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April 15, 2011 CORPORATION FINANCE DEPARTMENT SECURITIES AND EXCHANGE COMMISSION SEC Building, EDSA Greenhills, Mandaluyong City, Metro Manila ATTENTION : ATTY. JUSTINA CALLANGAN Director

RE : SEC FORM 17-A (Annual Report 2010) Dear Atty. Callangan: We file herewith three (3) copies of SEC Form 17-A (Annual Report 2010) of Aboitiz Power Corporation. Kindly acknowledge receipt hereof. Thank you. Very truly yours, ABOITIZ POWER CORPORATION By

LEAH I. GERALDEZ Office of the Corporate Secretary cc: Philippine Stock Exchange, Inc.

Attn: Ms. Janet A. Encarnacion Head – Disclosure Department

Philippine Dealing & Exchange Corp. Market Regulatory Services Group Attn: Ms. Ma. Concepcion M. Magdaraog Mr. Paolo Narciso

Issuer Compliance and Disclosures Department

COVER SHEET

C 1 9 9 8 0 0 1 3 4S.E.C. Registration Number

A B O I T I Z P O W E R C O R P O R A T I O N

( Company's Full Name )

A B O I T I Z C O R P O R A T E C E N T E R

G O V . M A N U E L A . C U E N C O A V E N U E ,

K A S A M B A G A N , C E B U C I T Y( Business Address: No. Street City / Town / Province )

ATTY. LEAH I. GERALDEZ 032-411-1804Contact Person Company Telephone Number

3rd Monday of May

1 2 3 1 1 7 - A 0 5 1 7Month Day FORM TYPE Month Day

Fiscal Year Annual Meeting

Secondary License Type, if Applicable

S E CDept. Requiring this Doc Amended Articles Number/Section

xTotal No. of Stockholders Domestic Foreign

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To be accomplished by SEC Personnel concerned

File Number LCU

Document I.D. Cashier

S T A M P S

Remarks = pls. Use black ink for scanning purposes

Annual Report 2010

1 • SEC FORM 17-A (ANNUAL REPORT)

SECURITIES AND EXCHANGE COMMISSION

SEC FORM 17-A

ANNUAL REPORT PURSUANT TO SECTION 17 OF THE SECURITIES REGULATION CODE AND SECTION 141

OF THE CORPORATION CODE OF THE PHILIPPINES 1. For the year ended 2010 2. SEC Identification Number C199800134 3. BIR TIN 200-652-460 4. Exact name of registrant as specified in its charter Aboitiz Power Corporation 5. Cebu City, Philippines 6.

Province, country or other jurisdiction Industry Classification Code of incorporation 7. Gov. Manuel A. Cuenco Ave., Kasambagan, Cebu City 6000 Address of principal office Postal Code 8. (032) 411-1800 Issuer’s telephone number, including area code 9. NA Former name or former address, if changed since last report 10. Securities registered pursuant to Sections 8 and 12 of the SRC, or Section 4 and 8 of the RSA. Title of Each Class Number of Shares of Common Stock Outstanding and Amount of Debt Outstanding Common (as of December 31, 2010) 7,358,604,307 Total Debt (as of December 31, 2010) π76,822,622,000 11. Are any or all of the securities listed on a Stock Exchange? Yes ( ) No ( )

If yes, state the name of such stock exchange and the classes of securities listed therein: Philippine Stock Exchange Common

12. Check whether the registrant:

(a) has filed all reports required to be filed by Section 17 of the Securities Regulation Code (SRC) and SRC Rule 17.1 thereunder or Section 11 of the RSA and RSA Rule 11 (a)-1 thereunder, and Sections 26 and 141 of the Corporation Code of the Philippines, during the preceding 12 months (or for such shorter period that the registrant was required to file such reports);


Yes ( ) No ( ) (b) has been subject to such filing requirements for the past 90 days.

Yes ( ) No ( )

13. State the aggregate market value of the voting stock held by non-affiliates of the registrant. The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within sixty (60) days prior to the date of filing. If a determination as to whether a particular person or entity is an affiliate cannot be made without involving unreasonable effort and expense, the aggregate market value of the common stock held by non-affiliates may be calculated on the basis of assumptions reasonable under the circumstances, provided the assumptions are set forth in this Form.

For 2010, aggregate voting stock of registrant held outside of its affiliates and/or officers and employees totaled 1,508,601,000 shares (for details please refer to the attached notes to financial statements and Schedule K of this report) while its average market price per share was P 18.90.

Based on this data, total market value of registrant’s voting stock not held by its affiliates and/or officers and employees was computed to be P 28,512,558,900.00.

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN INSOLVENCY/SUSPENSION OF PAYMENTS PROCEEDINGS

DURING THE PRECEDING FIVE YEARS: 14. Check whether the registrant has filed all documents and reports required to be filed by Section

17 of the RSA subsequent to the distribution of securities under a plan confirmed by a court or the SEC.

Yes ( ) No ( )

DOCUMENTS INCORPORATED BY REFERENCE

If any of the following documents are incorporated by reference, briefly describe them and identify the part of SEC Form 17-A into which the document is incorporated:

(a) Any annual report to security holders;

(b) Any information statement filed pursuant to SRC Rule 20;

(c) Any prospectus filed pursuant to SRC Rule 8.1.


PART 1 – BUSINESS AND GENERAL INFORMATION Item 1. Business (1) Business Development Incorporated in 1998, AboitizPower is a publicly listed holding company that, through its subsidiaries and affiliates, is a leader in the Philippine power industry and has interests in a number of privately-owned generation companies and distribution utilities. AEV owns 76.40% of the outstanding capital stock of AboitizPower as of February 28, 2011. The Aboitiz Group’s involvement in the power industry began when members of the Aboitiz family acquired a 20% ownership interest in Visayan Electric Company, Inc. (VECO) in the early 1900s. The Aboitiz Group’s direct and active involvement in the power distribution industry can be traced to the 1930s, when Aboitiz & Company, Inc. (ACO) acquired the Ormoc Electric Light Company and its accompanying ice plant, the Jolo Power Company and Cotabato Light & Power Company (Cotabato Light). In July 1946, the Aboitiz Group strengthened its position in power distribution in the Southern Philippines when it acquired Davao Light & Power Company, Inc. (Davao Light), which is now the third-largest privately-owned electric utility in the Philippines in terms of customers and annual gigawatt-hour (GWh) sales. In December 1978, ACO divested its ownership interests in the Ormoc Electric Light Company and the Jolo Power Company to allow these companies to be converted into electric cooperatives, which was the policy being promoted by the government of then-President Ferdinand Marcos. ACO sold these two companies and scaled down its participation in the power distribution business in order to focus on the more lucrative franchises held by Cotabato Light, Davao Light and VECO. In response to the Philippines’ pressing need for adequate power supply, the Aboitiz Group became involved in power generation, becoming a pioneer and industry leader in hydroelectric energy. In 1978 the Aboitiz Group incorporated Hydro Electric Development Corporation (HEDC). HEDC carried out feasibility studies (including hydrological and geological studies) and hydroelectric power installation and maintenance and also developed hydroelectric projects in and around Davao City. The Aboitiz Group also incorporated Northern Mini-Hydro Corporation (now Cleanergy, Inc.) on June 26, 1990, which focused on the development of mini-hydroelectric projects in Benguet province in northern Luzon. By 1990 HEDC and Cleanergy had commissioned and were operating 14 plants with a combined installed capacity of 36 megawatts (MW). In 1996 the Aboitiz Group led the consortium that entered into a build-operate-transfer (BOT) agreement with the National Power Corporation (NPC) to develop and operate the 70 MW Bakun AC hydroelectric plant in Ilocos Sur province. AboitizPower was incorporated on February 13, 1998 as a holding company for the Aboitiz Group’s investments in power generation and distribution. However, in order to prepare for growth in the power generation industry, AboitizPower was repositioned in the third quarter of 2003 as a holding company that owned power generation assets only. The divestment by AboitizPower of its power distribution assets was achieved through a property dividend declaration in the form of AboitizPower’s ownership interests in the different power distribution companies. The property dividend declaration effectively transferred direct control over the Aboitiz Group’s power distribution business to AEV. Further, in 2005 AboitizPower consolidated its investments in mini-hydroelectric plants in a single company by transferring all of HEDC’s and Cleanergy’s mini-hydroelectric assets into Hedcor, Inc. In December 2006, the Company and its partner, SN Power Invest AS (SN Power) of Norway, through SN Aboitiz Power-Magat, Inc. (SNAP-Magat) submitted the highest bid for the 360 MW Magat hydroelectric plant auctioned by PSALM. The price offered was USD530 mn. PSALM turned over possession and control of the Magat Plant to SNAP-Magat on April 26, 2007.


In a share swap agreement with AEV on January 20, 2007, AboitizPower issued a total of 2,889,320,292 of its common shares in exchange for AEV’s ownership interests in the following distribution companies, as follows:

• An effective 55% ownership interest in VECO, which is the second largest privately-owned distribution utility in the Philippines in terms of customers and annual GWh sales and is the largest distribution utility in the Visayas region;

• A 100% equity interest in each of Davao Light and Cotabato Light. Davao Light is the

third largest privately-owned distribution utility in the Philippines in terms of customers and annual GWh sales;

• An effective 64% ownership interest in Subic Enerzone Corporation (SEZ), which

manages the Power Distribution System (PDS) of the Subic Bay Metropolitan Authority (SBMA); and

• An effective 44% ownership interest in San Fernando Electric Light and Power Company

(SFELAPCO), which holds the franchise to distribute electricity in the city of San Fernando, Pampanga, in Central Luzon, and its surrounding areas.

In February 2007, the Company entered into a memorandum of agreement with Taiwan Cogeneration International Corporation to collaborate in the building and operation of an independent coal-fired power plant in the Subic Bay Freeport Zone. In May 2007 Redondo Peninsula Energy, Inc. (RP Energy) was incorporated as the project company that will undertake the Subic Coal Project. On April 20, 2007, the Company acquired 50% of the outstanding capital stock of East Asia Utilities Corporation (EAUC) from El Paso Philippines Energy Company, Inc. (El Paso). EAUC operates a Bunker C-fired plant with a capacity of 50 MW within the Mactan Export Processing Zone I (MEPZ I) in Mactan Island, Cebu. On the same date, the Company also acquired from EAUC 60% of the outstanding common shares of Cebu Private Power Corporation (CPPC). CPPC operates a 70 MW Bunker C-fired plant in Cebu City. On June 8, 2007, as part of the reorganization of the power-related assets of the Aboitiz Group, the Company agreed to acquire from its affiliate, Aboitiz Land, Inc. (AboitizLand) a 100% interest in Mactan Enerzone Corporation (MEZ), which owns and operates the PDS in the MEPZ II in Mactan Island in Cebu, and a 60% interest in Balamban Enerzone Corporation (BEZ), which owns and operates the PDS in the West Cebu Industrial Park-Special Economic Zone (WCIP-SEZ) in Balamban town in the western part of Cebu. The Company also consolidated its ownership interest in SEZ by acquiring the combined 25% interest in SEZ held by AEV, SFELAPCO, Okeelanta Corporation (Okeelanta) and Pampanga Sugar Development Corporation (PASUDECO). These acquisitions were made through a share swap agreement which involved the issuance of a total of 170,940,307 common shares of the Company issued at the initial public offering price of π5.80 per share in exchange for the foregoing equity interests in MEZ, BEZ and SEZ. In August 2007, the Company, together with Vivant Energy Corporation of the Garcia Group, signed a memorandum of agreement with Global Business Power Corporation (Global Power) of the Metrobank Group for the construction and operation of a 3x82 MW coal-fired power plant in Toledo City, Cebu. The Company, together with the Garcia Group, formed Abovant Holdings, Inc. (Abovant). The Company owns 60% of Abovant. The project, which is being undertaken by Cebu Energy Development Corporation (CEDC), a joint venture company among Global Power, Formosa Heavy Industries and Abovant, broke ground last January 2008 and is expected to be completed and start full commercial operations by first quarter of 2011. The Company has an effective participation of 26.40% in the project.


On November 15, 2007, AboitizPower closed the purchase of a 34% equity ownership in STEAG State Power, Inc. (STEAG), owner and operator of a 232 MW coal-fired power plant located in the PHIVIDEC Industrial Estate in Misamis Oriental, Northern Mindanao. The Company won the competitive bid to buy the 34% equity from Evonik Steag GmbH (formerly known as Steag GmbH) in August 2007. The total purchase price for the 34% equity in STEAG is USD102 mn, inclusive of interests. On November 28, 2007, SN Aboitiz Power-Benguet, Inc. (SNAP-Benguet), a consortium between AboitizPower and SN Power, submitted the highest bid for the Ambuklao-Binga Hydroelectric Power Complex consisting of the 75 MW Ambuklao Hydroelectric Power Plant located at Bokod, Benguet and the 100 MW Binga Hydroelectric Power Plant located at Itogon, Benguet. The price offered amounted to USD325 mn. In 2007, AboitizPower entered into an agreement to buy the 20% equity of Team Philippines in SEZ for π92 mn. Together with the 35% equity in SEZ of AboitizPower’s subsidiary Davao Light, this acquisition brings AboitizPower's total equity in SEZ to 100%.

In 2008, AboitizPower bought the 40% equity ownership of Tsuneishi Holdings (Cebu), Inc. (THI) in BEZ for approximately π178 mn. The acquisition brought AboitizPower’s total equity in BEZ to 100%. Last May 26, 2009, AP Renewables, Inc., (APRI), a wholly owned subsidiary of AboitizPower, took over the ownership and operations of the 289 MW Tiwi geothermal power plant facility in Albay and the 458 MW Makiling-Banahaw geothermal power plant facility in Laguna (collectively referred to as the “Tiwi-MakBan geothermal facilities”) after winning the competitive bid conducted by PSALM on July 30, 2008. The Tiwi-MakBan geothermal facilities have a sustainable capacity of approximately 462 MW. Therma Luzon, Inc. (TLI), a wholly owned subsidiary of AboitizPower, won the competitive bid for the appointment of the Independent Power Producer (IPP) Administrator of the 700 MW Contracted Capacity of the Pagbilao Coal Fired Power Plant (the Pagbilao IPPA) last August 28, 2009. It assumed dispatch control of the Pagbilao power plant last October 1, 2009, becoming the first IPP Administrator in the country. As IPP Administrator, TLI is responsible for procuring the fuel requirements of, and for selling the electricity generated by, the Pagbilao power plant. The Pagbilao power plant is located in Pagbilao, Quezon. AboitizPower, through its wholly owned subsidiary, Therma Marine, Inc. (TMI), assumed ownership over Power Barge (PB) 118 and PB 117 last February 6, 2010 and March 1, 2010, respectively, after acquiring the two power barges from PSALM for USD30 mn through a negotiated bid concluded last July 31, 2009. Each of the barge mounted diesel powered generation plants has a generating capacity of 100 MW. PB 117 and PB 118 are moored at Nasipit, Agusan del Norte and Barangay San Roque, Maco, Compostela Valley, respectively. Ownership in AboitizPower was opened to the public through an initial public offering of its common shares in July 2007. Its common shares were officially listed in the Philippine Stock Exchange (PSE) on July 16, 2007. The Company is in the process of implementing a corporate reorganization that will put all its renewable energy assets under Aboitiz Renewables, Inc. (ARI) (formerly Philippine Hydropower Corporation), and all its non-renewable generation assets under Therma Power, Inc. (TPI). Neither AboitizPower nor any of its subsidiaries has ever been the subject of any bankruptcy, receivership or similar proceedings.


(2) Business of Issuer With investments in power generation and distribution companies throughout the Philippines, AboitizPower is considered one of the leading Filipino-owned companies in the power industry (Please see Annex “A” hereof for AboitizPower’s Corporate Structure). (i) Principal Products GENERATION OF ELECTRICITY Since its incorporation in 1998, AboitizPower has accumulated interests in both renewable and non-renewable generation plants. As of December 31, 2010, approximately 93% of AboitizPower’s net income from business segments is derived from its power generation business. AboitizPower conducts its power generation activities through the following subsidiaries and affiliates: The table below summarizes the generation companies’ operating results as of December 31, 2010.

Energy Sold

Generation

Energy Sold

Generation

Energy Sold

Generation

Revenue

Revenue

Revenue

Generation Companies 2010 2009 2008 2010 2009 2008

(In GWh) (in Mn Pesos) APRI (1) 3,483 1,886 N/A 22,426 6,843 N/A Hedcor, Inc. 155 171 170 704 703 618 LHC 282 324 301 935 1,223 1,088 Hedcor Sibulan 108 N/A N/A 529 N/A N/A SNAP - Magat 673 1,150 1,036 7,804 3,971 4,604 SNAP - Benguet 265 413 208 2,828 1,063 885TLI (2) 3,540 767 N/A 22,426 2,801 N/ACEDC (3) 561 N/A N/A N/A N/A N/ASTEAG 1,553 1,384 1,330 6,577 6,206 6,265WMPC 498 220 107 1,319 1,207 1,284SPPC 315 226 164 707 688 691CPPC 246 318 296 2,043 2,119 2,367EAUC 224 202 202 1,741 1,382 1,579TMI (4) 767 N/A N/A 4,898 N/A N/ADavao Light (5) 41 7 6 Revenue

neutral Revenue

neutral Revenue

neutral Cotabato Light (5) 5 1 0 Revenue

neutral Revenue

neutral Revenue

neutral TOTAL 12,716 7,069 3,820 74,937 28,206 19,381

(1) The Tiwi-MakBan geothermal plants were turned over to APRI on May 26, 2009.

(2) TLI assumed dispatch control of the Pagbilao plant last October 1, 2009.

(3) The CEDC coal-fired power plant was completed as follows: Unit 1 in First quarter of 2010, Units 2 and 3 in second and fourth

quarters of 2010, respectively. In 2010, the plant was still being commissioned, thus at pre-operating stage. No revenues were

booked during the year. AboitizPower has an effective participation of 26% in the project.

(4) PB 118 and 117 were turned over to TMI last February 6, 2010 and March 1, 2010, respectively.

(5) Plants are operated as stand-by plants and are revenue neutral, with costs for operating each plant recovered by Davao Light

and Cotabato Light, as the case may be, as approved by the ERC.


Aboitiz Renewables, Inc. (ARI) AboitizPower, one of the leading providers of renewable energy in the country, holds all its investments in renewable energy through its wholly owned subsidiary, ARI. ARI owns equity interests in the following generation companies:

• 100% equity interest in APRI which owns the Tiwi-MakBan geothermal facilities. • 100% equity interest in Hedcor, Inc., which operates 15 mini-hydroelectric plants (plants

with less than 10 MW in installed capacity) in Benguet province in Northern Luzon and in Davao City in Southeastern Mindanao with a total installed capacity of 38.2 MW.

• 50% equity interest in LHC, which operates the 70 MW Bakun AC hydroelectric plant in Ilocos Sur province in northern Luzon.

• 50% effective interest in SNAP-Magat, which operates the 360 MW Magat hydroelectric plant in Isabela in northern Luzon.

• 50% effective interest in SNAP-Benguet, which operates the 175 MW Ambuklao-Binga Hydroelectric Power Plant Complex in Northern Luzon.

• 100% equity interest in Hedcor Sibulan, Inc. (Hedcor Sibulan), which owns the 42.5 MW Sibulan hydropower project in Santa Cruz, Davao del Sur.

• 100% equity interest in Hedcor Tamugan, Inc. (Hedcor Tamugan), which proposes to build a 11.5 MW Tamugan hydropower project along the Tamugan River in Davao City.

• 100% equity interest in Hedcor Tudaya, Inc. (Hedcor Tudaya), which proposes to build the 6.6 MW Tudaya 1 and 7 MW Tudaya 2 run-of-river hydropower projects in Santa Cruz, Davao Del Sur.

• 100% equity interest in Hedcor Sabangan, Inc. (Hedcor Sabangan), which proposes to build the 13.2 MW Sabangan run-of-river hydropower project in Sabangan, Mountain Province

Since beginning operations in 1998, the Company has been committed to developing expertise in renewable energy technologies. The Company’s management believes that due to growing concerns on the environmental impact of power generation using traditional fossil fuel energy sources, greater emphasis will be placed on providing adequate, reliable, and reasonably priced energy through innovative and renewable energy technologies such as hydroelectric and geothermal technologies. As such, a significant component of the Company’s future projects are expected to focus on those projects that management believes will allow the Company to leverage its experience in renewable energy and help maintain the Company’s position as a leader in the Philippine renewable energy industry. AP Renewables, Inc. (APRI) APRI is one of the country’s leading power generation companies. It is a wholly-owned subsidiary of ARI that acquired the Tiwi-MakBan geothermal facilities located at Tiwi, Albay, Bay and Calauan, Laguna and Sto. Tomas, Batangas from PSALM in May 2009. The two complexes have a total capacity of 485 MW. As geothermal power plants, Tiwi and Makban produce clean energy that is reasonable in cost, efficient in operation and environment-friendly. With the continuous advancement in technology, APRI is setting its vision to operate and maintain the Tiwi and Makban geothermal complexes in accordance with the highest professional standards of world-class independent power producers operating in a merchant market. The Asset Purchase Agreement (APA) between APRI and PSALM requires APRI to rehabilitate units 5 and 6 of the Makban Geothermal Power Plant at its own cost and expense, which must be accomplished and completed within four years from closing of the APA last May 2009. APRI is currently in the midst of rehabilitation and refurbishment process. Based on initial estimates, the rehabilitation and refurbishment


costs could reach USD140-150 mn over a period of two to three years. This rehabilitation and refurbishment plan is expected to improve the geothermal plant’s operating capacities. APRI is a Board of Investment (BOI) registered enterprise as New Operator of the Tiwi-Makban geothermal complex, on pioneer status with six years income tax holiday starting on June 19, 2009. SN Aboitiz Power-Magat Inc. (SNAP-Magat) SNAP-Magat is ARI’s joint venture company with SN Power, a leading Norwegian hydropower company with projects and operations in Asia, Africa and Latin America. On December 14, 2006, SNAP-Magat participated in and won the bid for the 360-MW Magat hydroelectric power plant (the Magat Plant) conducted by PSALM for a bid price of USD530 mn. The Magat Plant, which is located at the border of Isabela and Ifugao provinces in northern Luzon, was completed in 1983. As a hydroelectric facility that can be started up in a short period of time, the Magat Plant is ideally suited to act as a peaking plant with opportunities to capture the significant upside potential that can arise during periods of high demand. The Magat Plant has the ability to store water equivalent to one month of generating capacity, allowing for the generation and sale of electricity at the peak hours of the day, which command premium prices. Magat’s source of upside, water as a source of fuel and the ability to store it, is also its source of limited downside. This hydroelectric asset has minimal marginal costs, granting it competitive advantage in terms of economic dispatch order versus other fuel-fired power plants that have significant marginal cash costs. SNAP-Magat sells most of the electricity generated by the Magat Plant through the Wholesale Electricity Spot Market (WESM). It is also a provider of much needed ancillary services to the Luzon grid. SNAP-Magat obtained Board of Investments (BOI) approval of its application as new operator of the Magat plant with a pioneer status, which entitles it to an income tax holiday until July 12, 2013. A portion of the land underlying the Magat plant is in the name of the National Irrigation Administration (NIA). This portion is being leased by SNAP-Magat from NIA under terms and conditions provided under their O&M Agreement for the operations and maintenance of the non-power component of the Magat hydroelectric plant. On March 23, 2007, President Arroyo issued a presidential proclamation reserving and granting NPC ownership over certain parcels of public land in Isabela province and instructing the Department of Environment and Natural Resources to issue a special patent over the untitled public land on which a portion of the Magat plant is situated. This portion of land, which was titled in 2007, was eventually bought by SNAP-Magat. In September 2007, SNAP-Magat obtained a USD380 mn loan from a consortium of international and domestic financial institutions which include the International Finance Corporation, Nordic Investment Bank, BDO–EPCI, Inc., Bank of the Philippine Islands, China Banking Corporation, Development Bank of the Philippines, The Hong Kong and Shanghai Banking Corporation Limited, Philippine National Bank and Security Bank Corporation. The USD380-mn loan consists of a dollar tranche of up to USD152 mn, and a peso tranche of up to π10.1 bn. The financing agreement was hailed as the region’s first-ever project finance debt granted to a merchant power plant. It won Project Finance International’s Power Deal of the Year and Asset’s Best Project Finance Award as well as Best Privatization Award. The loan was used to partially finance the deferred balance of the purchase price of the Magat Plant under the Asset Purchase Agreement with PSALM. Part of the loan proceeds was also used to refinance SNAP-Magat’s USD159 mn loan from AEV and its advances from its shareholders used to acquire the Magat Plant.


As a hallmark of innovation in revenue generation, SNAP-Magat garnered an ancillary services contract on October 12, 2009 with the National Grid Corporation of the Philippines (NGCP), a first for a privately owned plant. These services are necessary to maintain power quality, reliability and security of the grid. After 25 years of operations without any major rehabilitation works done on the generating units and considering the age and results of technical assessments, SNAP-Magat has embarked on a four-year refurbishment program for all major plant equipment starting 2009 to 2013. The main objective is to put back the lost efficiency and address operational difficulties due to obsolescence. The project will preserve the remaining life and the continuance of its availability for the next 25 years. In December 2010, SNAP-Magat announced it will proceed with the feasibility study for the expansion of the Magat hydroelectric plant from 360 MW to up to 540 MW. The conduct of the feasibility study was formalized on December 15, 2010 upon the signing of a Memorandum of Understanding (MOU) between SNAP-Magat and the NIA. The MOU facilitates the gathering of information to determine the feasibility of expanding the capacity of the Magat plant for an additional 90 to 180 MW. The existing Magat plant was designed for two additional units. The study will also include the feasibility of installing a pumped-storage system. The result of the feasibility study will enable SNAP-Magat to evaluate whether to proceed with the construction phase of the project. SN Aboitiz-Benguet, Inc. (SNAP-Benguet) On November 28, 2007, SNAP-Benguet, also a consortium between ARI and SN Power, submitted the highest bid to PSALM for the Ambuklao-Binga Hydroelectric Power Complex, which consists of the 75-MW Ambuklao Hydroelectric Power Plant (Ambuklao Plant) located in Bokod, Benguet and the 100-MW Binga Hydroelectric Power Plant (Binga Plant) located in Itogon, Benguet. The price offered amounted to USD325 mn. The Ambuklao-Binga Hydroelectric Power Complex was turned over to SNAP-Benguet on July 10, 2008. In August 2008, SNAP-Benguet signed a USD375 mn loan agreement with a consortium of local and foreign banks where USD160 mn was taken up as U.S. dollar financing and USD215 mn as peso financing. Proceeds from the facility were used to partially finance the purchase price, rehabilitate the power plant complex and refinance SNAP-Benguet’s existing advances from shareholders with respect to the acquisition of the assets.

SNAP-Benguet obtained BOI approval of its application as new operator of the Ambuklao and Binga plants with a pioneer status, which entitles it to an income tax holiday commencing from date of registration. Binga’s approval is effective until August 12, 2014, while that of Ambuklao lasts until July 2016. Ambuklao Plant has been under preservation since 1999 due to damage from the 1990 earthquake. Rehabilitation of the Ambuklao Plant commenced in late 2008. The initial attempt to close the old headrace tunnel using concrete plug has proven difficult due to the unexpected volume of sediments (silt and clay) in the tunnel compounded by the effects of Typhoon Pepeng (international name: Parma) that hit the province in October 2009. Instead, SNAP-Benguet is now extending the new headrace tunnel and building new penstocks up to the main inlet valves to allow water to flow through to the new turbines; consequently, it has abandoned the old tunnel plugging solution. With the extension of the


new headrace tunnel and building of new penstocks, the first unit of Ambuklao plant is expected to be completed by second quarter of 2011 with all three units operational by third quarter of 2011, instead of end 2010 as earlier reported. The refurbishment of the Binga Plant commenced in 2010. Headrace tunnel and intake excavation is 80% completed. Construction of the new intake structure is on-going and target completion of the project is in 2014. The projects are expected to increase the capacity of the Ambuklao Plant to 105 MW and of the Binga Plant to 120 MW. In 2010, SNAP-Benguet also entered into a contract with the NGCP for the Binga plant to provide ancillary services. This hallmark of business innovation has resulted in a new stream of revenue for the company. Hedcor, Inc. (Hedcor) Hedcor was originally incorporated on October 10, 1986 by ACO as the Baguio-Benguet Power Development Corporation. ARI acquired its 100% ownership interest in Hedcor in 1998. In 2005, ARI consolidated all of its mini-hydroelectric generation assets, including those developed by HEDC and NORMIN, in Hedcor. Hedcor currently owns, operates and/or manages 15 run–of–river hydropower plants in northern Luzon and Davao City with a combined installed capacity of 38.2 MW. All the electricity generated from Hedcor’s hydro plants are taken up by NPC, APRI, Davao Light, and Benguet Electric Cooperative (BENECO) pursuant to power purchase agreements with the said offtakers. During the full years 2009 and 2010, Hedcor’s hydropower plants generated a total of 171.4 GWh and 155.5 GWh of electricity, respectively. Northern Luzon’s climate is classified as having two pronounced season--dry from November to April and wet for the rest of the year. Due to this classification, generation levels of Hedcor’s plants, particularly those located in northern Luzon, are typically lower during the first five months of each year. Hedcor used to have a 50% equity interest in LHC until it transferred its equity stake to its parent company, ARI, through a property dividend declaration in September 2007. Luzon Hydro Corporation (LHC) LHC is ARI’s joint venture company with Pacific Hydro Pty. Ltd. (Pacific Hydro) of Australia, a privately-owned Australian company that specializes in developing and operating power projects that use renewable energy sources, principally water and wind power. LHC operates and manages the 70 MW Bakun AC hydro project, which is located within the 13,213 hectare watershed area of the Bakun River in Ilocos Sur province in northern Luzon. The project is a run–of–river power plant which taps the flow of the Bakun River to provide the plant with its generating power. The USD150 mn project was constructed and is being operated under the government’s build–operate–transfer scheme. Energy produced by the plant is delivered and taken up by NPC pursuant to a power purchase agreement (the Bakun PPA) and dispersed to NPC’s Luzon Power Grid. Under the terms of the Bakun PPA, all of the electricity generated by the Bakun plant will be purchased by NPC for a period of 25 years from February 2001. The Bakun PPA also requires LHC to transfer the Bakun plant to NPC in February 2026, free from liens and without the payment of any compensation by NPC. Amlan Power Holdings Corporation was awarded the IPP Administrator contract for the 70-MW Bakun hydropower facility following a competitive bidding process conducted by PSALM.


On March 31, 2011, ARI, LHC and Pacific Hydro signed a Memorandum of Agreement (MOA) to give ARI full ownership over LHC. ARI will assume full ownership and control of LHC upon fulfillment of certain conditions in the MOA. The total transaction value is approximately USD30 mn. Hedcor Sibulan, Inc. (Hedcor Sibulan) Hedcor Sibulan, a wholly owned subsidiary of ARI, is the project company of the Sibulan hydropower project. Sibulan, which broke ground on June 25, 2007, entailed the construction of two run-of-river hydropower plants, Sibulan A and Sibulan B harnessing the Sibulan and Baroring rivers in Santa Cruz, Davao del Sur. The 26 MW Sibulan B started commercial operations in March 2010. The 16.5 MW Sibulan A was completed in July 2010. Hedcor Sibulan is part of a consortium that won the competitive bidding for the 12-year power supply agreement to supply new capacity to Davao Light. The bid price for the contracted energy was π4.0856/kWh, subject to adjustment based on changes to the Philippine consumer price index. All the energy generated by the Hedcor Sibulan power plants will be supplied to Davao Light pursuant to a power supply agreement signed on March 7, 2007. The Sibulan Project is registered as a clean development mechanism project with the United Nations Framework Convention on Climate Change under the Kyoto Protocol. This allows Hedcor Sibulan to sell the plants’ generated carbon credits. Hedcor Tamugan, Inc. (Hedcor Tamugan) Hedcor Tamugan, a wholly owned subsidiary of ARI, is the project company organized to build the proposed Tamugan run-of-river hydropower project. In 2010, Hedcor entered into a compromise agreement with the Davao City Water District (DCWD) as a settlement to the dispute in connection with the Tamugan water rights. Originally planned as a 27.5 MW run-of-river facility, Hedcor Tamugan proposed the the construction of 11.5 MW run-of-river hydropower plant. After Hedcor Tamugan secures all required permit, the two-year construction period will commence. Hedcor Sabangan, Inc. (Hedcor Sabangan) Hedcor Sabangan, a wholly owned subsidiary of ARI, is the project company organized to build the proposed 13.2 MW run-of-river hydropower project in Sabangan, Mountain Province. As part of the Free and Prior Informed Consent (FPIC) process for the project as required under the Indigenous Peoples’ Rights Act of 1997 (IPRA), Hedcor Sabangan signed Memoranda of Agreement with the indigenous peoples of Barangays Namatec and Napua and the municipality of Sabangan, Mountain Province in February and March 2011, respectively. With the completion of the FPIC process, Hedcor Sabangan is awaiting the issuance of the Certificate of Precondition by the National Commission on Indigenous Peoples. The other permits required for the project, such as the ECC and water rights, are currently being processed. The two-year construction period is expected to commence in the first quarter of 2012 assuming that the required permits are secured by then. Hedcor Tudaya, Inc. (Hedcor Tudaya) Hedcor Tudaya, a wholly owned subsidiary of ARI, is the project company organized to build the proposed 6.6 MW Tudaya 1 and 7 MW Tudaya 2 run-of-river hydropower projects in Tudaya, Santa Cruz, Davao del Sur. In February 2011, Hedcor Tudaya signed a Memorandum of Agreement with the of


Bagobo-Tagabawa indigenous peoples as a result of the FPIC process conducted for the Tudaya 1 as required under the IPRA. With the completion of the FPIC process, Hedcor Tudaya is awaiting the issuance of the Certificate of Precondition by the National Commission on Indigenous Peoples. The proposed construction of Tudaya 2 does not require a FPIC process as there are no indigenous peoples in the area. The other permits required for the project, such as ECC and water rights, are currently being processed. The two-year construction period is expected to commence in July 2011 assuming that the required permits are secured by then. Therma Power, Inc. (TPI) TPI, a wholly owned holding company of AboitizPower, owns equity interests in the following generation companies:

• 100% equity interest in TLI, the IPP Administrator of the 700 MW contracted capacity of

the Pagbilao power plant. • 100% equity interest in TMI, owner and operator of PB 117 and PB 118, barge-mounted

power plants, each with a generating capacity of 100 MW. • 26% effective interest in CEDC, which is currently constructing a 3x82 MW coal-fired

power plant in Toledo City, Cebu. • 50% equity interest in RP Energy, the project company that proposes to build and

operate a 300 MW coal-fired power plant in Redondo Peninsula in the Subic Bay Freeport Zone (SBFZ).

• 100% equity interest in Therma South, Inc., the project company that proposes to build a 300 MW circulating fluidized bed coal-fired plant in Toril, Davao.

AboitizPower is in the process of implementing a corporate reorganization that will put all its non-renewable generation assets under TPI. If completed, TPI will hold AboitizPower’s ownership interest in STEAG Power, EAUC, CPPC, Southern Philippines Power Corporation (SPPC) and Western Mindanao Power Corporation (WMPC). Therma Luzon, Inc. (TLI) TLI, a wholly owned subsidiary of AboitizPower, submitted the highest offer in the competitive bid conducted by PSALM for the appointment of the IPP Administrator of the 700 MW Contracted Capacity of the Pagbilao Coal Fired Thermal Power Plant located in Pagbilao, Quezon. The offer by TLI resulted in a bid price of USD691 mn as calculated in accordance with bid rules. This value represents the present value of a series of monthly payments to PSALM from October 2009 to August 2025 using PSALM discount rates. On October 1, 2009, TLI became the first IPP Administrator in the country when it assumed dispatch control of the said contracted capacity of the Pagbilao Plant. As IPP Administrator, TLI is responsible for procuring the fuel requirements of and selling the electricity generated by the Pagbilao Plant. The Pagbilao Plant is being operated by TEAM Energy under a build-operate-transfer scheme. Therma Marine, Inc. (TMI) TMI, a wholly owned subsidiary of AboitizPower, owns and operates PB 117 and 118, two power barges each with a generating capacity of 100 MW. TMI assumed ownership of PB 118 and 117 from PSALM last February 6, 2010 and March 1, 2010, respectively. The acquisition followed the successful conclusion of a


USD30 mn negotiated bid for the two power barges last July 31, 2009. PB 117 is moored in Bgy. San Roque, Maco, in Compostella Valley, while PB 118 is moored in Nasipit, Agusan del Norte. TMI signed Ancillary Services Procurement Agreements (ASPA) with the National Grid Corporation of the Philippines (NGCP) for a supply by each of PB 117 and 118 of 50 MW of ancillary services consisting of contingency reserve, dispatchable reserve, reactive power support and blackstart capacity for the Mindanao Grid. The ERC issued a provisional authority for the PB 118 ASPA on March 8, 2010 and made it retroactive to February 6, 2010 in consideration of the ongoing power crisis in Mindanao. PB 117 likewise got its provisional authority on March 24, 2010 with retroactive effect to March 1, 2010. On October 4, 2010, ERC issued its final approval on the ASPA application for both barges but with a 55% reduction in the capital recovery fee rates and also a reduction on the fuel consumption rates. A Motion for Reconsideration was filed by TMI and is still pending before the ERC. The ASPA between NGCP and TMI for the supply of 50 MW each of ancillary services by PB 117 and PB 118 with expiry dates of February 6, 2011 and March 1, 2011, respectively, were extended to June 25, 2011 for both barges under the same terms and conditions. STEAG State Power Inc. (STEAG) AboitizPower closed the sale and purchase of the 34% equity ownership in STEAG from Evonik Steag GmbH (Evonik Steag) last November 15, 2007 following a successful bid in August 2007. The total purchase price for the 34% equity in STEAG was USD102 mn, inclusive of interests. Incorporated on December 19, 1995, STEAG is the owner and operator of a 232 MW (gross) coal-fired power plant located in the PHIVIDEC Industrial Estate in Misamis Oriental, Northern Mindanao. The coal plant was built under a BOT arrangement and started commercial operations on November 15, 2006. The coal plant is subject of a 25-year power purchase agreement with the NPC, which agreement is backed by a Performance Undertaking issued by the Republic of the Philippines. STEAG currently enjoys a 6-year income tax holiday from the BOI. With its 34% stake in STEAG, AboitizPower is equity partner with majority stockholder Evonik Steag, Germany’s fifth largest power generator, which currently holds 51% equity in STEAG. La Filipina Uy Gongco Corporation holds the remaining 15% equity in STEAG. On June 28, 2010, AboitizPower and its partners in STEAG firmed up their collective intention to develop a third unit of approximately 150 MW capacity adjacent to the existing facility. AboitizPower and its partners agreed to maintain their shareholdings in the same proportions in the new corporation to be established for the planned additional capacity. Certain essential facilities, such as the jetty, coal handling facilities and stockyards and the 138-kV interconnection with the Mindanao Grid are to be shared with the existing facilities. Depending on the interest the market demonstrates, the agreement contemplates the possibility of another unit. East Asia Utilities Corporation (EAUC) On April 20, 2007, AboitizPower acquired a 50% ownership interest in EAUC from El Paso Philippines, which still owns the other 50% of EAUC. EAUC was incorporated on February 18, 1993 and since 1997 has operated a Bunker C-fired power plant with an installed capacity of 50 MW within the MEPZ I in Mactan Island, Cebu. Pursuant to the Power Supply and Purchase Agreement (PSPA), as amended, with the Philippine Economic Zone Authority (PEZA), PEZA shall be entitled to buy electric power from the spot


market, other electric power suppliers and/or generation companies in excess of the contracted demand of 42,500 kW that shall be sourced from EAUC solely or blended with other suppliers. The amended PSPA shall be effective up to April 25, 2011, with the option to renew under mutually acceptable conditions. EAUC and PEZA are currently negotiating for the renewal/extension of the PSPA. With the start of WESM operations in the Visayas Region, EAUC is also capable of selling power to the spot market. Cebu Private Power Corporation (CPPC) Incorporated on July 13, 1994, CPPC owns and operates a 70 MW Bunker-C fired power plant in Cebu City, one of the largest power plants in the island of Cebu. Commissioned in 1998, the CPPC plant was constructed pursuant to a BOT contract to supply 62 MW of power to VECO. The CPPC plant will revert to VECO in November 2013. On April 20, 2007, AboitizPower acquired from EAUC 60% of the outstanding common shares of CPPC. The remaining 40% of the outstanding common shares is owned by Vivant Energy Corporation of the Garcia family of Cebu, who together with AboitizPower, are the major shareholders of VECO. VECO owns all of the outstanding preferred shares of CPPC, which comprises approximately 20% of the total outstanding capital stock of CPPC. Cebu Private Power Corporation (CPPC)

Incorporated on July 13, 1994, CPPC owns and operates a 70 MW Bunker-C fired power plant in Cebu City, one of the largest power plants in the island of Cebu. Commissioned in 1998, the CPPC plant was constructed pursuant to a BOT contract to supply 62 MW of power to VECO. The CPPC plant will revert to VECO in November 2013. On April 20, 2007, AboitizPower acquired from EAUC 60% of the outstanding common shares of CPPC. The remaining 40% of the outstanding common shares is owned by Vivant Energy Corporation of the Garcia family of Cebu, who together with AboitizPower, are the major shareholders of VECO. VECO owns all of the outstanding preferred shares of CPPC, which comprises approximately 20% of the total outstanding capital stock of CPPC. Abovant Holdings, Inc. (Abovant) and Cebu Energy Development Corporation (CEDC)

Incorporated on November 28, 2007, Abovant is a joint venture company formed by TPI, a wholly-owned subsidiary of AboitizPower, and Vivant Integrated Generation Corporation (VIGC) of the Garcia Group, to hold their investments in a new power plant to be built in Barangay Daanlungsod, Toledo City, Cebu. Abovant is 60% owned by AboitizPower, through TPI, and 40% owned by VIGC. Abovant and Global Formosa Power Holdings, Inc., a joint venture between Global Business Power Corporation of the Metrobank Group and Formosa Heavy Industries, Inc. formed CEDC. CEDC is the owner of a new 3x82 MW coal-fired power plant in the existing Toledo Power Station complex in Barangay Daanlungsod, Toledo City, Cebu. With Abovant’s 44% stake in the project (Global Formosa owns the remaining 56%), AboitizPower’s effective interest in the new power plant, which broke ground in January 2008, is approximately 26.40%. The first 82 MW unit was commissioned in February 2010, while the second and third units in the second and fourth quarter of 2010, respectively. The power generated from the new power plant provides much needed security to the power supply of the province of Cebu in the coming years. Additional power will be needed with the influx of business process outsourcing companies and new hotels in the province and the presence in the Toledo-Balamban area of large industries such as Carmen Copper Corporation, the shipbuilding facility of Tsuneishi Heavy Industries (Cebu) Inc. (THI) and the modular fabrication facility of Metaphil International.


