national potential for cogeneration;
d. Support schemes for cogeneration must be based on useful heat demand and energy savings; and
e. Member states to:
i. Ensure that cogenerator producers are able to access transmission and distribution networks;
7 DIRECTIVE 2004/8/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 11 February 2004 - http://europa.eu.int/eur-lex/pri/en/oj/dat/2004/l_052/l_05220040221en00500060.pdf
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ii. Establish clear rules for access to networks; and
iii. Ensure that there are published tariffs for top-up and back-up energy for cogenerator producers if there is no competitive supply market.
4.1.2. The United States of America (“USA”) The uptake of cogenerated and decentralized capacity in the USA currently stands at approximately 7.9% of total generating capacity and 4.1% of total electricity generated. Cogeneration is supported through: a) The Public Utility Regulatory Policy Act of 1978 (“PURPA”) of 1978, which i. Obliges regulated utilities to purchase output from qualifying cogeneration facilities at up to the utility’s avoided cost, ii. To provide cogenerators with non-discriminatory access to back-up power; and iii. Exempts cogenerators from the state public service commission or the Federal Energy Regulatory Commission. b) Exemption for most cogenerators from the Public Utility Holding Company Act (“PUHCA”) c) State level Renewable or Advanced Energy Portfolio Standards mandating a certain level of power output to be supplied by targeted technologies have been enacted in 18 states
The US Department of Energy and the Energy Policy Administration have recently adopted aggressive targets for cogeneration and this together with fears of rising, commodity prices, and national security fears about system vulnerability have led to a recent upsurge new cogeneration capacity. The graph below8 shows cogeneration capacity growth in the USA over the last 25 years:
Figure 4 – Growth in cogeneration capacity in the USA
8 Source US Department of Energy 2005
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4.1.3. Brazil The uptake of cogenerated and decentralized capacity in Brazil currently stands at approximately 4.4% of total generating capacity and 3.3% of total electricity generated. Cogeneration is supported through:
a) Law 10848 (decree 5163), which guarantees a market for CHP and decentralized generation At present Brazil has one of the most centralized electricity infrastructure systems in the world with over 92% of power being generated in this way. Electricity is primarily generated at remote hydro power stations and transported over vast transmission networks marking the regionalisation of generation capacity as one of the key drivers for the growth of cogeneration.
In 2005 Brazil ran a highly successful auction for cogeneration and decentralised capacity with 1099MW in successful bids making Brazil one of the fastest cogeneration markets in the world. This market is also forecast to continue growing at record pace given:
• Abundant opportunities for biomass fired generation from Brazil’s sugar industry
• Diminishing reserve margins, increasing power demand and a need for reliable energy supply
• Opportunities for Clean Development Mechanism based cogeneration projects
4.2. The South African market
4.2.1. The electricity market Supply and demand Issues
The power generation market is South Africa is currently quite dynamic after many years of little activity. South Africa and the region are both running out of surplus capacity. In particular South Africa is running out of peak load capacity and hence the need for peaking type stations, particularly at the coastal centres that are far removed from the base load power stations.
Power market demand / supply balance
Eskom supplies 93% of all power in South Africa of which most is generated from coal plants in Mpumalanga province.
Eskom is facing a challenge to meet demand growth. Annual demand growth in recent years has been at 3.5% year on year; economic growth has however accelerated to almost 6% per annum and it is expected that electricity demand growth will follow. In July 2004, new record peak demand was registered of 34,156 MW – 6.98% or 2,228 MW higher than the previous year; depending on the severity of the winter a new peak demand is expected in 2006. Power cuts and interruptions have become more frequent and are expected to increase in the short term.
In relation to new capacity it is expected that:
• Current surplus peaking generation capacity in South Africa will start to run out by 2006/07;
• New/additional peaking generation capacity of 2,500 MW will be needed between 2006 and 2010;
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• Current surplus base load generation capacity in South Africa will run out by 2010/11;
• The lack of adequate spinning reserve [energy supply assurance] is already decreasing the international competitive position of South Africa as an electricity intensive industry base;
• Current surplus base load generation capacity in South Africa will run out by 2010/11;
• It is expected that between 1000-2000MW of new capacity needs to be come on line every year starting about 2007.
The growing need for power is exacerbated by the fact that the existing mainly coal fired stations will be aging and need to be replaced at the same time as demand is expected to expand and capacity is reached. After 2020 most of the existing stations need to be replaced. Furthermore, the relatively newer power plants require considerable additional capital expenditures after a lifetime of 20 years in order to operate for another 10 to 20 years.
It cannot be expected that the current coal fired power stations can be replaced by the same carbon intensive form of power generation. Under the current international emission regulation in the light of global warming it is obvious that new investments should be accompanied by emission reductions measures, cleaner techniques or other fuels.
Eskom’s capital investment framework outlines that 10,000 MW of additional capacity is needed by 2014. Current expansion plans are approved by the Regulator in terms of the NIRP (2) that was completed in 2004. A new NIRP (3) is expected early in 2007 which is expected to confirm an increased demand growth following Governments increased economic growth targets leading up to 2010 and beyond.
4.2.2. Cogeneration Given (i) the benefits identified from cogeneration and the (ii) expected need for new capacity, cogeneration offers a logical, timely means of bringing new capacity online.
To this end Eskom has announced an internal resolution to support the development of 900MW of new cogenerated capacity over the next 5 years.
Fieldstone research indicates that cogeneration currently accounts for approximately 3.1% of electricity generation in South Africa.
Based on discussions held with EIUG members, there is further scope for the expansion of cogeneration capacity up to around 10% of installed generation capacity. Of particular interest and potential benefit is the range of project options identified within the EIUG. These include:
• Waste flue gas recovery;
• Waste heat and fuel recovery;
• Fuel swapping; and
• Waste fibre:
o Sugar industry bagasse; and
o Pulp and paper waste wood products.
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5. What should be done in support of cogeneration?
5.1. Policy framework As outlined in the preceding section the development of a cogeneration sector in South Africa could deliver significant social and environmental benefits and could contribute to the achievement of the energy efficiency target of the Government. When coupled with the challenges facing potential cogeneration projects a strong case emerges in favour of a national policy framework to support the development of the sector.
National Cogeneration Standard (“NCS”)
It is proposed that the Regulator enact a policy, endorsed by DME, in support of cogeneration through the development of a National Cogeneration Standard. This standard would determine that:
1. The development of cogeneration in South Africa has the potential to deliver environmental, energy efficiency and social benefits and should be supported by regulation;
2. The development of a cogeneration sector should proceed in a rational economic manner and that consequently the cheapest, quickest to deliver projects should be targeted first;
3. As a condition of licensing, a minimum portion of electricity output on a year-by-year basis, should be sourced by Eskom from qualifying cogeneration plants;
4. Both the long term contracting costs as well as ancillary costs to Eskom, as the obligated party, of sourcing qualifying cogenerated capacity be fully recoverable;
5. Procedures for pricing power to be supplied by cogenerators should be enacted; and
6. Standardised contracting procedures are enacted to ensure transparent cost-effective treatment for potential developers.
The above proposal would be consistent with a single-buyer model, would remove the uncertainty surrounding capacity to contract with cogenerators and would also be consistent with best practice internationally in terms of specifying portfolio standards for beneficial technology. Additionally the above proposal could be configured to meet Eskom’s stated objectives of developing 900MW of cogeneration capacity over the next 5 years.
Depending on the implementation structure such a standard could also serve as an enabler for the provision of financial support to qualifying generators. The determination of technologies and output to be covered by the NCS as well as possible financial support structures which could be enacted to ensure performance under the standard are the aim of the remainder of this document.
