The recovery of heat from power generation in Scotland: study

4 Financial Modelling

With the potential district heating networks identified for each of the four power stations, a model was developed to calculate the annual and whole life cost for each of the power stations when supplying heat to surrounding buildings via the district heating networks. The model also provides an assessment of carbon dioxide savings.

The model does not include the wider socio-economic benefits of district heating. Hence the social cost of carbon is not included in the assessment, nor are wider impacts of lower energy costs on the economic and social situation of clients. Hence the assessment is taken from the perspective of the potential investor - who will not be able to realise value from these wider benefits.

The model does not include a detailed comparison of the carbon savings from district heating with other carbon saving measures that could be implemented on the buildings that are provided recovered heat. In the case of new properties it is assumed that they comply with building regulations and that appropriate energy efficiency measures have been included to reach the standards required.

4.1 Summary of Approach Used

The model allows variations on several parameters such as discount rate, energy prices, power station CHP operating mode, operating lifetime, etc. The model includes the following key financial and technical factors:

• The capital cost of modifying each power station to recover heat.
• The heat demand build-up and capital cost of the heat network.
• The operating cost for each heat network.
• Current and projected fuel cost for each power station and any top-up heating fuel.
• Current and projected wholesale value of the power generated at each power station.
• Current and projected value for heat sold to consumers, this depends on their conventional heating costs.
• The impact of current relevant policies ( EU- ETS, CCL and ROCs) on the power station.
• Ratio of heat extracted from steam turbine to reduction of power output (Z ratio) and hence the loss of electricity generation (see section 2 for explanation).
• Fuel mix and efficiency of power stations.
• Efficiency of top-up heating boilers; and
• Efficiency of displaced heating boilers and carbon intensity of make-up grid power.

The model also allows the financial performance to be assessed from the perspective of three possible parties:

A power station operator if separate.

A district heat developer operator if separate; and

A power station also developing and operating the district heating.

Flexibility is built into the model, allowing variations on assumptions over:

• The responsibility split for power generation.
• Boiler top up.
• DH transmission (main pipe before branching to multiple loads); and
• DH distribution (pipe work downstream of transmission up to connections in buildings replacing individual boilers).

If the power station and district heat developer are one entity, it compares the performance of:

Base Case - power stations generating only electricity and individual conventional boilers supplying heat to the same buildings considered for district heating.

CHP Case - power stations supplying heat to surrounding buildings via a district heating network with central back up boilers supplying heat when the power stations are being maintained.

The model calculates the cost and carbon dioxide savings compared to the base case of a new conventional condensing boiler and power from the grid. As costs and carbon factors can vary from year to year, a macro steps through each year of the anticipated life of the power station district heating scheme and calculates the lifetime cost and carbon dioxide savings. The user can vary different parameters, so that different scenarios that might have an impact on uptake rates and carbon dioxide/cost savings can be explored.

Where the power station and district heating operator are separate, the model allows financial modelling from each party's perspective but does not attempt to apportion the carbon savings between parties.

The cost comparison from the power station's perspective is:

Base Case - build conventional power station and generate and sell maximum electricity to grid at wholesale price.

CHP Case - build CHP ready power station and bleed some steam to generate heat and sell to a district heating operator for an agreed price which will be a share of the price received by the district heating operator from end consumers. Generate a bit less electricity as a result of bleed steam. If responsible, build part of district heating network before branching and provide top up heat via power station's boilers and fuels when heat demand exceeds availability from power generation.

The cost comparison from the district heating operator's perspective is:

Base Case - do nothing.

CHP Case - build district heating network, buy heat from power station for agreed price and sell to consumers at an agreed price which will be approximately equivalent to what it would otherwise cost them to generate in conventional boilers.

4.2 Detail of Main Whole Life Cost Model

CHP technical and cost data is input into a CHP database. This includes power station and district heating operation and maintenance costs and availability. The annual energy, cost and carbon analysis is split into 24 time slots. These consist of 6 weekly periods (3 day and 1 night period for weekdays, 1 day and 1 night period for weekends) for each of four different seasons. The timing of these slots can be varied by the user to coincide with significant changes in energy price or demand.

Energy price forecasts from 2013 to 2052 are included for electricity, natural gas, coal, oil and biomass. Energy price forecasts include prices for the power station, the district heating operator or for end consumers as appropriate.

The price values currently entered are derived from the DECCUEP price projections ( UEP40). The prices to end consumers are used to estimate the value of heat which could be charged by the district heating operator, a proportion of which might be passed onto the power station if the two are separate parties.

In estimating the carbon savings we have assumed the carbon intensity of natural gas, coal and oil remain constant. We have also looked at two scenarios for the carbon intensity of electricity generated elsewhere. This is included to reflect the extra emissions due to the loss of electricity generated by the power station through heat extraction and electricity used by a district heating operator (if separate from the power station) for pumping.