The power plant, which will cost approximately USD450 mn, is expected to be completed and will start full commercial operations by first quarter of 2011. CEDC had signed an Electric Power Purchase Agreement (EPPA) with VECO for the supply of 105 MW for 25 years. To date, it also has an EPPA with PEZA-MEPZ I; Mactan Electric Company, Inc. (MECO); BEZ; Cebu I Electric Cooperative, Inc.; Cebu II Electric Cooperative, Inc.; Cebu III Electric Cooperative, Inc.; and Bohol Electric I Cooperative, Inc. All its EPPAs will provide contracted minimum energy offtake with fuel as pass through. Southern Philippines Power Corporation (SPPC) SPPC is a joint venture among AboitizPower, Alsing Power Holdings, Inc. and Tomen Power (Singapore), Pte Ltd. AboitizPower has a 20% equity interest in SPPC, which owns and operates a 55 MW bunker-C fired power plant in Alabel, Sarangani just outside General Santos City in Southern Mindanao. The SPPC power plant was developed on a build-own-operate basis by SPPC under the terms of an Energy Conversion Agreement (ECA) with the NPC. Under the ECA, NPC is required to deliver and supply to SPPC the fuel necessary to operate the SPPC power plant during an 18-year cooperation period, which ends in 2016. NPC is also required to take all the electricity generated by the SPPC power plant during the cooperation period and pay SPPC on a monthly basis capital recovery, energy, fixed operations and maintenance (O&M) and infrastructure fees as specified in the ECA. During this cooperation period, SPPC is responsible, at its own cost, for the management, operation, maintenance and repair of the SPPC power plant. Aside from providing much needed capacity to the Southwestern Mindanao Area, the SPPC power plant also performs the role of voltage regulator for General Santos City, ensuring the availability, reliability, and quality of power supply in the area. Western Mindanao Power Corporation (WMPC) Like SPPC, WMPC is also a joint venture among AboitizPower, Alsing Power Holdings, Inc. and Tomen Power (Singapore), Pte Ltd. AboitizPower has a 20% equity interest in WMPC, which owns and operates a 100 MW bunker-C fired power station located in Zamboanga City, Zamboanga del Sur in Western Mindanao. The WMPC power plant was developed on a build-own-operate basis by WMPC under the terms of an ECA with NPC. Under the ECA, NPC is required to deliver and supply to WMPC the fuel necessary to operate the WMPC Plant during an 18-year cooperation period which ends in 2015. NPC is also required to take all the electricity generated by the WMPC Plant during the cooperation period and pay WMPC on a monthly basis capital recovery, energy, fixed O&M and infrastructure fees as specified in the ECA. During this cooperation period, WMPC is responsible, at its own cost, for the management, operation, maintenance and repair of the WMPC Plant. Aside from providing much needed capacity to the Zamboanga Peninsula, the WMPC power plant also performs the role of voltage regulator for Zamboanga City, ensuring the availability, reliability, and quality of power supply in the area.

Redondo Peninsula Energy, Inc. (RP Energy) Incorporated on May 30, 2007, RP Energy is a joint venture company owned equally by AboitizPower and Taiwan Cogeneration International Corporation. It is the project company that proposes to build and operate a 300-MW coal-fired power plant in Redondo Peninsula in the SBFZ with a planned phase two expansion for another 300 MW unit. In April 2008, RP Energy issued a letter of award to Formosa Heavy Industries for the supply of the boiler,


steam turbine, generator, and related services that will be used for the construction of the power plant. The award serves to fix the price and delivery time of the equipment amidst an environment of rising prices and longer delivery period of raw materials. The project is estimated to cost approximately USD500 mn. In view of increasing power demand in the Luzon Grid, RP Energy is re-evaluating the plant configuration of the plant from 2x150 MW units to a 1x300 MW unit. RP Energy has signed a Lease Development Agreement with SBMA and has paid its first five year lease for the site. It has secured an Environmental Clearance Certificate and its related amendments as well as the Special Land Use Permit from the DENR. RP Energy has also completed the relocation of all affected residents in the site in accordance with existing rules and regulations and is now the in the final stages of negotiations with a site development contractor for the site development works on site. Therma South, Inc. Therma South, Inc. is a wholly owned subsidiary of TPI and the project company for the proposed 300 MW circulating fluidized bed coal-fired plant in Toril, Davao. The project is in the planning and governmental approval stage and as such does not have any contracts to sell its power as of yet. If approved within the expected timeframe, the plant should be operational in early 2014. Other Generation Assets AboitizPower’s distribution utilities, Davao Light and Cotabato Light, each has its own stand-by plant. Davao Light currently maintains the 53 MW Bunker C-fired Bajada stand-by plant, which is capable of supplying 19% of Davao Light’s requirements. Cotabato Light maintains a stand-by 7 MW Bunker C-fired plant capable of supplying approximately 30.50% of its requirements. Future Projects Before undertaking a new power generation project, the Company conducts an assessment of the proposed project. Factors taken into consideration by the Company include the proposed project’s land use requirements, access to a power grid, fuel supply arrangements (if relevant), availability of water (for hydroelectric projects), local requirements for permits and licenses, the ability of the plant to generate electricity at a competitive cost and the presence of potential offtakers to purchase the electricity generated. For the development of a new power plant, the Company, its partners and suppliers are required to obtain the necessary permits required before commencement of commercial operations, including permits related to project site, construction, the environment and planning, operation licenses and similar approvals. Notwithstanding the review and evaluation process that the Company’s management conducts in relation to any proposed project, acquisition or business, there can be no assurance that the Company will eventually develop a particular project, acquire a particular generating facility or that projects will be implemented or acquisitions made or businesses conducted in the manner planned or at or below the cost estimated by the Company. In addition, there can be no assurance that a project, if implemented, or an acquisition, if undertaken, will be successful. DISTRIBUTION OF ELECTRICITY The Aboitiz Group has more than 70 years of experience in the Philippine power distribution sector and has been known for innovation and efficient operations. Through the years, AboitizPower has managed to build strong working relationship with the industry's regulatory agencies. With ownership interests in seven distribution utilities, AboitizPower is currently one of the largest electricity distributors in the Philippines. AboitizPower’s distribution utilities collectively supply


electricity to franchise areas covering a total of 18 cities and municipalities in Central Luzon, Visayas and Mindanao, with an aggregate land area of approximately 5,095 square kilometers. Collectively, AboitizPower’s distribution utilities contributed approximately 7% of its net income for 2010. The distribution utilities had a total customer base of 714,423 in 2010, 685,378 in 2009, and 658,318 in 2008. The table below summarizes the key operating statistics of the distribution utilities for 2010 and the previous two years.

Electricity Sold (MWh) Peak Demand (MW) No. of Customers Company 2010 2009 2008 2010 2009 2008 2010 2009 2008 VECO 1,994,237 1,829,500 1,766,059 378 336 326 316,845 304,002 296,003Davao Light

1,548,155 1,459,161 1,370,951 293 276 248 281,234 268,708 257,101

SFELAPCO 446,513 421,139 406,022 83 80 75 81,891 79,669 73,600Cotabato Light

129,788 120,186 118,450 24 24 23 31,611 30,171 28,927

SEZ 405,038 372,391 298,050 83 97 64 2,734 2,724 2,585MEZ 138,128 117,014 141,225 22 23 23 77 76 74BEZ 90,174 60,376 63,329 27 21 15 31 28 28

Total 4,752,033 4,379,768 4,164,086 910 857 774 714,423 685,378 658,318 Visayan Electric Company, Inc. (VECO) VECO is the second largest privately owned distribution utility in the Philippines in terms of customers and annual MWh sales. VECO supplies electricity to a region covering 672 square kilometers in the island of Cebu with a population of approximately 1.5 mn. Its franchise area includes the cities of Cebu, Mandaue, Talisay and Naga, and the municipalities of Minglanilla, San Fernando, Consolacion and Liloan. To date, VECO has 13 substations located in different areas around the cities of Cebu, Mandaue, Naga and the municipality of Consolacion. VECO, directly and through its predecessors-in-interest, has been in the business of distributing electricity in Cebu Island since 1905. In the early 1900s, the predecessors-in-interest of the Aboitiz Group acquired a 20% interest in VECO’s predecessor-in-interest, the Visayan Electric Company, S.A. Since that time, the Aboitiz Group’s ownership interest in VECO has increased from 20% to the current beneficial ownership interest of 55.19% held by AboitizPower. In 1928, Visayan Electric Company, S.A. was granted a 50-year distribution franchise by the Philippine Legislature. The term of this franchise was extended by Republic Act 6454 for an additional 25 years beginning in 1978 and was conditionally renewed for another 25 years from December 2003, subject to the resolution of an intra-corporate dispute at that time involving AEV, AboitizPower’s parent company, and Vivant Corporation. In September 2005, the Philippine Congress passed Republic Act 9339, which extended VECO’s franchise to September 2030. VECO’s application for the extension of its Certificate of Public Convenience and Necessity (CPCN) was approved by the ERC last January 26, 2009. In April 2004, AEV and Vivant, which is the holding company of the Garcia family, entered into a Shareholders’ Cooperation Agreement that sets out guidelines for VECO’s day-to-day operations and the relationship among VECO’s shareholders, including: restrictions on share transfers (including the grant of rights of first refusal in the event of a transfer to a third party and rights to transfer to affiliates, subject to certain conditions), board composition and structure, proceedings of directors and shareholders, minority shareholder rights, dividend policy, termination, and non-compete obligations. Under the terms of the agreement, day-to-day operations and management of VECO were initially assumed by AEV and, after AboitizPower acquired AEV’s ownership interest in VECO in January 2007, by


AboitizPower. AboitizPower and Vivant are each required to place in escrow 5% of the shares in VECO registered in their respective names to guarantee compliance with their respective obligations under the Shareholders’ Cooperation Agreement. The escrow shares will be forfeited in the event a shareholder group violates the terms of the Shareholders’ Cooperation Agreement. The Shareholders’ Cooperation Agreement was adopted as a result of a dispute between AEV and Vivant regarding the management of VECO. Relations between the shareholders of VECO are amicable. VECO is part of the third group (Group C) of private distribution utilities to shift to PBR. The ERC issued its final determination on VECO’s application for approval of its annual revenue requirements and performance incentive scheme under the PBR for the regulatory period July 1, 2010 to June 30, 2014. Such final determination became final in May 2010. Also in May 2010, VECO filed with the ERC its application for approval of the translation into distribution rates of its different customer classes for the first regulatory year of the ERC-approved Annual Revenue Requirement (ARR) under the PBR for the regulatory period July 1, 2010 to June 30, 2014. The application was approved on June 28, 2010 and the approved distribution, supply and metering charges were implemented by VECO effective August 1, 2010. Davao Light & Power Company, Inc. (Davao Light) Davao Light is the third largest privately-owned electric distribution utility in the country in terms of customers and annual kilowatt-hour (kWh) sales. With a franchise covering Davao City and Davao del Norte areas of Panabo City and the Municipalities of Carmen, Dujali and Santo Tomas, Davao Light services a population of approximately 1,777,926 and a total area of 3,561 square kilometers. Although Davao Light was organized on October 11, 1929, the Aboitiz Group acquired its ownership interest in the company in 1946. Currently, the AboitizPower owns 99.93% of the shares in Davao Light. Davao Light’s original franchise, which covered Davao City, was granted in November 1930 by the Philippine Legislature and was for a period of 50 years. In 1976, the National Electrification Administration (NEA) extended Davao Light’s franchise for Davao City to November 2005 and granted Davao Light franchises for the City of Panabo and the municipalities of Carmen and Santo Tomas in Davao del Norte province. In September 2000, the Philippine Congress passed Republic Act 8960, which granted Davao Light a franchise over its current franchise area for a period of 25 years, or until September 2025. Davao Light has a 150-MVA and a 2x50-MVA substation drawing power at 138 kV. In 1998 it entered into a 10-year power purchase agreement with NPC, which had been extended until 2015 by a separate contract signed in 2005 by the parties. Davao Light’s power purchase agreement with the NPC allows the delivery of most of Davao Light’s power requirements through Davao Light’s 138- kV lines. As a result, in taking delivery of electricity from NPC, Davao Light is able to bypass the NGCP connection assets and avoid having to pay corresponding wheeling fees to NGCP, thereby allowing Davao Light to cut its operating costs. In February 2007, Davao Light awarded to the Hedcor Consortium (composed of Hedcor, ARI, Hedcor Sibulan, and Hedcor Tamugan) a 12-year supply contract of new capacity. The price differential between the Hedcor Consortium’s winning bid price of π4.0856 per kWh and the next lowest bid was approximately π1.0129 per kWh. Over the life of the supply contract, the differential will amount to approximately π4.9 bn at current peso value, representing significant savings for Davao Light customers. Davao Light decided to secure the new supply contract in anticipation of the full utilization of the existing contracted energy supply under the 10-year contract with the NPC for 1,363,375 MWH and the


12-year contract with Hedcor. In 2010, amidst the power crisis in Mindanao during the first semester, Davao Light’s franchise area was spared of the long daily rotating brownouts of up to 8 to 12 hours experienced in other areas. The shorter service interruptions of up to a maximum of three hours were attributed to Davao Light’s implementation of its contingency plans which include operation of its 54.8-MW Bunker C-fired standby plant or an average of 40 MW on a sustaining basis. The standby plant is capable of supplying 19% of Davao Light’s electricity requirement. The power from Hedcor Sibulan’s 42.5 MW and Hedcor, Inc.’s Mintal 4 MW hydroelectric plants likewise augmented power supply in the Davao Light franchise area. The Bunker C-fired plant and the Sibulan and Mintal hydroelectric plants are embedded in the Davao Light franchise. Thus, the power generated from these facilities are dispatched directly into the Davao Light distribution network without passing through the NGCP transmission lines. To further alleviate the impact of the brownouts on small consumers, Davao Light instituted the Interruptible Load Program (ILP) with the cooperation of its large industrial customers. These customers volunteered either to run their own generators or shutdown their operation during power shortage so that the available power can be made available to small customers. Despite the load curtailment issued by NGCP during the power crisis, Davao Light registered 1.548 bn kWh sales, representing 6.10% growth versus 2009. All sectors of customers, residential, commercial and industrial posted rise in sales revenues, with the bulk coming from the banana, manufacturing and refrigeration businesses in the industrial sector. Influx of other medium business ventures such as retail shopping centers, beverage and cold storage gave a boost in the commercial electricity sales. Peak demand hit 291 MW for a 5.41% increase versus last year. New service connections grew by 4.66% increasing the number of customers to 281,234 by year-end. Fast development of new subdivisions and condominiums drove an upscale of 5% in residential consumers. As required by EPIRA, Davao Light filed with the ERC its distribution wheeling rates in order to enter into the PBR rate methodology. Based on Davao Light’s approved annual revenue requirements for the regulatory period July 1, 2010 to June 30, 2014, the ERC adjusted its average distribution related charges by π0.08 from π1.08 per kWhr to π1.16 for the first year. Davao Light operates its distribution system at a systems loss level lower than the government mandated 8.50% cap set for private distribution utilities. From 7.94% in 2009 the company further reduced its systems loss figure by 0.53% to 7.41% by the end of December 2010. Constantly innovating on services to add convenience to paying customers, Davao Light’s partnership with the country’s top payment service providers, EC Pay and CIS Bayad Center, added a combined 99 payment centers. Aside from payment centers in its own offices, Davao Light also engages the services of third party collection agents, such as mall payment centers, authorized banks and convenience stores. Customers now have 129 different payment venues to choose from, 61 of which are convenience stores that have been commissioned to receive bill payments 24/7.


To improve service reliability, a total of 19 circuit kilometers of 69 kV Sub-transmission and 13.8 kV were upgraded. Ten 138 kV transmission line structures were also converted from wood to steel. In order to maintain the standby Bunker C-fired plant’s dependability, four of its machines with a total generating capability of 20 MW were overhauled. On substation operations, comprehensive maintenance and servicing on five distribution facilities were undertaken. At the same time 3 control rooms were completed. Following VECO, Davao Light rolled out Project Pearl, the project name for the Customer Care and Billing (CC & B) system developed by Oracle being implemented among AboitizPower’s distribution utilities. The π100 mn CC&B is an integrated customer care software that will replace the various in–house developed systems currently used. Cotabato Light & Power Company (Cotabato Light) Cotabato Light supplies electricity to Cotabato City and portions of the municipalities of Datu Odin Sinsuat and Sultan Kudarat, both in Maguindanao province in Mindanao. Its franchise area covers approximately 191 square kilometers and has a population of approximately 350,692. In 2010, it has a manpower complement of 74 full-time employees and a number of contractual employees serving a customer base of 31,611, composed of residential, commercial, industrial and flat rate customers. Cotabato Light was formally incorporated in April 1938. Its original 25-year franchise was granted in June 1939 by the Philippine Legislature. In 1961, the Philippine Congress passed Republic Act 3217 which was further amended by Republic Act 3341 extending Cotabato Light’s franchise until June 1989. In August 1989, NEA extended Cotabato Light’s franchise for another 25 years, which will expire in August 2014. AboitizPower owns 99.93% of Cotabato Light. As of 2010, Cotabato Light has three substations of 10 MVA, 12 MVA and 15 MVA and is served by two 69-kV transmission lines, which provide redundancy in case one transmission line fails. Cotabato Light’s distribution voltage is 13.8 kV. To further boost its systems’ reliability and efficiency, the construction of the new Malagapas 10 MVA Substation is ongoing and is expected to be operational by May 2011. Cotabato Light maintains a standby 7-MW Bunker C-fired plant capable of supplying approximately 30.50% of its franchise area requirements. The existence of a standby power plant, which is capable of supplying electricity in cases of supply problems with NPC and for the stability of voltage whenever necessary, is another benefit to Cotabato Light’s customers. During the recent Mindanao power crisis, Cotabato Light’s franchise area experienced one of the lowest rotating power outages due to its back-up power plant. In 2010 Cotabato Light posted a modest kWh growth of 7.99% compared to 2009 basically because of increase in number of residential customers and increase of industrial consumptions. Although a relatively small utility, Cotabato Light’s corporate relationship with its affiliate, Davao Light, allows the former to immediately implement benefits from the latter’s system developments. Keeping pace with world class standards, Cotabato Light adopted a new computerized accounting system called ERP from Oracle. Also, it is now in the process of implementing the Oracle’s CC& B system, which is the standard billing, collection and customer service related systems utilized by other distribution utilities of AboitizPower. The CC & B system is expected to be onstream by mid-2011.


Managing its systems loss is a challenge for Cotabato Light. With system losses capped by ERC at 8.50%, Cotabato Light aims to lower systems losses through various measures most of which are aimed to address pilferage, the primary cause of its higher-than-cap systems losses. The implementation of Meter on Post (MOP) or Elevated Metering System project contributed much to the reduction of its systems loss to 9.10% in December 2010 from as high as 10.80% at the start of the year. This project will continue to be implemented in 2011 to further reduce the systems loss to 8.50%. The ERC issued its final determination on Cotabato Light’s application for approval of its Annual Revenue Requirement and performance incentive scheme under the PBR scheme covering a 4-year regulatory period which commenced on April 1, 2009 until March 30, 2013. On April 15, 2009, the ERC approved Cotabato Light’s application for translation of its approved Annual Revenue Requirement for the first regulatory year into applicable rates per customer class. Cotabato Light implemented the approved rates last May 1, 2009 – a month after the start of the first regulatory year. The resulting under recovery from the one-month lag was reflected and recovered in the next regulatory year’s rate translation application which was approved by ERC on February 22, 2010. The resulting new rates were implemented in April 2010. Cotabato Light filed on December 15, 2010 the third regulatory year MAP recalculation and rate translation to be implemented from April 2011 to March 2012. ERC is scheduled to release its decision on the third regulatory year rates before the end of March 2011. San Fernando Electric Light and Power Company, Inc. (SFELAPCO) SFELAPCO supplies electricity to approximately 32 barangays in San Fernando City, 29 barangays in the municipality of Floridablanca, five barangays in the municipality of Bacolor and two barangays in the municipality of Guagua, a portion of Lubao and Santo Tomas, all located within Pampanga province in Central Luzon. Its franchise area covers 204 square kilometers and has a population of approximately 372,753. SFELAPCO was incorporated on May 17, 1927. In 1961, the Philippine Congress passed Republic Act 3207, which granted SFELAPCO a franchise to distribute electricity for a period of 50 years or until June 2011 within the franchise area described above. Republic Act 9967 extending SFELAPCO’s franchise for another 25 years from the date of its approval lapsed into law last February 6, 2010. On November 11, 2009, SFELAPCO signed a Power Supply Agreement (PSA) with APRI. Under the PSA, APRI will supply the additional energy required by SFELAPCO that cannot be supplied by NPC from December 25, 2009 to September 25, 2010. Thereafter, APRI will then become the sole provider of power to SFELAPCO until December 25, 2012. SFELAPCO is part of the fourth batch of private utilities to enter PBR, and is expected to enter its four-year regulatory period by October 1, 2011. AboitizPower has an effective interest of 43.78% in SFELAPCO. Subic Enerzone Corporation (SEZ) In May 2003, the consortium of AEV and Davao Light won the competitive bid to provide distribution


management services to the SBMA and to operate the SBFZ power distribution system for a period of 25 years. On June 3, 2003, SEZ was incorporated as a joint venture company owned by a consortium comprised of Davao Light, AEV, SFELAPCO, Team Philippines, Okeelanta and PASUDECO to undertake the management and operation of the SBFZ power distribution system. SEZ was formally awarded the contract to manage the SBFZ’s power distribution system on October 25, 2003 and officially took over the operations of the power distribution system on the same day. SEZ’s authority to operate the SBFZ power distribution system was granted by the SBMA pursuant to the terms of Republic Act 7227 (The Bases Conversion and Development Act of 1992), as amended. As a company operating within the SBFZ, SEZ is not required to pay the regular corporate income tax of 30% and instead pays a preferential tax of 5% on its gross income in lieu of all national and local taxes. Following the acquisition of AboitizPower in January 2007 of the 64.30% effective ownership interest of AEV in SEZ, AboitizPower entered into another agreement on June 8, 2007 to acquire the combined 25% equity stake in SEZ of AEV, SFELAPCO, Okeelanta, and PASUDECO. On December 17, 2007, AboitizPower bought the 20% equity of Team Philippines in SEZ for π92 mn. Together with the 35% equity in SEZ of AboitizPower’s subsidiary Davao Light, this acquisition brought AboitizPower's total equity in SEZ to 100%. In September 2008, SEZ acquired the 100-MVA Subic Substation from the NGCP. The substation has a 230/69/13.8kV power transformer supplying power to the Subic Bay Industrial Park, Binictican and Kalayaan housing areas, Cubi, Naval Magazine, and Grande Island in the SBFZ. In November 2008, SEZ implemented a rate increase as per approved unbundled rates. In 2010, SEZ acquired more advanced equipment to further enhance the company’s service to its customers. In January, the company purchased a Meter Test Equipment (MTE) 5-Position Test Bench from Germany to improve its meter calibration services. As a result, meter calibration improved from 25 meters to 130 meters a day. In July 2010, SEZ procured a Megger Fault Locator for underground power cable trouble-shooting. With this new equipment, SEZ can determine electrical underground faults more quickly, thus reducing power outage time. SEZ is part of the fourth batch of private utilities to enter PBR. The ERC is expected to release by the end of June 2011 its final determination on SEZ’s application for approval of its MAP, annual revenue requirements, and performance incentive scheme for the period covering October 2011 to September 2015. The approved MAP will then be translated into new per customer class rates and will be implemented starting October 2011. Mactan Enerzone Corporation (MEZ) MEZ was incorporated in January 2007 when AboitizLand spun off the power distribution system of its MEPZ II project. The MEPZ II project, which was launched in 1995, is operated by AboitizLand under a BOT agreement entered into with the Mactan-Cebu International Airport Authority (MCIAA). On June 8, 2007, AboitizPower entered into an agreement to acquire AboitizLand’s 100% equity stake in MEZ represented by 8,754,443 common shares of MEZ. Pursuant to the agreement, AboitizPower acquired AboitizLand’s ownership interest in MEZ valued at π609.5 mn in exchange for AP’s common shares issued at the initial public offering price of π5.80 per share. MEZ sources its power from NPC pursuant to a Contract to Supply Electric Energy. Under the supply


contract, NPC is required to provide power to MEZ up to the amount of contracted load, which is based on the projections provided by MEPZ II locators under their respective Power Service Contracts with MEZ. In 2010, MEZ mounted two sets of Automatic Voltage Regulator (AVR) to its old substation to improve voltage levels to locators. To further provide world-class customer service, MEZ constructed their main administration office within the zone where they operate, MEPZ II. The MEZ control room was also renovated and expanded to improve the efficiency of operation. To avail of the opportunities in the competitive electricity market, MEZ decided to register as a direct participant of the Wholesale Electricity Spot Market (WESM) during the end of 2010. For the 2011 operating period, MEZ plans to transfer its NGCP metering to its substation in order to minimize line losses and further improve the voltage quality by the addition of two more sets of AVR. Balamban Enerzone Corporation (BEZ) BEZ was incorporated in January 2007 when CIPDI, a joint venture between AboitizLand and Tsuneishi Holdings (Cebu), Inc., spun off the power distribution system of the WCIP-SEZ. WCIP-SEZ is a special economic zone for light and heavy industries owned and operated by CIPDI. The park, which is located in Balamban, Cebu, is home to the shipbuilding and ship repair facilities of THI as well as the modular fabrication facility of Metaphil International. On May 4, 2007, CIPDI declared property dividend to its stockholders in the form of its equity in BEZ. On June 8, 2007, AboitizPower entered into an agreement to acquire AboitizLand’s 60% equity stake in BEZ represented by 4,301,766 common shares of BEZ. Pursuant to the agreement, AboitizPower acquired AboitizLand’s ownership interest in BEZ valued at π266.9 mn in exchange for AboitizPower’s common shares issued at the initial public offering price of π5.80 per share. On March 7, 2008, AboitizPower purchased Tsuneishi Holdings’ 40% equity in BEZ for approximately π178 mn. The acquisition brought AboitizPower’s total equity in BEZ to 100%. During the early months of 2010, BEZ completed the construction of the 33 MVA on-load tap changer substation, including the control room with 15 kV metal-clad switchgear, as well as the two-kilometer 69 kV line from Arpili to Buanoy substations. BEZ also erected their fast and slow moving warehouses within their Buanoy and Arpili Substations respectively. Supervisory Control and Data Acquisition (SCADA) will be implemented starting first quarter of 2011 to raise the quality of operation in BEZ’s Arpili and Buanoy substations. To ensure continuous supply of power, BEZ decided to register as a direct participant of WESM during the end of 2010. RETAIL ELECTRICITY AND OTHER RELATED SERVICES One of the objectives of electricity reform in the Philippines is to ensure the competitive supply of electricity at the retail level. In particular, when Open Access and Retail Competition under the Rules and Regulations to Implement the EPIRA is fully implemented, large-scale customers will be allowed to obtain electricity from Retail Electricity Suppliers (RES) licensed by the ERC.


Aboitiz Energy Solutions, Inc. (AESI) AESI, a wholly owned subsidiary of AboitizPower, holds a license to act as a RES (issued on November 9, 2009) and a license to act as a Wholesale Aggregator (issued on January 26, 2007). AESI intends to take advantage of its affiliation with the Aboitiz Group in marketing its power to Open Access customers. AESI also provides a range of value added technical services to the various customers of the AboitizPower generation group, including power quality analysis, thermal scanning and power factor evaluation and correction. These technical services allow power supply customers to properly assess their power consumption profile leading to a more efficient power consumption management. Aside from providing technical assistance in power quality analysis, AESI is also involved in project management services for transmission lines and substations. These products - from power supply to technical support - allow AESI to provide a one stop shop convenience to AboitizPower customers for all their power requirements. As the era of Open Access begins, these same services currently enjoyed by existing AboitizPower generation customers, from distribution utilities to large manufacturing firms, will be made available by AESI to new retail supply customers. This will positively impact the efficiency and use of power in these industrial and residential customers in the years ahead. (ii) Sales Comparative amounts1 of revenue, profitability and identifiable assets are as follows:

2010 2009 2008 Gross Income 59,551 23,174 12,243 Operating Income 26,232 5,456 1,653 Total Assets 134,557 111,341 47,272

Note: Operating Income is operating revenue net of operating expenses.

The operations of AboitizPower and its subsidiaries and affiliates are based only in the Philippines. Comparative amounts2

of revenue contribution by business grouping are as follows:

Business Segment

2010 2009

2008 As restated

Power Generation 46,982 78% 12,466 53% 2,985 24% Power Distribution 13,065 22% 10,734 46% 9,228 73% Services 465 0% 296 1% 328 3% Total Revenue 23,496 100% 23,496 100% 12,541 100% Less: Eliminations (961) (322) (298) Net Revenue 59,551 23,174 12,243

Note: Percentages refer to the business group’s share in total revenue for a given year.

(iii) Distribution Methods of Products or Services The Generation Companies sell their electricity either through the WESM or through bilateral power supply agreements with NPC, private distribution utilities or other large end-users. 1 Amount in millions. 2 Id.


Currently, SNAP-Magat and SNAP-Benguet have ASPAs with NGCP as ancillary service providers to the Luzon Grid. As ancillary service providers, SNAP-Magat and SNAP-Benguet nominate their available capacity for ancillary service to NGCP (System Operator). If NGCP accepts the nominated ancillary capacity, it will then provide a notice of ancillary service schedule to SNAP-Magat and SNAP-Benguet. TMI also has an ASPA with NGCP for a supply by each of PB 117 and 118 of 50 MW of ancillary services consisting of contingency reserve, dispatchable reserve, reactive power support and blackstart capacity for the Mindanao Grid. Majority of AboitizPower’s Generation Companies have transmission service agreements with NGCP for the transmission of electricity to the designated delivery points of their customers, while others built their own transmission lines to directly connect to their customers. In some instances, where the offtaker is NPC, NPC takes delivery of the electricity from the generation facility itself. On the other hand, AboitizPower’s Distribution Utilities have exclusive distribution franchises in the areas where they operate. These utilities own distribution lines with voltage levels ranging from 220 volts to 23 kV and 69 kV backbone and sub-transmission lines. VECO also owns a 138 kV tie line embedding CEDC to its system. These lines distribute electricity to the distribution utilities’ customers in their respective franchise areas. All customers that connect to these distribution lines are required to pay a tariff for using the system. Each of the Distribution Companies has a distribution network consisting of a widespread network of predominantly overhead lines and substations. Customers are classified in different voltage levels based on their electricity consumption and demand. Large industrial and commercial consumers receive electricity at distribution voltages of 13.8 kV to 23 kV while smaller industrial, commercial and residential customers receive electricity at 240 V or 480 V. All of AboitizPower’s Distribution Utilities have entered into transmission service contracts with NGCP for the use of NGCP’s transmission facilities in the distribution of electric power from the Grid to their respective customers. (iv) New Products/Services Other than the ongoing Greenfield and/or rehabilitation projects undertaken by AboitizPower’s Generation Companies, AboitizPower and its subsidiaries do not have any publicly announced new product or service to date. (v) Competition Generation Business With the privatization of NPC-owned power generation facilities and the establishment of WESM, AboitizPower’s generation facilities located in Luzon, the Visayas and Mindanao will face competition from other power generation plants that supply electricity to the Luzon, Visayas and Mindanao Grids. In particular, SNAP-Magat, SNAP-Benguet, APRI and TLI are expected to face competition from leading multinationals such as Marubeni Corporation and Korea Electric Power Corporation, as well as Filipino-owned IPPs such as First Gen Corporation, DMCI Holdings, Inc. and San Miguel Energy Corporation. AboitizPower will face competition in both the development of new power generation facilities and the acquisition of existing power plants, as well as competition for financing these activities. Factors such as the performance of the Philippine economy and the potential for a shortfall in the Philippines’ energy supply have attracted many potential competitors, including multinational development groups and


equipment suppliers, to explore opportunities in the development of electric power generation projects in the Philippines. Accordingly, competition for and from new power projects may increase in line with the expected long-term economic growth of the Philippines. Distribution Business Each of AboitizPower’s Distribution Utilities currently has an exclusive franchise to distribute electricity in the areas covered by each franchise. Under Philippine law, the franchises of the distribution utilities may be renewed by the Congress of the Philippines, provided that certain requirements related to the rendering of public services are met. The Company intends to apply for the extension of each franchise upon its expiration. The Company may face competition or opposition from third parties in connection with the renewal of these franchises. It should be noted that under Philippine law, a party wishing to secure a franchise to distribute electricity must first obtain a Certificate of Public Convenience and Necessity from the ERC, which requires that such party prove that it has the technical and financial competence to operate a distribution franchise, as well as the need for such franchise. Ultimately, the Philippine Congress has absolute discretion over whether to issue new franchises or to renew existing franchises, and the acquisition by competitors of any of the Distribution Utilities’ franchises could adversely affect the Company’s results of operations. (vi) Sources of Raw Materials and Supplies Generation Business AboitizPower’s hydroelectric facilities utilize water from rivers located near the facilities to generate electricity. The hydroelectric companies, on their own or through NPC in the case of LHC, possess water permits issued by the National Water Resources Board (NWRB), which allow them to use a certain volume of water from the applicable source of the water flow. Under the APA between APRI and PSALM for the Tiwi-MakBan geothermal complex, the management and operation of the steam fields which supply steam to Tiwi-MakBan remains with Chevron Geothermal Philippines Holdings, Inc. (Chevron). The steam supply arrangement between APRI and Chevron is currently governed by a Transition Agreement which provides for the reimbursement of capital expenditures and operating expenses, as well as payment of service fees, by APRI to Chevron. The Transition Agreement is to be effective no more than four years from the date of the turnover of Tiwi-MakBan to APRI and will be replaced by a Geothermal Resource Service Contract (GRSC) when Chevron becomes a Philippine corporation and after the rehabilitation of MakBan units 5 and 6. Under the GRSC, APRI will no longer pay service fees or reimburse Chevron for capital expenditures and operating expenses. Instead, the price of steam shall be linked to the Barlow Jonker and Japanese Public Utilities (JPU) coal price indices. As a result, the steam cost structure under GRSC will shift from a largely fixed to a full variable cost. AboitizPower’s oil-fired plants use Bunker C fuel to generate electricity. EAUC and CPPC each have a fuel supply agreement with Petron, while SPPC and WMPC get fuel supplies from NPC pursuant to their respective ECAs with NPC. TMI has existing fuel supply agreements with Shell and Petron for PB 117 and 118, respectively, which peg fuel prices based on Mean of Platts Singapore (MOPS). STEAG has existing long-term coal supply agreements with PT. Jorong Barutama Greston of Indonesia and Samtan Co. Ltd of Korea. TLI has entered into long-term coal supply contracts for the Pagbilao plant’s annual coal requirements. With the tight coal supply situation in the market as a result of weather disturbances in coal producing


countries, TLI is looking at and evaluating alternative sources other than Indonesia to ensure security of supply. Distribution Business The bulk of volume of electricity the Distribution Utilities sell is purchased from NPC, rather than from the Generation Companies. The following Distribution Utilities purchase electricity from the Generation Companies: Davao Light from Hedcor, SFELAPCO from APRI and VECO from CPPC and CEDC. Most of AboitizPower’s Distribution Utilities have bilateral agreements in place with NPC for the purchase of electricity, which set the rates for the purchase of NPC’s electricity. The following table sets out material terms of each Distribution Company’s bilateral agreements with NPC:

Distribution Company

Term of Agreement with NPC

Contract Energy (MWh per year)

Take or Pay Pricing Formula

VECO NPC - (extended) expiring in December 25, 2011

870,481 Yes ERC approved NPC rate + ERC approved adjustments

Davao Light NPC- 10 years; expiring in December 2015

1,238,475 Yes ERC approved NPC rate + ERC approved adjustments

Cotabato Light NPC - 10 years; expiring in December 2015


MEZ NPC - 10 years; expiring in September 2015


SEZ Three years; expiring in March 2011

90,000 Yes Average generation rate π3.4742/kWh and Franchise and Benefit Tax π0.0245

The rates at which Davao Light and SFELAPCO purchase electricity from AboitizPower’s Generation Companies are established pursuant to the bilateral agreements that are executed after the relevant Generation Company has successfully bid for the right to enter into a PPA with either Davao Light or SFELAPCO. These agreements are entered into on an arm’s-length basis and on commercially reasonable terms and must be reviewed and approved by the ERC. In addition, ERC regulations currently restrict AboitizPower’s Distribution Utilities from purchasing more than 50% of their electricity requirements from affiliated Generation Companies. Hedcor Sibulan supplies Davao Light with electricity generated from its Sibulan plants pursuant to the Hedcor Consortium’s 12-year power supply agreement to supply new capacity to Davao Light. VECO has PPAs pursuant to which it purchases a minimum of 18,000,000 kWh per month on a take-or-pay basis from Toledo Power Corporation, and approximately 61.72 MW of dispatchable capacity from CPPC (with no minimum energy off-take requirement). In September 2009, VECO entered into an Electric Power Purchase Agreement (EPPA) with CEDC for the supply of 105 MW for 25 years to address VECO’s long-term power supply requirement. Meanwhile, to mitigate the power supply shortage in 2010, VECO’s largest customer, CEMEX Philippines, agreed to supply 10 MW to VECO during peak hours for one year. CEMEX's last delivery of power to VECO was on November 2010. The provisions of the Distribution Utilities’ PPAs are governed by ERC regulations. The main provisions of each contract relate to the amount of electricity purchased, the price, including adjustments for various factors such as inflation indexes, and the duration of the contract. Under current ERC regulations, the Distribution Utilities can purchase up to 90% of their electricity requirements using bilateral contracts. Meanwhile, Davao Light and Cotabato Light each has its own stand-by plant. Davao Light currently maintains the 53 MW Bunker C-fired Bajada stand-by plant which is capable of supplying 19% of Davao Light’s requirements. Cotabato Light maintains a stand-by 7 MW Bunker C-fired power plant capable of


supplying approximately 30.50% of its requirements. Transmission Charges Each of the Distribution Utilities has entered into a transmission service contract with NGCP for the use of NGCP’s transmission facilities in the distribution of electric power from the Grid to its customers. The Distribution Utilities have negotiated agreements with NGCP in connection with the amount and form of security deposit to be provided by the Distribution Utilities to NGCP to secure their obligations under their transmission services contracts. (vii) Major Customers Close to 76% of the total electricity generated by the Generation Companies are either sold to private Distribution Utilities pursuant to long-term bilateral agreements or delivered to the NPC pursuant to long-term bilateral power supply agreements. The bilateral agreements with NPC are supported by NPC’s credit, which in turn is backed by the Philippine government. The remaining 24% of the total electricity generated by AboitizPower’s Generation Companies is sold through the Wholesale Electricity Spot Market (WESM). Most of AboitizPower’s Distribution Companies, on the other hand, have wide and diverse customer bases. As such, the loss of any one customer will have no material adverse impact on AboitizPower. The Distribution Companies’ customers are categorized into four principal categories:

(a) Industrial customers. Industrial customers generally consist of large-scale consumers of electricity within a franchise area, such as factories, plantations and shopping malls.

(b) Residential customers. Residential customers are those who are supplied electricity for use in a

structure utilized for residential purposes.

(c) Commercial customers. Commercial customers include service-oriented businesses, universities and hospitals.

(d) Other customers. Other customers include public and municipal services such as street lighting.

(viii) Transactions With and/or Dependence on Related Parties AboitizPower and its subsidiaries (the Group) enter into transactions with its parent, associates and other related parties, principally consisting of:

(a) Up until December 31, 2008, the Group had service contracts with ACO for corporate center services rendered, such as human resources, internal audit, legal, treasury and corporate finance, among others. With the transfer of all ACO employees to AEV in January 2009, AEV is now providing these same services and shares with the member companies the business expertise of its highly qualified professionals. Transactions are priced on a cost recovery basis, and billed costs are always benchmarked on third party rates to ensure competitive pricing. Service Level Agreements are in place to ensure quality of service. This arrangement enables the Group to maximize efficiencies and realize cost synergies. Management, professional, legal and other service fees paid by the Group to AEV and ACO amounted to P293.70 mn in 2010, P409.40 mn in 2009, and P362.60 mn in 2008, respectively.


(b) Management and other service contracts of certain subsidiaries with ACO at fees based on agreed rates. Management and other service fees paid by the Group to ACO amounted to nil in 2010 and 2009 and P40.70 mn in 2008.

(c) The Company also obtained standby letters of credit (SBLC) and is acting as surety for the

benefit of certain subsidiaries and associates in connection with loans and credit accommodations. The Company provided SBLC for STEAG Power, LHC, SNAP-Magat and SNAP-Benguet in the amount of P1.70 bn in 2010 and P1.80 bn in 2009 and 2008.

(d) Energy fees billed by Hedcor to SFELAPCO amounted to nil in 2010, P19.60 mn in 2009 and

P17.30 mn in 2008.

(e) Energy fees billed by CPPC to VECO amounted to P2.04 bn in 2010, P2.10 bn in 2009 and P2.35 bn in 2008.

(f) Energy fees billed by TLI to SNAP-Magat in 2010 amounted to P22.10 mn.

(g) Energy fees billed by TMI to Pilmico Foods Corporation (Pilmico) in 2010 amounted to P47.40

mn. Pilmico is a wholly owned subsidiary of AEV.

(h) Energy fees billed by BEZ to affiliates (ACO subsidiaries and associates) amounted to P521.90 mn in 2010 P287.70 mn in 2009 and P181.50 mn in 2008.

(i) Aviation services rendered by AEV Aviation to the Group. Total expenses from associate

amounted to P32.70 mn in 2010, P24.80 mn in 2009 and P19.90 mn in 2008. AEV Aviation is a wholly owned subsidiary of AEV.

(j) Lease of commercial office units by the Group from Cebu Praedia Development Corporation

(CPDC) for a period of three years. Rental expense amounted to P69.40 mn in 2010, P48.20 mn in 2009 and P32.20 mn in 2008. CPDC is a wholly owned subsidiary of AEV.

(k) The Company provides services to certain subsidiaries and associates such as technical and legal

assistance for various projects and other services. Total technical and service fee income amounted to P93.70 mn in 2010, P2.20 mn in 2009 and P9.40 mn in 2008.

(l) Cash deposits with AEV associate Union Bank of the Philippines (UnionBank) and AEV

subsidiaries City Savings Bank (CitySavings).

