The Northern Ireland Assembly - Enterprise, Trade and Investment

Priority Oil and Gas LLC in partnership with S Morrice & Associates LLC, based in Denver, have 100% title to a total 9 licences covering over 1 million acres (2,170 km²) onshore Northern Ireland and Northern Eire. This area encompasses the entire NW Carboniferous Basin and its potential shallow gas play (Ref: Montage). The group has completed Phase I and II G&G work programmes since being awarded the acreage in 1996/98. They are now looking for partners to take control of the operations through the Phase III drilling and testing programmes which are scheduled to begin in late 2000.

Commercially Proven Analogues in Carboniferous New Brunswick and Appalachian Basins

The hydrocarbon prospectivity of the NW Carboniferous Basin onshore Ireland is contained within sandstones of the Lower Carboniferous (Mississipian). Palaeogeographically these were developed in a series of depocentres along what is now known as the ‘Appalachian Corridor’. This formed between the closing continents which bounded the ancient lapetus Ocean in the middle Palaeozoic and formed a NE-SW trending suture zone prior to the opening of the Atlantic. In the Lower Carboniferous, the Corridor once linked similar depocentres in Scandinavia, Scotland, Northern Ireland, Newfoundland and the Appalachian Basin of North America (ref: Palaeostratigraphic map on montage). Permian Basin overprinting and local subsidence of the Carboniferous trend led to the development of the Lough Neagh Basin Permian depocentres are today responsible for the productive Irish and Celtic Sea Basins and the more recent Corrib gas field currently being appraised by Enterprise on the Atlantic margin which is expected to be declared commercial later this year. By comparison, the area of the present day NW Carboniferous Basin onshore Ireland was uplifted during the Permian when most of the Upper Carboniferous was eroded. The current configuration consists of a relatively shallow Lower Carboniferous Basin containing gas-prone clastics and carbonates. Source rocks overlying, underlying and interbedded with the Lower Carboniferous sand objectives were generating gas prior to Pre-Permian erosion and are largely untouched by the subsequent Mesozoic tectonics and the opening of the Atlantic. Recent Alpine related tectonics have only served to enhance regional fracture development of potential reservoirs.

A total of nine wells have been drilled in the NW Carboniferous Basin onshore. Marathon drilled five of these in the 1960s looking for oil and, even though they were targeted without the aid of seismic, four of the wells encountered gas which flowed naturally at rates of up to 30 mcfd whilst drilling with air. The most recent wells, drilled between 1984 and 1985 by Aran Energy, were drilled with mud and were targeted with the aid of seismic. The four wells drilled all encountered good gas shows, which, similar to the earlier wells, were developed in stacked sandstone sequences in the Mullaghmore and Dowra formations of the Lower Carboniferous.

1-4 TCF Potential Onshore Close to Markets with up and Downstream Value Chain Control

Significantly, the 1980s testing focused on the tight Dowra sands which are poor quality when compared with the Mullaghmore sandstones now identified as the primary target.

Historically the Mullaghmore was largely ignored due to its high feldspar content which gives a misleadingly ‘dirty gamma ray’ response on logs. Detailed new petrophysical work carried out by the group indicates that in fact the interbedded sand/shale target ranges up to 730 feet thick in the northern part of the basin with porosity ranging up to 20% Æ compared with less than 5% in the thinner (40-50 ft thick) Dowra sandstones.

Due to the misleading log response, the zones containing good shows in the Mullaghmore were never perforated, frac’d or specifically tested during either the 1960s or ‘80s campaigns.

Highly specialised North American technologies have enabled even tight sands from similar aged reservoirs to produce significant quantities of gas commercially with flow rates enhanced by modern completion techniques. These are enhanced by modern stimulation which successfully sustains long term production from formations in the North American basins.

Detailed geological, geophysical, geochemical, engineering and economic evaluations have confirmed that the Lower Carboniferous Basin in Ireland is an ideal target for the techniques developed in North America. This ‘technology transfer’ is thought capable of generating large quantities of gas onshore and at sustainable flow rates to feed a regional power generation scheme. The Mullaghmore reservoir alone in the NW Carboniferous Basin is estimated capable of yielding total reserves in excess of 2-4 TCF recoverable.

The whole Carboniferous sequence is underlain by and interbedded with gas prone source rocks which are predicted to have remained in the wet gas window to the present in the north and eastern parts of the basin.

Prime ‘Technology Transfer’ Candidate for Proven us Reservoir Development Techniques

The Joint Venture are planning an appraisal drilling programme which will confirm the play’s potential and satisfy the obligations required in 2000 and 2001. Well locations have been identified to test the gas resource and establish its commercial potential. This initial drilling programme includes three wells in the most prospective area close to previous drill sites where the presence of the gas reservoir has been firmly established.

It is estimated the pilot programme will cost US $ 1.5 million including stimulating and testing. The follow-on drilling programme is budgeted at around US $ 2-3 million, which would fulfil all outstanding obligations and provide additional tests in the main play fairway. Based on the success of the initial drilling, a subsequent development drilling programme, estimated likely to cost US $ 15 million, would establish the gas flow necessary to scale the design of a power plant project.

Gas/Power Gen. Project Economics Benefit From Lowest Government Take in the World

Ireland has a reputation for its very low Government take and further justifies its reputation by having the most attractive fiscal regime anywhere in the world. The Licences situated in the Republic are subject to terms based on a 12.5% Corporation Tax with no royalties. The Licences in Northern Ireland include a 7.5% royalty. As a result, the economics show that sustained flows of as little as 45 mcfgd per well would produce a commercial gas development. Evidence that these rates can be achieved already exists in the historical wells based on tests of the tight Dowra objective. Threshold flow rates are expected to be achieved easily if the Mullaghmore target sands are proved up by drilling in the initial Phase III work programme.

One of the Republic’s main aims for the future is to commission at least one new power station. Annual growth in demand for power is expected to continue at 7% per annum, putting the existing utilities under severe pressure. Plans are already in place to bring the gas from Enterprise’s Corrib field ashore by pipeline to the west coast, which is most likely to be used for power generation.

Significant new market opportunities now also exist following the deregulation and liberalisation of the Irish gas and power industries which has opened the door for independent operators to build and run power generation schemes. In this regard, the group’s acreage in Ireland also contains the now defunct Arigna power station which is close enough to existing and planned extensions of the power transmission network for a new and modern power station.

A presentation and data reviews can be arranged after execution of the confidentiality agreement arranged through:

Tel:         +44 (0)20 8354 7715
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Contact: Mike Lakin

Priority Oil & Gas LLC was incorporated in March, 1995 in Denver, Colorado for the purpose of conducting oil and gas exploration, acquiring and operating producing US oil and gas properties and generating international projects which utilized natural gas technology transfer.

Priority has acquired 100% of two fields producing from tight gas sands in Kansas, which it operates and is presently infill drilling. Two other on-going projects include development of fractured shale acreage in northwest Colorado and exploration in south central Colorado in a frontier sub-volcanic play. In the fall of 2000, a 3D seismic survey was conducted on the Colorado properties and drilling for oil and gas in the area will commence in the summer of 2001. Priority, in 1996-99, with partner S. Morrice & Associates, was successful in acquiring licences in Ireland and Northern Ireland for natural gas exploration and technological transfer initiatives.

Robbie Gries, President, has developed a reputation within the industry for hard work, integrity and an ability to accomplish ambitious endeavors over the course of 27 years in the industry. She is an innovative explorationist and has owned her own consulting firm and operated as an oil and gas independent for 20 years. In 1992, she was instrumental in the $12.5 million acquisition and merger of Skaer Enterprises in a partnership with Pease Oil & Gas Company. Robbie and her partner went to the public market in a secondary offering to finance the acquisition.

Robbie’s diverse experience includes oil and gas prospecting, geophysical interpreting, management, company operations, budgeting and finance, land work, exploration, and acquisition evaluations. She worked for Texaco, Inc. and Reserve Oil, Inc. prior to starting her own business.

Robbie was recently elected as President of the American Association of Petroleum Geologists (AAPG), is a Trustee Associate of the AAPG and is a Certified Petroleum Geologist. She is a Director for the Colorado Oil and Gas Association and on the Geology Foundation Advisory Council for The University of Texas at Austin. She is an Honored Alumnus of the Colorado State University College of Natural Sciences. She has been a past officer in the Rocky Mountain Association of Geologists. She has written numerous papers on exploration and geology.

The exploration and production goals of Priority and Morrice in Ireland have focused on developing Mullaghmore and Dowra “tight gas sands” which were identified from drilling in the 1960’s and 1980’s. Priority owns and operates fields that produce from similar tight gas sands in the United States. In northwest Kansas, Priority’s two natural gas fields produce from a tight carbonate reservoir and in Utah, Priority’s production is from a multiple pay, tight gas sand. These are low volume, long-lived natural gas producers with similar dry gas characteristics as those found in Ireland.

In addition, one of the principals, Robbie Gries, has been active in exploring the Cretaceous Niobrara Formation where it is more thermally mature at Loveland Field adjacent to the Colorado Front Range. A second reservoir which was developed at Loveland is the Codell Sandstone—a classic basin-centered tight gas sand. Loveland Field is a structural monocline and production is optimized by using the natural fracture patterns. Gries, while a Director and Vice President for Exploration and Development of Pease Oil & Gas Company, implemented an exploitation program for developing the tight gas reservoirs at Loveland. This included drilling four new vertical wells and using four new technologies:

4. and new hydraulic fracturing techniques developed by the Gas Research Institute and by industry consultant, Tony Losacano.

In addition to the vertical drilling program, Gries evaluated drilling and production from a recently drilled horizontal well and developed a program to use another new technology (cased hole lateral drilling) to further develop the field using the natural fracture information gained from FMI logs in the recent vertical wells.

Loveland Field is approximately four miles east of outcrops of the key producing tight reservoirs and these have not been flushed to the surface because of the low permeability of the reservoir. It is anticipated that tight reservoirs in Ireland which are exposed on the west and northwest flanks of the basin, may have similar potential for natural gas accumulations.

Gries has organized and completed proprietary studies on the tight Niobrara Formation in east central Wyoming, southern Colorado, northwest Colorado and the Denver Basin of Colorado. She also completed a proprietary study of the Codell Sandstone in the Denver Basin of Colorado, which is a 25-35 feet thick section of Cretaceous tight gas sand. Codell field development and Codell commingled with Niobrara have been the key reservoirs in Colorado where tight gas sand exploitation techniques have been developed.

1. Hydraulic fracturin1. Hydraulic fracturingg advances which account for greater productivity and better economics include:

f) better imaging to determine the length, position, size, shape and asymmetry of the induced fractures

FMS—the formation micro scanner replaces the formation mico imager (FMI) with twice the well bore coverage and with more detailed resistivity response. This has made fracture identification much more reliable. Neither tool has been used in the Northwest Carboniferous Basin.

a) Slim hole drilling.—Where smaller bits and completions allow smaller drill strings and casing, making equipment more mobile, faster and costs lowered from smaller casing and smaller locations.

b) Downhole motors.—Downhole positive-displacement mud motors have been developed which rotate fixed-cutter bits at high speeds. This controls the hole more efficiently in highly structured areas and cuts drilling and rig time substantially.

c) New drilling technologies.—Such as high-torque positive displacement motors, use of percussion hammers for surface holes and use of percussion air drilling with flat bottom bits to provide the highest possible penetration rates.

d) Optimal matching of bits to formation drilling characteristics.—Greater attention to optimum drill bits for each part of a drilling program has brought new cost saving to large drilling programs.

e) Mud additives and underbalanced drilling equipment.—These improved technologies reduce reservoir formation damage (very important for fractured reservoirs) and provide a continuous sample of hydrocarbons during the drilling process.

f) Pitless drilling.—Where applicable with mud drilling or water drilling, this reduces the surface cleanup time after drilling.

Horizontal drilling for tight gas sands and fractured reservoirs has emerged as one of the most promising technologies in the 1990’s. Horizontal wells have yielded two to seven fold improvements in payout and two to five fold increases in reserves from successful programs in the US. Lack of economic success in some programs illustrates that horizontal drilling is not a panacea. In the exploration/drilling stages of developing tight gas sands in the Northwest Carboniferous Basin, the parameters for attempting horizontal drilling will be evaluated and future exploitation programs will consider the feasibility of applying this technology.

S. Morrice & Associates, Ltd. (SMA) is a privately held natural resource company incorporated in Denver, Colorado, USA. The principals have been active in international oil and gas exploration since 1982. SMA has originated and/or participated in exploration programs with capital requirements ranging from US$500,000 to US $15,000,000. SMA and related affiliates have been successfully utilizing technology to enhance asset value and improve geological understanding in the areas in which it has an exploration interest.

SMA has operated in Belize since 1985 through both S. Morrice & Associates, Ltd. and an affiliate, Belize Natural Resources, Ltd. (BNR). The company’s licence positions are located both onshore and offshore. SMA conducted the initial field exploration and technical work that led to the discovery of a previously unknown basin. Negotiations with the Belize government resulted in an onshore licence position consisting of approximately 700,000 acres in Northern Belize. SMA and its partners (VAALCO Energy, Inc., I.N. Rankin Oil Ltd. and Exeter Oil & Gas Ltd.) acquired US$4,000,000 seismic survey and delineated 4 drillsites.

BNR negotiated two offshore production-sharing agreements (PSA’s with the Belize government authorities following extensive geological and geophysical investigations incorporating proprietary magnetics, gravity, geochemistry, seismic and the work of previous operators. BNR’s total offshore position consists of approximately 1,300,000 acres. BNR secured partners (Dover Technology, Inc.; Petrofina sa; Deminex; Magellan Petroleum Australia) and earlier this year, succeeded in drilling the first offshore well in Belize since 1982 on the Gladden PSA. The well was drilled in water depths of 300 meters at a cost in excess of US$13,000,000.

SMA, jointly with Priority Oil & Gas LLC, has 1 million acres in licences covering the Northwest Carboniferous basin straddling the borders of Northern Ireland and the Republic of Ireland. Through earlier joint venture alliances in 1987-1988, Susan Morrice, a principal in SMA, raised capital and participated in the drilling of four wells in this area. Gas accumulations were deemed uneconomic at the time. SMA and POG believe that transfer of recently developed technology could be successful in exploiting shallow, low volume gas present in the Northwest Carboniferous basin.

SMA through its principal, Susan Morrice, was responsible for exploration, development and marketing of natural gas in Turkey in association with Thrace Natural Gas. The produced gas in meeting the energy needs of local business interests in this region.

SMA, in conjunct with Dr. Tommy Thompson, were the leading consultants for ARCO international’s offshore Moroccan concession. The work program included detailed tectonic integration, structural modeling, seismic interpretation and drillsite delineation. Exploration in Morocco continues as a result of these technical determinations.

SMA evaluated the country of Costa Rica for Mallon Oil Company to focus their exploration program in prospective areas. Mallon Oil is presently negotiating with the Costa Rican government abased on these recommended licence positions.

SMA and its affiliate Aspect Management Corporation financed the originating group that developed geological concepts, which led to the drilling of two wildcats by Mobile Oil and Murphy Oil in northern onshore Peru.

SMA, through an affiliate, Antrim Resources, Inc., manages approximately 45 oil and gas wells in the continental US.

SMA is in various stages of technical review and negotiations in Trinidad, Mongolia, and Bolivia. SMA is also actively investigating potential joint ventures with an affiliate, Aspect Management Corporation, using 3D seismic technology to reduce drilling risks.

Thank you for your letter of 19 December offering Banbridge District Council the opportunity to comment to the Department of Enterprise, Trade and Investment Committee on the energy market in Northern Ireland.

Banbridge District Council are part of a regional consortia of Councils which are advocating for non-fossil fuel energy in the east of Northern Ireland. A separate detailed response is being submitted by the Consortia.

However, the provision of natural gas in this area is high on the agenda of local politicians and Banbridge welcomes the opportunity to make some points with regard to the Terms of Reference of your Committee.

1. The majority of electrical load in Northern Ireland is located to the East around the Belfast/Craigavon/Newry axis. This is due to high industrial output in this region and therefore should have a high priority with regard to the need to have low cost energy options and more environmentally friendly fuels.

2. The current proposals to provide a pipeline from Scotland to Dublin, offers the opportunity to provide gas in the eastern corridor of Ireland, thus benefiting all the major towns and industrial centres in this area.

3. Banbridge District Council has been proactive in encouraging reduction of energy costs within local businesses. The Council advocates that IRTU work closely with Councils to train, educate develop energy reduction measures within local industries and businesses, however small.

4. Renewable energy has been poorly developed in Northern Ireland, yet potential has been identified through biomass, recycling of farm effluent, mushroom waste compost. A concerted effort should be made to work with the agricultural community at a local level to consider how they can develop alternative energy sources on their land and market it in a collective manner.

I enclose herewith a submission prepared by CANCO, the Canal Corridor Natural Gas Task Force, of which Craigavon Borough Council is a lead partner.

I would advise that Craigavon Borough Council has endorsed the content and would wish to be associated with the case made therein.

CANCO was established in December 1996 under the auspices of Portadown 2000, one of the Town Development Companies created by Craigavon Borough Council. CANCO incorporates business and local authority interests in the Council areas of Craigavon, Armagh, Banbridge, Dungannon and Newry & Mourne. Since its inception it has been actively lobbying for the extension of Natural Gas to the South East of the Province which has the greatest concentration of industry in Northern Ireland outside Belfast.

The lobbying has taken the form of meetings with the three MEPs, First Minister, Minister for Enterprise, Trade and Investment, Minister of Agriculture, the NI Assembly, prospective suppliers of Natural Gas, the Regulator, the Department of Enterprise, Trade and Investment, the Department of Public Enterprise in Dublin together with conferences and written representations.

CANCO believes that energy in all its forms has a key impact on the social and economic well being of Northern Ireland generally, and of the South East area in particular. We therefore welcome this opportunity to provide an input to the process of establishing a future policy for the sector.

Our over-riding concerns, which are expanded upon later in this submission, centre round ensuring that there will be similar access to competitively priced electricity, gas, oil and coal for the businesses and citizens within our council areas relative to elsewhere in the United Kingdom or the Republic of Ireland. We also want to see greater emphasis being placed on the environmental aspects of energy production, energy efficiency and of course its conservation.

Since oil and coal products are readily available throughout Northern Ireland from multiple suppliers, prices by and large reflect the competitive nature of the business. Therefore our concerns on these fuels are not that great. Our main focus in this submission will be on those energy types where competition or access is restricted – namely the electricity and gas sectors.

Before leaving the oil and coal sectors however, from an environmental perspective, we would urge the stepping-up of programmes for conversion of coal-fired heating systems to alternative fuels, such as oil and gas, and an increased emphasis, by way of educational support, for energy conservation and its efficient use. The Northern Ireland Housing Executive, as the Home Energy Conservation Authority and the owners of approximately one in four of the homes in Northern Ireland, must provide a more dynamic lead in this regard.

We are aware that policy in fuel taxation matters is dictated by Westminster; but to the extent that the Northern Ireland Assembly is able to influence these issues, we would ask you to lobby strongly for the following:

n A further derogation for Northern Ireland in the imposition of the Climate Change Levy (CCL) with respect to new gas networks outside Greater Belfast so as to encourage extension of the gas network. As things stand, thanks to previous lobbying efforts by the Assembly, the CCL will not apply for a period of five years within Northern Ireland. In reality, however, this concession benefits only those customers connected to, or who within the next 4 years, will be connected to, the Phoenix network. If, as we hope, gas is extended to the area represented by CANCO, the present concession will have little benefit, since the start-up and roll out timetable for building the network will probably coincide with the derogation period. A further derogation, aimed solely at the areas outside Greater Belfast, would encourage gas network developers for these areas to come forward. (We will come back to the wider issues surrounding gas network extension later.)

n Further taxation issues concern the application of VAT and other fuel taxes, their impact on competitive pricing, and particularly, the possible distortion of end prices that these taxes cause. We appreciate that some taxes, such as the CCL, are intended to send particular signals to encourage environmental action but we would ask you to ensure that their application, within a Northern Ireland context, takes account of the already high end-price that we pay for most fuels relative to other UK regions. This comes about as a consequence of our remoteness, resulting in higher transportation and other charges.

For example, someone in Northern Ireland paying £400 per year for electricity that would cost approximately £280 in another part of the UK, would incur an extra £6 in VAT charges over his mainland counterpart. For industry, the cost impact is even more pronounced. A much fairer system would be to apply tax on a ‘per unit’ of energy used basis. This would de-couple fuel taxation from geographic price variations.

Mainly as a result of being a nationalised industry during the crucial development years and thereby giving government the ability to dictate policy and subsidise cost, Northern Ireland is fortunate in already having a widespread electricity network. Access to mains electricity is no longer an issue for the vast majority of homes and businesses. Only a small number of households in the more remote parts of our area have not yet been connected to the NIE network. Some grant aid might be necessary to connect those remaining homes where income levels prohibit access to this essential service.

With privatisation of the industry in 1992-93, electricity generation was taken away from NIE leaving them with the remaining activities. Two of the main NIE activities are relevant to our submission:-

n Supply Business - the supply (or selling) of electric energy purchased on long-term contracts by the NIE Power Procurer from the private generators; and

n Networks Business - the transmission/distribution of that electricity (and now with de-regulation, the electricity of other, competing suppliers) over their monopoly network.

Each of these activities gives rise to distinct charges. The energy element of the overall bill accounts for somewhere between 80 percent (large industries) and 40 percent (households), the difference reflecting the respective volumes taken and the investment cost of the particular network required. For industry, at 80 percent of the total bill, the energy portion is the key issue. For households, the network charge is the chief contributing factor to their high charges. A reduction in the charges for both activities must be a primary objective.

In subsequent sections we raise a number of issues regarding each of these NIE activities but we also touch on the role of the Department and Regulator in a number of related aspects.

The ‘Network’ business of NIE is regulated by OFREG and consultations are underway between the Regulator and NIE to establish new charges for the next regulatory period. We support the Regulator in these efforts to reduce prices but would expect that any reductions brokered will not be at the expense of reliability. The performance of the NIE network over two recent consecutive winters was a cause for concern. Although the network investment necessary to ensure good network performance was recouped from customers via NIE’s regulated tariffs in the period since privatisation, the necessary work was not carried out. The income however, was not retained for future network investment, but was distributed to shareholders, not customers. The network performance over those winter periods seems to confirm that necessary investment was neglected. Better control of NIE’s network investment to improve reliability needs to be an integral part of the future Regulatory framework and since NIE collected the funds in earlier periods, customers should not be asked to pay twice for it.

Electricity costs in Northern Ireland are higher that in comparable regions of the United Kingdom with detrimental consequences for existing industry; the region’s attractiveness to future new industry; and the living standards of our citizens. Both the energy (generation) element and the network element of the bill are higher than in other comparable UK regions.

A consultation paper published by the Regulator last year highlighted this higher cost issue and we would expect strong action on his part and that of the Department of Enterprise, Trade and Investment, to bring Northern Ireland prices quickly into line with other regions of the United Kingdom.

The greatest single factor influencing higher generation costs is undoubtedly the relatively high price extracted by government from the owners of the generating stations at the time of privatisation. The second most important factor influencing higher end-prices is the high cost - and long-term nature of - the gas supply contracts attaching to the Ballylumford station sale. On a per megawatt basis, the Northern Ireland stations were sold at roughly twice the price of the stations in England and Wales. In order to recover their greater outlay, the new station owners need to charge much higher output prices.

Actions taken to date by the Department and the Regulator have failed to address both of these key issues. The Regulator has been given the unenviable task of trying to reduce prices by other means. While some £80 million of government money was made available over several years to help reduce prices (temporarily) and to re-structure some power station contracts, further return of the monies attaching to the original station sales is needed to bring any meaningful restructuring of generation costs.

Some re-balancing of charges occurred over recent years between the industrial and domestic customer sectors to facilitate opening of the market (to comply with the European Union Directive). The manner in which this was done is a cause for concern. We understand that some electricity energy ‘contracts’ were auctioned off, below cost, to new supply companies who then sold this ‘cheaper’ energy onto eligible (industrial) customers - with the difference in NIE’s purchase cost versus auction price being ‘smeared’ over the already high priced domestic tariffs without customers knowledge. We are in favour of reducing industrial tariffs but not at the expense of other customer groups. Such action calls into question the role of regulation and the lack of protection afforded to ordinary citizens in this respect. If the Regulator has not been charged with undertaking this ‘safeguarding’ role of domestic customers rights, then the Department must be held answerable for the incident and steps taken to ensure there is no recurrence.

The cost to new industries for connecting to the NIE network has been a concern in some instances and while NIE does not have a monopoly in this activity, it is not required to publicise that fact nor make the task of would-be competitors easy. We would recommend that competition in this ‘connections’ activity be encouraged.

We look forward to the commissioning of the new Moyle Interconnector in the hope that it will bring more competition in the Supply activity and greater network security. We would encourage further interconnections with the Republic of Ireland for the same reason.

Greater competition will only come about, however, if there are no barriers to cross-network energy trading. An example of this might be the imposition of separate network charges by NIE and ESB thus increasing the final price and leaving it uncompetitive against indigenous generation that has only one network charge to face. An all-island network charge should be agreed particularly if further interconnections do come about.

We actively support the extension of natural gas networks to other areas of Northern Ireland and to the South East in particular, but we want this gas to be at competitive prices.

We believe the rationale for extending into our area is overwhelming. However we are extremely concerned with the way in which the recent competition for new gas network extensions was conducted by the Regulator and the Department. The process as it evolved ‘directed’ developers to the North West by favouring that location for new electricity generation (generation takes the bulk of the gas volumes and hence incurs the majority of pipeline costs, leaving the other gas customers to cover small marginal costs).

