Economic Issues in the Case • The case can be used to study a number of issues • Risks and returns of merchant versus contract • How can risks be evaluated in a model • Covenants in contract and merchant operation • Debt service reserves in alternative operation • Costs and benefits of bond financing • EPC contract • LD for delay • LD for plant performance • Evaluate Merchant versus Contract • What is the long-run equilibrium price • How can break-even be calculated
“…in the US, private companies that own merchant plants have lost of more than $100 billion in market capitalization.” Banks are “now highly reluctant to take merchant risk of any kind… and they are skeptical about long-term purchase or tolling contracts that in any way are considered to be out of the money.” “Merchants will have to redesign their business models. Those players that have 80-90 percent of their capital in the form of debt won't survive. The ratings agencies have said that such debt-to-capital ratios must be in the 50-50 range to earn investment grade status so that the cost of borrowing is reasonable.” The merchant plant activity has been very high. Merchant Plant Activity
Argentina Example of Merchant Problems • In Argentina, plant efficiency, over-capacity and increased hydro generation caused financial problems with projects.
Argentina Example – AES Panera • Combined Cycle Plant (830 MW) • Sponsors: AES and CEA; Plant Cost $448 Million • Financing • Equity $154 Million: 34% • IDB – A Loan $ 66 Million: 15%; 14.5 Year • IDB – B Loan $ 66 Million: 15%: 12.5 Year • JEXM Direct $ 81 Million: 19% • JEXM Comml $ 81 Million: 19% • No long-term Contracts • Plant Operation – 1999 • High DSCR’s – 2.31 in first 5 years • Trapped Cash • Cash Sweep Mechanisms • Forward Looking Financial Ratios • 12 Month Debt Service Reserve
Commodity Prices Merchant Electricity Plant Financing in UK • Before Financial Meltdown • Leverage -- 75-80% • Debt tenor -- 20 years • Credit spread -- 150-200 basis points • Equity IRR – 13%-15% • After Meltdown • Leverage 50% • Debt tenor 10 Years • Credit spread 250 basis points • Equity IRR – 16%
Agreements • EPC Contract • 790 MW for 322 Million GPB • Plant Cost -- 397/kW in GBP; 650/kW in USD • Actual Fixed Cost Assets at COD 314 Million • Capacity and Tolling Agreement • Terminates in 2014 • O&M Agreement • 5 Million for 12 Years with Escalation • Administrative Expense Agreement for 25 Years • Initially with Enron at 330,000 • Now at 200,000 with EDF • Exchange Rate Swap
Debt Financing • Bonds • Principal • 195 Million GBP • 150 Million USD (91.9 GBP) • Total -- 287 GBP • Rates • UK 8.625% • US 7.97%; After Swap Effective Rate is 8.45% • Exchange Rate 1.6317 • Weighted Average Rate is 8.56% • Term • 25 Years • Dates • 30 June and 31 December
Sutton Bridge Bond Financing and EPC • Sutton Bridge is a 790 MW combined cycle gas-fired power plant located 140 miles north of London. By financing it via a capital markets issue sponsor Enron obtained favorable fixed-rate debt at longer maturities and with greater flexibility than would have been achieved had it used a more typical loan syndication. It used a variety of financial engineering tools to obtain these attractive terms, including a shifting credit structure, dual-currency tranches, and sharing risk between several groups within the Enron family of companies. • The key to the structure was the three-phase life of the bonds. • In the first 19 months, the bonds carry construction risk, but it is mitigated by the fixed-price engineering contact with Enron. This contract, however, falls short of the standard turnkey EPC contract usually found in project bonds, and that generally come at premium to sponsors. Liquidated damages and other agreements with primary equipment supplier GE mitigate most of the construction-related and plant-performance risks. The cost overrun facility is also helpful in this regard.