(m) Advances to/from related parties, both interest and noninterest-bearing, payable on demand. Interest-bearing advances are based on annual interest rates ranging from 1.80% to 8.25% in 2010, 3.00% to 9.25% in 2009 and 3.00% to 10.40% in 2008. Net interest expense incurred on these advances amounted to P1.50 mn in 2010. Net interest income earned on these advances amounted to P55.80 mn in 2009 and P142.70 mn in 2008.

(ix) Government Approvals, Patents, Copyrights, Franchises GOVERNMENT APPROVALS Generation Business Power generation is not considered a public utility operation under the EPIRA. Thus, a franchise is not needed to engage in the business of power generation. Nonetheless, no person or entity may engage in the generation of electricity unless such person or entity has complied with the standards, requirements


and other terms and conditions set by the ERC and has received a Certificate of Compliance (COC) from the ERC to operate the generation facilities. A COC is valid for a period of five years from the date of issuance. A generation company must ensure that all its facilities connected to the Grid meet the technical design and operational criteria of the Grid Code and Distribution Code promulgated by the ERC. Additionally, a generation company must meet the minimum financial capability standards set out in the Guidelines for the Financial Standards of Generation Companies issued by the ERC. Under the said guidelines, a generation company is required to meet a minimum annual interest cover ratio or debt service coverage ratio of 1.5x throughout the period covered by its COC. For COC applications and renewals, the same guidelines require the submission to the ERC of, among other things, comparative audited financial statements, a schedule of liabilities, and a five-year financial plan. For the duration of the COC, these guidelines also require a generation company to submit to the ERC audited financial statements and forecast financial statements for the next two fiscal years, among other documents. The failure by a generation company to submit the requirements so prescribed by the guidelines may be a ground for the imposition of fines and penalties. AboitizPower’s Generation Companies, as well as Davao Light and Cotabato Light which own generation facilities, are required under the EPIRA to obtain a COC from the ERC for its generation facilities. They are also required to comply with technical, financial and environmental standards provided in existing laws and regulations in their operations. The generation companies, Davao Light and Cotabato Light possess COCs for their generation businesses, as follows:

Power Plant

Title of Document:

Issued under the name of:

Type

Location

Capacity (in MW)

Fuel

Years Of Service

Date of Issuance

Hydro Tadlangan, Tuba, Benguet

2.56 Hydro 13

Hydro Nangalisan, Tuba, Benguet

2.50 Hydro 13

Hydro Ampucao, Itogon, Benguet

2.40 Hydro 15

Hydro Bito, La Trinidad, Benguet

10.75 Hydro 15

Hydro Banengbeng, Sablan, Benguet

8.00 Hydro 15

COC No. 03-11-GXT33-0033

HEDC

Hydro Calinan, Davao City 1.00 Hydro 16

December 7, 2006

COC No. 05-02-GXT 286b - 0331

HEDCOR

Hydro

Electric Turbine

Brgy. Mintal, Talomo, Davao City

3.47

Hydro

15

February 26, 2007

Hydro Bakun Central, Bakun, Benguet

10 Hydro 15 COC No. 03-11-GXT32-0032

NMHC

Hydro Amusongan, Bakun, Benguet

2.6 Hydro 15

December 7, 2006

COC No. 03-08-GXT17-0017

LHC

Hydro

Amilongan Alilem, Ilocos Sur

70

Hydro

23

July 29, 2008


Diesel Engine J.P. Laurel Ave., Bajada, Davao City

58.7 Diesel 25

Diesel Engine Ponciano Reyes Substation

105.60 Diesel 25

Diesel Engine Don Ramon Substation

80.00 Diesel 25

Diesel Engine J.P. Laurel Ave., Bajada, Davao City (BPP/ERA Blackstart)

80.00 Diesel 25

COC No. 10-12-GXT13701-13728M

Davao Light

Diesel Engine Panabo Office 41.6 Diesel 25

December 1, 2010

COC No. 07-01 GXT-15911-16153

Cotabato

Light

Diesel

Sinsuat Ave., Cotabato City

9.9

Diesel

January 10, 2007

COC No. 08-06-GXT2-0002

EAUC

Land-Based Diesel HFO

Fired Engine

Mactan Export Processing Zone, Lapulapu City

46

Heavy

Fuel Oil

20

June 10, 2008

COC No. 08-06-GXT1-0001

CPPC

Land-Based Diesel HFO

Fired Engine

Old VECO Compound, Brgy. Ermita, Cebu City

70

Heavy

Fuel Oil

20

June 3, 2008

COC No. 08-08-GXT20-0020

WMPC

Diesel

Sitio Malasugat, Sangali, Zamboanga City

100

Bunker-C/Diesel

30

August 7, 2008

COC No. 08-08-GXT21-0021

SPPC

Diesel

Baluntay, Alabel, Sarangani Province

50

Bunker-C/Diesel

30

August 7, 2008

Hydro electric turbine

Gen. Aguinaldo, Ramon, Isabela

360 Hydro COC No. 05-11-GXT-2860-13433

SNAP-Magat (Magat Plant)

Stand-by Diesel Genset

Gen. Aguinaldo, Ramon, Isabela

350 Diesel

November 29, 2005 (Change of ownership issued on January 28, 2008)

COC No. 10-11-GXT 286M-13429L

NPC (Binga Plant)

Hydro Electric Turbine

Brgy. Binga, Tinongdan, Itogon, Benguet

100 Hydro November 15, 2010

Coal fired

Park V, Phividec Industrial Estate, Balacanas, Villanueva, Misamis Oriental

232 Coal 25 COC No. 06-08-GN-16

STEAG Power

Stand-by Genset

1.25 Diesel 25

August 30, 2006

Brgy. Bitin, Bay, Laguna

Plant A 126.40MW Plant D –

40 MW Sitio Tamlong, Brgy. Limao, Calauan, Laguna

Plant B – 126.40 MW Plant C – 126.4 MW

Steam

May 31, 2010

COC No. 10-05-GXT286e-7833

APRI (Makban

Geothermal Plant)

Geothermal

Brgy. Sta. Elena, Sto. Tomas, Batangas

Plant E – 40 MW


COC No. 10-12-GXT 286r-13736L

APRI (Tiwi

Geothermal Plant)

Geothermal

Brgy. Cale, Tiwi, Albay

234 MW

Steam

December 10, 2010

COC No. 06-04-GXT 286aa-14632

Ormat-

Mak-Ban Binary GPP

Geothermal

Brgy. Sta. Elena, Sto. Tomas, Batangas Brgy. Bitin, Bay, Laguna Brgy. Tamlong, Calauan, Laguna

18.50

Steam

April 6, 2006 release of new COC was deferred by ERC pending completion of rehabilitation of the plant

Diesel Engine

103.80 Diesel COC No. 06-04-GXT 28699-15074

Power Barge 118

Stand-by Diesel Genset

Carlos Cutler Ave., Brgy. San Roque, Maco Compostela Valley 1.68 Diesel

April 19, 2006 new COC application still pending with ERC

Diesel Engine 100.00 Diesel

Steam Turbine

3.50 Steam

COC No. 06-04-GXT 286bb-14633

Power Barge 117

Stand-by Genset

Nasipit, Agusan del Norte

1.68 Diesel

April 6, 2006 new COC application still pending with ERC

AboitizPower’s Generation Companies, which operate hydroelectric facilities, are also required to obtain water permits from the NWRB for the water flow used to run their respective hydroelectric facilities. These permits specify the source of the water flow that the Generation Companies can use for their hydroelectric generation facility, as well as the allowable volume of water that can be used from the source of the water flow. Water permits have no expiration date and generally are not terminated by the Government as long as the holder of the permit complies with the terms of the permit regarding the use of the water flow and the allowable volume. Distribution Business Under the EPIRA, the business of electricity distribution is a regulated public utility business that requires a national franchise that can be granted only by the Congress of the Philippines. In addition to the legislative franchise, a Certificate of Public Convenience and Necessity from the ERC is also required to operate as a public utility. Except for distribution utilities operating within ecozones, all distribution utilities possess franchises granted by Philippine Congress. All distribution utilities are required to submit to the ERC a statement of their compliance with the technical specifications prescribed in the Distribution Code (which provides the rules and regulations for the operation and maintenance of distribution systems), and the performance standards set out in the implementing rules and regulations of the EPIRA.


Shown below are the respective expiration periods of the Distribution Companies’ legislative franchises:

Expiration Date VECO 2030 DLP 2025 CLP 2014 SFELAPCO 2035 SEZ3 2028

MEZ and BEZ, which operate the power distribution utilities in MEPZ II and the WCIP, respectively, are duly registered with PEZA as Ecozone Utilities Enterprises. Supply Business The business of supplying electricity is currently being undertaken solely by franchised distribution utilities. However, once Retail Competition and Open Access starts, the supply function will become competitive. Like power generation, the business of supplying electricity is not considered a public utility operation under the EPIRA. However, it is considered a business affected with public interest. As such, the EPIRA requires all suppliers of electricity to end-users in the contestable market, other than distribution utilities within their franchise areas, to obtain a license from the ERC in accordance with the ERC’s rules and regulations. In preparation for the implementation of Retail Competition and Open Access, AboitizPower’s wholly-owned subsidiaries, AESI and Adventenergy, Inc., obtained separate licenses to act as Retail Electricity Suppliers and Wholesale Aggregators. Trademarks AboitizPower and its subsidiaries own, or have pending applications for the registration of intellectual property rights for, various trademarks associated with their corporate names and logos. The following table sets out information regarding the trademark applications the Company and its subsidiaries have filed with the Philippine Intellectual Property Office.

Trademarks Applicant Date Filed Certificate of Registration

No./Date Issued Description Status

ABOITIZ ENERGY SOLUTIONS & DEVICE (Class No. 42)

AESI January 25, 2007

4-2007-000784 September 03, 2007

Application for trademark ABOITIZ ENERGY SOLUTIONS and Device.

Original Certificate of Registration for the ABOITIZ ENERGY SOLUTIONS & DEVICE was issued on September 03, 2007

Cleanergy (Class No. 42)

AboitizPower October 19, 2001 4-2001-07900. January 13, 2006

Application for trademark “Cleanergy”.

Original Certificate of Registration for the mark CLEANERGY was issued on January 13, 2006

3 Distribution Service Management with the Subic Bay Metropolitan Authority




Cleanergy and Device (Class No. 42)

AboitizPower July 30, 2002 4-2002-06293 July 16, 2007

Application for trademark Cleanergy and Device with the representation of a light bulb with three leaves attached to it, with the words “CLEANERGY” and a small “ABOITIZ” diamond logo below it.

Original Certificate of Registration no. 4-2002-006293 was issued on July 16, 2007

A Better Future (Class No. 39,40, and 42)

AboitizPower April 23, 2010 4-2010-004383 Application for trademark "A Better Future.”

Trademark application has been allowed and its publication in the Official Gazette has been approved in IPO's Notice of Allowance dated August 4, 2010. Payment for publication has been paid on October 4, 2010.

Better Solutions (Class No. 39, 40 and 42)

AboitizPower April 23, 2010 4-2010-004384 Application for Trademark "Better Solutions".


Cleanergy Get It and Device (Class No. 39, 40 and 42)

AboitizPower April 23, 2010 4-2010-004381 The word "Cleanergy" with the phrase "get it" below it with both words enclosed inside a representation of a thumbs up sign. The whole mark is rendered in two shades of green.


AboitizPower word mark (Class 39,40, & 42)

AboitizPower April 23, 2010 4-2010-004385 Application for Trademark "AboitizPower word Mark".

Trademark application has been allowed and its publication in the Official Gazette has been approved in IPO's Notice




of Allowance dated August 4, 2010. Payment for publication has been paid on October 4, 2010.

Cleanergy got it & Device (Class 39, 40 and 42)

AboitizPower April 23, 2010 4-2010-004382 The word "Cleanergy" with the phrase "got it" below it with both words enclosed inside a representation of a thumbs up sign. The whole mark is rendered in two shades of green.


AboitizPower Spiral (Class 39, 40 and 42)

AboitizPower April 23, 2010 4-2010-004380 The representation of a spiral rendered in blue.

Trademark application has been allowed and its publication in the Official Gazette has been approved in IPO's Notice of Allowance dated November 3, 2010. Payment of the issuance and publication fees has been made on December 29, 2010.

AboitizPower and Device (Class 39, 40 and 42)

AboitizPower April 23, 2010 4-2010-004379 The words "Aboitiz" and "Power" rendered in two shades of blue with the representation of a spiral above it and the words "A Better Future: below it.

Trademark application has been allowed and its publication it the Official Gazette has been approved in IPO's Notice of Allowance dated November 3, 2010. Payment of the issuance and publication fees has been made on December 29, 2010.

Power One (wordmark) (Class No. 42)

AESI July 29, 2002 4-2002-6232 February 19, 2007

This is an application for trademark “Power One”

Original Certificate of Registration was issued on February 19, 2007.

Power One and Device (Class No. 42)

AESI February 17, 1999

4-1999-001121 September 18,2006

Application for trademark “ Power One and Device “

Original Certificate of Registration no. 4-1999-001121 was issued on September 18, 2006.




SUBIC ENERZONE CORPORATION and LOGO (colored) (Class No. 39)

SEZC July 6, 2006 4-2006-07306 August 20,2007

Trademark Application for Subic Enerzone Corporation and Logo (blue & yellow). The mark consists of the words "Subic Enerzone" in fujiyama extra bold font with the word "Corporation" below it, also in fujiyama font, rendered in cobalt medium blue color, and a representation of the letter "S" taking the shape of a flame (the company logo) above the words. The logo is likewise rendered in the cobalt medium blue color, in a yellow background.

Original Certificate of Registration No. 4-2006-007306 was issued on August 20, 2007.

SUBIC ENERZONE CORPORATION and LOGO (gray) (Class No. 39)

SEZC July 6, 2006 4-2006-07305 August 20,2007

Trademark Application for Subic Enerzone Corp. wordmark and logo (gray). The mark consists of the words "SUBIC ENERZONE" in Fujiyama extra bold font with the word "Corporation" below it, also in Fujiyama font, and a representation of the letter "S" taking the

Original Certificate of Registration No. 4-2006-007306 was issued on August 20, 2007.




shape of a flame (the company logo) above the words.

SUBIC ENERZONE CORPORATION (wordmark) (Class No. 39)

SEZC July 6, 2006 4-2006-007304 June 4, 2007

Trademark Application for Subic Enerzone Corporation (wordmark)

Original Certificate of Registration was issued on June 4, 2007.

RP Energy and Device (Class No. 39)

RP Energy August 12, 2008 4-2008-009737 April 13, 2009

A representation of 2 mountains, colored blue and red, with the representation of the sun over them, and the words "RP Energy" and "Redondo Peninsula Energy Incorporated" below it.

Original Certificate was issued on April 13, 2009

(x) Effect of Existing or Probable Governmental Regulations Since the enactment of the EPIRA in 2001, the Philippine power industry has undergone and continues to undergo significant restructuring. Through the EPIRA, the Government has begun to institute major reforms with the goal of fully privatizing all sectors of the power industry. Among the provisions of the EPIRA which have or will have considerable impact on AboitizPower’s businesses are the following: Wholesale Electricity Spot Market The WESM, a spot market for the buying and selling of electricity, is a mechanism established by the EPIRA to facilitate competition in the production and consumption of electricity. It aims to: (a) provide incentives for the cost-efficient dispatch of power through an economic merit order; (b) create reliable price signals to assist participants in weighing investment options; and (c) protect a fair and level playing field for suppliers and buyers of electricity, wherein prices are driven by market forces. The WESM provides a venue whereby generators may sell power, and at the same time suppliers and wholesale consumers can purchase electricity where no bilateral contract exists between the two. Although generators are allowed under the WESM to transact through bilateral contracts, these contracts will have to be “offered” to the market for the purpose of determining the appropriate merit order of generators. Settlement for bilateral contracts will, however, occur outside the market between the contracting parties. Traded electricity, not covered by bilateral contracts, will be settled through the market on the basis of the market clearing prices for each of the trading periods.


Open Access and Retail Competition The EPIRA likewise provides for a system of Open Access to transmission and distribution wires, whereby Transco, its concessionaire NGCP and any distribution utility may not refuse use of their wires by qualified persons, subject to the payment of transmission and distribution retail wheeling charges. Conditions for the commencement of the Open Access system are as follows:

(a) Establishment of the WESM; (b) Approval of unbundled transmission and distribution wheeling charges; (c) Initial implementation of the cross subsidy removal scheme; (d) Privatization of at least 70% of the total capacity of generating assets of NPC in Luzon and

Visayas; and (e) Transfer of the management and control of at least 70% of the total energy output of power

plants under contract with NPC to the IPP administrators.

The Government expects Retail Competition and Open Access to be implemented in phases. As far as Luzon is concerned, the WESM began operations in June 2006 and end-users who comprise the contestable market have already been identified. The WESM for the Visayas began trial operations sometime in 2007. Open Access in Luzon and the Visayas will commence once preconditions thereto as provided under the EPIRA have been complied with. In Mindanao, a truly competitive environment required by Retail Competition is not expected to exist prior to at least 2011 because the largest generating asset owned by NPC in Mindanao cannot by law be privatized for at least 10 years from the passage of EPIRA. Upon implementation of Open Access, the various contracts entered into by utilities or suppliers may potentially be “stranded.” Stranded contract costs refer to the excess of the contracted costs of electricity under eligible contracts over the actual selling price of the contracted energy under such contracts in the market. On February 18, 2011, the ERC issued an Order in ERC Case No. 2011-004RM entitled “In the Matter of the Declaration of the Retail Competition and Open Access Pursuant to Section 31 of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001, and Sections 3 and 4 of its Implementing Rules and Regulations,” setting public hearings to determine whether or not Retail Competition and Open Access may already be declared. In the said Order, the ERC motu propio initiated the proceedings to determine whether or not Retail Competition and Open Access may already be declared. The ERC scheduled the public hearings on March 7 to 11, 2011 in ERC, Pasig City. Unbundling of Rates and Removal of Subsidies The EPIRA mandates the unbundling of distribution and wheeling charges from retail rates with such unbundled rates reflecting the respective costs of providing each service. The EPIRA also states that cross subsidies shall be phased out within a period not exceeding three years from the establishment by the ERC of a universal charge, which shall be collected from all electricity end-users. However, the ERC may extend the period for the removal of the cross-subsidies for a maximum of one year if it determines there will be material adverse effect upon the public interest or an immediate, irreparable and adverse financial effect on a distribution utility.


The EPIRA likewise provides for a socialized pricing mechanism called a lifeline rate set by the ERC for low-income, captive electricity consumers who cannot afford to pay the full cost of electricity. These end-users are exempt from the cross-subsidy removal for a period of ten years, unless extended by law. Implementation of the Performance-based Rate-setting Regulation (PBR) On December 13, 2006, the ERC issued the Rules for Setting Distribution Wheeling Rates (RDWR) for privately-owned distribution utilities entering PBR for the second and later entry points that set out the manner in which this new PBR rate-setting mechanism for distribution-related charges will be implemented. PBR is intended to replace the RORB that has historically determined the distribution charges paid by the Distribution Companies’ customers. Under PBR, the distribution-related charges that distribution utilities can collect from customers over a 4-year regulatory period will be set by reference to projected revenues which are reviewed and approved by the ERC and used by the ERC to determine a distribution utility’s efficiency factor. For each year during the regulatory period, a distribution utility’s distribution charges are adjusted upwards or downwards taking into consideration the utility’s efficiency factor set against changes in overall consumer prices in the Philippines. The ERC has also implemented a performance incentive scheme whereby annual rate adjustments under PBR will also take into consideration the ability of a distribution utility to meet or exceed service performance targets set by the ERC, such as the average duration of power outages, the average time of restoration to customers and the average time to respond to customer calls, with utilities being rewarded or penalized depending on their ability to meet these performance targets. The ERC issued its final determination on Cotabato Light’s application for approval of its annual revenue requirement and performance incentive scheme under the PBR scheme covering a 4-year regulatory period which commenced on April 1, 2009 until March 30, 2013. On April 15, 2009, the ERC approved Cotabato Light’s application for translation of its approved annual revenue requirement for the first regulatory year into applicable rates per customer class. Cotabato Light implemented the approved rates last May 1, 2009 – a month after the start of the first regulatory year. The resulting under recovery from the one-month lag was reflected in Cotabato Light’s second regulatory year MAP recalculation and rate translation application which was approved by the ERC on February 22, 2010. The new rates were implemented April 2010. Cotabato Light filed on December 15, 2010 the third regulatory year MAP recalculation and rate translation to be implemented from April 2011 to March 2012. ERC is scheduled to release its decision on the third regulatory year rates before the end of March 2011. VECO and Davao Light filed on May 2010 their respective first regulatory year rate design applications based on the ERC’s final determinations on their annual revenue requirements for the 4-year regulatory period from July 2010 to June 2014. The proposals were approved by ERC on June 2010 and the new rates were implemented on August 2010. The second regulatory year MAP recalculation and rate translation for both Davao Light and VECO are scheduled to be filed before the end of March 2011 and ERC is expected to release the new rates by June 2011. For SFELAPCO and SEZ, the regulatory reset process is on its final stages and ERC is scheduled to release before the end of March 2011 its draft determination on the applications for annual revenue requirements and performance incentive schemes for the regulatory period October 2011 to September 2015. The draft determination will be subjected to public consultations before ERC releases its final


determination on June 2011. Thereafter, SFELAPCO and SEZ will be filing their respective rate design applications for the first regulatory year to be implemented from October 2011 to September 2012. Reduction of Taxes and Royalties on Indigenous Energy Resources To equalize prices between imported and indigenous fuels, the EPIRA mandates the President of the Philippines to reduce the royalties, returns and taxes collected for the exploitation of all indigenous sources of energy, including but not limited to, natural gas and geothermal steam, so as to effect parity of tax treatment with the existing rates for imported coal, crude oil, bunker fuel and other imported fuels. Following the promulgation of the implementing rules and regulations, President Arroyo enacted Executive Order No. 100 to equalize the taxes among fuels used for power generation. Proposed Amendments to the EPIRA Since the enactment of the EPIRA, members of the Philippine Senate and House of Representatives have proposed amendments to the EPIRA. Some of the proposed amendments are discussed below.

(a) Disallow recovery of Stranded Contract costs; (b) Require transmission charges, wheeling charges, connection fees, and retail rates to be

approved by the ERC only after due notice and public hearing participated in by all interested parties;

(c) Exclude from the rate base the following items that Transco and the distribution utilities

charge the public: corporate income tax, value of the franchise, value of real or personal property held for possible future growth, costs of over-adequate assets and facilities, and amount of all deposits as a condition for rendition and continuation of service;

(d) Prohibit cross-ownership between Generation Companies and distribution utilities or any of

their subsidiaries, affiliates, stockholders, officials, or directors, or the officials, directors, or other stockholders of such subsidiaries or affiliates, including the relatives of such stockholders, officials, or directors within the fourth civil degree of consanguinity;

(e) Prohibit distribution utilities under a bilateral electric power supply contract from sourcing

more than 33% of its total electric power supply requirements from a single generation company or from a group of generating companies wholly owned or controlled by the same interests. On the effectiveness of the proposed law, any distribution utility that has contracts which exceed the allowable 33% limit will be directed to desist from further awarding additional electric power supply contracts with any generation company or group of generating companies wholly owned or controlled by the same interests, until its present electric power supply requirements, when added to the proposed additional electric power supply contract or contracts with any generation company or group of generating companies wholly owned or controlled by the same interests shall comply with the 33% limit;

(f) Add the following exceptions under Section 45 of EPIRA (Cross Ownership, Market Power

Abuse and Anti-Competitive Behavior): (1) generating companies utilizing or producing power from site-specific indigenous and renewable energy source such as hydro, geothermal and wind power and (2) if the breach in market share limits is due to the temporary or permanent shutdown or non-operation of other generating facilities;

(g) Exempt or defer some assets of NPC from privatization, such as the Unified Leyte (Tongonan)

Geothermal Complexes, Agus and Polangui Complexes, and the Angat Dam;


(h) Expand the definition of host communities to include all barangays, municipalities and

provinces or regions that protect and maintain watersheds that provide water supply to the dam or hydroelectric power generating facility; and

(i) Distribution utilities to pay a franchise tax equivalent to 3% of the distribution utility’s gross

income in lieu of all taxes. The Renewable Energy Act of 2008 Republic Act No. 9513, the Renewable Energy Act of 2008 (RE Law), is a landmark legislation and is said to be the most comprehensive renewable energy law in Southeast Asia. The RE Law was signed into law by President Gloria M. Arroyo in December 16, 2008 but took effect on January 31, 2009. The RE Law’s declared policy is to encourage and develop the use of renewable energy resources of the country to reduce the country’s dependence on fossil fuels and reduce overall costs of energy, and reduce, if not prevent harmful emissions into the environment to promote health and sustainable environment. The RE Law imposes a government share on existing and new RE development projects at a rate of 1% of gross income from sale of renewable energy and other incidental income from generation, transmission and sale of electric power and a rate of 1.50% of gross income for indigenous geothermal energy. Micro-scale projects for communal purposes and non-commercial operations with capacity not exceeding 100 kW will not be subject to the government share. More importantly, the RE Law offers fiscal and non-fiscal incentives to RE developers of RE facilities, including hybrid systems, subject to a certification from Department of Energy (DOE), in consultation with the BOI. These incentives include income tax holiday for the first seven years of operation; duty-free importations of RE machinery, equipment and materials effective within 10 years upon issuance of certification, provided, said machinery, equipment and materials are directly, exclusively and actually used in RE facilities; special realty tax rates on equipment and machinery not exceeding 1.50% of the net book value; net operating loss carry-over (NOLCO); corporate tax rate of 10% after the 7th year; accelerated depreciation; zero-percent value-added tax on sale of fuel or power generated from emerging energy sources and purchases of local supply of goods, properties and services of RE facilities; cash incentives for RE developers for missionary electrification; tax exemption on carbon emission credits; tax credit on domestic capital equipment and services. All fiscal incentives apply to all RE capacities upon effectivity of the RE Law. RE producers are also given the option to pay Transco transmission and wheeling charges on a per kilowatt-hour basis and are given priority dispatch. RE producers are likewise exempted from universal charge imposed under the EPIRA. In addition, the RE Law provides a financial assistance program from government financial institutions for the development, utilization and commercialization of renewable energy projects, as may be recommended and endorsed by the DOE. According to Department Circular No. DO2009-05-0008 dated May 25, 2009 (Rules Implementing the Renewable Energy Act of 2008), the DOE, Bureau of Internal Revenue (BIR) and the Department of Finance (DOF) shall, within six months from the issuance of the implementing rules of the RE law, formulate the necessary mechanism and/or guidelines to implement the entitlement of the general incentives and privileges to qualified RE developers. However, as of this date, no specific guidelines or regulations has been issued yet by the relevant implementing agencies. Such being the case, the renewable energy companies of AboitizPower, such as APRI, Luzon Hydro, Hedcor Sibulan, Hedcor Tamugan, SNAP-Magat and SNAP-Benguet filed last August 6, 2010 a request for ruling before the BIR Law Division on the application of zero-rated value-added tax on all its local purchases of goods and


services needed for the development of the RE plant facilities, whole process of exploration and development of RE sources up to their conversion into power and the services of subcontractors and contractors. To date, the said request is still pending with the BIR Law Division. New ERC Regulation on Systems Loss Cap Reduction Under ERC Resolution No. 17, Series of 2008, which amends the systems loss caps adopted by Republic Act No. 7832 (Anti-Pilferage of Electricity and Theft of Electric Transmission Lines/Materials Act of 1994), the actual recoverable systems losses of distribution utilities was reduced from 9.50% to 8.50%. The new system loss cap was implemented in January 2010. Under the new regulation, actual company use of electricity shall be treated as an expense of the distribution utilities in accordance with the following rules: for distribution utilities that are yet to enter PBR, the actual use shall be treated as Operation and Maintenance in their PBR applications; and for distribution utilities that are already under PBR, the actual use shall be treated as Operation and Maintenance in their subsequent reset. (xi) Estimate of Amount Spent for Research and Developmental Activities AboitizPower and its subsidiaries do not allocate specific amounts or fixed percentages for research and development. All research and developmental activities are done by AboitizPower’s subsidiaries and affiliates on a per project basis. The allocation for such activities may vary depending on the nature of the project. (xii) Costs and Effect of Compliance with Environmental Laws AboitizPower’s power generation and distribution operations are subject to extensive, evolving and increasingly stringent safety, health and environmental laws and regulations. These laws and regulations, such as the Clean Air Act (Republic Act No. 8749), address, among other things, air emissions, wastewater discharges, the generation, handling, storage, transportation, treatment and disposal of toxic or hazardous chemicals, materials and waste, workplace conditions and employee exposure to hazardous substances. Each of AboitizPower Generation Companies and Distribution Utilities has incurred, and expects to continue to incur, operating costs to comply with such laws and regulations. In addition, each of AboitizPower’s Generation Companies and Distribution Utilities has made and expects to make capital expenditures on an ongoing basis to comply with safety, health and environmental laws and regulations. AboitizPower’s hydropower companies allocate a budget for watershed management system in the respective watersheds where their projects are located. The RE Law adds new and evolving measures that must be complied with. The law ushers new opportunities for the Company and sets competitive challenges. The Renewable Portfolio Standard supports the growth of renewable energy in the Philippines. The Renewable Energy Market, Green Energy Option and Net Metering will redefine the competitive landscape of the industry. Further, the adoption of new safety, health and environmental laws and regulations, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments in the future may require that the Company make additional capital expenditures or incur additional operating expenses in order to maintain the operations of its generating facilities at their current level, curtail power generation or take other actions that could have a material adverse effect on the Company’s financial condition, results of operations and cash flow. In 2010 AboitizPower and its subsidiaries and affiliates did not incur any major sanctions for violation of environmental standards and law. Investments for occupational health and safety measures paid off for


some companies who have gained recognition for operating without accidents. Regulations such as Energy Regulation 1-94 gets the companies to allocate funds for the benefit of host communities. Compliance is not only for protection of the natural environment but also of the communities that inhabit the landscape. AboitizPower continues to be cognizant of new opportunities to comply with regulatory requirements and improvement of systems to prevent adverse impacts to the environment or affected ecosystems. (xiii) Employees On the parent company level, AboitizPower has a total of 100 employees as of January 31, 2011, composed of executive, supervisory, and rank and file staff. There is no existing collective bargaining agreement covering AboitizPower employees. As of January 31, 2011, the Company, its consolidated subsidiaries, Luzon Hydro, VECO, SNAP-Benguet, SNAP-Magat, EAUC and MORE employed a total of 591 employees. The following table provides a breakdown of total employee headcount on a per company basis, divided by function, as of January 31, 2011. The Company does not anticipate any increase in manpower within the next 12 months unless new development projects and acquisitions would materially require an increase.

Number of Employees Business Unit

Total Executives Managers Supervisors Rank & File

Unionized Employees Expiry of CBA

AboitizPower 100 28 14 12 46 0 N/A AESI 14 1 0 1 12 0 N/A BEZ 9 0 0 1 8 0 N/A MEZ 17 1 1 1 14 0 N/A ARI 7 7 0 0 0 0 N/A

APRI 311 4 19 70 218 93

Negotiations for a newCBA with a newly organized union is about to start

CPPC 46 0 2 15 29 0 N/A EAUC 44 1 3 13 27 0 N/A Luzon Hydro 40 3 3 5 29 0 N/A MORE 56 10 9 20 17 0 N/A

SEZ 57 1 4 4 48 0 N/A SNAP-Magat 44 0 2 11 31 0 N/A SNAP-Benguet 105 1 7 26 71 0 N/A STEAG 190 3 16 42 129 0 N/A WMPC 80 0 4 21 55 0 N/A SPPC 68 0 4 19 45 0 N/A

Cotabato Light 74 0 2 16 56 47 06/30/14

Davao Light 285 12 26 65 182 182 06/15/11

Hedcor, Inc. 335 11 11 25 288 131 09/19/11 VECO 302 5 20 28 249 249 12/31/2011 SFELAPCO 88 3 0 21 64 62 05/09/11

TOTAL NO. OF EMPLOYEES 2,272


On October 28, 2010, the Visayan Electric Company Employees Union – ALU – TUCP (the Union) filed a Notice of Strike against VECO on grounds of unfair labor practice for alleged illegal dismissal of the union president and officers and alleged failure to observe the grievance procedure in the Collective Bargaining Agreement (CBA). The Secretary of Labor assumed jurisdiction over the strike and remanded the illegal dismissal case of the union president to the National Labor Relations Commission (NLRC). The compulsory arbitration over the labor dispute and the illegal dismissal case remain pending before the NLRC. The compulsory arbitration enjoins all parties to maintain industrial peace. (xiv) Major Risk/s Involved in the Business Through prudent management and investment decisions, AboitizPower constantly strives to minimize the risks it might encounter in the businesses in which it is involved. However, certain risks are inherent to specific industries that are not within the direct control of AboitizPower or its investee companies. Of note are the following: Reputation Risk AboitizPower recognizes that its reputation is its major asset and source of competitive advantage as well as its primary source of vulnerability in view of the increasing presence of AboitizPower and its business units throughout the Philippines. Media and communication have also reached a point where scrutiny from stakeholders and the general public have become more stringent than ever. Regulators are a vital stakeholder in the power business and it is imperative for AboitizPower businesses to keep their reputation levels high. A Reputation Management Department was established in 2009 to ensure the protection and enhancement of this vital asset. Corporate social responsibility programs, undertaken mainly through the Aboitiz Foundation, and sustainability efforts are given full management support, these being important sources of reputational gain for AboitizPower. Competition Risk The move towards a more competitive environment could result in the emergence of new and numerous competitors. Some of these competitors may have greater financial resources, more extensive operational experience, and thus be more successful than the Company in acquiring existing power generation facilities or in obtaining financing for and the construction of new power generation facilities. The Company has demonstrated its ability to acquire the skill and talent to operate its newly acquired plants at their expected level of operating standards. It also has the necessary expertise in building and financing greenfield assets. The Company intends to continue the strategy of hiring experienced talent for plants that will be constructed as part of its investment plan in the future. Trading Risks Power prices are subject to significant volatility from supply and demand imbalances. From the time the WESM for Luzon began operating in June 2006, market prices for electric power have fluctuated substantially. These factors have caused and are expected to cause fluctuation or instability in the operating results of the Generation Companies, particularly the companies that sell substantial portions of the electricity they generate to the WESM. To mitigate this, the Company aims to achieve a balanced portfolio of contracted and merchant business. In particular, it intends to contract a majority of its base load capacity under price-stable bilateral contracts.


Regulatory Risk AboitizPower’s generation and distribution businesses are now subject to constantly evolving regulations. To manage this risk, planning ahead and preparing for expected changes in regulation now, rather than waiting for regulations to be imposed. Trying to respond to new regulatory standards in a short space of time can be difficult, especially in a climate where forbearance may be scarce. To respond proactively to such fundamental changes may require companies to take a long view on possible regulations and consider alternate scenarios. The Distribution Companies’ drive for operational excellence allows them to deliver world-class service at the least possible cost to their customers. This gives the Distribution Companies credibility and the ability to successfully justify and implement their rates. In addition, the Company’s cost competitive generation asset portfolio places it in a competitive position against other generation companies. This allows ERC-regulated clients to easily secure approval of power supply contracts with the Company. Business Interruption due to Natural Calamities and Critical Equipment breakdown Loss of critical functions caused by natural calamities such as earthquakes, windstorms, typhoons and floods could result in a significant interruption of the businesses. Interruption may also be caused by other factors such as major equipment failures, fires and explosions, hazardous waste spills, workplace fatalities, product tampering, terrorism, and other serious risks. In order to prevent and manage the risk of business interruption, regular preventive maintenance of the Company’s facilities are being strictly observed and loss prevention controls are continually being evaluated and strengthened. In addition, to ensure the continuity of operations in the event of a business interruption, a Business Continuity and Crisis Management Plan will be developed and implemented in 2011 and Business Interruption insurance has been procured to cover the potential loss in gross profits of the Group’s critical operations and assets. Financial Risks In the course of operation of Company and its business units, the Company is exposed to financial risks namely, interest rate risk resulting from movements in interest rates that may have an impact on outstanding long-term debt; credit risk involving possible exposure to counter-party default on its cash and cash equivalents, AFS investments and trade and other receivables; liquidity risk in terms of the proper matching of the type of financing required for specific investments; and foreign exchange risk in terms of foreign exchange fluctuations that may significantly affect its foreign currency denominated placements and borrowings. Details of above risks including measure to mitigate them are discussed in the notes to the financial statements. Fuel Supply Risk The Company’s thermal plants - i.e., STEAG Power and CEDC which both use coal, and CPPC, EAUC, and TMI which use Bunker C fuel, have contracts that allow for their fuel cost to be recovered from their tariffs. Meanwhile, SPPC and WMPC power plants are operated under ECAs with NPC. Under the ECAs, NPC is required to deliver and supply to both plants the fuel necessary to operate these power plants for the duration of the cooperation period. Meanwhile, on the supply side, CPPC, EAUC and TMI each has medium term (2-3 year) contracts with the large oil companies in the Philippines. CPPC and EAUC currently have medium term supply contracts in place, while TMI will be negotiating in 2011 for a new supply contract. CEDC has long term coal contracts with various coal suppliers which will kick in upon commercial operations. STEAG hadentered into an alternate coal supply agreement to allow it to diversify its fuel


supply. Meanwhile, TLI had managed to lock in the prices of its coal supply at a fixed price for 2011. It has entered into a long term coal supply agreement after an evaluation of the various Indonesian coal sources to allow flexibility in its coal sourcing. As regards APRI’s steam supply, it is possible that the steam resource will decline faster than anticipated. The Company believes that having Chevron, the largest producer of geothermal energy in the world as steam contractor mitigates the risks inherent in the supply of steam. Chevron has proven itself capable of managing the resource efficiently, having almost 40 years of experience in developing, operating and maintaining the Tiwi-MakBan steamfields. Political and Economic Factors The results of operations of the Company’s business units have historically been influenced to a certain extent by the political and economic situation in the Philippines. In the past, the country experienced periods of slow or negative economic growth. Any future political or economic instability may have an adverse effect on the business and results of operations of the Company or its investee companies. Working Capital For 2010, AP derived its working capital mainly from the steady cash flow generated and contributed by its subsidiaries and associates and, to a certain extent, from its capital raising activities for the year. Item 2. Properties The Company’s head office is located at the Aboitiz Corporate Center, Gov. Manuel A. Cuenco Avenue, Cebu City, Philippines. The premises are leased from an affiliate, Cebu Praedia Development Corporation (CPDC). On a consolidated basis, the 2010 total Property, Plant and Equipment of AboitizPower were valued at P74.29 bn as compared to P72.90 bn for 2009. The breakdown, as follows:

Property, Plant and Equipment as of December 31, 2010 & 2009

2010 2009 Land 114,336 125,774 Buildings, Warehouses and Improvements 951,281 898,699 Powerplant & Equipment 73,370,137 66,628,765 Transmission, Distribution and Substation Equipment 4,998,903 4,553,427 Transportation Equipment 459,746 386,970 Office Furniture, Fixtures and Equipment 159,951 111,304 Leasehold Improvements 204,563 183,302 Electrical Equipment 1,642,611 1,651,908 Meter and Laboratory Equipment 383,765 358,801 Tools and Others 375,433 326,462 Construction in Progress 1,552,872 4,633,416 Less: Accumulated Depreciation and Amortization 9,921,834 (6,957,799) TOTAL 74,291,764 72,901,029

Note: Values for the above table are in Thousand pesos


Locations of Principal Properties and Equipment of AboitizPower subsidiaries are as follows:

SUBSIDIARY DESCRIPTION LOCATION/ADDRESS CONDITION Cotabato Light Industrial land, buildings/plants,

eqpt. & machineries Sinsuat Avenue, Cotabato City In use for

operations Davao Light Industrial land, buildings/plants,

eqpt. & machineries P. Reyes Street, Davao City; Bajada, Davao City

In use for operations

Hedcor, Inc. Hydropower plants Kivas, Banengneng, Benguet; Beckel, La Trinidad, Benguet; Bineng, La Trinidad, Benguet; Sal-angan, Ampucao, Itogon, Benguet; Bakun, Benguet


Hedcor Sibulan Hydropower plant Santa Cruz, Sibulan Davao del Sur In use for operations

CPPC Bunker C thermal power plant Cebu City, Cebu In use for operations

APRI Geothermal power plants Tiwi, Albay Caluan, Laguna Sto. Tomas, Batangas


TMI Barge-mounted diesel power plants

Nasipit, Agusan del Norte Barangay San Roque, Maco, Compostela valley


Item 3. Legal Proceedings Material Pending Legal Proceedings PEMC Investigation of Bakun plant dispatch As a run-of-river facility, the Bakun plant is not considered either a peaking plant or a base load plant. It is considered an intermittent generator of electricity because it can only generate electricity from water flowing through the Bakun river at any given time, but without a guarantee of when and for how long a given load will occur. Under the Bakun PPA with NPC, for as long as water flow does not go below 0.3 cubic meters per second, the Bakun plant is required to generate electricity for delivery to NPC. If the water flow goes below 0.3 cubic meters per second, it becomes technically inadvisable to allow the Bakun plant to operate because this could result in irreparable damage to its turbines. Electricity generated by the Bakun plant is traded in the WESM by traders for the PSALM for and on behalf of NPC, the contractual offtaker of the Bakun plant. Sometime during trading intervals on July 27 and 28, 2006, August 2, 20, 27, 28, 29, 30, and 31, 2006 and September 1, 4, and 6, 2006, the WESM determined there was overcapacity in the Luzon Grid at off-peak times. In order to avoid excessive frequency on the Luzon Grid, the Bakun plant was instructed by the Philippine Electric Market Corporation (PEMC), the market operator of the WESM, to reduce its load from approximately 40 MW to 3 MW. LHC did not follow these dispatch instructions and did not reduce the load of the Bakun plant since there was sufficient water flow to run the plant at a load of more than 3 MW. As a result of LHC’s failure to comply with PEMC’s dispatch instructions, PEMC sent PSALM, the trader of the Bakun plant’s electricity, a notice of violation of the WESM rules. Although LHC is not a party to the investigations conducted by PEMC, LHC presented to the PEMC board the following reasons why it could not follow the PEMC dispatch instructions:


(a) LHC is required under the Bakun PPA to let the Bakun plant generate its nominated capacity and to deliver to NPC all electricity from available water supplies in accordance with the agreed technical operating parameters under the Bakun PPA;

Annual Rep (b) being a run-of-river facility, the Bakun plant has no storage or impoundment capacity and a

curtailment of the Bakun plant’s load would result in huge losses to NPC from the non-generation of electricity from available water, as well as result in the waste of a renewable energy resource; and

(c) curtailment of the Bakun plant to a load as low as 3 MW would have forced LHC to operate the

Bakun plant manually, which is not technically prudent. This would have required LHC to de-water the Bakun plant abruptly, which the Bakun plant is not designed for and which could result in the collapse of the tunnel to the Bakun plant, leading to serious damage to property and risk to life.