Developers interested in extending into the South East, or elsewhere, were required to apply the cost benefit from any generation they propose building in the South East area, only to the North West pipeline. We want to make it absolutely clear that we also whole-heartedly support gas network extension to the North West. By questioning the process above, we are seeking only to ensure that a ‘level playing field’ approach is taken in signalling development opportunities and that normal unbiased evaluation procedures be allowed to determine the outcome. If at all possible, commercial evaluation techniques should prevail. If government wishes to dictate outcome, then perhaps it should consider nationalisation of the gas industry during these formative years (as was the case with electricity).

There is every reason to believe that siting new electricity generation in the South East is commercially attractive; the majority of the load lies to the East, a North/South pipeline, giving access to two alternative gas network sources, would provide greater reliability than a ‘spur’ fed station site elsewhere. Electricity output prices would be lower than, for example, a North West site, due to the fact that a shorter network length would be required. Greater volume flows – and hence lower unit charges -would be achievable because of North/South trading on the same pipeline. In addition, the proximity of the area to the main NIE/ESB interconnector and the Dublin load must be advantageous. All we seek is a fair chance to be considered for any gas- fired station development.

Of the Council areas represented by CANCO, Craigavon alone provides one third of Northern Ireland’s industrial base with the largest number of IDB client Companies outside Belfast having attracted 44% of all IDB investment over the past 10 years. IDB’s recognition of the qualities of the area can be witnessed by virtue of the fact that it is currently holding circa.252 acres of industrial land in the Borough for future development. This is in addition to the 453 acres currently owned by the IDB.

Craigavon has a large and increasing gas user base, currently equating to at least 60 million therms per annum, which with the anticipated future industrial and population growth could exceed 120 million therms per annum. (Craigavon has been identified as one of the major growth centres in the Province in the Regional Strategic Framework document – ‘Shaping our Future’.

Without the extension of the Natural Gas network there are real concerns that regional disparities will result; that indigenous companies will be forced to relocate to the Greater Belfast area where a cheaper source of energy supply is available; that the IDB will be unable to attract new investment to avail of the large land bank if the alternative of gas is not available; and that employment opportunities will be displaced to the Greater Belfast Area at the very time when this is being discouraged by Government.

As mentioned above, a generation station in the South East supports the viability of a North/South gas interconnector that then brings other benefits. Wider availability of gas over a different pipeline, as well as helping industry and households in the South East, provides competition to the Phoenix/Premier system and crucially, provides back-up supplies to the Belfast gas customers should the undersea pipeline suffer a fault (such a fault could take several months to repair). It could also carry gas to a North West network.

We believe a proper, independent, study of Northern Ireland’s future generation requirements, generation siting preferences and gas network expansion should be undertaken. From this, the opportunities for both new generation and gas network build should then be advertised more widely. NIE could surely signal which parts of the network would provide optimum technical (and lowest output price) connection. To date, they have only indicated which of several competing North West station projects provides the best technical solution in the North West. They have not been asked by the Regulator to indicate which of those competing projects offered the lowest cost electricity output nor where in Northern Ireland would be the optimum location for stations and at what megawatt output. We believe these questions should have been, and still should be, asked.

Building new gas generation remote from the existing gas network around Belfast has direct cost consequences for electricity customers due to the high cost of providing gas pipelines. It is imperative that the most cost-effective location is selected so as not to aggravate the already high electricity tariff situation any further. New gas-fired generation will, under market opening requirements, only supply the industrial/ commercial customer base - a market that lies mainly to the east of the region and that may well be adequately covered by the increased electricity interconnections coming on-stream later this year. Domestic customers will see no immediate benefit from any new generation since they will continue to be forced to take high price electricity from the long-term contracts with existing stations.

Since solutions to these matters are policy related and also to ensure greater accountability to the electorate, the Department, not the Regulator, should oversee this initial study. The Regulator would still licence the successful developer(s) and regulate their operations.

We would support a widening of the study suggested to consider the energy needs, primarily gas and electricity, of the island as a whole; on the basis that a greater interchange of energy and the minimising of duplication (of networks) must bring cost benefits to all.

It has been suggested that the cost of building new gas pipelines should be supported through grant aid and/or by allowing the cost to (again) be ‘smeared’ across the present gas and electricity customers through a form of ‘postalisation’. We would vigorously resist any proposal to visit further costs on electricity and/or gas customers, as this would impact their competitiveness. With so many worthy projects (hospitals, roads, education) requiring aid, any grant aid to a power station project(s) targeting commercial customers should not be at the expense of other projects that benefit Northern Ireland’s citizens as a whole. It would be essential to ensure that the aid is exclusively for the benefit of the wider population and not to support a project that should be commercially viable in its own right. Either we have a privatised electricity industry or we don’t.

In this submission we have set out some of the concerns that we have for the energy sector, primarily on electricity and natural gas issues. In particular, we would want the Committee to ensure that fair and equitable treatment is afforded to our council areas in the way in which any new gas network extensions are determined.

We have also put forward some positive suggestions for consideration. We would welcome the opportunity to elaborate on these or any other aspect of the submission in a follow-up meeting if that would be helpful. Finally, we wish the Committee well in its endeavours.

Northern Ireland faces the highest electricity prices in Europe and a geographically limited natural gas network – both issues need to be addressed.

Government must take responsibility for developing an effective energy policy which is broadly focused and integrated with other policies. Government’s role must include:

n a willingness to take a more proactive role as an ‘impresario’ in facilitating energy developments

The long-term generating contracts must be addressed – government must be involved in securing an appropriate buyout to remove excessive costs.

Enhance integration with larger systems in Great Britain and in the Republic of Ireland through interconnection of both gas and electricity networks.

Maximise the potential of the island of Ireland energy market by facilitating energy trading and encouraging competition and customer choice.

Action is required to address the negative impact of the Climate Change Levy.

n secure an extension of the proposed 5 year natural gas derogation to a minimum of 10 years

n extend the eligibility criteria for Climate Change Levy Agreements (CCLAs) to enable all companies based in Northern Ireland to negotiate energy efficiency agreements in return for 100% rebate on the CCL

1. The Confederation of British Industry is an independent, non-party political organisation funded by its members in industry and commerce. Its mission is to help create and sustain the conditions in which businesses in the UK can compete and prosper. CBI members come from all sectors of UK business and include more than 250,000 public and private companies, as well as more than 200 trade associations.

2. This submission aims to highlight key issues and challenges impacting on the development of a more competitive energy market, outlines what needs to be done to address the existing problems and concludes with a section addressing the issue of renewables.

We start by setting out our vision and the key components of a Northern Ireland energy strategy.

3. Northern Ireland needs to have an energy market that can provide secure, diverse and sustainable supplies of energy at internationally competitive prices.

4. To achieve such an energy market a number of key requirements are required. This includes the following:

n Recognition by Government of the importance of creating a competitive energy market – this is important to securing economic and social progress

- The development of a competitive island of Ireland energy market is a priority

- Interconnection with Great Britain (in both gas and electricity) will bring benefits, particularly in the medium and longer term

n Extending and developing the natural gas market – this will have an important role in encouraging balanced regional growth

n There is a need to modernise generating plant using the latest technology to ensure greater efficiency of fuel usage

n There is an urgent need to remove “expensive” obligations and impediments to the development of a fully competitive market

5. In respect to fuel oil and coal the Northern Ireland energy market is mature and competitive and there are a large number of commercial suppliers. The focus of our attention is therefore on electricity and the development of the natural gas market.

6. Northern Ireland electricity prices are the highest in Europe with increasing divergence with the rest of the UK and Europe. From a consumer perspective there is little effective competition (due principally to the generating contracts put in place at privatisation resulting in only a limited amount of uncontracted generating capacity in Northern Ireland (or indeed in the Republic of Ireland) and an insufficient integration with other larger systems, although this situation is expected to improve with the completion of the Scottish interconnector late in 2001. Northern Ireland is also unduly exposed to high fuel costs with electricity prices in 2001/2 expected to increase by over 10%. We have an emerging natural gas market but it is currently geographically limited thereby restricting choice to customers.

7. Energy issues impact across a wide spectrum of activities and have significant economic development, environmental and social aspects. These should be clearly drawn out in a Northern Ireland energy strategy so that the ‘silo’ mentality is no longer apparent and the energy policy is clearly integrated with other policies. As the Energy Working Group (EWG – formed during the development of Strategy 2010) states energy policy “……should be a comprehensive document wrapping together the totality of governance policy objectives which interface with energy”. Furthermore the strategy needs to complement and in part integrate with energy strategies of our neighbours (in GB and Republic of Ireland). For too long energy policy has tended to be too narrowly focused.

8. It is also necessary to frame Northern Ireland’s energy policy in the context of the broader global environment and in particular the current changes that are occurring across the European Union due to liberalisation and the creation of more open and competitive markets. This is having a dramatic impact on prices and choice and reinforces the need to effectively address the structural problems faced in Northern Ireland, due to the existence of the long-term generation contracts, and the lack of a comprehensive natural gas network. The EWG report rightly recognises that the central difficulty is the “enduring and widening price differential between Northern Ireland and Great Britain……”. This is against the background where the Government expects GB prices to fall by 10% in the medium-term and falls across the EU are also currently being experienced.

9. These changes within the energy markets are a reflection of much greater change taking place with the increasing globalisation of markets, greater price transparency and an intensification of competitive pressures. This results in even greater pressure to be the lowest-cost producer – and that means having a low cost base to match. With energy being a key component of input costs for many industrial processes it is important that internationally competitive prices are achieved. Unfortunately Northern Ireland is very badly positioned.

10. Limited competition and choice We believe the encouragement of effective competition is essential to developing competitive prices – this should be a major priority. Current proposals restrict themselves largely to the requirements of the EU’s Internal Market for Electricity Directive – this falls far short of developments elsewhere in the UK. CBI Northern Ireland recommends that there should be a timescale for a greater level of opening of the market. As a minimum all industrial and commercial customers should have access to the competitive market no later than 2003. As stated above this will require the buying-out of the inappropriate parts of the existing generator contracts – this is essential to delivering the right context for further liberalisation and the development of an island of Ireland market and provides the opportunity for delivering high efficiency, high-tech and low emission generating plant. Barriers to potential new entrants (ie CCGT, lignite, CHP etc) need to be minimised both north and south. We recognise the importance, and value, of encouraging liberalisation in the ROI market at similar rates – co-operation in this area has potential to bring significant benefits to consumers.

11. Existing problems are caused by having a semi de-regulated market where a limited supply of competitive electricity has unsurprisingly followed the basic rules of supply and demand and increased the prices to just below the alternative rate of the Tariff (BST). In the initial stages savings of around 10% of BST were obtained. Eligible customers must be given the opportunity to compete in a real competitive market with a clear framework and rules. A speedy transition to a proper effective market is required. Government has responsibility for implementation of the IME directive and must drive this forward – Northern Ireland needs a champion within Government to ensure that progress is achieved. We believe that Government must accept one of two alternatives if real competition is going to take place both within Northern Ireland and on an island of Ireland basis:

n pick up the costs of the exceptional stranded costs until 2010 by annual increments – this will need to be done carefully to ensure that no particular provider is given unfair advantage which could potentially block new market entrants

12. An isolated market. Northern Ireland has been penalised for having an isolated electricity system and until 1996 a lack of natural gas. There is strong support for the development of an island of Ireland energy market, set within the context of the developing European energy market. This must be a major priority and be pursued with urgency. The re-established (in 1995) north-south electricity interconnector needs to be strengthened and developed, and greater transparency on interconnector pricing achieved. The regimes in both parts of the island are very different and need to evolve – this may mean difficult, but necessary, political decisions on both sides of the border. But this will not happen unless there is a strong commitment from both Governments to create this market, and both Regulators are tasked with ensuring the objective is delivered. The development of an island of Ireland market should be phased to take account of practical limitations.

13. We have welcomed the proposed interconnector with Scotland, particularly in relation to the enhanced capacity and opportunity to allow eligible customers to trade. It is obviously important that agreement is secured at an early stage on the pricing mechanisms for the use of the interconnector – customers who benefit from the interconnector should pay for those benefits. It is also important that the pricing regime does not unduly favour GB suppliers.

14. A restricted natural gas market. A key element of any new energy strategy must be the extension of the natural gas network as widely as possible within Northern Ireland and as soon as possible. This should take account of the Regional Strategic Framework. The extension of the natural gas network is of strategic importance with wide economic, social and environmental benefits. Many companies would benefit from having access to natural gas with significant savings in energy costs and bringing associated environmental benefits. There is very broad agreement on this issue and an acceptance that this is very likely to require some Government/EU financial support. However it is also important to ensure that the any extension of the network improves the competitiveness of Northern Ireland and does not increase costs to other consumers. We also recognise that not all areas within Northern Ireland will get access to natural gas and this must also be made clear so that expectations are not unnecessarily raised, particularly in rural areas. While economic sustainability must be a prerequisite for network extension, the interdependence between gas network development and electricity generation cannot be overlooked.

15. CBI Northern Ireland has also been supportive of the proposals to develop a north/south gas pipeline. This would have significant security of supply benefits, facilitate and an important extension of the natural gas network (to the south and west) and introduce the potential for higher levels of competition.

16. Long- term generating contracts - The Office of Fair Trading has recently stated that “until such time as all the contracts entered into in 1992 are amended or set aside , the electricity market in Northern Ireland will not be as competitive as the rest of the UK”. Government created these contracts and must take responsibility for addressing this unfair situation. The existence of these contracts, introduced at privatisation in 1992, have been a major source of contention for many years and are the key impediment to achieving more competitive costs and a more competitive market. The costs of generating electricity are particularly important to industrial consumers as they make up around 80% of total electricity costs (Transmission, Distribution and Supply costs account for the other 20% - it is important that through Regulation that these costs are competitive too).

17. Firstly Government must take responsibility. The role of Government needs to be set out clearly. In the case of Northern Ireland this role is somewhat more significant as a result of the structures put in place at privatisation. The generator contractual arrangements clearly impede the creation of a dynamic energy strategy. This role includes: setting strategic goals; establishing an appropriate framework in which the industry can operate; and willingness to take a more proactive role as an ‘impresario’ in facilitating energy developments (which for commercial reasons alone will not proceed) but where there are significant and quantifiable broader positive externalities which help address other policy objectives. The Government also has a role to play through its purchasing policies and other activities including the implementation and spread of best practice.

18. Secondly, address the long-term generating contracts. Government is failing to accept its responsibility in this area leaving renegotiation to the Regulator – however competitive prices will not be achieved without Government intervention. The objective must be to ensure that a buyout is undertaken which removes the excess costs that customers are incurring. This could take a variety of forms including direct financial intervention and introducing appropriate legislation to enable some financial re-engineering.

19. Thirdly, pursue with haste the development of an island Ireland market. For example we outline what such a phasing should look like below:

n establishment of joint working group (as proposed) with preliminary report on future development of all-Ireland market

n develop a plan and appropriate machinery for gas interconnection – the proposed public service levy in the ROI is most unwelcome and will undermine proposals to build a north to south pipeline

n investment in reinforcement and upgrading of electricity interconnectors using EU Structural Funds as required

n full electricity interconnection with no limitations to trading, permitting an effective island of Ireland market

n comprehensive island of Ireland natural gas market in place with links to new Corrib field

20. We believe that the policy on environmental issues should be set within the framework of the legally binding Kyoto targets together with the Government’s UK targets of a reduction in CO2 emissions of 20 % by 2010. Northern Ireland is uniquely placed to make a disproportionately large contribution to CO2 reductions through fuel switching and improvements in energy efficiency within the electricity generating industry – and if possible secure some reward for this! There should be a clear objective of a specific CO2 reduction target and a strategy should be developed to meet this target (including a reduction in other green house gases). Reductions in CO2 must be achieved in the most cost-effective way.

21. Fourthly, action is required to address the negative impact of the Climate Change Levy. The proposed Climate Change Levy will be highly damaging to the Northern Ireland economy and is wholly inappropriate. It clearly fails to recognise the unique attributes of the Northern Ireland energy market which are as follows:

n The current problem faced by high, and increasingly uncompetitive electricity prices – there are already very significant price signals to encourage a reduction in energy consumption

n an emerging natural gas market – the CCL reduces the competitive position of gas and will be detrimental to developing the gas network outside Belfast

n energy consumers are already contributing to significant environmental improvements (the biggest contribution coming from Premier Power’s construction of a CCGT plant at Ballylumford)

n there will be a negative environmental impact as the CCL will lead to higher CO2 emissions beyond what they would have been due to impact on the development of the natural gas market

n an extension of the 5 year natural gas derogation to a minimum of 10 years (note that no consumer outside the existing licence area will benefit from the full 5 years due to the construction time required to expand the network)

n extend the current limited eligibility criteria for Climate Change Levy Agreements (CCLAs) to enable all companies based in Northern Ireland to negotiate energy efficiency agreements in return for 100% rebate on the CCL (– currently certain companies can participate in sectoral agreements which allow 80% rebates)

Northern Ireland can exceed the Kyoto targets and indeed Government CO2 targets by developing its own strategy. Regrettably this has not been recognised by the UK government.

22. Fifthly, continue to promote and encourage investment in energy efficiency ensuring that both private and public sectors are targeted. Government must continue to lead by example by establishing challenging targets, through use of best practice and through public procurement policies. Consideration needs to be given to enhancing standards of insulation in new buildings (commercial and domestic). New regulations for England and Wales are at an advanced stage – rather than wait the usual 18 months or so it will be important that similar arrangements are introduced to Northern Ireland within a few months. As the vast majority of buildings will remain for 25 years or more, attention should be paid to the insulation of existing buildings.

23. Sixthly, ensure that barriers to the development of CHP are addressed. CHP is underdeveloped in Northern Ireland. Historically there have been institutional barriers to the take-up of CHP and some bad experiences with certain CHP projects have undermined confidence in this technology. We believe that the potential for CHP extends much wider than the sectors represented in Strategy 2010 and there may exist innovative opportunities for joint private/public ventures in this area which need to be explored and encouraged. Obviously the extension of the natural gas network is going to have an impact on the potential for CHP development and this needs to be recognised.

In this final section we address some of the issues around the development of renewables.

24. The development of new and renewable sources of energy will clearly have a part to play in helping the UK meet its legally-binding Kyoto target of a 12.5% reduction in greenhouse gas emissions below 1990 levels by 2008-2012. They are likely to play an even greater role in helping the UK meet future international emissions targets beyond 2012.

25. The CBI believes that the new and renewable energy should be promoted in a way that:

n is cost-effective in terms of other Government measures to tackle climate change – in some circumstances there will be more cost effective ways of reducing CO2 emissions

n delivers consistency between different policy initiatives – in particular, the overall UK Climate Change programme, the proposed Climate Change levy, the review of utilities regulation, the development of the market liberalisation and the ongoing revision of regional planning guidance. Greater clarity on policy objectives is required.

n encourages market-based solutions and customer choice. In Northern Ireland where electricity prices are significantly higher than in the rest of GB and Europe market-based solutions should be at an advantage relative to other locations, assisted further by the introduction of the Climate Change Levy in April 2001. This should be particularly feasible for onshore wind generation due to favourable wind conditions relative to many other EU regions.

n only provides support for new and renewable sources in the Northern Ireland market up to the point that they are able to compete effectively with other energy sources in the market place

n develops the export potential of new and renewables technologies, while ensuring that the cost of this is met from general economic development funds rather than by electricity customers, who are already penalised

n recognises the cost disadvantage that Northern Ireland electricity consumers already face due to previous Government policy decisions and the impact on Northern Ireland competitiveness. This is of fundamental importance. Northern Ireland consumers must not be penalised with any further additional costs. Any further Non-Fossil Fuel Obligation must not result in increased costs to consumers.

26. In the light of the above principles and taking into consideration ongoing energy liberalisation we believe that:

n The development of renewables should be market-led. We believe that current market conditions offer commercial opportunities. Indeed an increasing number of multinational companies are committing to purchase ‘green’ sources. We therefore welcome the proposed approach set out in the Ofreg consultation paper produced in autumn 2000

n Policy must be focused on the most cost-effective means of reducing green house gas emissions while at the same time encouraging and promoting the development of renewable energy sources for the future.

n Reducing the cost of capital - the customers’ equity proposal recently suggested by Ofreg appears to be an extremely innovative idea with lots of promise. The return appears to be very attractive (albeit that the proposal is rather simplistic and does not include the costs of top-up etc), though it should be made clear whether this ‘free’ electricity includes the transmission and distribution element – we assume it doesn’t.

n Purchaser of last resort – we would not support the purchaser of last resort proposal recently suggested by Ofreg which risks adding additional costs to consumers. All other avenues need to be pursued including the development of a public sector market which could provide the critical mass for a long-term low-cost renewable sector in Northern Ireland.

n Developing a credible customer base – in principle it appears both sensible and economically attractive to encourage the public sector to show some green credentials by committing to purchase a certain proportion of renewable energy.

n Changing the trading arrangements – we have submitted views to Ofreg on a number of technical issues which need to be addressed, particularly relating to ‘top up’ and ‘spill’

n Green credits – we would support the development of a market in ‘green credits’. We understand that the current Renewable Obligations Preliminary Consultation in GB by the DTI is proposing a scheme that limits trading to GB and not the entire UK – this needs to be addressed to enable Northern Ireland to participate in both this market and indeed in the development of any wider EU market.

27. From a market perspective it would appear that onshore wind power offers the most significant potential in the short-medium term. However the biggest potential barrier may be in securing planning permission for the necessary wind farms. Planning guidance needs to ensure this potential can be facilitated.

28. There is growing recognition that there is potential for market based renewables, particularly wind power. However it is also recognised that the overall contribution from windpower will be constrained by technical reasons (largely due to the inconsistency and unpredictability of wind).

Thank you for your letter of 8 January 2001 addressed to Bruce Robinson informing him of the Committee’s proposed inquiry into Energy and inviting the Department to submit any comments by 31 January 2001. As Mr Robinson is away on business this week, I am responding on behalf of the Department.

The Department welcomes the Committee’s inquiry which is timely in respect of a number of vital issues on the energy scene. These include the progressive opening of the electricity and gas markets; continuing efforts to stimulate competition, especially among generators, and to reduce the costs of energy in a privatised market; promoting development of the gas industry and CHP; and encouraging the development of renewable energy sources. The Terms of Reference are comprehensive and the outcome of the inquiry will be a valuable input and source of information as key decisions are taken over the course of the next year on future energy strategy, the structure of the market and the policy and regulatory framework required.

In the context of its previous inquiry, the Committee will already have copies of Strategy 2010, including the report of the Energy Working Group, and Vision 2010 – Energy Action Plan. The attached submission is essentially factual summarising the background, setting out the main energy-related Strategy 2010 recommendations, providing details of the Members of the Energy Working Group and listing some key developments following the publication of Vision 2010. I am arranging to forward copies of the Renewable Energy in the Millennium paper mentioned in Annex 3 to the submission.

The Department will be happy to provide any further information which the Committee may need as the inquiry progresses, including additional copies of the documents mentioned above. I should be glad if you would regard Jim McKeown, Head of Energy Division (telephone: 29293) as the main point of contact for that purpose.

1. In late 1997, the former Minister for the Economy, Adam Ingram MP decided to conduct a fundamental review of Northern Ireland’s economic development strategy. This was formally announced on 29 January 1998 with the aim of developing, by mid-1999, a new economic development strategy for Northern Ireland, to cover the period to 2010.

2. The Committee is familiar with Strategy 2010 and the collaborative public / private sector process by which it was produced. For the Committee’s convenience, the main Strategy 2010 findings and recommendations in relation to Energy have been extracted and are reproduced at the end of this chapter.

3. The Strategy 2010 Steering Group recognised the need to examine crosscutting issues which could significantly influence the performance of all sectors of the economy of Northern Ireland. It therefore established seven Cross-Sector Working Groups, one of which examined Energy. The Members of the Energy Working Group are listed at the end of this chapter.

4. In July 1999, the Department published for consultation “Vision 2010 – Energy Action Plan” as a specific response to Strategy 2010. This set out the position on each of the recommendations as a first stage in the revision of energy policy. It also proposed a 12-point action plan for the way forward. Comments were invited on the proposals by 31 October 1999.

5. Vision 2010 recognised that the Northern Ireland Assembly, the Regulator, the various sectors of the energy industry, and consumers and their representative bodies had a collective role to play in delivering the Strategy 2010 recommendations. The Committee’s inquiry is a timely opportunity to take stock of progress and its Terms of Reference specifically include an assessment of the energy market in Northern Ireland and its role in the growth of the economy as described in Vision 2010.

6. Almost 40 responses to Vision 2000 were received by the Department with a high level of consensus, including unanimous support for the central recommendation of an all-island energy market. Following devolution, the Minister, Sir Reg Empey, met his counterpart, Mrs Mary O’Rourke, TD, on 7 December 1999. This meeting set a number of initial parameters for taking forward consideration of an all-island energy market. This important work was further progressed at a second meeting on 8 September 2000.

7. A summary of key developments on the Vision 2010 Action Plan up to the present date is contained at the end of this chapter.