Sutton Bridge Bond Re-payment Construction Tolling Agreement Merchant
Tolling Agreements and Risk (S&P) • In an era of competitive power, when merchant generators are assuming risks of price and dispatch (volume), tolling arrangements can materially reduce the risk of revenue volatility for owners and operators of single-asset plants. • The presence of electricity market risk in a project is often a constraint in obtaining an investment-grade rating, especially for single-asset plants that have no portfolio diversification. • Having a tolling agreement can mitigate risk to the extent that a single-asset generator operating in a competitive electricity market can obtain an investment-grade rating even with fairly high debt leverage and relatively low debt-service coverage ratios.
Financing During Tolling Agreement • The second phase runs from March 1, 1999 and runs until 2014. In this period there are none of the usual fixed-price fuel supply and offtake contracts, which protect downside risk but can end up hindering plants from operating at maximum efficiency. "They may lock the project into gas purchase prices that run out to be above market, or, conversely, force it to sell electricity at power sales prices that are ultimately below market," according to a report on the project in the Journal of Project Finance (Winter 1997). To offset these risks, the CTA with the Enron Capital assumes most fuel supply and offtake responsibility. Enron Capital makes monthly fixed payments related to the project's capacity that will be sufficient to meet all debt service obligations, plus quarterly variable energy payments based on the number of hours the gas turbines actually operate. The project then makes generating capacity available to Enron Capital, which is also the supplier of its natural gas. • Taking advantage of the deregulated EU gas markets, the plant will only operate in this second period when pool prices are sufficiently high. It is expected to be switched on and off several times a day.
Merchant Period • The third phase runs from 2014 to 2022. The project may operate as a true merchant plant in this time, with no sales contracts at all and thus subject to greater market and commodity price risk. By this time approximately 70% of the debt will have been paid down, and a higher debt service reserve will be created. Enron is expected to reduce its ownership position substantially in this period, perhaps to as little as 10%, although still manage the plant, and there is also the possibility that new 'clean' coal gasification technology could drive down the prices the plant could command in the UK markets. • Independent consultants' projections, however, convinced the rating agencies that the plant would still be highly competitive in this time. "Ultimately Sutton Bridge Power's credit strength will rest with its ability to maintain a high availability and to produce electricity in the most cost effective and efficient way possible," argued S&P's credit report. "In structuring this transaction, Enron has adequately mitigated this risk for the project's rating level."
Exchange Rate Risk • There is also some exchange risk, since the project earns revenues in sterling but has some dollar exposure. To mitigate this the issuer has a dollar bond currency swap arrangement with Enron Capital over the life of the dollar bonds that will provide it with fixed amounts of dollars in exchange for sterling, plus other swap agreements that limit its exposure to devaluation. • Swap converts GBP to USD at fixed rate to Sutton Bridge so payments are effectively in GBP. Loss on swap meant that USD increased relative to GBP and new swap would increase interest payments in GBP. • If interest rate swaps were sold or terminated, any gain or loss would be deferred and amortised over the remaining life of the debt instrument being hedged by the interest rate swap. • If the debt instrument being hedged by interest rate swaps were to be extinguished, any gain or loss attributable to the swaps would be recognised in the period of the transaction.
Market Concentration in UK 1990 and 2000 • The problems for banks exposed the sector boil down to one thing: overcapacity. There is calculated to be roughly 22% overcapacity and it is therefore not surprising that prices have slumped so spectacularly. Prices are now around 17 to 18 per MWH, down 40% from levels prior to NETA’s introduction. • The atomisation of the generation sector was a function of new entrants and forced sales and pricing power was lost before NETA was introduced. • .
