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Greg Kinross, President, CIC Energy Corp. NERSA Public Hearing on Eskom’s Proposed Revenue Application – MYPD2 Gallagher Estate Midrand, 21 January 2010.

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Presentation on theme: "Greg Kinross, President, CIC Energy Corp. NERSA Public Hearing on Eskom’s Proposed Revenue Application – MYPD2 Gallagher Estate Midrand, 21 January 2010."— Presentation transcript:

1 Greg Kinross, President, CIC Energy Corp. NERSA Public Hearing on Eskom’s Proposed Revenue Application – MYPD2 Gallagher Estate Midrand, 21 January 2010

2 Forward Looking Statements T his presentation contains certain “forward-looking statements”. Capitalized terms used herein and not otherwise defined have the meanings ascribed thereto in the presentation. All statements, other than statements of historical fact, that address activities, events or developments that CIC Energy believes, expects or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of CIC Energy based on information currently available to CIC Energy. Such forward-looking statements include, among other things: statements relating to the MEP, the CTH Project and the Export Coal Project; development activities, planned operations, anticipated expenditures and the commencement of construction, operations and the production of power at the MEP and commencement of commercial operations of the CTH and Export Projects; estimates and/or assumptions in respect of the production of electrical power at the MEP; the demand for power and petroleum refining capacity in southern Africa; estimates and/or assumptions in respect of mineral resources, mineral resource qualities, targets, future production, goals, scheduling, objectives and plans; future economic, market and other conditions; the status of ongoing negotiations of the PPAs for the MEP; and discussions between Eskom and the Government of South Africa in respect of a sustainable funding model for the purchase of electricity from an IPP and the timetable for consideration of such a funding model. Forward-looking statements are subject to significant risks and uncertainties and other factors that could cause the actual results to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, CIC Energy. Factors that could cause actual results or events to differ materially from current expectations include, but are not limited to: the delay or failure of negotiations between Eskom and the Government of South Africa to determine a sustainable funding model for the purchase of electricity from an IPP, on favourable terms or at all; the delay or failure of the Government of South Africa to consider such a funding model in a timely manner or at all; the delay or failure in receiving a favourable response from Eskom in respect of the offer submitted by CIC Energy to Eskom and BPC in March, 2009; further delays or failures in entering into PPAs and/or transmission agreements with Eskom and/or BPC and other requisite agreements for the development, operation and financing of the MEP, on favourable terms or at all; the failure of the counterparties (including SEC, Shell and International Power plc) to requisite agreements to comply in all material respects with the terms and conditions of such agreements; the failure to complete definitive agreements with equity partners, including an arrangement with an IPP partner on favourable terms or at all; the ability to raise the required debt or equity financing for the implementation of the MEP, the CTH Project and/or the Export Coal Project on favourable terms or at all; capital equipment, infrastructure and operating costs varying significantly from estimates; the failure to obtain acceptable tariffs and/or concessions, including tax concessions, from the Government of Botswana; inability to obtain requisite credit support from the Government of South Africa and/or the Government of Botswana in relation to the MEP; delays in the development of the MEP, the CTH Project and/or the Export Coal Project caused by the unavailability of equipment, labour or supplies, climatic conditions or otherwise; delays or failures in obtaining regulatory permits and/or licences (and renewals thereof) respecting mining, power generation and/or power transmission lines and other transportation and industrial activities; failure to obtain or develop available transportation solution to export coal and/or failure to enter into export coal purchase agreements on favourable terms or at all; the existence of undetected or unregistered interests or claims, whether in contract or tort, over the properties of CIC Energy and its subsidiaries; the loss of any key executives, employees or consultants; inflation; changes in exchange rates; Rand liquidity and constraints under applicable South African law and/or practice on the amount that a single lender is permitted to lend a single borrower; capital and operating costs varying significantly from estimates; volatility of and sensitivity to market prices for coal and prices (market or otherwise) for electricity; changes in anticipated demand for power in southern Africa; changes in equity markets; environmental and safety risks, including increased regulatory burdens; insufficient or sub-optimal transportation and transmission capacity; dispatch risk; geological and mechanical conditions; availability of water and sorbent; amendments to the laws of South Africa or Botswana that may be prejudicial to the development of the MEP, the CTH Project and/or the Export Coal Project or the failure to obtain amendments to any such laws that may be necessary to implement the MEP, the CTH Project and/or the Export Coal Project; political risks arising from operating in Africa; lack of markets for CIC Energy’s coal resources; the grade, quality and recovery of coal which is mined varying from estimates (the mineral resource figures referred to, or incorporated by reference, herein are estimates and no assurances can be given that the indicated levels of coal will be produced); or other factors (including development and operating risks). Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, CIC Energy disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although CIC Energy believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein. No assurances can be given that the levels of coal indicated by the current mineral resource estimates for the Mmamabula Energy Complex will be produced. Such estimates are expressions of judgment based on knowledge, mining experience, analysis of drilling results and industry practices. Valid estimates made at a given time may significantly change when new information becomes available. While CIC Energy believes that the current mineral resource estimates for the Mmamabula Energy Complex are well established, by their nature resource estimates are imprecise and depend, to a certain extent, upon statistical inferences which may ultimately prove unreliable. If such estimates are inaccurate or are reduced in the future, this could have a material adverse impact on CIC Energy. Mineral resources are not mineral reserves and do not have demonstrated economic viability. There is no certainty that mineral resources can be upgraded to mineral reserves through continued exploration. 2

