Philippine Power Market - Background Frequent brown outs ranging from 2 to 12 hrs daily in early 1991. Cancelled 625 MW Batam Nuclear plant when it was almost complete. Projected growth in electricity demand requires commissioning of new plants and rehabilitation of old plants. State-owned Generating Company was NAPCOR; Approx. 72% of NAPCOR’s capacity is in Luzon. Frequent closure of existing plants due to deterioration of oil based plants. Failure to undertake regular maintenance of certain plants Postponed maintenance due to insufficient power reserve The S&P bond rating for the Philippines was BB The World Bank estimated that power outages in 1990 reduced economic output in Metro Manila alone by $2.4 billion.
Background on Existing State-Owned Utility Company Approx. 72% of NAPOCOR’s capacity is in Luzon. Existing plant capacity exceeds peak demand (est. at 3,473 MW). NAPOCOR unable to operate its plants at full capacity, only 2,333 MW (50%) of 4,639 MW total Luzon capacity. Frequent closure of existing plants due to deterioration of oil based plants. Failure to undertake regular maintenance of certain plants Postponed maintenance due to insufficient power reserve
Context of Power Crisis in Early 1990’s To understand the rush to welcome private investment in the early 1990s, it helps to also see the cost of the chronic blackouts of that time. At the peak of the shortage, the blackouts averaged 12-14 hours per day, 300 days per year. A World Bank report in 1994 estimated that gross economic cost of the outages was US$0.50/kWh. Thus, even though IPP-generated electricity (average cost US$0.0652/kWh) at the time was more expensive that NPC-generated electricity (US$0.0637/kWh), the inability of the government to finance rapid expansion of the power sector made private investment extremely attractive.
Legislation and the Power Shortage The Philippines entered the IPP market early, with a 1988 presidential decree authorizing private investment in the generation sector. Major investment in IPPs occurred in response to a 1991-93 electricity crisis. The Electric Power Crisis Act passed in 1993 authorized negotiating IPP contracts on a fast track basis. In terms of addressing the power shortage, this law was a success—several thousand megawatts of generating capacity was installed in the country in the first 18 months. Most of the generating capacity built during this time was based on combustion turbines or diesel systems—the only generation plants that could be brought to operation within a year—which are characterized by low initial capital costs, but high operating costs. The fast track authority under this law expired in April 1994.
Growth in Electricity Generation from EIA Prediction was for about 9% Growth
Fast Track Contracting Because of the power crisis, the government had no significant leverage in the negotiations. The unstable political condition created a situation where “economy risks” required a premium placed on project returns. The entry of some IPPs had to be on a “fast-track” basis and some were contracted through negotiations rather than competitive bidding. In contrast, Thailand bided out its first batch of IPP capacity during the time when its economic performance was the envy of all ASEAN. As a result, the offers were very competitive (some offers took on the FOREX risk) and represented about ten times more capacity than what EGAT had asked for.
Three Rounds of Development The IPP sector in the Philippines developed in three main rounds. First, the plants contracted in the early 1990s to address the power crisis were largely oil-fired plants with 5-12 year PPAs. These tended to be expensive because: (1) the rapid capital recovery period under short PPAs, (2) the extreme pressure on government negotiators stemming from the grave electricity crisis, and (3) the high fuel cost oil plants were dispatched as baseload facilities during the crisis. Second, a wave of large baseload coal plants – most importantly Pagbilao (700MW), Sual (1200MW), and Quezon (originally 440MW, now rated at 460MW). These reached operation between 1996 and 2000 and had longer PPAs (up to 25 years). Third, a round of big hydro/irrigation projects and natural gas plants that reached aoperation from 1998 to 2002, including Casecnan hydro (140MW), San Roque hydro (345MW), CBK hydro (640MW), Ilijan natural gas (1200MW), Santa Rita natural gas (1000MW) and San Lorenzo natural gas (500MW).