8. In pursuance of its key objective to develop and maintain the equality, policy and regulatory environment to achieve high levels of enterprise and fairness, the Department will work to ensure that our energy infrastructure meets the standards that our economy requires. As set out in Vision 2010, we shall seek to achieve a secure, diverse, competitive and efficient energy market in an all-island and European context. The Actions which we perceive as fundamental to creating such an energy market appear in the draft Programme for Government (Section 5.2.2) and are as follows :

n by December 2001, prepare an energy market strategy for Northern Ireland in an all-island and European context;

n by April 2001, working with our Southern counterparts, seek to secure firm private sector proposals for North South gas interconnection and a gas supply to the North West;

n by September 2001, seek to secure Northern Ireland Electricity / Electricity Supply Board agreement on action to address the conclusions of a joint feasibility study into further interconnection between their networks.

9. The next 12 months will be a critical period for setting the future energy strategy, including the necessary regulatory framework for the market. We believe that the outcome of the Committee’s inquiry will be a vital source of information in informing policy decisions on these matters.

ENERGY – EXTRACTS FROM STRATEGY 2010
OPPORTUNITIES AND CHALLENGES (Section 7.39 – 7.42)

There are structural weaknesses which stand in the way of the emergence of a low cost electricity market

7.39 The energy industry in Northern Ireland is characterised by high electricity prices, limited access to a natural gas supply and market weaknesses which make it difficult to increase competitive pressures.

7.40 Analysis of Northern Ireland’s main energy market weaknesses in the early 1990s highlighted its small size, peripherality, scattered demography, lack of electricity interconnection, over-dependence on oil for power generation, lack of effective commitment to energy efficiency and failure to integrate energy efficiency with environmental protection and conservation. These weaknesses, the most fundamental of which are structural, have led to prices for consumers which are uncompetitive compared to the GB average, the Republic of Ireland and the rest of Europe.

7.41 The energy scene has experienced far-reaching changes over the past 10 years, not least the re-structuring (and subsequent privatisation of the electricity supply industry) and the introduction of natural gas. These changes have required intervention by a Regulator acting in the interests of consumers.

7.42 Northern Ireland needs to achieve – a low cost electricity supply system; a fully competitive electricity market; widespread availability of natural gas; full exploitation of renewable energy sources at competitive prices; and substantial improvements in energy efficiency. This will require a range of complex and interrelated issues to be addressed.

9.22 There is widespread acceptance of a number of aims in the energy field – developing competitive electricity and gas industries leading to lower consumer costs; ensuring secure, reliable and diverse energy supplies and promoting energy conservation and efficiency in the context of sustainable development. Realisation of these aims will, however, require a balance between a number of competing priorities such as :

n accelerating the expansion of the gas distribution system while promoting gas-on-gas competition;

n ensuring that lower costs do not lead to increasing use and lower efficiency; and

Drawing on the analysis of the Energy Cross Sector Working Group, the Strategy Steering Group makes the following recommendations.

9.22.1 The Government should adopt as soon as possible an updated energy policy statement setting out a coherent policy for energy with clear objectives for where the industry should be in 10 years time.

This statement should highlight and prioritise the investments needed to achieve the objectives, and indicate how and by whom the necessary decisions and action on these investments should be taken. It should also highlight the extent to which these strategic investments, examples of which are listed below, require a public and private sector partnership:

n modernisation of electricity generation plant, with the benefits passed transparently on to customers;

n expansion of the natural gas distribution system beyond the Belfast area through provision of a pipeline to Dublin (as part of a new interconnection between Scotland and the Republic of Ireland) and provision of a pipeline to the North West; and

9.22.2 Strategic investments may require a public-private partnership, with public support, provided the project is economically sound.

The Government should be prepared to offer support for strategic investments in the energy market where it is clear that these investments will not go ahead otherwise on a proper scale or on a timely basis. Factors which might be expected to influence Government decisions to offer support include the pursuance of interconnection of Northern Ireland’s gas and electricity systems to other systems in order to create competition and / or economies of scale as a means of lowering costs, and increasing security of supply. A gas pipeline to Dublin is an example of where there may be a case for a contribution from Government / EU funds towards infrastructure costs.

9.22.3 Targets should be set for the use of Non-Fossil Fuels for electricity generation, for the achievement of energy efficiency and the use of Combined Heat and Power (CHP).

Renewable energy has important environmental benefits and Northern Ireland should adopt the overall UK target of 10% of electricity generated from renewables by 2010, implying a total of 130MW by that year. Given the comparatively high price of electricity in Northern Ireland, there will be a need to maintain pressure on the cost of renewable energy here.

Energy efficiency is important for business users both as a means of reducing costs and in order to protect the environment. Each industry sector should, therefore, set a target for reducing energy usage relative to output on an annual basis.

CHP is one of the most efficient energy technologies for industry but, to date, only a few CHP plants have been installed. The Combined Heat and Power Association should, therefore, be asked by each industry sector to advise it on the benefits to be secured. A suggested target for CHP installed in Northern Ireland by 2010 is 150MW.

9.22.4 The recommendations of the Government’s Utilities Regulation Review should be fully implemented in Northern Ireland as soon as possible.

These recommendations provide for a new primary duty on Regulators to protect the interests of consumers in the short and longer term; an effective and powerful voice for consumers within the regulatory system; a framework for economic regulation allowing the right combination of competition and regulation in each sector with a balance between the interests of consumers and shareholders; and a clearer definition of the respective roles of Ministers and Regulators, with Regulators making decisions within the framework set by Government, such regulation to include social and environmental objectives.

9.225 The Government should facilitate the creation of the largest possible electricity market at the earliest possible date in accordance with the EU Directive on an Internal Market in Electricity as a means of creating competition and lowering costs. To this end (i) the current review of the electricity generation contracts should be brought to a speedy conclusion; and (ii) the £40 million fund (to compensate Northern Ireland customers following abolition of the nuclear levy in GB), held by DED, should be used to buy out generating capacity currently under contract to NIE.

Action to reduce electricity prices in Northern Ireland cannot be fully effective without the opening up of an effective trading system which, in turn, cannot happen while the existing contractual arrangements for electricity generation remain and Northern Ireland continues to be reliant on the present outdated generating plant. The electricity supply industry in 2010 should be characterised by efficient generation which minimises both costs and emissions. The Regulator published the outcome of his own discussions with the electricity generators in December 1998, highlighting how lower costs could result from the implementation of his proposals, which include the introduction of new technology, the upgrading of existing technology and the refinancing of the Ballylumford and Kilroot contracts. Further discussion between NIE plc and the generators is required about the financial bases of these proposals to ensure clear benefits to customers in lower prices. As an interim measure, to kick start an internal market and to reduce capacity charges, the £40 million fund (to compensate Northern Ireland customers following abolition of the nuclear levy in GB), held by DED, should be used to buy out generating capacity currently under contract to NIE to the maximum benefit of franchise and eligible customers.

Tom Barrett Head of Division,Transport & Energy UK and North Sea
European Investment Bank

Douglas McIldoon Director General
Office for the Regulation of Electricity and Gas (Ofreg)

n Sir Reg Empey and Mrs Mary O’Rourke meet regularly on energy issues and, on 10 January 2001, announced details of the award of a major consultancy contract. The joint study involves the preparation of information papers reflecting the energy markets in Northern Ireland and the Republic of Ireland, and the identification of options for the future evolution of both markets. The aim of the exercise is to identify possibilities for increasing convergence between the two energy markets with the ultimate aim of an all-island market for energy in a European context. The focus will be to bring about tangible benefits for business and consumers on both sides of the border. The study is due to be completed by the summer 2001.

n DETI and DPE officials meet monthly, working closely on energy issues. A formal Steering Group as suggested in Vision 2010 has not been created but there will be full opportunity for consultation through formal and informal mechanisms as the joint study findings and subsequent legislation proposals emerge.

n Work is continuing to reinforce North-South and to establish East-West electricity interconnection. By the end of 2001, the Moyle interconnector will have been commissioned ending the isolation of both Northern Ireland and Republic of Ireland electricity networks, and enabling suppliers in both jurisdictions to access electricity in Great Britain and wider European markets. The interconnector will enhance competition in the Northern Ireland market as 375MW of its 500MW capacity will be open to third party access from the outset.

n North-South interconnection will also have been reinforced by the end of 2001 with the doubling of the capacity of the main Tandragee / Louth interconnector from 300MW to 600MW and the upgrading of the two 110kv standby links in the North West of the island to full interconnector status. NIE and ESB are jointly exploring the potential for further strengthening of North-South interconnection and future proposals are expected to emerge by September 2001.

n Progressive opening of the electricity market continues with an extension to 32% taking effect from 1 October 2000. This allows around 420 of the largest (mainly industrial) electricity consumers to buy their electricity directly from generators and second tier suppliers instead of being required to buy it from NIE’s power procurement business. Many of those who have done so, have achieved savings of around 10%.

n Market opening has proceeded in a quicker timeframe than was anticipated in Vision 2010 and further expansion to 35% is planned from 1 April 2001, allowing a further 230 eligible companies to shop around for the most competitive price. This is two years earlier than required by the original EU Directive although there are recent signs that the Commission wishes to advance the timetable for full market opening.

n Vision 2010 proposed the use of the £40M support fund to buy down existing availability payments on both the Kilroot and Ballylumford contracts, to the maximum benefit of franchise and eligible customers.

n Implementing this recommendation has proved a protracted exercise, throwing up complex legal, financial and taxation issues. However, the Ballylumford buy-down – involving a payment of £10M – was concluded on 6 December 2000. In the context of this arrangement, Ballylumford is converting to modern Combined Cycle Gas Technology (CCGT) which should, after 2002, result in significant fuel efficiency savings with a consequent downward impact on prices. The Kilroot buy-down – involving the other £30M - is in its final stages with resolution of a major taxation matter being the final hurdle.

n The Utility Bill was enacted in GB in July 2000. Sir Reg Empey has indicated that he intends bringing forward legislation proposals for NI in the September 2001 to July 2002 programme. A Consultation Paper will be prepared and a full consultation process undertaken in advance of these proposals being submitted. The report of the Enterprise, Trade and Investment Committee’s inquiry and the options identified by the joint study at Action Point 1 above will be key elements in defining areas requiring legislation.

n The Department is preparing Regulations to implement the Gas Directive in Northern Ireland. A draft of these will be passed to the Committee for scrutiny in due course. It was hoped that they would have been with the Committee in December 2000 but the provisions are complex and a number of issues remain to be clarified by the Department’s legal advisers.

n The possibility of securing support funding from the new European Programme funds has been factored into the negotiation documents for the next round of Structural Funds. An alternative option for energy projects is the Executive’s Infrastructure Programme Fund.

Action Point 8 - Examine Possibility of EU Funding for Sound, Well-developed Pipeline Projects

n The Department and the Regulator are currently appraising a number of proposed gas pipeline projects and it is virtually certain that all will require a degree of assistance.

n Simultaneously with the publication of Vision 2010, the Department published “Renewable Energy in the Millennium – The Northern Ireland Potential”. (Copies of this will be forwarded to the Committee). In October 2000, the Department published, jointly with the Department of Public Enterprise, an “Assessment of Offshore Wind Energy Resources” in the Republic of Ireland and Northern Ireland.. Following on from the outcome of a consultation paper, “Stimulating Renewable Generation in Northern Ireland”, published by the Regulator in September 2000, the Department intends to consult interested parties shortly on the development of renewable energy sources in Northern Ireland. This process will also seek views on replicating the recent GB Utilities Act provisions relating to the placing of a renewables obligation on licensed electricity suppliers.

n As indicated in Vision 2010, the Department wrote to all the industry sectors involved in Strategy 2010 asking them to set out their energy efficiency and CHP targets. The outcome was disappointing with no sector responding. Getting across the energy efficiency message in a manner which brings tangible improvements in the use of energy remains a fundamental issue.

n When introduced on 1 April 2001, the levy will increase the price of electricity for Northern Ireland industrial users by 0.43p per kilowatt hour. The levy is intended to be overall fiscally neutral – it is offset by a 0.3% reduction in employers’ National Insurance Contributions and intensive energy users can also take advantage of discounts of up to 80% on the levy. HM Treasury agreement to a 5 year derogation for the fledgling gas industry was secured. However, at this point in time, all aspects of the levy remain subject to approval by the European Commission.

n Many complexities remain to be dealt with as the electricity and gas markets are progressively liberalised. The Department appreciates the continuing co-operation of all interested parties as it seeks to put in place a framework for the structure of the energy market, including regulatory arrangements, for the ultimate benefit of all consumers. In this context, the Department welcomes the Committee’s inquiry and looks forward to its assessment of the current energy market and its recommendations for improving it.

Further to your letter of 19 December, please find attached evidence to the above committee for its enquiry into energy. If the committee feel it to be useful, I would be happy to also be invited to provide oral evidence.

1 This evidence is provided by Professor Brian Norton. Professor Norton is Professor of Built-Environmental Engineering and Dean of Engineering at the University of Ulster. He has over twenty years experience in the energy field, having worked on engineering, economic and policy aspects of energy supply and use. He is a specialist in solar energy applications, has authored over 200 publications and received a number of international awards. Among a variety of relevant roles he chairs the World Renewable Energy Network and the Eco-Energy Trust. He is a past-chair of the Institute of Energy in Northern Ireland.

2 The market for energy services is far from perfectly competitive. Though it is estimated that energy consumption can be reduced by over 20% by measures viable economically in a conservative context, consumers have limited choices and incomplete knowledge. Decisions are made without consideration of long-term costs. For example, consumers do not pay for negative impacts on natural and urban environments. Equally, where for economically-viable energy-saving products the initial cost is high, consumers continue to make imperfect economic choices. As a result, the choice made by individuals and firms can be the consumption of more energy than would be the case in a perfectly competitive economy. Consequential high energy consumption levels are not the least-cost option economically or environmentally.

3 Energy consumption is not controllable directly but, rather, is a consequence of decisions regarding built form, urban planning, energy supply infrastructures the specification and quality of manufactured products, labour costs and capital expenditure. Energy consumption is, thus, largely a side-effect of decisions by manufacturers, service providers, consumers, builders, planners and equipment suppliers. The minimum amount of energy used to heat a home, for example, is determined mainly by the builder and by building regulations. The builder decides how well insulated, beyond the needs of regulatory compliance, the home will be and what type of heating equipment will be installed. For similar buildings, about a 40% variance in energy consumption arises from occupancy patterns, habits of occupants and discretionary equipment choices.

4 Energy is considered by governments at variance with how consumers see it. The consumer is concerned with the end-product; for example, they want hot water, not the fuel to heat the water. Energy policy should focus on the ultimate “energy service” required. An energy service approach lowers energy consumption because it considers complete energy conversion systems, not just fuels and electricity.

5 The relative emphasis on competition and regulation depends on the institutional frameworks in place in a particular moment of time and available distribution, generation and metering technologies. Moves towards free access of new suppliers to energy networks will loosen certain obstacles to the development of a competitive market place. However, if greater competition leads to cheaper energy, that can give signals to consumers which will impede environmentally-sustainable lower energy use per unit output. There is no rationally “correct” price for energy. New prices are compared by consumers to current prices not to those that may prevail in a hypothetical perfect market. More fundamentally, it is unlikely that the costs of social and environmental impacts can be expressed scientifically in monetary values that will gain any consensus. Finally, whether undertaken by government directly or by via an intermediary regulator, energy prices are political decisions.

6 Part of the problem of bringing public awareness to energy efficiency is the fact that environmental damage is not included in energy costs. Energy policy and regulation should act not only on energy suppliers but also directly on users, builders, manufacturers and planners. Policy and regulation must relate to specific demand-side issues concerning equipment, vehicles, buildings and transportation. The Climate Change Levy provides the means to grant-aid supporting initiatives. Levy and grant-aid, however, must form a closed-loop that returns grant aid to those levied in a way that selectively encourages conservation, sustainable supply and reduces energy costs.

7 In the short-to-medium term lower energy costs (if appropriately regulated) accompanied by low carbon emissions, would result from an expansion of the provision of natural gas. Such expansion is also desirable to discourage the migration of energy-intensive industries to gas-supplied areas. This would be particularly adverse to employment in the Craigavon area and the north-west. Infra-structural investment in gas pipelines should thus be a priority.

8 In Northern Ireland, an electricity production strategy should have as core elements:

n including an efficiency factor in the regulated prioritised utilities regulation formula

n eco-tariffs and an eco-pool to finance renewable electricity production. NIE has introduced an “eco-tariff” that enables consumers, for a small premium, to buy “green” electricity. For every “eco-unit” sold, NIE will guarantee there will be renewable generation capacity installed. NIE will be able to contract new renewable capacity as the demand for eco-units grows

n supplying thermal energy and electricity services to those not connected to an electricity grid or natural gas distribution system

Complementary distributed energy services, such as solar energy, are effective in the form of passive solar heating, daylighting and ventilation of buildings, active solar water heating and via photovoltaic (PV) technology to provide electricity. PV, micro-hydro, biomass and wind can compete with electricity generation for areas not connected to the grid. Renewable energy can also be supplied to the grid by wind energy, wood biomass, hydro electricity and photovoltaics. This has been encouraged by the price guarantees to suppliers. Though price guarantees can render certain renewable resource options more attractive, it should have only the mildest effect on the price of energy. Any extra cost will be insignificant because price is based on resources already in place, not the total cost which is much larger than the additional new resource.

10 In general, the capital cost of electrical generation is lower with centralised facilities, however, this cost advantage is off-set by transmission and distribution costs. The need to transmit and distribute energy reduces when energy production is located near the point of use and matched in scale to end-use. This increases efficiency and reduces environmental impact. Finding appropriate matches means planning from the bottom-up rather than, at present, the top-down. For example: building energy use is small scale and, in rural areas, is dispersed; solar energy is also dispersed and well-suited to building applications. Renewable energy technologies (for example, a solar water heater) have generally high initial capital costs which are off-set by low operating costs. The cost of borrowing is high to small developers and home owners. Without price guarantees contracts, or other incentives (for example “cash-back” schemes for solar water heater installations) the high cost of capital would inhibit private investment in renewable energy even when the total cost over the life of the system is less than fossil-fuelled sources (for example, wind power in the second Northern Ireland NFFO round was cheaper than the average price paid by NIE for fossil fuel generated electricity during 1995).

Not all renewable energy is consistent with environmental sustainability. For large or storage hydro-electric projects, the land and other resources flooded and irretrievably lost often presents an unacceptable environmental impact. The environmental impact of a hydro project is also not a direct function of its size, as small diversions of rivers and of associated eco-systems can have disproportionately adverse impacts.

11 Trading the ability in Northern Ireland to generate electricity from renewables with elsewhere in the EU which have less scope for renewable electricity production would benefit Northern Ireland. Via an “Eco-pool”, trading “greener power” put into the Northern Ireland grid for “brown power” generated elsewhere would enable (for example, Dutch) consumers to pay any modest additional costs associated with renewable electric power, but reduce the EU’s overall CO₂ emissions. Though this is not physical trading (that is, greater substitution of fossil fuels in Northern Ireland is traded for less substitution in the Netherlands) it could become so with an electricity interconnector to Scotland in place. Trading wind-generated electricity from Northern Ireland brings new investors to the Northern Ireland renewable energy sector.

12 Northern Ireland’s indigenous substantive renewable energy industries are limited to one manufacturer of solar water heaters and several suppliers and operators of wind and biomass systems. The world market for renewable energy is growing substantially and given Northern Ireland’s universities recognised R&D record in the field and consequently the availability of local expertise, there are certainly opportunities for the development of a renewable energy product industry in Northern Ireland. Many Northern Ireland firms have capabilities and production capacities cognate with various renewable energy products (eg glass processing, building product manufacture, airfoil sections, off-shore platforms, semi-conductors). There is a need for a pro-active approach to make relevant sectorial firms aware of the business opportunities and support for market-focussed new product development.

13 Transport externalities (ie the costs borne by those other than the traveller or beneficiary of the journey) are considerable when greenhouse gas emissions, air pollution, noise, congestion and accidents are taken fully into account. For the UK, these costs are between £45.9 and £52.9 billion which is three times all taxation income from road transport. A conservative estimate would be transport externalities of £0.09 billion in Northern Ireland. Transport accounts for over 22% of Northern Ireland energy consumption. All conventional transport fuels are non-renewable. The non-sustainable combustion of transportation fuels accounts for a large proportion of the emissions of carbon dioxide and nitrous oxide. Measures for pursuing sustainable energy use in the transport sector should:

14 Urban and suburban growth has turned away from compact mixed use, towards lower density with a separation of commercial and residential areas. Rethinking development is fundamental in achieving energy efficient transportation which has positive implications for air quality, greenhouse gas emissions and land use. By encouraging mixed use and higher density, the necessity for many car trips may be shortened or eliminated. More emphasis on public transport use would then be feasible. Building more roads and bridges does not, in the longer term, reduce overall congestion - in fact it leads to increased demand which, in turn, leads to increased congestion. To reduce the number of car journeys, vehicle occupancies need to increase and more people need to travel by bus and rail. Several specific measures could promote more energy efficient modes of transport - encouraging developers to make better use of inner city sites, more bus lanes, more facilities for cyclists and charging tolls for roads and bridges. As it is now possible for tolls to be collected electronically, (their use consequently not increasing congestion), pricing each trip would ensure that individuals make decisions based on a cost close to the actual cost of road transportation. This would eliminate many marginal journeys or divert them to more energy efficient modes.

15 Buildings designed now will require the same amount of energy and produce the corresponding amount of greenhouse gases 40-80 years from now. Retrofitting energy efficient measures is expensive and only partially effective in reducing energy requirements. Bearing in mind this and the 30% contribution of energy use in buildings to total energy use, urgent measures are necessary. There is a plethora of measures that can be adopted now without changing building design. A less-conservative design and construction client culture would enable many innovative energy-saving or solar energy harnessing house building fabric components to find widespread use. The insulation of buildings needs to improve and all systems within buildings that produce and distribute useful energy need to be improved in their efficiency. There need to be joint financial mechanisms between builders, utilities and lending institutions for energy efficient design and construction, for example, “energy saver mortgages” in which the energy cost savings are included when determining mortgage terms. An alternative could be for the cost of equipment and upgraded building fabric to be paid as part of subsequent energy bills. Energy rating should be linked with the rateable value of the property.

This submission has been prepared by Northern Ireland Electricity to assist the DETI Committee in its Inquiry into Energy in Northern Ireland.

We have responded to the Terms of Reference as set out in your letter of 19th December:

n To assess the energy market in Northern Ireland and examine its role in the growth of the economy as described in Vision 2010 and the Programme for Government and the potential for supply and co-operation beyond the region.

n To assess the potential for the renewable energy market both domestically and in terms of capturing the emerging export markets with particular reference to the potential for renewable indigenous energy industries.

Our submission deals chiefly with electricity matters and the prospects for renewables, although we do comment on the potential for expansion of the gas industry in Northern Ireland.

The information provided has been drawn both from our experience of the electricity market, and the detailed analysis supporting many formal consultation exercises carried out within the industry over the last 5 years or so.

This is an extensive and often complex subject where the underlying problems have not been amenable to quick solutions, involving as they do very large capital amounts and long contractual commitments.

In our submission we have endeavoured to be as concise as possible and limit our comment to what we see as the central issues requiring attention.

We would be glad to provide any further written submissions or evidence which the committee decides necessary.

1. Treasury receipts for the power stations in NI were approximately twice the figure per MW of capacity, compared with England & Wales.

2. Generation costs in NI are over 40% higher than in GB. This figure has been confirmed in work carried out by both Ofreg and ourselves.

3. They will remain at this level for the duration of the contracts, i.e. until the period 2010-2012.

4. If this disparity were removed electricity tariffs in NI would fall by some 20% giving prices to NI customers comparable to those in GB.

5. There has been little reduction in generation prices for the vast majority of customers since privatisation was introduced (see chart on page 7).

6. The recent announcement of a 9% price increase in tariffs is due to the pass-through of higher fuel costs incurred by the power station operators.

7. Conversely NIE’s own charges to domestic customers have been reduced by some 41% in real terms since privatisation (see chart on page 7).

8. In the decade since privatisation NIE will have invested some £650m in improving its network infrastructure. The increased level of investment during the 90’s addresses both the infrastructure deficit of the 70’s and 80’s, and the need to ensure there is no constraint on future economic growth.

9. Recent generator contract restructuring, although introducing more efficient and environmentally friendly plant, has had a negligible effect on bringing down prices and will not do so until after 2012.

10. It would cost some £500m to buy the generator contracts down to competitive cost levels.

11. Refinancing the contracts into the future could exchange lower costs today for higher costs in the future. This route however extends the life of potentially uncompetitive contracts, raises public interest questions, and requires legislation to back the financing arrangements.

12. Any new generating capacity entering the market in NI should do so on a competitive basis and not be underwritten by long-term contracts.

13. The introduction of the electricity interconnector with Scotland in December 2001 will provide access to alternative, more competitive generation.

14. Additional interconnection with RoI would facilitate a closer integration of the markets in the two jurisdictions providing the opportunity of a larger single market with a more competitive dynamic and economies of scale.

15. Market opening has provided the opportunity for the larger customers to contract with alternative suppliers. However their ability to do so is constrained by the limited amount of uncontracted generating capacity available in NI (or RoI).

16. Further market opening carries the risk of leaving an increasing share of the burden of the present contracts with domestic customers.

17. Renewable energy sources could potentially provide some 7.7% of NI’s electricity needs.

18. In the present circumstances it would be hard to make a case that renewable energy should add to the burden of costs carried by electricity customers. NIE’s eco-tariff provides choice for customers who wish to support ‘green’ energy, without burdening the general body of customers.

19. The introduction of the Climate Change Levy (CCL) will create a market opportunity for renewables.

20. Renewables should be encouraged where clearly they can compete with conventional energy sources.

21. Energy efficiency initiatives should receive at least as much attention as renewables.

22. All-Ireland trading in renewables provides an opportunity for a larger market for renewable generation.

23. It is unlikely that there will be early extension of the gas industry in NI based solely on private sector investment.