3 CIC Energy Overview  CIC Energy Corp. is the developer of the Mmamabula Energy Project (“MEP”) in Botswana  Electricity to be sold under long-term Power Purchase Agreements (PPA), currently being negotiated, to Eskom Holdings Limited (or other buyer nominated by the Department of Energy) for 75% of the capacity and to Botswana Power Corporation (BPC) for 25% of the capacity  First Phase of Project: Mine of approximately 6 mtpa ROM, supplying Power Plant of 1,320 MW (gross), super-critical technology and flue gas desulphurisation Capital equipment & infrastructure cost approximately US$3bn  Can roll-out multiple phases (4800MW) 3

4 MEP location  Located in Botswana’s Mmamabula coalfield - an extension of South Africa’s Waterberg coalfield  The Waterberg Is host to Exxaro’s 19mtpa Grootegeluk coal mine and Eskom’s 3,690MW (gross) Matimba power station Also host to Eskom’s ~4,800MW (gross) Medupi power station currently under construction (and Exxarro’s planned 25mtpa mine)

5 Mmamabula East & South: 2.63 billion tonnes (Measured and Indicated) NI Mineral Resource Estimates, June 2009 CIC Energy has drilled in excess of 186,000 metres in over 2,000 holes

6 MEP transmission integration  Created by CIC in partnership with Eskom and Botswana Power Corporation (“BPC”)  Tight integration with Eskom and BPC networks in South Africa and Botswana  Generally compliant with South African Grid Code  Long-term solution catering for significant future expansions Well advanced transmission solution

7 MEP Overview  Water and coal availability for 40 years +  Botswana can absorb the CO 2 emissions because it is a net green house gas “sink” (absorbs more CO 2 than it emits)  Substantial procurement from South Africa  Shanghai Electric Group is the Engineering, Procurement and Construction (EPC) contractor for the power station;  International Power plc will operate the power station and be an equity partner  Commercial Operations Date for 1 st unit of initial power station targeted for 2014 (depending on approvals)  CIC appointed NM Rothschild and Sons Limited as Financial Advisors for the MEP debt financing with the following Mandated Lead Arrangers Bank of China Absa Capital Standard Bank 7

8 Development Milestones  Due to the development work done in the last 4 years at a cost of over R750m, the MEP is “good-to-go” and includes the following development milestones: Coal drilled out and mine plans completed Aquifer drilled out and water rights secured Site geotechnical work completed Environmental Impact Assessments completed Transmission solution finalised Lump sum, turnkey EPC contract concluded for power plant Significant fiscal incentives from GoB, subsidising tariff Power Purchase Agreement with Eskom (for 75%) and BPC (for 25%) substantially agreed Implementation Agreement with GoB and power generation license substantially negotiated Financing process advanced 8