Capacity was Added over Many Years
Additions of Capacity by Type
Diesel Added Early/Gas and Hydro Added Later
Initial Contracts The country had its first Build-Operate-Transfer contract in 1987, with Hopewell Holdings Ltd. of Hong Kong tycoon Gordon Wu as the proponent. Hopewell constructed two 100-megawatt gas turbine plants in Luzon. The venture was deemed so successful that the government was encouraged to enter into more BOT power contracts and even enact the BOT law (Republic Act 7718) that would allow Napocor to tap the private sector more effectively. Past and present government officials agree that the early Hopewell contracts provided the model for all future power deals with the private sector. But Napocor soon found itself with more IPP contracts, and more power, than it could handle, and what was once thought of as a brilliant solution to the country's power needs have now become problems themselves. At the time it was accumulating IPP contracts, the government had also let the private Manila Electric Co. (Meralco) to build its own power plants, which later exacerbated an energy oversupply.
Summary of Capacity and Costs By 1998, foreign owned IPPs accounted for US$6 billion of investment and 4800 MW of generating capacity. Over 90% of new capacity installed during the 1990s came from foreign owned IPPs. Average capital cost of $1,250 per kW. IPP capacity with PPAs is now 55% of the total capacity. The first contract was signed in 1988 and more than forty projects have been built in total. IPPs in the Philippines have exhibited a wide variety of characteristics from fuel choice to the composition of project sponsors and the identity of the offtaker. IPPs in the Philippines have largely earned healthy returns, even in the wake of economic crises and a highly visible renegotiation of most of the PPAs in the sector. From the country perspective, returns have been mixed. Political instability and poor sector planning have led to expensive electricity.
Cost of New Plants
Comparative Plant Costs
Cost of Plants per kW
Philippines PPA Features Capacity-based formula with take or pay and capacity nominated by the IPP. Energy-based formula, a percentage is applied on a contracted or guaranteed annual energy. Availability fee formula carries both the capacity recovery and the fixed O&M fees. These fees are payable as long as the facility is available even if not dispatched. NPC is responsible for the supply of fuel, with delivery at site. Storage, usage and management of the fuel are within the control of the IPP. This was because NPC has tax-exempt privileges with respect to fuel oil purchases and government-to-government arrangements for coal; making fuel pass through charges to consumers cheaper. Fee payments by NPC to the IPPs have large dollar denominated components. NPC thus bears the currency risk to the extent of the dollar payments.
Philippines PPA Provisions Continued Payments in IPP contracts have both Capacities cost recovery and O&M component. In turn, the O&M portion is subject to escalation. In some of the geothermal contracts, fees are bundled into a single energy charge and escalation is pegged thereon to as high as 75%. Escalation is based on varying factors depending on the project such as salary adjustment of personnel, movement of local and foreign consumer price indices, and the peso-dollar exchange rate. A number of NPC’s obligations are fully backed up by a government guarantee or performance undertaking. Very few contracts have only partial government performance undertaking depending on stipulations regarding payments of fees, privatization, and foreign exchange convertibility.
BOT and Sovereign Guarantee Ownership structure for IPPs in the Philippines is dominated by the BOT form. The prevalence of BOT contracts as opposed to other forms results from the fact that the “transfer” element of the project makes the project eligible for a sovereign guarantee. Formally, only solicited projects are eligible for this guarantee – a rule that invited substantial controversy in the case of the CBK hydro project, which although unsolicited, received a performance undertaking from the Department of Finance.