24. Linking the gas infrastructure in NI and RoI would provide increased security of supply and potential diversity in sourcing gas supplies.

25. There are proposals presently being put forward by the power stations for additional schemes for emissions abatement involving costs of between £3m and £30m p.a.

26. NI electricity customers already largely fund the costs of the gas interconnector with Scotland and investment in emissions abatement, via the generator contracts.

27. We would advocate no further imposition of costs of this nature on electricity customers either via postalisation of new gas pipeline costs, or the application of further emissions abatement legislation in advance of absolute need.

28. Similar to GB, regulation has operated effectively in transferring the benefits of NIE’s efficiency gains to customers. Unlike GB however it has not been possible to introduce as yet any meaningful level of competition to bring pressure on generation costs.

29. Historically, NIE tariffs have been linked to the highest tariff in England and Wales. During the early 1980’s, due to over-dependence on oil as a power station fuel and the very high price of oil at that time, NIE’s tariffs were heavily subsidised by Government. The subsidy was calculated to bring NIE’s tariffs into line with the highest tariffs in the Area Boards in England and Wales. This policy continued into the late 1980’s.

30. In 1992-1993 the electricity industry in Northern Ireland was privatised. The stated aim was a gradual introduction of competition to create a downward pressure on costs allied with regulation of prices where competition was not effective. In addition to being relieved of the duty to control the industry, Government would also be relieved of the burden of capital borrowings and might, from the sale of the various components of the industry and from subsequent taxation of profits, achieve significant new revenues.

31. The method of privatisation in Northern Ireland differed from the process in GB in that it involved both a public offering and a trade sale. The transmission and distribution and supply businesses were formed as NIE and floated in June 1993 with a similar regulatory regime to that in Great Britain. The generating stations were separated from NIE and privatised by setting long-term contracts for each power station and selling the stations as a trade sale.

32. The generator contracts could be cancelled at specific earliest cancellation dates and by this means, a competitive wholesale power system could eventually be introduced.

33. The generator sale proceeds totalled some £353m. In addition, the sale of Ballylumford Power Station to British Gas brought with it a commitment to contract for a gas pipeline between Scotland and Northern Ireland, and to enter into a contract with British Gas for the conversion of the power station to gas firing.

34. The level of proceeds received by the Treasury for the sale of 2200MW of generation in Northern Ireland (£160/KW) was approximately twice that received for the sale of generating plant in England & Wales on a comparable basis.

35. It was recognised that the costs of the gas pipeline and the conversion of Ballylumford to gas firing would increase prices in Northern Ireland, and that the removal of the nuclear levy in England & Wales would decrease prices on the mainland at the time. The differential arising was estimated to be of the order of 1.0p/kWh (circa 12%).

36. The outcome to the domestic electricity customer bore out these predictions. The price in Northern Ireland matched that of the highest companies in England & Wales (Manweb, Swalec and Sweb) from 1992/93 to 1994/95 but began to diverge in 1995/96. The differential which has emerged between N Ireland and England & Wales prices since then is largely due to the reduction in prices seen in England & Wales due to the expiry of the pre-privatisation coal-fired contracts, the move to competitive markets and the removal of the nuclear levy.

37. The only substantial generator contract restructuring to date has been the replacement of the existing plant at Ballylumford Power Station with a new combined cycle gas plant. The new plant is considerably more efficient and therefore less polluting and should, in the long run, provide a path to lower generation costs. However the installation of the new plant also required the buy-out of the future profit stream of the existing plant. This involved raising borrowings of £180m to pay British Gas for their existing contracts. The financing of the contract buy-out will be repaid by customers in the form of a levy until 2012.

38. The approach to dealing with the generator contracts thus far has been a voluntary one where the generators have been asked to bring forward proposals for contract restructuring which would reduce the cost of their generation.

39. Therefore although the restructuring of the contracts at Ballylumford has brought new, more efficient plant onto the NI system, because the existing station had to be bought out, the customers will see little price reduction before the expiry of the buy-out termination date in 2012. The more efficient plant does however have the benefit of reducing the impact of gas price increases.

40. The only other proposal, which we understand has been presented to Ofreg, has come from Kilroot and involves the conversion of the station to fire orimulsion, a bituminous fuel from Venezuela. We do not take a view on the environmental acceptability or otherwise of orimulsion, we assume that such considerations would be fully dealt with as part of any consents process. We do however have serious reservations about the economics of such a proposal.

41. As part of the October 1999 review of generation costs, Ofreg’s consultants, London Economics, considered the investment needed to convert Kilroot to orimulsion and the likely savings in fuel costs which could be derived. As orimulsion has a high sulphur content it would be necessary to incur the cost of Flue Gas Desulphurisation equipment as part of the conversion. London Economics felt that unless the conversion could be carried out before 2002, the scheme was not obviously economic.

42. The orimulsion proposal also entailed the removal of the early cancellation clause from the Kilroot contract and allowing the contract to continue to 2024. The prospect of such an extension to an already uncompetitive contract is alarming, unless an overwhelming case could be made for such a step. No such case exists at present.

43. As mentioned earlier, the buy-out of the future profit stream of the Ballylumford contract involved finding approximately £180m of new borrowings. A similar profit buy-out at Kilroot would also cost around £180m. These figures taken together with the LTi3 gas contract indicate a buy-down figure of around £500m to bring generation prices in Northern Ireland down to competitive levels.

44. The main contribution to solving the problem of diverging tariffs (indeed the only material contribution so far) has been via NIE’s efficiency gains and our periodic price review.

45. However as generation forms such a large portion of customers bills (around 60% for the average domestic customer, and over 85% for the large industrial customer), it is obvious that a solution must be found to the high cost of the generator contracts if any serious impact is to be made on NI’s tariff.

46. During the 8 years since the privatisation of the industry in NI, NIE’s component of the domestic electricity bill has fallen by 41% in real terms.

47. The major contribution to the reduction in the NIE component of the bill has come from the fall in transmission and distribution (T&D) charges. Overall T&D charges have fallen by 27% in real terms from their 1992/93 level.

48. The present price control which came into effect from 1st April 1997, required an immediate 25% cut in T&D charges which was followed by an annual reduction of 2% below the rate of inflation for the ensuing 5 years. NIE’s T&D price controls are presently under review and new controls will apply from the 1st April 2002.

49. While T&D prices have fallen investment in the NI electricity network has increased significantly. By the end of the current regulatory period, NIE will have invested some £650m since privatisation, in improving, reinforcing and expanding the electricity network.

50. The strategy behind this investment was to address the investment deficit of the previous two decades and to ensure that the reliability and capacity of the network would never be a constraint on economic growth in NI.

Figure 2 shows that the investment in the post privatisation period is almost twice the level in the previous decade.

51. It would not have been possible to make these investments and reduce NIE’s T&D prices, but for the very substantial cost reductions in its operations which NIE has achieved. These efficiency gains have either been passed directly to customers in lower charges, or have funded the increased costs of the investment programme.

52. Since 1992, controllable operating costs in NIE’s T&D business have fallen by 20% in real terms. On the basis of cost comparisons published by the Centre for the Study of Regulated Industries, NIE has been reducing its costs faster than the GB average. Over the period 1992/93 to 1998/99 the average annual reduction in NIE’s operating costs (less depreciation) was 4.49% compared to 3.86% for the GB average.

53. The reduction in operating costs has also been accompanied with increased levels of customer service.

54. The average length of time customers are off supply due to faults has been reduced by over 40% since 1993 and we have reduced our failures against Guaranteed Standards in the same period by over 90%. We were the first UK electricity company to abolish standing charges for domestic customers and amongst the first to totally eliminate the disconnection of customers for non-payment.

55. NIE has won many awards at both local and national level for the quality of its businesses and its involvement in the community. The company also holds Chartermark and Investors in People. Many of our individual activities are ISO9000 accredited and we expect to be awarded ISO14001 for environmental management for NIE early this year. (This will again be a first for the entire operations of a UK utility).

56. The Director General is currently conducting a review of NIE’s transmission and distribution price control and is scheduled to publish his final proposals in July 2001.

57. NIE does not consider that a comparison of prices in NI and GB should be a guiding principle of the review. In T&D pricing the GB average price is not an appropriate comparator since the size and nature of the customer base and the service territory are key determinants of T&D costs. In these respects NIE is very different from the average GB company having one of the smallest customer bases connected to the most widely dispersed rural network. In addition NIE has had a large capital investment programme which has been running at over twice the GB average levels, partly in response to peak demand for electricity which has been growing at around four times the GB rate.

58. Indeed even amongst the GB companies there is a wide variation in T&D prices. For example, the cheapest GB company’s T&D price is currently 25% below the average, while the most expensive is 44% above the average.

59. In the absence of any major restructuring of the generator contracts the key influence on lowering generation costs is competition in the generation market.

60. The ways in which competition can be introduced in NI are limited. Firstly, additional generation, not under long-term contract, could be built, although the opportunities for introduction of such generation are limited by the size of the market. Secondly, Northern Ireland could become part of a larger market through interconnection with its neighbours.

Creating and enhancing interconnection between the electricity system in Northern Ireland and those in RoI and Scotland has been a central plan of energy policy in Northern Ireland since the adoption of “Energy for the Nineties and Beyond”, and remains so in Vision 2010.

61. At vesting in 1992, the NIE transmission system was totally isolated. In line with energy policy for Northern Ireland and recognising the potential strategic and competitive benefits to customers which could be realised through interconnection with its neighbours, the company has invested considerable resources in promoting interconnection. Since 1992 NIE has constructed the 110kV connections with the ESB system at Strabane/ Letterkenny and Enniskillen/Flagford, repaired and restored the 275/220Kv North-South Interconnector in 1995, and commenced the construction of the 500MW interconnector linking Northern Ireland with Scotland.

62. We have also commenced work in conjunction with the ESB which will double the capacity of the main North/South 275kV link, and convert the 110kV connections to full system interconnectors. Both these projects are under construction and are due for commissioning in December 2001. These projects are a very good start in providing the interconnection capacity necessary to facilitate the development of an all-Ireland electricity market.

63. From 2002 onwards interconnectors will become much more significant in terms of potential benefits to customers in NI as the NIE system becomes more closely integrated with its neighbours. The Moyle Interconnector linking the NIE system to that of ScottshPower will provide 500MW of interconnection capacity by the end of 2001. At the same time the increased North-South capacity incorporating the upgraded 110kV connections, and the increased capacity of the main North-South 275kV interconnector from Tandragee to Louth, will have provided 940MW of physical interconnection capacity between the two systems.

64. The effects of this major expansion of interconnection capacity will be felt in downward pressure on electricity prices in the competitive markets, both North and South. It is expected that these competitive pressures will grow as trading between the three systems increases. Electricity market participants will thus gain unprecedented freedom to trade electricity in an all-Ireland market which will benefit from the stimulus of external competition from Great Britain. It is particularly significant in this context that the Scottish generation system has for some years had surplus low-cost capacity, and this should be available for export to Northern Ireland.

65. Opportunities to establish further interconnectors between NIE and ESB networks in the future, particularly at 110kV, are the subject of joint studies between the two companies. These studies are recognised and part funded by the EU as possible forerunners to further interconnection. It should be noted, however, that significant constraints exist on interconnection capacity, particularly for South to North power flows, due to weakness in the ESB transmission system. The ideal solution, though more costly, is further interconnection at the 275kV voltage level.

66. In summary, NIE believes that one of the significant contributors to lowering electricity prices in Northern Ireland is enhanced interconnection with neighbouring systems. The company has made a major contribution to achieving this and will continue to promote interconnection where feasible and economic. It is hoped that the development of energy policy for Northern Ireland, and indeed on an all-Ireland basis, will continue to recognise the significant role of electricity interconnection and provide incentives to its continued enhancement.

67. The long-term aim of the privatisation process was to introduce a competitive system where customers would have the opportunity to ‘shop around’ for the best price for their electricity consumption. The structure put in place in 1992 was initially set so that NIE’s Power Procurement Business was the monopsony purchaser and the monopoly seller of power to supply companies. However, it was expected that the Director General would introduce a system of wholesale trading which would facilitate the early cancellation of the power station contracts which in turn would free the plant to operate in the competitive market.

68. In the event the EU introduced the single market Directive in 1997 which enabled the Internal Market for Electricity. The Directive required that by February 1999 the largest customers, across all European states, making up 26% of the market, should be allowed to contract directly with any generator for their supplier. The Directive also requires market opening to progress to 30% in February 2000, and to 35% in February 2003.

69. In NI the Department, Ofreg and the electricity industry agreed to open the market to 35% by 1st April 2001, i.e. 2 years early. The aim of introducing a competitive wholesale system as soon as possible was so that cancelled power station contracts would be available to offer their output to the new competitive market, and thereby allow at least some customers to begin to benefit from competition.

70. Those customers able to contract with the newly independent power plants could potentially realise lower prices due to the downward pressure of competition. Customers remaining within the franchise market might however see an increase in prices, since the fixed costs of the remaining power station contracts would be spread over fewer customers. However this tendency would be offset by the cancellation of some contracts which would, in turn, remove some of the fixed costs and thereby avoid material increases to any group of customers. This has generally been the case up to now.

71. The Bulk Supply Tariff (BST) issued by NIE is required to recover the costs of the long-term contracts. As the wholesale competitive market emerges and begins to grow, the total sales under the BST will diminish. Since the contracts contain a considerable amount of fixed costs, which do not reduce with lesser sales, the tariff will naturally tend to rise. The transition from a market supplied 100% from contracts, to an emerging wholesale competitive market has been managed so far without significant price increases to franchise customers. This has been mainly due to the limited amount of market opening (35%), and the expiry of contracts at Power Station West and Coolkeeragh reducing the amount of contracted costs which customers have to bear.

72. However, if the market is opened further, the costs of the long-term contracts would fall on an ever-decreasing customer base, and eventually those customers least able to carry the burden.

73. The solution acceptable to European authorities in this regard, and already partially agreed with the Department and with Ofreg, is that there should be a levy over all customers covering such stranded costs.

74. It is quite likely that Europe will decide to legislate for full market opening in the near future, possibly to be achieved by 2005. It is important that either some form of stranded cost arrangement is put in place before then, or a solution to the uncompetitive cost of the generator contracts is found.

75. In 1993, the DED in Northern Ireland, in line with United Kingdom Government policy, announced its intention to encourage the development of commercially viable renewable energy sources in Northern Ireland. A scheme was developed which involved placing a non-fossil obligation (NFFO) on NIE to initially secure about 16MW of renewable generation, rising through successive NFFO’s to 45 MW by 2005.

76. In August 1993 the DED, NIE and the Office of Electricity Regulation (OFFER (NI)) held a seminar in Belfast for prospective renewable energy developers where the NFFO competitive tendering process was described in detail. The first stage of the tender process involved proposers completing and returning a technical and planning questionnaire. Tenderers who completed the initial questionnaire satisfactorily were asked to make a business case submission, which assisted NIE in establishing the financial and commercial viability of the scheme.

77. Following the call for proposals, a total of 64 developers returned the Technical and Planning Submission to NIE. Of these a total of 45 schemes completed both phases of the process. Seven technology types were tendered, ranging from Biogas through waste incineration to small-scale hydro and wind.

78. Following assessment 20 contracts were awarded to 12 different companies. Most of the companies were based in Northern Ireland.

79. The NFFO schemes covered 3 technology bands. There were 6 wind schemes totalling 12.664MW and 9 small-scale hydro schemes totalling 2.374MW capacity. The 5 sewage gas projects totalling 560Kw have now been withdrawn. The schemes are located in all six counties in Northern Ireland.

80. The average bid price paid to successful generators were approximately 6p/kWh. The comparative price of electricity generated by Northern Ireland thermal power stations is 3p/kWh.

81. The NI-NFFO2 tender process was broadly similar to that of NI-NFFO1. A total of 90 schemes were submitted at the first stage of the tender process, followed by 79 developers submitting priced tenders. Of the 79 schemes proposed, 33 were wind projects and 18 were hydro. The remainder consisted of biogas, waste incineration, landfill gas and biomass.

82. Ten successful projects were announced in September 1996, involving a total capacity of 15MW. The projects represented 6 technology bands; waste incineration, wind power, hydro, landfill gas, biogas and biomass.

83. The average bid price paid to NI-NFFO2 contractors is approximately 4p/kWh. This lower bid price is a reflection of the improvement in the technology between NI-NFFO1 and NI-NFFO2, particularly in wind energy technology. Via the NFFO order NIE now have contracts for 32MW of renewable power.

84. While NFFO is a mandated approach to bringing forward renewables, an alternative is to offer a ‘renewables tariff’ to customers who wish to pay a premium to encourage renewable energy.

85. The NIE EcoEnergy Tariff, introduced on 20 October 1998, allows renewable generated electricity to be purchased and sold through NIE’s supply business. NIE has pledged to match EcoEnergy users’ consumption with an equivalent amount of new renewable energy. Consumers can choose to have 10%, 50% or 100% of their energy supplied under the EcoEnergy tariff.

86. Any electricity customer, regardless of size, can purchase renewable electricity from any renewables generator anywhere in Northern Ireland and, since 2000, any generator in the Irish Republic. As a trial trading arrangement, NIE sold a portion of its contracted NFFO energy to Eirtricity, a renewable energy supplier in RoI.

87. As present the only significant stimulus to growth in the renewables market in the absence of a further NFFO order is NIE’s EcoEnergy tariff. Under the terms of its price control NIE has committed to a tenfold increase in the level of sales of NIE’s existing EcoEnergy tariff. The demand for renewable energy to satisfy this obligation will be met through both existing and new contracts with approved renewable energy developers. The existing EcoEnergy contracts are wind based and include a 7.2GWh wind energy contract with B9 Energy Services Limited and a 12.5 GWh contract with Enron. A further contract will be required to fully satisfy the tenfold increase and it is proposed to tender for the balance in the Spring of 2001.

88. NIE will be required to match the supply of renewable energy with a demand from customers. Although uptake has been initially enthusiastic, further increase in sales will require new strategies, such as targeted marketing, special purchase arrangements with environmental NGO’s and sales to larger customers, such as Government estates and education authorities.

89. The introduction of the Climate Change Levy (CCL) will give a further impetus to renewables. The CCL will add 0.43p/KWh (around 5%-10% depending on the type of customer) to the price of electricity for most businesses and industry.

91. The price of energy from modern wind schemes is such that they will be able to compete with conventional tariffs which will include the levy. We would expect to see a ramping-up of activity in the coming year by supply companies in these markets. There are around 50,000 SME customers in Northern Ireland who could potentially avoid the CCL by taking their supply on a renewable tariff.

92. There is a shortfall of around 13MW against the original target following the two NFFO rounds (i.e. 32MW contracted against 45MW in the order). DETI have suggested that EcoEnergy and any independent renewable generation could be counted towards the target, however they have not ruled out a further NFFO round.

93. The Utilities Bill will, when introduced in GB, place a requirement on all electricity suppliers to contract to provide at least 10% of their electricity from renewable sources by 2010. The Bill states that the obligation will be in force subject to the cost to customers. When the NIE version of the bill is considered by the Assembly the treatment of renewables under the bill can be considered.

94. We would advocate that particular care is exercised in deciding the method to bring forward further renewables in Northern Ireland to ensure that no further cost burden is placed on customers.

95. The report ‘Renewable Energy in the Millennium – the Northern Ireland Potential’ commissioned by the DETI in a joint study with NIE and WREAN identified that even if the maximum estimated contribution from all the reviewed technologies was realised, a figure of 10% of NI electricity needs could not be met. A figure more like 7.5% may be achievable.

96. Clearly then even if the maximum resource could be utilised (which is very unlikely) there would be significant difficulties in making a 10% obligation.

97. It may be that an all-Ireland solution is possible but the potential for renewables in RoI to meet NI obligations, and for trading between RoI and NI, would need to be thoroughly explored.

98. The extension of the natural gas network throughout NI should bring greater energy choice and the prospect of competition between competing fuels to a much wider range of customers than is the case at present.

99. Obviously competition at the primary energy level is particularly important to those customers whose input prices are dependent, in a sizeable way, on energy prices.

100. Gas networks are heavily investment intensive and given the dispersed nature and relatively low population of the majority of NI’s towns, it is difficult to achieve the demand levels necessary to make wide geographic network extension, economic.

101. Almost certainly extension to supply the wider domestic market in NI, while possibly socially desirable, is not an economic prospect without substantial subsidy. Equally however, if there is a tentative case for extension to supply industry, or for power generation for example, then the existence of a local retail market can add to the overall economic case for the pipeline. We understand that this sort of argument underpinned the case for extension of the gas network to the North/West.

102. We are of the opinion that maximum geographic coverage can be achieved by ‘bundling’ together opportunities to extend the network. For example, we proposed that the North/West proposal should be bundled with a pipeline to Craigavon, which in turn, could act as the forerunner of a cross-border link.

103. Our experience however, of pipeline projects in NI, has been that it is very difficult to see an economic case for major extension without subsidy.

104. We would also advocate that a substantial impetus could be given to customer uptake into the gas market if the downstream gas business was immediately opened to any supply company. A number of companies marketing the product and competing for increased sales would give customers choice, introduce competition and accelerate expansion.

105. Also with the prospect of gas coming ashore at Corrib in the west of Ireland there is the potential to supply the Derry/Sligo/Galway corridor with gas in a way that was impractical from Kinsale or Dublin.

106. We understand that the proposals contained in the Brattle report into pipeline charging in the RoI are a significant deterrent to a North/South pipeline. This is obviously a hurdle that needs to be tackled at ministerial level.

107. When the sale of the power stations was proposed, it was recognised that Government would get a higher return for the sale if the risk of further expenditure due to tightening of restrictions on station operations could be passed through to NIE and on to customers. Thus a ‘Change in Law’ clause was included in the contracts which allows that any increase in power station costs which is caused by an act of Government, can be claimed back from NIE.

108. The first effect of this clause came via the requirement of the Industrial pollution and Radiochemical Inspectorate (IPRI) on the electricity generators to restrict the amount of sulphur dioxide being emitted into the atmosphere. In 1990, around 90,000 tonnes of this gas were emitted by NI power stations. This amount was to be reduced to minimise further acid rain damage on the environment.

109. A more expensive form of heavy fuel oil (low-sulphur HFO) was purchased for the Ballylumford Station, burning this low-sulphur fuel enabled the station to meet the restrictions. A further example of additional costs was the requirement that Kilroot should install equipment in their burners to reduce the amount of Nitrous oxides emitted.

110. We now face the threat of further requirements by IPRI to reduce emissions still further. The sulphur dioxide emissions from NI power stations have already fallen from 90,000 tes in 1990 to around 30,000 tes in 2000 and are expected to fall to around 10,000 tes by 2010. We are of the view that these levels of emissions, particularly from power stations with high chimneys, ensure that there is no health risk to the surrounding area. Also that a total NI emissions figure of 10,000 tes is acceptable to the other European states for the year 2010. We do not believe that there is any value at all in further expenditure being required to reduce sulphur dioxide emissions from NI. To this end we have been pressing the Air Policy branch of the Department of the Environment to avoid this requirement.

111. There is also a desire within IPRI to reduce nitrous oxide emissions from power stations. Again, there has already been expenditure on reduction equipment at Kilroot and the re-powering of Ballylumford with a CCGT plant will significantly reduce nitrous oxide emissions. Again there is no health risk if there is a high chimney and the forecast level of output is within the European requirement. We do not believe there is any value for NI in further expenditure in this area, particularly were it seems to be driven by DTI policy over and above European requirements.

112. We believe that it would be valuable to challenge the department of the Environment – Air Policy branch and IPRI to define the value to NI of any further pollution control requirements on local power stations before making any directions which will increase the price of electricity to the small customer sector still further.

113. Regulation of an industry is required where competition is not, or not yet, effective.

114. The purpose of regulation is to ensure that prices customers pay for goods or services and the quality with which they are delivered, is consistent with what would be expected in a competitive market. Regulators will also usually have a duty to promote and facilitate the emergence of competition.

115. Regulation in the UK (and perhaps throughout the world) has not been an entirely satisfactory experience. It has often been characterised by disagreement and dispute. While a certain amount of ‘tension’ in the relationship between regulators and regulated may be healthy, too much discord creates the perception of a regulatory system which lacks stability and leads to a poorer result for customers in general.

116. Part of the reason behind the introduction of the Utilities Bill in GB was to address best regulatory practice and to ensure that transparency, consistency and predictability were recognised as guiding principles central to good regulation and a stable regulatory system. To this end the Bill clarifies and strengthens the role of the Competition Commission in dispute resolution.

117. While NI may indeed require some ‘tailored’ solutions to its particular problems, and a recognition that there are factors at work in NI which can be unique, there is also the availability of established conclusions, precedent from GB reviews, and a body of decision from exhaustive consultations and referrals. This body of precedent should not be easily ignored when forming opinions about the form of regulation which should apply in NI.

118. NIE is now into the work of its second price review and there will no doubt be differences of opinion and sometimes fact, between the company and Ofreg. It is possible that such differences can be accommodated within the review process providing the purpose of the review is clear and not contrived to fit an inappropriate objective.

119. The purpose of the price control review is not to bring NIE’s T&D price into line with the GB average, but rather to establish a revised price control for NIE which, taking account of the context in which NIE operates, will produce sufficient revenue for NIE to conduct its T&D activities to the standard required by customers. Many of the main issues to be examined in this price control review have not changed significantly since the MMC Review of 1997. NIE believes that, notwithstanding any differences of interpretation, the work of the MMC provides the starting point for the current review.