5.2. Determination of Qualifying Cogeneration Technologies Projects to be covered by the guidelines (and ultimately under any NCS) and, therefore, possibly eligible for financial support will be determined via a two-step process namely:
1) To what extent does the project design meet the definition of a cogeneration project? – Broad definition
2) Should it be covered by the proposed financial support structures? – Narrow qualification
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5.2.1. Projects Meeting Cogeneration Definition In order for a project to meet the definition of a cogeneration project (“cogenerator status”) the Regulator will apply the following evaluation criteria:
1) Is the project a new generation project located in South Africa?
Some industrial companies have subsidiaries in neighbouring counties like Swaziland and Mozambique that have significant cogeneration potential. These counties are also currently dependent on imports from South Africa. The question might therefore rightfully be raised whether cogeneration projects in those circumstances should be supported by the South African Regulator.
However, the scope of the Regulator is currently limited to South Africa and therefore it is recommended that only South African based or South African regulated projects producing electrical power, which is in turn consumed by either an industrial client and/or exported onto the relevant distribution or transmission network, will be considered as eligible for cogenerator status. [International projects of merit may however be considered from time to time.] The Electricity Regulation Act of 2006 gives the NERSA the mandate to issue licenses for export/import of electricity. (Chapter III of ERA 2006, Clause 8).
Additionally only new projects, adding generation capacity, or significant refurbishment projects, will be considered eligible under the programme.
In this way cogenerator status is intended to be limited to planned generation or refurbishment projects, which will increase generating capacity, rather than other forms of demand reduction or energy efficiency projects.
2) Is the electricity produced by the project a co-product of an underlying industrial process?
In order for a project to qualify for cogenerator status the electricity produced by the project will need to be a co-product, by-product, waste product or residual product of an underlying industrial process. For practical purposes the following types of projects are proposed as pre-qualifying for cogenerator status:
a) Projects utilizing process energy which would otherwise be underutilized or wasted - Type “I” projects (WHRS):
These would include but not necessarily be limited to the following project types:
a) Projects utilising waste heat from an industrial process as the primary energy source to generate electricity - Waste Heat Recovery Systems (WHRS)
b) Projects utilising waste or unused fuel, of a non-renewable nature, produced as a direct output of the underlying industrial process, as the primary energy source to generate electricity. e.g. projects burning waste flue gas to generate electricity
b) Primary fuel based generation projects which produce, as part of their core design, other usable energy in addition to electricity – Type “II” projects (CHP)
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These would include but not necessarily be limited to the following project types:
a) Combined Heat and Power (CHP) projects where in addition to electricity the project produces consumable heat e.g. projects producing process steam or district heating type projects
b) Trigeneration or Combined Heat, Cooling and Power (“CHCP”) projects where in addition to usable heat the project produces usable cooling via absorption cycles. For measurement purposes, and given that the cooling is produced via heat utilisation, this would be treated the same way as a) above
c) Renewable fuel based projects, where the renewable fuel source is both (i) the primary source of energy used for generation and (ii) a co-product of an industrial process – Type “III” projects
These would include, but not necessarily be limited to the following project types:
a) Projects utilising fibrous waste as the primary energy source to generate electricity e.g. bagasse from the sugar industry, or forestry waste from the paper and pulp industry The Government is developing different financial support for Renewable energy projects including bagasse and waste forestry. Therefore to avoid duplication these projects may be excluded from the cogeneration financial support scheme. In no case should projects receive more than one support mechanism.
b) Projects utilising wastewater as the primary energy source to generate electricity. This project type should be incorporated under Type II above.
c) Project utilising solid waste as the primary energy source to generate electricity. This project should be incorporated under Type II above.
It is intended that as part of their submission to the Regulator, projects will indicate whether they wish to be classified as a Type “I”, “II” cogeneration project, together with the intended fuel to be used as the basis for qualification. The final project classification will then be made by the Regulator.
Projects falling outside of the categories described above may still be eligible for cogenerator status but will need to be evaluated on a case by case basis by the Regulator with the key criteria for qualification being:
a) Principal fuel source – is this a co-product of an industrial process or a primary fuel?
b) Project output – generation only or other usable energy?
c) Underlying energy and environmental efficiency of the project
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5.2.2 Determining Project Eligibility for Proposed Financial Support Structures – Qualification Criteria Projects achieving cogenerator status, as defined in section 3.1, will then be evaluated on a detailed project specific basis to see on what basis and to what degree the applicant project would qualify for the proposed financial support envisaged under these guidelines. In order for the projects to be considered eligible for financial support (“qualifying cogenerators”) the Regulator will consider the following criteria: a) Economic efficiency The primary criteria for any cogeneration project to be considered eligible for financial support, in the initial stages of the NCS, will be its economic efficiency. In the context of these guidelines, economic efficient projects will be those projects whuch all-in, levelized, unit avoided cost of generation (“net avoided cost”) is lower than the next best alternative baseload plant which could be brought onto the system by the incumbent generator (Eskom). In this way projects coming in below the incumbent net avoided cost of base load generation will provide a direct economic benefit to end consumers by way of bringing generation onto the system at a lower cost than what could have been achieved in a non-cogeneration scenario. The mechanics for pricing the level at which cogeneration is to be supported are detailed in Section 6.
Project Types -I and II-can be considered ‘low-hanging fruit’ from a project development perspective given their presumed low-cost fuel source and the existence of waste processes onto which generation can be added relatively quickly and cheaply. Given the suggested terms of the Standard the NCS will likely target these types of projects first and once exhausted the applicability of the economic efficiency criteria will need to be revisited. b) Size For the purposes of determining eligibility criteria, and applicable financial support structures it is desirable to classify prospective cogeneration projects by size. The table below shows the suggested classification of projects according to generation output:
Size Classification Covered by guidelines < 1MW Micro-cogen Yes 1MW - 10MW Small Yes 10MW - 150MW Large Yes 150MW + Utility scale Yes
It has been suggested to limit the size of projects to 500MW as it is considered that beyond this size the project really becomes a fully blown IPP. c) Energy efficiency In principle well-designed cogeneration projects should provide direct energy efficiency benefits versus the status quo of energy either wasted or underutilised in industrial processes. The task for the Regulator and the principle to be enshrined in these guidelines is to ensure that projects are sufficiently energy efficient to qualify for cogeneration specific financial support.
In determining the correct approach for ensuring sufficient levels of energy efficiency it is useful to distinguish projects by (i) size and (ii) project type
Project Size Given the limited scale of smaller cogeneration projects it would be undesirable to impose energy efficiency requirements across all project size categories. With this in mind the following table details the correct energy efficiency criteria to apply based on project size:
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Size Energy Efficiency Criteria Applied? Micro-cogen Exempt Small Exempt Large By Project Type Utility scale By Project Type
Type I and Type III - Non-Primary Fuel Based Projects Type I and Type III projects, which do not rely on an outside primary fuel source for the majority of their output should by definition deliver energy efficiency benefits as they utilise an essentially free fuel source (e.g. heat, gas or renewables) which would otherwise be underutilised.
For these types of projects the importance of measuring energy efficiency is to ensure that the energy converted through fuel usage (generation) exceeds the energy expended on fuel collection.
There exists the extreme unlikelihood that a project would be economically viable if it expended more energy in fuel collection than it gained through fuel usage. This fact coupled with the difficulty of measuring the net energy gain mitigates in favour of a subsidiary principle being applied to Type I and Type III. This principle would rest on economically efficient projects qualifying by definition as energy efficient.
Type II - Primary Fuel Based Projects For Type II projects energy efficiency is arguably of far greater importance than for Type I and Type III projects. This is a consequence of Type II projects using a primary fuel source and spreading production across more than one form of useable energy. In this way it would be difficult to apply a subsidiary principle as, by way of example, plants of this type may be economically efficient producers of electricity but may produce heat at a very uneconomic rate. This could result in the overall process being less efficient than producing power and heat separately with the concomitant risk for the Regulator that it provides financial support to a cheap source of power and in so doing ends up subsidising inefficient heat production.