List of Projects and PPA Terms
Case 1: Enron Subic Summary Financial Close: 1993 (First Round) Commercial Operation: 1994 PPA Agreement: 15 Years; Guarantee by Government Bonds: $105 Million Maturity 15 Years Repayment Level Interest Rate 9.5% (3.68% spread to Treasury) Minimum DSCR 1.37 Completion Guarantee/Liquidated Damages Capacity Charge $21.6/kW/Month
BOT/PPA Contract 15 year BOT and toll process NAPOCOR (government owned generation company) to supply fuel & take electricity - no fuel availability risk Capacity fee $21.6/kW/month on available capacity Capacity fee is dollar denominated – no direct foreign exchange risk, overseas a/c O&M fixed fee and energy fee is in Peso - $4.56/kW/Month heat rate penalty & bonuses buy out rights @ NPV capacity fees- late payment, change of BOT law, war, etc
Case Study - FundingEnron - Subic Bay, Philippines Equip’t Cos. Warranties Philippines Government Enron Power Operating Co. Completion Guarantee Fluor Daniel EPC Enron Corp. Enron Power Phils. Op’g Co. 15-year BOT Concession Turnkey Construction Contract Performance Undertaking Enron Subic Power Corp O&M Agreement Supply Fuel Free Napocor 113MW Subic Power Corp. Enron Power Philippines Corp Ground Lease 65% Buyout Rights 35% Philippine Investors Capacity Charge O&M Charge Energy Charge PPA Insurances US$105 million, 15-year Notes
113 MW Diesel Generator Power StationSubic Bay, Philippines Sources of Funds: Notes $ 105 M Subordinated Note 7 Contr. Of Shareholders 28 Working Capital 2 TOTAL $ 142 Uses of Funds: Turnkey Contractor $ 112 M Bonus to Turnkey Contractor 7 Development and other related costs and Fees 14 Pre operating, Start-up and Commissioning Costs 3 IDC 4 Working Capital 2 TOTAL $ 142
Subic Covenants Financial Covenants Debt Service Cover Ratio 1.10 Debt Service Reserve Account: 6mos debt service deposit Debt Payment Account: monthly retention Restrictions on additional indebtedness other than financing acquisition of Additional Facilities @ max 75% financing scheduled payments to EPOC subordinated debt < US$ 25mln working capital loan shareholder payments / repayments payments of sub-debt investments other than permitted investments
Conclusion from Investor Perspective In Conclusion: Attractive Return Well Structured Deal Solid Sponsors (Enron, NAPOCOR and the Philippine Government) Manageable Risks Minimum Take: US$ 20 Million
Bond issue under rule 144 A BORROWER - Subic Power Corporation Amount - USD 105 million Maturity - 15 years Payments of Principal & Interest are fully guaranteed by Enron Corporation until the Facility Completion Date. Repayment - equal semi-annual Jun 28/Dec 28. Interest is accrued - 9 1/2 % p.a payable semi annual. Interest base and Margin - US Treasuries 15 Y + 385 bp fixed rate
Key Defaults Failure to pay principal/ interest within 15 days after due dates Fails to perform following covenants maintain DSRA, DPA & Revenue account & payments therein amendment of project contracts or merge/ sell assets outside indenture default on other indebtedness over $1 mn. - right of acceleration not waived Ceasure of BOT/ Performance undertaking and/ or reduction under BOT by over 2% and modification of Performance u’tkg. for the same Enron’s completion guarantee held invalid/ unenforceable NAPOCOR’s bankruptcy and Govt.’s non-confirmation of performance u’tkg.
Completion Guarantee Completion Guarantee All principal and interest payments on the Notes are guaranteed fully by Enron Corporation, and severally, in proportion to their ownership interest in the Company, by House of Investment (HI) and Rizal Commercial Banking Corporation (RCBC). Security: Mortgage on all real property and security interest on all substantial tangible property. Security interest in Company’s cash and investment. Collateral assignment of: BOT Agreement Turnkey Construction contract Performance Undertaking Other project contracts
EPC Contract EPOC wrap- Fluor Daniels assistance & local contracts $112m fixed price LDs $6m capacity, $10m heat rate $2m scope discrepancy bonus payments for $3.6m capacity and $3m heat rate 12-19 month warranty with liquidated damages per day
Quezon Coal Plant Case
Quezon Case Study Capacity 440 MW Cost USD 808.9 Million Transmission 230 kV 31 km PPA 25 Years covered costs as long as as-contracted performance met Offtaker: Meralco (First PPA with Private Utility) BOO without government guarantee
Sources and Uses of Funds
Development Risks Approval and Construction Financing Risks Contractual and Operating Currency/Country
Public Support During Contruction
Quezon EPC Contract Pulverized Coal -- Proven Construction since 1950’s Bechtel EPC Contractor LSTK Liquidated Damage Caps Meralco Leased Property Contingency USD 35 Million Cost Over-run Facility Debt 30 Million Contingent Equity 20 Million
Sponsors Contribution Ownership Intergen 72.5% 71.875% Bechtel and Shell Joint Venture Ogden Enterprises 27.5% 26.125% Local Developer 2.000%
Fuel Supply Fuel Supply from Indonesia Potential and Desire to Use Local
PPA Provisions Four Part Tariff Capacity Payment for Fixed Charges Fixed O&M Charges Variable O&M Charges Energy Charges
Off-taker Meralco is Private Distribution Utility Currency Risk Franchise Renewal Electricity Prices Bond Rating BB+