9 Eskom’s MYPD2

10 Introduction – MYPD2  As stated in Eskom’s submission, the MYPD2 is extremely finely balanced any variation or non-achievement of one or more of a whole basket of important assumptions could lead to a very negative impact on Eskom’s situation (and therefore by default SA’s economy), both in terms of its financial position as well as its ability to provide the country’s energy needs in the medium term  This response aims to highlight, at a high level, key areas of risk and uncertainty which NERSA should factor into its decision and which would also hopefully be taken into consideration in finalizing any longer-term IRP by the Department of Energy  Our detailed comments on both the original and revised Eskom MYPD2 submissions have been submitted to NERSA 10

11 Tariff over-recovery  Due to its weak balance sheet and cashflow position, Eskom does not have the potential to fund its capex program (of approximately R300bn over the next 3 years (all things going well)) on its own balance sheet  It is proposing to fund capital with revenue via a significant tariff increase  Capital should be funded with capital  As a result of trying to fund capital with revenue, Eskom is trying to cover its funding deficit, being the difference in the R300bn it forecasts it will incur over the next three years and the debt it thinks it can raise (after exhausting all GoSA guarantees available to it), by lifting tariffs excessively  In other words, Eskom is raising tariffs now, to finance capital to build capacity for electricity that will only be generated in the future Today’s users will be subsidizing tomorrow’s, at great current cost to the economy  The impact of this approach is that Eskom is significantly over-recovering operating costs (including depreciation) because it is focused on funding and not cost recovery 11

12 Tariff over recovery contd.  Even though DoE’s pricing policy approved in Dec’08 prescribes the revaluation of assets, the policy allows for phase-in of such revaluation and does not prescribe the method to be used  It would seem that Eskom has significantly overvalued assets, against which a (high) weighted average cost of capital is charged, justifying the higher tariff NERSA needs to carefully analyse the revaluation of assets because very little information on this fundamental issue was disclosed in the MYPD2 The Modern Equivalent Asset valuation methodology preferred by Eskom appears to be the one that results in the highest asset values and hence the biggest burden in terms of tariff increases In any event, revaluation of 100% of generation assets (and thereby reserving for replacement of the entire fleet) implies that Eskom will be responsible for replacing the entire fleet, which is certainly contrary to Government policy about the introduction and active participation by IPPs The benefit of a significantly depreciated generation asset base of 40,000MW is not being passed on to consumers at all 12

13 Tariff over recovery contd.  If true cost recovery was considered (the spirit of the regulatory methodology),  assuming an all-in-cost of 40c/kWh, Eskom would more than fully recover current operating costs on its 40,000MW current installed capacity,  adding another 10,000MW of base load capacity at say 75-80c/kWh (along with additional associated transmission and other costs), a blended real tariff (2009 money terms) in the order of 55c/kWh by 2013 (versus the 70c/kWh (in real terms) applied for by Eskom (equating to 82c/kWh in nominal terms)) should be sufficient for Eskom to recover its operating costs (including depreciation) A nominal annual increase for 3 years of closer to 25% is required to achieve this (versus the 35% applied for) 13

14 Financing observations  Eskom have stated that there is significant risk that it may not be able to raise the debt it forecasts to raise  Even if it is able to raise debt as per the MYPD2, and assuming no changes to the cash flow forecasts (and the risks to this as otherwise highlighted in this presentation), the funding shortfall over the next 3 years will be approx. R40bn  National Treasury, in the latest budget speech announced that there will be no further funding support for Eskom beyond the circa. R170bn which has already been taken into account in the funding plan (which includes the R60bn ‘quasi equity’ contribution and some R110bn in guarantees for new loans, assumed to be raised in the MYPD2 period)  To help bridge the funding shortfall, Government is anticipating selling a private stake in Kusile to the extent of 30% (now mooted at potentially up to 49%) The MYPD2 says this could take between one to two years 14

15 Financing observations contd.  The risk of not securing a partner for Kusile during the MYPD2 period is high!  Success for this initiative would only be achievable by GoSA providing completion guarantees, indemnities, more explicit credit guarantees and/or a guaranteed return on a fixed investment (which would mean National Treasury increasing funding support beyond that which it has said it will provide) since it is unlikely that an investor will be prepared to commit to a potential PPP before significant details have been clarified (such as the capped investment amount, the agreed equity returns, the terms of a PPA, credit support for the PPA etc) step into material contracts it has not been part of negotiating (also impacting on what performance and availability risks it is prepared to take on Kusile) assume environmental risk assume water supply risk (water supply has not been resolved) assume coal supply risk (coal supply has not been finalised)  If the IRP1 is used to determine the timing of the capacity roll-out (rather than the MYPD2), the R40bn funding shortfall would increase significantly, if not more than double to R80bn+ 15