The Technical Committee of the PEMC recommended the denial of LHC’s request for a reclassification from its current WESM participant status as scheduled generator to a renewable energy with intermittent power resource. The PEMC Board affirmed the recommendation of the technical committee. LHC believes though that there is legal basis to reclassify the Bakun plant as an intermittent generation facility with the passage of the RE Law. The RE Law contains specific provisions on intermittent generation. VECO Redundancy Program 1. Jeanu A. Du, et. al vs. VECO

(Aguinaldo Agramon et.al.) NLRC RAB VII Case No. 04-0956-06 NLRC RAB VII Case No. 05-1014-06 NLRC RAB VII Case No. 05-1070-06 NLRC RAB VII Case No. 05-1099-06 NLRC RAB VII Case No. 05-1146-06 NLRC RAB VII Case No. 05-1193-06 NLRC RAB VII Case No. 06-1253-06 NLRC RAB VII Case No. 06-1300-06 NLRC RAB VII Case No. 06-1404-06 NLRC RAB VII Case No. 08-1708-06 CA GR SP No. 03379 Court of Appeals, 19th Division June 15, 2006

2. Alejo C. Pol, et.al vs. VECO

NLRC RAB VII Case No. 08-1782-06 NLRC RAB VII Case No. 08-1878-06 NLRC RAB VII Case No. 08-1832-06 NLRC RAB VII Case No. 09-1953-06 NLRC RAB VII Case No. 08-1981-06 Cebu City September 11, 2006

3. Melchor E. Custodio, Frederick Rivera & Henry Bacaltos vs. VECO

NLRC RAB VII CASE No. 11-2542-2006 NLRC RAB VII CASE No. 12-2714-2006


Cebu City November 23, 2006

4. Bernard Acebedo & Alexander E. Alo vs. VECO

NLRC RAB VII Case No. 06-1218-2007 Cebu City June 12, 2007

VECO is involved in cases for illegal dismissal and/or non-payment of retirement benefits filed by approximately 120 former employees claiming back wages, damages, and reinstatement. These employees previously accepted VECO’s redundancy program, a program initiated in 2004 and which was explained and discussed at length and discussed at length with VECO’s labor union and entire work force at that time. The employees, whose positions were made redundant, including complainants, received their individual notices of redundancy between May and November 2004. They were formally separated from VECO between the periods June to December 2005. At the time of their termination from employment, each of the complainants read through, and was made to understand the contents of, and did sign their individual release, waiver, and quitclaim in the presence of a representative from the Department of Labor and Employment. These employees received separation benefits which were clearly above the minimum requirements provided under the Labor Code. All the complaints have been dismissed for lack of merit at the labor arbiter level and VECO’s redundancy program has been upheld as a management prerogative. The Court of Appeals and the Supreme Court have affirmed the dismissal of the complaints. VECO vs. Roy Salubre, et. al. Civil Case No. CEB-36172, RTC Branch 16, Cebu City The Province of Cebu assessed delinquency real property tax against VECO on the ground that VECO’s electric posts and transformers located in Consolacion should be treated as real property. A Notice of Sale of Delinquent Property covering these poles and transformers was subsequently issued against VECO. VECO filed this case to question the legality of the assessment and the public auction, insisting that the electric poles and transformers are not real properties and therefore not subject to real property taxes. Moreover, VECO is exempt from paying real property tax on poles, wires and transformers by virtue of its legislative franchise (R.A. 9339). On July 27, 2010, the lower court rendered a decision in favor of VECO and ordered the issuance of a writ of prohibition and injunction against the defendants. The case is now pending appeal with the Court of Appeals. In The Matter of the Assessed Real Property Tax On Electric Posts And Transformers Located Within Talisay City Local Board of Assessment Appeals- Talisay City December 30, 2003 On October 29, 2003, the Local Board of Assessment Appeals (LBAA) of Talisay City, Cebu issued a Notice of Assessment and Tax Bill (for Tax Declaration Nos. 68006 to 68065) against VECO for P10.50 mn, real property tax on VECO’s electrical posts and transformers. The assessment was increased to P16.90 mn in 2004. On November 17, 2005, the assessment was further increased to P17.50 mn. In 2003, VECO paid under protest the amount of P2 mn. This matter is currently pending before the LBAA of Talisay City. Despite the pendency of this case before the LBAA, VECO also filed last May 10, 2007 a


letter-request for legal opinion/confirmation before the Bureau of Local Government Finance, Department of Finance (BLGF-DOF) on the exemption from real property tax of VECO’s electrical poles pursuant to VECO’s legislative franchise. This request is also pending for resolution. In The Matter Of The Assessed Real Property Tax On Electric Posts And Transformers Located Within The Municipalities Of Minglanilla, Consolacion and Lilo-an, Province of Cebu Local Board of Assessment Appeals- Province of Cebu September 23, 2008 On July 25, 2008, the Provincial Assessor of Cebu issued a Notice of Assessment for the electric poles and transformers owned by VECO located in the Municipalities of Minglanilla, Consolacion and Lilo-an. The Provincial Assessor, motu proprio, declared for tax purposes for the first time the said properties under Tax Declaration Nos. 39178 to 39193 (for Minglanilla), 39135 to 39166 (for Consolacion) and 54445 to 54458 (for Liloan). On August 27, 2008, VECO received a letter from the Provincial Treasurer demanding payment of approximately P32 mn as real property tax due on the supposed real properties computed from year 1992 up to 2008, including penalties, to the three municipalities. On September 23, 2008 VECO filed a Notice of Appeal and Memorandum of Appeal before the LBAA of the Province of Cebu questioning the demand letter and refuting the assessment on the following grounds: (i) VECO is exempt from paying real property tax on poles, wires and transformers by virtue of its legislative franchise (R.A. 9339); (ii) poles and transformers are not real properties; (iii) the valuation is erroneous and excessive; (iii) it includes assessments which have already prescribed; (iv) the municipalities did not give VECO the opportunity to present controverting evidence; (v) it did not consider depreciation cost of the assets; (vi) the assessment violates due process for it did not comply Section 223 of the Local Government Code of 1991; (vii) the Provincial Assessor erred in giving retroactive effect to the assessment in violation of Section 221 of the Local Government Code of 1991; and (viii) the assessments are null and void for lack of ordinance on the schedule of market values and lack of publication of the same. To date, the said appeal is still pending resolution. Luzon Hydro Corporation vs. The Province Of Benguet, The Provincial Treasurer Of Benguet And Hon. Imelda I. Macanes In Her Capacity As Provincial Treasurer Of La Trinidad, Province Of Benguet Civil Case No. 08-CV-2414 RTC Branch 10, La Trinidad, Benguet March 7, 2008 On October 11, 2007, the Provincial Treasurer of Benguet issued a franchise tax assessment against LHC, requiring LHC to pay franchise tax for the years 2002 to 2007 in the approximate amount of P40.40 mn, inclusive of surcharges and penalties. LHC filed a protest letter with the Provincial Treasurer in December 2007 on the ground that LHC is not a grantee of any legislative franchise on which basis franchise taxes may be imposed. On February 8, 2008, the Provincial Treasurer, through the Provincial Legal Officer, denied LHC’s protest letter. On March 7, 2008, LHC filed before the Regional Trial Court (RTC) of Benguet a petition against the Provincial Treasurer of Benguet for the annulment of the franchise tax assessment. The trial of the case is ongoing.


Hedcor Inc. vs. The Province of Benguet, The Provincial Treasurer of Benguet and Hon. Imelda I. Macanes in her Capacity as Provincial Treasurer Civil Case No. 08- CV-42398 RTC Br. 63, La Trinidad, Benguet Jan. 18, 2008 On October 22, 2007, Hedcor received a franchise tax assessment from the Provincial Treasurer of the Province of Benguet requiring Hedcor to pay the unpaid franchise taxes of Hydro Electric Development Corporation (HEDC) and Northern Mini Hydro Corporation (NMHC) in the approximate amount of P30.9 mn, inclusive of surcharges and penalties, for the fourth quarter of 1995 up to 2007. Hedcor filed a protest letter on the basis that HEDC and NMHC are not required to pay franchise taxes. Hedcor’s protest letter was denied by the Provincial Treasurer in a letter dated November 27, 2007. Pursuant to Section 195 of the Local Government Code of 1991, Hedcor filed a petition last January 4, 2008 against the Provincial Treasurer before the RTC to annul the assessment of the franchise tax. On February 18, 2008, the Province of Benguet filed its answer to the petition, insisting on the liability of Hedcor, and relying on the Articles of Incorporation of Hedcor to substantiate its allegation that Hedcor possesses both a primary and secondary franchises. Hedcor is of the opinion that it is not liable for franchise tax since it does not need a national franchise to operate its business, pursuant to Section 6 of the EPIRA. Moreover, Hedcor argues that it is a separate and distinct legal entity from HEDC and NMHC, and as such, it cannot be made liable for whatever obligation, if any, as may pertain to HEDC and/or NMHC. With the completion of the trial and formal offer of evidences of the parties, this case is now pending resolution. Hedcor Inc. vs. The Province of Benquet, The Provincial Treasurer of Benquet and Hon. Imelda I. Macanes in her Capacity as Provincial Treasurer Civil Case No. 08-CV-2416 RTC Br. 63. La Trinidad, Benquet December 21, 2007 On October 25, 2007, Hedcor received from the Provincial Treasurer of Benguet an assessment in the amount of P30.5 mn representing the share of the Province and host municipalities and barangays in the national wealth tax due from HEDC and NMHC for the years 1997 to 2007. On December 21, 2007, Hedcor filed its protest letter with the Provincial Treasurer of Benguet stating that it is a separate and distinct legal entity from HEDC and NMHC. Hedcor only acquired the hydroelectric power plants, which are the subject of the assessed national wealth tax, from HEDC and NMHC on June 25, 2005. Prior to June 25, 2005, Hedcor did not own any operating hydroelectric power plants. Thus, if Hedcor is indeed liable for any national wealth tax with respect to the operation of the hydroelectric power plants, it is liable only for taxes after June 25, 2005. Aboitiz Power Corpora

In addition, Hedcor is of the opinion that the Province of Benguet does not have legal basis to collect national wealth tax from private generation companies prior to the effectivity of EPIRA in June 2001. Since June 2005, Hedcor has been contributing the amount equivalent to 3% of its gross revenues to its host municipalities and barangays in compliance with the national wealth tax provision contained in Section 291 of the Local Government Code of 1991. Hedcor has been generously paying amounts higher than the amount required by the Local Government Code. The Province of Benguet, through the Office of the Governor, and Hedcor, have been engaged in negotiations to arrive at a possible settlement for the national wealth tax case. In view of the pending negotiations for settlement, the proceedings of this case have been suspended.


Mactan Electric Co. vs. Acoland, Inc. Civil Case No. MDI-56 RTC Branch 56, Mandaue City June 16, 1996 On July 16, 1996, MECO filed a quo warranto case against AboitizLand attacking the latter’s legal basis to distribute power within the MEPZ II as well as the Philippine Economic Zone Authority’s (PEZA) authority to grant Aboitizland the operation or distribution of power in the area in question. MECO argues that AboitizLand does not possess the legal requirements to distribute power within MEPZ II, and that the amendment of AboitizLand’s Articles of Incorporation to include the right to engage in the operation, installation, construction and/or maintenance of electric and other public utilities only six days after the filing of this case was an afterthought, and as a consequence, it is liable to pay damages to MECO. MECO further alleges that PEZA has no right to grant franchise to distribute electricity within the MEPZ II. AboitizLand’s argument that the Special Economic Zone Act of 1995 (R.A. 7916) which created PEZA grants the latter broad powers and functions to manage and operate special economic zones, that these include the power to grant enfranchising powers under Section 12(c) and 13(d) thereof, and that the SEC approval of its amended Articles of Incorporation is valid. Regarding damages, AboitizLand argues this was not prayed for in MECO’s petition for quo warranto and the courts have no basis to grant any damages. The PEZA intervened and argued that, it is authorized by its charter to undertake and regulate the establishment and maintenance of utilities including light and power within economic zones under its jurisdiction. In doing so, it can directly construct, acquire, own, lease, operate, and maintain on its own or through contract, franchise, license, bulk purchase from the private sector, and build-operate-transfer scheme or joint venture, adequate facilities such as light and power. The parties are currently undergoing court-mandated mediation proceedings. In 2007, with the approval of PEZA, AboitizLand transferred all of its power assets and business to a new corporation, MEZ, which is now the real party in interest in the case. The parties to the case are currently trying to settle the case amicably. In view of this, the trial has been suspended until May 30, 2011. In The Matter Of The Assessed Real Property Tax On Machineries Located Within The Municipality of Bakun, Province of Benguet Central Board of Assessment Appeals CBAA Case No. L-57 and L-59 The Municipality of Bakun, Province of Benguet issued an assessment against LHC for deficiency real property tax on its machineries in the amount of approximately P11.0 mn, inclusive of interests and penalties, for the period 2002. The assessment was appealed by LHC to the LBAA. NPC intervened in the proceedings before the LBAA arguing that (i) the liability for the payment of real property tax over the machineries is assumed by NPC under Section 8.6(b) under the Bakun PPA dated as of November 24, 1996; and (ii) NPC is exempted from the payment of real property tax under Section 234 of the Local Government Code, which provides that machineries that are actually, directly and exclusively used by government-owned and controlled corporations engaged in the generation and transmission of electric power are not subject to the real property tax. The LBAA ruled in favor of the Municipality of Bakun on the ground that NPC could not invoke the exception under Section 234 of the Local Government Code because the machineries covered by the assessment are not yet owned by NPC.


NPC further appealed the ruling of the LBAA to the Central Board of Assessment Appeals (CBAA) docketed as CBAA Case No. L-57/59. According to the CBAA, NPC sent a compromise proposal in 2006 to the CBAA. Currently, the Province of Benguet, through the Office of the Governor, and LHC, have been engaged in negotiations to arrive at a possible settlement. Trial of the case is ongoing. Annual Report 2010

PHILIPPINE HYDROPOWER CORPORATION (now Aboitiz Renewables, Inc.) vs. PACIFIC HYDRO BAKUN INC. & PACIFIC HYDRO PTY LIMITED Complaint for Tortious Interference in Contractual Relations and Exercise of Property Rights RTC-Branch 17, Cebu City Filed: 10-2-2009 This is a Complaint for Tortious Interference in Contractual Relations and Exercise of Property Rights filed by ARI with the Regional Trial Court in Cebu City against Pacific Hydro Bakun, Inc. (PHBI), its joint venture partner in Luzon Hydro Corporation (LHC). LHC is the special purpose vehicle formed to develop, construct and operate the 70-megawatt (MW) Bakun hydropower plant in Ilocos Sur (the Bakun Plant) under a build-operate-transfer (BOT) scheme with the National Power Corporation (NPC). The complaint by ARI against PHBI and its parent company, Pacific Hydro Limited (PHL), arose from PHBI’s and PHL’s tortious conduct including: (a) threatening and intimidating ARI and its nominee directors in LHC to vote in favor of allowing LHC to participate in the bidding for the Independent Power Producer Administration (IPPA) for the combined contracted capacities of the Bakun Plant, the 345 MW San Roque hydropower plant and the 30 MW Benguet mini-hydro plants (the Bidding) and, (b) spreading malicious allegations of wrongful conduct on the part of the nominee directors of ARI to third persons. ARI maintains that LHC is a special purpose vehicle formed specifically and solely to undertake the construction of the Bakun Plant under a BOT agreement with NPC. PHBI’s proposal for LHC to engage in the business of an IPPA for the power plants included in the Bidding is outside the primary or secondary purposes of LHC and is beyond the original intent of the shareholders of LHC. For these reasons, ARI believes that PHBI and PHL cannot rightfully compel it to enter into the IPPA business with PHBI and PHL through LHC. Moreover, notwithstanding ARI’s refusal to enter into the IPPA business with PHBI and PHL, such refusal did not deprive the latter of participating in the Bidding if they really wanted to do so. The case is now under court-mandated mediation proceedings at the Philippine Mediation Center. The parties have agreed to include in the mediation proceedings the intra-corporate suit by PHBI against ARI. PACIFIC HYDRO BAKUN, INC. for itself and/or on behalf of LUZON HYDRO CORPORATION vs. PHILIPPINE HYDROPOWER CORPORATION (now Aboitiz Renewables, Inc.) its parent company, subisidiaries and/or affiliates participating in the bidding (for appointment as IPP Administrator for contracted capacities of the Bakun, San Roque and Benguet HydroElectric Plants) Jose Venancio Batiquin, Antonio Moraza, Rene B. Ronquillo Civil Case No. 01332-T Filed: 10-7-2009 Intra-Corporate Suit This is a derivative stockholders’ suit filed by Pacific Hydro Bakun, Inc., (PHBI) against ARI, et. al. for alleged violation by the defendants of their fiduciary duties to LHC and PHBI by refusing to allow LHC to participate in the bidding for the Independent Power Producer Administration (IPPA) for the combined contracted capacities of the Bakun Plant, the 345 MW San Roque hydropower plant and the 30 MW Benguet mini-hydro plants (the “Bidding”) resulting in the following:


1. Being barred from participating in the Bidding; 2. Loss of any business and commercial advantages it would have over the other bidders in the

bidding, considering that LHC is the builder and operator of the Bakun Hydroelectric Power Plant;

3. Loss of profits that would have been earned from its acting as IPP Administrator, particularly for the Bakun Hydroelectric Power Plant; and

4. Diminution, if not elimination of LHC’s prospect of permanently acquiring the Bakun Hydroelectric Power Plant after the expiration of its PPA/BOT in 2026.

Among others, PHBI prays for the immediate assignment/transfer of the defendants’ equity/participation in the joint venture between ARI and the SN power-related company (“the Other Bidder”) which defendants hold in constructive trust for plaintiffs and also to cause the Other Bidder to consult with plaintiffs on all matters in the Bidding. The parties have agreed to submit this case to a court-mandated mediation proceedings together with the complaint for tortious conduct filed by ARI against PHBI, et. al. in the RTC of Cebu City. Luzon Hydro Corporation and the National Power Corporation vs. The Local Board of Assessment Appeals of the Province of Ilocos Sur, Fatima Tenorio, in her official capacity as the Provincial Assessor of the Province of Ilocos Sur, Antonio A. Gundran, in his capacity as the Provincial Treasurer of the Province of Ilocos Sur Central Board of Assessment Appeals, Manila CBAA Case Nos. L-96 and L-99 On July 2, 2003, the Municipal Assessor of Alilem sent LHC two notices of assessment of real property. The first notice required LHC to pay real property taxes in the amount of P4.3 mn, for the 4th quarter of 2002, while the second notice required LHC to pay P17.2 mn for 2003. The notices of assessment also contained an additional imposition of 40% of the acquisition cost, which allegedly represented installation costs, and a further imposition of 15%, which allegedly represented freight costs. LHC filed a Protest before the LBAA which ruled against LHC by upholding the notices of assessment. Thus LHC appealed directly to the CBAA where the trial of the case is ongoing. SN Aboitiz Power-Magat, Inc. vs. The Municipality of Alfonso Lista, Hon. Charles L. Cattiling, in his capacity as Mayor of the Municipality of Alfonso Lista, and Estrella S. Aliguyon, in her capacity as Treasurer of the Municipality of Alfonso Lista RTC Alfonso Lista, Ifugao, Branch 15 Special Civil Action No. 17-09 On July 12, 2007, SNAP-Magat was issued by the Board of Investments (BOI) Certificate of Registration No. 2007-188 classifying SNAP-Magat’s operation of the Magat Power Plant as a pioneer enterprise. Pursuant to Section 133(g) of the Local Government Code, SNAP-Magat is exempt from local business taxes for a period of six years from the date of registration with the BOI. However, the Municipality of Alfonso Lista (Alfonso Lista) refused to recognize such exemption and insists on assessing and collecting local business taxes from SNAP-Magat. In March 2009, SNAP-Magat filed a Complaint for Injunction with the RTC of Alfonso Lista, Ifugao against the Municipality of Alfonso Lista, its Mayor, and Treasurer. The Complaint prayed that the defendants and all persons acting under their direction or authority be prevented from: (i) assessing and collecting local business taxes from SNAP-Magat; (ii) refusing to issue a Mayor’s Permit to SNAP-Magat for non-payment of local business taxes; and (iii) distraining and levying on SNAP-Magat’s properties, closing the Magat Power Plant, and committing any other act against SNAP-Magat that obstructs or


delays its operations in connection with its non-payment of local business taxes. The complaint also prays for the issuance of a temporary restraining order and writ of preliminary injunction. The RTC denied SNAP-Magat’s application for a temporary restraining order. SNAP-Magat then filed a Petition for Certiorari with the Court of Appeals for the issuance of temporary restraining order and/or writ of preliminary injunction being sought from the RTC and for the nullification of the RTC order. The Court of Appeals granted SNAP-Magat’s Petition for Certiorari and made permanent the temporary restraining order it initially issued. Negotiations are ongoing between the parties for the settlement of the case. Trial is ongoing. Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report.

PART II - OPERATIONAL AND FINANCIAL INFORMATION

Item 5. Market for Issuer’s Common Equity and Related Stockholder Matters (1) AboitizPower’s common shares are traded on the PSE. The high and low stock prices of AboitizPower’s common shares for each quarter of 2008 to 2010 were as follows:

2011 2010 2009 2008

High Low High Low High Low High Low First Quarter 31.60 26.20 12.75 8.60 4.65 3.90 5.60 4.50 Second Quarter NA NA 19.25 12.25 6.00 4.65 5.60 4.80 Third Quarter NA NA 21.80 18.00 6.70 5.30 6.00 4.85 Fourth Quarter NA NA 35.80 20.90 8.90 6.40 5.00 3.25

As of February 28, 2011, AboitizPower has 484 stockholders of record, including PCD Nominee Corporation (Filipino) and PCD Nominee Corporation (Foreign). Common shares outstanding as of same date were 7,358,604,307 shares. The closing price of AboitizPower common shares as of March 31, 2011 is P30 per share. (2) The top 20 stockholders of AboitizPower as of February 28, 2011 are as follows:

Name Number of Shares Percentage 1. ABOITIZ EQUITY VENTURES, INC. 5,622,113,063 76.40% 2. PCD NOMINEE CORPORATION (Filipino) 804,762,081 10.94% 3. PCD NOMINEE CORPORATION (Foreign) 584,666,672 7.95% 4. ABOITIZ & COMPANY, INC. 151,112,722 2.05% 5. ARMOZA MANAGEMENT & DEVELOPMENT CORPORATION 28,050,041 0.38% 6. SAN FERNANDO ELECTRIC LIGHT AND POWER CO., INC. 7,931,034 0.11% 7. UNIONBANK TISG AS INVESTMENT MANAGER FOR IMA #4B1-166-10 7,880,769 0.11% 8. PARRAZ DEVELOPMENT CORPORATION 7,827,522 0.11 % 9. KAYILKA HOLDINGS, INC. 7,783,834 0.11 %


10. LILOAN AGRO INDUSTRIAL DEVELOPMENT CORPORATION 6,051,405 0.08% 11. ABOITIZ, SABIN M. 6,050,985 0.08% 12. SIERRAROSA, INC. 5,892,110 0.08% 13. JOEMOR MANAGEMENT AND DEVELOPMENT CORPORATION 4,455,501 0.06% 14. BANILAD ESTATE, INC. 4,000,000 0.05% 15. EMETASI HOLDINGS, INC. 4,000,000 0.05% 16. RAMON ABOITIZ FOUNDATION, INC. 3,900,000 0.05% 17. ABOITIZ, IKER M. 3,177,545 0.04% 18. TAN BEN KUAN 2,750,000 0.04% 19. UBP T/A 4B1-153-09 2,484,698 0.03% 20. LMM HOMES MANAGEMENT & DEVELOPMENT CORP. 2,376,335 0.03 % (3) The cash dividends declared by AboitizPower to common stockholders from 2009 to 2011 are shown in the table below:

AboitizPower intends to maintain an annual cash dividend payment ratio of approximately one-third of its consolidated net income from the preceding fiscal year, subject to the requirements of the applicable laws and regulations and the absence of circumstances which may restrict the payment of cash dividends, such as the undertaking by AboitizPower of major projects and developments requiring substantial cash expenditures or restrictions on cash dividend payments under its loan covenants. (4) Recent Sales of Unregistered or Exempt Securities including Recent Issuance of Securities

Constituting and Exempt Transaction

(a) On December 18, 2008, AboitizPower availed a total of P3.89 bn under a Notes Facility Agreement dated December 15, 2008 with BDO Capital & Investment Corporation, BPI Capital Corporation, First Metro Investment Corporation, ING Bank N.V., Manila Branch as Joint Lead Managers. The Notes Facility Agreement provided for the issuance of 5-year and 7-year peso denominated corporate notes in a private placement to not more than 19 institutional investors pursuant to Section 9.2 of the Securities Regulation Code (SRC) and Rule 9.2(2)(B) of the SRC Rules.

The corporate notes were issued to the following institutional investors:

NOTEHOLDERS (5-Year Notes) AMOUNT DUE

BDO PRIVATE BANK INC. WEALTH ADVISORY & TRUST GROUP 90,000,000.00 BDO TRUST AND INVESTMENT GROUP 180,000,000.00 BPI-AMTG AS INVESTMENT MANAGER FOR ALFM PESO BOND FUND, INC. 200,000,000.00 BPI-AMTG AS INVESTMENT MANAGER FOR AYALA LIFE ASSURANCE, INC. 100,000,000.00 BPI-AMTG AS INVESTMENT MANAGER FOR VARIOUS TRUST ACCOUNTS 200,000,000.00 BSP PROVIDENT FUND 50,000,000.00 CHINA BANK SAVINGS, INC. – TRUST DEPARTMENT 60,000,000.00 DEUTSCHE BANK AG MANILA BRANCH TRUST DEPARTMENT 50,000,000.00 DEUTSCHE BANK AG MANILA BRANCH TRUST DEPARTMENT 20,000,000.00 FIRST METRO INVESTMENT CORPORATION 400,000,000.00 FIRST METRO SAVE AND LEARN FIXED INCOME FUND 20,000,000.00

Year Cash Dividend Per Share Total Declared Record Date 2011 P1.32 P9.71 bn 3/17/2011 2010 P0.30 P2.21 bn 3/24/2010 2009 P 0.20 P1.47 bn 2/26/2009


MAYBANK PHILIPPINES, INC. 300,000,000.00 RCBC TRUST & INVESTMENTS DIVISION FAO TA#59-098-3 10,000,000.00 ROBINSONS SAVINGS BANK 200,000,000.00 SECURITY BANK CORPORATION 500,000,000.00 SOCIAL SECURITY SYSTEMS 450,000,000.00 STERLING BANK OF ASIA, INC. 100,000,000.00 UNITED COCONUT PLANTERS BANK 300,000,000.00

TOTAL PRINCIPAL DUE 3,330,000,000.00


BDO PRIVATE BANK INC. WEALTH ADVISORY AND TRUST GROUP 19,600,000.00 BDO TRUST AND INVESTMENT GROUP 19,600,000.00 FIRST GUARANTEE LIFE ASSURANCE COMPANY, INC. 19,600,000.00 THE INSULAR LIFE ASSURANCE COMPANY, LTD. 490,000,000.00

TOTAL PRINCIPAL DUE 548,800,000.00 The total underwriting fees paid to the Joint Lead Managers for the issuance of the P3.89 bn corporate notes was P18.82 mn.

(b) On September 28, 2009, AboitizPower issued 5-year peso-denominated corporate fixed rate notes in the aggregate amount of P5 bn to a consortium of primary institutional lenders in a private placement made in accordance with Section 9.2 of the Securities Regulation Code (SRC) and Rule 9.2(2)(B) of the SRC Rules. The issuance of the P5 bn corporate notes was made pursuant to a Notes Facility Agreement with First Metro Investment Corporation as Issue Manager.

The corporate notes were issued to the following institutional investors:


METROPOLITAN BANK & TRUST GROUP 1,500,000,000.00BDO PRIVATE BANK WEALTH ADVISORY & TRUST GROUP 1,058,000,000.00THE INSULAR LIFE ASSURANCE CO., LTD. 700,000,000.00PHILIPPINE SAVINGS BANK 500,000,000.00UNITED COCONUT PLANTERS BANK 100,000,000.00UNITED COCONUT PLANTERS BANK 100,000,000.00UNITED COCONUT PLANTERS BANK 100,000,000.00UNITED COCONUT PLANTERS BANK 100,000,000.00UNITED COCONUT PLANTERS BANK 100,000,000.00METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR DE LA SALLE UNIVERSITY

100,000,000.00

METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR LASALLIAN EDUC INNOVATORS FOUNDATION, INC. (ST. BENILDE)

60,000,000.00

METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR DE LA SALLE SANTIAGO ZOBEL, INC.

25,000,000.00

METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR HERMANO SAN MIGUEL FEBRES CORDERO MEDICAL EDUCATION FOUNDATION (DE LA SALLE HEALTH SCIENCES CAMPUS)

15,000,000.00

METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR C-13-09 50,000,000.00

METROBANK TRUST BANKING GROUP AS INVESTMENT MANAGER FOR C-13-08 50,000,000.00


SOCIAL SECURITY SYSTEM 50,000,000.00SOCIAL SECURITY SYSTEM PROVIDENT FUND 100,000,000.00DEUTSCHE BANK AG MANILA BRANCH TRUST DEPARTMENT FOR VARIOUS TRUST ACCOUNTS (TAX-EXEMPT)

128,000,000.00

DEUTSCHE BANK AG MANILA BRANCH TRUST DEPARTMENT FOR VARIOUS TRUST ACCOUNTS (TAXABLE)

4,000,000.00

UCPB TRUST BANKING GROUP 100,000,000.00PIONEER LIFE, INC. 50,000,000.00FIRST LIFE FINANCIAL COMPANY, INC. 10,000,000.00

TOTAL PRINCIPAL DUE 5,000,000,000.00 The total underwriting fees paid to the Issue Manager for the issuance of the P5 bn corporate notes was P24.19 mn. Item 6. Management’s Discussion and Analysis or Plan of Action MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion and analysis of the Company’s consolidated financial condition and results of operations and certain trends, risks and uncertainties that may affect its business. The critical accounting policies section discloses certain accounting policies and management judgments that are material to the Company’s results of operations and financial condition for the periods presented in this report. The discussion and analysis of the Company’s results of operations is presented in three comparative sections: the year ended December 31, 2010 compared with the year ended December 31, 2009, the year ended December 31, 2009 compared with the year ended December 31, 2008, and the year ended December 31, 2008 compared with the year ended December 31, 2007. Prospective investors should read this discussion and analysis of the Company’s consolidated financial condition and results of operations in conjunction with the consolidated financial statements and the notes thereto set forth elsewhere in this report. KEY PERFORMANCE INDICATORS Management uses the following indicators to evaluate the performance of the Company and its subsidiaries:

1. Equity in Net Earnings (Losses) of Investees. This represents the Group’s share in the undistributed earnings or losses of its investees for each reporting period after the acquisition of said investments, net of goodwill impairment cost, if any. Goodwill is the difference between the purchase price of an investment and the investor’s share in the value of the net identifiable assets of investee at the date of acquisition. Equity in net earnings (losses) of investees indicates the profitability of the investments and the investees’ contribution to the Group’s net income.

Manner of Computation: Investee’s Net Income (Loss) x Investor’s Percentage Ownership less Impairment Loss.

2. Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA). EBITDA is calculated

as net income before minority interest, net interest expense, income tax expense, amortization and depreciation. It provides management and investors with a tool for determining the ability of the Group to generate cash from operations to cover financial charges and income taxes. It is also a measure to evaluate the Group’s ability to service its debts.


3. Cash Flow Generated. Using the Statement of Cash Flows, management determines the sources

and usage of funds for the period, and analyzes how the group manages its profit and uses its internal and external sources of funds. This aids management in identifying the impact on cash flow when the Group’s activities are either in a state of growth or decline, and in evaluating management’s efforts to control the impact.

4. Current Ratio. This is a measurement of liquidity, calculated by dividing total current assets by

the total current liabilities. It is an indicator of the Group’s short–term debt paying ability. The higher the ratio, the more liquid is the Group.

5. Debt–to–Equity Ratio. This gives an indication of how leveraged the Group is. It compares

assets provided by creditors to assets provided by shareholders. It is determined by dividing total liabilities by total equity.

The table below shows the comparative figures of the top five key performance indicators for 2010 and 2009: DISCUSSION ON KEY PERFORMANCE INDICATORS:

Key Performance Indicators 2010 2009 Amounts in thousands of Ps, except for financial ratios SHARE IN NET EARNINGS OF ASSOCIATES 4,625,883 2,535,386EBITDA 34,361,919 9,866,532CASH FLOW GENERATED: Net cash flows from operating activities 27,275,647 5,873,633Net cash flows (used in) investing activities (4,368,509) (23,953,482)Net cash flows from (used in) financing activities (8,358,116) 7,721,594 Net Increase (Decrease) in Cash & Cash Equivalents 14,549,022 (10,358,255)Cash & Cash Equivalents, Beginning 3,814,906 14,333,676 Cash & Cash Equivalents, End 18,301,845 3,814,906 CURRENT RATIO 2.58 0.68 DEBT-TO-EQUITY RATIO 1.33 2.18

Above key performance indicators are within management expectations. Share in Net Earnings of Associates nearly doubled from last year’s results. The largest contributing companies were SNAP-Magat and SNAP-Benguet, both of which benefitted from a fresh inflow of revenues from their respective ancillary service contracts with NGCP. Both companies also saw a marked improvement on their average selling prices to the electricity spot market which further improved their revenues for the year. On the other hand, the following factors allowed VECO to increase its share to the Company’s Net Earnings of Associates:(a) the continued growth of its sales of electricity on the back of higher demand from its industrial, commercial and residential customers, and (b) additional margins brought about by rate adjustments in the second half of 2009 under the RORB regime and in August of this reporting period under the PBR scheme. All the above positive contributions managed to offset a one-time refinancing cost of P398 mn incurred by STEAG. The positive effects brought about by the income contribution of the Company’s new acquisitions during the year vastly improved the Company’s EBITDA which is up 248% versus the prior year. The income contributions from the geothermal assets of APRI starting May 2009 and the TLI IPPA for the Pagbilao coal starting October 2009 were the main drivers of the increase in EBITDA.


The Company’s Current Ratio managed to increase to 2.58x at year-end versus 0.68x in the prior year. The marked increase in Current Assets is due to higher cash balances and an increase in Trade and Other Accounts Receivables. The increase in Cash is attributable to healthy cash flows from various subsidiaries while the increase in Trade Receivables is due to higher volumes of energy sold at better margins as well as new Trade Receivables recognized at TMI and Hedcor Sibulan which started operating this year. The recognition of the period’s robust net income lead to the improvement of the Company’s Debt to Equity ratio. Financial Results of Operations The Company’s net income for 2010 grew by 335% to P25.08 bn from P5.77 bn for the same period last year. This brought up earnings per share to P3.40 for the year ending December 31, 2010 versus an earnings per share of P0.77 ending December 31, 2009. The power generation business improved its contributions by 424% from prior year as it shored in a net income contribution of P24.39 bn, from last year’s P4.66 bn. This impressive performance has allowed this segment to be the major contributor to the Company’s bottom line for the year.The generation business accounted for 93% of earnings contributions from AboitizPower’s business segments. The profit growth of this segment is largely due to: (a) new income contributions from generation assets which were acquired in 2009; (b) income contributions from new acquisitions this year; and (c) the start of operations of a greenfield project in the first half of 2010. The contributions coming from the following events accounted for the significant contributions from the power generation segment:

(a) Full year contribution of APRI, operator of the Tiwi-Makban geothermal facilities which were acquired in May 2009, compared to only four months for the same period in 2009;

(b) Full year contributions of TLI, which assumed dispatch control of the 700 MW Pagbilao coal fired

plant in October 2009;

(c) New contributions from TMI following its take-over of two 100 MW power barges in the first quarter of 2010; and

(d) The start of operations of the 26 MW Sibulan hydropower plant in March 2010.

Total attributable sales of the distribution group grew by 9% on a year-to-date (YTD) basis. This segment continues to see robust growth from its industrial accounts complemented by respectable growth from its residential and commercial accounts. Improved margins resulting from the shift to PBR for the two major distribution utilities under this segment in August 2010 as well as the margins from the full year effect of an RORB increase that got approved in the latter part of 2009 for one of the distribution utilities also provided additional increases to the distribution group’s income contribution. These contributions came in despite the significant operating expenses seen in the first half of this year due to the forced operation of a back-up power plant at Davao Light in Mindanao plus higher costs absorbed in two distribution utilities due to a lower systems loss cap mandated by ERC (from 9.50% to 8.50%) which took effect in January 2010. The distribution group contributed P1.93 bn this reporting period versus P1.57 bn last year or an increase of 23%.


Material Changes in Line Items of Registrant’s Income Statement Consolidated net income attributable to equity holders grew by P19.38 bn or 343%. Below is a reconciliation of the growth in the consolidated net income.

Consolidated Net Income Attributable to Equity Holders of the Parent for 2009 P5,658,581

Increase in Operating Revenues 36,377,193

Increase in Operating Expenses (15,601,780)

Increase in Share in Net Earnings of Associates 2,090,497

Decrease in Interest Income (185,814))

Increase in Interest Expense (3,864,315)

Increase in Other Income 786,989

Higher Provision for Income Taxes (289,507)

Decrease in Non - controlling Interests 69,273

Total Growth 19,382,536

Consolidated Net Income Attributable to Equity Holders of the Parent for 2010 P25,041,117 The increase in Operating Revenues by 157% for 2010 versus that of 2009 is mainly due to the following: (1) the full year take up of revenues recognized from APRI’s operations in 2010 versus only four months in 2009; (2) full year operating revenues from the dispatch of the Pagbilao power plant by TLI; and (3) the revenues generated by newly acquired power barges of TMI and the newly operational hydro plants of Hedcor Sibulan. The revenues recognized by our consolidated distribution companies also managed to improve over prior years due to PBR rate adjustment granted last August 2010 for Davao Light and also due to growth in energy sales. At least 77% out of the total P15.60 bn increase in Operating Expenses can be attributed to the full year operations of TLI and the fresh take up of the operating expenses of newly acquired power barges under TMI. The remaining increase in Operating Expenses for the year can be attributed to (1) the full year operations of APRI and the operating expenses of recently operated Hedcor Sibulan; (2) the higher costs of purchased power for the distribution utilities in Mindanao, and (3) the cost of running the back-up power plants of the Mindanao distribution utilities in the first two quarters of this year to mitigate the impact of the power shortfall in their respective franchise areas. A significant improvement in Share in Net Earnings of Associates contributed P2.09 bn which represents an 82% increase compared to 2009. The largest contributing companies were SNAP-Magat and SNAP-Benguet, which benefitted from fresh inflow of revenues from their ancillary service contracts with NGCP for the period which were not yet fully in place for the same period last year. Both companies also saw marked improvement on their average selling prices to the electricity spot market. From the distribution segment, higher demand from its residential and industrial customers and additional margins brought about by rate adjustment in the second half of 2009 allowed VECO to increase its contributions to the Company’s Net Earnings of Associates. All the above positive contributions managed to offset a one-time refinancing cost of P398 mn incurred by STEAG in the third quarter. The Company started the year with lower cash balances as it deployed funds to various investing activities in the prior year. Over the course of the year, the Company managed to see a gradual buildup of cash but this still resulted to lower average cash balances over 2010 than in 2009. Hence the lower interest income recognized in 2010. This went down by 45% or P185.81 mn compared to 2009. The increase in Interest Expense for the year is primarily due to the interest expense recognized in TLI arising from the recognition of its IPPA contract as a finance lease. As a finance lease, incremental borrowing rates were used in order to recognize the asset and liability relating to the long term obligation. Correspondingly, the discount determined at the inception of the agreement is amortized


and recognized as interest expense. Although the recognition of the interest is a non-cash transaction, the interest expense recognized by TLI on its statement of income for the year on the finance lease was P5.12 bn or a 316% increase over the P1.23 bn expensed out in the previous year. New interest expense coming from debt raised at CPPC during the year as well as the recognition of interest expenses at Hedcor Sibulan as it went into commercial operations also contributed to the increase to this line item. The increase in Other Income of P786.99 mn to P1.60 bn from P813 mn from the previous year is mainly due to the unrealized foreign exchange gains recognized by TLI. TLI’s IPPA monthly payments to PSALM are composed of peso and dollar payments. The unrealized foreign exchange gain refers to the dollar component of these monthly payments. The Company’s considerable investing activities in the prior years has yielded the robust results which allowed net income before tax to grow by 306%. Provision for income tax meanwhile increased by a lower amount or 46% owing to tax holidays that were granted to recently contributing subsidiaries APRI, TLI, TMI and Hedcor Sibulan. Changes in Registrant’s Resources, Liabilities and Shareholders Equity Assets The Company’s assets grew by 21% from P111.34 bn ending 2009 to P134.56 bn ending 2010.

a) Cash & Cash Equivalents increased due to the following: (a) higher cash balances at AP Parent which grew by P11 bn due to significant cash upstreams from the various operating companies, mainly from APRI and TLI, during the year, (b) increase in TLI cash balances at year end. Cash and Cash Equivalents stood at P18.03 bn at year end after paying P2.21 bn in dividends during the year.

b) Trade & Other Receivables increased by 52% from P4.48 bn in 2009 to P6.81 bn in 2010. At least

61% of the increase is due to the higher Trade Receivables recognized by TLI which was higher by P1.42 bn. The rest of the increase is due to the recognition of new Trade Receivables at TMI which stood at P436 mn. Increases in this account was also true for APRI which had a net increase of P201 mn while the distribution subsidiaries Davao Light,Cotabato Light, MEZ and BEZ managed to increase Trade Receivables due to growth. Davao Light’s increase in this account can also be attributed to higher selling prices at year end from its PBR rate adjustment.

c) Derivative assets increased by P6.82 mn as AP Parent recognized derivative assets relating to

various non-deliverable short-term forward contracts with counterparty banks in order to manage its foreign currency risks associated with foreign currency-denominated liabilities and purchases.

d) The P735 mn increase in the Inventories account is in part due to the higher inventories held by

TLI as of year end, which was higher by P560 mn as it recognizes the higher cost of coal on its coal inventory. The remaining increase is due to the initial recognition of inventories held at TMI.

e) Other current assets grew by 87% owing primarily to recognition of input VAT at newly

operating subsidiary TMI.

f) Although the Property Plant and Equipment account went up by less than 2% versus prior years, it is worth mentioning that this account increased as a result of the acquisition of two power barges during the year by TMI. The barges were acquired for a total of P1.39 bn.


g) Due to invested capital expenditures into the service concession area of one of the Company’s

ecozone utilities, the Intangible Asset – service concession rights account increased by 6.2%

h) The increase in Investments and Advances to Associates by P4 bn is mainly due to the recognition of equity earnings of P4.63 bn as well as additional investment made into MORE to fund the rehabilitation projects of SNAP-Benguet and advances to RP Energy. This was likewise decreased by cash dividends received during the year as well as the redemption of preferred shares by EAUC. These factors combined, decreased the account by P1.16 bn.

i) Pension assets increased as a result of the one-time funding of the group’s past service

liabilities in 2010.

j) Deferred Tax Assets decreased by 20% primarily due to lower deferred tax assets recognized by AP Parent on its NOLCO, MCIT and Unrealized Foreign Exchange Gain.

k) Other Noncurrent Assets decreased by 20.68% primarily due to previously recorded restricted

cash in 2009 which was held to secure a long-term loan of an associate. The loan was fully paid in 2010 upon maturity and hence the restricted cash is no longer part of the Other Noncurrent Asset Account.