O&M Contract Ogden was O&M contractor Received USD 160,000 per year above costs Bonuses Achieving high capacity factor Costs under budget Intergen Management Fee USD 400,000
Project Debt Political Risk Insurance Generally not for bonds Exim takes insurance, but includes up-front fee Treatment of Exim Up-front Fee
S&P Initial Comments on Project
S&P Comments on Quezon Continued
Downgrade of Bonds
Problems with Quezon
S&P Comments on Meralco
Comments on Meralco
Cost Comparison in Case
Recent Comparison of Cost of Project PAGBILAO, Quezon ,Philippines – Team Energy, a joint undertaking of Japanese firms Marubeni Corp. and Tokyo Electric and Power Corp., will start the $700-million expansion of the Pagbilao coal-fired power plant in this province next year. Federico Puno, Team Energy president and chief executive officer, said the company would finalize the details of the project that would generate another 400 megawatts of power. Puno said talks with another Japanese firm, Mitsubishi, for the engineering, procurement and construction (EPC) contract of the project are ongoing. “If there is no agreement firmed up within the first half of the year, Team Energy will bid out the EPC contract to enable them to set up everything they need in time for the planned groundbreaking in the first quarter of next year,” he said. He said Team Energy is optimistic commercial operations could start in 2015.
Valuation of Plant Covanta Holding Corporation (NYSE:CVA) (Covanta), announced that it has agreed to sell all of its interests in the Quezon coal-fired electric generation facility located in the Philippines to Electricity Generating PCL (EGCO) for a price of approximately $215 million in cash. EGCO is a current partner in the Quezon project and we expect the transaction to close in the first quarter of 2011, subject to customary approvals and closing conditions. Quezon is a world-class asset and the valuation reflects its strong potential going forward." The Quezon assets being sold consist of the Company's entire interest in Covanta Philippines Operating, Inc., which provides operation and maintenance services to the facility, as well as its approximately 27% ownership interest in the project company, Quezon Power, Inc. (QPI). The sale is expected to generate a one-time after tax book gain of approximately $140 million at closing. For the twelve months ended September 30, 2010, Quezon's contribution to Covanta's consolidated results was: $2.8 million of revenue, $19.5 million of Adjusted EBITDA, $15.9 million in Free Cash Flow and $0.12 of diluted earnings per share. Covanta Completes Sale of its Interest in Quezon Project March 28, 2011 – Covanta Holding Corporation today announced that it has completed the sale of its interests in the Quezon coal-fired electric generation facility located in the Philippines to Electricity Generating PCL (“EGCO”). The purchase price of $215 million was paid in cash.
Quezon Transactions 14 May 2012 (Reuters) - Thailand's second-largest private power producer, Electricity Generating Pcl (EGCO), said on Monday it would spend $375 million to buy an additional 45.875 percent stake in Quezon power plant in the Philippines. The transaction, expected to be completed in the second quarter, will raise EGCO's holding in Quezon Power to 98 percent. Quezon owns and operates a 503 MW coal-fired power plan. The deal would also include a 100 percent stake in InterGen Management Services (Philippines) Ltd, which provides project management and administrative services to Quezon Power,
Philippines Case - Results
Results – Power Outages Measured by their ability to reduce power outages, the BOT programs were undoubtedly a success. Notably, this increased provision of power came without increased government debt as most projects were financed on global capital markets. The BOT and related programs also significantly increased the scope of private sector involvement. At the beginning of 1996, 21% of the country’s installed capacity for power generation was contracted with the IPPs. Because the IPP schemes also encouraged private sector operation of government-owned plants, fully 42% of Philippine generation capacity was operated by the private sector. 21 The World Bank praised the BOT programs, calling them a potential model for other developing economies.
Capacity and Demand By 1998, peak capacity was 11,988 MW while peak demand was 6,421 MW. Demand projections in the early- and mid-1990s forecast demand growth ranging from 9.5-12% per year. A 1994 report by the World Bank already warned implicitly against the risk of over-commitment through the uncoordinated signing of PPAs, which essentially passed demand risk to the consumer through take-or-pay provisions. The costs of IPPs were often high because the new capacity was not consistent with the least-cost expansion path and the private sector required high rates of return. The focus on production rather than efficient distribution put the public sector in the position of retaining that activity in which it was least effective and restricting the private sector from performing the customer focused activities (distribution and supply) where it had real expertise. At the same time, it isolated the private sector from the market through a combination of regulated pricing and guarantees against commercial risks.