The key issue for the Regulator is thus to find a means of ensuring that Type II projects produce a net energy gain from the cogeneration of usable energy versus using the same fuel input in separate production processes to produce an equivalent level of usable energy.
International experience in resolving this issue as well as quantifying the ‘right’ required level of energy gain has proven to be a non-trivial, engineering intensive task with reams of literature dedicated to suggesting the right approach. This also reflects the fact that these ‘classic CHP’ type projects offer the widest scope for adoption as well as potentially delivering the greatest possible energy efficiency benefits given their ability to be deployed in utility scale applications.
Given the complexities in quantifying the inter-relationship between heat and power it is suggested that the Regulator look for the simplest means possible of implementing a monitoring scheme to ensure sufficient energy efficiency.
Two international approaches are presented as possible best Regulatory practice:
1. Definition of a minimum overall efficiency level underpinning support – minimum efficiency approach
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2. Quality Index approach
Both of the suggested approaches are supported by extensive international research and could be used as bases for the evaluation of Type II projects in South Africa
Minimum efficiency approach
The EU CHP directive determines the calculation of overall energy efficiency from cogeneration as:
“the annual sum of electricity and mechanical energy production and useful heat output divided by the fuel input used for heat produced in a cogeneration process and gross electricity and mechanical energy production”
In the above calculation efficiency is calculated on the basis of the net calorific value of fuels
Under the directive, the level of qualifying electrical output from the facility is then 100% of total output if the overall energy efficiency level is at or above 75%-80% depending on the cogeneration technology in use.
For efficiency levels below this range the following formula is suggested under the directive to determine the qualifying electricity from the cogenerated process:
Figure 5 – calculation of electricity from cogeneration from EU CHP directiv9 For the above calculation the directive suggests using the actual power to heat ratio of the cogeneration unit. In the event that the actual power to heat ratio is not known or easily determined then the directive goes on suggest the use of the following default set of values by technology type:
Figure 6 – reference power- to-heat ratios from EU CHP directive This approach has the virtue of being relatively simple to apply and is supported by extensive research and implementation. It does, however, suffer from the requirement to set arbitrary
9Source EU CHP directive annexes: http://europa.eu.int/eur-lex/pri/en/oj/dat/2004/l_052/l_05220040221en00500060.pdf
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Quality Index approach
The monitoring and evaluation method adopted in the United Kingdom and administered by the Department for Environment, Food & Rural Affairs (DEFRA) offers an alternative means of identifying ‘Good Quality CHP’10 and operates by looking at the net energy efficiency gains from both heat and power in CHP schemes as well as offering standards and techniques for applying the definition. Projects qualifying as ‘Good Quality CHP’, under the scheme, receive exemptions on qualifying output from the Climate Change Levy (“CCL”) as a means of providing financial assistance to energy efficient cogeneration.
The scheme works by defining a Quality Index (“QI”) as an indicator of the energy efficiency and environmental performance of a CHP scheme, where the QI is defined11 as:
QI = (X * ηpower) + (Y * ηheat)
Where:
• X = coefficient related to alternative power supply options and reflecting the cost and relative environmental benefits of alternative supply options e.g. larger schemes have a lower x and renewable fuel schemes have a higher X
• Y = coefficient for heat generation, related to alternative heat supply options. Generally this is a constant value under the UK scheme.
• Power Efficiency (ηpower) = the total annual power output divided by the total annual fuel energy input
• Heat Efficiency (ηheat) = the total annual heat output divided by the total annual fuel energy input.
Given the above Good Quality CHP schemes are defined as having a power efficiency of greater than 20% and a QI of greater than 100.
The reference values for X and Y under the UK scheme are detailed below:
10 See www.chpqa.com for more details. The full standard can be found at: https://www.chpqa.com/guidance_notes/documents/Standard_-_FINAL_VERSION.pdf 11 Sourced from “EU ETS PHASE II: TREATMENT OF CHP” - A report given to DEFRA by ILEX Energy Consulting in August 2005
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Figure 7 – values of X and Y under QI scheme administered by DEFRA12 In general the calculation of the QI is based on annual self assessment by generators with the CHP Quality Assurance programme administered by DEFRA providing oversight as well as extensive and detailed guidance notes to cogenerators to guide them in applying the standards. d) Qualifying electrical output The explicit aim of the guidelines is to support cogeneration and therefore it is necessary to determine the extent of output from projects with cogenerator status which would qualify for financial support. Again it is useful to address this issue by project type.
Type I and Type III - Non-Primary Fuel Based Projects For Type I and III projects the aim in determining qualifying output is to ensure that a sufficient portion of the project output, on an annualised basis, was generated from the fuel sources underlying the project classification and which would then allow the project to receive support as a cogenerator rather than as an IPP. Balancing this requirement is the need for the project to achieve minimum levels of reliability and availability.
In the case of some Type I and Type III projects there may not be sufficient qualifying fuel available to allow the projects to operate to the necessary reliability and availability levels. In the interests of ensuring quality and security of supply it would therefore be desirable to allow these projects to utilise alternative, primary, sources of fuel to generate electricity.
In the initial instance it is anticipated that the entire output of Type I and projects be eligible for the proposed financial support if a total of two-thirds of the fuel (on a net calorific value basis) used in
12 Source: https://www.chpqa.com/guidance_notes/documents/Standard_-_FINAL_VERSION.pdf
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For projects using less than the specified level of qualifying fuel and therefore utilising an excess of primary fuel sources in generating power, the following tapering formula will apply in determining qualifying output:
% of Qualifying Output = 1.5 x (% Qualifying Fuel)
By way of example the above formula will give 100% qualifying output if the qualifying fuel level is 2/3 of the total and 75% qualifying output in the event that the qualifying fuel level is 50% of the total fuel used
Type II - Primary Fuel Based Projects
For Type II projects the level of qualifying output will depend on the energy efficiency evaluation scheme chosen: Minimum energy efficiency approach The method for calculating qualifying electrical output is as determined under Section 5.2.2 c) above
Quality index Scheme: Assuming that a quality assurance scheme such as the one described in 4.2.2 is in place, the key issue will not be determining qualifying output but rather determining whether the overall scheme meets the threshold QI criterion. For schemes that meet the QI criterion the entire annual electrical output of the scheme will be defined as eligible for support. It is assumed that schemes which do not meet the QI criterion in their initial project design will not be classified as qualifying cogenerators and will therefore not generally be eligible for financial support. In the event that such schemes are to be considered as eligible or in the case of schemes which had previously met the QI threshold but have subsequently lapsed below the threshold the following formula13 for determining qualifying output could apply:
Figure 8 – Calculation of electricity from CHP under the QI scheme administered by DEFRA Clawbacks and Reallocations
Irrespective of the project type the suggested evaluation period for determining qualifying output is annually, matching the energy efficiency reporting period and avoiding the difficulties in
13Source: https://www.chpqa.com/guidance_notes/documents/Standard_-_FINAL_VERSION.pdf
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Given this feature and the likelihood that the financial support structure is likely to provide income support rather than capital payments, there will need to be some form of claw back mechanism to recover support provided in error to projects which miss their forecasts of qualifying output. Additionally there will need to be a mechanism to provide additional support (up to 100% of total output) to projects, which exceed their qualifying output forecasts.
From the above analysis it is clear that judging projects on efficiency can be rather complex and companies are not favourably disposed towards what may be regarded as bureaucratic and meddling. In discussion with the EIUG and others it became evident that economics rather than technical efficiency should drive the qualification of a plant under a cogeneration support scheme. Economic efficiency will be dictated by the pricing of the electricity available under a particular cogeneration scheme. e) Quality/reliability In order for the project to qualify under the NCS the quality and reliability of the load needs to be sufficient to allow for the project to be included in the National Integrated Resource Plan (“NIRP”) to be prepared by the Regulator. This can occur either by way of the project providing:
1) Sufficiently quantifiable demand reduction from the grid
2) Sufficiently quantifiable levels of power exported to the grid f) Other environmental factors There is increasing international concern about the effect of industrial processes on the environment and in particular the emission of greenhouse gasses that has been found to be responsible for global warming and climate change. Power generation is a big contributor in this regard in particular of
• CO2 emissions;
• Other emissions - SOX/NOX; and
• Effluent and ash.