120. There are well tried and tested methodologies and precedents for arriving at an optimal answer when reviewing utility price controls and they are well suited in their application in Northern Ireland. On this basis there should be no reason why Ofreg and NIE should not come to an agreed conclusion as to the new price control and we would welcome such an outcome.

121. The outcome of this review is of great importance to customers and to the company. In the area of capital expenditure for instance, whilst recognising the continuing need for the effective use of resources, NIE is acutely conscious of the need to ensure that an appropriate level of investment is available to meet the potential for any acceleration of demand growth which might be consequent upon a new momentum in economic development.

ESB submits the following comments through its subsidiary ESB International Investments (ESBII). ESB welcomes the opportunity presented by the Enterprise, Trade and Investment committee to comment in advance of its enquiry into energy. We believe that it is timely and appropriate to review the energy market in Northern Ireland, to acknowledge progress to date and review how best to develop the market in the future.

ESB, through its subsidiary ESB International Investments (ESBII) is committed to a significant long-term role in the development of the Northern Ireland energy markets. This has been demonstrated to date by:

n ESBII’s development of a new 400MW CCGT power station to replace the existing power station, in partnership with Coolkeeragh. This new power station will act as the anchor tenant for the development of a natural gas pipeline to the North and Northwest and will provide competitively priced electricity in Northern Ireland. The Director General of OFREG has recommended this new development as offering the best value for consumers.

n ESB’s commitment to the competitive market in it’s role as a Second Tier Supplier.

To date the Northern Ireland electricity market has seen the initial benefits of competition in electricity supply, though the lack of competitive generation has been a constraint. It is now appropriate to review how Northern Ireland may best benefit in the context of:

n strengthened interconnection of the Northern Ireland electricity system with the Republic of Ireland and with Scotland,

n evolving market conditions in Northern Ireland, the Republic of Ireland and Great Britain.

These new market aspects present the potential to maximise the benefits that may accrue to Northern Ireland from entering a new era of energy market forces.

While the Northern Ireland electricity industry has made progress since privatisation in 1992, the current high electricity prices point to a need for further reform.

Furthermore, the benefits which competition will bring to the eligible sector will undoubtedly lead to pressures to widen the net of competition in terms of market opening. In Northern Ireland this is unlikely to be achieved without addressing the long-term power purchase contracts which have existed since privatisation.

It is against the above background that ESBII submits the comments within this paper. Please note that the purpose of this paper is to present for consideration guiding principles, rather than a detailed and comprehensive analysis.

The structure of the paper is similar to the Terms of Reference as outlined in C. White’s letter to ESBII [19th December 2000]; thus our comments are presented in the following areas:

n General assessment of the energy market in Northern Ireland and its role in the growth of the economy.

2. GENERAL ASSESSMENT OF THE ENERGY MARKET IN NORTHERN IRELAND AND ITS ROLE IN THE GROWTH OF THE ECONOMY

There is a fundamental need for sufficient energy to meet the current and future needs of the economy in Northern Ireland. However, it is not sufficient to merely meet the energy needs of an economy, it is also necessary to provide a quality energy service that is competitively priced, meets the highest environmental standards, provides fuel choice for industrial and domestic consumers and promotes growth throughout Northern Ireland. The availability of such energy will be a stimulant for economic growth and should actively enhance the attractiveness of an economy for industries, particularly those industries with high-energy demand requirements.

To date, limited competition has been introduced to the Northern Ireland electricity market. However, it is appropriate to review how this market can now be developed further to ensure that the electricity market plays a role in the well-being and growth of the Northern Ireland economy.

It is our opinion that competitive energy costs can both support the competitiveness of existing industries and be a driver of future growth in the Northern Ireland economy.

The Northern Ireland Assembly debate of 6th November 2000 discussed the current cost of electricity in Northern Ireland, which is the primary measure for such commodities and saw it as cause for concern in contrast to neighbouring markets. This inquiry into energy will provide a means for reviewing the current market structure, which can lead to lower priced energy. The price aspects of energy shall be subject to further comment in Section 4.

Currently, 32% of the market is open in Northern Ireland, and a planned further opening to 35% in April 2001. For comparative purposes, the Republic of Ireland market is currently 32% open, leading to a further interim stage of 40% opening, culminating in 100% opening in 2005. Great Britain is already 100% open. In January of this year, the EU Energy Commissioner announced plans to bring forward a proposal to completely open energy markets in the EU by 2005.

The harmonisation of market opening in Northern Ireland with surrounding markets will need to be viewed both in the context of existing market structure in Northern Ireland, developments in neighbouring markets and in an EU context. By 2005, in the absence of revised targets for Northern Ireland, surrounding markets will have progressed to full market opening. It is presented for consideration to the inquiry that the Northern Ireland market should be examined in a manner consistent with neighbouring markets in key areas, e.g.

The existing power purchase contracts (Generating Unit Agreements between NIE and the power stations) will need to be reviewed in the context of any revised market structure and in particular those agreements with a substantial period of time prior to expiry. Such agreements should not prevent the development of a more open and competitive market, which can only be achieved by additional market opening to that already planned.

The potential for supply and co-operation beyond Northern Ireland will present further opportunities for the Northern Ireland market. In the past, the North–South interconnector was of mutual benefit to the Republic of Ireland and Northern Ireland systems, in the absence of interconnection with any other system. Both systems, which are relatively small, were able to avail of network support, assistance with security of supply and mutually beneficial trading, which was made possible by the existence of the interconnector.

The Department of Enterprise, Trade and Investment in partnership with the Department of Public Enterprise in Dublin have initiated a report on the energy sectors in Northern Ireland and the Republic of Ireland. One of the key areas that will be examined is the opportunities and benefits of an All-Island energy market approach. Subject to the degree of final market structures, it is our view that market forces will drive the benefits and reality of such an All-Island market. The emergence of an All-Island market would provide many opportunities and there is much sense in a co-ordinated and planned approach between the electricity systems in Northern Ireland and the Republic of Ireland.

To maximise the benefits of this the following areas of co-operation are suggested:

Looking forward, the introduction of the Moyle interconnector in addition to the availability of North-South interconnector capacity will permit increased trading with external markets. Access to interconnector capacity by the independent sector will present further opportunities to increase the competitiveness of the Northern Ireland market. Existing Northern Ireland market participants will be presented with the opportunity to supply beyond the home market, whilst the Northern Ireland customer will reap the benefits of the interconnector, since the increased interconnector capability will permit additional competitive presence in the Northern Ireland market.

In the fully interconnected electricity market it is important to recognise the benefits to consumers of potential competitively priced imports. However we believe that the maximum benefits will accrue to the Northern Ireland economy by promotion of competitive generation within Northern Ireland with the additional benefits of exports.

In section 2, the opening of the Northern Ireland market to competition was contrasted with surrounding markets. It can be seen that within the next few years, in the absence of any revisions to the existing targets that the Northern Ireland market will not be 100% open unlike neighbouring markets. Thus, the majority of energy users will not be exposed to competition and will not have the element of choice with regard to their electricity supplier.

However, progressive and sustained opening of the market will enable more customers to access the competitive market. A larger market for competitive supply will encourage the presence of additional competition, which will lead to more competitive supply. Thus further market opening will unlock the potential for more Northern Ireland customers to avail of cheaper energy prices.

It is submitted for consideration that the Northern Ireland market opening should be consistent with the Republic of Ireland and Great Britain markets. Permitting customers access to the competitive market will increase consumer choice and present a sharp focus on quality of service and price for competitors.

To move towards more progressive market opening, the role of the Power Procurer will need to be substantially revised. Previously OFREG consulted on the role of the Power Procurement Business (PPB). ESB submitted a comment in response to this consultation and is attached in Appendix A. The key points of ESB’s submission were:

n The PPB should focus on the management of existing contracts while at the same time being incentivised to develop and administer arrangements, which facilitate the development of the competitive market.

n It would be appropriate to focus the PPB on the constraints, which the current structure of the franchise market causes to restrict the competitive market.

n It would be entirely inappropriate for the PPB to operate as a trader in the second tier supply market. The Power Procurer should not be empowered to trade in the competitive sector on either side of the interconnector as to do so would take the focus away from its core activity (the management of generating contracts to the overall benefit of the franchise customers).

n PPB should only be allowed enter into further contracts in the context of immediate short term supply terms, and should not be allowed to restrict further market opening or indeed development of an all island market.

n Ultimately the cost of power purchase contracts, if stranded, would need to be met in a fair and equitable manner to all participants. If the net long-term costs were reduced or removed then such a move would of course lead to an increase in competitive operation of the market to the benefit of all consumers.

When the market was previously restructured, the Power Procurement Business (PPB) was established and acted as a single buyer of generation. Power purchase contracts were entered into with typical durations of 15 to 20 years. With the opening up of the market in line with more recent EU directives, the Power Procurer model for an industry is no longer consistent such directives. The opening up of the market presents many issues for the existing power purchase contracts. Many of these contracts may still have a substantial period to run, thus tying up generation. Fuller market opening similar to Republic of Ireland or Great Britain could lead to stranded costs, however if the market is to evolve to a more open and competitive market a mechanism will need to be found to minimise the cost of such contracts to the market.

It is also important to address the role of the Transmission System Operator (TSO) in the new market. The first steps have been taken to establish the TSO as an independent body. It is important to build upon these steps, to clarify the roles and responsibilities of the TSO and to and further advance the independence and separation of the TSO function.

Looking forward, modern competitive plants such as the Coolkeeragh 400MW CCGT will offer competitively priced electricity, which will be complimentary to other initiatives to attract industry. It is plant such as this that will provide cleaner, cheaper electricity using modern CCGT technology for Northern Ireland. ESBII is committed to a long-term role as a significant player in the competitive energy market as evidenced by building a new 400MW CCGT plant at the site of the existing Coolkeeragh site.

This new station will be built to compete in the All-Island market and will offer generated electricity substantially cheaper than current Northern Ireland levels and on a par with the best new entrants in the Republic of Ireland. The new Coolkeeragh power station will be available to market in 2004. This is in line with the programme schedule to allow for station and gas pipeline planning and construction. Substantial work has been completed by the ESB Coolkeeragh partnership, including preparation of Environmental Study, public consultation process, grid connection study with NIE and lodging of planning application in February 2001.

One of the key strands from Strategy 2010 and the Programme for Government is the expansion of the natural gas industry throughout Northern Ireland and outside of the existing franchised greater Belfast area. The availability of gas will facilitate companies, providing for their energy requirements in addition to electricity. Competitive energy prices will proactively support companies with high-energy demand and enhance their competitiveness.

The Coolkeeragh ESB proposal to build a new 400MW CCGT power station will serve as the anchor tenant for the building of the new gas pipeline in the North and Northwest corridor. The benefits of natural gas, which have been widely reported, provide a vital economic stimulus and a sound infrastructural development.

Coolkeeragh ESB support Governments objectives of receiving firm private sector proposals to develop the gas industry in the North and Northwest and are committed to full co-operation with the final licensed pipeline applicant. A key element of the economic viability of the new pipeline is the need for equality in the charging mechanism for gas, consistent with the postalisation[i] policy for the electricity consumer.

Increased deployment of renewable generation is a key component of European energy and environmental policy and should be comprehensively addressed to the overall benefit of both the consumer and the environment in Northern Ireland.

ESB has recently submitted a commentary paper to OFREG on the subject of stimulating renewables. The following points represent a synopsis of ESB’s comment on the stimulation of renewable generation in Northern Ireland in response to the OFREG consultation document.

n Support of the need to revise the existing renewables targets in Northern Ireland.

n Revision of the renewables targets will provide a strong indicator regarding the initial scope for future renewables development in Northern Ireland and thus should be undertaken in a short timeframe.

n The use of profile metering would remove the need for specific ½ hourly metering, thus enhancing the accessibility of renewable energy for all customers. It would also deliver consistent treatment between Northern Ireland and Republic of Ireland markets and should immediately facilitate customers who wish to avail of renewable energy, and be of substantial assistance to renewable suppliers endeavouring to increase their customer base.

n Support for the principles of market based renewable energy driven by demand and supported by an overall government policy framework, which provides assurances via specific targets and a long-term commitment to renewable energy.

n It is important that perverse signals are not sent to renewable generation sectors. Having co-ordinated targets, definitions and support measures for the renewable sector should help to avoid undesirable distortions.

n Consistent trading arrangements across all sectors; e.g. there should not be a reduced top up or spill price for the green sector or indeed any other specific sector of the market.

n Access to interconnectors should be on a transparent and equitable basis for all market participants including renewables. Partitioning of the interconnector can result in less than optimal usage of the available interconnector capacity; thus it is unnecessary to provide for a dedicated green corridor on interconnectors.

n There is a need to develop a co-ordinated and consistent approach to green certificates across jurisdictions.

ESB was formed in 1927 and owns and operates generation, transmission and distribution businesses in the Republic of Ireland. Today ESB has over 4,400MW of domestic generating capacity and serves 1.45 million customers. ESB turnover exceeds £1,200million on sales in excess of 19,000 GwHr.

ESB has designed, constructed and commissioned thirty-one generating stations since its foundation in 1927. These stations include combined cycle, coal-fired, peat-fired, oil-fired, hydro and pumped storage. Units range in size from 5MW to 300MW. ESB transmission and distribution systems, consisting of 400kV. 220kV, 110kV, 38kV and 10kV networks, have been planned, designed, constructed, operated and maintained using ESB’s own resources.

ESB has over 25 years international power sector experience, beginning with its first contracts in the middle east in the mid 1970’s. The company rapidly evolved into a substantial engineering design and construction business by the late 1980’s at which time a significant transmission engineering and maintenance business had been built in the UK. ESB’s wholly owned subsidiary company, ESB International, was set up to further develop opportunities in the international power sector.

ESB is convinced that the continued rapid pace of change within the electricity supply industry will provide an increasing number of investment opportunities in the coming years. In response to this challenge ESB has formed its International Investments division who objectives are to secure profitable investment positions and provide facility management services in the global electricity supply industry. ESB is confident that ESBII’s existing success in identifying and winning investment opportunities will enable us to continue the rapid pace of growth, which the company has experienced to date.

ESB has long recognised the investment potential outside its domestic base in the Republic of Ireland. Through ESBII, it will continue to develop profitable business opportunities in the international electricity sector. This will involve equity participation and the provision of facility management services. ESB has operated for many years in the international arena and has built up a high reputation in both the generation and distribution sectors.

ESBII’s current investment portfolio includes generation plant based on conventional and CCGT technologies and also utility businesses. ESBII seeks to develop and finance international power sector projects in both developed and developing countries that permit it not only to deploy financial resources but also its technical and operational expertise as part of a long term investment strategy.

ESBII has the necessary technical, financial and people skills and resources to develop and manage power sector projects in an increasingly competitive international business. ESBII can draw from over seventy years domestic experience and over 25 years international experience in the power business, including:

ESBII own 40% of Coolkeeragh Power Limited, which is a 360MW conventional oil fired generating plant, located in Derry, Northern Ireland. ESBII has been an investor since 1998. The other investors are the management and staff.

ESBII plan to build a new 400MW CCGT power station to replace the existing power station in partnership with Coolkeeragh. This project is currently being developed through the planning application process and grid connection with NIE. The Director General of OFREG has recommended this development as most clearly assisting him in ‘both promoting competition and in protecting customers with respect to price’.

ESB’s is the largest independent Second Tier Supplier in the Northern Ireland eligible market.

ESBII have a 50% equity shareholding in Corby Power station, one of the UK’s first Independent Power Projects and have been involved as an investor since 1993. Powergen of the UK currently hold the remaining equity. ESBII were awarded a full facility management contract to carry out all operational and administrative functions at the plant.

ESBII’s subsidiary, Bizkaia Energy, is engaged in the planning of a proposed 800 MW CCGT power station in the Basque country.

Together with CDC (Commonwealth Development Corporation), ESBII invested in 49% of the shareholding in Guyana Power and Light in 1999. GPL is an electrical utility in Guyana that has 107,000 customers and 100MW installed capacity. ESBII are responsible or all aspects of the operation.

The Volta River Authority awarded ESBII a contract for operation and maintenance services for a 350MW CCGT facility in Takoradi. ESBII has been involved since 1997.

Together with its investment partners Siemens AG and Galadari Group, ESBII developed and financed the Rousch 412MW generating plant in Pakistan. In 1996, ESBII entered into a long-term operation and maintenance agreement for this plant.

ESBII’s second plant in Pakistan is located in Uch. In 1996, ESBII was awarded a 23-year operation and maintenance contract for this 586MW facility.

ESBII has operated the 440MW generating plant on behalf of Port Dickson Power in Port Dickson, Malaysia since 1994. This project has involved extensive localisation of operating skills and knowledge.

Subsequent to ESBII’s involvement in Port Dickson, in 1999 ESBII was awarded the OMM (Operations, Maintenance and Management) contract for the 440MW Kulim Hitech Industrial Park project in Malaysia. ESBI’s responsibilities include O&M of the combined cycle generation plant and associated distribution system and management of the utility.

ESBII, with local partner ONEC, operates the 628MW Rusail generating plant. ESBII has been involved since 1997.

The Al-Taweelah plant is capable of 100 million gallons of water per day plus 2000MWelectricity generation. ESBII has been responsible for supervision and management of all scheduled and breakdown maintenance since 1993. The plant consists of four power and desalination plants and the contract covers O&M in areas such as combustion turbines, steam turbines, desalination equipment, heat and recovery steam generators and boilers.

ESB response to OFREG consultation The Power
Procurement Business – its functions and future

This paper sets out ESB’s comments on the OFREG consultation paper The Power Procurement Business – Its Functions and Future.

The Power Procurer role is closely aligned to serving the needs of the franchise market in Northern Ireland by managing the generation contracts to the overall benefit of franchise customers. The Power Procurer can only provide energy to Licensed Suppliers on tariff however in addition the Power Procurer can initiate competitive change through the operation of Virtual IPP and top up and spill arrangements as set out in the OFREG paper.

It is ESB’s view that the Power Procurer role going forward should focus on the management of existing contracts while at the same time being incentivised to develop and administer arrangements which facilitate the development of the competitive market. While the Power Procurer should facilitate trading between market participants and help develop arrangements in pursuit of this objective it should not be empowered to trade in the competitive sector on either side of the interconnector as to do so would take the focus away from its core activity and may stifle the development of the second tier supply sector. This applies equally to the role of the Power Procurer in providing supplies for export to the Republic of Ireland. The pricing of such supplies should consider competition concerns in each jurisdiction. Specifically pricing should be based on full cost rather than marginal cost and should be provided in an open and equitable manner.

It is important when considering policy decisions to take account of (a) the likely degree of market opening which will be required in Northern Ireland over the coming five years and (b) the implementation of a broader energy market across the entire Island. In both cases it is more likely than not that further market opening and co-ordination and consolidation between markets will occur. It would seem appropriate that the structures put in place for the TSO and the Power Procurer should not inhibit either of these likely events.

We generally welcome the intent to provide for optimisation between contracted generation and merchant generation through the utilisation of negative supplies as referred to in the OFREG paper.

1. Should the Power Procurer become part of an Independent TSO? If so what safeguards would be required?

2. Should the Power Procurement Business remain within Viridian Group after 2002? If so where in the Group should it be located and what licence conditions are required to resolve the conflict of interest between its public interest duties and Viridian’s commercial interest?

Two elements of the Power Procurer cause conflict with other industry activities. Firstly, its role as provider of wholesale energy to licensed Suppliers and Viridian’s own franchise supply business, secondly its role in optimising its generation contract position in both planning and operational timescales.

Assuming that an Independent TSO is a separate entity to Viridian plc and that the Power Procurer does not have a trading role competing with second Tier Suppliers in the market, the first conflict would not arise or be perceived to arise.

However the second conflict would remain and would perhaps become more acute. Of particular concern should be the preferred access, which the Power Procurer has to short term Interconnector capacity. Such access would be entirely inappropriate if the Power Procurer had a competitive trading role on either side of the interconnector.

It would appear that a more appropriate structure would be to establish the Power Procurer as an entirely separate entity focused on managing the costs and volumes of the existing contracts while transferring elements of the market facilitation activities to the Independent TSO.

3. Should the Power Procurer be explicitly charged with operating in a manner that sharpens and stimulates the competitive market in Northern Ireland to ensure it produces a competitive market outcome.

It may be more appropriate to focus the Power Procurer on the constraints, which the current structure of the franchise market cause to restrict the competitive market. It would be entirely inappropriate for the Power Procurer to operate as a trader in the second tier supply market.

4. Should the PPB be able to enter into contracts if franchise market demands exceeds supply?

This should only be considered as a short-term mechanism to deal with immediate short-term supply problems and should not be allowed to restrict further market opening or indeed development of an All Island market. A more enduring and market oriented mechanism could be developed using the concept of negative sales which is briefly mentioned in the OFREG paper.

5. Should PPB be able to sell its contracts and replace them as a way of ensuring the orderly provision of new entrant low cost efficient plant in Northern Ireland?

Ultimately the costs of these contracts, if stranded, would need to be met in a fair and equitable manner to all participants. If the net long-term costs were reduced or removed then such a move would of course lead to an increase in competitive operation of the market to the benefit of all consumers.

6. Would another private sector owner for PPB be acceptable and if so, should the owner be required to have no electricity or the energy interests in either Northern Ireland, Scotland or the Irish Republic?

Another private operator without energy interests in the specified jurisdictions should be acceptable however it should in these circumstances be seen as a residual role diminishing over time with a regulated return.

7. Should the financial underpinning, which PPB requires as counter party to the contracts be provided by legislation?

8. What incentive structure is appropriate for PPB to enable it to most effectively both its tasks?

We assume that both tasks are (a) procuring for the franchise market and (b) providing wholesale energy for the competitive market via BST type arrangements.

At a very much overview level the Power Procurer should be incentivised against the actions which it is licensed to carry out. For example if the Power procurer was allowed to act in the manner provided in question 3,4 and 5 then its actions should be governed by commercial incentive/penalty mechanism as well as more general economic purchase type obligations.

The Power Procurer could be incentivised to manage the contract portfolio to deliver specified average unit price and volumes to the franchise consumer for varying levels of franchise demand. Management of this portfolio could employ negative sales type tools or allow the Power Procurer to buy out the firm volume component assuming that there is a net present value to any such actions.

ESB response to OFREG Consultation on Stimulating Renewable Generation in
Northern Ireland

This paper sets out ESB’s comments on the OFREG consultation paper entitled “Stimulating Renewable Generation in Northern Ireland” dated September 2000”.

ESB welcomes the opportunity presented by OFREG to comment on the stimulation of the renewables market in Northern Ireland. Increased deployment of renewable generation is a key component of European energy and environmental policy and should be comprehensively addressed to the overall benefit of both the consumer and the environment in Northern Ireland.

The only existing official target for use of renewables is to secure 45MWs of renewables by 2005. We support the proposal to revise these targets as suggested in the consultation paper and agree that these revised targets should be of the same magnitude as those in GB. As the current target is approximately equivalent to 3% of NI electricity output, the attainment of revised targets that would be of the same order as GB will require positive and definite steps to encourage renewable generation to achieve the respective figures of 5% by 2003 and 10% by 2010. For comparative purposes, there is currently a target of 12.4% (500MW additional capacity) for renewables in the Republic of Ireland by 2005. The revision of the renewables target will provide a strong indicator regarding the initial scope for future renewables development in NI and thus should be undertaken within a short timeframe.

We note that the NI market has been fully liberalised for renewables since 1998 and that the ROI is open to all customers for renewables since 19th Feb 2000. However we believe and propose that the use of standard profiling for smaller customers rather than the current metering requirements, which necessitate ½ hour metering capability in NI, would enhance the accessibility to renewable energy for all customers. This will deliver consistency of treatment between the ROI and NI markets and should immediately facilitate smaller customers who wish to avail of renewable energy, and be of substantial assistance to renewable suppliers endeavouring to increase their customer base.

The consultation paper highlights that the first round of NFFO was composed of 15MWs of generation, whilst the second round has only secured 2.94MWs to date. Furthermore the cost of NFFO is spread amongst all customers (eligible and franchise) in NI and adds around 0.1p to the final cost of each unit of electricity consumed in NI. We note that more recently, market based renewables have been more successful than NFFO II, and are due to deliver 28MWs approximately of wind and hydro projects.

Whilst market based renewables may encounter a higher level of financial risk (in contrast to NFFO 15 year contracts) we believe that this risk is a feature of an open market, similar to that encountered by traditional thermal (merchant) plant.

With regard to Purchaser of Last Resort, whilst this would be of comfort to renewable generators, we believe that it is (in effect) a reversion to the NFFO structure, whereby the PPB or its successor is required to underwrite the contracts. This would result in additional cost, which would necessitate a recovery mechanism that would ultimately be apportioned to the customer. Such a fall back mechanism is not necessary and is not in line with the principles of market based renewable energy driven by demand and supported by an overall government policy framework which provides assurances via specific targets and a long term commitment to renewable energy.

The customer equity approach would appear to be a novel way of reducing the cost of capital for renewable generation projects. It is unclear, however, how this differs from current provisions or the actions which OFREG proposes taking. Developers of renewable generation can, at present, enter into supply contracts with customers to supply electricity over a given contractual period. Subject to the payment of network charges and other industry wide charges a parallel capital investment by the customer in this developers project may effectively result in “free” units, if the investment is chosen judiciously. It is not clear what role OFREG would play in putting the investor/consumer and the developer together.

