Darrell Nightingale from the Irish Hydropower Association reports on the current state of affairs in his home industry
Ireland is a small and generally low-lying country without large catchments at altitudes above 300m. Long before private sector involvement in the early 1980s, the country’s hydro power resources were developed by the public sector electricity utility. In total 220MW of utility hydro has been developed with an average annual output of 725GWh. The principal sites are near Limerick on the Shannon, Ireland’s largest river, and north of Sligo on the Erne.
The Shannon station was the foundation of the national electricity supply. A long diversion flow was established, with the residual flow requirement in the bypassed stretch of river set at 5% of mean flow. Subsequently in the 1980s the utility installed a 600kW low head turbine to generate from this residual flow.
The utility also owns a similar sized Pelton installation, commissioned in 1991, in the high rainfall southwestern area of the country. This was the only fruit of a utility plan to build ten small hydro stations, mostly in the southwest, with assistance from EU Valoren funds which were initially available to the private sector.
The private sector seemed better placed than the public to deliver untapped small scale energy resources. A water power study in 1922 and a hydroelectric potential study in 1985 had attempted to catalogue this available capacity. The 1922 conclusion equated to about 35MW in small scale potential, with 80% in the relatively elevated counties of Donegal, Wicklow, Cork and Kerry, while the 1986 value was set at 38MW. In 1997 an EU Altener-supported study looked at total Irish renewable energy resources. It identified 50-100MW of undeveloped hydro potential available at costs rising from 50-100E per MWh, much of which was located remotely from existing load.
By the early 1980s the utility’s dependency on oil for generation had led to very high energy costs, and it was eager to encourage private small hydro development. This was viewed largely as a fuel substitution exercise, since the utility judged that private plant, which could not be centrally dispatched, gave little contribution towards its capacity requirement.
The initial enthusiasm for small hydro generation was embodied in favourable ancillary circumstances. Asynchronous generators up to 1MW in size were welcomed on lightly loaded rural networks operated at 10.5kV. Regional fishery authorities were, given the Shannon example, content with moderate residual flow requirements. The planning consent process was reasonably expeditious and the overall paradigm was that of ‘organic growth’: the addition of new projects was gradual and unregulated, on a come-as-you-will basis, with the same purchase price on offer to all. However, the three following factors had an adverse effect on the development of small hydro.
In 1991 the utility introduced a new connection policy for future small generators that did not already have agreed connection terms. Those above 100kW in size were to be connected via new, sole-use lines to transformer stations on the 38kV MV distribution network. Three principal factors induced this change:
• Effects of volt drops occurring on asynchronous generator magnetisation when starting.
• Behaviour of automatic, reversible line voltage regulators when experiencing a reverse power flow at times when generator output exceeded the line load downstream of the regulator.
• Excess line voltage (under identical circumstances as above) but without a line voltage regulator, given that the voltage at the 38kV transformer stations was regulated to the declared maximum line voltage and that the voltage gradient from there to the generator was positive.
These were technical issues which required technical solutions. The utility commissioned an independent technical report, which power producers were not permitted to examine, and upheld its position that dedicated lines were the only and unavoidable solution, despite their disproportionate cost.
Following numerous complaints, the Minister for Energy established a technical committee with representatives from power producers and the utility, which proposed the required technical solutions. These covered:
• Starting: two stage coupling – the first via current limiters that were then shorted out to achieve acceptably brief and small starting disturbances.
• Line voltage regulators: redesigning the voltage regulator controllers to assign the regulated output to the appro-priate side of the reversible regulator, according to the direction of imaginary power flow rather than, as previously, of real power flow.
• Over-voltage: reliance on voltage monitoring at the lower MV level (by now 10 or 20kV) at the generator to enable reduction of its power output at times of minimal local load. This was backed up by over-voltage relays to trip the plant in the event of the MV voltage exceeding a revised standard, which made some allowance for volt rise from the 38kV to 10/20kV transformer station to the generator.
In 1991 the Regional Fishery Boards sought a residual flow provision of 30% of mean flow in all rivers, even those that were not fished. New generation was not permitted where there were fishery interests.
