Quezon Coal Plant Case Study

• 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.

Philippine Power Market - Background

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).

Philippines Contracts

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

May 18, 2001Subic Group 22

Latest Photograph of Plant Under Construction

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

Enron PowerPhilippines Corp

PhilippinesGovernment

EnronCorp.

113MWSubicPowerCorp. Philippine

Investors

15-yearBOTConcession

NapocorSupplyFuel Free

•Capacity Charge•O&M Charge•Energy ChargePPA

Enron PowerOperating Co.

TurnkeyConstructionContract

CompletionGuarantee

Equip’t Cos. Warranties

US$105 million, 15-year Notes

BuyoutRights

Enron SubicPower Corp

O&MAgreement

PerformanceUndertaking

GroundLease

Insurances

Fluor DanielEnron PowerPhils. Op’g Co.

EPC

65%

35%

Case Study - FundingEnron - Subic Bay, Philippines

113 MW Diesel Generator Power StationSubic Bay, Philippines

Sources of Funds:Notes $ 105 MSubordinated Note 7Contr. Of Shareholders 28Working Capital 2

TOTAL $ 142Uses of Funds:

Turnkey Contractor $ 112 MBonus to Turnkey Contractor 7Development and other related costs and Fees 14Pre operating, Start-up and Commissioning Costs 3IDC 4Working 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

May 18, 2001 27

In Conclusion:

– Attractive Return

– Well Structured Deal

– Solid Sponsors (Enron, NAPOCOR and the Philippine Government)

– Manageable Risks

– Minimum Take: US$ 20 Million

Conclusion from Investor Perspective

• 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

Bond issue under rule 144 A

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

What IfMin

DSCRMin

InterestCover

PV LoanCoverRatio

EquityIRR

(Post Tax)Base Case 1.39 2.01 1.53 19%Availability = 81% 1.25 1.80 1.36 14%Operating expensesare 50% higher/yr

1.19 1.72 1.23 9%

Interest Rate is 12% 1.37 1.77 1.40 17%

Sensitivity Cases

Adjusted Results

Other Assumptions

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 FundsCapacity 440,000 MW

Construction Operation USD/kW PercentSources of Funds

Eximbank-Supported (Political Risk) Loan Facility 358,894,000Eximbank Direct Term Loan Facility 391,733,000 890.30 48%Senior-secured bonds, due 2017 215.000.000 215,000,000 488.64 27%Total Credit Facilities 573,894,000 606,733,000 1,378.94 75%

Total Equity Contributions 202,244,000 202,244,000 459.65 25%

Total Sources 776,138,000 808,977,000 1,838.58 100%

Uses of FundsGeneration Facility 419,560,000 419,560,000 953.55 52%Transmission Line 23,306,000 23,306,000 52.97 3%VAT, Insurance, Escalation 21,878,000 21,878,000 49.72 3%Total EPCM Costs 464,744,000 464,744,000 1,056.24 57%

Start-up and Other Owner Costs 50,487,000 50,487,000 114.74 6%Development Costs 37,885,000 37,885,000 86.10 5%Development Fee 8,000,000 8,000,000 18.18 1%Eximbank Exposure Fee 32,839,000 74.63 4%Interest During Construction 75,038,000 75,038,000 170.54 9%Other Financing Fees 68,425,000 68,425,000 155.51 8%Contingency, budgeted 35,000,000 35,000,000 79.55 4%Other 36,559,000 36,559,000 83.09 5%

Total Uses 776,138,000 808,977,000 1,838.58 100%

Contingent Commitments

Cost-Overrun Loan Facility (Unsupported) 30,000,000 30,000,000Contingent Equity Contributions 20.000.000 20.000.000TotatContingent Commitments 50,000,000 50,000,000

Construction Period1996 1997 1998 1999

USES DURING CONSTRUCTION Environmental, Procurement, Contracting 11,408 170,178 210,784 54,123Start-up Costs 559 4,968 13,370 8,973Development Costs & Fees 30,098 13,000IDC 16,487 32,515 44,648Financing Costs Upfront Fees 9,250 2,930 45,128Commitment Fees 245 5,580 4,689 3,978Development Capital & Project Equity 3,250 0Debt Placement Advisory 3,750 7,498 5,473Other Financing Costs 7,300 6,552Contingency 11,667 11,667 11,667

Working Capital 8,865

Other 8,711 6,596 9,474 10,463

TOTAL USES 74,571 224,958 289,997 206,318

SOURCES DURING CONSTRUCTIONDebtWorking CapitalEximbank 44,601 192,848 144,435

Capital Markets Debt 215,000OPIC Loan 74,573 -74,573Net Bonds 74,573 140,427 0 0

Local Bank LoanInternational BanksTotal Debt 74,573 185,028 192,848 144,435

EquityInterGen 28,950 70,433 44,864Ogden 10,981 26,716 17,017Total Equity 39,931 97,149 61,882

TOTAL SOURCES 74,573 224,959 289,997 206,317

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

Moody’s Comments

Downgrade of Bonds

Problems with Quezon

Moody’s Comments

S&P Comments on Meralco

Comments on Meralco

Cost Comparison in Case

Project Location Capacity Total Cost Cost per kW Operational Date Major Owners

Quezon Philippines 440 MW, Coal-fired $812 million $ 1845.45 per kW Dec. 1999 InterGen 71.5% Ogden 26.5% PMR 2%

Rocksavage United Kingdom

770 MW, Combined cycle

$600 million $ 779.22 per kW Jan. 1998 InterGen 100%

Samalayuca Mexico 700 MW, Combined cycle

$630 million $ 818.18 per kW Nov. 1998 InterGen 20%; GE40% El Paso 30% ICA 10%

Spalding United Kingdom

770 MW, Combined cycle

$577rnillion $ 749.35 per kW March 2000 InterGen 100%

TermoEmcali Colombia 235 MW, Natural gas-fired

$212 million $ 902.13 per kW Jan. 1999 InterGen 54% Emcali 43% CFP 3%

Jacui Brazil 360 MW, Pulverized coal fired

$370 million $ 1027.78 per kW June 2000 InterGen 100%

Sao Paulo 1 and II Brazil 900 MW $510 million $ 566.67 per kW June 2001 InterGen 50% Shell 40% VBC 10%

Coryton United Kingdom

750 MW $660 million $ 880.00 per kW March 2001 InterGen 100%

Meizhou Wan China 2 x 360 MW, Coal-fired

$751 million $ 1043.06 per kW Aug. 2000 InterGen 40.5% Lippo Group 49.5% Others 10%

Mayakan Mexico700 km natural gas pipeline $260 million Sept. 1999

InterGen 32.5% TransCanada 62.5% Gutsa Const. 5%

Average $ 956.87 per kW

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 RatesDepreciation 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

1961

1963

1965

1967

1969

1971

1973

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

0.00

10.00

20.00

30.00

40.00

50.00

60.00

Philippines Exchange Rate and Inflation Rate

Infllation RateExchange Rate

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

Singapore

HK

- Island

HK

- Kolow

oon

Iceland

Perú

South A

frica

US

A

Malaysia

Australia

Finland

Canada

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

28.80

15.31

12.30 11.80 11.6110.44 10.15 9.28

7.42 7.11 6.95 6.18

Price Comparison from Wikipedia

Cents per kWh in USD

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.