Any new power station or cogeneration facility would have to acquire appropriate permitting. South Africa has modern environmental laws and it is expected that most facilities will therefore be compliant. It would however be important to only choose those facilities that have the best possible environmental compliance.
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6. Financial support mechanisms As detailed in Section 5.2.2 the project size will be a key determining factor in the type of financial support to be offered. With this in mind it makes intuitive sense to divide the support mechanisms between the larger and the smaller class of prospective cogeneration projects.
6.1. Small Scale Projects For the smaller scale projects (less than 10MW), the resources and funds available for project development are likely to be limited. Additionally these projects will make less individual impact in providing a reliable source of power onto the South African electricity system.
Given these factors it has been decided that small scale projects are exempted from cogeneration specific financial support.
6.2. Large Scale Projects With large scale projects (greater than 10MW), both the Regulator and Eskom have an incentive to ensure that cogenerators are required to provide long-term reliable power to the grid. For this reason it does not make sense to “de-risk” the cogeneration project equity at day one through the provision of capital grants. Given this feature the chosen assistance method will therefore need to support the output price of generation from the project over a specified length of time. In order to this the Regulator will need to determine two things namely:
1) What price level to provide support?
2) What contractual structure to use to implement the price support?
Proposals for each of these two issues are discussed in more detail below
6.2.1. Determining the supported price level In order to determine the supported price level the Regulator will need to balance (i) the desire to support energy efficiency, (ii) the need to bring additional economic generation online, (iii) the desire to capture as much additional value as possible for end consumers and (iv) the ease of implementation of the pricing system. These competing issues are illustrated below:
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c/kWh Cost of wholesale power – SA system (line B)
Net avoided cost of incumbent next best alternative plant (line A)
Potential economic benefit versus next best option
Time Figure 9 - Eskom avoided cost comparison graph Overall priority – energy efficiency and environmental gains
If the Regulator were to prioritise energy efficiency alone then it should be prepared to support a generation price for cogenerated output above the avoided cost line (Line A) for new generation by Eskom. This would be to ensure that the cost of providing the external benefits of energy efficiency were sufficiently internalised and passed on to end consumers.
While this would ensure the maximum energy efficiency benefits, by targeting the widest possible pool of cogeneration projects, this system would likely be untenable, in the short term, given the Regulator’s mandate to achieve price value for end users.
In the long-run, and once the possibility of expanding the cogeneration asset base through the ‘low- hanging fruit’ of waste fuel projects (Type I and III) has been exhausted, the Regulator may have to consider just such a pricing scheme.
For the near term however, the desired focus is understood to be on motivating cogeneration projects, with the attendant environmental and social benefits, but with sufficient referencing to current generation economics.
Overall priority – adding new capacity at comparable costs If the Regulator chooses to prioritise bringing new capacity onto the South African system at costs comparable to the incumbent’s net avoided costs then it ought to set the price level equivalent to line A in figure 9 above. This would result in all cogeneration projects which could profitably be built at this level coming online and receiving a levelized tariff equivalent to the net avoided cost level.
Although this would result in all of the notional economic benefit to consumers (the yellow triangle in figure 9 above) being lost it would still result in generation being added at the same cost as the next best alternative from Eskom. Additionally and given the scale and scope of the probable cogeneration mix this approach could also result in capacity being added in a shorter timeframe than what is possible from the incumbent.
Arguably, and given a cogent definition of Eskom’s avoided cost level, this would be the easiest system to implement. There is also precedent for this sort of system for encouraging the
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Overall priority – capturing value for end consumers If the Regulator chooses to prioritise capturing additional value for end consumers then the correct method for determining the price level to be supported would be to limit explicitly the amount (MW) of cogeneration capacity to be brought online and to run an auction to determine the price at which the additional capacity should be supported.
This ought to have the effect of encouraging potential cogenerators to bid their true project marginal cost and to drive the achieved prices for cogeneration down towards Line B in figure 9 above. In so doing this would have the effect of maximising the additional benefits to consumers versus Eskom’s next best alternative (the yellow triangle in figure 9 above). Whilst this would maximise the economic benefits to consumers, it would by definition limit the amount of capacity which could come online and given the requirement for periodic auctioning could also be the most bureaucratic and difficult system to implement.
Under this pricing mechanism there would be additional disadvantages for potential project developers as they could end up expending significant monies on project and bid development only to find that they are priced out of the market at a level below the Eskom net avoided cost as opposed to alternative and transparent approach of a defined price level at which cogeneration would be accepted onto the system.
Use of avoided cost as a comparator
A key feature of all of the above pricing is that they rely on comparison to the assumed economic cost of future baseload power investment – Eskom’s net avoided cost. The reasons for this are as follows:
1. The use of Eskom’s avoided cost sets a benchmark for both Eskom and project developers
a. In the case of developers the benchmark determines a level below which they can be relatively certain that their power product (rather than energy efficiency or social gains) is competitive with future power investments and;
b. In the case of Eskom sets a benchmark below which contracting with third parties would be economic compared to its own investment
2. The definition of a benchmark allows for reasonable certainty of project completion. By way of example running a simple capacity auction for cogenerated power could result in projects coming in above the avoided cost line which could prove difficult as a basis for contracting and could ultimately result in delays in bringing cogeneration capacity online. Given the suggested National Cogeneration Standard this could push Eskom into the difficult position of having to support power which is uneconomic compared to its current alternative choices but for which it is nonetheless forced to contract given the need to provide a certain amount of its output from cogenerated sources. Similarly delays in contract completion could destroy the confidence of the project development community.
3. No equitable alternative exists for determining a pricing benchmark. Given the diversity of project options available under the cogeneration banner as well as the multitude of fuel sources, funding options and differences in technologies it is virtually impossible to determine the hypothetical best case cogeneration project. Furthermore defining a benchmark using this ‘bottom-up’ methodology would result in the almost certain
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exclusion of clean projects which could supply meaningful additional generation at costs lower than Eskom’s
Notwithstanding the above there are complex issues associated with the use of avoided cost as a benchmark which will need to be resolved in order for the system to function properly. These primarily relate to:
1. The comparability of the end generation product being produced by the cogenerator versus that produced by Eskom. Typically there will be both positive and negative differences in the end product produced by Eskom’s large centrally dispatched plants and the small, embedded plants of the cogenerators. Resolving where the value split lies, and resolving the degree to which cogenerated power output is of higher or lower quality than Eskom’s, will thus be key in determining the level of comparability
2. The effect of non-priced cogeneration benefits. The social and environmental benefits listed in favour of cogeneration will not necessarily be reflected by simply using an avoided cost comparator but should ideally be internalised and price by end customers.
6.2.2. Suggested structures Given the difficulties in balancing objectives and following discussions between the Regulator and the Energy Intensive Users Group the following approaches are suggested as means by which the Regulator could price the support level for cogeneration in South Africa:
Price support at specified percentage of avoided cost – defined cost scheme This approach is illustrated graphically below:
c/kWh
Cost of wholesale power – SA system (Line B)
Avoided cost of incumbent next best alternative plant (line A)
Economic benefit versus next best option Cogen supported price level Maximum Wholesale price crossover (Line C) additional point economic benefit accruing to the cogenerators
Time Required Timescale for support Figure 10 – defined cost scheme graph Under this approach, the Regulator would need to define both the net avoided cost for Eskom (Line A above) and the percentage of net avoided cost at which cogeneration projects would be supported (Line C above). Qualifying cogenerators would then receive a levelized tariff over a specified tenor equivalent to the level of Line C above.