Case 1: Evaluate Risk Using Model • Objective • Compute risk using model so that tools to mitigate risk can be evaluated. • Understand the theory of probability of default and loss given default in the context of project finance models. • Compute break-even price for merchant period • Use the DSCR to measure probability of default • Use loan outstanding to measure LGD • Compute break-even price in merchant case • Determine alternative break-even price if the financing is 40% equity. • Check the IRR on Debt
Case 2: Work with Construction • Objective • Evaluate effects of construction delay and construction over-run in order to set-up LD analysis and to set-up Senior and Subordinated Debt analysis. • Step by Step Analysis • Run with bank financing (20%) and find break-even price • Increase the construction expenditures by 30% • Change the construction profile • Evaluate IRRs • Evaluate DSCRs
Case 3: Evaluate Construction Issues and Liquidated Damage • Objective • How to use the model to compute liquidated damages, evaluate risk and return tradeoffs in EPC contracts, evaluate waterfall effect of liquidated damages, • Steps in LD analysis • Run model with delay • Compute required LD for project IRR, equity IRR, and DSCR • Compute the LD per day • Run with alternative delay scenarios • Evaluate LD with shorter life • Evaluate DSCR with alternative uses of LD (debt or debt and equity) • South Africa and Intergen examples
Case 4: Evaluate DSCRA with Model • Objective • Understand the cost and benefits of a DSCRA as compared to other tools. • Step by step • Compute the IRR and the DSCR with alternative levels of debt service reserve • Compute the break-even price with alternative DSCRAs • Contract case • Merchant case • Alternative volatility
Case 5: Evaluate DSCRs • Objective • Understand the logic of various DSCR issues in the context of how the PD measures break-even price • Step by Step • Compute break-even price • Compute break-even with DSCRA in the numerator • Consider • Cash flow injections to the debt service reserve • Operating reserve accounts • Gains and losses on unwinding swaps • Interest income from reserves
DSCR Exercise Continued • Consider selected issues • Unwinding Swap • Unwinding swap if the interest rate increases results in gains, but the new swap will have a higher rate. • Do not include the swap gains in cash flow for debt service • Projected DSCR will capture future increases • Asset Sale
Case 5: Cash Flow Restriction Exercise • Objective • Understand what covenants do to cash flow in alternative circumstances • What covenant matters most. • What covenants should be used in different circumstances • What level of covenant is best • Step by Step • Compute break-even with no covenant • No volatility, high volatility • Compute break-even with alternative covenants
Evaluate the Debt Structure of the Project • Assuming Contract • Assuming Merchant • Alternative Leverage • Alternative Debt Tenor • Alternative Debt Structure • Alternative Interest Rate
Moody’s Comments on Sutton Bridge • GBP 195 Million/US$ 150 Million Guaranteed Secured Bonds due 2022 • Rating: Baa3 May 1997 • Rating Factors: • Low Marginal Cost 790 Megawatt Gas-Fired Combined Cycle Plant • Involvement of Enron Corp. and Subsidiaries • 15-Year Capacity and Tolling Agreement (CTA) • Two-Thirds of Principal Repaid During CTA Term • Eight Year Merchant Risk Period • Transparency of UK Pool Price Setting Mechanism
Moody’s Comments on Sutton Bridge Tolling Agreement • Sutton Bridge is an Enron Corp owned and sponsored 790-megawatt combined cycle plant now under construction in the UK. It is also an excellent example of how market risks associated with sales into a competitive power market can be mitigated to a level which supports an investment grade rating. • The principal method by which the project did so was through its 15-year Capacity and Tolling Agreement with Enron Capital & Trade (ECT), under which ECT has agreed to purchase generating capacity from the plant, as well as supply natural gas which will be converted by Sutton Bridge into electricity for sale into the UK pool. • In return for making itself “available” to ECT, Sutton Bridge will receive a fixed monthly capacity payment designed to cover, among other things, projected debt service on the notes. • Moreover, the level and price at which Sutton Bridge will offer its power into the market will be determined solely by ECT, which would then receive the corresponding pool payments associated with a successful bid. As a result, Sutton Bridge has, during the term of the tolling arrangement, no economic exposure to changes in the market price of electricity. What’s more, since ECT is also responsible for delivering natural gas to the project, Sutton Bridge is similarly unaffected by changes in the price of its fuel.