16 Financing observations contd.  Funding shortfalls will be seriously exacerbated if Eskom does not get the tariff increase and/or if any of the issues which put cashflow forecasts and budgets at risk, as highlighted herein, are realised (and there is a high probability that some of these will)  Delaying or downsizing all/or part of Kusile (and replacing with IPPs) would reduce cashflow requirements significantly  Conclusion: It is difficult to see how the Eskom build programme, as set out in MYPD2 and/or IRP1 can be resolved, and contracts committed to, for as long as significant cashflow shortages over the next three years are evident 16

17 MYPD2 vs IRP1  The IRP1 gazetted on the 31 December 2009 conflicts significantly with the MYPD2 Provides for the acceleration of Kusile to a commercialization date which seems to be implausible Provides for the acceleration of DME’s peaking OCGT plant by two years which seems implausible Does not recognize Eskom’s statements that Komati RTS is running behind schedule  As a short term plan, IRP1 does not provide for new capacity required on or after 1 April 2013  Due to planning, development and construction timelines for new power plants (in excess of 5 to 6 years for coal-fired and other base load plants), should additional new capacity be needed for 2013 – 2016, this capacity is already at risk of not being delivered given that important strategic decisions on procurement are not being made 17

18 MYPD2 vs IRP1 contd.  Conclusion: NERSA will need to work with DoE to overcome this issue, potentially even prior to the tariff determination, since it is CIC’s view that unless IPPs are used to solve this problem, Eskom may incur further unbudgeted costs during the MYPD2 period (which it is unable to fund) NERSA should also consult with Ministry of Finance on these issues because it seems now that, in the absence of the potential to reopen Eskom tariffs annually and to significantly increase these, National Treasury will be called in to support Eskom 18

19 MYPD2 cash flow forecasts - observations  CIC believes that Medupi and Kusile may be further delayed (beyond the completion dates estimated per the MYPD2) and this would: Exacerbate the energy crunch Require existing plant and diesel fueled peaking plant to run hard, which significantly increases cost (maintenance and fuel) For example, running 2000MW of peaking plant (Ankerlig and Gourikwa) an extra 6 hours per working day, would cost Eskom approximately ZAR5.5bn per annum in additional diesel costs alone (excluding effects of significantly decreasing the useful life of the plants), and Increase the capital cost of Medupi and Kusile projects due to Interest During Construction on loans continuing to be incurred during delays To get a feel for the impact, each year of delay could cost Eskom in the order of R15bn in additional annual interest, per project  Due to the fact that Eskom contracts on a multi contracting approach (versus single Lump Sum Turnkey “EPC” approach that IPPs use), the cost of Medupi, Kusile and others may very well experience further unbudgeted cost overruns  Poor historic cashflow forecasting by Eskom must be taken into account in assessing current cashflow forecasting 19

20 MYPD2 cash flow forecasts – observations contd.  Due to Eskom’s financial constraints, Eskom is borrowing from Development Finance Institutions (like World Bank and AfDB) who are enforcing best practice international environmental compliance, which will further increase cost For example, adding Flue Gas Desulphurisation to Medupi could add in the order of R8bn to the budgeted cash flow requirement  Primary energy costs may also be understated As stated by Eskom in its submission, coal supply and available new sustainable sources of coal remain a significant risk Demand outstripping supply will almost certainly increase costs and these increases may well be above those budgeted for by Eskom (demonstrated by a rising “Cost of Coal Index”) The opening up of Greenfield coal mines will also almost certainly increase coal costs, and these increases may well be above those budgeted for As high quality reserves get depleted and more rail and port capacity to export a lower grade coal becomes available, Eskom inland coal prices will tend towards higher export parity prices (less logistics costs) 20