Dedicated access to the public sector would constitute a considerable and sizeable market for either renewable or non-renewable generation. Given that the market is fully open for renewable supply to all such parties, the proposal in the paper for bulk purchase of renewable generation by these parties could be implemented now subject to normal procurement and competition regulations. Clearly equitable and transparent arrangements would be required to ensure that competitive arrangements deliver best value.

It is important that perverse signals are not sent to the renewable generation sectors in Great Britain, Northern Ireland and the Republic of Ireland. Having co-ordinated targets, definitions, incentives and support measures for the renewable sector should help to avoid undesirable distortions. In this context, consideration should be given to ‘The Renewable Obligation preliminary Consultation’ document published by the DTI and the ‘Strategy for Intensifying Wind Energy Deployment’ produced by the ROI Department of Public Enterprise.

In the Trading arrangements in the ROI, renewable generation currently has the facility to purchase top up and sell spill into/from the market, with the requirement that quantities of top up and spill must balance over the course of the year. Furthermore the bilateral contract arrangements in ROI offer the opportunity for intertrading amongst suppliers/generators which assists the reduction of exposure to top up/spill.

We believe that arrangement similar to those in existence in the ROI offer sufficient flexibility for renewable generation if arrangements similar to current support mechanisms are to be maintained. To offer reduced top-up or spill prices to a particular subset of the market could distort usage of the top up/spill facility, which consequently would effect the actual prices. These prices are a function of the market as a whole and accordingly it would be inappropriate to offer reductions on these prices to renewables or any other specific sector or the market.

Access to the Available Transfer Capacity of interconnectors should be on a transparent and equitable basis for all market participants including renewables. There is also the additional risk that partitioning of interconnector ATC can result in less than optimal utilisation of the Available Transfer Capacity. Consequently we believe that it is unnecessary to provide for a dedicated green corridor on interconnectors.

Eurelectric, the European association of electricity utilities, has produced a position paper setting out its consensus view of how further renewable generation should be promoted. This was produced in response to the EU Commission’s amended proposal for a Directive on renewable energy (COM(2000)279). EURELECTRIC favours the use of renewables energy obligations and Green Certificates trading and is of the view that rules should be harmonised across the EU to facilitate international trade in Green Certificates. In this context, and given UK Government intentions to implement a green certificate arrangement, harmonisation of the support systems between Northern Ireland and Great Britain is necessary if the potential of the interconnection to Scotland to facilitate least cost delivery of renewable energy objectives is to realised. Trading in green certificates offers the prospect of cost effectively developing renewables in line with increasing targets in a non distortionary manner but only as long as a co-ordinated and consistent approach is adopted across Europe as a whole.

1. To assess the energy market in Northern Ireland and examine its role in the growth of the economy as described in Vision 2010 and the Programme for Government and the potential attention for supply and co-operation beyond the region.

2. To access the potential for the renewable energy market both domestically and in terms of capturing the emerging export markets with particular reference to the potential for renewable indigenous energy industries.

3. This submission is made by AES Kilroot, a subsidiary of The AES Corporation. AES has businesses in electricity generation, distribution and retail in over 19 countries. In 1992 AES and Tractebel, a Belgium company, acquired Kilroot Power Station and Belfast West Power Station as part of a trade sale of NIE’s power stations. In 2000 AES acquired Tractebel’s share in both businesses.

4. This submission concentrates on electricity generation in Northern Ireland and in particular the reasons for high prices, the position of AES Kilroot and our efforts to reduce generation prices. Some views are also expressed on future market developments.

5. One of Government’s objectives of the privatisation of Northern Ireland Electricity was to maximise proceeds to Treasury. Bidders for the power stations were offered long term contracts with NIE for the sale of electricity generation. Bids were offered based on expected cash flows from operating under the terms of these contracts.

6. The Northern Ireland Audit Office Report on “The Privatisation of Northern Ireland Electricity” revealed that Treasury received £217.2m for Kilroot and Belfast West, which was 23% higher that the Government benchmark. The Northern Ireland assets were also sold at almost twice the sale price (£/MW) of assets in GB, yet these assets were older and less efficient.

7. AES and Tractebel bid much higher than the Government benchmark because they anticipated higher efficiency improvements from operating the businesses. The audit report also states that the Department considered a profit claw-back arrangement to capture these efficiency improvements for consumers. However the Department rejected this because they concluded that such an arrangement would impact adversely on the sale prices to a degree, which outweighed any benefits therefrom.

8. In conclusion, the price received by Treasury for the sale of the assets in 1992 largely influences the price of generation today.

9. All four existing plants in Northern Ireland are relatively old and as such have higher operating costs and lower conversion efficiencies than modern plants. In addition, although coal is purchased on the international markets, coal-importing facilities at Kilroot are limited and this contributes to higher costs. These technology limitations can be addressed but substantial investment would be required.

10. NI is a small isolated market and requires higher reserve margins to maintain security of supply. It is also difficult to realise the benefits of competition in a small market. Power plants require high levels of initial investment and competition would result in a higher cost of capital due to a higher level of uncertainty.

11. For several years now we have been working with OFREG, NIE and DETI to try to find ways to reduce generation prices. We have participated in this work on the clear understanding that our contracts with NIE are legally binding and that in agreeing to any voluntary changes, our shareholders and bondholders cannot be expropriated in any way. Indeed the DGES confirmed this understanding in his report published in December 1998.[ii] AES invested in Northern Ireland in good faith and any attempt to expropriate would send an extremely bad message to potential inward investors.

12. On the basis of our Power Purchase Agreements with NIE, the terms of the Northern Ireland Electricity Order (1992), our generation licence and letters of assurance from DED, we have raised significant bond finance for this investment. More than 60% of Availability Payments are needed for re-payment of this debt and any expropriation would quickly cause us to default on these payments. In any case the Regulator has a statutory obligation to ensure that we can finance the activities which we have been licensed to carry out.

13. Since 1992 Kilroot has operated at very high levels of Availability. This has produced savings for consumers in allowing greater use of Kilroot, which is the most efficient plant on the system. Additionally the need for investment in a new generating plant has been deferred. At the time of privatisation Government anticipated that this need would arise in the mid-90s.

14. At privatisation Belfast West was scheduled to close in 1998. However, working with OFREG and NIE, the contracts were voluntarily re-arranged until 2001, to the benefit of customers. The contracts were re-arranged a second time until 2002, this time freeing up capacity for large customers at prices significantly less that NIE’s tariff.

15. We are presently working with DETI to buy down the Kilroot contracts using £30m of the £60m Government Support Fund. If this can be concluded in a tax efficient manner, Availability Payments from Kilroot would reduce by £5.2m (8.7%) per year.

16. Since 1998 we have been working with NIE and OFREG on a proposal to restructure the Kilroot contracts to produce lower prices for consumers.[iii] Although our contracts run until 2024, they contain clauses that allow the DGES, under certain conditions, to cancel the contracts any time after 2010. The DGES can also remove the cancellation clauses from the contracts or delay the effective date. The proposal has the following components:

a) Removal by the DGES of the early cancellation clause, allowing the contracts to run the full term until 2024.

b) We would then seek to re-finance the business over a longer period of time, reducing annual costs.

c) We would also seek to convert the plant to burn Orimulsion and install FGD. The delivered fuel cost of Orimulsion is lower than coal.

17. Economic analysis by London Economics, on behalf of OFREG, concluded that re-financing produced benefit for consumers. They also concluded that conversion to Orimulsion produced further benefit, if Northern Ireland needed to maintain diversity in generation.

18. To date NIE have not been able to accept this proposal on the basis that they do not want to be the counter party to the contracts until 2024 against a background of progressive market liberalisation. They have also recently suggested that the economics of the Orimulsion proposal needs to be updated to reflect new information.

19. Recently we have been working with the DGES and NIE on a different approach to implementing this proposal, as follows:

a) Government, using legislation, would establish a special purpose vehicle with an ability to raise debt finance. This debt would be repaid over time by levies on all consumers.

b) Using this special purpose vehicle, our bond would be refinanced over a longer period of time as a separate transaction between customers and bondholders, outside of the Kilroot contract. As a result the total annual payments by consumers would be reduced.

c) Kilroot would remain contracted to NIE until at least 2010 under the existing contracts, but with Availability Payments reduced to reflect the bond buy-out. The cancellation clause would remain in the contracts, allowing the DGES to cancel beyond 2010 if this was in the interest of consumers.

d) The economic analysis of converting Kilroot to burn Orimulsion needs to be updated to reflect new information since the last analysis. If benefit still exists for consumers and the development and conversion costs of Orimulsion, including the fitting of Flue Gas Desulphurisation, can be financed by customers, outside of the Kilroot contracts, we would seek to obtain planning permission at the earliest possible date.

20. Implementing this proposal will require the support of Government. Legislation will be required to establish the special purpose financing vehicle and European approval will be required for the necessary levies on consumers.

21. Increasing the size of the market increases the potential for competition and hence should reduce costs. Both Governments and the independent Regulators should adopt a co-ordinated approach to both market and infrastructure developments on the island of Ireland and between the island of Ireland and Great Britain.

22. The implementation of energy policy often involves trade-offs between promotion of competition, maintaining diversity and security of supply, and protection of the environment. It is important that Government establishes clear, co-ordinated and practical measures to achieve the best balance between these objectives.

23. We fully support Government’s objective to extend the natural gas pipeline to all parts of NI. However we would urge that this objective should not be achieved by making sub-optimal decisions on the location of new power plants. We understand that the DETI are considering the postalisation of gas pipeline costs across all electricity and gas users. This effectively means that electricity generators who use gas do not pay in full for gas transportation. Instead, the cost is spread across all electricity users. This distortion results in some electricity producers not paying enough for gas transportation and some electricity users, whose electricity producer does not use gas, paying too much. This effect is more pronounced the further the gas generator is from the source of gas. As a consequence postalisation of gas transportation costs will lead to costs being higher than they need be. Generators may choose to site in uneconomic locations and leave consumers to pick up the extra costs of gas transportation. Gas can still be delivered to other parts of NI for industrial and domestic purposes using smaller pipelines. If an electricity producer requires a larger pipe, then that producer should pay for the differential cost. However this cost can be avoided altogether by siting the gas generator close to the source of gas.

Attached is Bitor Europe’s submission to the Enterprise, Trade and Investment Committee Inquiry into Energy. It contains the views of Bitor Europe based on its own experience of the Orimulsion Kilroot project since its inception in 1998, as part of the Regulator’s Report to reduce generating costs in Northern Ireland.

Orimulsion together with flue gas desulphurisation (FGD) at Kilroot has all the factors of a good project in terms of economics, environment and fuel diversification. Nevertheless, other aspects may have conditioned the slow progress of the project such as, potential increase in the competitive risk for NIE and a lack of incentive for AES Kilroot away from the status quo situation.

Bitor Europe believes that everyone has acted in good faith within the existing generating contract framework and the new market opening policy. However, an appropriate political and strategic decision maybe required to reach an outcome combining the benefits to the consumer from the use of Orimulsion and FGD and a favourable solution to AES and NIE concerns.

The Regulator’s report planned for project start in 2002 has now slipped to the earliest 2005. It is Bitor Europe’s view that the potential economic advantages will be eroded if further delays lead to a start approaching 2010 when the plant is due to shut and, the consumer will have paid in full the cost of the plant under the existing contract framework.

If a timely decision is not made, Northern Ireland will have in effect lost this option to reduce energy prices and improve the environment whilst maintaining a long term diversified energy policy.

The electricity prices in Northern Ireland are now amongst the highest in Europe. Whilst in Great Britain there has been a considerable reduction in the price of electricity since privatisation, prices in Northern Ireland have gone up. At the same time, electricity prices in the Republic have remained substantially lower thus placing Northern Ireland at a substantial competitive disadvantage.

The Regulator for Gas and Electricity in Northern Ireland has been working with the industry to find a way to reduce this trend in generation, transmission and distribution costs. To this end, in May 1998 the generating company NIGEN (now AES) made proposals to the Regulator which were incorporated into a report published in 1998 ‘Reducing the cost of Generating Electricity in Northern Ireland, the Generators’ proposals – the basis for the future ?’.

The proposal that best fits the economic purchase assessment and was the Regulator’s recommendation was for Kilroot power station to be converted to a fully integrated package of Orimulsion and flue gas desulphurisation (FGD).

The existing contract for generation runs until 2024 with an option to cancel in 2010. At present, the plant runs without flue gas desulphurisation (FGD) and cannot meet EU New Plant Standards and is unlikely to meet the standards required for existing plant at its present load. Because of this, the only option for the existing plant to date would be running down the plant for environmental reasons and terminating the contract in 2010 with the plant debt repayments (the majority of the plant’s availability payments) spread over this shorter period as currently established under the terms of the existing generating contract framework. The plant will then be closed and a new gas plant or a clean coal plant will have to be built. Neither option is able to reduce the price of electricity now nor represents an economic or diversified solution for the future.

In the short term the most feasible method of reducing electricity costs is to refinance the loan over the full length of the contract. To run for the full length of the contract the plant would require fitting of abatement equipment. Due to the high delivered fuel cost, coal or fuel oil with FGD would not meet economic purchase requirements. The long term operation of Kilroot would also be the most economic for fuel diversification in Northern Ireland by modernising existing plant and not requiring the building of new power plant. Using Orimulsion will enable the plant to generate at its liquid fuel design capacity, offering an additional 130 MWe to the grid. Re-financing alone without FGD now (to install some time in the future) would limit the plant present output for environmental and technical reasons and leave the uncertainty of future new plant legislation compromising the station’s ability to operate for the full life of the contract (therefore still burdening the consumer with the cost of a new plant). This would also definitely mean there would be no improvement in the local environment in the short term.

The proposal for a fully integrated package of Orimulsion and FGD now seems to be the only solution that enables the operation of the plant for the full length of the contract and will have four major achievements:

All of which are consistent with the strategy of the DED Energy Action plan 2010 to modernise the existing plant with the benefits passed onto consumers, providing security and diversity of supply and the pursuit of lower prices.

Compared to the emissions of Kilroot when using coal as a fuel, the proposed changes will significantly benefit the environment in the shortest possible time.

The use of Orimulsion with full abatement, to meet the EU Large Combustion Plant Directive (LCPD), will result in at least:

n 12 – 15% reduction in emissions of carbon dioxide (CO²) thereby reducing Kilroot’s contribution to global warming;

n 70% reduction in particulate emissions due to lower ash production from combustion of Orimulsion and improvements to the Electrostatic Precipitator (ESP) plant;

n The combustion characteristics of Orimulsion will allow the recovery of residual metals from the ash collected in the ESP plant.

CO₂ , NO_x and particulates are all improvements due to the composition of the fuel and need no new abatement equipment. To match this performance coal would require significant new plant in addition to FGD.

In the draft recommendation for second reading of the LCPD very strict measures are being applied to existing plant which if implemented would severely limit the operational life of the plant as it is until 2010. The proposed changes to the plant will meet the draft recommendations for second reading of the LCPD and therefore ensure the running of the plant for the full life of the contract.

Maintaining the existing contract will safeguard the jobs at the power station until 2024 and provide local construction jobs to build the FGD.

Without the full length of the Kilroot contract and therefore Orimulsion with FGD leaves Northern Ireland totally dependent on gas for generation. There are two major implications of this, the first is a physical dependence on gas pipes from GB (and when the Corrib Field is available) and interconnectors.

Secondly there is the issue of price diversification. The oil price shocks of 1974 and the early eighties highlighted the vulnerability of a system dependent on a single fuel. The Kilroot project secures this fuel diversity on a very competitive basis.

Interconnectors can provide a physical back up to the grid but are limited in their potential to diversify against Kilroot on a price basis. The fixed cost of the contracts is sunk and will remain with the consumer whatever the source of the electricity and whatever the duration of the contract. The interconnectors are two-way and can provide a potential sales revenue rather than a cost reduction with a true diversification policy based on source fuels in Northern Ireland. This has been the case since the North/South Interconnector was re-commissioned.

Orimulsion is the trade name for an established, clean burn conventional fossil fuel. It consists of 70% natural bitumen dispersed in approximately 30% water, using a commercially available surfactant package to stabilise the emulsion. The emulsification of natural bitumen with water enables Orimulsion to be stored and transported at ambient temperatures and enhances the fuel’s combustion performance.

Since its introduction into the market over 10 years ago over 35 million tonnes have been safely delivered and consumed by commercial customers world-wide to produce clean electricity. It has been utilised in many countries around the world including Canada, Japan, Denmark, Italy, Germany and the UK. In all this time there has never been a single interruption of supply and electricity production for any of these customers.

Orimulsion was used in GB in two plants from 1991 until 1997 on a commercial test basis. Over 7 million tonnes of fuel was supplied and the plants met all the technical and environmental targets. Both contracts ran for their full length (five years each) and their environmental permits still had some years to run. Commercial contracts were not initiated due to the poor logistics of each plant requiring secondary transportation which meant FGD could not be installed economically (like the coal situation at Kilroot).

Previous Orimulsion projects have been characterised by a reactive response to public and political opinion. The view held by generators in the early stages of market development was that if the statutory requirements were met then the projects would go ahead. Projects were also run with Bitor acting very much at arms length as the conventional fuel supplier. This strategy worked in countries where there was no indigenous fuel supply and therefore no potential large local loser. In the U.S.A and GB where there are sensitive issues of indigenous fuel supply, this strategy led to poor local public relations, uncertainty, doubt and finally the requirement of project Judicial review or Public Inquiry, the potential delay from which made the projects uneconomic and the case of two projects, one in Pembroke UK and the other in Florida USA, generators withdrew their planning applications.

Since the middle of 1998 when the Orimulsion Kilroot project was first conceived from the recommendations of NIGEN to the Regulator a pro-active campaign of briefings consultations and studies has been carried out jointly by the generator and Bitor Europe with the local and national opinion formers. The fully integrated package of Orimulsion and FGD at Kilroot has been considered by all parties to date as acceptable in providing an alternative for consideration in meeting the objectives of the Regulator.

If activities required for planning consent such as the Environmental Impact Statement were started 1Q 2001 the first unit could be commissioned in 2005 assuming consideration of the planning application taking less than a year. Bitor Europe consider with the wealth of knowledge and data available on the fuel, developments of the fuel, continued briefings of the opinion formers, political will and the Environmental Forum in addition to the usual full official and public consultation as part of the planning process, there will not be a requirement for a review of the open ended nature of a public inquiry which is not usual in a power plant modification of this type. The fuel can be judged solely as an alternative fuel, not a special case as it has in all other countries including Denmark, Germany, Canada, Italy and Japan countries amongst those with the highest environmental standards in the World.

Appendix A                        Historic and Predicted Fuel Prices
                        Gas delivered Coal (Graph I)
                        Fuel Oil versus Coal (Graph II)

n Assess the energy market in Northern Ireland, examine its role in the growth of the economy as described in Vision 2010, Programme for Government and the potential for supply and co-operation beyond the region

n Assess the potential for the renewable energy market, both domestically and in terms of capturing the emerging export markets, with particular reference to the potential for renewable indigenous energy industries.

This submission to the Northern Ireland Department of Enterprise Trade and Investment (DETI) Committee has been made by Bitor Europe at the initiation of the DETI, following a meeting and presentation with the Chairman and Deputy Chairman on November 15th 2000.

The submission concerns the energy market, its role in the growth of the economy as described in Vision 2010, the Programme for Government and the potential for supply and co-operation beyond the region. It concerns the use of Orimulsion at Kilroot power station as an option available to the Department to reduce energy costs.

The Regulator for Gas and Electricity in Northern Ireland has been working with the industry to find a way to reduce this trend in generation, transmission and distribution costs. To this end, in May 1998 the generating company NIGEN (now AES) made proposals to the Regulator which were incorporated into a report published in 1998 ‘Reducing the Cost of Generating Electricity in Northern Ireland, the Generators’ proposals – the basis for the future ?’(ref 1).

As referred to in the DED 2010 Energy Action Plan (ref 2), the Regulator subjected the plans to an economic purchase assessment and confirmed that if the proposals made by British Gas for Ballylumford and by NIGEN for Kilroot were implemented they would bring considerable savings to all electricity consumers.

The proposal that best fits the economic purchase assessment and the Regulator’s recommendation was for Kilroot power station to be converted to a fully integrated package of Orimulsion and flue gas desulphurisation (FGD).

Kilroot has a present capacity of 390 MWe on coal and 520 MWe on fuel oil. This represents 3,400 GWh and 4,500 GWh of electricity per year respectively (45 and 60% of current demand). The only other fuel available in Northern Ireland and making up the balance of supply is gas.

The plant has been the most economic on the grid since privatisation in 1992 and, at today’s gas prices, would remain so against the highest efficiency combined cycle gas turbine (CCGT). The existing contract for generation runs until 2024 with an option to cancel in 2010. At present, the plant runs without flue gas desulphurisation (FGD) and cannot meet EU New Plant Standards and is unlikely to meet the standards required for existing plant at its present load. Because of this, the only option for the existing plant to date would be running down the plant for environmental reasons and terminating the contract in 2010 with the plant debt repayments (the majority of the plant’s availability payments) spread over this shorter period as currently established under the terms of the existing generating contract framework. The plant will then be closed and a new gas plant or a clean coal plant will have to be built. Neither option is able to reduce the price of electricity now nor represents an economic or diversified solution for the future.

In the short term the most feasible method of reducing electricity costs is to refinance the loan over the full length of the contract. To run for the full length of the contract the plant would require fitting of abatement equipment. Using coal or fuel oil with FGD would not meet economic purchase requirements. The long term operation of Kilroot would also be the most economic for fuel diversification in Northern Ireland by modernising existing plant and not requiring the building of new power plant. Using Orimulsion will enable the plant to generate at its liquid fuel design capacity, offering an additional 130 MWe to the grid. Re-financing alone without FGD now (to install some time in the future) would limit the plant present output for environmental and technical reasons and leave the uncertainty of future new plant legislation compromising the station’s ability to operate for the full life of the contract (therefore still burdening the consumer with the cost of a new plant). This would also definitely mean there would be no improvement in the local environment in the short term.

All of which are consistent with the strategy of the DED Energy Action plan 2010.

(ref 2) to modernise the existing plant with the benefits passed onto consumers, providing security and diversity of supply and the pursuit of lower prices.

Compared to the emissions of Kilroot when using coal as a fuel, the proposed changes will benefit the environment in the following main areas (information source- NIGEN):

The use of Orimulsion with full abatement, to meet the EU Large Combustion Plant Directive, will result in at least:

n 12 – 15% reduction in emissions of carbon dioxide (CO₂) thereby reducing Kilroot’s contribution to global warming;

n 70% reduction in particulate emissions due to lower ash production from combustion of Orimulsion and improvements to the Electrostatic Precipitator (ESP) plant;

n The combustion characteristics of Orimulsion will allow the recovery of residual metals from the ash collected in the ESP plant.

CO₂ , NO_x and particulates are all improvements due to the composition of the fuel and need no new abatement equipment. To match this performance coal would require significant new plant.

It is very likely that the plant will have to operate at reduced load with the present environmental performance before 2010. As an example of the way legislation is becoming more stringent for existing plants, in the draft recommendation for second reading of the Large Combustion Plant Directive (ref 3) it includes an amendment that ‘member states shall by 1 January 2005 at the latest, achieve significant emission reductions by: the operator of an existing plant undertakes, in a written declaration submitted by 30 June 2004 at the latest to the competent authority, not to operate the plant for more than 10,000 operational hours starting from 1 January 2008’. Its justification is ‘ Existing plants are large emitters of pollutants that damage the environment and public health. The emission reductions for these types of plants should therefore apply at an earlier date’.

The proposed changes to the plant for Orimulsion and FGD will meet the draft recommendations for second reading of the LCPD for new plant and therefore ensure the running of the plant for the full life of the contract.

The implications of not utilising the full life of the contract are to run the plant down (for environmental reasons) and then shut in 2010. This would lose local construction jobs building the FGD and mean having to build new gas fired capacity at greater expense.

The use of Orimulsion and FGD means maximising the use of the existing assets as well as immediately making available to the grid 130 MWe free capacity safeguarding the jobs of the 100 + people working there.

A core policy in the Government’s energy Strategy for the 90s and beyond as set out in Vision 2010 (ref 2) is diversity of supply.

Without the full length of the Kilroot contract and therefore Orimulsion with FGD would leave Northern Ireland totally dependent on gas for generation. There are two major implications of this, the first is a physical dependence on gas pipes from GB (and the Corrib Field when available) and interconnectors.

We realise that energy prices over the life of the plant can be lower than they are currently as shown by the low gas prices from 1994 - 1999. What the first graph in Appendix A demonstrates is the volatility of gas prices (that are oil related) and the value of fuel price diversification through a coal related price that historically has been very stable, please see Appendix A, Graph II. The wisdom of the fuel diversification policy away from fuel oil to coal adopted in the mid 80s is self –evident, especially today (even with reduced coal plant capacity and high secondary freight charges). However, as highlighted by the Regulator’s report (ref 1) diversifying fuel supply by building a new coal plant (and in addition would require building new coal import facilities) would be unnecessarily expensive. The only commercially proven clean coal technology is fluidised bed combustion and will not achieve the same overall environmental performance as Orimulsion and FGD nor increase the plant efficiency.

Since its introduction into the market over 10 years ago over 33 million tonnes have been safely delivered and consumed by commercial customers world-wide to produce clean electricity. The price of long term contracts for Orimulsion are typically linked to a stable commodity such as internationally traded coal to provide the stability required to investment in abatement equipment such as Flue Gas Desulphurisation.