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This would have the benefits of defining explicitly the level of economic benefit being captured by end consumers under the support scheme (the yellow triangle in the figure above) as well as providing a simple, easy to understand, ex-ante, benchmark that prospective projects would have to match in order to qualify under the scheme. This would also provide an easily implemented and administered scheme.
A defined cost scheme such as this should also result in the project cost of capital and internal financial and commercial structuring being independent of the decision as to whether the project is accepted. This should also greatly simplify the degree of potentially commercially sensitive project information which needs to be shared between prospective cogenerators and both the Regulator and Eskom.
The challenge under this pricing scheme will be to determine:
1. The ‘right’ percentage of Eskom net avoided cost at which projects should qualify for support.
2. The allocation method for determining the capacity of projects accepted under the scheme. Given that the suggested National Cogeneration Standard will determine required levels of output on annual basis some means will need to be applied to ration the amount of cogeneration to be accepted under the scheme.
Modified auction below Eskom net avoided cost level Under the scheme suggested above the possibility exists that highly efficient cogenerators will have levelized project costs which approach the current cost of wholesale power on the South African system (Line B in figure 10 above), which in turn leaves at least a portion of the possible economic benefit to end consumers unclaimed by the Regulator. In the maximum this would be equal to the blue triangle in figure 10 above.
For this reason an alternative scheme would be for the Regulator to run a modified capacity auction, for a defined MW level and over a defined tenor, for projects below the bar of either (i) Eskom’s net avoided cost or (ii) a suitably determined defined percentage of the avoided cost level. All projects up to the defined capacity level at the market clearing price would then be accepted onto the support scheme and enter into long-term contracts with Eskom. This would have the potential benefit of capturing additional benefit to consumers, compared to the defined percentage scheme, and would maintain at least a notional indicator to the project bidders of the maximum clearing price for support.
Such a scheme would also provide an equitable basis for project development amongst cogenerators under the suggested National Cogeneration Standard as market access would be determined by bid prices and not some arbitrary allocation mechanism.
The challenge for the Regulator would then be to determine the maximum additional capacity level to be auctioned with the concomitant risks (as well as the percentage of the avoided cost) that:
i. Specifying too much capacity will result in projects ‘gaming’ their bids towards the Eskom net avoided cost level (and just below? the defined percentage in the alternative scheme), destroying much of the possible economic benefit
ii. Specifying too little capacity will result in projects being rejected at unit price levels below that in the defined percentages scheme
Ultimately the decision for the Regulator will be whether to establish the bar for new projects in an ex-ante (defined cost scheme) or ex-post (modified auction) manner.
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6.2.3. Contractual structures for price support Irrespective of the choice of either of the pricing mechanisms described in Section 6.2.2 there are anticipated to be qualifying cogeneration projects with an agreed price at which to sell their generation output. Following on from this the contracting structure to be applied to implement the support is described below.
Power Purchase Agreement with Eskom As a result of joint discussions between industry and the Regulator and its Adviser’s the consensus view appears to be that the best implementation mechanism for the chosen price support should be a relatively standardised Power Purchase Agreement (“PPA”) to be entered into between Eskom and the qualifying generators and providing offtake at the supported price level.
Eskom’s costs incurred under the PPA would then be sanctioned by the Regulator and would form part of the authorised cost base which Eskom could recover through its end tariffs. This approach has the following beneficial qualities versus alternative contracting structures:
• Willing buyer and seller - Eskom sourcing power and, ultimately, deferring higher cost investments with full cost recovery through the tariff, whilst the project has an assured and creditworthy route for marketing its output.
• Simplified implementation – standardised PPA will cut down on negotiation time between project Parties and Eskom
• Highly credit-worthy contract counterpart – direct contract with the single, national regulated utility as well as Regulatory sanctioned cost pass-through will markedly increase the bankability of the cogeneration PPA contract. This will also have the effect of increasing the pool of financing options available to cogeneration projects possibly reducing the ultimate project cost of capital and bringing even more capacity onto the system. Increased creditworthiness will also assist in identifying and implementing BEE opportunities in the cogeneration sector
• Performance monitoring – excepting cogeneration specific Regulatory requirements administration of the scheme will be governed by the terms of the PPA rather than requiring additional monitoring from the Regulator
Single buyer
Eskom is the logical single buyer since it has the lowest weighted average cost of production. Other industrial and utility buyers would not be interested to buy from any new plant that is considerable more expensive than the current Eskom wholesale tariffs. This situation is expected to continue to the foreseeable future making Eskom the only logical buyer of power.
There is however an important issue of succession to be considered. It is expected that RED’s will be evolving over time. It is unclear who will then be the buyer of power but it can safely be assumed that there will be some central purchasing authority or that contracts can be ceded to new purchasing companies. Such succession will however be dictated by the credit quality of the succession company.
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PPA characteristics Given that a PPA with Eskom is considered to be the best way forward in terms of the optimal contracting structure to support the development of cogeneration in South Africa the next logical step is to determine the key issues which will need to be addressed in the PPA.
Any PPA will have to address the following issues among others in order to be meaningfully applied and to support cogeneration:
Tariff structure
Whilst the price payable to qualifying cogeneration will have been predetermined under the support scheme pricing mechanism the exact cash structure of the tariff to be received by the cogenerator will need to be determined. Possibilities in order of required plant reliability and availability include:
1. Energy only spill pricing on an annualised baseload basis with each qualifying unit of cogenerated output receiving the same per-unit price irrespective of time of day or season with no capacity payments
2. Time variable energy only pricing with each qualifying unit of cogenerated output receiving the per-unit price consistent with a time of day and seasonally adjusted payment profile similar to the tariff structures charged by Eskom to large industrial cutomers. No capacity payments would be payable
3. Capacity payment plus energy charge equivalent to a percentage of the weighted energy charge charged by Eskom to large industrial customers
Given the specific requirements under 4.2.3 for only qualifying output to be remunerated, and given that qualifying output is likely to be assessed after delivery of the energy to the system any price structure may have to have a clawback mechanism for non-qualifying output.
Tenor
The following are some of the issues to be resolved in determining the correct tenor for PPAs to be offered in support of cogeneration:
• Bankability – in order for cogenerators to receive project finance style loans for their projects and to lock in long-term financing at lowest cost, banks will typically require at least two years of contract life to be in place post loan tenor. This indicates a minimum contract tenor in the region of 10 years with an optimal contract life of 15 years and upwards.
• Balancing utility, Regulatory and project risk - longer tenors will support ultimately lower tariffs being bid by prospective cogenerators under a modified auction scheme and would allow a lower per-unit price bar being set under a defined percentage pricing scheme. They would also tend to align the Regulator and Eskom’s desire to support the development of long-term, reliable baseload generation. The cogenerator’s industrial hosts are unlikely to have such long-term investment cycles however indicating the need for a compromise position.
• Price risk - Given the prospect of a levelized tariff being offered, longer tenors would also allow Eskom to reap the additional benefits of below wholesale-market supply contracts
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beyond the crossover point in figure 10. This could however also result in the locking in of out-of-market contracts if the actual net avoided cost turns out to be lower than what was initially predicted at the time of contracting. Indeed this feature of locking in at what turn out to be uneconomic prices has been a feature of many markets around the world especially where deregulation has occurred and markets have become more liberalised.
Quality and reliability of supply
Notwithstanding the additional benefits from enhanced economic and energy efficiency the key concern for Eskom in agreeing a PPA with a cogeneration plant will be the quality and reliability of supply from the plant. This will, necessarily, be a feature of the chosen tariff structure.
Non-Eskom offtake and metering
One of the unique features of cogeneration plants versus normal generation is the increased likelihood that the cogeneration project will be embedded in a local distribution network without direct access to the high-voltage transmission network and that a at least a portion of the electricity generated by the plant will be consumed by either an industrial host or exported to the local distribution network.