This 30% value was proposed on the basis of a North American study of, by Irish standards, large catchment rivers. Power producers argued for a standard that was based on a given duration flow, not on a given percentage of mean flow. Such a value would transfer between catchments of varying size and flow duration characteristics. The 90% duration flow was suggested as probably being larger than 30% of mean flow on the American study’s large catchments. On some very small, high head plant catchments in Ireland, 30% of mean flow had just 56% duration. The 30% of mean flow requirement was modified to 10% where the watercourse in question was impassable for migratory fish. Fifteen per cent of mean flow has been accepted in recent times, without formal modification of the policy.
Open network sale access
Despite the success of the previous ‘organic growth’ policy in the decade prior to 1993, the government was determined to drive down the price of renewable energy. It required that, in future, prospective renewable generators would have to submit tender applications in (what have proved to be) four-yearly competitions.
The applications required very extensive technical documentation, appropriate for 15MW wind turbine arrays but quite unappropriate for 100-300kW small hydro generators. The irregularity of the competitions was a further disincentive – the first for hydro was in 1994, the second in 1997 and another is expected in 2001, although this has not yet been announced.
The final and most lethal aspect was the introduction of price competition and the resulting uncertainty about achieving a purchase contract, even after waiting for the next competition. The expenditure on obtaining planning consent and project designs up to the standard required by the technical documentation, with no certainty about obtaining a purchase contract, was a major obstacle to smaller players in the renewable energy market.
The 1994 competition occurred at a time when the economic price trend for wind generation in Ireland fell beneath that for small hydro generation. The key factors in falling wind energy costs were the availability of output factors as high as 40-45% on uplands in Ireland, and the growing unit size of wind turbines. Consequently no power purchase agreements were offered to hydro applicants in the 1994 competition, as they were underbid by wind applicants operating on a much larger scale. Instead, the final batch of ‘organic growth’ projects that had already agreed connection terms prior to the competition, were presented as successful hydro applicants. It is quite a cynical manoeuvre to seek credit for one system of hydro generation by misappropriating the fruit of another, more successful system.
However, one exception was made to the termination of guaranteed network access: projects which had achieved EU Thermie financial aid were to be accepted at any time at the average price for hydro in the previous competition.
The most important improvement introduced in the competitions was that the successful bid prices were contracted for 15 years and compensated annually for inflation.
The 1997 competition resulted in the award of several power purchase agreements to hydro schemes. These were almost entirely to projects put forward by companies associated with one individual, at prices between 42-47.5E/MWh – prices first seen in 1984-1986. At about the same time, the existing ‘organic growth’ generators entered into 15-year contracts with the utility at inflation compensated prices, equivalent initially to 52E/MWh.
The 1997 competition projects were supposed to be completed by the end of 1999 but none went forward as expected. A new joint venture (95% owned by the utility and 5% by the competition applicant) is expecting to commission five small hydro projects in 2001. Four are from the 1997 competition and one is Thermie-aided. Three high head sites – in Cork, Kerry and Donegal – will employ Pelton turbines from US manufacturer Canyon. One medium head site will employ a Francis turbine from the Hungarian manufacturer, Ganz. The remaining low head site will employ a Kaplan turbine from French manufacturer, Bouvier. The sites are expected to add 9.7GWh per annum to small hydro generation in the public network, which is currently, and has been since 1994, at about 38.5GWh annually.
It is expected that the next tendering competition open to small hydro may declare a fixed purchase price that will guarantee a purchase agreement, removing one damaging element for small players – uncertainty.
It is intended that hydro, with its more stable output pattern, will form a part of Ireland’s carbon dioxide reduction strategy, despite a price for medium scale wind projects in the range 28-35E//MWh in the 1997 competition. Ireland is experiencing extraordinary economic growth for a developed nation, resulting in a far more arduous carbon dioxide reduction task than more slowly expanding Euro-pean economies.
Projected hydro growth is of the order of 1.5-2MW per annum, which has not yet been achieved. There is discussion about how to facilitate small scale (<100kW) generation, given the less economic scale of such projects. They could include community projects and watermill renovations.
Proposals exist for distributed net metering, where participatory investors in a small renewable energy generator will be able to offset their metered electricity import against a local generator’s metered output, in prescribed proportions.