More than 1.2 trillion barrels of bitumen exist in the Orinoco Belt where Orimulsion is manufactured, an amount greater than 50% of the worlds estimated oil reserves. The recoverable reserves of bitumen are estimated at 267 billion barrels, which on an energy basis is similar to reserves of coal in South Africa.

The existence of these reserves, located in eastern Venezuela to the north of the Orinoco River, has been known for 50 years. Only in the last decade however has the technology been available to economically extract the bitumen using the highest oil company environmental standards similar to US EPA legislation. As well as producing Orimulsion the bitumen is used in upgrade processes to produce synthetic crude oil, asphaltenes as well as being utilised directly.

Natural bitumen is pumped to the surface, a distance of 500-1100 m, by cluster wells of screw pumps using the latest directional and horizontal drilling techniques to minimise the surface impact. The bitumen is cooled, dispersed in fresh water with a small quantity (<2000ppm) of commercial surfactant to stabilise the emulsion and then pumped 300km to the distribution terminal for export to world markets.

Bitor manufacturing plant is built on a modular basis with each production module having a capacity of 7 million tonnes per year. Each module takes two to three years to build which is the same project time to convert a plant to Orimulsion and FGD. Production capacity in Venezuela is allocated to a project and fixed for the full project life. The opposite ends of the supply train are therefore mutually dependent. In the last few years demand for Orimulsion has increased dramatically and the exisitng production module is now at full capacity. The second module of 7 million tonnes is being built to supply the potential demand under current project development

Orimulsion is shipped using the best industry practices by conventional modern vessels which are selected using major oil company vetting procedures and are of double hulled construction with segregated ballast tanks.

Orimulsion can be handled and stored using the same facilities as heavy fuel oils but at normal ambient temperatures due to the lower viscosity of the fuel. Orimulsion is non-flammable with a flash point in excess of 120°C.

Prevention of possible incidents by implementation of responsible care is the cornerstone of Bitor’s shipping operations which has ensured that over 35 million tonnes of Orimulsion have been shipped world wide without incident.

Detailed training, regular audits and consultation is carried out for loading and unloading facilities and operations by experienced Marine Superintendents to ensure that all personnel are trained in spill prevention and fully aware of health, safety and environmental responsibilities.

Orimulsion has been successfully burned on a commercial basis for over 10 years. It has been utilised in many countries around the world including Canada, Japan, Denmark, Italy, Germany and the UK as shown in Appendix C. Attached is a list of the customers supplied to date and the cumulative quantity of the fuel delivered. In all this time there has never been a single interruption of supply or electricity production to any of these customers. In addition, the following contracts are at the negotiating stage:

BITOR requires all commercial Orimulsion contracts to utilise FGD. This is usually on a long-term basis with a stable pricing structure to amortise investment in the FGD.

The conversion to Orimulsion requires the same planning permits as any other fuel. Some of the well reported difficulties associated with specific projects in the early days of the introduction of Orimulsion have been overcome by improvements on fuel configuration and utilisation (see below), pro-active integrated generator/fuel supplier strategy for project development (see Section 8) and extensive operational data now available proving the fuel meets the very highest operational and environmental standards.

Bitor continuously strives to improve the environmental performance and the public perception of Orimulsion. Previous concerns with the use of the fuel have been addressed and incorporated into the development programme as follows:

n Continuous monitoring of plant performance and emissions data to generate full mass balance data based on actual plant measurements

n Company environmental policy to install FGD as a fully integrated package with Orimulsion at all commercial plants

n Actively study the behaviour of Orimulsion spills and develop methodologies to mitigate the environmental effect of Orimulsion spills to the extent that AEA Technology stated “Perhaps if all oils had received similar studies [to Orimulsion] we would have a solution to containment and recovery of oil spills” at the 1997 Oil Spill Conference

n Initiation of environmental forums to brief and discuss environmental issues of Orimulsion use with interested parties, such as NGO’s and academics, during all the phases of the project development

n Proactive briefing to all interested parties of future Orimulsion projects well in advance of any submission of official applications such as planning applications.

BITOR is a wholly owned subsidiary of Petróleos de Venezuela S.A. whose core business is to produce competitively priced, consistent quality Orimulsion fuel to be used to generate environmentally sound electricity in power plants world-wide.

PDVSA is the national energy conglomerate of Venezuela created in 1976 after the oil industry was nationalised. PDVSA is a holding company that oversees the operations of more than a dozen companies such as R&D, coal, petrochemicals, oil, gas and Orimulsion.

PDVSA is the largest corporation in Venezuela and third largest energy corporation in the World (larger than Shell and BP Amoco). The Venezuelan oil industry is over 80 years old. It contributes approximately 70% of the country’s export revenue, 35% of the government’s income and 13% of the gross domestic product.

Venezuela is situated in the northern part of South America within the Northern Hemisphere, just above the equator. It covers an area of 916,445km² with 3,700km of coastline. The official language of Venezuela is Spanish and the population is 22 million.

There has been a democratic government in Venezuela since 1958 and the economy is based on the system of free enterprise. Venezuela is blessed with a large amount of natural resources including crude oil, natural gas, iron ore, gold, bauxite and hydropower.

Orimulsion can only be economically utilised when it meets certain marketing criteria. It is usual for commercial projects to fit most of the following criteria, but not all. The test plants in GB did not and that is why the contracts were not extended commercially.

As discussed previously each production module takes two to three years to build which is the same project time to convert a plant to Orimulsion and FGD and the opposite ends of the supply train are therefore mutually dependent which is the perfect foundation for a long term contract.

n dialogue with local NGOs such as Friends of the Earth (who led opposition to the Pembroke project), positive coverage by the BBC , UTV and Belfast Telegraph

n detailed independent environmental evaluation by Dr Galwey (ref 4) QUB (retired) and Dr McMullen of the University of Ulster

n The consumer committee for electricity (ref 5), Carrick and other councils, MLAs and MPs.

n A presentation to the DETI Minister and the DETI Committee Chairman and Deputy Chairman.

The fully integrated package of Orimulsion and FGD at Kilroot has been considered by all parties to date as acceptable in providing an alternative for consideration in meeting the objectives of the Regulator.

An Environmental Forum consisting of the Generator, Bitor Europe and interested parties such as, Friends of the Earth has been initiated to review environmental activities during the course of the project.

These activities are used for input into the activities required for planning consent.

The scope of future critical activities has been defined, preliminary fuel supply negotiations started and agreement to a Memorandum of Understanding between Bitor and AES to replace the one between NIGEN and Bitor.

1. Douglas Mc Ildoon (OFREG), Regulator’s Report – Reducing the Cost of Generating Electricity in Northern Ireland, the Generators’ Proposals – the Basis for the Future? December 1998

2. Department of Economic Development (DED), Vision 2010 – Energy Action Plan, March 1999

3. European Parliament, Draft Recommendation for Second Reading on the Council common position for adopting a European Parliament and Council directive on the limitations of emissions of certain pollutants into the air from large combustion plants. 4th January 2001

4. Andrew K Galwey, Environmental Aspects of the Proposal to Burn Orimulsion at Kilroot Power Station, August 1999

5. Northern Ireland Consumer Committee for Electricity (NICCE), Annual Report 1998/2000 “Electricity Generation Costs”

6. Electricity Association (EA), Environmental Briefing Orimulsion, Orimulsion No.12 Revised March 2000. Website www.electricity.org.uk

8. Det Norske Veritas (DNV) Maritime Risk Assessment – Orimulsion Transport Risk Assessment Overview Report for Bitor and AES Kilroot, January 2001

The p/kWh means the fuel cost of generation (which is the criterion for deciding which plant supply to the grid and is only paid when the plant generates).

DGXVII Directorate General XVII – is a quarterly index for prices for power station coal imported from non-member countries published by the European Commission Energy Division. This index is currently used for the coal price delivered to Scotland. The full fuel price for Kilroot includes secondary transportation in coasters to the plant. The cost of Orimulsion for Kilroot at the plant will be equivalent to the DGXVII index for direct deliveries to the plant. The savings of the secondary transportation pay for the flue gas desulphurisation (FGD). The graph above excludes secondary transportation

WEFA World Energy Forecasting Association. This is an independent organisation that all the major energy companies are subscribed to and is recognised as the leading authority on predicting energy prices. All the forecast data on the graph is from WEFA. As you can see historically the WEFA coal line tracks the EU Index.

Gas 31% This is the cost of generation for the spot gas price in the North Sea + a transmission charge to Northern Ireland being used at the current net efficiency of 31% at Ballylumford. It can be seen why Kilroot is the cheapest plant on the grid and always the first to dispatch to the grid.

Gas 55% This is the cost of generation for the spot gas price in the North Sea with a transportation cost to Northern Ireland being used at the current net efficiency of 55% for the most up to date combined cycle gas turbine plant (CCGT) being planned for Ballylumford.

This forecast for gas prices was made at August last and gas prices have increased even further and the gas lines after the current spike would therefore most likely be higher. The estimated prices post- 4Q 00 has been maintained as in the August forecast but it is most likely the price level would be correspondingly higher.

The Enterprise, Trade and Investment Committee is about to undertake an enquiry into energy. The committee’s terms of reference are to:

n Assess the energy market in Northern Ireland and examine its role in the growth of the economy as described in Vision 2010 and the Programme for Government and the potential for supply and co-operation beyond the region, with particular attention to:

n Assess the potential for the renewable energy market both domestically and in terms of capturing the emerging export markets with particular reference to the potential for renewable indigenous energy industries.

This submission has been prepared by Coolkeeragh Power Ltd (CPL) in response to the request made by Cathie White, Committee Clerk on the 19 December 2000.

Coolkeeragh Power Station has been majority owned by its management and employees since 1992, the year when the 4 power stations in N. Ireland (the GenCo’s) were privatised. Ownership is through a holding company arrangement which has undergone one major restructuring in 1997 / 1998. This saw the introduction of ESB International (ESBI) as 40% shareholders, to take the place of the Venture Capital banks which facilitated the 1992 management and employee buy-out (MEBO).

The present MEBO company has a very limited role in the future N. I. ‘Energy Park’. The existing Coolkeeragh old station is destined for closure in 2004, when its current contracts with NIE – the GUA’s - terminate. It is at this point that a new Combined Cycle Gas Turbine (CCGT) – a modern highly efficient gas fired power station – is expected to be commissioned on the Coolkeeragh site. The new power station will be majority owned by ESBI.

The MEBO has had a partnership arrangement with ESBI for several years now. As noted above, this was consolidated with ESBI taking a 40% equity stake in 1998, following the exit of the original Venture Capital partners. ESBI have made a particular contribution within this partnership to the development of plans for the new CCGT, and its place in the emerging markets.

Views in this submission by CPL are therefore largely restricted to structures and operations of the existing station, and the contribution the company has made and continues to make to the evolution of the power industry in N. Ireland today. Our partners ESBI have made a separate and substantial submission, which address our shared view of the future.

The existing Coolkeeragh’s contributions to promoting change in energy structures and operations, while perhaps modest, are nevertheless deserving of mention. For instance, the initiative taken by the company in 1998 to reprofile its power contracts was deemed by the Regulator to be beneficial to consumers. This re-profiling created an important precedent among the GenCos. in N. Ireland

The MEBO has also played a role in strategic energy matters. Through its various involvements in the North West, the Coolkeeragh team - both management and employees - became involved with others in building and promoting the case for the expansion of the natural gas industry beyond Belfast to the North and North West. This activity was led by the lobby group “Group 22 – Gas to the North & North West”.

The trade unions at Coolkeeragh, led by the AEEU, separately promoted the specific benefits of a new modern power station at the Coolkeeragh site at several high level meetings with Government Ministers and Officials.

Group 22 initiated several important studies which were submitted to the then Department of Economic Development. These studies provided valuable evidence, and presented soundly based arguments for the expansion of natural gas and lower electricity prices. The importance of a new CCGT power station in the North West was the common component for both lower power prices and wider gas availability, and over a period of time government gradually came to accept the Group 22 arguments. The inclusion of both projects in Vision 2010, and the gas pipeline in the recent Programme for Government, can be attributed to a large extent to the work of Group 22.

The Committee is encouraged to examine the Group 22 Reports as they present energy matters in a very wide context, and bring out the economic, social, environmental and other strategic benefits which the North & North West potential developments hold. Group 22 can be contacted through the Chief Executive Derry City Council or via the President of the Londonderry Chamber of Commerce.

CPL is one of four independent generating companies created in late 1991 to facilitate the privatisation of the four Northern Ireland electricity generating stations. In the absence of any stand-alone bids from other interests, CPL was acquired in April 1992 by a MEBO owned company (Coolkeeragh Power (Holdings) Ltd) with Venture Capital support. Such ownership arrangements are unusual – indeed Coolkeeragh is the only employee owned power station anywhere, to our knowledge.

Following the exit of the Venture Capital Banks, a new holding company in which ESBI hold their 40% stake - Coolkeeragh Group Ltd - was formed.

The facts speak for themselves that the MEBO company has operated as a successful independent GenCo since that date, and employee commitment and willingness to accept change has been a major contributory factor to that success. The annual fuel burn and electrical output from the power station has increased substantially since 1992 (See Appendix A), against a background of falling manpower numbers.

CPL operates under a set of contracts to NIE under which CPL will make available steam driven generating units for the production of electricity. These are referred to as Generating Unit Agreements (GUA’s). The structure of the GUA arrangements reflect a gradual scaling down of generation capacity at the station – partial closure and GUA termination occurred in 1998, with further individual GUA terminations in March 2002, March 2003 and finally March 2004, when the last GUA terminates.

GUA’s for each of the 5 operable steam driven generating units were entered into with NIE in 1992 when the company was privatised, against a backdrop of expected GUA cancellation (and station closure) on 1 November 2000. The steam unit GUA’s are the primary basis of the company business. The company was allowed to earn revenue from the availability of 4 of the 5 generating units during the period 1992 – 1998.

The company voluntarily cancelled one of its GUA’s in April 1998 in exchange for the lifting of the threat of cancellation on (1 November 2000) of all its GUA’s. It currently therefore operates 4 steam unit GUA’s, earning revenue from the availability of 3 of these 4 units. CPL will continue to operate at this level until 31 March 2002 when a further 2 GUA’s will terminate. Thereafter and in the two-year period through until the March 2004 GUA terminations, the company’s income will reduce considerably. CPL will derive its earnings in this period from the availability of 2 units reducing to 1 unit in the final year (at a reduced payment level - equivalent to approximately 75% of current GUA payment levels from a steam set). By that time the steam plant at Coolkeeragh will be close to the end of its economic life.

It should be noted that Coolkeeragh’s GUA’s terminate on a gradually reducing basis through to 2004. They are not therefore long term contracts. They contrast with GUA’s in other stations which have expiry dates ranging from 2010 through to potentially 2024.

In addition to the steam set contracts, CPL has one Gas Turbine GUA with NIE. The GT is a stand-alone distillate fired generator available to NIE at very short notice, usually where system emergency conditions apply. Its payment structure is different from the steam GUA’s, with a strong incentive factor for fast response.

Generating units under a GUA are not available for supply to customers other than NIE.

Coolkeeragh has already made a contribution to reducing energy costs in N. Ireland. In 1998, following long but ultimately successful negotiations with NIE and the Regulator, CPL voluntarily took one of its generating units (Unit 5) out of contract. At that time CPL had 5 operable steam sets, each under a GUA with NIE on which availability payments were payable for 4 steam sets. The outcome of this negotiation was the company giving up value in exchange for the lifting of the threat of early closedown.

This voluntary GUA cancellation resulted in a 25% reduction in the cost of the Coolkeeragh steam plant to NIE (in turn passed on to the consumer) and a 25% reduction in the income earned by CPL from its steam plant. This reduction in income could only be partially offset by efficiency savings in the operation of the plant and therefore lead to a reduction in the profitability of the CPL business.

In exchange for the reduction in income the threat of total GUA cancellation on 1 November 2000 was removed, thereby securing the potential for an (albeit reduced) income stream, until at least 31 March 2002. This was granted in a deal endorsed by the Regulator as offering value to customers. The deal also secured additional time for the development of proposals for the replacement of the aging oil fired plant at Coolkeeragh with modern efficient gas fired plant.

In early 1998 the Venture banks had their interest bought out by the other shareholders, and under CGL, the MEBO formed a partnership with ESB International, whose Investment Division now hold a 40% stake in Coolkeeragh. This partnership was formed with the specific objective of replacing the existing old fired plant with a modern power station using Combined Cycle Gas Turbine technology of approximately 400MW capacity.

In August 2000 the joint Coolkeeragh ESB proposal to build a new plant at Coolkeeragh was accepted by the Transmission System Operator and endorsed by the Regulator as offering best value to the consumer.

This new plant will have a thermal efficiency over two times greater than the existing Coolkeeragh plant (Thermal Efficiency is a measure of the plant’s ability to convert the total energy in any fuel into electricity). The new plant will therefore be able to produce over twice as much electricity for the same amount of fuel consumed.

It will also deliver a significant improvement on the environmental performance of the existing plant and produce much lower levels of emissions per tonne of fuel consumed and will operate to the most modern environmental standards.

As well as providing a clean low cost source of electricity generation the new station will provide the anchor load for a new natural gas pipeline to the North West thereby assisting the Executive’s stated objective of securing firm private sector proposals for a North West gas pipeline[iv]. As well as bringing gas to Coolkeeragh on the outskirts of Derry City, the pipeline will be routed through a corridor close to the towns of Antrim, Ballymena, Ballymoney, Coleraine and Limavady. This provides the potential for the further expansion of the natural gas infrastructure to many industries and homes which could otherwise not avail of natural gas. The potential for further expansion beyond Derry clearly exists.

As Coolkeeragh Power Ltd has no direct experience of the renewables electricity industry the authors of this submission have not made any comment on this matter as any views expressed would be personal views rather than corporate views based on experience of that sector of the electricity industry.

Energy prices in N. Ireland have been higher than the rest of the UK and Ireland for many years. This has been mainly due to N. Ireland being an island system (i.e. no interconnection with any other electrical supply system), aging low efficiency generating plant and the low density of population and industry in the province. On top of this the privatisation of the industry in 1992 was achieved through fixed and inflation proofed contracts. These contracts were expensive and were the collateral for the loans, which were required to purchase the power stations. The result was that there was no true competition in the early days of privatisation.

1. The existing long term GUA contracts – some of which extend potentially to 2024 - will not allow full competition to develop and ways must be found to either remove these contracts completely or minimize their impact. CPL has made a contribution by re-profiling its contracts and accepting a below inflationary adjustment to its shorter term steam plant GUA contracts though to 31 March 2002 and accepting a substantial reduction in its contract rates – to be more reflective of market value – after this date until GUA termination in 2004.

2. Replacement of the existing aging plant with modern efficiency plant delivering power prices competitive with other markets. The existing generating stations use old technology and unlike other regions in GB the NI Generation Park has no modern stations. There has been no incentive for new build given the existing contract arrangements and the absence of a competitive market.

Considerable progress is being made, and changes are being driven by EU policies on market liberalization and transnational interconnection. To this end Coolkeeragh along with ESBI have put forward proposals to the TSO and OFREG to build a new 400MW gas fired CCGT power station at Coolkeeragh. These proposals have been accepted and the station will be built without GUA’s, with the commercial objective of selling its output competitively to the increasingly liberalised markets in Ireland. This is the first, and only, plant presently planned in Northern Ireland which is not underpinned by GUA’s.

With regard to the provision of gas across N. Ireland, the new CCGT plant at Coolkeeragh will require gas being piped across N. Ireland from Ballylumford in Larne. The CCGT power station will act as the anchor customer for the pipeline, taking the major proportion of gas throughput.

As stated previously this new pipeline will extend the gas network beyond the Greater Belfast area and provide a new alternative energy source to the main towns along the pipeline route, with potential for further expansion. This objective is totally consistent with the Vision 2010 – Energy Action Plan (July 1999) and the aims of the Programme for Government October 2000 Section 5 – Securing a Competitive Economy.

The cost of a new gas fired power station and related natural gas pipeline is in the region of £200 million, excluding the further expansion of the natural gas network to towns and industries. These are major infrastructural construction projects which hold much potential for economic stimulus and local contractor involvement, particularly in the North West area.

The arguments supporting the case for a North / North West gas pipeline have been well made by Group 22 and others and have been accepted by Government. The evidence shows that a high efficiency power generator fuelled by natural gas will provide low cost electricity which in turn will increase competition and, through gas availability, consumer energy choice. This will drive costs down and help in attracting new industry along the route of the pipeline. The various reports produced by Group 22 and others in connection with the North and North West gas project have shown that if this opportunity is not grasped it will be decades before such an opportunity presents itself again and a unique opportunity will be missed to improve the energy infrastructure across N. Ireland.

Coolkeeragh Power Ltd is available to the Committee to clarify or expand upon any of the points raised in the above submission.

This submission was prepared by the following members of the CPL executive team and CGL Board Members.

Richard Sterling joined Coolkeeragh immediately after its break from NIE in 1992.

He has brought a strong business and strategic dimension to the new company gained over 20 years in different industries. He has fostered a strong partnership with the employees and their trade unions involved at the power station, based on a shared commitment to Coolkeeragh’s longer term survival. He has also been at the centre of the company’s drive to develop a combined gas and power industry for the North West Region, with a new gas fired Coolkeeragh station at the hub.

John has over 30 years experience in the Electricity Supply Industry. He joined Coolkeeragh as a junior engineer in 1967. He worked in both operational and maintenance engineering capacities until 1992 and was involved on the management side of the Management and Employee Buy-Out (MEBO) team when Coolkeeragh was privatised. In 1992 he was appointed Production Director of the newly privatised company and oversees power station operation supplying electricity to NIE under contract.

Roy Devine joined Coolkeeragh in 1994 as Financial Controller and was appointed Finance Director in 1997. In the 16 years prior to joining Coolkeeragh he worked in a financial capacity for a number of companies in the Manufacturing and Services sectors. Since joining Coolkeeragh he has been involved in a number of company initiatives including the renegotiation of the generating contracts with NIE in 1998, the development of the partnership arrangements with ESBI and more recently as the company’s Project Manager on the Project Team charged with the development of a CCGT at Coolkeeragh.

1.1 Eamon Beattie, an energy consultant, acting in a private capacity, makes this brief submission.

1.2 Until January 1999, I was employed by NIE as a senior manager with responsibility for new business development, primarily examining potential projects in generation and electricity networks both in Ireland and overseas. On their behalf, and recently, on behalf of others, I also examined the potential for gas network extensions in Ireland, North and South. In the past two years, I have worked overseas for ESB evaluating projects. I have also undertaken projects in Ireland for BGE and Questar Gas of the United States.

2.1 The absence in Northern Ireland of direct local input to policy making during the critical years of electricity privatisation and establishment of the natural gas industry has given rise to the un-coordinated development of policy for these sectors. In the vacuum that was created, there was inadequate local accountability for decisions taken. This is most evident in the high sale price extracted for power stations; servicing the high capital cost of this subsequently led to high electricity output prices.

2.2 That vacuum also allowed the office for Electricity and Gas Regulation to step in to the breach and dictate policy in areas such as generator contract negotiation, dictating future generation development opportunities and related gas network extensions. Such policy matters are too critical to the well being of Northern Ireland to be left to a Regulator. Regulation is vitally necessary - but only after accountable representatives have undertaken the due processes of inclusive consultation, policy setting and informed decision-making.

3.1 The implementation of the EU Directive on Electricity Market Opening has been undertaken in Northern Ireland in a manner that acts against the public interest. Previously, all electricity generation here was under contract to NIE and therefore not available to trade freely so as to meet the 30 – 35 per cent of the market required to be opened to competition.

3.2 The ‘opened’ share of the market relates to large electricity users and does not bring any immediate benefits to domestic customers. In Northern Ireland, in order to free up the 30–35 per cent of generation output required, and to lower the price of this percentage to the benefit of large users, the generation cost difference was re-allocated across the domestic customer tariffs. This was not made public. Such cross-subsidy is not supposed to be permitted let alone sanctioned by the Office of Regulation.

3.3 The safeguarding of domestic customer interests by the Northern Ireland Electricity Committee, as a sub-division of the Regulator’s office, is not acceptable. I would recommend that responsibility for this function be returned to the General Consumers Council or brought under some other independent body.

3.4 There are also concerns that in the negotiation of new generation contract arrangements, including those for new combined cycle gas-fired generation at Ballylumford and possibly Coolkeeragh, further restructuring of the long-term, high cost contracts will again disadvantage domestic customers. No further cross-subsidy of the large users by the domestic customers should be permitted.

4.1 The recent competition, seeking proposals from network developers, organised by the Office for Regulation was seriously flawed - both in the proscriptive nature of the projects allowed and in the evaluation methods employed. The only outcome that has been made public has been the declaration that the Coolkeeragh proposal for generation in the Northwest is the option preferred by the Regulator. No competition for generation was ever arranged; so it is difficult to see how such a conclusion could be arrive at.

4.2 The developers have stated that their station will result in lower electricity prices. Relative to existing high prices, this in not in dispute. But it is a fact that output prices from a similar project if sited to the east of the Province where the demand requires it more, would lead to even lower output prices, since it would not then have to support the cost of building a high-capacity gas pipeline to the Coolkeeragh site.

4.3 In the light of forthcoming increased electricity interconnections, I recommend that a proper evaluation of Northern Ireland’s electricity generation requirements (and optimum new power station location) together with fuel diversity needs, be undertaken by outside consultants reporting jointly to the Department of Enterprise, Trade and Industry and the Department of Finance. Minimising the output price for customers, rather than manipulating the process so as to support gas network extensions, should be the primary objective.