Liabilities Consolidated liabilities stayed relatively flat ending the year at P76.82 bn versus P76.29 bn in the previous year.

a) Bank Loans decreased by P3.85 bn as AP Parent supported by healthy cash upstreams from its subsidiaries managed to decrease bank loans by P3.60 bn.

b) Trade and Other Payables increased by 15.46% due to the first time consolidation of TMI’s

Trade Payables, which accounted for 76% of the increase, as well as higher Trade and Other Payables at year end for TLI.

c) Derivative liabilities decreased by P16.15 mn as previously recognized marked to market losses

on foreign currency forwards entered into by AP Parent and TMI did not recur as of year end. Current forward contracts in place are by AP Parent which now stands as Derivative Assets as of year end.

d) As of end 2009, TLI recognized P233 mn in income taxes payable on its books. After being

granted a tax holiday for four years commencing January 1, 2010, this liability did not recur year end 2010 hence the decrease in this account by 50.81% or P185.56 mn. The net change is owing to higher taxes payable at year-end for the other subsidiaries who are not on tax holiday.

e) Long-term Debt remained at about the same levels as of year-end 2009 as no new significant

Long Term Debt was entered into during the year except for the recent availment of an P800 mn 3-year corporate notes by CPPC under a Notes Facility Agreement entered into in January 2010.

f) Total Finance Lease obligations at year-end 2010 increased by 6%. Monthly payments on this

obligation exceeds monthly interest expense recognized hence the increase noted at year end.


g) Payable to Preferred Shareholder of a Subsidiary went down by 13% as annual payments were timely made to preferred shareholders

h) An increase in Customer’s Deposit of 12.54% or P223.27 mn was mainly due to new connections

in the franchise areas of Davao Light as it continued to see robust growth in its customer base. Davao Light’s increase in customer deposits make up 74% of the total increase. The balance comes from increased customer deposits of Cotabato Light, MEZ, and SEZ as well as from APRI and TLI on their bilateral contracts.

i) Pension liability decreased during the year as obligations were funded during the year. j) Deferred Income Tax Liability increased by 745% due to the recognition of Deferred Tax

Liability at TLI on unrealized foreign exchange gains on its dollar obligations to PSALM, past its’ tax holiday period.

Equity Equity attributable to equity holders of the parent increased from P34.48 bn as of December 2009 to P57.33 bn as of December 2010. This is mainly driven by the Net Income recorded for the year of P25.04 bn. The Company declared dividends of P0.30 per share to all shareholders of record as of March 24, 2010, which was paid last April 16, 2010. Material Changes in Liquidity and Cash Reserves of Registrant After significant investing activities made in 2009 that brought down the Company’s cash reserves down to P3.81 bn by year end, 2010 marked a period of cash build up for the Company as it realized the rewards on investments made. These investments brought up cash balances to P18.30 bn at year end 2010. Out of the total Net Cash flow from Operating Activities of P27.28 bn, P26 bn comes from Income Before Income Tax recognized for the year. Robust income most especially from newly operating business units provided the healthy streams of cash from operations. Net cash used in investing activities was P4.37 bn compared to P23.95 bn for the same period last year. The cash used in investing activities went to the increases in Power Plant and Equipment invested in TMI and Hedcor Sibulan and more outlays related to the funding of the rehabilitation projects of SNAP-Benguet and advances to RP Energy. This was supplemented by dividends received during the year of P1.82 bn. Cash was used in various financing activities this year totalling P8.36 bn versus a net cash inflow last year of P7.72 bn. These financing activities relate to the payment of short term debt at AP Parent of P3.60 bn, dividends paid to shareholders of P2.21 bn, monthly payments made by TLI to PSALM during the year of P1.12 bn as well as interest paid on long term debt of P1.62 bn. All of the above mentioned activities resulted to a net cash inflow for the year of P14.55 bn bringing up cash and cash equivalents by year end to P18.30 bn versus P3.81 bn in 2009. Financial Ratios Current ratio increased by 1.90, from 0.68x as of December 2009 to 2.58x in December 2010. This was due to the marked increase in cash which shored up current assets. The ratio also improved due to the decrease in current liabilities as a significant amount of short term debt was paid during the year.


With liabilities remaining flat and equity increasing due to the healthy results of operations, during the year, the debt-to-equity ratio improved from 2.18 ending 2009 to 1.33 ending 2010. Outlook for the Upcoming Year/ Known Trends, Events, Uncertainties which may have Material Impact on Registrant Notwithstanding external and uncontrollable economic and business factors that affect its businesses, AboitizPower believes that it is in a good position to benefit from the opportunities that may arise in the current year. Its sound financial condition, coupled with a number of industry and company specific developments, should bode well for AboitizPower and its investee companies. These developments are as follows: Generation Business 1. Continued growth in the Company’s attributable capacity AboitizPower ended the year 2010 with an 18% YoY expansion in its total attributable generating capacity, from 1,745 MW to 2,051 MW. The capacity growth was mainly due to the following:

- Takeover of the two barge mounted diesel powered generation plants, each with a generating capacity of 100 MW

AboitizPower, through wholly owned subsidiary TMI assumed ownership of PB 118 and PB 117 on February 6, 2010 and March 1, 2010, respectively. PB 118 is a power barge with a 100 MW bunker-fired generating facility moored at Bgy. San Roque, Maco, in Compostella Valley, Mindanao, while PB 117 is a power barge with a 100 MW bunker-fired generating facility moored at Bgy. Sta. Ana, Nasipit, Agusan del Norte, Mindanao.

AboitizPower acquired both power barges on July 31, 2009 via a successfully concluded negotiated bid with PSALM. The total purchase price for both barges is USD30 mn. TMI has Ancillary Services Procurement Agreements with the NGCP. In 2010, TMI signed bilateral contracts with various distribution utilities covering approximately 75 MW in contracted capacity. These contracts are awaiting ERC approval.

- Completion of Greenfield power plant developments

42.5 MW Hedcor Sibulan Hydro Power Plant Project. This is a Greenfield run-of-river hydro power plant located in Barangay Sibulan, Sta. Cruz, Davao del Sur by AboitizPower’s 100% owned subsidiary Hedcor Sibulan. The facilities, which comprise two cascading hydropower generating facilities tapping the Sibulan and Baroring rivers, are expected to generate an estimated 212 mn kWh of clean and emissions-free energy annually. Plant B, which has a capacity of 26 MW, commenced its operations in May 2010, while Plant A, which has a capacity of 16.5 MW, was completed in July 2010.

246 MW Cebu coal-fired Power Plant. The 3x82 MW coal-fired power plant in Toledo City, Cebu, which is a joint venture with Metrobank Group’s Global Business Power Corporation and Cebu-based Vivant Energy Corporation of the Garcia Group, was completed in 2010. Two units with a capacity of 82 MW each have started generating and feeding power into the Visayas Grid in February and May 2010. Construction of the last unit was completed in the fourth quarter of 2010. AboitizPower has an effective participation of 26% in the project.


Moving forward, AboitizPower’s attributable capacity is seen to further increase as the following events take place:

- Rehabilitation of the Ambuklao-Binga hydro power facilities

The Company, together with its partner SN Power, is pursuing the programmed rehabilitation of both the 75 MW Ambuklao and 100 MW Binga hydro facilities. Completion of the rehabilitation of the former has been delayed due to the construction of a new headrace tunnel (HRT). Difficulties were encountered in completing the plugging of the existing plant HRT due to the unexpectedly larger quantity of sediments (silt and clay) in the facility compounded by the effect of Typhoon Pepeng that hit the country in 2009. The plant’s rehabilitation works are expected to be completed by the third quarter of 2011, when all three units are operating, instead of end-2010 as earlier estimated. After the rehabilitation, the Ambuklao plant will have a capacity of 105 MW of renewable energy that will significantly augment supply of electrical power to the Luzon Grid. Rehabilitation works on Binga will commence in 2011, performing works on one unit per year. Completion of rehabilitation of all four units is expected by 2014, which should enhance generating capacity by 20%, to 120 MW.

- Completion of the rehabilitation of the Tiwi-Makban geothermal power facilities

100%-owned APRI is currently undertaking the rehabilitation of several units of the Tiwi-Makban geothermal power plant complex. Once completed, generation capacity and plant availability are expected to improve. At present, the Tiwi-Makban geothermal power plants have a combined estimated generation capacity of 467 MW, which is based on the plants’ peak generation in 2009. AboitizPower reckons that after completion of the rehabilitation works, generation capacity could increase to approximately 484 MW, which takes into account current steam supply and decline rates. Completion of works will be in stages, with Tiwi plants estimated to be finished by second quarter of 2011, while Makban plants by first quarter of 2012.

- Greenfield and Brownfield developments

300 MW coal-fired Power Plant in Subic. After revisiting the power demand and supply situation in the Luzon Grid, 50%-owned RP Energy has decided to pursue its 300 MW coal-fired power plant project in the Subic Bay Freeport Zone (the Subic Coal Project). After re-evaluating the project, RP Energy is contemplating of increasing the planned generating capacity of the Subic Coal Project to 600 MW. The company is in talks with prospective turnkey contractors for the Engineering, Procurement and Construction contract for the project. Construction period is estimated at 36 months.

300 MW coal-fired Power Plant in Davao. AboitizPower is planning to put up a 2x150MW coal-fired power plant in Davao, which is the biggest load center in the island of Mindanao. The Company is in the process of obtaining the necessary permits and government clearances. AboitizPower has already identified a location in Davao and has successfully negotiated a lease with an option to purchase. The Company has engaged engineering and environmental consultants that have initiated physical and environmental data collection. Once completed, together with all the necessary permits and approvals, construction is expected to be completed in 36 months.

150 MW Coal-fired Power Plant in Misamis Oriental. On June 28, 2010, AboitizPower and its partners in STEAG owner of the 232 MW coal plant located at the Phividec Industrial Estate in Villanueva, Misamis Oriental, firmed up their collective intention to develop a third unit of


approximately 150 MW capacity adjacent to the existing facility. AboitizPower and its partners agreed to maintain their shareholdings in the same proportions in the new corporation to be established for the planned additional capacity. Certain essential facilities, such as the jetty, coal handling facilities and stockyards and the 138-kV interconnection with the Mindanao Grid are to be shared with the existing facilities. Depending on the interest the market demonstrates, the agreement contemplates the possibility of another unit.

13.6 MW Tudaya 1 and 2 Hydro Power Plant Project. Wholly owned subsidiary Hedcor Tudaya will implement a greenfield project involving the construction of run-of-river power plants to be located in the upper and downstream sections of the existing Sibulan hydro power plant, tapping the same water resource, which are the Sibulan and Baroring rivers. The two plants will have a combined capacity of 13.6 MW. Hedcor Tudaya is currently working on obtaining the water permits and environmental clearances. Target groundbreaking is by third quarter of 2011. Construction is estimated to be completed in 20 months.

11.5 MW Hedcor Tamugan Hydro Power Plant Project. In 2010, wholly owned subsidiary, Hedcor Tamugan, has reached an agreement with the DCWD on the use of the Tamugan river. Originally planned as a 27.5 MW run-of-river facility, Hedcor Tamugan submitted a new proposal, which involves the construction of an 11.5 MW hydropower plant. Hedcor Tamugan is waiting for the City council to approve the project. Once approval and permits are secured, the two-year construction period will commence.

Other Greenfield and Brownfield developments. AboitizPower, together with its subsidiaries and associate company, is conducting feasibility studies for potential Greenfield and Brownfield projects.

• The SNAP Group is in the process of evaluating several hydropower plant projects. A

Brownfield project is being evaluated for its Magat hydropower plant, which involves the construction of a pumped storage that could potentially increase its capacity by at least 90 MW. The SNAP Group is likewise evaluating several Greenfield hydropower plant projects that have at least 70 MW of potential capacity each.

• 100%-owned subsidiary Hedcor is conducting feasibility studies for potential

hydropower projects located in both Luzon and Mindanao. Based on current findings, Hedcor sees the potential of building 5-50 MW plants in the identified areas. The feasibility studies are expected to be completed in two years. Once permits are secured, another two years will be needed for the actual construction of the hydro facilities.

2. Participation in the Government’s Privatization Program for its Power Assets The Company continues to closely evaluate the investment viability of the remaining power generation assets that PSALM intends to auction off. AboitizPower is also keen on participating in PSALM’s public auction for the IPP Administrator contracts, which involves the transfer of the management and control of total energy output of power plants under contract with NPC to the IPP administrators. Distribution Business The Company remains optimistic that it will realize modest growth on its existing distribution utilities. It continually seeks efficiency improvements in its operations to maintain healthy margins.


The implementation of the rate adjustment formula for the distribution companies under the performance-based regulation (PBR) is on a staggered basis. In addition to annual adjustments, PBR allows for rate adjustments in between the reset periods to address extraordinary circumstances. There is also a mandatory rate-setting every four years wherein possible adjustments to the rate take into account current situations. Cotabato Light’s 4-year regulatory period commenced on April 1, 2009 and ends on March 30, 2013. The ERC issued its final determination on Cotabato Light’s application for approval of its annual revenue requirement and performance incentive scheme under the PBR scheme covering the second year of the 4-year regulatory period. Last December 2010, Cotabato Light submitted for ERC approval its rate translation adjustments covering the third year of its regulatory period. Cotabato Light is the first distribution utility in the AboitizPower group to implement this incentive-based scheme. VECO and Davao Light are part of the third group (Group C) of private distribution utilities to shift to PBR. Both VECO and Davao Light started to implement their PBR approved rate structures in August 2010. Both companies are now preparing to file with the ERC for their rate translation adjustments for the second year of its 4-year regulatory period. SFELAPCO and SEZ are part of the fourth batch (Group D) of private distribution utilities to enter PBR. For SFELAPCO and SEZ, the regulatory reset process is on its final stages and ERC is scheduled to release before the end of March 2011 its draft determination on the applications for annual revenue requirements and performance incentive schemes for the regulatory period October 2011 to September 2015. The draft determination will be subjected to public consultations before ERC releases its final determination on June 2011. Thereafter, SFELAPCO and SEZ will be filing their respective rate design applications for the first regulatory year to be implemented from October 2011 to September 2012. The Company’s strategy in running its utilities is one of providing world-class service at the least possible cost. Providing value to its customers allows the Company credibility and the ability to successfully implement justified rate increases. This, along with a transparent and open relationship of over 70 years with the regulators, ensures the Company’s continued ability to successfully apply and implement rate increases. Market and Industry Developments Open Access and Retail Competition Per EPIRA, the conditions for the commencement of the Open Access and Retail Competition are as follows:

(a) Establishment of the WESM; (b) Approval of unbundled transmission and distribution wheeling charges; (c) Initial implementation of the cross subsidy removal scheme; (d) Privatization of at least 70% of the total capacity of generating assets of NPC in

Luzon and Visayas; and (e) Transfer of the management and control of at least 70% of the total energy

output of power plants under contract with NPC to the IPP administrators. As of date, the government was able to comply with the first four conditions for the implementation of Open Access and Retail Competition. Privatized NPC generating assets in Luzon and Visayas have reached approximately 92%. The only remaining condition that has to be met is the privatization of at least 70% of NPC’s IPP contracts, which currently stands at approximately 68%.


Under the Open Access and Retail Competition, an eligible contestable customer, which is defined as an end-user with a monthly average peak demand of at least 1 MW for the preceding 12 months, will have the option to source their electricity from eligible suppliers that have secured a Retail Electricity Supplier license from the ERC. Eligible suppliers shall include the following:

- Generation companies that own, operate or control 30% or less of the installed generating capacity in a grid and/or 25% or less of the national installed capacity

- NPC-Independent Power Producers with respect to capacity which is not covered by

contracts

- IPP Administrators with respect to the uncontracted energy which is subject to their administration and management

- Retail Electricity Suppliers (RES) duly licensed by the ERC

The implementation of the Open Access presents a big opportunity for AboitizPower, as it has two wholly owned subsidiaries (i.e. Aboitiz Energy Solutions, Inc. and AdventEnergy, Inc.) that are licensed retail suppliers, which can enter into contracts with the eligible contestable customers. Moreover, AboitizPower’s generation assets that have uncontracted capacity will be able to have direct access to eligible contestable customers through AboitizPower’s licensed RES. Year ended December 31, 2009 vs. Year ended December 31, 2008 The table below shows the comparative figures of the top five key performance indicators for 2009 and 2008. DISCUSSION ON KEY PERFORMANCE INDICATORS:

Key Performance Indicators 2009 2008 Amounts in thousands of πs, except for financial ratios SHARE IN NET EARNINGS OF ASSOCIATES 2,535,386 2,784,511EBITDA 9,866,532 5,406,974CASH FLOW GENERATED: Net cash flows from operating activities Net cash flows (used in) investing activities Net cash flows from financing activities

5,873,633 (23,953,482)

7,721,594

1,905,394 (5,787,844)

5,049,159 Net Increase (Decrease) in Cash & Cash Equivalents (10,358,255) 1,166,709 Cash & Cash Equivalents, Beginning 14,333,676 12,706,103 Cash & Cash Equivalents, End 3,814,906 14,333,676 CURRENT RATIO 0.68 2.12 DEBT-TO-EQUITY RATIO 2.18 0.54

Above key performance indicators are within management expectations. The Company’s Share in Net Earnings of Associates is slightly behind last year’s results primarily due to the lower contributions from STEAG, operator of a 232-MW coal plant in Misamis Oriental, as it felt the impact of the decrease of a major index in its pricing formula which went down this year versus last year. The positive effects brought about by the income contribution of the Company’s new acquisitions


during the year has vastly improved the Company’s EBITDA which is up 82% versus the prior year. The EBITDA contributions from the geothermal assets under APRI starting May 2009 and the EBITDA contributions arising from the TLI IPPA for the coal plants in Pagbilao which started in October 2009 were the main drivers of the increase in EBITDA. Current ratio decreased due to the decrease in the Company’s Consolidated Cash as capital got invested into various acquisitions made during the year. To further augment the capital needed for its investment activities, the Company entered into various capital raising activities which increased its debt to equity ratio. Financial Results of Operations The Company’s net income for 2009 grew by 31% to P5.77 bn from P4.42 bn for the same period last year. This lifted earnings per share to P0.77 for the year ending December 31, 2009 versus an earnings per share of P0.59 ending December 31, 2008. The power generation business improved its contributions by 68% from prior year as it shored in a net income contribution of P4.66 bn from last year’s P2.78 bn. The primary contributor to this year’s impressive earnings is APRI, as it took over in May 2009 the geothermal facilities in Tiwi-MakBan from PSALM. On its first year of operations APRI manage to contribute 44% of the total income contribution of the generation group. Total power sold by the Generation Companies for the period grew by 167% year-on-year (YOY) from 1,728 GWh to 4,619 GWh. As of end-2009, AboitizPower’s power generation group had an attributable capacity of 1,745 MW, a 202% YOY increase from end-2008. It is this increase in attributable capacity resulting from the acquistions of APRI (467 MW) and the IPPA of TLI for Pagbilao (700 MW) which has led to the surge in generation sold by the Generation companies. The Distribution Companies’ income contribution improved by 6% or P1.57 bn, from last year’s P1.48 bn. The Distribution Companies’ kilowatt-hour electricity sales for the period grew by 6% YOY, from 3,142 GWh to 3,322 GWh. The healthy growth particularly that of AboitizPower’s major distribution utilities, Davao Light and VECO-was observed to be coming from both its residential and commercial/industrial customers.


Material Changes in Line Items of Registrant’s Income Statement Consolidated net income attributable to equity holders grew by P1.32 bn or 31%. Below is a reconciliation of growth in the consolidated net income:

Consolidated Net Income Attributable to Equity Holders of the Parent for 2008 P4,333,613Increase in Operating Revenues 10,931,285 Increase in Operating Expenses (7,127,623)Decrease in Share in Net Earnings of Associates (249,126) Decrease in Interest Income (197,568) Increase in Interest Expense (2,435,442)Increase in Other Income 436,719Higher Provision for Income Taxes (12,806)Increase in Minority Interests (20,471)Total Growth 1,324,968 Consolidated Net Income Attributable to Equity Holders of the Parent for 2009 P5,658,581

Consolidated Operating Revenues increased by 89% versus last year. The increase in consolidated revenue is accounted for by the new revenue contributions by TLI since the turnover of dispatch control of the 700-MW Pagbilao plant in October 2009 and the revenue contributions from APRI geothermal plants that were turned over in May 2009. The revenues from these plants combined make up close to 90% of the increase in consolidated revenue. The remaining increase is attributable to the higher revenue brought about by growth and higher passed on generation costs by the distribution utilities. As expected, as the operations of the new acquisitions are folded in, a corresponding increase in costs and expenses followed which increased operating expenses by 67% over last year. The costs and expenses of TLI and APRI, account for 83% of the increase while 11% of the increase was brought about by higher operating expenses at Davao Light due to higher purchased power costs. The decrease in the share in equity earnings for the year is due to the lower contributions from STEAG, operator of a 232-MW coal plant in Misamis Oriental, as it felt the impact of the decrease of a major index in its pricing formula which went down this year versus last year. Share in net earnings of associates fell by 9% compared to last year or a total of P249 mn. As the Company’s cash is deployed to various investing activities, the interest income compared to prior years has gone down by 33% or P197.57 mn. Interest expense also increased by 643% due to the various debt raising acitivites entered into by the Company namely: 1) Fixed Rate Note of 5-year peso-denominated corporate fixed rate notes (Notes) in the aggregate amount of P5 bn. The Notes were issued in September 2009, 2) a total of P3 bn worth of peso-denominated fixed rate retail bonds issued last April 2009, 3) P3.89 bn in 5-year and 7-year peso-denominated corporate fixed rate notes issued last December 2008, 4) higher short-term bank loans. Another transaction that led to the increase of the interest expense for the year is the effect of TLI’s IPPA which was accounted for as a finance lease. As a finance lease, incremental borrowing rates were used in order to recognize the asset and liability relating to the long-term obligation. Correspondingly, the discount determined at the inception of the agreement is amortized and recognized as interest expense. Although the recognition of the interest is a non-cash transaction, the interest expense recognized by TLI on its statement of income for the year on the finance lease was P1.23 bn. Other Income increased by P436.72 bn mainly due to the unrealized forex gains recognized by TLI on


future minimum dollar payments to PSALM as part of its IPPA agreement. As a result of the foregoing, income before income tax increased by P1.36 bn or 27% from P5.04 bn in the previous year to P6.40 bn in the current year. Provision for taxes ending 2009 increased by 2% to P631.19 mn from a prior period provision of P618.38 mn. Changes in Registrant’s Resources, Liabilities and Shareholders Equity Assets Compared to year-end 2008 levels, consolidated assets increased by 136%, from P47.27 bn in December 2008 to P111.34 bn in December 2009 due to the following:

a) Cash & Cash Equivalents was at P3.81 bn, down by 73% from year-end 2008 level of P14.33 bn (as restated). Through the debt-raising activities entered into by AP Parent, total cash raised reached close to P11 bn. A significant portion of the Company’s cash was then deployed to APRI thru PHC to fund the full payment for the geothermal assets from PSALM. The total purchase price for these assets totalled close to P21 bn. In 2009, cash was also used to pay shareholder dividends totalling P1.47 bn.

b) Trade & Other Receivables increased by 125%, from P1.99 bn to P4.48 bn due to the

consolidated trade and other receivables of both TLI and APRI totalling P2.53 bn.

c) Inventories increased by 234% due to APRI’s supplies and materials as well as coal inventory held by TLI.

d) The asset account for Property, Plant and Equipment considerably increased by 1065% from

P6.26 bn in 2008 to P72.90 bn. APRI’s newly acquired geothermal property, plant and equipment account for P19.91 bn, while TLI’s finance lease recognition of the power plant and equipment on the Pagbilao assets added another P44.52 bn. The balance of the increase is due to the construction in progresss of the hydro plants being built by Hedcor Sibulan.

e) Investments in and Advances to Associates increased by 17% or a total of P3.55 bn due to

additional investments in associates of P1.34 bn for a coal plant being constructed in Toledo, Cebu, and the recognition of equity earnings of P2.54 bn.

f) Increase of 283% in Pension Assets resulting from actuarial adjustments for Davao Light and

CPPC which lead to the increase.

g) Deferred Income Tax Assets increased by P183.43 mn or 276% primarily due to unrealized foreign exchange losses on dollar cash holdings and Net Operating Loss Carryover (NOLCO) recognized by AP Parent during the year.

h) Other Noncurrent Assets increased by 132% or P879.62 mn due to prepaid rent of P460.87 mn

mostly on advance payment of land rental to PSALM by APRI and the build up of Input Vat Receivable due to the construction of a hydropower plant by Hedcor Sibulan.

Liabilities Consolidated liabilities increased to a total of P76.29 bn, a 360% increase over year-end 2008 level. The following were the reasons for the increase:


a) Bank Loans increased by 21% or P1.03 bn due to AP Parent’s availment of a short-term bank

loan to support its investment activities.

b) Trade and Other payables increased by 91% from P3.15 bn in 2008 to P6.02 bn ending 2009 due to the first-time consolidation of both APRI and TLI trade payables and accruals.

c) The first-time recognition of Derivative Liabilities of P16.48 mn represents the booking of

marked to market losses on foreign currency forwards entered into by AP Parent and TMI.

d) Income Tax Payable increased by 349% or P283.79 mn due to TLI’s recognition of income tax payable for the year.

e) Long-term Debts were increased by 149% or P9.73 bn versus year-end 2008 level by the

following: 1) Fixed Rate Note of 5-year peso-denominated corporate fixed rate notes (Notes) in the aggregate amount of P5 bn. The Notes were issued in September 2009 2) a total of P3 bn worth of peso-denominated fixedrate retail bonds issued last April 2009. The proceeds from these debt-raising activities were invested into the acquisition of the geothermal assets of APRI. The remaining increase is because of additional loan drawdowns made by Hedcor Sibulan to finance the construction of its Sibulan hydropower project.

f) A new liability account this year is the account - Finance Lease Obligation. The Pagbilao

IPPA agreement between PSALM and TLI was deemed a finance lease. As a finance lease the lease is conceived to be a purchase of an asset requiring the recognition of an asset (booked under property, plant and equipment) and a corresponding liability. The amount recognized as of end 2009 as Finance Lease Obligation is P45.59 bn.

g) An increase in Customers’ Deposits of 13% or P210.02 mn was due to new connections

mainly in the franchise areas of Davao Light as it continues to see robust growth in its customer base. Davao Light’s increase in customer deposits makes up 83% of the total increase. The balance is coming from increased customer deposits from Cotabato Light, SEZ and APRI.

h) Payable to Preferred Shareholder of a Subsidiary went down by 9% as annual payments

were timely made to preferred shareholders.

i) Pension liability increased by 95% or P13.69 mn due to the recognition of pension obligations of newly consolidated company APRI and an increase in pension liabilities at Hedcor, Inc., Cotabato Light and AP Parent.

j) Deferred Income Tax Liability decreased by 36% or P21.02 mn due to the realization of forex

transactions in 2009 for AP parent that previously warranted the booking of the deferred tax liability in the previous year.

Equity Equity attributable to equity holders of the parent increased by 14% from P30.16 bn as of December 2008 to P34.48 bn as of December 2009. This was mainly due to the consolidated net income of P5.77 bn, an upward adjustment in share in cumulative translation adjustments of associates of P133.67 mn and after a cash dividend payment of P1.47 bn in the first quarter of 2009. The Company declared dividends of P0.20 per share to all shareholders of record as of February 26, 2009. This was paid on March 23, 2009. Material Changes in Liquidity and Cash Reserves of Registrant


As of December 31, 2009, the Group’s cash reserves ended with a balance of P3.81 bn a 73% decrease from its balances as of December 31, 2008 of P14.33 bn (as restated). This was after major investing and financing activities conducted during most of the year. Net cash from operating activities brought in P5.87 bn this year compared to net cash inflow of only P1.91 bn for the same period last year. The higher income before income tax of P6.40 bn is the primary driver of the increase. Net cash used in investing activities was P23.95 bn compared to P5.79 bn for the same period last year. The primary investing activity for the period was the purchase of the geothermal assets of Tiwi-MakBan from PSALM, for P20 bn. The construction in progress by Hedcor Sibulan for its hydro plant in Mindanao is still ongoing adding another P1.91 bn in cash used for investing activities. Another P1.34 bn went to the construction of a coal plant in Toledo, Cebu. Net cash from financing activities for the period in review was P7.72 bn, which was mainly the net result of inflows of long-term debt in the amount of P9.76 bn, of which AP Parent raised fixed rate notes of P5 bn and P3 bn in corporate bonds. There was also an increase in long term debt relating to the Hedcor Sibulan project as more draw downs were made in 2009. Short-term loans from banks of P1.14 bn were availed of by AP parent as part of the purchase for the geothermal assets, and by subsidiaries to fund working capital requirements. There were also cash outflows for the P1.47 bn dividend payout in the first quarter of 2009 as well as interest paid during the period totalling another P1.47 bn. The Company finished the year with net cash outflows of P10.36 bn. The cash and cash equivalents for the period ending December 31, 2009 was P3.81 bn versus cash and cash equivalents as of December 31, 2008 of P14.33 bn (as restated). This is consistent with management’s plan of raising capital and to deploy cash raised from these activities to acquire existing power facilities and develop Greenfield projects as well as to improve its generation and distribution facilities. Financial Ratios Current ratio decreased by 1.44, from 2.12x as of December 2008 (as restated) to 0.68x in December 2009. This was due to the marked decrease in cash used to finance investment activities although the recognition of trade receivables and inventory buffered the decrease in cash. This was also brought down by the increase in current liabilities due to higher bank loans incurred in 2009 to fund working capital requirements and due to higher trade and other payables as well as the recognition of the current portion of the Finance Lease Obligation. The use of the cash raised from the capital raising activities during the year is consistent with the Company’s long-term plan of improving shareholder value by deploying capital into high yielding investments. Debt-to-equity ratio increased from 0.54 as of December 31, 2008 to 2.18 as of December 31, 2009 as AboitizPower raised debt to fund its various investing activities. Year ended December 31, 2008 vs. Year ended December 31, 2007 DISCUSSION ON KEY PERFORMANCE INDICATORS:

Key Performance Indicators 2008

(As restated) 2007

(As restated)


Amounts in thousands of πs, except for financial ratios SHARE IN NET EARNINGS OF ASSOCIATES 2,784,511 2,803,833EBITDA 5,406,974 5,584,406CASH FLOW GENERATED: Net cash flows from operating activities Net cash flows (used in) investing activities Net cash flows from financing activities

1,905,394 (5,787,844)

5,049,159

4,040,389 (8,644,866)

16,613,532 Net Increase in Cash & Cash Equivalents 1,166,709 12,009,055 Cash & Cash Equivalent, Beginning 12,706,103 912,564 Cash & Cash Equivalent, End 14,333,676 12,706,103CURRENT RATIO 2.12 2.43DEBT-TO-EQUITY RATIO 0.54 0.32 Above key performance indicators are within management expectations. Earnings contributions of power assets acquired in 2007 remained significant contributors to the equity net earnings compared to amounts recorded in the same period last year. The year 2008 ended with incremental contributions from the full year contributions of these companies with the largest incremental contribution coming from STEAG, which contributed P1.09 bn. From the full year income of EAUC, also a recent acquisition, came an incremental contribution of P112 mn. LHC, an existing investment, also contributed P540.25 mn in additional earnings, most of which came from the reversal of accrued costs and tax provision following the settlement of the dispute with Transfield, the turnkey contractor of LHC’s Bakun Plant. The incremental contributions mentioned above were offset by the effects of the weakening currency leading to non-recurring forex losses on some other investees. Both SNAP-Magat and SNAP-Benguet were impacted by the weaker peso, which resulted in a huge swing from unrealized forex gains for the two companies in 2007 to unrealized forex losses in 2008. Notwithstanding the effects of the exchange rate fluctuations on its bottom line, SNAP-Benguet managed to contribute in operating terms following the turnover of the Ambuklao-Binga plants in July 2008. The Company’s EBITDA is lower by 3% YOY. The positive effects brought about by the income contribution of the Company’s new acquisitions as well as its prudent spending failed to translate into a higher EBITDA due to non-recurring forex losses from the effects of a weakened peso. The decrease in the current and other financial ratios was a consequence of improved utilization of capital. This is apparent in the increase in the investments made by the Company during the year versus investments made as of year-end 2007. This is consistent with the Company’s long-term plan of improving shareholder value by deploying capital into highyielding investments. The Company continues to evaluate the investment viability of the remaining power generation assets that the PSALM intends to auction off. The financial figures presented are in compliance with the requirements/comments made by the SEC’s Office of the General Accountant in its letter to AboitzPower dated February 3, 2009 and which letter AboitizPower replied to on February 18, 2009. To address the SEC’s comments on the completeness of the Segment Reporting Disclosure in the December 2007 financial statements, Note 25 in the accompanying audited financial statements as of December 31, 2008 has endeavored to disclose the basis of inter-segment revenues. As disclosed in the notes to the financial statements, inter-segment revenues, are in the form of management fees as well as inter-segment sales of electricity which are eliminated in consolidation. The transfers are accounted for at competitive market prices on an arms length transaction basis. The Company has not allocated or transferred revenues or expenses among its segments. On the disclosure relating to Business Combination, Note 7 on the accompanying audited financial


statements as of December 31, 2008, the Company has disclosed the profit or loss on companies acquired in 2007 from date of acquisition that is included in the Company’s profit or loss for the period. On the accompanying audited financial statements, the Company has disclosed that from the date of acquisition in April 2007 to December 31, 2007, CPPC contributed P162.6 mn to the net income of the Group. Another acquisition in 2007, EAUC contributed P61.6 mn. STEAG, which was acquired in the last quarter of 2007 contributed P94.8 mn. In the December 31, 2007 financial statements of the Company, Note 29 referred to a Davao Light refund obligation as a result of an adverse decision rendered by the Supreme Court. The amounts were disclosed in Davao Light’s financial statements as immaterial. The estimated amount due for refund to Davao Light’s customers is P4.08 mn, which is disclosed under Note 31 Other Matters on the accompanying audited financial statements for the year ending December 31, 2008. Financial Results of Operations The Company’s net income for 2008 grew by 3% to P4.42 bn from P4.28 bn for the same period last year. This translates to an earnings per share of P0.59 for the year ending December 31, 2008 versus an earnings per share of P0.66 ending December 31, 2007. Earnings per share fell by 11% due to the higher number of outstanding shares as of ending 2008 compared to year ending 2007. The Distribution Companies brought in an income contribution of P1.48 bn, which was lower by 3% from last year’s P1.52 bn. The drop in income contribution is due to higher operating costs on the larger distribution utilities which outpaced any increases brought in by the slower growth. The Distribution Companies’ kilowatt-hour electricity sales for the period grew by 13% year-on-year, from 2,789 GWh to 3,142 GWh. The growth mostly came from the contributions arising from the 2007 acquisitions and the expansion of SEZ’s industrial segment, mainly due to the operation of the Hanjin shipyard in SBFZ. The power generation business shored in a net income contribution of P2.78 bn, recording an 6% YOY growth from last year’s P2.61 bn. The growth is attributed to the incremental earnings contributions from the 2007 acquisitions, with a major contribution coming from the 232-MW STEAG coal power plant. Total power sold by the Generation Companies for the period recorded a 70% YOY expansion, from 1,018 GWh to 1,728 GWh. As of end-2008, AboitizPower’s power generation group had an attributable capacity of 578 MW, an 18% YOY increase from 2007. The increase was due to the turnover of the 175-MW Ambuklao-Binga hydro power plants in July 2008. Moreover, improved capacity factors of the hydroelectric plants due to higher rate of rainfall also led to the improvement in the power generation for the period.


Material Changes in Line Items of Registrant’s Income Statement Consolidated net income attributable to equity holders grew by P172.97 mn or 4%. Below is a reconciliation of growth in the consolidated net income:

Consolidated Net Income Attributable to Equity Holders of the Parent for 2007 P4,160,645 Increase in Operating Revenues 930,989 Increase in Operating Expenses (1,261,818)Growth from Share in Net Earnings of Associates (19,321) Increase in Interest Income 276,627 Increase in Interest Expense (181,034)Increase in Other Income 387,844 Lower Provision for Income Taxes 15,949Decrease in Minority Interests 23,732Total Growth 172,968 Consolidated Net Income Attributable to Equity Holders of the Parent for 2008 P4,333,613

Total consolidated operating revenues grew by 8% versus the same period last year. The distribution subsidiaries’ consolidated revenues increased by P430.19 mn, a 5% increase for the period. The combined revenues of the Enerzone companies recent acquisitions MEZ and BEZ as well as SEZ - as a group grew by 36%. On the other hand, the consolidated revenues of the power generation business recorded a strong growth of 19% or P485.9 mn. As in the year 2007, CPPC’s contribution to 2008 consolidated revenue is the sole reason for the increase in this segment’s increased revenue. The increase in CPPC’s revenue contribution is attributed to its full-year contribution compared to only seven months revenue contribution for the year 2007. CPPC’s revenue contribution for 2008 also rose as against 2007 level due to the higher cost of fuel which is passed on as part of its tariffs. The 14% or P1.26 bn increase in consolidated costs and expenses was primarily due to the additional cost of CPPC’s generated power. The higher cost of power purchased by SEZ, MEZ and BEZ also added to the increase. Share in net earnings of associates came in almost flat for the full year 2008 at P2.79 bn versus P2.80 bn in 2007. The P1.09 bn income contribution of STEAG cushioned the impact of the decrease in MORE’s consolidated net income as a result of the decreased contribution of its subsidiaries, SNAP-Magat and SNAP-Benguet. Both SNAP-Magat and SNAP-Benguet were impacted by the weaker Peso, which resulted in a huge swing from unrealized forex gains for the two companies in 2007 to unrealized forex losses in 2008. Notwithstanding the effects of the exchange rate fluctuations on its bottom line, SNAP-Benguet managed to contribute in recurring operating terms following the turnover of the Ambuklao-Binga plants in July 2008. EAUC, another recent acquisition, made a full-year contribution of P112.19 mn. Interest income increased by 84%. The increase in interest income was due to the income earned on interest on the significant cash balances carried by parent through most of the year compared to 2007 where interest income from cash raised during the IPO proceeds came in for only half of the year. Interest expense also increased by 92% due to the full-year effect of a short-term loan versus only two months of interest expense on this loan for 2007. Other Income increased by P387.84 mn mostly due to the unrealized forex gains from the AP Parent’s dollar denominated cash balances. As a result of the foregoing, income before income tax increased by P133.29 mn or 3% over the same period a year ago. Provision for taxes decreased by almost 3% to P618.39 mn from a prior period


provision of P634.33 mn. Changes in Registrant’s Resources, Liabilities and Shareholders Equity Assets Compared to year-end 2007 levels, consolidated assets increased by 31%, from P36.18 bn in December 2007 to P47.27 bn in December 2008, due to the following:

a. Cash & Cash Equivalents was at P14.33 bn (as restated), up by 31% from year-end 2007 level of P12.71 bn (as restated). This was due to additional cash brought in by short-term loans of P949 mn and the proceeds from the fixed-rate notes offering of the Company which amounted to P3.89 bn. The increase in cash brought about by the capital-raising activities mentioned above were expended for additional investments totaling P3.78 bn as well as for payment of dividends in the first quarter of the year amounting to P1.32 bn. The rest of the cash deployment was made for the capital expenditures during the year. Cash also increased due to dividends of P1.93 bn from associates.

b. Trade & Other Receivables increased by 20%, from P1.66 bn to P1.99 bn due to dividends

receivable from an associate as well as interest bearing advances made to related parties.

c. Inventories decreased by 11% due to the purchase of inventories before yearend 2007 for purposes of conducting programmed schedule of maintenance and use in Capex projects in 2008.

d. Other Current Assets increased by 59%, to P501.15 mn from P314.89 mn due to input VAT

arising from construction in progress as well as higher taxes withheld.

e. Property, Plant and Equipment increased by 53% from P4.10 bn (as restated) in 2007 to P6.26 bn mainly due to the consolidation of the plant and equipment of Hedcor Sibulan, which is currently undertaking the construction of a 42.5-MW hydropower project in Davao del Sur into ARI.

f. Intangible Assets-Service Concession Rights increased by P192 mn or 29% primarily due to

new capital expenditures by SEZ and MEZ which were booked as intangible assets following their adoption of IFRIC 12.

g. Investments in and Advances to Associates increased by 46% or a total of P6.65 bn due to

additional or new investments in associates with the significant investment/advances as follows:

I. P3.39 bn for additional equity into MORE, which was in turn invested into the

acquisition of the Ambuklao-Binga hydropower complex;

II. P278.89 mn in equity into RP Energy; and

III. P1.47 bn in investments/advances of subsidiary Abovant into CEDC, the project company for a 3X82-MW coal plant in Toledo City, Cebu.

h. Decrease of 58% in available for sale investments deemed to have decreased in value.

i. Decrease in Pension Assets by 66% resulting from the decreased contributions on

retirement fund.


j. Deferred tax assets increased by 10% primarily due to the recording of deferred tax asset of subsidiary PHC on dollar-denominated advances from AP Parent and some incremental deferred tax asset increase.

k. Other Noncurrent Assets increased by 20% and is mainly representing the unamortized

portion of remittances made by a subsidiary, SEZ, on various lease agreements with SBMA. Liabilities Consolidated liabilities increased to a total of P16.58 bn, an 88% increase over year-end 2007 level. The following were the reasons for the increase.

a) Bank Loans increased by 44% or P1.45 bn due to the availment of credit lines by some of

the companies subsidiaries for their working capital requirements as well as due to the increase in dollar-denominated debt as a result of the weakening of the peso.

b) Trade and Other payables increased by 17% due to advances payable by subsidiary Abovant

to shareholders to fund infusions into CEDC.

c) Income Tax Payable was lower by 27% due to lower income tax provision recorded during the period under review.

d) Long-term debt increased by 678% or by P5.68 bn versus year-end 2007 level. This is due

to the P3.89 bn in fixed rate notes of AP Parent availed of last December 2008 as well as Hedcor Sibulan’s availment of P1.72 bn long-term debt to finance the construction of its 42.5-MW hydropower project and SEZ’s refinancing of its longterm debt.

e) An increase in customers’ deposit of 14% or P197.16 mn was mainly due to new connections

in the franchise areas of Cotabato Light, Davao Light and SEZ.

f) Payable to preferred shareholder of a subsidiary went down by 7% as annual payments were timely made to preferred shareholders.

g) Pension liability decreased by 6% as a result of lower pension obligations of AP Parent and

PHC (now ARI).

h) Deferred Income Tax Liability increased by 52% due to unrealized forex gains on cash and dollar advances to a related party.