This necessitates that the a system for two-way metering be in place in order to evaluate the power consumed on-site or exported to the local distribution network as though it were a separate PPA with Eskom and to make the required payments under the chosen price support mechanism. This creates three possible metering scenarios to be described in the PPA:
1) Project is a standalone exporter to the transmission system with no on-site or local distribution network off-take;
2) Project has an industrial client or local distribution network as off-taker for 100% of the output; and
3) Project has either an industrial client or local distribution network as an off-taker and exports power to the transmission system
Back-up power and maximum demand charges
Industrial hosts consuming part of the cogenerated load would have the in-principle option of reducing their notified maximum demand from Eskom but would suffer adverse charges in the event that the cogeneration plant were to suffer an outage without a simultaneous reduction in demand from the underlying industrial process. Resolving this issue will require consideration of the following issues amongst others:
1) Reduction in notified maximum demand by the industrial host; and
2) Resolving the interplay between IPP type cogenerators and an industrial or embedded offtaker.
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7. Implementation issues It is recommended that implementation of the chosen support structure(s) for cogeneration should be simple and, not put a substantial additional burden on NERSA staff. The following issues will need to be resolved in the process of implementing the guidelines
7.1. Regulatory issues The following Regulatory issues will be relevant in implementing the envisaged standard and associated pricing and contracting structures.
Clarification of Regulatory framework
There is a need to confirm the exact extent of NERSA’s ability to deliver a National Cogeneration Standard and enforce portfolio standards for ESKOM:
• Within current Regulatory scope in terms of the legislation?; and
• Is there a requirement for Ministerial approval from the Department of Minerals and Energy? It appears that some approval would be necessary.
Agreement on key principles requiring decision from guidelines
In addition to approving the general principles and the approach enshrined in the guidelines, the Regulator will need to consult stakeholders and agree on:
• Choice of energy efficiency measure for Type II projects;
• Agreeing a pricing structure for supported large-scale cogeneration projects; and
• Delivering a draft standardised PPA contract.
Determination on the roll-out of the cogeneration standard
In order for the envisaged standard to be implemented in a meaningful, orderly manner the following issues will need to be resolved:
• Determination of year by year contribution to come from cogeneration:
o Decision on annual or regular allocation in terms of National Integrated Resource Plan (“NIRP”)
o Tenor of standard?
o Eskom ability to support new connections
• Timing of requests invitations for additional cogeneration capacity:
o Annual?
o Immediate?
• Allocation method for cogenerators seeking coverage under the standard
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o Automatic in the case of a modified auction scheme
o First in line under a defined cost scheme? Possibility to ration in line with some alternative criteria such as extent of BEE participation
• Consideration for modifications to be made to the scheme in the out-years and when all of the ‘low-hanging fruit’, low cost projects have been exhausted
Determination of pricing scheme and benchmark
The Regulator will need to decide whether a defined cost, modified auction or some other scheme should be used to determine the supported cogeneration price level
Irrespective of the scheme chosen, pricing determination will rely on a comparator in the suggested form of Eskom’s avoided cost. Determining this value will therefore be a key feature of any policy to be implemented. The following are key issues to be resolved in determining the avoided cost level:
• Choice of Eskom plant for comparison – baseload or peak?
• Calculation methodology to be used. Possibilities include:
o Actual planned or contracted next best available project licensed by the Regulator and compliant with the NIRP. NIRP contains the calculation methodology which is used by Eskom as well;
o Hypothetical best case project available to Eskom; and
o Hypothetical market comparator.
• Determining period for updating avoided cost level
• Ensuring consideration of comparability to decentralised generation – reflective of reduced transmission investments and the lack of transmission losses for on-site consumption of power.
Once the avoided cost line has been determined and an agreed to by the Regulator, the next step will be to determine the percentage of avoided cost which forms:
1) The price level to be received, on average as the contracted tariff, by cogenerators for their electricity output under the defined cost scheme or,
2) The price below which cogenerators will need to bid for their project capacity in order to be considered for contracts under the modified auction scheme
In determining the correct level the principle of Regulatory indifference should apply. This principle suggests that the Regulator should be indifferent to the identity of the power provider at Eskom’s avoided cost level provided that the power supplied is of an equal quality across the two projects.
However in the case of a defined cost scheme the Regulator may also need to demonstrate sufficient efficiency gains from the cogeneration scheme and thus an arbitrary additional level of reduction from avoided cost may be indicated.
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The indifference principle suggests that as a means of determining the benchmark, for comparison of cogeneration output versus output at Eskom’s avoided cost, the following approach could be used:
Output _ Quality _ Cogenerator Benchmark = * Eskom _ Avoided _ Cost Output _ Quality _ Eskom _ Comparator _ Plant
With an implied maximum of 100% of avoided cost in the early years of the scheme and while there are assumed to be sufficient low-cost generation projects to allow Eskom to fulfil the terms of the Standard.
If such an approach were to be adopted then it would be necessary to define ‘Output quality’ for electricity supplied as the basis for comparison. The features to be included in this calculation could include but not be limited to the following variables:
• Plant availability
o Planned outages
o Forced outages
• Inter-operability with centralized despatch system
• System balancing capabilities
• Blackstart capabilities and ability to reinforce the network
• Grid location benefits
Such an approach would necessarily only value the expected actual power output from the two generation types and would not attach any value to the energy efficiency, environmental or social benefits which could be derived from cogeneration. Additionally such a system would suffer from having to determine average qualities for a comparator cogeneration plant and would in so doing ignore the fuel and asset diversity benefit, originally being from cogeneration. The Regulator may therefore need to consider alternative approaches, which attach sufficient weight to the non-priced benefits from cogeneration
7.2. Carbon credits The possibility of cogeneration projects securing carbon credits through the Clean Development Mechanism (“CDM”) is a major current driver for the possibility of adding value to cogeneration projects in a low electricity price environment. A short overview of the carbon market and carbon credit development process follows.
Carbon credits under CDM
The Clean Development Mechanism is an important component of the international carbon market, which introduces a price for carbon (CO2 and other Green House Gasses) to the international economy. The saleable outputs of a CDM project are called Certified Emissions Reductions (1 CER = 1 Tonne CO2 equivalent).
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Under the CDM, investors from developed countries acquire Certified Emission Reductions (CERs) for each tonne of Greenhouse gas they prevent from entering the atmosphere. The CER’s can also be bought from projects in developing countries that reduce their emissions.
Carbon Funds from developed countries are now active in the South African market and pay cash in a forward sales contract, called an Emission Reduction Purchase Agreement (ERPA), for CER’s produced in, amongst others, co-generation projects.
An ERPA effectively provides an extra stream of revenues thus improving the projects financial performance, increasing its profitability and helping overcome further investment hurdles (by, for example providing collateral to the project developer/technology to help them secure additional loan finance).
For every new type of project activity, a thorough baseline and emissions reduction methodology must be submitted to the CDM Methodology Panel for their approval. A baseline methodology entails the development of a means of measuring and demonstrating that the emissions reductions (and, hence carbon credits) are actually occurring and would not have occurred in the absence of the project activity.
Methodologies are intended to be replicable and applicable to similar projects occurring around the world. Several kinds of co-generation techniques are already qualified for generating CER’s. Thus the “average” project can now use approved methodologies, further minimising transaction costs and time delays.
Demonstration of Additionality
The concept of additionality refers to the fact that all GHG emissions reductions claimed as part of a CDM activity must be ‘additional’ to that which would have occurred in the absence of that finance. If the CDM activity would have gone ahead in a ‘business as usual’ situation or is required under the laws of the host country prior, then the GHG emissions would have been cut anyway, rendering the carbon finance superfluous to the project’s needs.
Carbon credits and the cogeneration support programme
In terms of supporting further development of the cogeneration sector carbon credits have the potential to offer an alternative and attractive means of financing cogeneration projects as:
1) The implied support from carbon credits is in effect a subsidy from the consumers of highly industrialised countries,
2) Could result in some of the costs of cogeneration, which would have been passed onto South African electricity customers being borne by foreign electricity customers
3) Since carbon finance improves the financial performance of a project, it contributes to investment prioritization in favour of energy efficiency projects within companies and helps overcome financing hurdles by securing additional loan finance.