21 MYPD2 cash flow forecasts – observations contd. Eskom have on numerous occasions stated that they would like to see more “washed” coal for operational and environmental reasons and the washing, as well as the yield impact, will have an adverse effect on the Primary Energy costs  Conclusion: There is a possibility that forecast costs for primary energy operating costs as well as capital costs have been significantly under-budgeted, with the result that Eskom may require further tariff increases during the MYPD2 period The introduction of IPPs would significantly decrease the risk of underbudgeting costs because: IPPs generally assume the delay risk and the risk of cost overruns Primary energy costs for IPPs can be locked in for the (say) 30 to 40 year life of the PPA 21

22 Supply and Demand observations DEMAND  Eskom have assumed a relatively slow and moderate economic recovery with clear impact on the demand growth assumption Commodity prices are recovering strongly which means that SA’s energy intensive industries are increasing production, creating solid demand growth The tight demand and supply balance assumed by Eskom in the MYPD effectively put a ceiling on what economic growth can be realized/sustained in SA in the medium term  Eskom is assuming very aggressive Demand Side Management targets, with the timeframe for realizing these appearing generally overly optimistic For example, the Solar Water Heater rollout is extremely ambitious and is being relied upon to reduce a potential energy shortfall 3,000MW of savings is targeted by 2013 there is a high probability, in CIC’s view, that the actual saving will be a fraction of this (not more than 1,000MW), i.e. 2,000MW of capacity will have to be provided for through other means 1 mill solar water heaters in 3 years is in CIC’s view not achievable  1,000 would need to be installed per day, every day, for three years  Currently, less than 3,000 per annum 22

23 Supply and Demand observations contd. SUPPLY  Eskom assumptions on completion dates of Komati RTS, Medupi and Kusile continue to appear optimistic  Plant availability: A high availability from existing plants is assumed, which, given the fact that these plants are run harder, is optimistic Overly optimistic plant availability assumptions increases the risk of maintenance costs being under-budgeted Issues relating to security of supply of coal (i.e. coal availability) may also adversely affect plant availability Lower availability results in lower supply and hence a greater risk of a major energy crunch  Conclusion: There is a possibility that the MYPD2 overstates supply capability and/or understates demand, putting the reserve margin at risk and putting the country at risk of further protracted power shortages into the future 23

24 Other MYPD2 shortcomings  Unless confidentially disclosed to NERSA, Eskom have not disclosed a detailed capex and overall project cost budget per project (therefore impossible to form opinion)  The benchmark cost information for base-load coal fired plant referred to in the application is higher than comparable costs of known IPP projects such as the Mmamabula Energy Project being promoted by CIC Energy  Also impossible to benchmark costs without knowing if/how the following have been taken into account: Interest During Construction, hedging costs, commissioning costs, project management costs, infrastructure costs, financing fees, working capital etc.  Eskom have not disclosed the terms of contracts entered into for Medupi, Kusile, Ingula and others, material in determining the risk and potential size of cost overruns  Eskom have not disclosed a “levelised tariff” per project but there are indications that IPP base-load projects may represent lower cost options to SA than Eskom’s own build coal-fired plants, and that Eskom has previously understated the cost of its new build capacity  Conclusion: The lack of transparency prevents one from properly evaluating and comparing alternatives 24

25 General conclusions  Eskom would significantly over-recover operating costs if its 35% p.a. increase is approved  A lower tariff increase could provide for full operating cost recovery  CIC agrees that ultimately Eskom’s tariff should increase to the long run marginal cost of production (which significantly exceeds the current tariff), but the rate of increase can be significantly lowered (and spread over a longer period of time)  Eskom still would need to solve its funding shortfall  In terms of Eskom’s MYPD2, it already exceeds its share of the country’s indicated CO 2 emissions cap for 2025, which means Medupi and Kusile will significantly worsen this issue Regional IPPs mitigate this risk  CIC is able to demonstrate that IPP projects like the Mmamabula Energy Project Reduce the tariff increase required Reduce the Eskom funding shortfall (since costs are only incurred by Eskom at the same time energy is available for use) Reduce the country’s emissions challenge (for regional projects)  Due to risk factors highlighted herein, and not to constrain South Africa’s growth prospects, Government should look to bring on additional base load capacity sooner (than what is articulated in the MYPD2) as the reserve margin is likely to remain under significant pressure for the foreseeable future 25

26 Thank You


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