Equity Equity attributable to equity holders of the parent increased by 13% from P26.74 bn as of December 2007 to P30.16 bn as of December 2008. This was mainly due to consolidated net income of P4.33 bn, an upward adjustment in share in cumulative translation adjustments of associates of P557.55 mn and after a cash dividend payment of P1.33 bn in the first quarter of 2008. The Company declared dividends of P0.18 per share to all stockholders as of record date February 21, 2008. This was paid on March 3, 2008. Material Changes in Liquidity and Cash Reserves of Registrant As of December 31, 2008, the Group’s cash reserves posted a balance of P14.33 bn (as restated) after major investing and financing activities. The excess cash will be used to fund its programmed capital expenditures and to finance planned asset acquisitions for the remainder of the year.


Net cash from operating activities was only P1.90 bn this year compared to the net cash inflow of P4.04 bn for the same period last year. The seemingly lower cash from operations in 2008 versus 2007 is actually due to the inflow in 2007 from AEV payment of its advances to AboitizPower. This year’s cash from operations was mostly from cash flows from higher income before income tax in 2008. Net cash used in investing activities was P5.79 bn compared to P8.64 bn for the same period last year. Out of the amounts used, P3.78 bn is accounted for by additional or new investments, acquisitions of and or capital expenditures for property, plant and equipment of P2.62 bn and payments of advances to associates of P1.69 bn. These outflows were met partially through interest received in the amount of P595 mn, dividends received from associates in the amount of P1.93 bn and collections of advances from affiliates and interest income received. Net cash from financing activities for the period in review was P5.05 bn, which was mainly the net result of inflows of long-term debt in the amount of P5.71 bn, of which fixed-rate notes came in at P3.89 bn and P1.7 bn in Hedcor loans. Short-term loans of P949 mn were availed of by subsidiaries to fund working capital requirements. There were also cash outflows for the P1.32 bn dividend payout in the first quarter of 2008. The Company finished the year with net cash inflows of P1.17 bn. The cash and cash equivalents of P14.33 bn (as restated) for the period ending December 31, 2008 was 13% higher than the cash balance of P12.71 bn in December 31, 2007. With the significant cash balances management will be able to continue with its plan to deploy cash raised to improve its generation and distribution facilities, acquire existing power facilities and develop Greenfield projects. Financial Ratios Current ratio decreased by 0.31, from 2.43x as of December 2007 to 2.12x in December 2008 (as restated). This was due to the increase in current liabilities due to higher bank loans incurred in 2008 to fund working capital requirements and translation impact of the weaker peso. Current liabilities also went up due to higher trade and other payables. The cash raised from capital raising activities of the Company in 2007 and 2008 was deployed into investments made by the Company during the year. This is consistent with the Company’s long-term plan of improving shareholder value by deploying capital into high-yielding investments. Debt-to-equity ratio increased from 0.32 as of December 31, 2007 versus 0.54 as of December 31, 2008 as AboitizPower raised debt to fund its various investing activities. Item 7. Financial Statements The consolidated financial statements of AP are incorporated herein by reference. The schedules listed in the accompanying Index to Supplementary Schedules are filed as part of this Form 17-A. Item 8. Information on Independent Accountant and Other Related Matters (A) External Audit Fees and Services The following table sets out the aggregate fees billed to the Company for each of the last two years for professional services rendered by SGV & Co.

Fee Type 2010 2009 Audit Fees P300,000 P300,000 Tax Fees P50,000 -- All Other Fees -- -- Total P350,000 P300,000

As a matter of policy, the Company’s Board Audit Committee recommends to the Board of Directors regarding the selection of the Company’s external auditor. The Board Audit Committee also pre–


approves audit plans, scope and frequency before any audit is conducted. Audit services of SGV & Co. for the 2010 and 2009 were pre–approved by the Board Audit Committee. The Board Audit Committee also reviewed the extent and nature of these services to ensure that the independence of the external auditors was preserved. SGV & Co. does not have any direct or indirect interest in the Company. (B) Changes in and Disagreements with Accountants on Accounting and Financial Disclosure The SGV accounting firm has been AboitizPower’s Independent Public Accountant for the last 12 years. Mr. J. Carlitos G. Cruz served as audit partner of AboitizPower since 2009. He replaced Mr. Ladislao Z. Avila who served as audit partner for five years from 2004 to 2008. AboitizPower shall comply with the requirements of Section 3(b)(iv) of SRC Rule 68 on the rotation of external auditors or signing partners. Representatives of SGV will be present during the annual meeting and will be given the opportunity to make a statement if they so desire. They are also expected to respond to appropriate questions if needed. There was no event in the past 12 years where AboitizPower and SGV or the handling partner had any disagreement with regard to any matter relating to accounting principles or practices, financial statement disclosured or auditing scopes or procedures. In its regular meeting last March 2, 2011, the Board Audit Committee of the Company approved a resolution to submit for the approval of the stockholders during the Annual Stockholders’ Meeting a proposal to delegate to the Board of Directors and/or the Board Audit Committee the authority to appoint the Company’s external auditors for 2011. The proposal is intended to give the Board Audit Committee sufficient time to evaluate the different auditing firms who may act as AboitizPower’s external auditor for 2011.

PART III – CONTROL AND COMPENSATION INFORMATION

Item 9. Directors and Executive Officers of the Issuer Below is a list of AboitizPower’s directors for 2010-2011 with their corresponding positions and offices held for the past five years. The directors assumed their directorship during AboitizPower’s annual stockholders’ meeting in 2010 for a term of one year. ENRIQUE M. ABOITIZ, JR. Chairman of the Board of Directors Mr. Aboitiz, 57 years old, Filipino, has served as Director and Chairman of the Board of Directors of AboitizPower since 2009. He also served as Director of AEV since 1994 and was recently appointed as Senior Vice-President of AEV. He is also the Chairman of the Board of Directors of Aboitiz Land, Inc.; Director of AP Renewables, Inc., Manila-Oslo Renewable Enterprise, Inc., and Therma Luzon Inc. He was President and Chief Executive Officer of Aboitiz Transport System (ATSC) Corporation before it was sold to Negros Navigation Co., Inc. (NENACO) in December 2010. Mr. Aboitiz graduated with a degree in Bachelor of Science in Business Administration (Major in Economics) from Gonzaga University, Spokane, Washington, U.S.A. JON RAMON ABOITIZ Vice Chairman of the Board of Directors Mr. Aboitiz, 62 years old, Filipino, has been a Director of AboitizPower since 1998 and served as Chairman of the Board of AboitizPower for 1998 to 2008. Mr. Aboitiz began his career with the Aboitiz Group in 1970. From a manager of Aboitiz Shipping Corporation, Mr. Aboitiz was promoted to President of the company in 1976 and became President of Aboitiz & Company, Inc. in 1991 until


2008. He is currently the Chairman of the Boards of ACO, AEV, Aboitiz Transport Systems (ATSC) Corporation, Inc. and Aboitiz Jebsen Bulk Transport Corp.; Director of City Savings Bank, Inc. and International Container Terminals Services, Inc. (ICTSI). Mr. Aboitiz is also the Vice-Chairman of the Board of Directors of Union Bank of the Philippines, and the Chairman of the bank’s Executive Committee, Risk Management Committee, and Corporate Governance Committee, including the latter’s Compensation and Remuneration and Nomination Sub-Committees. Mr. Aboitiz is also the President of the Aboitiz Foundation, Inc.; Trustee and Vice President of Ramon Aboitiz Foundation, Inc.; Trustee of the Santa Clara University, California and the Philippine Business for Social Progress Foundation; and member of the Board of Advisors for the Association of Foundations, and Coca-Cola Export Corporation (Philippines). Mr. Aboitiz holds a B.S. Commerce degree (Major in Management) from the Santa Clara University, California. ERRAMON I. ABOITIZ President & Chief Executive Officer Member – Board Corporate Governance Committee, Board Risk Management Committee Mr. Aboitiz, 54 years old, Filipino, has served as President and Chief Executive Officer of AboitizPower since 1998. He is also the President and Chief Executive Officer of AEV. He has been AEV’s Director since 1994 and was its Executive Vice President and Chief Operating Officer from 1994 to December 2008. He is also President and Chief Executive Officer of ACO; Chairman of the Board of Directors of City Savings Bank, Inc., Davao Light & Power Company, Inc., San Fernando Electric Light and Power Company, Inc., Cotabato Light & Power Company, Subic Enerzone Corporation, SN Aboitiz Power-Magat, Inc. and SN Aboitiz Power-Benguet, Inc., Aboitiz Renewables, Inc., Therma Marine, Inc., Therma Power, Inc., Aboitiz Energy Solutions, Inc.; Vice Chairman of Visayan Electric Company, Inc.; Director of Union Bank of the Philippines, STEAG State Power, Inc. and Pilmico Foods Corporation. He is also the Chairman of the Aboitiz Foundation, Inc., and a director of the Family Business Development Center (Ateneo de Manila University). He received a Bachelor of Science degree in Business Administration (Major in Accounting and Finance) from Gonzaga University, Spokane, U.S.A. MIKEL A. ABOITIZ Director Chairman – Board Corporate Governance Committee Member- Board Audit Committee Mr. Aboitiz, 56 years old, Filipino, has been a Director of AboitizPower since 1998. He is also a Senior Vice President-Chief Information Officer and Chief Strategy Officer of AEV; Director and Senior Vice President for Strategy of ACO; President & Chief Executive Officer of City Savings Bank, Inc.; Director of Visayan Electric Company, Inc., Cotabato Light and Power Company, Davao Light and Power Company, Inc., Aboitiz Land, Inc., Pilmico Foods Corporation, Pilmico Animal Nutrition Corporation, Cebu Praedia Development Corporation, Aboitiz Construction Group, Inc., AP Renewables, Inc., AEV Aviation, Inc., Metaphil International, Inc., Therma Power, Inc., Therma Luzon, Inc.; and Trustee and Treasurer of Ramon Aboitiz Foundation, Inc. He holds a degree in Bachelor of Science (Major in Business Administration) from Gonzaga University, Spokane, U.S.A. JAIME JOSE Y. ABOITIZ Director Member-Board Audit Committee Executive Vice President & Chief Operating Officer - Power Distribution Group Mr. Aboitiz, 49 years old, Filipino, was a Director of AboitizPower from 2004 to April 2007. He was again elected as Director of AboitizPower in 2009. He is also the Executive Vice President and Chief Operating Officer of Visayan Electric Company Inc.; President and Chief Executive Officer of Cotabato Light & Power Company, Inc., Subic Enerzone Corporation, Davao Light & Power Company, Inc.; President of Mactan Enerzone Corporation and Balamban Enerzone Corporation; Director of Aboitiz Renewables, Inc., Hedcor Sibulan, Inc., Cebu Private Power Corporation, San Fernando Electric Light and Power Company, Inc., Hedcor, Inc. and Aboitiz Energy Solutions, Inc. He holds a degree in Mechanical Engineering from Loyola Marymount University in California and a master’s degree in Management from the Asian Institute of Management.


ANTONIO R. MORAZA Director Executive Vice President & Chief Operating Officer - Power Generation Group Chairman – Board Risk Management Committee Mr. Moraza, 54 years old, Filipino, has served as Director of AboitizPower since 1999. He has been a director of AEV since May 2009. He is also Chairman of the Board of Directors of AP Renewables, Inc., Pilmico Foods Corporation, Pilmico Animal Nutrition Corporation, and East Asia Utilities Corporation; Chairman and Chief Executive Officer of Hedcor, Inc. and Hedcor Sibulan, Inc.; Vice-Chairman of Propriedad Del Norte, Inc. and Aboitiz Land, Inc. He is likewise a Director and Senior Vice President of ACO; President and Chief Executive Officer of Abovant Holdings, Inc. and Aboitiz Renewables, Inc.; President of Manila-Oslo Renewable Enterprise; and Director of SN Aboitiz Power-Benguet, Inc., SN Aboitiz Power-Magat, Inc., Therma Marine, Inc., Therma Power, Inc., Luzon Hydro Corporation, Southern Philippines Power Corporation, STEAG State Power, Inc., Therma Luzon, Inc., Western Mindanao Power Corporation, Metaphil International, Inc., and Cebu Private Power Corporation. He holds a degree in Business Management from Ateneo de Manila University. JOSE R. FACUNDO Independent Director; Chairman- Board Audit Committee Member – Board Corporate Governance Committee, Board Risk Management Committee Mr. Facundo, 72 years old, Filipino, has been an Independent Director of AboitizPower since 2008. He currently serves as member of the Board of Directors of Security Bank Corporation, Siemens Philippines, Inc., and an Independent Director of Alaska Milk Corp. Mr. Facundo has an extensive career in banking. He served as a member of the Board of Directors and Executive Committee and as President of BPI Capital Corporation. He was also a member of the Board of Directors and Executive Committee of the Bank of the Philippine Islands (BPI). Prior to BPI’s merger with CityTrust Banking Corp. (CityTrust), Mr. Facundo served as President and CEO of CityTrust and was a member of its board and executive committees. He was also a Senior Managing Director of Ayala Corporation and formerly a Senior Officer of Citibank Manila. He also served as member of the Board of Directors of Temic Phil., Inc, and Chairman and member of the Board of Directors of the Philippine Clearing House. He is likewise a member of the Philippine Business for Social Progress, Junior Achievement of the Philippines and the Rotary Club. He holds a degree in AB Engineering and took post graduate studies in Statistics and Engineering. ROMEO L. BERNARDO Independent Director Member – Board Audit Committee, Board Corporate Governance Committee Mr. Bernardo, 56 years old, Filipino, has been an Independent Director of AboitizPower since 2008. He is the Managing Director of Lazaro Bernardo Tiu and Associates (LBT), a boutique financial advisory firm based in Manila. He is also GlobalSource economist in the Philippines. He does World Bank and Asian Development Bank-funded policy advisory work, Chairman of ALFM Family of Funds and Philippine Stock Index Fund. He is likewise a Director of several companies and organizations including Globe Telecom, BPI, RFM Corporation, Philippine Investment Management, Inc., Philippine Institute for Development Studies (PIDS), BPI-Philam Life Assurance Corporation (formerly known as Ayala Life Assurance, Inc.), National Reinsurance Corporation of the Philippines and Institute for Development and Econometric Analysis. He previously served as Undersecretary of Finance and as Alternate Executive Director of the Asian Development Bank. He was an Advisor of the World Bank and the IMF (Washington D.C.), and served as Deputy Chief of the Philippine Delegation to the GATT (WTO), Geneva. He was formerly President of the Philippine Economics Society; Chairman of the Federation of ASEAN Economic Societies and a Faculty Member (Finance) of the University of the Philippines. Mr. Bernardo holds a degree in Bachelor of Science in Business Economics from the University of the Philippines (magna cum laude) and a Masters degree in Development Economics at Williams College (top of the class) from Williams College in Williamstown, Massachusetts.


JAKOB DISCH Independent Director; Member – Board Audit Committee, Board Corporate Governance Committee, Board Risk Management Committee Mr. Disch, 56 years old, a Swiss national, has been an Independent Director of AboitizPower since March 2010. He is the Chairman, Chief Executive Officer and Founder of Convergence GmbH, an energy and environmental consulting firm located at Wintherthur, Switzerland. He gained extensive experience in the energy business from serving in various capacities in the ABB group of companies, among others as member of the Top Management Council of ABB and President of ABB Enertech Ltd. with Global Responsibility; Executive Vice-President Power Generation and member of the Asia Pacific Regional Management of ABB Asia Pacific Ltd.; Chairman of the Board of ABB India and Singapore; President of ABB Power Generation Sdn. Bhd in Malaysia; and Vice President for Marketing, Sales and Project Management of ABB Kraftwerke AG of Baden, Switzerland. Nominations for Independent Directors and Procedure for Nomination The procedure for the nomination and election of the independent directors is in accordance with Rule 38 of the Securities Regulation Code (SRC Rule 38), AboitizPower’s Amended By-Laws and AboitizPower’s Guidelines for the Constitution of the Nomination Committee and the Nomination and Election of Independent Directors (the Guidelines). These Guidelines were duly approved by the AboitizPower Board. AboitizPower’s By-Laws was amended on May 15, 2007 to incorporate the requirements of SRC Rule 38. Nominations for independent directors were accepted starting January 1, 2011 as provided for in Section 2 of the Guidelines and the table for nominations was closed on February 15, 2011 as provided for in Section 3 of the Guidelines. SRC Rule 38 and the Guidelines further require that the Board Corporate Governance Committee shall meet to pre-screen all nominees and submit a Final List of Candidates to the Corporate Secretary no later than February 22, 2011 so that such list will be included in the Corporation’s Preliminary and Definitive Information Statements. Only nominees whose names appear on the Final List shall be eligible for election as independent directors. No other nominations shall be entertained after the Final List of nominees has been prepared. The name of the person or group of persons who recommend the nomination of an independent director shall be identified in such report including any relationship with the nominee. All these procedures were complied with. In approving the nominations for independent directors, the Board Corporate Governance Committee considered the guidelines on the nominations of independent directors prescribed in SRC Rule 38, the Guidelines and AboitizPower’s Revised Manual on Corporate Governance. No nominations for independent director shall be accepted at the floor during the stockholders’ meeting at which such nominee is to be elected. However, independent directors shall be elected in the stockholders’ meeting during which other members of the Board are to be elected. Messrs. Jose R. Facundo, Romeo L. Bernardo and Jakob Disch are the nominees for Independent Directors of AboitizPower. They are neither officers nor employees of AboitizPower or its affiliates, and do not have any relationship with AboitizPower which would interfere with the exercise of independent judgment in carrying out the responsibilities of an independent director. AboitizPower stockholders Joy Ann Bisnar, Mary Jean Magluyan and Gina Unabia have respectively nominated Messrs. Facundo, Bernardo and Disch as AboitizPower’s independent directors. None of the nominating stockholders has any relation to Mr. Facundo, Mr. Bernardo or Mr. Disch.


Other Nominees for Election as Members of the Board of Directors As conveyed to the Corporate Secretary, the following have also been nominated as members of the Board of Directors for the ensuing year (2011-2012): Jon Ramon Aboitiz Erramon I. Aboitiz Antonio R. Moraza Mikel A. Aboitiz Enrique M. Aboitiz, Jr. Jaime Jose Y. Aboitiz Pursuant to Section 7, Article I of the Amended By-Laws of AboitizPower, nominations for members of the Board of Directors other than independent directors for the ensuing year must be received by the Corporate Secretary no less than 15 working days prior to the regular annual stockholders’ meeting on May 16, 2011 or not later than April 25, 2011. All other information regarding the positions and offices by the abovementioned nominees are integrated in Item 5 (a)(1) hereof. Officers for 2010-2011 Below is a list of AboitizPower’s officers for 2010-2011 with their corresponding positions and offices held for the past five years. The officers assumed their positions during AboitizPower’s annual organizational meeting in 2010 for a term of one year. ERRAMON I. ABOITIZ President & Chief Executive Officer Member – Board Corporate Governance Committee, Board Risk Management Committee Mr. Aboitiz, 54 years old, Filipino, has served as President and Chief Executive Officer of AboitizPower since 1998. He is also the President and Chief Executive Officer of AEV. He has been AEV’s Director since 1994 and was its Executive Vice President and Chief Operating Officer from 1994 to December 2008. He is also President and Chief Executive Officer of ACO; Chairman of the Board of Directors of City Savings Bank, Inc., Davao Light & Power Company, Inc., San Fernando Electric Light and Power Company, Inc., Cotabato Light & Power Company, Subic Enerzone Corporation, SN Aboitiz Power-Magat, Inc. and SN Aboitiz Power-Benguet, Inc., Aboitiz Renewables, Inc., Therma Marine, Inc., Therma Power, Inc., Aboitiz Energy Solutions, Inc.; Vice Chairman of Visayan Electric Company, Inc.; Director of Union Bank of the Philippines, STEAG State Power, Inc. and Pilmico Foods Corporation. He is also the Chairman of the Aboitiz Foundation, Inc., and a director of the Family Business Development Center (Ateneo de Manila University). He received a Bachelor of Science degree in Business Administration (Major in Accounting and Finance) from Gonzaga University, Spokane, U.S.A. ANTONIO R. MORAZA Director Executive Vice President & Chief Operating Officer - Power Generation Group; Chairman – Board Risk Management Committee Mr. Moraza, 54 years old, Filipino, has served as Director of AboitizPower since 1999. He has been a director of AEV since May 2009. He is also Chairman of the Board of Directors of AP Renewables, Inc., Pilmico Foods Corporation, Pilmico Animal Nutrition Corporation, and East Asia Utilities Corporation; Chairman and Chief Executive Officer of Hedcor, Inc. and Hedcor Sibulan, Inc.; Vice-Chairman of Propriedad Del Norte, Inc. and Aboitiz Land, Inc. He is likewise a Director and Senior Vice President of ACO; President and Chief Executive Officer of Abovant Holdings, Inc. and Aboitiz Renewables, Inc.; President of Manila-Oslo Renewable Enterprise; and Director of SN Aboitiz Power-Benguet, Inc., SN Aboitiz Power-Magat, Inc., Therma Marine, Inc., Therma Power, Inc., Luzon Hydro Corporation, Southern Philippines Power Corporation, STEAG State Power, Inc., Therma Luzon, Inc., Western


Mindanao Power Corporation, Metaphil International, Inc., and Cebu Private Power Corporation. He holds a degree in Business Management from Ateneo de Manila University. JAIME JOSE Y. ABOITIZ Director Executive Vice President & Chief Operating Officer - Power Distribution Group; Member – Board Audit Committee Mr. Aboitiz, 49 years old, Filipino, was a Director of AboitizPower from 2004 to April 2007. He was again elected as Director of AboitizPower in 2009. He is also the Executive Vice President and Chief Operating Officer of Visayan Electric Company Inc.; President and Chief Executive Officer of Cotabato Light & Power Company, Inc., Subic Enerzone Corporation, Davao Light & Power Company, Inc.; President of Mactan Enerzone Corporation and Balamban Enerzone Corporation; Director of Aboitiz Renewables, Inc., Hedcor Sibulan, Inc., Cebu Private Power Corporation, San Fernando Electric Light and Power Company, Inc., Hedcor, Inc. and Aboitiz Energy Solutions, Inc. He holds a degree in Mechanical Engineering from Loyola Marymount University in California and a master’s degree in Management from the Asian Institute of Management. JUAN ANTONIO E. BERNAD Executive Vice President - Strategy and Regulation Mr. Bernad, 54 years old, Filipino, has been AboitizPower’s Executive Vice President for Strategy and Regulation since 2009. He previously served AboitizPower in several capacities, as Director from 1998 until May 18, 2009, as Executive Vice President/Chief Financial Officer/Treasurer from 1998 to 2003 and as Executive Vice President for Regulatory Affairs/Chief Financial Officer from 2004 to 2007. He is also AEV’s Senior Vice President, a position he has held since 1995. He was AEV’s Senior Vice President – Electricity Regulatory Affairs from 2004 to 2007 and Senior Vice-President and Chief Financial Officer from 1995 to 2004. He is Executive Vice President-Regulatory Affairs of Davao Light & Power Company, Inc.; Director and Senior Vice President of Visayan Electric Company, Inc.; Director of Cotabato Light & Power Company, AEV Aviation, Inc., AP Renewables Inc. and Union Bank of the Philippines; Director and Vice President of Cebu Praedia Development Corporation. He has a degree in Economics from the Ateneo de Manila University and a master’s degree in Business Administration at The Wharton School, University of Pennsylvania, U.S.A. LUIS MIGUEL O. ABOITIZ Senior Vice President - Power Marketing and Trading Mr. Aboitiz, 46 years old, Filipino, has been AboitizPower Senior Vice President – Power Marketing and Trading since 2009. He is also AEV’s First Vice President and a member of the Board of Advisers of ACO. He is currently the President and Chief Executive Officer of Aboitiz Energy Solutions, Inc.; Director and Senior Vice President – Business Development of Hedcor, Inc.; Director and Vice President-Treasurer of Aboitiz Renewables, Inc. and Therma Power, Inc.; Director and Vice President of Therma Marine, Inc.; Executive Vice President and Chief Operating Officer of Adventenergy, Inc.; Director and Treasurer of Redondo Peninsula Energy, Inc.; and Director of ACO, Davao Light & Power Company, Inc., Pilmico Animal Nutrition Corporation, Pilmico Foods Corporation, Manila-Oslo Renewable Enterprise, Inc., SN Aboitiz Power-Magat, Inc., SN Aboitiz Power-Benguet, Inc., Therma Luzon, Inc., AP Renewables, Inc., Hedcor Sibulan, Inc. and Subic Enerzone Corporation. He graduated at Santa Clara University, California, U.S.A. with a degree of Bachelor of Science in Computer Science and Engineering and took his Masters in Business Administration from the University of California at Berkeley, U.S.A. IKER M. ABOITIZ First Vice President/Chief Financial Officer/Corporate Information Officer Ex-Officio Member - Board Audit Committee Ex-Officio Member - Board Risk Management Committee Mr. Aboitiz, 38 years old, Filipino, has been AboitizPower’s First Vice President and Chief Financial Officer since August 29, 2007. He is currently a Director and Chief Financial Officer of Abovant Holdings, Inc.; Chief Financial Officer and Treasurer of Hijos de F. Escaño; Director of Cotabato Light & Power Company, Southern Philippines Power Corporation, Therma Power, Inc., Therma Marine,


Inc., Aboitiz Renewables, Inc. and Union Bank of the Philippines. He has extensive professional experience in corporate finance within and outside the Aboitiz Group. Prior to his appointment as Chief Financial Officer, he was the Chief Financial Officer of Aboitiz Construction Group, Inc. He graduated cum laude from Boston College with a degree in Bachelor of Science in Business Management major in Finance. GABRIEL T. MAÑALAC Senior Vice President - Treasurer Mr. Mañalac, 54 years old, Filipino, has been Treasurer of AboitizPower since 2004 and its Senior Vice President – Treasurer since 2009. He is the Senior Vice President - Group Treasurer of AEV since January 2009. He joined AEV as Vice President for Treasury Services/Treasurer in 1998 and was promoted to First Vice President for Treasury Services/Treasurer of AEV in 2004. He is also the Vice President and Treasurer of Davao Light & Power Company, Inc. and Treasurer of Cotabato Light & Power Company. Mr. Mañalac graduated cum laude with a degree of Bachelor of Science in Finance and Bachelor of Arts in Economics from De La Salle University. He obtained his Masters of Business Administration in Banking and Finance from the Asian Institute of Management and was awarded the Institute’s Scholarship for Merit. RAYMOND E. CUNNINGHAM First Vice President - Business Development Mr. Cunningham, 69 years old, American, has been AboitizPower’s First Vice President – Business Development since 2009. He has extensive experience in the power industry in the Philippines and the US, especially in power project planning, regulatory approvals, financing, design, construction and operations. He was previously the Business Development, Acquisitions and Special Projects Manager of CalEnergy International Services, Senior Vice President and Project Director of San Roque Power Corporation, Vice President of AT&T Capital Corporation and Vice President for Engineering & Operations of Consolidated Power Company. He earned his Bachelor of Science in Engineering degree from the US Coast Guard Academy. He also earned a Naval Engineer’s degree and a Masters of Science in Mechanical Engineering from the Massachusetts Institute of Technology. MANUEL R. LOZANO First Vice President/Chief Financial Officer - Power Generation Group Mr. Lozano, 40 years old, Filipino, has been Chief Financial Officer of the Power Generation Group of AboitizPower since 2009. He is concurrently Chief Financial Officer of AP Renewables, Inc., Hedcor, Inc. and Hedcor Sibulan, Inc. He is Treasurer of Therma Marine, Inc. and Therma Luzon, Inc. He was the CFO and Director of Paxy’s Inc., a PSE-listed company focused on the BPO industry and other IT-related courses within Asia Pacific region before he joined the Aboitiz Group. He has a wide range of experience working in several management institutions. He earned his Bachelor of Science in Business Administration from the University of the Philippines - Diliman and his MBA from The Wharton School, University of Pennsylvania. MANUEL M. ORIG First Vice President - Mindanao Affairs Mr. Orig, 69 years old, Filipino, was appointed First Vice President for Mindanao Affairs of AboitizPower in 2010. He has been with the Aboitiz Group for over 40 years, most of it with AboitizPower’s subsidiary Davao Light & Power Company. He was Executive Vice President of Davao Light & Power Company prior to his appointment in AboitizPower. He was instrumental in transforming Davao Light & Power Company into a professional and customer-oriented organization. In 2004, he was awarded the Don Ramon Aboitiz Award of Excellence, the highest recognition bestowed on Aboitiz Group team members and team leaders, for his outstanding contribution to the Aboitiz Group. He finished his bachelor’s degree in Commerce from the University of San Jose Recoletos and had his Masters in Business Administration from the University of the Philippines.


MA. CHONA Y. TIU Vice President and Chief Financial Officer - Power Distribution Group Ms. Tiu, 53 years old, Filipino, has been Vice-President and Chief Financial Officer for the Power Distribution Group since 2009. She joined the Aboitiz Group in 1977 as Research Assistant of the Corporate Staff Department of ACO. She rose from the ranks and held various finance positions in different companies within the Aboitiz Group, including Aboitiz Construction Group, Inc. and Aboitiz Land, Inc. She joined the AboitizPower Group when she was appointed as Vice President – Administration and Chief Finance Officer of AboitizPower’s affiliate, Visayan Electric Company, Inc. in 2007. She is also a Director, Vice President/Chief Financial Officer/ Treasurer of Balamban Enerzone Corporation; Vice President – Chief Financial Officer of Cotabato Light & Power Company, Davao Light & Power Company, Subic Enerzone Corporation and Mactan Enerzone Corporation. ALVIN S. ARCO Vice President- Regulatory Affairs Mr. Arco, 50 years old, Filipino, has been Vice President for Regulatory Affairs of AboitizPower since April 2007. He was Accounting Manager of AboitizPower from 1998 to 1999, Assistant Vice President – Finance from 2000 to 2004 and was promoted to Vice President – Finance in 2005. He is also the Vice President – Regulatory Affairs of Davao Light & Power Company, Inc. and Vice President – Finance of Cotabato Light & Power Company. Mr. Arco is a Certified Public Accountant. He holds a degree in Accountancy from the University of San Jose-Recoletos, Cebu City. WILFREDO R. BACAREZA, JR. Vice President - Project Development Mr. Bacareza, 33 years old, Filipino, has been Vice President of AboitizPower since 2008. Since joining AboitizPower, he has handled or been involved in numerous projects like the 300MW coal fired power plant project in Subic Bay, Philippines, acquisition of two 100MW power barges located in Mindanao and the 700MW IPPA contract for the Pagbilao coal plant. He was formerly the President and Chief Executive Officer of the Philippine National Oil Company-Development Management Corporation (PNOC-DMC) from 2006 to 2007. In 2005, he served as legal adviser of the Philippine National Construction Corporation (PNCC) and Metropolitan Waterworks and Sewerage System (MWSS). He was also a Government Corporate Attorney II in the Office of the Government Corporate Counsel from 2004 to 2005 and Legal Consultant of National Power Corporation from 2003 to 2004. He holds a degree in Interdisciplinary Studies minor in Management and Economics from the Ateneo de Manila University and is a graduate of the Ateneo Law School with a degree of Juris Doctor. RAUL C. LUCERO Vice President - Engineering (Power Distribution Group) Mr. Lucero, 43 years old, Filipino, has been Vice President - Engineering (Power Distribution Group) of AboitizPower since 2009. He joined the Aboitiz Group in 1990 via Davao Light & Power Company, Inc. He became Vice President for Engineering of Davao Light in 2000. He was involved in the successful bid by AEV for the management of Subic Bay Metropolitan Authority’s (SBMA) distribution system in the Subic Bay Freeport Zone (SBFZ) in 2003. He was promoted to Senior Vice President of Davao Light in 2004. In the same year, he was brought into Visayan Electric Company, Inc., to help transform its engineering group. He was officially transferred to Visayan Electric Company, Inc. in 2008. He is a graduate of Bachelor of Science in Electrical Engineering and Bachelor of Science in Electronics and Communications Engineering from the University of San Jose-Recoletos. ANASTACIO D. CUBOS, JR. Vice President - Special Projects Mr. Cubos, 60 years old, Filipino, has been Vice President for Special Projects of AboitizPower since 1998. Mr. Cubos’ experience in the power industry dates back to 1972 when he joined Davao Light & Power Company, Inc., as an engineer. Between 1989 and 1997, he was Assistant Vice President – Engineering of Davao Lights & Power Company, Inc. He was also Davao Light’s Vice President – Engineering from 1998 to 2000 and Davao Light Senior Vice President – Special Projects since 2001. He is a Consultant of Hedcor and is a member of the Technical Executive Committee of Cotabato


Light. He is a consultant to the Republic of Palau for its generation projects. He holds a degree in electrical engineering from the Cebu Institute of Technology and a master’s degree in Business Administration from the Ateneo de Davao University. THOMAS J. SLIMAN, JR. Vice President - Business Development Mr. Sliman, 50 years old, American, has been Vice President for Business Development of AboitizPower since 2010. He has extensive experience in the power industry, both in the Philippines and in the US. After working for 20 years in the US for the Southern Company in various operations and maintenance roles in thermal power plants, he relocated to the Philippines to work with Mirant Philippines, and was initially assigned at the Pagbilao and Sual plants as plant manager. He was the EVP - Operations for Mirant Philippines until its sale in 2007. He previously worked with AboitizPower in 2009 as consultant during AboitizPower’s submission of bid proposals to be the IPP Administrator of the Pagbilao and Sual Coal Fired Power Plants. He earned his degree in BS Electrical Engineering from Mississippi State University in 1983. He had completed approximately 75% of the required coursework for a Masters of Business Administration degree from the University of Southern Mississippi, Long Beach, Mississippi. ROLAND U. GAERLAN Vice President - Marketing Mr. Gaerlan, 48 years old, Filipino, has been Vice President for Marketing of AboitizPower since 2010. He has over 28 years of extensive experience in sales and marketing in consumer goods, telecom and financial plan industries. He was Vice President - Business Development of Advanced Contact Solutions before he joined AboitizPower. He is a member of various professional organizations such as the British and the American Chambers of Commerce. Mr. Gaerlan is a graduate of Bachelor of Science in Industrial Engineering from the University of the Philippines and obtained his Masters Degree in Business Administration from the Ateneo de Manila University. BIENAMER D. GARCIA Vice President - Distribution Customer Services Mr. Garcia, 52 years old, Filipino, has been Vice President for Distribution Customer Services of AboitizPower since January 2011. He joined the Aboitiz Group in 2002 as an Assistant to the Chief Operating Officer and Senior Vice President of Davao Light & Power Company, Inc. In 2004, he was brought to Visayan Electric Company, Inc. to help transform its customer services group. He then became the Vice President of Administration and Customer Services Group of Visayan Electric Company, Inc. from 2004 to 2006. He was the Vice President for Retail Services and Administration of Davao Light & Power Company, Inc. prior to his appointment in AboitizPower. Mr. Garcia is a registered Metallurgical Engineer. He earned his masters degree in Business Administration and diploma in Urban and Regional Planning from the University of the Philippines-Diliman. CRISTINA BRIONES- BELORIA Assistant Vice President - Controller Ms. Beloria, 48 years old, Filipino, has been Assistant Vice President and Controller of AboitizPower since 2008. She was the Plant Controller of East Asia Utilities Corporation and Cebu Private Power Corporation from 2000-2008. She held various consulting engagements in Tokyo, Japan from 1999-2000. She also served as Senior Auditor in the E.C. Ortiz and Co., CPA's in Chicago, Illinois USA. Ms. Beloria holds a degree in Bachelor of Science in Commerce, Major in Accounting from the University of San Jose Recoletos. She is a Certified Public Accountant in the Philippines and Illinois, USA. PAQUITA S. TIGUE- RAFOLS Assistant Vice President - Accounting (Power Generation - Mindanao) Ms. Rafols, 46 years old, Filipino, was appointed Assistant Vice President - Accounting (Power Generation - Mindanao) in 2009. She joined the Aboitiz Group as Finance and Accounting Manager of the Aboitiz shipbuilding company, FBMA Marine, Inc. She was Assistant Vice President - Finance and Controller of FBMA prior to her appointment in AboitizPower. She was also connected with


Trans-Asia Shipping Lines, Inc. and Price Waterhouse/Joaquin Cunanan & Co. before she joined the Aboitiz Group. Ms. Rafols is a Certified Public Accountant. She holds degrees in Bachelor of Science in Commerce, Major in Accounting from St. Theresa's College (Magna Cum Laude) and Bachelor of Laws from the University of San Carlos. ARAZELI L. MALAPAD Assistant Vice President - Accounting (Power Generation - Luzon) Ms. Malapad, 42 years old, Filipino, was appointed Assistant Vice President - Accounting (Power Generation - Luzon) in 2010. She has 16 years of extensive experience performing finance and accounting managerial functions in various private companies. She is a Certified Public Accountant and a member of the Philippine Institute of Certified Public Accountants. She earned her Bachelor of Science in Commerce (Major in Accounting) from Immaculate Conception College. CARLOS COPERNICUS S. PAYOT Assistant Vice President & Controller (Power Distribution Group) Mr. Payot, 46 years old, Filipino, a CPA, was appointed Assistant Vice President - Controller for AboitizPower Distribution in July 2009. Prior to his appointment, he served in various positions in the Aboitiz Group. He was Assistant Vice President for Accounting of Visayan Electric Company, Inc., AVP – Accounting Services of AEV, and Audit Manager of ACO. He worked with SGV & Co. after graduating from University of San Carlos where he got his Bachelor’s degree in Commerce major in Accounting (Cum Laude). CLOVIS B. RACHO Assistant Vice President - Procurement and Logistics (Power Distribution Group) Mr. Racho, 46 years old, Filipino, has been Assistant Vice President - Procurement and Logistics - AboitizPower Distribution Group since 2009. He joined the Aboitiz Group in 1989 as Assistant Systems Analyst of Davao Light & Power Company, Inc., where he subsequently held various positions until his promotion as Department Manager of Technical Services Department in 2000. He was promoted as Assistant Vice President for Procurement and Logistics of Davao Light in 2004. He is currently the Assistant Vice President for Technical Services of Davao Light. He is a graduate of Bachelor of Science in Industrial Engineering and Bachelor of Science in Mechanical Engineering from Cebu Institute of Technology. He is a Registered Mechanical Engineer. ALADINO B. BORJA, JR. Assistant Vice President - Information Services (Power Distribution Group) Mr. Borja, 47 years old, Filipino, has been Assistant Vice President - Information Services (Power Distribution Group) since 2009. He started his career with the Aboitiz Group when he was hired as Computer Programmer of Davao Computer Services, Inc., an affiliate of Davao Light & Power Company, Inc., in 1997. He later joined Davao Light & Power Company, Inc. in 1990 as Junior Programmer where he rose from the ranks, becoming Head of Information Service Group in 2000. He was later assigned to Visayan Electric Company, Inc. as Assistant Vice President for Information Service Group in 2004. He graduated from Cebu Institute of Technology. RONALD ENRICO V. ABAD Assistant Vice President - Project Development Mr. Abad, 40 years old, Filipino, has been Assistant Vice President - Project Development since 2009. He was Manager of Team Energy Corporation prior to joining AboitizPower. He was also Manager of ABB handling sales, marketing and project management. He is a graduate of Bachelor of Science in Electrical Engineering from the University of Sto. Tomas. MA. KRISTINA C.V. RIVERA Assistant Vice President - Human Resource and Quality (Power Generation Group) Ms. Rivera, 40 years old, Filipino, has been Assistant Vice President for Human Resources of AEV seconded to AboitizPower since January 2009. She has 17 years experience in human resources


management with a diverse background in human resource strategic planning, implementation and administration. Before joining the Aboitiz Group in 2003, she was with the PNOC- Energy Development Corporation. She holds Bachelor of Science and Masters degrees in Psychology from the University of the Philippines. ROBERTO V. OROZCO Assistant Vice President - Civil Site Construction Mr. Orozco, 46 years old, Filipino, joined AboitizPower on January 2011 as Assistant Vice President for Civil Site Construction. Prior to joining AboitizPower, he was a Senior Civil and Structural Engineer of PacificTech Solutions and a Technical Operations Manager of the Philippine Branch of Ove Arup & Partners Hong Kong Ltd. Mr. Orozco is a member of the Philippine Institute of Civil Engineers and the American Institute of Steel Construction. He is a graduate of Bachelor of Science in Civil Engineering from Far Eastern University and obtained his Masters Degree in Geotechnical Engineering from Mapua Institute of Technology. ANA LIZA M. ALETA Assistant Vice President & IT Director (Power Generation) Ms. Aleta, 42 years old, Filipino, has been Assistant Vice President - IT Director of the Generation Group of AboitizPower since 2009. She joined the Aboitiz Group in 1989 as a marketing assistant of ACO. She rose from the ranks and held various positions relating to information technology in Pilmico Foods Corporation. She was Assistant Vice President - Information Technology of AP Renewables, Inc., before she joined AboitizPower. She has 21 years of experience in information infrastructure and systems management with diverse background in Corporate and IT strategic planning, domestic operations, implementation, project management and technical marketing. She is a graduate of Bachelor of Science in Electronics & Communication Engineering from the University of San Carlos and earned her degree in Master in Management from the University of the Philippines. CRISANTO R. LASET, JR. Assistant Vice President - Power Economics & Distribution System Planning Mr. Laset, 52 years old, Filipino, has been Assistant Vice President - Power Economics & Distribution System Planning since 2009. He was Assistant Vice President - Technical Assistant to the Chairman of Cagayan Electric Power & Light Company, Inc., before he joined AboitizPower. He was also previously connected with ATOM Industrial Sales as Technical Assistant to the President. Mr. Laset is a graduate of Bachelor of Science in Electrical Engineering from Mapua Institute of Technology and has units in MS Electrical Engineering from the University of the Philippines. JUAN MANUEL J. GATMAITAN Assistant Vice President - Power Marketing Mr. Gatmaitan, 39 years old, Filipino, joined AboitizPower in 2007 and has been Assistant Vice President for Power Marketing since 2010. He was the Assistant Vice President for Power Sales and Marketing of AP Renewables, Inc. prior to his appointment in AboitizPower. He earned his degree in AB Management Economics from the Ateneo de Manila University and had his Master of Business Administration in General Management from the Rotterdam School of Management, Erasmus University, Rotterdam, The Netherlands. SUSAN S. POLICARPIO Assistant Vice President – Government Relations Ms. Policarpio, 54 years old, Filipino, has been AboitizPower’s Assistant Vice President for Government Relations since 2009. Prior to her stint in AboitizPower, she was Assistant Vice President for Government Relations of Aboitiz Transport System (ATSC) Corporation since 2003. She was also Executive Director of Domestic Shipping Association from 2001 to 2003 and Executive Director Honorary Investments and Trade Representative of the Department of Trade and Industry from 1998 to 2001. She is currently a Director of the Port Users Confederation, Inc. and is a member of the Philippine Chamber of Commerce and Industry. She is a graduate of Bachelor of Arts in Communication Arts from St. Paul College.