Bearing in mind the issue of additionality the Regulator is advised to give due consideration to the risk that regulation to encourage cogeneration could set a new ‘business as usual’ case and carbon credits will not be rewarded anymore for these energy efficiency projects. Under this scenario obligatory clean production goals could be set past 2012 and in the meantime financial incentives, like Carbon finance, could possibly be used to develop energy production in a cleaner way until this becomes common practice: a gradual development.
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Carbon finance will help matching the avoided cost of Eskom, however to what extend differs from project to project. Moreover, the actual income stream of carbon credits is subject to a long and strenuous approval process and cannot be 100% counted on. Furthermore, no credits can be sold past 2012 since the regulatory framework beyond that is not yet in place. Carbon finance therefore has a limited value for newly to be developed co-generation projects.
7.3. Project ownership Three generic ownership structures can be envisaged for the development of cogeneration projects. These are:
• Ownership by the industrial host directly or through a project company;
• Ownership by a separate project company that is controlled by a third party;
• Ownership of a project company that is controlled by the utility i.e. Eskom.
A typical project company structure is set out below:
Development Developer/Other Development Developer/Other Lenders Agreement Equity Providers Lenders Providers of Agreement Equity Providers Capital
Key Supply Cogeneration Fuel Supply Cogeneration PPA and Offtake Fuel Supply Plant PPA Plant Contracts
Other Permits and O&M contract EPC Contract Permits and Contracts O&M contract EPC Contract Licencing Licencing
Figure 11 – Typical IPP structure For cogeneration projects the possibility exists that in addition to the above contracts cogeneration projects may also have key contracts in the form of (i) other products offtake (typically heat) and a site leasing agreement from the underlying industrial host. This structure is shown below:
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Development Developer/Other Development Developer/Other Lenders Agreement Equity Providers Lenders Agreement Equity Providers
PPA PPA
Cogeneration Steam Offtake Fuel Supply Cogeneration Steam Offtake Fuel Supply Plant Contract Plant Contract
Site Lease Site Lease Permits and O&M contract EPC Contract Permits and O&M contract EPC Contract Licencing Licencing
Figure 12 - Modified cogeneration IPP structure It is expected that in all instances industrial hosts will structure the cogeneration project as a separate company if it is possible to ringfence the generation operations from the rest of the industrial operations. If that is not possible then the generation of electricity and other energy such as steam is to be conducted as an integral part of the industrial host operations. The off-take of electricity will then be directly between the host and Eskom.
In the case of third party outsourcing, the industrial host may still elect to have a shareholding in the project company but may elect to bring in an industry specialist and or a BEE development party. Such outsourcing is in fact a unique opportunity for Black economic development as these new projects will be a new and separate skills transfer opportunity and should provide BEE companies substantial equity ownership.
It is expected that smaller projects may well be undertaken directly by Eskom if no other party wants to make the development investment.It is important to appreciate that the project company will be an IPP although it may well be structured somewhat differently and may well have more than one product to sell.
Cogeneration projects are expected to be structured mostly as stand alone projects for the following reasons:
• The industrial host would want to separate and ring fence his energy generation risks;
• The supply of waste steam, fuel and other services such as thermal return (in the case of sugar an paper mills), water effluent and land need to be separated from the rest of the operations;
• The required returns for generation projects are different to those required by industry;
• Industry would like to limit its risk to a project company; and
• A separate company means that the ownership of the project may from time to time be transferred to a third party.
It is expected that the projects would require substantial gearing to become viable and competitive. Debt may well be as high as 80% of total project cost. Banks are however now comfortable with this type of structure but will therefore rely on a carefully constructed contract structure that is
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• The PPA;
• The agreement to sell other forms of energy such as steam;
• The development agreement with the industrial host;
• The site lease with the industrial host
• The shareholders agreement;
• The EPC contract with the contractor that would build the project ;
• The O&M and LTSA agreement with an operator to operate the plant ;
• Loan agreements with funders;
• Insurance agreements;
• Licences; and
• Environmental permits.
The Regulator should be indifferent to the type of ownership offered for each project although he must be satisfied that the project company is well funded has the ability to deliver. An important issue to be encouraged though is the creation of BEE ownership opportunities.
7.4. Applications, licensing and permitting It is envisaged that in general cogenerators would be treated in the same manner as other IPP generators, from a licensing point of view, and in so doing would be required to go through the normal steps in making applications for generation licenses and in the application for other relevant permits. The key exception to this process would be a requirement from cogenerators to make an application to the Regulator to seek:
1) Approved cogenerator status and,
2) To have their output certified as qualifying in terms of the support scheme in place
If the above are approved by the Regulator, Eskom would then be able to contract with the party and be assured that the contracted capacity would count towards the National Cogeneration Standard. The cogeneration submission from prospective projects would need to include:
• Type of plant;
• Description of fuel source and evidence of risk management in fuel procurement strategy;
• Details of proposed technology and desired project classification ;
• Details of project size and location;
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• Evidence of ability to comply with the energy efficiency standard in place for the project type;
• Details on the project ownership structure and proposed BEE component (if any). BEE credentials could be used as potential tie-break under the modified auction scheme or as a standalone allocation tool under the defined cost scheme;
• Evidence of a credible financing plan for the project;
• In the event of an auction scheme being chosen, details of the required tariff;
• Details on any variances from the envisaged standardised PPA.
Decision-making time frame
Given that one of the key issues raised as an obstacle to the development of projects was the length of time and perceived bureaucratic nature of the application process, both the Regulator and Eskom should endeavour to create a sensible and achievable timetable for processing applications and implementing projects.
The expected standardised contract and pricing scheme should assist in achieving this aim but ideally both the Regulator and Eskom should encourage the development of a dedicated in-house resource set to further this aim.
Cogeneration development process in context of the guidelines
Based on the guidelines above and the, to be decided on, support structures, the possible breakdown of responsibilities in implementing the cogeneration programme as well as the expected development process is shown below:
Guidelines Guidelines Design project in Relative certainty of from project approval from lineDesign with guidelines project in NERSA before design NERSA line with guidelines
Known parameters Clearly define range of Determine project from guidelines: Project Design permissible projects Determine project financing and 1. Modified auction and Pricing requiredfinancing tariff and required tariff 2. Defined cost
Clarification Project submission Decision within on project Projectto NERSA submission defined timeframe specifics to NERSA
Approval by NERSA Approvalon cogenerator by NERSA statuson cogenerator qualifying statusoutput qualifying output Execution Clarification on project Execute contract specifics Project execution Project execution under agreed by ESKOM structures from by ESKOM guidelines
Ongoing contract Monitoring and Ongoing contract Cogeneration performance and Cogeneration Evaluation performance and oversight: NERSA monitoring: Eskom oversight: NERSA monitoring: Eskom Figure 13 – Process for project development under the guidelines NOTE the Implementation would in fact be by both parties to the signature of the PPA.
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Developing cogeneration projects (or any generation project for that matter) takes substantial development effort. This effort translates into substantial costs amounting to up to 3-5% of project costs. This includes various technical studies and even the EIA. In the case of large industrial companies the availability of development resources normally is not a problem, but will still have to be justified. BEE groups typically however do not have such resources either. There may therefore be a need to develop a financial support structure to further stimulate the initiation of projects in addition to the guidelines proposed above.