Moody’s Comment on Merchant Risk • Following expiration of the tolling agreement, however — and assuming that new hedging arrangements are not secured — Sutton Bridge’s ability to generate cash flow and service its debt will be exclusively dependent upon its production costs relative to those of other facilities competing in the pool. As a result, the transaction is exposed to pure “merchant” risk for the remaining term of the financing, or roughly eight years. • A structure such as this presents a particular challenge from an analytical perspective, because it relies heavily on forecasts of supply and demand in the UK beginning in year 2014, and through to the bonds maturity in 2022.
Moody’s Merchant Scenarios • During this period, the Sutton Bridge market forecast (prepared by Ilex Associates) assumes, for the sake of conservatism, that the plant will not be dispatched, and that all project revenues are exclusively derived from the pool’s reliability premiums. While an unlikely scenario, the model implicitly recognizes that, by that point, most, if not all of the system’s relatively inefficient generation will have been displaced, and that Sutton Bridge’s profitability will be primarily derived from the value of its capacity. For this reason, the analysis focused on which specific plant would be setting the capacity prices on the system. • Under the most likely assumption, which is that capacity prices would be set by a baseloaded combined cycle plant, debt service coverage ratios average 2.5 times during the merchant period, and remain at sufficiently robust levels under a wide range of forecast gas prices. In fact, the only scenario where Sutton Bridge’s economics are materially threatened is under what is called the “retention” case, which refers to an environment where the value of capacity is determined by the cost of retaining the most costly plant on the system (the Net Avoidable Cost, or NAC). • This could occur under either of two scenarios, one of which is that new power stations are so cost effective that there would be an economic incentive to build them ahead of an immediate need for new capacity — a situation which would require unrealistically high gas prices, in order for the NAC to exceed the cost of a new station. • The second scenario in which the NAC could set the value of capacity is where large-scale government or regulatory intervention in support of “low carbon” environmental policies leads to the construction of new capacity ahead of need, but even if it is uneconomic to do so. The probability of occurrence for either of these cases — which would imply, based on what we know today, something less than rational market behavior or regulatory policy — is regarded as sufficiently remote to support the final Baa3 rating.
S&P Comments on Sutton Bridge • Enron’s Sutton Bridge Power project in the U.K. is an example of a tolling plant. The other version of a tolling plant entails a tolling agreement with the power purchaser; the power purchaser decides when to pull gas through the plant, how much electricity to generate, and what market price to accept. • Enron’s Sutton Bridge Power project uses the GE F9A+ turbine, which has had various technology problems. Hence, the project carries technology insurance, although General Electric will pay the premium surcharge cost. • Sutton Bridge Power and LS Batesville projects feature tolling agreements that remove market risk until the merchant period begins. In Australia, the large brown coal plants that the state sold as part of the privatization scheme are now single asset generating facilities structured as projects, relying on vesting contracts in part to mitigate demand-side risk.
Recent Comments by S&P • Sutton Bridge Financing Ltd. (U.K.) BBB- Stable • Availability of the plant over the summer has been good and in line with expectations. • Generation levels have been above budget. • Next annual maintenance is planned for March 2005. The plant has been running well as a base-load plant since commercial operations began. • The capacity and tolling agreement with EDF Energy PLC continues to result in a stable financial performance as no price or volumes risk is taken.
Sutton Bridge Award • ENRON EUROPE WINS 1997 JAMES H. McGRAW AWARD FOR SUTTON BRIDGE BOND FINANCING Friday, November 7, 1997 • LONDON - Enron Europe Limited has been awarded a 1997 James H. McGraw Award for Business Excellence from Electrical World Magazine for the bond financing of the Sutton Bridge power station. • In honouring Enron Europe for the financing of the £337 million project, the editors noted that the bond issue "highlights the project's innovative structure and financing arrangements, in particular its precedent-setting power sales agreement and risk management components. • "Sutton Bridge's BBB bond rating reflects Enron's carefully crafted financial features that successfully mesh innovation and sound economics by balancing contractual commitment, merchant risk and ties to natural gas sales." • The Sutton Bridge power station project, which is set to begin commercial operation in March 1999, is a 790 MW combined-cycle gas turbine plant in Lincolnshire, UK. • Jeffrey McMahon, vice president and chief financial officer of Enron Europe Limited, accepted the award at a ceremony in Washington, D.C.