Philippines IPP Contracts Reserve Margin is about 155% Estimated Growth – 9.2% Actual Growth – 3%
PPA Provisions The take-or-pay provisions ensure that the IPP proponents are paid up to the level of the minimum energy off-take (MEOT) whether the government utility was able to sell the power or not. IPP liabilities estimates up to the remaining terms of the contracts is in-between $6 - $ 8B in net present value. The buy-out figure of $11.8 B is gross since the Government can turn around and sell the capacity to another party. In 1992, the GDP was US$52 billion. PPA buyout in total would be 21% of GDP.
Effects of PPA Program The effects of the PPA capacity charges were exacerbated by the structure and implementation of the IPP program. The rapid build-out of IPPs during the 1990s meant that with the impact of the Asian financial crisis in 1998, the cost of electricity began to explode dramatically due to a combination of: the high fixed cost of the IPPs (capacity payments or minimum offtake) and the escalating foreign exchange liability stemming from deep reliance on foreign capital. The controversial “PPA” pass-through mechanism began climbing rapidly with the crisis, eventually becoming larger than the base rate itself.
Exchange Rates Depreciation in exchange rates of about 70% caused increases in capacity charges
Risk Mitigation and Purchasing Power Parity Purchasing Power Parity Change in exchange rate (versus USD) Current exchange rate x (1+local inflation)/(1+US$ inflation) How purchasing power parity mitigates risk In theory people in the country are willing to pay higher nominal prices because of inflation and the net cash flow for the project should be the same For example, if the inflation rate increases to 20%, the exchange rate should reflect depreciation in the currency of 20%. Problems with purchasing power parity assumption Large devaluations can occur without inflation rate changes For example, the East Asian Crisis of 1997
Example of Purchasing Power Parity and Inflation
Index of Exchange Rate and Purchasing Power
Result – High Power Rates Exceptionally high power rates were cited as one reason why Intel Philippines, one of the country's biggest foreign investors and largest employers, with over 5,000 workers, plans to close down its Philippine operations and divert the company's investments to lower-cost Vietnam and Malaysia. A recent government survey showed that the high cost of electricity is one of the main reasons why foreign investors are reluctant to locate their businesses in the Philippines. According to the Heads of ASEAN Power Utilities/Authorities, a consultative group attached to the 10-member Association of Southeast Asian Nations, the average cost of electricity in the Philippines last year was 17.5 US cents per kilowatt-hour (kWh). That is more than three times the 5.38 per kWh cost in Vietnam, and is markedly higher then the 6.77 per kWh cost in Indonesia, 7.67 per kWh in Malaysia and 8.50 per kWh in Thailand. Even high-cost Singapore recorded cheaper power rates at 13.07 per kWh.
High Power Rates (Excluding Europe)
Philippines – Contract Review The process began with a 2001 electricity sector reform law (“EPIRA”) that required the appointment of an inter-agency commission (“IAC”) to review the IPP contracts, which by 2001 had become politically and economically vulnerable. The law also mandated the unbundling of electricity rates in consumer bills. This seemingly innocuous measure allowed Filipino citizens to see for the first time the precise origins of the costs that created some of the highest electricity rates in Asia. What they saw was that the power purchase adjustment that financed the state utility’s IPP obligations was almost equal to the cost of the actual electricity consumed.
Philippines – Review of Contracts The IAC Review covered a total of 35 projects—all of Napocor’s operating contracts with IPPs. Of these, six were cleared, and the other 29 contracts were found to have issues of various kinds and were targeted for renegotiation. Upon completing the review, the IAC handed responsibility for implementing its findings to the Power Sector Assets and Liabilities Management Corporation (“PSALM”). First, IPPs would bear cost or fee reductions that were not contrary to the terms of the original contract—most commonly the project companies made a collateral agreement not to nominate the full 105% or 110% that the contract allowed, or clarified ambiguous terms in a manner advantageous to the government. Second, PSALM also considered a negotiated buy-out when the sponsor firms were interested in exiting the project.