M. CARMELA N. FRANCO Assistant Vice President - Investor Relations Ms. Franco, 39 years old, Filipino, has been AboitizPower's Assistant Vice President for Investor Relations since 2008. She is also Assistant Vice President for Investor Relations of AEV. Ms. Franco's professional experience in investment analysis and corporate finance includes working with various corporations in different capacities prior to her stint in AboitizPower. She was previously a Trader, Associate and Credit Analyst of Capital One Equities Corporation & Multinational Investment Bancorporation from 1992 to 1994 and was formerly an Investment Analyst of ING Barings (Phils), Inc. & Kim Eng Securities (Phils), Inc. from 1994 to 1997. She also served as Investment Officer of Standard Chartered Bank from 1998 to 2000 and went on to serve as Project Analyst of Newgate Management, Inc., from 2000 to August 2002. Immediately prior to her stint with AboitizPower, she was connected with San Miguel Corporation as Investor Relations Officer of its Corporate Finance Group and later as Senior Project Analyst of its Corporate Planning Group. She holds a degree in Bachelor of Science in Business Economics (Cum Laude) from the University of the Philippines. KATRINA M. PLATON Assistant Vice President - Legal and Regulatory Affairs Ms. Platon, 44 years old, Filipino, has been Assistant Vice President for Legal and Regulatory Affairs of AboitizPower since 2009. She was Senior Associate General Counsel of AEV before she moved to AboitizPower in May 2007. Prior to joining the Aboitiz Group, she served as Corporate Legal Manager of the regional headquarters of e-Room Corporation and Associate Legal Officer at the United Nations Compensation Commission in Geneva, Switzerland. She started her law practice as an associate of the Ponce Enrile Reyes & Manalastas Law Offices where she specialized in corporate law. She finished her bachelor’s degree in Business Administration from the University of the Philippines, and is a graduate of the Ateneo de Manila University-School of Law. She took her LL.M. in International Banking and Finance Law from the Boston University - School of Law in Boston, MA. DENNIS DE LA SERNA Assistant Vice President - Regulatory Affairs Mr. de la Serna, 37 years old, Filipino, has been Assistant Vice President - Regulatory Affairs since 2010. He was Contracts Manager for Aboitiz Energy Solutions, Inc. before joining AboitizPower. He was also Department Manager of the Universal Levy, Tariff and Financial Valuation Department of the Power Sector Assets and Liabilities Management Corporation (PSALM). He earned his degree in Bachelor of Arts in Management Economics from Ateneo de Manila University, and obtained his MBA from Fordham University. NESTOR F. ALIMAN Assistant Vice President - Business Development Mr. Aliman, 58 years old, Filipino, has been Assistant Vice President - Business Development since 2010. He was previously the Head of Electricity Trading of SN Aboitiz Power Inc. He was also Electricity Trading Manager of PSALM. He earned his degree in Mechanical Engineering from the University of San Carlos with a specialized training in Energy Derivatives and Risk Management. He completed his graduate studies in Industrial Engineering and Operations Research from the University of the Philippines. MARIA P. GARCIA Assistant Vice President - Trading Ms. Garcia, 55 years old, Filipino, has been Assistant Vice President - Trading since 2010. She was Trading Manager of Emerald Energy Corporation, a subsidiary company of GDF-Suez in the Philippines. She was also Electricity Trading Manager of PSALM. She earned her degree in Bachelor of Science in Electrical Engineering from the Nueva Ecija University of Science and Technology. She has a Masters Degree in Engineering Major in Systems Management from the Pamantasan ng Lungsod ng Maynila.


KATRINA MICHAELA D. CALLEJA Assistant Vice President - Branding Ms. Calleja, 33 years old, Filipino, has been Assistant Vice President - Branding since January 2011. She joined the Aboitiz Group in 2001, where she was Superferry's Marketing Executive for four years. She served as Retail Sales and Brand Manager of 2GO Express from 2005 to 2009. Before her current post, she was AboitizPower's Brand Manager until 2010. Ms. Calleja graduated from Ateneo de Manila University, with a Bachelor of Arts degree, Major in Economics. MA. CIELITA C. AÑIGA Assistant Vice President - Human Resources (Power Distribution Group) Ms. Añiga, 54 years old, Filipino, has been Assistant Vice President - Human Resources (Power Distribution Group) since January 2011. She joined the Aboitiz Group in 1993 as Total Quality Management Coordinator of Davao Light & Power Company, Inc. In 1994 she was named Department Manager for Quality and Human Resource Development and was eventually promoted as Assistant Vice-President, a position she held until 2000. She rejoined the Aboitiz Group in 2004 as part of the management team that was tasked to manage and transform Visayan Electric Company, Inc. She was Assistant Vice-President for Human Resources of Visayan Electric Company, Inc. prior to her appointment in AboitizPower. Ms. Añiga holds Bachelor of Science degrees in Chemical Engineering from the University of Mindanao, and Metallurgical Engineering from a consortium between the University of the Philippines and the Mindanao State University. She also has a Masters in Management degree major in Industrial Relations from the University of the Philippines. M. JASMINE S. OPORTO Corporate Secretary/ Compliance Officer Ex-Officio Member - Board Corporate Governance Committee Ms. Oporto, 51 years old, Filipino, has been the Corporate Secretary of AboitizPower since 2007. She is also First Vice President-Chief Legal Officer, Corporate Secretary and Chief Compliance Officer of AEV. She is also Vice President for Legal Affairs of Davao Light & Power Company, Inc.; Corporate Secretary of Visayan Electric Company, Inc., Luzon Hydro Corporation, Therma Power, Inc., Hijos de F. Escano and Cebu Private Power Corporation. Prior to joining AboitizPower, she worked in various capacities with the Hong Kong office of Kelley Drye & Warren, LLP, a New York-based law firm and the Singapore-based consulting firm Albi Consulting Pte. Ltd. A member of both the Philippine and New York bars, she obtained her Bachelor of Laws from the University of the Philippines. JOSEPH TRILLANA T. GONZALES Assistant Corporate Secretary Mr. Gonzales, 44 years old, Filipino, has been the Assistant Corporate Secretary of AboitizPower since 2007. He is also Vice President for Legal and Corporate Services of AEV and Corporate Secretary of AP Renewables, Inc. He was previously Special Counsel of SyCip Salazar Hernandez & Gatmaitan Law Offices until he joined the Aboitiz Group in 2007 as Assistant Vice President of the Corporate and Legal Services of ACO. He is a graduate of Bachelor of Arts in Major in Economics and Bachelor of Laws from the University of the Philippines. He also has a Master of Laws degree from the University of Michigan. Period in which the Directors and Executive Officers Should Serve The directors and executive officers should serve for a period of one year. Term of Office of a Director Pursuant to the amended By-laws of AboitizPower, the directors are elected at each annual stockholders’ meeting by stockholders entitled to vote. Each director holds office until the next annual election for a term of one year and until his successor is duly elected, unless he resigns, dies or is removed prior to such election.


Any vacancy in the Board of Directors other than by removal or expiration of term may be filled by a majority vote of the remaining members thereof at a meeting called for that purpose, if they still constitute a quorum. The director so chosen shall serve for the unexpired term of his predecessor in office. Significant Employees AboitizPower considers the contribution of every employee important to the fulfillment of its goals. Family Relationships Messrs. Jaime Jose Y. Aboitiz and Luis Miguel Aboitiz are first cousins. Messrs. Jon Ramon Aboitiz and Mikel A. Aboitiz are brothers. Messrs. Erramon I. Aboitiz, Enrique M. Aboitiz, Jr. and Iker M. Aboitiz are brothers as well. Messrs. Jon Ramon Aboitiz and Mikel A. Aboitiz are second cousins of Messrs. Erramon I. Aboitiz, Enrique M. Aboitiz, Jr., Iker M. Aboitiz, Jaime Jose Y. Aboitiz and Luis Miguel Aboitiz. Involvement in Certain Legal Proceedings as of February 28, 2011 People of the Philippines vs. Renato Francisco et. al. (c/o Fuller O’ Brien Paint Company, Inc., Reliance St., Mandaluyong City) Criminal Case No. 35-5784 MTC Branch 66, Makati City July 19, 2007 On July 23, 2008, the Metropolitan Trial Court (MTC) of Makati issued an Order finding probable cause to hold the alleged directors/stockholders of Fuller O’Brien Paint Company, Inc. (Fuller O’Brien), including Erramon I. Aboitiz, liable for violation of PD No. 1752 or the Pag-Ibig Fund Law, as amended. Upon motion by Mr. Aboitiz, the MTC reconsidered its order finding probable cause against him. The MTC also directed the Office of the City Prosecutor of Makati to conduct a preliminary investigation against Mr. Aboitiz. In the preliminary investigation, Mr. Aboitiz alleged that he should be exonerated from the charges filed against him as he was no longer a director of Fuller O’Brien when the alleged violations of the Pag-Ibig Fund Law occurred. The case is still pending resolution before the Office of the City Prosecutor of Makati. To the knowledge and/or information of AboitizPower, other than as disclosed above, none of its nominees for election as directors, its present members of the Board of Directors or its executive officers, is presently or during the last five years, involved in any legal proceeding in any court or government agency in the Philippines or elsewhere, which would put to question their ability and integrity to serve AboitizPower and its stockholders. To the knowledge and/or information of AboitizPower, the above-said persons have not been convicted by final judgment of any offense punishable by the laws of the Republic of the Philippines or by the laws of any other nation or country. Resignation or Refusal to Stand for Re-election by Members of the Board of Directors No director has resigned or declined to stand for re-election to the Board of Directors since the date of AboitizPower’s last annual meeting because of a disagreement with AboitizPower on matters relating to its operations, policies and practices.


Item 10. Executive Compensation (1) Summary of Compensation Table

Information as to the aggregate compensation paid or accrued to AboitizPower’s Chief Executive Officer and other highly compensated executive officers, as well as other directors and officers during the last two completed fiscal years and the ensuing fiscal year are as follows:

EXECUTIVE OFFICERS PERIOD SALARY BONUS OTHER

COMPENSATION

TOP FIVE HIGHLY-COMPENSATED EXECUTIVES: 1. ERRAMON I. ABOITIZ - President & Chief Executive Officer 2. ANTONIO R. MORAZA

- Executive Vice President and Chief Operating Officer-Power Generation Group

3. JUAN ANTONIO E. BERNAD - Executive Vice President - Strategy and

Regulation 4. RAYMOND E. CUNNINGHAM

- First Vice President – Business Development 5. THOMAS J. SLIMAN, JR.

- Vice President - Business Development

Actual 2010 P 23,950,000 P 770,000 P 5,450,000

Actual 2009 P 18,670,000 P 860,000 P 6,470,000 All above-named officers as a group

Projected 2011 P 25,620,000 P 820,000 P 6,840,000

Actual 2010 P 31,790,000 P 2,350,000 P 14,290,000

Actual 2009 P 18,950,000 P 1,400,000 P 10,000,000 All other directors and officers as a group unnamed

Projected 2011 P 35,790,000 P 2,650,000 P 19,450,000

(2) Compensation of Directors (i) Standard Arrangements In 2010, all of AboitizPower’s directors received a monthly allowance of P80,000 except for the Chairman of the Board who received a monthly allowance of P120,000. In addition, each director and the Chairmen of the Board and the Board Committees received a per diem for every Board or Committee meeting attended as follows:

Type of Meeting Directors Chairman of the Board Board Meeting P60,000 P90,000

Type of Meeting Committee Members Chairman of the Committee

Committee Meeting P50,000 P60,000 For 2011 it is proposed that all of AboitizPower’s directors shall receive a monthly allowance of P100,000, except for the Chairman of the Board who shall receive a monthly allowance of P150,000. In addition, each director and the Chairmen of the Board and the Board Committees shall receive a per diem for every Board or Committee meeting attended as follows:


Type of Meeting Directors Chairman of the Board Board Meeting P100,000 P150,000

Type of Meeting Committee Members Chairman of the Committee

Committee Meeting P80,000 P100,000 The proposed monthly allowance and per diem of the AboitizPower directors for 2011 will be submitted for the approval of the stockholders during the 2011 Annual Stockholders’ Meeting. (ii) Other Arrangements Other than payment of a director’s allowance and per diem as stated, there are no standard arrangements pursuant to which directors of the Company are compensated, or are to be compensated, directly or indirectly, for any services provided as a director. (3) Employment Contracts and Termination of Employment and Change-in-Control Arrangements There is no compensatory plan or arrangement between AboitizPower and any executive in case of resignation or any other termination of employment or from a change in the management control of AboitizPower. (4) Warrants and Options Outstanding To date, AboitizPower has not granted any stock option to its directors or officers.


Item 11. Security Ownership of Certain Record and Beneficial Owners and Management (1) Security Ownership of Certain Record and Beneficial Owners (more than 5%) as of February 28, 2011:

Title of Class

Name/Address of Stockholder

and Beneficial Owner

Relationship

with AboitizPower

Citizenship

No. of Shares and

Nature of Ownership (Record or Beneficial)

Percent of

Class

Common

Common

Common

1. Aboitiz Equity Ventures, Inc.4

Aboitiz Corporate Center Gov. Manuel A. Cuenco Avenue, Kasambagan, Cebu City 6000

2. PCD Nominee Corp.

3. PCD Nominee Corp.

Stockholder

Stockholder

Stockholder

Filipino

Filipino

Non-Filipino

5,622,113,063

(Record and Beneficial)

804,762,081 (Record)

584,666,672

(Record)

76.40%

10.94%

7.95%

Aboitiz Equity Ventures, Inc. (AEV) is the public holding and management company of the Aboitiz Group, one of the largest conglomerates in the Philippines. As of February 28, 2011, the following entities own five per centum (5%) or more of AEV:

Title of Class

Name/Address of Stockholder and Beneficial

Owner

Citizenship

No. of Shares and

Nature of Ownership (Record or Beneficial)

Percent of

Class

Common

Common

Common

1. Aboitiz & Company, Inc. Aboitiz Corporate Center Gov. Manuel A. Cuenco Avenue Kasambagan, Cebu City 6000 2. PCD Nominee Corporation

3. Ramon Aboitiz Foundation, Inc. 35 Lopez Jaena St., Cebu City, 6000

Filipino

Filipino

Filipino

2,735, 600,915


644,656,703 (Record)

420,915,863


49.54%

11.67%

7.62%

4 Mr. Erramon I. Aboitiz, President and Chief Executive Officer of Aboitiz Equity Ventures, Inc. (AEV), will vote the shares of AEV in AboitizPower in accordance with the directive of the AEV Board of Directors.


(2) Security Ownership of Management as of February 28, 2011 (Record and Beneficial)

Title of Class

Name of Beneficial Owner and Position

Amount and Nature of Beneficial Ownership

Citizenship

Percent of

Class Common Mr. Enrique M. Aboitiz, Jr.

Chairman of the Board of Directors

31

Direct

Filipino

0.00%1 Direct 0.00%Common Mr. Jon Ramon Aboitiz

Vice Chairman

7,792,020 Indirect

Filipino

0.11%1 Direct 0.00%Common Mr. Erramon I. Aboitiz

President and Chief Executive Officer

12,925,000 Indirect

Filipino

0.18%1 Direct 0.00%Common Mr. Mikel A. Aboitiz

Director

7,960,920 Indirect

Filipino

0.11%1 Direct 0.00%Common Mr. Antonio R. Moraza

Director/Executive Vice President & Chief Operating Officer - Power Generation Group

29,004,041 Indirect

Filipino

0.39%2,362,500 Direct 0.03%Common Mr. Jaime Jose Y. Aboitiz

Director/ Executive Vice President & Chief Operating Officer - Power Distribution Group

1,738,594 Indirect

Filipino

0.02%Common Mr. Jose R. Facundo

Independent Director 1,000 Direct Filipino 0.00%

Common Mr. Romeo L. Bernardo Independent Director

1,000 Direct Filipino 0.00%

Common Mr. Jakob Disch Independent Director

1,000 Direct Swiss National

0.00%

Common Mr. Juan Antonio E. Bernad Executive Vice President- Strategy and Regulation


Common Mr. Luis Miguel Aboitiz Senior Vice President – Power Marketing and Trading

2,060,000 Direct Filipino 0.03%

Common Mr. Gabriel T. Mañalac Senior Vice President – Treasurer


Common Mr. Iker M. Aboitiz First Vice President/Chief Financial Officer/Corporate Information Officer

3,177,545 Direct Filipino 0.04%

N/A Mr. Manuel R. Lozano First Vice President/ Chief Financial Officer - Power Generation Group

0 N/A Filipino 0.00%

Common Mr. Raymond E. Cunningham First Vice President - Business Development

42,500 Direct American 0.00%

Common Mr. Manuel M. Orig First Vice President - Mindanao Affairs


Common Mr. Wilfredo R. Bacareza, Jr. Vice President - Project Development


Annual


Title of Class

Name of Beneficial Owner and Position Amount and Nature of Beneficial Ownership

Citizenship Percent of Class

N/A Mr. Thomas J. Sliman, Jr. Vice President – Business Development

0 N/A American 0.00%

N/A Mr. Alvin S. Arco Vice President – Regulatory Affairs


N/A Mr. Anastacio D. Cubos, Jr. Vice President – Special Projects


Common Mr. Raul C. Lucero Vice President for Engineering - Power Distribution Group


92,070 Direct 0.00% Common Ms. Ma. Chona Y. Tiu Vice President and Chief Financial Officer - Power Distribution Group

50,000 Indirect

Filipino

0.00% N/A Mr. Roland U. Gaerlan

Vice President - Marketing 0 N/A Filipino 0.00%

N/A Mr. Bienamer D. Garcia Vice President - Distribution Customer Services


N/A Mr. Dennis de la Serna Assistant Vice President - Regulatory Affairs


Common Mr. Nestor F. Aliman Assistant Vice President - Business Development

43,103 N/A Filipino 0.00%

N/A Ms. Maria P. Garcia Assistant Vice President - Trading


Common Mr. Carlos Copernicus S. Payot Assistant Vice President - Controller (Power Distribution Group)


Common Mr. Clovis B. Racho Assistant Vice President - Procurement and Logistics (Power Distribution Group)


N/A Mr. Aladino B. Borja, Jr. Assistant Vice President - Information Services (Power Distribution Group)


N/A Mr. Ronald Enrico V. Abad Assistant Vice President - Project Development


N/A Mr. Roberto V. Orozco Assistant Vice President - Civil Site Construction


N/A Mr. Crisanto R. Laset, Jr. Assistant Vice President - Power Economics & Distribution System Planning


Common Ms. Katrina M. Platon Assistant Vice President - Legal and Regulatory Affairs


Common Ms. Analiza M. Aleta Assistant Vice President & IT Director (Power Generation Group)



Title of Class

Name of Beneficial Owner and Position

Amount and Nature

of Beneficial Ownership

Citizenship

Percent of

Class

Common Ms. Arazeli L. Malapad Assistant Vice President - Accounting (Power Generation Group - Luzon)


N/A Ms. Paquita S. Tigue - Rafols Assistant Vice President - Accounting (Power Generation Group - Mindanao)


N/A Ms. Ma. Kristina C.V. Rivera Assistant Vice President - Human Resources and Quality (Power Generation Group)


N/A Mr. Juan Manuel J. Gatmaitan Assistant Vice President - Power Marketing


N/A Ms. Katrina Michaela D. Calleja Assistant Vice President - Branding


Common Ms. Ma. Cielita C. Añiga Assistant Vice President - Human Resources (Power Distribution Group)


N/A Ms. Susan S. Policarpio Assistant Vice President - Government Relations


Common Ms. M. Carmela N. Franco Assistant Vice President - Investor Relations


Common Ms. Cristina B. Beloria Assistant Vice President - Controller


Common Ms. M. Jasmine S. Oporto Corporate Secretary


Common Mr. Joseph Trillana T. Gonzales Assistant Corporate Secretary


TOTAL

68,986,385

0.94%

Voting Trust Holders of 5% or More of Common Equity No person holds more than five per centum (5%) of AboitizPower’s common equity under a voting trust or similar agreement. Item 12. Certain Relationships and Related Transactions AboitizPower and its subsidiaries and associates (the Group), in their regular conduct of business, have entered into related party transactions consisting of professional fees, advances and rental fees. These are made on an arm’s length basis and at the current market prices as of the time of the transactions. The Group has existing service contracts with its parent company AEV, for corporate center services, such as human resources, internal audit, legal, IT, treasury and corporate finance, among others. These services are obtained from AEV to enable the Group to realize cost synergies. AEV maintains a pool of highly qualified professionals with business expertise specific to the businesses of the Group.


Transactions are priced on a cost recovery basis. In addition, transaction costs are always benchmarked on third party rates to ensure competitive pricing. Service Level Agreements are in place to ensure quality of service. AboitizPower (Parent) has also provided support services to its business units such as marketing, trading and billing services. During the year, the Company has extended interest-bearing advances to AboitizPower’s subsidiaries and associates namely, Davao Light & Power Company, Inc., Cotabato Light & Power Company, Balamban Enerzone Corporation, and Hedcor, Inc., for working capital requirements. These are made to enhance AboitizPower’s yield on its cash balances. Interest rates are determined by comparing prevailing market rates at the time of the transaction. AboitizPower and certain subsidiaries and associates are leasing office spaces from Cebu Praedia Development Corporation, a subsidiary of AEV. Rental rates are comparable with prevailing market prices. These transactions are covered with lease contracts for a period of three years. Additional information on related party transactions is found under the section on Transactions with and/or Dependence on Related Parties. No other transaction, without proper disclosure, was undertaken by the Company in which any director or executive officer, any nominee for election as director, any beneficial owner (direct or indirect) or any member of his immediate family was involved or had a direct or indirect material interest. AboitizPower employees are required to promptly disclose any business and family-related transactions with the Company to ensure that potential conflicts of interest are brought to the attention of management.

(a) Parent Company

AboitizPower’s parent company is AEV. As of February 28, 2011, AEV owns 76.40% of AboitizPower. In turn, Aboitiz & Company, Inc. (ACO) owns, as of February 28, 2011, 49.54% of AEV.

(b) Resignation or Refusal to Stand for Re-election by Members of the Board of Directors

No director has resigned or declined to stand for re-election to the Board of Directors since the date of AboitizPower’s last annual meeting because of a disagreement with AboitizPower on matters relating to its operations, policies and practices.

Item 13. Corporate Governance AboitizPower has a Manual of Corporate Governance (the Manual) and Code of Ethics and Business Conduct (the Code) to guide the attainment of its corporate goals and strategies. To ensure compliance, copies of the Manual and the Code were disseminated to the Board of Directors, management and employees of AboitizPower. Company-wide orientations on the Manual and the Code were conducted as well. AboitizPower has in place a performance evaluation system for corporate governance. It also participated, and intends to participate in, the annual Corporate Governance Scorecard Survey of the SEC and the PSE to benchmark its corporate governance practices against best practices. The Compliance Officer regularly monitors and evaluates compliance by the Board of Directors, management and employees of the Manual and existing laws and regulations. Together with the Human Resources


Department, the Compliance Officer also ensures the implementation of AboitizPower’s rule against conflict of interests and the misuse of inside and proprietary information throughout the organization. The Compliance Officer regularly reports to the Board Corporate Governance Committee and the Board Audit Committee the Company’s compliance status with existing laws and regulations, as well as the Board’s and employees’ compliance with internal governance policies. Corporate governance is further fostered by the Board’s active role in reviewing and approving corporate goals and strategies set by management as well as in monitoring and evaluating management performance in meeting such goals. The different Board committees - Audit, Corporate Governance, and Risk Management - report regularly to the Board and are crucial in maintaining Board oversight in key management areas. There are no major deviations from the Manual as of the date of this report. The Board of Directors regularly reviews the Manual to ensure that the same remains relevant and responsive to the needs of the organization. Board Attendance The Board’s primary objectives are to improve shareholder returns, to develop responsible long-term investments, and achieve disciplined and sustainable growth. In 2010, the Board held nine regular and special meetings. Below is a summary of the attendance of the Directors:

Legend: P - Present A - Absent *Mr. Jakob Disch was first elected on March 10, 2010 and attended his first board meeting on March 31, 2010.

DIRECTORS

Regular

Special

Executive Strategy Sessions

Regular Meeting

Regular Meeting

Regular Meeting

Regular Meeting

Regular Meeting

Special

Executive Strategy Sessions

Regular Meeting

Total No. of

Meetings Attended by each Director

% of Meetings Attended by each Director

Jan 13 Feb 8 Mar 10 Mar 31 May 17 July 14 Sept 15 Oct 13 Nov 12

Enrique M. Aboitiz, Jr. P P P P P P P P P 9/9 100%

Jon Ramon Aboitiz P A P P P P P P P 8/9 88.88%

Erramon I. Aboitiz P P P P P P P P P 9/9 100%

Antonio R. Moraza P P P P P P P P P 9/9 100%

Mikel A. Aboitiz P P P P P P P P P 9/9 100%

Jaime Jose Y. Aboitiz A P P P P P P P P 8/9 88.88%

Jose R. Facundo

(Ind. Director)

P P P P P P P P P 9/9 100%

Romeo L. Bernardo

(Ind. Director)

P P P P P P P P P 9/9 100%

Jakob Disch (Ind.

Director)*

- - - P A P P P P 5/6 88.33%

TOTAL NO. OF DIRECTORS PRESENT IN EACH MEETING

7/8 7/8 8/8 9/9 8/9 9/9 9/9 9/9 9/9

PERCENTAGE OF NO. OF DIRECTORS PRESENT IN EACH MEETING

87.50% 87.50%

100%

100% 88.88% 100% 100% 100% 100%

103 • SEC Form 17-A

Corporate Governance Initiatives During its regular meeting last February 12, 2009, the Board of Directors of AboitizPower approved the creation of additional Board committees and the consolidation of existing ones. The reorganization aims to a) enhance the role of the Board of Directors in governance, b) better represent and protect the interests of all stakeholders of the Company, c) ensure compliance with regulatory standards and provide appropriate information and updates. In the Amended Manual on Corporate Governance submitted to the SEC on September 24, 2009, the Investor Relations Committee was dissolved and the Board Nominations and Compensation Committee merged with the Board Corporate Governance Committee. It is now called the Board Corporate Governance Committee. On a regular meeting held on May 17, 2010, the Board approved an amendment to the Company’s Amended Manual on Corporate Governance consisting of the folding in of the responsibility of the Board Strategy Committee. As decided by the Board, the functions of the Board Strategy Committee are now subsumed under the functions of the Board of Directors. The mandate as well as the composition of each Board committee are described below:

• The Board Corporate Governance Committee shall represent the Board in discharging its responsibility relating to issues around the Group’s governance principles and guidelines, nomination of persons into Board and Group senior leadership roles and the various compensation matters. Independent Directors comprise majority of the voting members of the Board Corporate Governance Committee.

Chairman: Mikel A. Aboitiz; Members: Erramon I. Aboitiz, Jose R. Facundo, Romeo L. Bernardo, Jakob Disch; Ex-Officio Members: M. Jasmine S. Oporto, Sebastian R. Lacson, Xavier Jose Aboitiz

• The Board Audit Committee shall represent the Board in discharging its responsibility related to

audit matters for the Group. Independent Directors comprise majority of the voting members of the Board Audit Committee.

Chairman: Jose R. Facundo; Members: Romeo L. Bernardo, Jakob Disch, Mikel A. Aboitiz, Jaime Jose Y. Aboitiz; Ex-Officio Members: Iker M. Aboitiz, Rolando C. Cabrera

• The Board Risk Management Committee shall represent the Board in discharging its

responsibility relating to risk management related matters around the Group.

Chairman: Antonio R. Moraza; Members: Erramon I. Aboitiz, Jose R. Facundo, Jakob Disch; Ex-Officio Members: Iker M. Aboitiz, Rolando C. Cabrera


PART V – EXHIBITS AND SCHEDULES Item 14. Exhibits and Reports on SEC Form 17-C (a) Exhibits. None

(b) Reports on SEC Form 17-C Reports filed by the AP on SEC Form 17-C from May 2010 to April 2011 are as follows: Date Disclosure Details May 6, 2010 First Quarter 2010 Financial and Operating Results May 17, 2010 Matters Approved by the Board : Amendments to AboitizPower's Manual on

Corporate Governance) May 17, 2010 Result of the Annual Stockholders' Meeting May 17, 2010 Result of the Organizational Meeting May 19, 2010 Amended Disclosure on Result of the Organizational Meeting May 21, 2010 Amended Disclosure on Result of the Organizational Meeting June 28, 2010 Memorandum of Understanding with STEAG State Power, Inc. partners July 7, 2010 75-MW Ambuklao Hydroelectric Power Plant (Ambuklao Plant)

rehabilitation July 14, 2010 Appointment of Mr. Manuel M. Orig as AboitizPower's First Vice President -

Mindanao Afffairs July 15, 2010 Appointment of the following AboitizPower officers:

- Mr. Dennis de la Serna as Assistant Vice President for Regulatory Affairs - Mr. Nestor F. Aliman as Assistant Vice President for Busines Development - Ms. Maria P. Garcia as Assistant Vice President for Trading

August 3, 2010 Subic Coal Project August 5, 2010 First Half 2010 Financial and Operating Results August 16, 2010 Appointment of External Auditor November 4, 2010 Appointment of Mr. Roland U. Gaerlan as Vice President - Marketing November 4, 2010 Third Quarter 2010 Financial and Operating Results November 4, 2010 Amended Disclosure on Appointment of Mr. Roland U. Gaerlan in

AboitizPower November 12, 2010 Matters approved by the Board: Approval of Amendment to Internal Audit

Charter and Amended By-laws January 3, 2011 Appointment of Ms. Katrina Michaela D. Calleja as Assistant Vice President

for Branding January 5, 2011 Appointment of Officers:

- Mr. Bienamer D. Garcia as Vice President of Distribution Customer Services - Ms. Ma. Cielita C. Añiga as Assistant Vice President of Distribution Human

Resources January 18, 2011 Levy on Pagbilao Plant January 28, 2011 Appointment of Mr. Roberto V. Orozco as Assistant Vice President for Civil

Site Construction February 23, 2011 Nominees for election as Board members for the 2011 annual stockholders'

meeting February 23, 2011 Amendment of the Last Interest Period of the AboitizPower Bonds March 3, 2011 Full Year 2010 Financial and Operating Results March 3, 2011 Matters Approved by the Board: Cash dividend declaration; Record date for

2011 annual stockholders' meeting; Proposed 2011 compensation of members of the board of directors

March 9, 2011 Approval of Listing of Bonds


March 24, 2011 Change of Venue of AboitizPower 2011 annual stockholders' meeting March 31, 2011 Luzon Hydro Corporation Buy-out April 12, 2011 Signing of Notes Facility Agreement

*SGVMC409382*

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December 31

2010 2009

Noncurrent Liabilities Long-term debts - net of current portion and

deferred financing cost (Note 12) 11,777,089,340 11,757,921,409 Pension liability (Note 15) – 2,468,100 Total Noncurrent Liabilities 11,777,089,340 11,760,389,509 Total Liabilities 16,426,756,371 17,823,814,922

Equity Capital stock (Note 13a) 7,358,604,307 7,358,604,307

Additional paid-in capital 12,588,894,332 12,588,894,332 Retained earnings (Note 13b) 4,112,546,810 5,423,880,835 Total Equity 24,060,045,449 25,371,379,474

TOTAL LIABILITIES AND EQUITY P=40,486,801,820 P=43,195,194,396 See accompanying Notes to Parent Company Financial Statements.

*SGVMC409382*

ABOITIZ POWER CORPORATION PARENT COMPANY STATEMENTS OF INCOME

Years Ended December 31 2010 2009 2008

REVENUE Dividends P=1,075,904,684 P=1,982,932,348 P=4,846,493,566 Technical, management and other service fees (Notes 5a and 5c) 395,048,665 223,978,095 236,127,816 Interest income (Notes 4, 5g and 5h) 109,685,170 379,273,110 486,027,457 1,580,638,519 2,586,183,553 5,568,648,839

GENERAL AND ADMINISTRATIVE EXPENSES Interest and other financing charges (Notes 5, 11, 12 and 17) 1,133,154,184 852,308,706 241,942,056 Personnel (Notes 14 and 15) 122,983,132 72,401,218 44,815,023 Service fees 43,634,139 19,853,063 6,067,298 Transportation and travel 32,078,196 25,701,416 21,059,745 Advertising and sponsorships 14,660,864 3,339,550 668,150 Taxes and licenses 11,823,066 4,018,169 8,344,769 Consultation fees and bidding expenses 9,734,419 10,800,445 17,102,023 Depreciation and amortization (Notes 8 and 10) 8,956,057 3,950,754 1,805,989 Rent 4,756,458 1,991,453 770,268 Legal research and development 4,681,971 25,442,688 27,139,548 Professional fees 4,557,230 55,367,677 56,060,396 Training 2,291,367 1,332,297 1,050,746 Entertainment, amusement and recreation 1,870,695 2,198,980 1,804,042 Donations and contributions 874,218 21,976,000 332,000 Information technology project costs (Note 5e) – 52,694,398 36,629,739 Management fees (Note 5d) – 40,000,000 40,000,000 Others 19,000,400 9,131,417 6,813,428

1,415,056,396 1,202,508,231 512,405,220

OTHER INCOME (CHARGES) Gain on redemption of preferred shares (Notes 6 and 7) 881,675,172 – – Foreign exchange gains (losses) - net (34,337,537) 62,653,412 122,749,163 Others (Note 5) 7,701,660 10,286,443 27,003,158

855,039,295 72,939,855 149,752,321

INCOME BEFORE INCOME TAX 1,020,621,418 1,456,615,177 5,205,995,940

PROVISION FOR (BENEFIT FROM) INCOME TAX (Note 16) 124,374,151 (163,724,122) 105,781,969

NET INCOME P=896,247,267 P=1,620,339,299 P=5,100,213,971 See accompanying Notes to Parent Company Financial Statements.

*SGVMC409382*

ABOITIZ POWER CORPORATION PARENT COMPANY STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31

2010 2009 2008

NET INCOME P=896,247,267 P=1,620,339,299 P=5,100,213,971

OTHER COMPREHENSIVE INCOME – – –

TOTAL COMPREHENSIVE INCOME P=896,247,267 P=1,620,339,299 P=5,100,213,971

See accompanying Notes to Parent Company Financial Statements.

*SGVMC409382*

ABOITIZ POWER CORPORATION PARENT COMPANY STATEMENTS OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

Capital Stock (Note 13a)

Additional Paid-In Capital

Retained Earnings

(Note 13b) Total

Balances at January 1, 2010 P=7,358,604,307 P=12,588,894,332 P=5,423,880,835 P=25,371,379,474

Net income for the year – – 896,247,267 896,247,267

Other comprehensive income – – – –

Total comprehensive income – – 896,247,267 896,247,267

Cash dividends at P=0.30 per share (Note 13b) – – (2,207,581,292) (2,207,581,292)

Balances at December 31, 2010 P=7,358,604,307 P=12,588,894,332 P=4,112,546,810 P=24,060,045,449


Net income for the year – – 1,620,339,299 1,620,339,299


Total comprehensive income – – 1,620,339,299 1,620,339,299




Net income for the year – – 5,100,213,971 5,100,213,971


Total comprehensive income – – 5,100,213,971 5,100,213,971



See accompanying Notes to Parent Company Financial Statements.

*SGVMC409382*

ABOITIZ POWER CORPORATION PARENT COMPANY STATEMENTS OF CASH FLOWS


CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax P=1,020,621,418 P=1,456,615,177 P=5,205,995,940 Adjustments for: Interest expense and other financing charges (Notes 5, 11, 12 and 17) 1,133,154,184 852,308,706 241,942,056 Depreciation and amortization (Notes 8 and 10) 8,956,057 3,950,754 1,805,989 Interest income (Notes 4, 5g and 5h) (109,685,170) (379,273,110) (486,027,457) Unrealized foreign exchange losses (gains) (Note 17) (271,967,107) 398,666,135 (88,132,654) Gain on redemption of preferred shares (Notes 6 and 7) (881,675,172) – – Dividend income (1,075,904,684) (1,982,932,348) (4,846,493,566) Operating income (loss) before working capital changes (176,500,474) 349,335,314 29,090,308 Decrease (increase) in: Other receivables (104,970,511) 2,551,700 (11,451,958) Prepaid taxes and other current assets 12,305,222 (18,921,304) (20,917,027) Pension asset (57,798,527) – – Increase (decrease) in: Accounts payable and accrued expenses 26,592,503 (13,457,948) (72,466,529) Pension liability (2,468,100) 1,689,768 (40,728) Net cash generated from (used in) operations (302,839,887) 321,197,530 (75,785,934) Income taxes paid (58,745,892) (68,303,069) (81,710,375) Net cash flows from (used in) operating activities (361,585,779) 252,894,461 (157,496,309)

CASH FLOWS FROM INVESTING ACTIVITIES Decrease (increase) in receivables from related parties 12,677,232,881 (18,265,649,771) (4,500,816,834) Dividends received 1,300,907,051 1,982,932,348 4,617,433,475 Interest received 94,363,489 426,759,606 478,384,985 Proceeds from disposal of property and equipment (Note 8) 48,661 – – Additional investments in: Subsidiary (103,035) (3,427,309,900) (296,128,338) Associates (392,813) (3,125,460) (180,091,927) Additions to: Intangible assets (Note 10) (5,686,820) – – Property and equipment (Note 8) (16,685,869) (12,483,457) (19,753,638) Disposal of investments in: Subsidiary – 1,510,000 – Associate – 5,000,000 – Net cash flows from (used in) investing activities 14,049,683,545 (19,292,366,634) 99,027,723

CASH FLOWS FROM FINANCING ACTIVITIES – Increase (decrease) in payables to related parties 3,911,291,102 (118,922,834) (460,811,162) Payments of long-term debt (5,600,000) (5,600,000) – Interest and other financing charges paid (1,111,671,551) (800,314,804) (222,995,398) Cash dividends paid (2,207,581,292) (1,471,720,861) (1,324,548,775) Net availment (payment) of bank loans (Note 11) (3,260,438,000) 1,059,500,000 – Proceeds from long-term debts (Note 12) – 8,000,000,000 3,890,000,000 Transaction costs from availment of long-term debt – (93,710,734) (42,094,081) Net cash flows from (used in) financing activities (2,673,999,741) 6,569,230,767 1,839,550,584 (Forward)

*SGVMC409382*

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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS P=11,014,098,025 (P=12,470,241,406) P=1,781,081,997

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (6,971,086) (162,673,302) 272,237,409

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 74,803,016 12,707,717,724 10,654,398,317

CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 4 ) P=11,081,929,955 P=74,803,016 P=12,707,717,724 See accompanying Notes to Parent Company Financial Statements.

*SGVMC409382*

ABOITIZ POWER CORPORATION NOTES TO PARENT COMPANY FINANCIAL STATEMENTS 1. Corporate Information

Aboitiz Power Corporation (the Company) is incorporated in the Republic of the Philippines and registered with Securities and Exchange Commission (SEC). The Company is a 76.40% subsidiary of Aboitiz Equity Ventures, Inc. (AEV), a company listed in the Philippine Stock Exchange (PSE), and is the holding company of the entities engaged in power generation, power distribution and other energy-related services of the AEV Group. The Company’s ultimate parent is Aboitiz & Company, Inc. (ACO).

The Company’s registered office address is Aboitiz Corporate Center, Gov. Manuel A. Cuenco Avenue, Kasambagan, Cebu City.

The parent company financial statements as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 were authorized for issue by the Board of Directors (BOD) on March 3, 2011.

2. Basis of Preparation and Summary of Significant Accounting Policies

Basis of Preparation The separate financial statements of the Company have been prepared on the historical cost basis except for derivative asset and derivative liability which are measured at fair value. The financial statements are presented in Philippine Peso, which is the Company’s functional and presentation currency under Philippine Financial Reporting Standard (PFRS). All values are rounded to the nearest Peso, except when otherwise indicated.

The Company also prepares and issues consolidated financial statements for the same period as the separate financial statements that are presented in compliance with PFRS. These may be obtained at Aboitiz Corporate Center, Gov. Manuel A. Cuenco Avenue, Kasambagan, Cebu City.

Statement of Compliance The separate financial statements of the Company have been prepared in compliance with PFRS.

Changes in Accounting Policies and Disclosures The accounting policies adopted are consistent with those of the previous financial year except for the following new and amended PFRSs and Philippine Interpretations which were adopted as of January 1, 2010: • PFRS 2, Share-based Payment (Amendment) - Group Cash-settled Share-based Payment

Transactions effective January 1, 2010 • PFRS 3 (Revised), Business Combinations, and PAS 27 (Amended), Consolidated and

Separate Financial Statements effective July 1, 2009 • PAS 19, Employee Benefits (Amendment) - Group Cash-settled Share-based Payment

Transactions effective July 1, 2009 • PAS 39, Financial Instruments: Recognition and Measurement (Amendment) - Eligible

Hedged Items effective July 1, 2009 • Philippine Interpretation IFRIC 17, Distribution of Non-cash Assets to Owners effective

July 1, 2009

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*SGVMC409382*

Improvements to PFRS Improvements to PFRS, an omnibus of amendments to standards, deal primarily with a view to removing inconsistencies and clarifying wording. There are separate transitional provisions for each standard. The adoption of the following amendments resulted in changes to accounting policies but did not have any impact on the financial position or performance of the Company. • PAS 7, Statement of Cash Flows: States that only expenditure that results in recognizing an

asset can be classified as a cash flow from investing activities. This amendment will impact the presentation in the statement of cash flows.