The two scenarios are:

1. The DECCUEP central generation mix projection out to 2020.

2. The current CO 2 intensity of CCGT.

The model takes account of the following appropriate current policy costs/benefits:

• Climate Change Levy ( CCL).
• CCL Levy Exemption Certificates ( LECs).
• Renewable Obligation Certificates ( ROCs) under current arrangements 2 ROCs for CHP/1.5 for non CHP.
• No Renewable Heat Incentive ( RHI); and
• EU Emissions Trading Carbon Charges ( EU- ETS) Phase 3 as proposed.

The results of this are captured and the annual model re-run for each year in the CHP's life, which is assumed to be the 40 years, from 2012 to 2052 (with the benefits extended out for the lifetime of the installation). The discounted life costs and lifetime carbon savings are then calculated. A macro then captures key results for all sites in the model.

4.3 Approach to NPV Calculation

For completeness and sense checking, when taking the financial assessment from the power station's point of view, a whole life costing was undertaken on both the base case power only option, and on the CHP option, discounted at a rate and lifetime (up to 40 years) set by the user. The NPV is the whole life cycle cost of the base case less that of the CHP case discounted at 9%.

The difference between these two cases is the key comparison.

However, analysing the NPV of the power station alone allows the user to see if the power station is financially viable in its own right which can also be a good sense check on inputs. If the model shows it to be highly unviable then this suggests the input variables may be incorrect. The model also calculates the IRR of the power station alone and the IRR of then converting to CHP.

4.4 Key Financial Variables

The heat price paid by end consumers assumes a 20% discount on the alternative cost of generating heat from new gas or oil boilers. This calculation assumes that the consumers' boiler systems have an efficiency of 85% ( HHV) (95% gas and 5% oil as per current consumption in Scotland excluding electric heating).

Using DECC's latest projection of gas and oil prices (2010 real terms) this gives a price of 3.36p/ kWh for heat in 2013. Thereafter heat prices are indexed to DECC Gas and Oil retail price projections ^[17] .

The value paid to the power station by the DH operator (if separate) will be a negotiated fraction of the heat price. The value used is found by iteration in the main WLC model to balance the benefits to both parties.

Electricity wholesale values are assumed to be as per DECC price projections ( e.g. 6.63p/ kWh in 2013). Carbon prices are assumed at DECC's central traded projection e.g. £14.70/Tonne CO 2 in 2013 ^[18] . ROC prices are assumed to remain at the current price of £45/ ROC in real terms.

4.5 Carbon Saving Assessment Methodology

The CO 2 savings have been calculated taking the following aspects into account:

I. The fuel that would have been used by heat consumers. This assumes gas is the avoided fossil fuel, which will provide a conservative estimate as this has a lower emissions factor than oil, LPG or coal. The assumed boiler efficiency is 85% ( GCV).

II. Fuel used by backup boilers at the power station or by a separate DH operator if applicable, these are used when the power station is not generating and hence the main power station boilers cannot provide the heat required. The fuel used is assumed to be the same mix as used for power generation or natural gas if supplied by a separate DH operator and the assumed boiler efficiency is 85 ( GCV)%.

III. The additional fuel used in the power generation. Electricity output is reduced slightly when heat is extracted. Hence to maintain the same level of total electricity generation extra fuel is burnt and extra CO 2 emissions occur - at another power station. It is assumed that this additional electricity demand comes from a marginal gas fired CCGT fired power station with a carbon factor of 0.43T CO 2/ MWhe. This assumption is made as the power station being used to provide the heat is running to support meet electricity demand when renewable generation is insufficient. Hence the alternative generation is gas fired and not renewable.

IV. The electricity used for pumping in the heat distribution network. Whether this is provided directly by the power station resulting in less power generation or imported by the power station or a separate DH operator, it necessitates make up power which again is assumed to come from marginal CCGT plant so again the emissions factor assumed is 0.43T CO 2/ MWhe.

For fossil fuels the emissions factors are taken from annexes for Defra's guidelines on company reporting of greenhouse gas emissions.

Over time the amount of heat supplied will increase. The study uses a number of assumptions regarding the time period that is needed to reach full heat sales. Hence over the development period all the factors above will change and the annual CO 2 savings will steadily increase. Once the development period is complete, the annual CO 2 savings will plateau.

Hence the annual CO 2 savings depend on what year and which development period is chosen. To make reporting of CO 2 savings simpler the results are quoted as lifetime CO 2 savings, i.e. the calculations described above over each year of the system lifetime of 40 years.

While this makes the CO 2 savings easier to present, the results cannot be compared with annual CO 2 savings in a given year.