US Utility Enron puts Sutton Bridge Power Plant up for Sale • Enron, the Texas-based utility which owns Wessex Water, has put its Sutton Bridge gas-fired power plant up for sale it emerged yesterday, less than a year after the station supplied its first electricity to the Grid. • The American firm, which has invested £370m in the plant, has retained investment bank Dresdner Kleinwort Benson to handle the auction after receiving a number of unsolicited approaches. An Enron official said the group had decided to divest the 790 megawatt plant near Kings Lynn in Lincolnshire because of the clear demand in an increasingly competitive market. The price will include a premium because of the current moratorium on building new gas-fired plant. Potential buyers could include British Energy, Scottish & Southern Energy, Electricité de France, Centrica and a clutch of American power groups. • "There have been some major changes in the UK market and we had become aware that there was some interest in Sutton Bridge," the official said. "We are very much committed to owning and generating capacity in the UK but always keep assets under review to see if capital could not be better deployed elsewhere." • Enron has another older plant in Teeside and has a planning application lodged for a 1,200 megawatt plant in Kent. The demand for assets was sharply illustrated by the sale of Drax, the National Power coal-fired power station which sold two weeks ago to US producer AES for a higher than expected £1.87bn. The sale reduced National Power's market share to just 12% from 46% at privatisation. • PowerGen had earlier disposed of two plants generating a similar 4,000 megawatts to Mission Energy of the US for £1.25bn. The power supply map is being rewritten by demands from the government to increase competition through forced sell-offs.
Tolling Agreements • In terms of risk allocation, tolling arrangements are similar to power purchase agreements in that they provide a stable stream of cash flow in the form of contractually based revenues. In many tolling arrangements that Standard & Poor's has reviewed, the risks that remain with the plant owner and operator are less severe than those remaining under a power purchase agreement with a utility. A typical tolling arrangement clearly delineates risk-sharing between the plant owner and the tolling party. In many such agreements, the risks assumed by the plant owner are reduced to availability of plant and plant efficiency. For greenfield projects, the owner often accepts construction risk, which can also be effectively mitigated under turnkey construction contracts.
Modeling Issues in the Case • How can the contract be computed using goal seek and solver • How should break-even analysis be performed • How should the leverage be computed with and without the contract
Example of LD for Delay in Completion • Should Contractor fail to achieve Commercial Operation of a Unit by the Scheduled Date of Commercial Operation for such Unit, • Contractor shall be subject to liquidated damages in the amount of FORTY THOUSAND DOLLARS ($40,000) per Unit for each full Day or part thereof by which Commercial Operation of such Unit occurs later than the Scheduled Date of Commercial Operation for such Unit up to and including the fourteenth (14th) Day after the Scheduled Date of Commercial Operation for such Unit. • For each full Day or part thereof by which Commercial Operation of a Unit occurs later than the fourteenth (14th) Day after the Scheduled Date of Commercial Operation for such Unit up to and including the thirtieth (30th) Day after the Scheduled Date of Commercial Operation for such Unit, Contractor shall be subject to liquidated damages in the amount of SIXTY FIVE THOUSAND DOLLARS ($65,000) per Unit. • For each full Day or part thereof by which Commercial Operation of a Unit occurs later than the thirtieth(30th) Day after the Scheduled Date of Commercial Operation for such Unit, Contractor shall be subject to liquidated damages in the amount of EIGHTY TWO THOUSAND DOLLARS ($82,000) per Unit.
LD for Completion Continued • Such liquidated damages shall continue to accrue until Commercial Operation for such Unit is achieved or the limit set forth in Section 14.1 is reached, whichever is earlier; provided that, if Contractor has not previously achieved Commercial Operation of a Unit under this Agreement, • Contractor shall be deemed to have achieved Commercial Operation of a Unit (but only for purpose of determining liquidated damages under this Section) on the date on which Owner achieves Commercial Operation of such Unit under the Power Purchase Agreement, • but only if net power output for such Unit is at least 148,590 KW of electricity • and the net heat rate for such Unit is not greater than 11,217 BTU/KW-HR (HHV) on natural gas and 11,362 BTU/KW-HR (HHV) on fuel oil as measured in the most recent Performance Test for such Unit.