4.4 In reality, the area outside Greater Belfast is sparsely populated and unable to support the high cost of building gas transmission pipelines. It will require grant support or manipulation of electricity and gas tariffs for that to happen, if at all. It is questionable whether the benefit justifies the cost. The number of industries and indeed domestic customers who would actually take gas is likely to be small. The experience of Phoenix in Belfast is a good example. With a potential market of some 350,000 customers, and after some five years of network build, Phoenix had at year-end, approximately 20,000 customers. The Northwest has some 70,00 potential users but, based on Phoenix’s experience, likely to have just 4,000 customers in the same period, growing perhaps to around 10,000 within 10 years.

4.5 Any proposals to divert public funds in support of such a project needs to be carefully weighed against this reality. Retaining the facility to generate (at higher cost) in a Northwest location is unnecessary as there are cheaper system solutions available to NIE to ensure adequate supplies in the area.

1. This submission is made jointly by B9 Energy Services Ltd, which is a wind farm development company in Northern Ireland, ROI and Canada and B9 Energy (biomass) Ltd, which is a developer/manufacturer of small scale CHP biomass power stations in Northern Ireland, ROI, Sweden and England.

2. The current views we have of policy towards renewable energy are set out in our responses to Stimulating Renewable Generation in Northern Ireland, a Consultation Paper by Director General of Electricity Supply for Northern Ireland, and New & Renewable Energy - The Renewables Obligation Preliminary Consultation, DTI, October 2000. These responses are attached for your information.

3.1 The first is the export of green electricity to the ROI through the North South interconnector. ROI has already exceeded it’s allowable 13% increase of CO2 emissions above 1990 levels by 2010. This fact combined with the rapid growth in demand for electricity as the Celtic Tiger marches on, means that ROI will have a strong need to buy green electricity and / or CO2 credits.

3.2 The second is the export of Green certificates or CO2 credits. These can be generated in conjunction with wind farms and traded internationally. (More on this subject in the attached documents.)

3.3 The third is export of small scale downdraft wood fuelled CHP power stations. We are currently building our third such unit in Surrey – the Bedington ZED project. The Climate change levy and 40% GB capital support for biomass technology has created much interest in our product and we anticipate at least three more orders during 2001, one from Northern Ireland, one from Scotland and one from Wales.

3.4 The final opportunity is foe the export of skills and services. We have started a wind farm company in Calgary, Canada which is reusing the knowledge and experience that we have gained from building 8 wind farms in NI and ROI. Our first Canadian project will be 50MW capacity which is 10 times larger than the typical site in NI.

stimulating renewable generation in northern ireland
consultation paper by director general of
electricity supply for northern ireland

We are very grateful for the opportunity afforded by the consultation to comment on the options for stimulating renewable energy in Northern Ireland. We welcome the fact that the OFREG paper will stimulate significant public debate on the issues.

The OFREG Paper should be considered against the backdrop of Government policy on renewable energy for Northern Ireland. Unfortunately, whilst the Draft Programme for Government supports in general the further development of renewable energy (Sections 5.1 and 5.2.2), there is still major uncertainty about Government policy for renewable energy in Northern Ireland. This uncertainty is contrasted with the policy initiatives being established in the rest of the UK, particularly in relation to the setting of renewable energy targets and the establishing of Renewable Energy Obligations.

As the OFREG Paper makes clear the only renewable energy target specifically for Northern Ireland aims at installing 45MW of declared net capability in Northern Ireland by 2005. We would welcome an announcement declaring Northern Ireland’s commitment to the more recent UK-wide renewable energy targets of 5% of electricity consumption by the end of 2003 and 10% by 2010.

A detailed paper setting down proposals for a Renewables Obligation for England and Wales has recently been published (and one is expected shortly covering Scotland)[v]. We consider that establishing a Renewables Obligation is absolutely necessary for ensuring that adequate supplies of renewable energy are developed. A Renewables Obligation for Northern Ireland represents a form of market-based stimulation for renewable energy that is structured and enabled by Government policy; in effect a Renewables Obligation represents a support framework where price is dictated by market forces and demand is stimulated by Government. Provided that suitable capital grants are made available for small projects utilising higher priced emerging technologies (such as biomass), then in our view, a Renewables Obligation is the most cost-effective and flexible means of achieving the targets. This is because it does not place a burden uniformly on consumers but encourages, instead, electricity suppliers to source both supplies of renewable energy and customers for renewable energy in such a way as to achieve the best value for the electricity consumer as a whole.

As with others in the renewable energy industry in Northern Ireland, we are extremely disappointed that the DETI has not progressed proposals in parallel with the rest of the UK in relation to establishing higher development targets and implementing a Renewables Obligation. Despite a UK-wide consultation programme on renewable energy and the formulation of a Utilities Bill (now Act) covering England Wales and Scotland, the DETI has not put any measures in place to establish a Renewables Obligation. We understand that the DETI may be producing a Consultation Paper shortly on these issues, which we hope will set down specific proposals for a Renewables Obligation for Northern Ireland. However, we consider that the delays to the implementation of a Renewables Obligation for Northern Ireland arising from the lack of progress to date will have serious implications for the Northern Ireland renewable energy industry. For example, by not implementing a Renewables Obligation in conjunction with England, Wales and Scotland, Northern Ireland will miss out on the significant capital grants being awarded to biomass and offshore wind energy projects of 40% of eligible capital costs.

We recognise the merits of creating opportunities for those who would like to exercise their freedom of choice and voluntarily go further in terms of stimulating renewable energy than obliged under a Renewables Obligation. We are therefore viewing the OFREG Paper as a very welcome consultation on measures that complement a Renewables Obligation by providing opportunities for generators and customers voluntarily to stimulate renewable energy development.

The OFREG paper sets the background to renewable energy in Northern Ireland, discusses the merits of a Non-Fossil Fuel Obligation (NFFO) system, compares such a system to different market-based support mechanisms and suggests options for future support. There seems to be a contrast made between ‘Government’ support schemes (characterised by the discussion on NFFO) and ‘market based’ schemes. We believe that there are alternative ways of looking at the issue since making a contrast between Government schemes and market schemes is essentially artificial. As stated in Section 1, a Renewables Obligation represents a Government initiative to introduce what is to all intents and purposes a market based system.

It is recognised that renewable energy is not necessarily the most cost-effective means of reducing CO₂ emissions in all circumstances. However, we are not convinced of the accuracy of the discussion regarding carbon dioxide emission savings. The graph shown in the OFREG paper should be seen only as theoretical in the absence of data and research to confirm the graph. For example, whilst CCGTs can offer low cost electricity (and therefore CO2 reductions over existing technology), it depends very much on the size of the CCGT plant being installed as to its absolute cost-effectiveness. This is also true for Orimulsion replacing Coal. Further, it seems dubious that the implementation of CCGT should be ranked more highly than cost-effective energy efficiency measures. There is, in addition some confusion as to whether Biomass should be at the right hand of the graph as currently indicated or on the left hand when it is in the form of a CHP scheme.

The replacement of existing generation with CCGT would help to reduce CO₂ emissions (over existing levels) but would be counter-productive in relation to two fundamental objectives of energy policy: energy security through diversity and energy price stability or reduction over the long term. Reliance on one fuel source (all of which would be imported) would expose Northern Ireland electricity consumers to the potential for future price movements as has been witnessed by the mild price variations experienced mid 2000 and which could be significant under other possible future international scenarios.

As the OFREG Paper sets down, there are of course other important advantages of renewable energy including the benefits of rural development from growing our own fuel through biomass.

We do not agree with much of the discussion about the NFFO system. Whilst not intending to defend the system, the comparisons drawn with GB are inappropriate because of the different contracts offered by NIE PP and the RECs in England and Wales through the NFPA. In addition the figure quoted for GB of 75p per household is expected to rise in 2010 to 3.7% of the annual bill or the equivalent of £9.92 for the 1998 average electricity bill[vi].

We strongly concur with the OFREG paper’s scepticism of continuing the NFFO system. In summary, our view is that it has been a useful tool for stimulating renewable energy development (and to that extent it has been very successful for some technologies) but it has been a cumbersome, inflexible lengthy process and will not in our view bring forward the required level of renewable energy development needed for Northern Ireland to meet its targets. Nevertheless, at the time, the contracts awarded were good value for money for the Northern Ireland consumer, being awarded as a result of intense tender competition, particularly NFFO2 in which only 2 wind energy projects were awarded contracts from the many low-costs projects that were tendered.

Our view that the NFFO system is no longer appropriate for renewable energy development does not mean that we reject the concept of Government initiatives to support renewable energy. As set out in Section 1, we strongly support the introduction of a Renewables Obligation for Northern Ireland through its operation will be market-based in essence.

We would disagree with the description of offering 15 year guaranteed contracts as ‘bearing heavily on customers’ whilst facilitating financing. The two should be seen as complementary. The cheapest electricity, ceteris paribus, will derive from contracts offered by high creditworthy companies on long terms. The NFFO contracts, being so bankable, operated as quasi-equity thereby increasing the capacity to draw down low-cost debt into the project financing. As a result they were able to offer lower financing costs than would be required for any less bankable contracts.

Though, in some circumstances, financiers would prefer shorter periods if the contract price were higher to compensate, it is generally true that the longer the contract term, the lower the unit selling price to the consumer. 15 year guaranteed contracts should therefore reduce the burden on customers compared to shorter term contracts.

For what the OFREG paper describes as market based projects, it is true that contracts will often be shorter than 15 years (though there is no reason why a supplier cannot voluntarily agree a 15 year contract with a generator). The price will therefore rise to compensate. If the contract becomes too short, then there are additional risks arising from the possibility of unusually poor early performance in one year having a disproportionately greater impact on the repayment schedule. The more significant problem with direct contracts between a generator and a customer is that the bank may have no confidence in a particular customer being able to honour the contract even for a period of a few years, whatever the size of the customer, because of the possibility of that customer ceasing to trade. This risk is reduced if the generator has a large portfolio of customers and is acting, in effect, more as a supplier than a generator. It is in this context that the concept of the purchaser of last resort should be considered; that is, as a backstop for the contracts between a supplier and its customers (see Figure 1a) rather than as a backstop for the contracts between the generator and a small number of final customers (see Figure 1b).

Another reason to prefer the scenario outlined in Figure 1a) is that for Figure 1b), if a generator were to cease trade, the purchaser of last resort, in stepping into the contract would become, de facto, a generator. If NIE PP were to be considered as the purchaser of the last resort, we are not sure that this would be an attractive proposition either for NIE PP or the generators. We are certainly not convinced that it would be attractive for generators to require contract approval of NIE PP as suggested in the OFREG paper.

We are aware that a similar proposal has been made for renewable energy supply companies in the Republic of Ireland[vii]. Under this scheme, projects commissioned within a specified time-frame will be protected from the supply company, to whom they are selling their output, ceasing to trade by means of a backstop PPA providing the difference between the Best New Entrant price of electricity and the lower of the relevant AER price and the unit price in the original contract between the generator and the renewable energy supplier.

The equivalent in Northern Ireland would be for a generator to have an option such that, upon the failure of the renewable energy supply company, it could take up a PPA with the purchaser of the last resort at a price representing the difference between the existing system marginal price in Northern Ireland and the lower of a suitable reference upper price and the unit price in the original contract between the generator and the renewable energy supplier. The reference price would prevent any profiteering or any manipulation of the backstop system.

It should be noted that backstop systems would not be required if there was a large market with a large number of renewable energy supply companies all competing for contracts with generators. Since this large market neither currently exists or is likely to exist in the future (even taking Northern Ireland and ROI markets together), a sensible backstop system would give significant comfort to a bank providing finance to a renewable energy generator.

We strongly concur with the suggestion that public bodies, as with all other companies, should consider purchasing a proportion of their electricity requirements from sustainable sources. We note that this could be done through the mechanism envisaged under the Renewables Obligation as easily as through any direct generator to customer contract. In fact, one considerable benefit of the Renewables Obligation system is that it stimulates supply companies to seek out customers of renewable energy since they have an obligation to purchase the electricity and therefore need to find customers to whom they can supply it.

The analysis of the effect of Topup and Spill on an intermittent source of electricity is very accurate. Wind energy is not able to sell its electricity within the liberalised market in any significant volumes because of the cost uncertainties associated with providing Topup and Spill at levels suited to conventional firm capacity. In our opinion, this is why even sales of wind energy to suppliers supplying the eligible market has not yet materialised.

Whilst we recognise the concept of trade in Topup and Spill between different renewable energy suppliers as theoretically possible, given the likely size of the renewable energy market, such trade will inevitably be limited. In addition, given the broad similarity of the day/night profiles of supply and demand across the whole island, the value of such trade will be very small.

The solution suggested of altering the Topup and Spill for intermittent and inherently unpredictable sources represents a creative solution to the problem. Spill is equivalent to the system marginal price which, in Northern Ireland, is a flat rate of 1.5p/kWh (summer) or 2.0p/kWh (winter), whereas Topup is variable every half hour period. In addition to a proposal set out below for introducing customer profiling, altering the Topup rate in Northern Ireland so that it became a flat rate equating to the time-weighted average of the aggregate of the Topup prices would significantly aid projects trading within the open market. For illustrative purposes, using the 2000/01 Topup prices, this flat rate would be 2.854p/kWh. We recognise that, for electricity traded to eleigible supply companies, the TSO will need to segregate trade of renewable energy and that of conventional energy because of the difference in Topup and Spill arrangements.

There are other issues that prevent full trade in renewable energy. For example, whilst it is true that theoretically any electricity consumer “irrespective of size” can purchase renewable energy, the reality is that small to medium businesses and domestic customers are not able to afford the cost of Category 5 half-hour metering required by NIE T&D. This is particularly true for, by example, a public body that has many buildings all of which would require separate specialist half-hour metering. This is a significant barrier to entry and has been addressed by liberalisation in the South through the use of customer profiling for all customers whose supply is less than 4GWh/year. In Northern Ireland, this would allow small to medium sized customers the ability to purchase directly from generators or renewable energy suppliers without the cost of additional Category 5 metering to allow real-time netting off between generators’ half-hour production and customers’ half-hour demand. The intention would be that each customer’s monthly demand would be broken down into half-hour billing periods either derived from a standard existing half-hour meter or based upon a profile published for that type of customer. These figures would be aggregated on a half-hour basis for all customers being supplied by the generator/supplier and would be reconciled with the actual half-hour production data recorded for the relevant month as measured at the generator’s site. Any Topup (an aggregate demand for any half-hour billing period over the monthly production for that half-hour billing period) should be purchased at the time-weighted average of the Topup rates (for 2000/01, 2.854p/kWh) and any Spill (the inverse) should be sold to the system at the SMP.

If this system were adopted, it would significantly aid the direct sales of renewable energy between generator and customer. However, it should be noted that if a customer as an eligible customer were able to avail of electricity generated at prices significantly below the BST (via sales from an independent supplier), then a generator/supplier would only be competitive if the source of renewable energy was itself generated at below the BST. It is currently difficult to envisage renewable energy competing directly with the wholesale electricity market in the absence of any trade for renewable energy certificates (see footnote 1 and Section 2.4.4, below). A significant commercial risk therefore exists for the renewable energy generator supplying a customer who, on account of increasing market opening, may be able in the future to purchase electricity within the eligible market at prices below that which would otherwise be available in the franchise market.

We strongly agree with the need to establish markets for renewable energy certificates. In this regard it is very important that the Renewables Obligations proposed for England, Wales and Scotland allow renewable energy certificate trading throughout the UK rather than just within GB, as is currently proposed in the Preliminary Consultation document. If this is not amended, Northern Ireland will not only be prevented from exporting its certificates into the larger GB market but will inevitably have an excessively limited market for the trade of such certificates when a Renewables Obligation is introduced in Northern Ireland thereby rendering competition in the trade of such certificates significantly less meaningful.

Currently, it appears from the consultation that this is not possible since an ROC is intended to certify not only that it represents renewable energy, but that “it has been supplied by a licensed supplier to a customer in Great Britain...” (pg13, 15 and similar on 21). This definition is based upon the wording in the Utilities Act. A Northern Ireland generator will therefore only be able to sell ROCs to a supplier in GB if he is also selling his electricity to a licensed supplier in GB, which is not currently physically possible and in any eventuality is an excessive and unnecessary requirement.

Certification of origin is required under the Treasury arrangements for the climate change levy (the Climate Change Levy Exemption Certificates – LECs) throughout the UK. Whilst it is recognised that different certificates are needed for the climate change levy and the Renewables Obligation (since the two are additive), why cannot OFREG (as responsible for renewable energy certification in Northern Ireland) certify renewable energy generation plant in such a way as to be capable of trade within the GB Renewables Obligations?

In this regard we look to OFREG to make its representations on this matter to OFGEM and the DTI and that, if necessary, protocols are established between OFREG and OFGEM as set out on page 47 of the Preliminary Consultation document (Annex B, Paragraph 24) headed “International Protocols” to effect the trade of ROCs from Northern Ireland to the rest of the UK.

New & Renewable Energy – The Renewables Obligation Preliminary Consultation, DTI, October 2000.

We consider that a Renewables Obligation is the most sensible approach for ensuring that adequate supplies of renewable energy are developed to achieve the targets of 5% of supply by 2005 and 10% by 2010. A Renewables Obligation for Northern Ireland represents a form of market-based stimulation for renewable energy that is structured and enabled by Government policy; in effect the Renewables Obligation represents a support framework where price is dictated by market forces and demand is stimulated by Government. Provided that suitable capital grants are made available for small projects utilising higher priced emerging technologies (such as biomass), then in our view, a Renewables Obligation is the most cost-effective and flexible means of achieving the targets. This is because it does not place a burden uniformly on consumers but encourages, instead, electricity suppliers to source both supplies of renewable energy and customers for renewable energy in such a way as to achieve the best value for the electricity consumer as a whole.

B9 Energy Services Ltd and B9 Energy Biomass Ltd are, however, very concerned about one aspect of the Renewables Obligation Preliminary Consultation document that relates to Northern Ireland. In the Renewables Obligation for England and Wales and its parallel in Scotland, the trade in Renewable Energy Certificates (ROCs) is going to be limited to within GB and consequently Northern Ireland will be forced to limit the trade of its ROCs (when a Northern Ireland Renewables Obligation emerges) only to Northern Ireland. This is going to be profoundly limiting for renewable energy projects in Northern Ireland. Originally, we were under the impression that trade in ROCs would be UK-wide, thereby allowing a generator to generate renewable energy in Northern Ireland and to sell its electricity to the Northern Ireland system but trade the ROC to a supplier in GB, thereby enabling the supplier to meet its Renewables Obligation. This must be the most logical approach since it provides the greatest flexibility to a supplier in England and Wales (or Scotland) to meet its obligation by sourcing the cheapest ROC from within the UK. It appears, from the consultation, that this is not possible since an ROC is intended to certify not only that it represents renewable energy, but that “it has been supplied by a licensed supplier to a customer in Great Britain...” (pg13, 15 and similar on 21). This definition reflects the wording of the Utilities Act. A Northern Ireland generator will therefore only be able to sell ROCs to a supplier in GB if he is also selling his electricity to a licensed supplier in GB, which is not currently physically possible and in any eventuality becomes an excessive and unnecessary requirement.

On page 21 of the Consultation document, there is reference to a GB wide market for a trade in ROCs arguing that this would be good for stimulating competition. By excluding Northern Ireland the competition is limited. More importantly, when a Northern Ireland Renewables Obligation emerges the scope for competition in ROC trading will be severely limited since it will only appear to be within Northern Ireland.

Certification of origin is required under the Treasury arrangements for the climate change levy (the Climate Chane Levey Exemption Certificates – LECs) throughout the UK. Whilst it is recognised that different certificates are needed for the climate change levy and the Renewables Obligation (since the two are additive), why cannot OFREG in Northern Ireland certify renewable energy generation plant in such a way as to be capable of trade to the GB?

Since the primary legislation cannot now be amended, we strongly urge the DETI for Northern Ireland to press the DTI to ensure that arrangements or protocols are put in place between Northern Ireland and England, Wales and Scotland (that is, between OFREG and OFGEM) that enable renewable energy plant in Northern Ireland to trade certificates into GB as a means of satisfying the GB Renewables Obligations. This would be similar to the arrangements set out on page 47 of the Preliminary Consultation document (Annex B, Paragraph 24) headed “International Protocols”.

Biogas (Ireland) Ltd is a new company formed in August 2000 to provide a legal status for to take the Fivemiletown Biogas Plant through from its current position as a project to the construction of a new facility to serve businesses and farms in the Erne and Blackwater catchments and the community of Fivemiletown itself.

The Fivemiletown Initiative is an Energy Challenge Shield award winning project (1997) originally developed and led by the Ulster Agricultural Organisation Society Ltd on behalf of one of its co-operative members – the Fivemiletown & Brookeboro’ Co-operative Agricultural & Dairy Society Ltd and the wider community of the town itself. Exploratory work began in 1994 and the pre-feasibility study completed in 1996, “Biogas in Society” showed that among Creamery farm suppliers alone there was sufficient animal manure to supply almost 1MW of electricity and a similar quantity of hot water.

With assistance from Interreg I & II and financial support from both Dungannon and Fermanagh District Councils, Danish Consultants were commissioned to establish the technical feasibility study (1998). Work has continued to date and reached the point where PricewaterhouseCoopers have been commissioned (February 15^th 2001) to undertake the Economic appraisal in preparation for securing both grant and private investments to build the plant.

Nicholas Lowry (Chairman) farmer, Bill Curry, (Managing Director, Fivemiletown & Brookeborough Dairy Society, Ltd), John Burrell & Wilfie Anderson, (Fivemiletown Community Development Association), Ron Murray, (Blackwater Catchment Scheme), Billy Moore, (County Engineer, Monaghan County Council), Robert Forde, (Director of Environmental Health, Fermanagh District Council), Alan Burke, (Director Environmental Health, Dungannon & South Tyrone Borough Council), Sean Murphy, (Financial Director, Cooneen Textiles), Dan Sinton, (Regional Energy Management, IRTU), Clare Lukehurst, (Technical Advisor), William Watterson, (Farm Advisor, Fivemiletown & Brookeborough Dairy Society), Tom Gibson, (Farmer), Kenneth Gould, (farmer), Robert Gibson, (Director of Environmental Services, Fermanagh District Council), Ian Murray, (Regional Director, Royal Institute of Chartered surveyors), Peter Buchanan, (Assistant Manager, Fivemiletown & Brookeborough Dairy Society, Ltd), Carole Graham, Accountant and Company Secretary, Fivemiletown & Brookeborough Dairy Society, Ltd)

This is a multi-purpose facility to convert animal manure, green residues; food processing and catering wastes into three new products – heat, power and bio fertiliser. When the latter is separated into liquid and fibre fractions some 65 per cent of phosphates are removed from circulation. A biogas plant fulfils a number of functions:

n Converts wastes to energy for the displacement of fossil fuels and attendant emissions.

n Provides an integrated farm waste management system with nutrient planning, over winter storage, a change to band spreading (or similar) and the displacement of mineral fertilisers.

n Heat and power provides a catalyst for industrial/commercial development and has the capacity to create new ‘growth poles’ in disadvantaged areas.

n As a community initiative, it brings together local groups/persons of all traditions to focus on creating a new facility for the benefit of all.

The basic concept of the plant is shown in the Figures 1 and 2. The animal manures and food wastes will be taken from farms and food processors in both catchments.

The total input of 88,000 tonnes per year is mixed, pasteurised, digested and then separated into fibres (removing 65% of phosphorus) and nitrogen enhanced liquid bio-fertiliser. The latter is stored in winter, applied during the growing season and therefore, in combination with fertiliser management plans and a change in farming practise avoids the need to apply when leaching risk is at its highest. The biogas plant operates on an entirely sustainable closed system in which the only waste from the 88,000 tonnes annual throughout is just 50 tonnes per year of grit that will have accumulated in the bottom of the reception and storage tanks.

There are 50 commercial biogas plants operating mainly in Denmark (20), Sweden (8), Northern Germany (12) and more recently new additions in Holland and Belgium. The capacity for the demonstration plant is:

Throughput of waste: 88,000 Tonnes on 50:50 basis animal manures: food wastes. (N.B. all spread year round to the Erne & Blackwater Catchments at present)

n Common response to waste management on farms, by food industries to avoid spreading to land year round.

n Through fibre separation, the removal of 345 tonnes of phosphate from circulation annually.

n Pathogen kill. E-Coli 0157. Salmonella spp. Mycobacterium bovis, Brucellosis, Leptospira etc.

n Avoided methane emission from the storage and spreading of animal manures (22 tonnes) and nitrous oxide (1 tonne) per year.

n Displaced of £300,000 electricity, oil & LPG and replacement with renewable heat & power from the biogas plant.

n Greater energy efficiency in key local businesses & schools from CHP system of district heating distribution.

n Stabilisation of energy costs for key businesses & schools, protection from price fluctuations

n Stabilisation and ‘cradle to grave’ waste management system for farmers and food processors.

The Biogas plant is one of many technologies for renewable energy production. Scope for its application in Northern Ireland has hitherto been overlooked. A recent awareness scheme funded under the Alterner Contract shows significant interest among food processing companies, farmers, local authorities, Members of the Local Assembly and local councillors across the party divides as well as among the technical and advisory services of the local and regional government.

Biogas plants make minimal landscape intrusion; yield significant net avoidances of greenhouse gases, particulates, etc. and fit into existing agricultural rural economy with only minor adaptations.

We shall be pleased to provide details and documentation and to discuss with you the outcome of the Economic Appraisal by PricewaterhouseCoopers on which work begins 7th March 2001. Please do not hesitate to contact us for further information.