7.5. Evaluation Methodology
The consultant was required to recommend methods and tools, other than commercial generation expansion planning software, required for economical and financial evaluation of proposed projects as well as evaluation of the energy efficiency and GHG emissions; There is no blue print or software that will generically evaluate projects as each project is unique. Modern discounted cash flow analysis should be used as basis for financial modelling and evaluation. It would be appropriate for NERSA to have staff trained to enable it to evaluate projects and applications if appropriate. In the absence of trained staff NERSA should utilise consultants where appropriate. In addition to cash flow analysis efficiency and green house emission calculation should be done. These calculations are also not generic and project specific and unless staff are adequately qualified and trained the utilisation of consultants would be advisable until such time those skills have been procured. An additional skill set will be the understanding from a technical, financial and legal perspective the issues involved in concluding a robust and workable PPA document. Although again much work can be done by external advisors it is thought appropriate that NERSA should acquire in-house skill sets over time. Such skills will need the education and training of suitably qualified staff. While courses may be appropriate seconding staff under contract to appropriate advisors may well be effective.
Fieldstone will cover both the modelling analysis issue and the PPA in greater detail during the proposed two day Workshop as part of this assignment. Samples of a comparable models and a PPA will be provided separately to improve in house appreciation of the issues. Other topics to be covered in the Workshop should be avoided cost and the possible use of carbon credits.
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8. Conclusions and recommendation It is clear from the international experience and the above analysis that cogeneration can be quite complicated and technical. Generation is also not a core business of industry. Low electricity prices provide very little incentive for investment in the industry despite energy efficiency and significant environmental advantages. The uncertainty, bureaucracy and relative small benefits of utilising carbon credits are not enough incentive for industries to invest in cogeneration.
South Africa is however running out of generation capacity and cogeneration has the additional the following advantages (in addition to energy and environmental efficiency);
• Stations can generally be built quicker than a large base load plant;
• Stations can be constructed close to load avoiding transmission losses as well.
This makes the need for incentives to encourage cogeneration different to places where there is a over capacity. The main burden to overcome is the low historical electricity tariff. There is also a need to make the process simple and not bureaucratic and avoiding undue inference in the normal business of the industrial hosts.
In the light of international green house gas regulation there is a need for South Africa to price ‘the right to pollute’. Producing carbon intensive energy creates a future environmental liability. This should be avoided by implementing, amongst others, energy efficiency measures.
The original scope of this assignment was to consider the use of the DSM fund, or even a separate fund, to assist cogeneration projects. This report has moved away from this “subsidy approach” due to high administrative work load and perceived lack of independence and bureaucracy. The subsidy approach has been replaced by getting Eskom as a credit worthy off-taker to sign a standard PPA with aspiring cogeneration developers at an economic tariff that will be determined independently from time to time by the Regulator.
Based on the discussion in previous chapters the following guidelines are proposed:
Parameter Requirement
Definition of qualifying plant Type I, II and III as defined in 5.2.1.
Energy efficiency Calculated energy efficiency in the case of type II plant. Type II plant will have to prove basic 14 efficiency as opposed to primary generation.
Green House Gases Plant should have demonstrable advantage over a base load coal fired plant that will be considered the base line reference plant
Allocation of capacity The Regulator to decide from time to time in accordance with the NIRP
Size of individual plant No minimum size but restricted in principle to 500MW where after specific approval may be sought
14 There is a strong suggestion that economics rather than energy efficiency should be the driving parameter qualifying the project.
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Location of plant Plant to be located in South Africa, but consideration may be given to plant in the region. Preference may be given to plant that are located further away from traditional generation base in order to avoid transmission losses and increase quality of supply
Support mechanism offered A PPA with Eskom. Terms of the PPA as set out below.
BEE requirement The development to afford BEE equity and other participation opportunities in line with the appropriate BEE charters.
The salient and typical points that will be covered in a PPA are set out below:
PPA Issue Proposed terms
Parties Cogenerator development company and ESKOM
Tenor Not more than 15 years unless otherwise approved by parties
Time to complete The plant will have a fixed completion time with penalties for late delivery
Pricing Suggest a take or pay arrangement at the cogeneration tariff as determined by NERSA from time to time. The pricing will be a fixed tariff for the tenor of PPA plus appropriate escalation adjustments.
Pricing will be affected by availability which will be expected to be as high as 90% Contracted capacity The capacity that is made available to the purchaser Performance - availability factor usually around 90% of the time with penalties for Guarantees and Related non-availability Penalties - shortfall in capacity, and efficiency lower than the agreed value
- events of defaults (see below) Testing regime Sets out the way the capacity of the plant is metered and the way the contracted capacity is determined as well as the timing of tests. Failure of delivery Consequences of non-delivery or partial delivery of the contracted capacity to the purchaser (other than Force Majeure, Forced Outage or Emergency Shutdown). Operating procedures of Determines how the power producer operates and maintains the Power the Power Producer Plant, regarding the capacity generated, Shutdowns for maintenance and emergencies, clearances necessary to operate and maintain the Power Plant and information that should be given to the Power producer to the purchaser. The sealing, opening, testing and calibration of the Meters
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Operating procedures of - conditions under which the power plant will be connected to the grid; the Power Purchaser
- Emergency Notice when disconnection of the Power Plant is required;
- Clearances. necessary for the interconnected operation and for its purchase of electrical energy;
- Operation and maintenance of the interconnection facilities and transmission facilities;
- how to keep appropriate records; Invoicing and payment - when and how the meters are read;
- dates of invoice and what information an invoice shall contain;
- payment date and currency;
- delays in payment;
- dispute over invoices;
- whether there is possibility to set-off or not;
- payment security;
- right of review. Events of Default Arranges matters like:
-failure to reach the availability factor in time
- the cessation or abandonment of the maintenance or operation of the Power Plant;
- representation or warranties are not met, or incorrectly presented;
- insolvency, bankruptcy;
- incapability of remedy;
- non-payment;
- failure to provide surety;
- notice of events of default; Rights of termination - Whether or not there is the right to terminate the contract other then in case of an event of default;
- when the contract can be terminated in case of an event of default (terms under which an event of default can be cured) Liability and - liability in case of non-performance; Indemnification
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- arrangements in case of damage or injury to persons;
- environmental liabilities;
- indemnification procedure;
- exclusion of liabilities ad indemnification. Force majeure - arrangement what happens in the case of force majeure
- suspension of performance;
- payments during a force majeure event Insurance - insurance coverage;
- liability;
- all risks;
- beneficiaries;
- waivers. Assignment and transfer - acquisition of permits of the projects assets - prohibition on transfer; Fuel supply - responsibility for fuel supply;
- stock piles Governing law - resolution of disputes;
- arbitration;
- independent experts;
- confidentiality;
- immunity
It is suggested that ESKOM, NERSA and the EIUG draft a standard PPA that can be used as a template for most if not all cases. This document will be the bedrock on which the support for new cogeneration is founded.
The pricing will be one of the critical items of the PPA. It is suggested that NERSA will determine the appropriate cogeneration pricing on a regular and independent basis as part of its normal pricing activities. Pricing will be based on the actual appropriate avoided cost of new generation in South Africa plus taking into account where the proposed plant is located as well as availability factors. It will also receive input from Eskom and industry in this regard before determining the applicable pricing. It is thought that this method will be more appropriate than an auction as most
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Implementation was discussed in detail in Section 7 above. It is anticipated that ownership will vest in either the industrial host or more likely in a separate project company that can be owned by an independent owner. Transfer and approval of ownership will be subject to normal license applications with NEWSA in terms of the Act. It is further suggested that NERSA make funds available from the DSM fund to assist with the development costs of cogeneration plants. These costs will be refundable at commercial operation of the plant. It is suggested that a maximum amount of R5m will be made available per project and that a provision should be made for not more than 10 projects, i.e. a fund of R50m. Applications should be made with NERSA. Funds can be released once the project is approved. The proposed guidelines and their successful implementation based on a robust commercial PPA to the economic benefit of all parties should go a long way to alleviate the current need for new capacity in the country. At the same time available scarce energy resources will be utilized in a optimal way and dangerous greenhouse gases will be sequestrated. The stimulation of the establishment of a series of smaller plants should further stimulate the economy and also create substantial BEE opportunities.
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