LD and Retainage • With respect to the amount of liquidated damages which is a reduction to the Guaranteed Lump Sum Price, • Owner shall have the right to deduct the amount(s) of such liquidated damages from the next payment(s) due to Contractor after the due date of the liquidated damages and from Owner's Security, until the total amount of the liquidated damages has been deducted; • provided however, Contractor shall, within fifteen (15) Days after written demand, refund to Owner the payments made by Owner on the Guaranteed Lump Sum Price to the extent the payments made to Contractor exceed the Guaranteed Lump Sum Price reduced pursuant to this Section 13.6 and the Owner's Security which is not needed to satisfy other claims against Owner's Security as provided herein. If the aggregate liquidated damages paid by Contractor on a Unit by Unit basis exceeds the final liquidated damages determined as set forth in Sections 13.3 and 13.4, • Owner shall pay to Contractor such excess amount within fifteen (15) days of the final determination of such liquidated damages. That portion of any payment or refund of liquidated damages which is not paid when due, as provided in Section 12.3(c), 13.6 and 13.7, shall bear interest at the prime rate as determined by the annual prime rate of The Chase Manhattan Bank as of the date due, plus one percent (1%), but not in excess of the lawful maximum rate.
Timing of LD • The amount of liquidated damages Contractor is subject to, or is liable for pursuant to the terms of this Agreement, except for liquidated damages under Section 13.7, shall be a reduction to the Guaranteed Lump Sum Price. • Except as otherwise provided in Sections 12.3(c) and 13.7, liquidated damages which accrue pursuant to Sections 13.3, 13.4 and 13.5 for each Unit shall become due to Owner on the later of the fifth (5th) Business Day after (i) the conclusion of Performance Testing for such Unit, • and (ii) the date of Commercial Operations for such Unit, • subject to final adjustment pursuant to Sections 13.3 and 13.4 following Commercial Operation of the last Unit. Liquidated damages payable pursuant to Section 13.7
Timing of LD Payments • Liquidated Damages under this Section 13.1 shall be calculated and become due to Owner fifteen (15) days after the scheduled Date of Commercial Operation for such Unit and shall continue to accrue and be subject to recalculation on the same day of each succeeding month until Commercial Operation is achieved for such Unit or the limit set forth in Section 14.1 is reached. • Any liquidated damages due from Contractor pursuant to this Section 13.1 with respect to a Unit shall be offset by Net Revenue, if any, received by Owner from the operation of such Unit prior to the Commercial Operation of such Unit or the deemed Commercial Operation of the Unit under Section 12.3(c). • Net Revenue for such purpose shall mean an amount equal to gross revenue (less any taxes payable on the receipt of such revenue) received or accrued by Owner for such Days from the sale of power, to the extent properly allocable to such Days in accordance with generally accepted accounting principles, consistently applied, less the sum of all costs incurred or accrued by Owner in generating such revenue, including costs of labor, fuel (including transportation), maintenance, consumables, and supplies (but not including any financing costs or charges), to the extent properly allocable to such Days in accordance with generally accepted accounting principles, consistently applied and less any liquidated damages paid by Owner under the Power Purchase Agreement as a result of the delay in Commercial Operation of such Unit.
Aggregate LD Limits • Contractor's total aggregate liability for liquidated damages under this Section 13.1shall not exceed twenty two and one half percent (22 1/2%) of the Guaranteed Lump Sum Price. • The aggregate liability of Contractor for liquidated damages under this Agreement shall not exceed an amount equal to thirty percent (30%) of the Guaranteed Lump Sum Price, as amended pursuant to this Agreement, excluding any reduction in the Guaranteed Lump Sum Price made for liquidated damages pursuant to Section 13.6.