• PAS 39, Financial Instruments: Recognition and Measurement: Clarifies that a prepayment option is considered closely related to the host contract when the exercise price of a prepayment option reimburses the lenders up to the approximate present value of lost interest for the remaining term of the host contracts. As a result, prepayment penalties identified as embedded derivatives may no longer be required to be accounted as such as they are now considered closely related to the host contract.

Other amendments resulting from the 2008 and 2009 Improvements to PFRS to the following standards did not have any impact on the accounting policies, financial position or performance of the Company: • PFRS 2, Share-based Payment • PFRS 5, Non-current Assets Held for Sale and Discontinued Operations • PFRS 8, Operating Segments • PAS 1, Presentation of Financial Statements • PAS 17, Leases • PAS 34, Interim Financial Reporting • PAS 36, Impairment of Assets • PAS 38, Intangible Assets • Philippine Interpretation IFRIC 9, Reassessment of Embedded Derivatives • Philippine Interpretation IFRIC 16, Hedge of a Net Investment in a Foreign Operation

Standards Issued but not yet Effective Standards issued but not yet effective up to the date of issuance of the Company’s financial statements are listed below. This is a listing of standards and interpretations issued, which the Company reasonably expects to be applicable at a future date. The Company intends to adopt those standards when they become effective.

• PAS 12, Income Taxes (Amendment) - Deferred Tax: Recovery of Underlying Assets

The amendment provides a practical solution to the problem of assessing whether recovery of an asset will be through use or sale. It introduces a presumption that recovery of the carrying amount of an asset will, normally, be through sale.

• PAS 24 (Amended), Related Party Disclosures

The amended standard is effective for annual periods beginning on or after January 1, 2011. It clarified the definition of a related party to simplify the identification of such relationships and to eliminate inconsistencies in its application. The revised standard introduces a partial exemption of disclosure requirements for government-related entities. The Company does not expect any impact on its financial position or performance.

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*SGVMC409382*

• PFRS 9, Financial Instruments: Classification and Measurement PFRS 9, as issued in 2010, reflects the first phase of the work on the replacement of PAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in PAS 39. The standard is effective for annual periods beginning on or after January 1, 2013. In subsequent phases, hedge accounting and derecognition will be addressed. The completion of this project is expected in early 2011. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Company’s financial assets. The Company will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

• Philippine Interpretation IFRIC 14 (Amendment) - Prepayments of a Minimum Funding

Requirement The amendment to Philippine Interpretation IFRIC14 is effective for annual periods beginning on or after January 1, 2011, with retrospective application. The amendment provides guidance on assessing the recoverable amount of a net pension asset. The amendment permits an entity to treat the prepayment of a minimum funding requirement as an asset. The amendment is deemed to have no impact on the financial statements of the Company.

Improvements to PFRS 2010 Improvements to PFRS is an omnibus of amendments to PFRS. The amendments have not been adopted as they become effective for annual periods on or after either July 1, 2010 or January 1, 2011. The amendments listed below are considered to have a reasonably possible impact on the Company: • PFRS 7, Financial Instruments: Disclosures • PAS 1, Presentation of Financial Statements • PAS 27, Consolidated and Separate Financial Statements Summary of Significant Accounting Policies Cash and Cash Equivalents Cash includes cash on hand and in banks. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash with original maturities of three months or less and that are subject to an insignificant risk of change in value. Financial Assets and Liabilities Financial assets and financial liabilities are recognized initially at fair value. Transaction costs, if any, are included in the initial measurement of all financial assets and liabilities, except for financial instruments measured at fair value through profit-or-loss (FVPL). The Company recognizes a financial asset or a financial liability in the parent company balance sheet when it becomes a party to the contractual provisions of the instrument and derecognizes a financial asset (or part of a financial asset) when it no longer controls the contractual rights that comprise the financial instrument, which is normally the case when the instrument is sold, or all the cash flows attributable to the instrument are passed to an independent third party. A financial liability (or a part of a financial liability) is derecognized when the obligation is extinguished. In the case of a regular way purchase or sale of financial assets, recognition and derecognition, as applicable, is done using settlement date accounting. Financial instruments are classified as liabilities or equity in accordance with the substance of the contractual arrangement. Interest, dividends, gains and losses relating to a financial instrument or a component that is a financial liability are reported as expense or income. Distributions to

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*SGVMC409382*

holders of financial instruments classified as equity are charged directly to equity, net of any related income tax benefits. Financial instruments are offset when there is a legally enforceable right to offset and intention to settle either on a net basis or to realize the asset and settle the liability simultaneously. Financial assets and financial liabilities are further classified into the following categories: financial asset or financial liability at FVPL, loans and receivables, held-to-maturity (HTM) investments, AFS financial assets and other financial liabilities. The Company determines the classification at initial recognition and re-evaluates this designation at every reporting date, where appropriate. a. Financial asset or financial liability at FVPL

Financial assets and liabilities at FVPL include financial assets and liabilities classified as held for trading and financial assets and liabilities designated upon initial recognition as at FVPL. Financial assets and liabilities are classified as held for trading if they are acquired for the purpose of selling in the near term or upon initial recognition if it is designated by management as at FVPL. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated and considered as effective hedging instruments. Gains or losses on financial assets held for trading are recognized in the parent company statement of income. Where a contract contains one or more embedded derivatives, the entire hybrid contract may be designated as financial asset at FVPL, except where the embedded derivative does not significantly modify the cash flows or it is clear that separation of the embedded derivative is prohibited. Financial assets may be designated at initial recognition as at FVPL if the following criteria are met: (i) the designation eliminates or significantly reduces the inconsistent treatment that would otherwise arise from measuring the assets or recognizing gains or losses on them on a different basis; (ii) the assets are part of a group of financial assets which are managed and their performance evaluated on a fair value basis, in accordance with a documented risk management strategy; or (iii) the financial asset contains an embedded derivative that would need to be separately recorded.

Included under this category is the Company’s derivative asset and derivative liability.

b. Loans and receivables Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They arise when the Company provides money, goods or services directly to a debtor with no intention of trading the receivables. Loans and receivables are carried at cost or amortized cost in the parent company balance sheet. Amortization is determined using the effective interest rate method. Loans and receivables are included in current assets if maturity is within twelve months of the balance sheet date. Otherwise, these are classified as noncurrent assets. Included under this category are the Company’s cash and cash equivalents (excluding cash on hand) and receivables.

c. HTM investments

HTM investments are quoted non-derivative financial assets with fixed or determinable payments and fixed maturities wherein the Company has the positive intention and ability to hold to maturity. HTM investments are carried at cost or amortized cost in the parent

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*SGVMC409382*

company balance sheet. Amortization is determined by using the effective interest rate method. Assets under this category are classified as current assets if maturity is within twelve months of the balance sheet date and noncurrent assets if maturity is more than a year.

The Company does not have any HTM investments at December 31, 2010 and 2009.

d. AFS financial assets AFS investments are non-derivative financial assets that are either designated in this category or not classified in any of the other categories. After initial recognition, AFS financial assets are measured at fair value with gains or losses being recognized as a separate component of equity until the investment is derecognized or until the investment is determined to be impaired at which time the cumulative gain or loss previously reported in equity is included in the parent company statement of income.

The Company does not have any AFS investments at December 31, 2010 and 2009.

e. Other financial liabilities This category pertains to financial liabilities that are not held for trading or not designated as at FVPL upon the inception of the liability. These include liabilities arising from operations or borrowings.

The liabilities are recognized initially at fair value and are subsequently carried at amortized cost, taking into account the impact of applying the effective interest rate method of amortization (or accretion) for any directly attributable transaction costs.

Included under this category are the Company’s bank loans, amounts owed to related parties, accounts payable and accrued expenses and long-term debts.

‘Day 1’ difference Where the transaction price in a non-active market is different from the fair value of other observable current market transactions in the same instrument or based on a valuation technique whose variables include only data from observable market, the Company recognizes the difference between the transaction price and fair value (a ‘Day 1’ difference) in the parent company statement of income unless it qualifies for recognition as some other type of asset. In cases where unobservable data is used, the difference between the transaction price and model value is only recognized in the parent company statement of income when the inputs become observable or when the instrument is derecognized. For each transaction, the Company determines the appropriate method of recognizing the ‘Day 1’ difference amount. Classification of financial instruments between liability and equity A financial instrument is classified as liability if it provides for a contractual obligation to: • deliver cash or another financial asset to another entity; or • exchange financial assets or financial liabilities with another entity under conditions that are

potentially unfavorable to the Company; or • satisfy the obligation other than by the exchange of a fixed amount of cash or another financial

asset for a fixed number of own equity shares. If the Company does not have an unconditional right to avoid delivering cash or another financial asset to settle its contractual obligation, the obligation meets the definition of a financial liability.

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*SGVMC409382*

Financial instruments are classified as liabilities or equity in accordance with the substance of the contractual arrangement. Interest, dividends, gains and losses relating to a financial instrument or a component that is a financial liability, are reported as income or expense. Distributions to holders of financial instruments classified as equity are charged directly to equity net of any related income tax benefits. The components of issued financial instruments that contain both liability and equity elements are accounted for separately, with the equity component being assigned the residual amount after deducting from the instrument as a whole the amount separately determined as the fair value of the liability component on the date of issue. Derecognition of Financial Assets and Liabilities Financial assets A financial asset (or, where applicable a part of a financial asset or part of a group of similar financial assets) is derecognized where:

• the rights to receive cash flows from the asset have expired; • the Company retains the right to receive cash flows from the asset, but has assumed an

obligation to pay them in full without material delay to a third party under a ‘pass-through’ arrangement; or

• the Company has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

Where the Company has transferred its rights to receive cash flows from an asset and has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the asset is recognized to the extent of the Company’s continuing involvement in the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that the Company could be required to repay. Where continuing involvement takes the form of a written and/or purchased option (including a cash-settled option or similar provision) on the transferred asset, the extent of the Company’s continuing involvement is the amount of the transferred asset that the Company may repurchase, except that in the case of a written put option (including a cash-settled option or similar provision) on an asset measured at fair value, the extent of the Company’s continuing involvement is limited to the lower of the fair value of the transferred asset and the option exercise price. Financial liabilities A financial liability is derecognized when the obligation under the liability is discharged or cancelled or has expired. Where an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognized in the parent company statement of income. Impairment of Financial Assets The Company assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.

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Assets carried at amortized cost If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset’s original effective interest rate (i.e., the effective interest rate computed at initial recognition). The carrying amount of the asset shall be reduced either directly or through the use of an allowance account. The amount of the loss shall be recognized in the parent company statement of income. The Company first assesses whether objective evidence of impairment exists individually for financial assets that are individually significant, and individually or collectively for financial assets that are not individually significant. If it is determined that no objective evidence of impairment exists for an individually assessed financial asset, whether significant or not, the asset is included in a group of financial assets with similar credit risk characteristics and that group of financial assets is collectively assessed for impairment. Assets that are individually assessed for impairment and for which an impairment loss is or continues to be recognized are not included in a collective assessment of impairment.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed. Any subsequent reversal of an impairment loss is recognized in the parent company statement of income, to the extent that the carrying value of the asset does not exceed its amortized cost at the reversal date. Assets carried at cost If there is objective evidence that an impairment loss on an unquoted equity instrument that is not carried at fair value because its fair value cannot be reliably measured, or on a derivative asset that is linked to and must be settled by delivery of such an unquoted equity instrument has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the current market rate of return for a similar financial asset. AFS financial assets If an AFS financial asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization) and its current fair value, less any impairment loss previously recognized in the parent company statement of income, is transferred from equity to the parent company statement of income. Reversals in respect of equity instruments classified as AFS are not recognized in the parent company statement of income. Reversals of impairment losses on debt instruments are reversed through the parent company statement of income, if the increase in fair value of the instrument can be objectively related to an event occurring after the impairment loss was recognized in the parent company statement of income. Investments in Subsidiaries and Associates A subsidiary is an entity over which the Company has the power to govern the financial and operating policies generally accompanying a shareholding of more than half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Company controls another entity. An associate is an entity in which the Company has significant influence and which is neither a subsidiary nor a joint venture.

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*SGVMC409382*

Investments in subsidiaries and associates are carried at cost, less impairment in value, in the parent company financial statements. The Company recognizes income from the investments only to the extent that the Company receives distributions from accumulated profits of the subsidiaries and associates arising after the date of acquisition. Distributions received in excess of such profits are regarded as a recovery of investment and are recognized as a reduction of the cost of the investment. Investment Property Investment property pertains to land not used in operations. Initially, investment property is measured at cost including transaction costs. Subsequent to initial recognition investment property is stated at cost less any impairment in value. Investment property is derecognized when it has either been disposed of or when the investment property is permanently withdrawn from use and no future benefit is expected from its disposal. Any gain or loss on the derecognition of an investment property is recognized in the parent company statement of income in the year of derecognition. Property and Equipment Property and equipment are stated at cost less accumulated depreciation and accumulated impairment in value, if any. Such cost includes the cost of replacing parts of such property and equipment. Depreciation is calculated on a straight-line basis over the useful lives of the assets as follows:

Category Number of Years Transportation equipment 3 - 5 Office and tools equipment 3 Communication equipment 3 Leasehold improvements 10

Leasehold improvements are amortized over the period of the lease agreement or the estimated useful lives of the improvements, whichever is shorter. Fully depreciated assets are retained in the accounts until these are no longer in use. When assets are retired or otherwise disposed of, both the cost and related accumulated depreciation and amortization and any allowance for impairment losses are removed from the accounts and any resulting gain or loss is credited or charged to current operations. An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the parent company statement of income in the year the asset is derecognized. The carrying values of property and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying value may not be recoverable.

The asset’s useful lives and depreciation method are reviewed, and adjusted if appropriate, at each financial year-end.

Construction in progress represents properties under construction and is stated at cost. This includes cost of construction and other direct cost. Construction in progress is not depreciated until such time the relevant assets are completed and available for use.

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*SGVMC409382*

Impairment of Nonfinancial Assets The Company assesses at each reporting date whether there is an indication that assets may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Company makes an estimate of the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cash-generating unit’s (CGU) fair value less costs to sell and its value in use (VIU) and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Impairment losses of continuing operations are recognized in the parent company statement of income in those expense categories consistent with the function of the impaired asset. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company makes an estimates of the asset’s or CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the parent company statement of income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Foreign Currency Transactions The Company’s financial statements are presented in Philippine Peso, which is the Company’s functional currency. Transactions in foreign currencies are recorded using the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are restated using the rate of exchange at balance sheet date. Exchange gains and losses arising from foreign currency transactions and translations of foreign currency denominated monetary assets and liabilities are credited to or charged against current operations. Revenue Recognition Revenue is recognized to the extent that it is probable that the economic benefits will flow to the Company and the revenue can be reliably measured, regardless of when the payment is being made. Revenue is measured at the fair value of the consideration received or receivable, taking into account contractually defined terms of payment and excluding taxes or duty. The Company assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent. The Company assesses whether it is acting as a principal or agent in all of its revenue arrangements. The following specific recognition criteria must also be met before revenue is recognized:

Dividend income Dividend income is recognized when the Company’s right to receive payment is established.

Interest income Interest income is recognized as it accrues taking into account the effective yield of the asset.

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*SGVMC409382*

Technical, management and service fees Technical, management and services fees are recognized when the related services are rendered. Expenses Expenses are decreases in economic benefits during the accounting period in the form of outflows or decrease of assets or incurrence of liabilities that result in decreases in equity, other than those relating to distributions to equity participants. Expenses are recognized when incurred. Pension Benefits The cost of providing benefits under the defined benefit plan is determined separately for each plan using the projected unit credit actuarial valuation method. Actuarial gains and losses are recognized as income or expense when the net cumulative unrecognized actuarial gains and losses for at the end of the previous reporting year exceeded 10% of the higher of the defined benefit obligation and the fair value of plan assets at that date. These gains or losses are recognized over the expected average remaining working lives of the employees participating in the plan. The past service cost is recognized as an expense on a straight-line basis over the average period until the benefits become vested. If the benefits are already vested immediately following the introduction of, or changes to, a pension plan, past service cost is recognized immediately. The defined benefit liability is the aggregate of the present value of the defined benefit obligation and actuarial gains and losses not recognized reduced by past service cost not yet recognized and the fair value of plan assets out of which the obligations are to be settled directly. If such aggregate is negative, the asset is measured at the lower of such aggregate or the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan. If the asset is measured at the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan, net actuarial losses of the current period and past service cost of the current period are recognized immediately to the extent that they exceed any reduction in the present value of those economic benefits. If there is no change or an increase in the present value of the economic benefits, the entire net actuarial losses of the current period and past service cost of the current period are recognized immediately. Similarly, net actuarial gains of the current period after the deduction of past service cost of the current period exceeding any increase in the present value of the economic benefits stated above are recognized immediately if the asset is measured at the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan. If there is no change or a decrease in the present value of the economic benefits, the entire net actuarial gains of the current period after the deduction of past service cost of the current period are recognized immediately. Income Taxes Current income tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted as of the balance sheet date.

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*SGVMC409382*

Deferred income tax Deferred income tax is provided using the balance sheet liability method on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognized for all taxable temporary differences, except: • where the deferred income tax liability arises from the initial recognition of goodwill or of

an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and,

• in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred income tax assets are recognized for all deductible temporary differences, carryforward benefits of net operating loss carryover (NOLCO) and minimum corporate income tax (MCIT), to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carryforward benefits of NOLCO and MCIT can be utilized except:

• where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and,

• in respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred income tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become probable that future taxable profit will allow the deferred income tax asset to be recovered. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted as of the balance sheet date.

Deferred income tax assets and deferred income tax liabilities are offset, if, and only if, a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred income taxes relate to the same taxable entity and the same taxation authority. Borrowing Costs Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period of time to get ready for its intended use or sale are

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*SGVMC409382*

capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period they occur. Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds.

Provisions and Contingencies Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event and it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Company expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the parent company statement of income, net of any reimbursement. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as an interest expense. Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognized but are disclosed in the financial statements when an inflow of economic benefits is probable. Events After the Reporting Period Post year-end events that provide additional information about the Company’s position at balance sheet date (adjusting events) are reflected in the financial statements. Post year-end events that are not adjusting events are disclosed when material.

3. Significant Judgments and Estimates The preparation of the Company’s financial statements requires management to make judgments, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities and the disclosure of contingent liabilities. However, uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of the asset or liability affected in the future periods. Judgment In the process of applying the Company’s accounting policies, management has made judgments, apart from those involving estimations, which have the most significant effect on the amounts recognized in the financial statements: Determining functional currency Based on the economic substance of the underlying circumstances relevant to the Company, the functional currency of the Company has been determined to be the Philippine Peso. The Philippine Peso is the currency of the primary economic environment in which the Company operates and it is the currency that mainly influences the sale of services and the costs of providing the services.

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*SGVMC409382*

Classification of financial instruments The Company exercises judgment in classifying a financial instrument, or its component parts, on initial recognition as either a financial asset, a financial liability or an equity instrument in accordance with the substance of the contractual arrangement and the definition of a financial asset, a financial liability or an equity instrument. The substance of a financial instrument, rather than its legal form, governs its classification in the parent company balance sheet.

Estimation Uncertainty The key assumptions concerning the future and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below. Impairment of receivables The Company maintains allowance for impairment of receivables at a level considered adequate to provide for potential uncollectible receivables. The level of this allowance is evaluated by management on the basis of the factors that affect the collectibility of the accounts. These factors include, but are not limited to, the Company’s relationship with its debtors, debtor’s current credit status and other known market factors. The Company reviews the age and status of receivables and identifies accounts that are to be provided with allowance either individually or collectively. The amount and timing of recorded expenses for any period would differ if the Company made different judgment or utilized different estimates. An increase in the Company’s allowance for impairment of receivables will increase the Company’s recorded expenses and decrease current assets. No provision for allowance for impairment of receivables was recognized as of December 31, 2010 and 2009. As of December 31, 2010 and 2009, the Company’s receivables amounted to P=10.7 billion and P=23.5 billion, respectively (see Note 5). Impairment of investments in subsidiaries and associates, investment property, property and equipment, computer software license and prepaid taxes and other current assets The Company assesses whether there are any indicators of impairment for all non-financial assets. Determining the recoverable amount of the assets, which require the determination of future cash flows expected to be generated from the continued use and ultimate disposition of such assets, requires the Company to make estimates and assumptions that can materially affect its parent company financial statements. Future events could cause the Company to conclude that these assets are impaired. Any resulting impairment loss could have a material adverse impact on the financial condition and results of operations. As of December 31, 2010, the carrying values of investments in subsidiaries, investments in associates, investment property, property and equipment, computer software license and prepaid taxes and other current assets amounted to P=11.5 billion, P=6.9 billion, P=10.0 million, P=41.2 million, P=5.4 million and P=90.0 million, respectively. As of December 31, 2009, the carrying values of investments in subsidiaries, investments in associates, investment property, property and equipment and prepaid taxes and other current assets amounted to P=11.6 billion, P=7.7 billion, P=10.0 million, P=33.2 million and P=85.0 million, respectively. No impairment losses were recognized in 2010 and 2009 (see Notes 6, 7, 8, 9 and 10). Pension benefits The determination of the Company’s obligation and cost of pension is dependent on the selection of certain assumptions used by actuaries in calculating such amounts. Those assumptions are described in Note 15, Retirement Costs, and include, among others, discount rates, expected rates of return on plan assets and rates of future salary increase. In accordance with PAS 19,

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*SGVMC409382*

Employee Benefits, actual results that differ from the Company’s assumptions are accumulated and amortized over future periods and therefore, generally affect the Company’s recognized expenses and recorded obligation in such future periods. While management believes that its assumptions are reasonable and appropriate, significant differences in the actual experience or significant changes in the assumptions may materially affect the Company’s pension and other post-employment obligations. Retirement benefit expense amounted to P=17.2 million, P=5.4 million and P=2.3 million in 2010, 2009 and 2008, respectively. The Company has pension asset amounting to P=57.8 million as of December 31, 2010 and pension liability amounting to P=2.5 million as of December 31, 2009 (see Note 15). Fair values of financial instruments The Company carries certain financial assets and liabilities at fair value, which requires extensive use of accounting estimates and judgment. While significant components of fair value measurement were determined using verifiable objective evidence (i.e. foreign exchange rates, interest rates, volatility rates), the amount of changes in fair value would differ if the Company utilized different valuation methodologies and assumptions. Any changes in fair value of these financial assets and liabilities would affect the parent company statement of income and equity. Where the fair values of certain financial assets and financial liabilities recorded in the parent company balance sheet cannot be derived from active markets, they are determined using internal valuation techniques using generally accepted market valuation models. The inputs to these models are taken from observable markets where possible, but where this is not feasible, estimates are used in establishing fair values. The fair values of the Company’s financial instruments are presented in Note 18 to the parent company financial statements. Deferred income tax assets The Company’s assessment on the recognition of deferred income tax assets on non-deductible temporary differences is based on the budgeted taxable income of the following reporting period. This budget is based on the Company’s past results and future expectations on revenue and expenses. As of December 31, 2010 and 2009, gross deferred income tax assets amounted to P=130.1 million and P=198.1 million, respectively. No deferred income tax assets were recognized for MCIT amounting to P=23.8 million incurred in 2010 and NOLCO amounting to P=369.5 and P=13.3 million incurred in 2010 and 2009, respectively (see Note 16). Legal contingencies The estimate of probable costs for the resolution of possible claims has been developed in consultation with outside counsel handling the Company’s defense in these matters and is based upon an analysis of potential results. No provision for probable losses arising from legal contingencies was recognized as of December 31, 2010 and 2009.

4. Cash and Cash Equivalents Cash in banks earn interest at floating rates based on daily bank deposit rates. Short-term investments are made for varying periods between one day and three months depending on the immediate cash requirements of the Company and earn interest at the respective short-term investment rates. Interest earned on cash and cash equivalents amounted to P=89.1 million in 2010, P=294.4 million in 2009 and P=375.9 million in 2008.

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5. Related Party Transactions

The Company, in its normal course of business, has transactions with its related parties, which consist of the following: a. The Company has management agreements with each of the following subsidiaries: Cotabato

Light & Power Company (CLP), Cotabato Ice Plant, Inc. (CIPI), Davao Light and Power Co., Inc. (DLP), Cebu Private Power Corporation (CPPC), Subic Enerzone Corporation (SEZ) and Hedcor Inc. (HI), for which it is entitled to management fees. Management fees charged to related parties amounted to P=242.4 million in 2010, P=215.5 million in 2009 and P=194.1 million in 2008.

b. The Company served as a guarantor on a loan obtained by HI from a local bank up to

March 27, 2009. Since then, the Company ceased to be the guarantor of the loan of HI and transferred the same to Aboitiz Renewables, Inc. (ARI; formerly Philippine Hydropower Corporation). As a guarantor, the Company received a guarantee fee amounting to nil in 2010, P=3.1 million in 2009, and P=13.1 million in 2008 (presented as part of “Other income” in the parent company statements of income).

The Company also obtained standby letters of credit (SBLC) and is acting as surety for the benefit of certain subsidiaries and associates in connection with certain loans and credit accommodations. As at December 31, 2010, the Company provided SBLC’s for STEAG State Power Inc. (STEAG), Luzon Hydro Corporation (LHC), SN Aboitiz Power - Magat, Inc. (SNAP M), SN Aboitiz Power Benguet, Inc. (SNAP B), HI and Hedcor Sibulan, Inc. (HSI) in the amount of P=1.7 billion; guarantee on the bank loans of CLP, DLP, HI and SEZ in the amount of P=689.8 million. As at December 31, 2009, the Company provided SBLC’s for STEAG, LHC, SNAP M and SNAP B in the amount of P=1.8 billion; guarantee on the bank loans of CLP, DLP, Aboitiz Energy Solutions, Inc. (AESI) and Balamban Enerzone Corporation (BEZ) in the amount of P=1.03 billion.

c. The Company renders various services to related parties such as technical and legal assistance for various projects, trainings and other services. Fees charged to related parties for these services amounted to P=143.7 million in 2010, P=2.2 million in 2009 and P=10.3 million in 2008.

d. Management fees charged by AEV to the Company amounted to nil in 2010, P=40.0 million in 2009 and P=40.0 million in 2008. In 2010, the Company set up support teams that included the management services previously rendered by AEV. Thus, no management fees were charged in 2010.

e. Share in information technology project costs of AEV amounted to nil in 2010, P=32.5 million in 2009 and P=36.6 million in 2008.

f. Cash deposits with Unionbank of the Philippines at prevailing market terms. Total cash deposit amounted to P=2.7 billion and P=74.2 million as of December 31, 2010 and 2009, respectively. Unionbank is an associate of AEV.

g. Unsecured advances to ACO and AEV for operational charges earn interest at 4% per annum, with no fixed payment terms. Advances amounted to P=15.7 million and P=0.3 million as of December 31, 2010 and 2009, respectively. Interest income earned on these deposits amounted to P=0.7 million in 2010 and P=0.01 million in 2009 and P=1.2 million in 2008.

h. Non-interest bearing advances to/from related parties that are payable on demand. Interest bearing advances are payable within one year. Interest income earned on these advances amounted to P=19.9 million in 2010, P=84.8 million in 2009 and P=110.1 million in 2008.

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i. Total compensation and benefits of key management personnel of the Company are as follows: 2010 2009 2008 Short-term benefits P=73,009,329 P=51,840,857 P=32,314,020 Post employment benefits 5,590,671 4,509,143 428,528 P=78,600,000 P=56,350,000 P=32,742,548

The parent company balance sheets include the following significant amounts resulting from the above transactions:

Receivables from Related Parties Amounts Owed to Related Parties Name of Company 2010 2009 2010 2009 Parents: AEV (Immediate) P=15,428,990 P=– P=– P=20,644,585 ACO (Ultimate) 319,560 242,769 – –

Subsidiaries: ARI 10,361,676,174 19,874,813,015 – – HI 21,957,814 3,088,000 – – Therma Luzon, Inc. (TLI) 21,086,208 – – –

Subsidiaries: AP Renewables, Inc. (APRI) 20,602,766 6,568 – – Therma Marine, Inc. (Therma Marine) 17,043,318 – – – DLP 16,307,874 12,536,963 – – CLP 1,245,184 1,113,227 – – Thema Power-Visayas, Inc. (TPVI) 903,739 – – – AESI 191,259 – – – SEZ 154,307 10,200 – – Therma Power, Inc. (TPI) – 3,040,177,980 3,113,662,486 – Abovant Holdings, Inc. (AHI) – 1,101,074 – –

Associates: Cebu Energy Development Corp. (CEDC) 45,100,000 272,548,447 – – Redondo Peninsula Energy, Inc. (RPEI) 15,782,252 620,178 – – Visayan Electric Co., Inc. (VECO) 9,341,766 4,860,500 – – SNAP M 4,860,500 4,860,500 – – Manila Oslo Renewable Enterprise, Inc. (MORE) 4,860,500 – – – East Asia Utilities Corporation (EAUC) 2,825 – 129,999,300 1,145,252,500 STEAG – 225,002,366 – –

Others: Prism Energy, Inc. 792,453 757,500 – – Mazzaraty Energy Corporation 560,857 560,857 – –

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6. Investments in Subsidiaries

The details of the Company’s investments in subsidiaries follow:

2010 2009

Aboitiz Renewables, Inc, (ARI) P=5,750,185,722 P=5,750,185,722 Davao Light & Power Company (DLP) 738,348,601 738,253,885 Mactan Enerzone Corporation (MEZ) 609,532,287 609,532,287 Balamban Enerzone Corporation (BEZ) 444,869,161 444,869,161 Subic Enerzone Corporation (SEZ) 227,000,000 227,000,000 Cotabato Light & Power Company (CLP) 214,040,236 214,031,918 Aboitiz Energy Solutions, Inc. (AESI) 21,000,000 21,000,000 Cebu Private Power Corporation (CPPC) 17,806,608 178,066,080 Adventenergy, Inc. (AI) 625,000 625,000 Therma Power, Inc. (TPI) 5,000 5,000 8,023,412,615 8,183,569,053 Deposit for future subscription in ARI 3,426,882,661 3,426,882,661 P=11,450,295,276 P=11,610,451,714

The Company’s subsidiaries (all incorporated in the Philippines) and the corresponding percentage

equity ownership are as follows:

2010 2009

Name of Company Nature of Business Direct Indirect Direct Indirect Aboitiz Renewables Inc. (ARI) and

Subsidiaries: Holding company 100.00% – 100.00% – Hedcor, Inc. (HI) Power generation – 100.00% – 100.00% Hedcor Tamugan Inc.* Power generation – 100.00% – 100.00% Hedcor Sibulan, Inc. (HSI) Power generation – 100.00% – 100.00% Cleanergy Inc.* Power generation – 100.00% – 100.00% Hydro Electric Development

Corporation* Power generation – 99.97% – 99.97% Hedcor Benguet, Inc.* Power generation – 100.00% – 100.00% AP Renewables, Inc. Power generation – 100.00% – 100.00%

Therma Power, Inc. (TPI) and Subsidiaries Holding company 100.00% – 100.00% – Therma Marine, Inc. (Therma Marine) Power generation – 100.00% – 100.00% Therma Luzon Inc. (TLI) Power generation – 100.00% – 100.00% Therma Mobile, Inc. (Therma Mobile)* Power generation – 100.00% – 100.00% Therma Power - Visayas, Inc (TPVI)* Power generation – 100.00% – 100.00% Therma Pagbilao, Inc. (Therma

Pagbilao)* Power generation – 100.00% – 100.00% Abovant Holdings, Inc. Holding company – 60.00% – 60.00%

Mactan Enerzone Corporation (MEZ) Power distribution 100.00% – 100.00% – Aboitiz Energy Solutions, Inc. (AESI) Energy related

service provider 100.00% – 100.00% –

Balamban Enerzone Corporation (BEZ) Power distribution 100.00% – 100.00% – Adventenergy, Inc.* Retail of electricity 100.00% – 100.00% – Davao Light & Power Company, Inc. (DLP) Power distribution 99.93% – 99.93% – Cotabato Light & Power Company (CLP) Power distribution 99.94% – 99.93% – Subic Enerzone Corporation (SEZ) Power distribution 65.00% 34.97% 65.00% 34.97% Cebu Private Power Corporation (CPPC) Power generation 60.00% – 60.00% – *No commercial operations as of December 31, 2010

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*SGVMC409382*

In 2010 and 2009, the Company, through its subsidiaries has indirect equity ownerships in the following companies:

Investing Subsidiary

Nature of Business

Effective Ownership 2010 2009

Luzon Hydro Corporation (LHC) ARI Power generation 50.00% 50.00% Manila-Oslo Renewable Enterprise, Inc.

(MORE) ARI Holding company 83.33% 83.33%

SN Aboitiz Power-Magat, Inc. (SNAP M) ARI Power generation 50.00% 50.00% SN Aboitiz Power-Benguet, Inc.(SNAP B) ARI Power generation 50.00% 50.00% SN Aboitiz Power Pangasinan, Inc.(SNAP P) ARI Power generation 50.00% 50.00% Cordillera Hydro Corp ARI Power generation 35.00% 35.00% Cebu Energy Development Corporation

(CEDC) AHI Power generation 26.40% 26.40%

Redondo Peninsula Energy, Inc. (RP Energy) TPI Power generation 50.00% 50.00%

ARI’s interest in MORE does not constitute control because the shareholders’ agreement stipulate that management of MORE is vested in its BOD and the affirmative vote of the other shareholder is required for the approval of certain corporate actions which include financial and operating undertakings. SNAP P, CEDC and RPEI have not yet started commercial operations as of December 31, 2010. Following the approval by SEC of the amendments on CPPC’s Articles of Incorporation on July 29, 2010, CPPC effected the conversion of its outstanding 5.4 million common shares to 5.4 million redeemable preferred shares (RPS). Sixty percent (60%) of the shares converted or 3.24 million shares is attributable to the Company.

In December 2010, CPPC redeemed the entire 3.24 million shares attributable to the Company at P=212 per share. The total redemption price amounting to P=688.3 million was set-off against the Company’s advances from CPPC. As a result, the Company recognized “Gain on redemption of preferred shares” amounting to P=528.0 million. Following is the summarized financial information of significant subsidiaries (amounts in thousands):

2010 2009 ARI and Subsidiaries Total current assets P=3,821,238 P=3,380,081 Total noncurrent assets 41,655,475 26,440,867 Total current liabilities 12,241,577 21,512,749 Total noncurrent liabilities 3,813,683 4,136,702 Gross revenue 17,615,717 7,545,925 Net income 13,691,582 3,366,097

(Forward)

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2010 2009 TPI and Subsidiaries Total current assets P=13,571,434 P=3,208,103 Total noncurrent assets 48,387,897 47,353,333 Total current liabilities 4,907,823 7,358,385 Total noncurrent liabilities 47,512,080 43,315,170 Gross revenue 27,323,737 2,800,786 Net income (loss) 9,655,195 (105,763) DLP Total current assets P=820,455 P=800,313 Total noncurrent assets 4,498,321 2,746,635 Total current liabilities 1,113,311 1,527,255 Total noncurrent liabilities 2,055,815 1,533,737 Gross revenue 8,983,027 7,403,080 Net income 831,076 872,888 SEZ Total current assets P=443,401 P=379,856 Total noncurrent assets 953,074 899,229 Total current liabilities 516,187 262,407 Total noncurrent liabilities 497,358 677,321 Gross revenue 1,816,962 1,651,321 Gross profit 319,700 312,716 Net income 143,549 146,427 CLP Total current assets P=288,827 P=206,909 Total noncurrent assets 369,389 299,413 Total current liabilities 347,725 271,981 Total noncurrent liabilities 88,351 84,419 Gross revenue 801,159 650,347 Net income 44,325 31,820 CPPC Total current assets P=903,989 P=1,250,902 Total noncurrent assets 489,496 617781 Total current liabilities 400,116 372400 Total noncurrent liabilities 488,162 79,328 Gross revenue 2,042,950 2,119,132 Net income 126,315 294,623 MEZ Total current assets P=157,372 P=122,889 Total noncurrent assets 114,517 82,718 Total current liabilities 60,056 73,680 Total noncurrent liabilities 45,612 43,465 Gross revenue 747,433 597,845 Gross profit 119,429 94,788 Net income 94,759 68,808

(Forward)

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2010 2009 BEZ Total current assets P=118,573 P=126,496 Total noncurrent assets 124,500 109,065 Total current liabilities 66,147 117,361 Total noncurrent liabilities 77,673 82,718 Gross revenue 704,611 431,834 Gross profit 71,070 44,372 Net income 49,534 27,268 AESI Total current assets P=31,738 P=22,466 Total noncurrent assets 29,013 21,877 Total current liabilities 5,497 11,125 Noncurrent liabilities 227 – Gross revenue 62,524 61,598 Net income 21,809 10,722

7. Investments in Associates

The details of the Company’s investments in associates follow:

2010 2009

STEAG State Power, Inc. (STEAG) P=4,400,611,465 P=4,400,611,465 Hijos de F. Escaño, Inc. (HIJOS) 858,069,586 858,069,586 Visayan Electric Company (VECO) 657,505,435 657,112,622 Western Mindanao Power Corporation (WMPC) 263,664,589 263,664,589 East Asia Utilities Corporation (EAUC) 217,550,994 1,009,142,750 Pampanga Energy Ventures, Inc. (PEVI) 209,465,106 209,465,106 San Fernando Electric Light & Power Co., Inc.

(SFELAPCO) 180,863,801 180,863,801 Southern Philippines Power Corporation (SPPC) 152,586,890 152,586,890

P=6,940,317,866 P=7,731,516,809

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The percentage of the Company’s ownership in associates is as follows:

Percentage of Ownership

Name of Company Nature of Business 2010 2009 VECO* Power distribution 43.44% 43.43% EAUC Power generation 50.00% 50.00% HIJOS* Holding company 46.73% 46.73% SFELAPCO** Power distribution 20.29% 20.29% PEVI** Holding company 42.84% 42.84% STEAG Power generation 34.00% 34.00% SPPC Power generation 20.00% 20.00% WMPC Power generation 20.00% 20.00%

*HIJOS has direct ownership in VECO of 25.15% in 2010 and 2009. Accordingly, the Company has effective ownership in VECO of 55.19% in 2010 and 55.18% in 2009, respectively. The Company’s effective ownership in VECO does not constitute control as the other shareholders’ group has control over VECO’s financial and operating policies.

**PEVI has direct ownership in SFELAPCO of 54.83% in 2010 and 2009. Accordingly, the Company has effective ownership in SFELAPCO of 43.78% in 2010 and 2009.

Following the approval by SEC of the amendments on EAUC’s Articles of Incorporation on September 27, 2010, EAUC effected the conversion of its outstanding 90 million common shares to 900,000 Series A RPS. Fifty percent (50%) of the shares converted or 45 million shares is attributable to the Company. In October 2010, EAUC redeemed 392,210 Series A RPS attributable to the Company at P=2,920 per share. The book value of the redeemed shares amounted to P=791.6 million, and the total redemption price amounting to P=1.15 billion was set-off against the Company’s advances from EAUC. As a result, the Company recognized “Gain on redemption of preferred shares” amounting to P=353.7 million. Following is the summarized financial information of significant associates (amounts in thousands):

2010 2009 VECO

Total current assets P=3,251,473 P=1,424,371 Total noncurrent assets 7,878,006 7,532,706 Total current liabilities 2,513,044 1,902,171 Total noncurrent liabilities 3,939,339 2,546,256 Gross revenue 13,405,730 10,830,879 Net income 609,526 315,082

(Forward)

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2010 2009 EAUC

Total current assets P=552,025 P=697,187 Total noncurrent assets 1,002,339 3,122,061 Total current liabilities 166,788 255,217 Total noncurrent liabilities 10,861 9,565 Gross revenue 1,741,244 1,381,633 Net income 252,754 286,577

STEAG Total current assets P=5,624,376 P=8,029,261 Total noncurrent assets 11,129,719 10,924,231 Total current liabilities 1,659,345 2,307,605 Total noncurrent liabilities 3,348,866 6,880,704 Gross revenue 6,507,354 6,205,924 Net income 1,754,369 2,602,400

WMPC Total current assets P=1,031,813 P=753,640 Total noncurrent assets 1,584,896 1,909,313 Total current liabilities 148,541 228,596 Total noncurrent liabilities 143,422 150,406 Gross revenue 1,324,461 1,206,970 Net income 851,962 524,283

SFELAPCO Total current assets P=669,949 P=454,647 Total noncurrent assets 1,103,853 1,064,917 Total current liabilities 466,986 406,246 Total noncurrent liabilities 334,181 349,027 Gross revenue 3,048,028 2,564,866 Net income 267,483 72,024

SPPC Total current assets P=580,253 P=508,700 Total noncurrent assets 999,546 1,339,635 Total current liabilities 120,986 126,524 Total noncurrent liabilities 302,659 465,533 Gross revenue 709,774 687,843 Net income 227,719 243,606

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8. Property and Equipment December 31, 2010

Transportation Equipment

Office and Tools Equipment

Communication Equipment

Leasehold Improvements Total

Cost At January 1 P=17,203,591 P=3,371,373 P=17,965 P=19,914,815 P=40,507,744 Additions 9,867,907 6,076,463 218,904 522,595 16,685,869 Disposals – (87,388) – – (87,388) At December 31 27,071,498 9,360,448 236,869 20,437,410 57,106,225 Accumulated Depreciation At January 1 5,051,691 1,273,515 17,965 995,741 7,338,912 Additions 4,666,059 1,927,189 39,597 1,991,481 8,624,326 Disposals – (38,727) – – (38,727) At December 31 9,717,750 3,161,977 57,562 2,987,222 15,924,511 Net Book Value P=17,353,748 P=6,198,471 P=179,307 P=17,450,188 P=41,181,714

December 31, 2009

Transportation Equipment

Office and Tools Equipment

Communication Equipment

Leasehold Improvements

Construction in Progress Total

Cost At January 1 P=7,777,300 P=1,396,870 P=17,965 P=– P=18,832,152 P=28,024,287 Additions 9,426,291 1,974,503 – – 1,082,663 12,483,457 Reclassifications – – – 19,914,815 (19,914,815) – At December 31 17,203,591 3,371,373 17,965 19,914,815 – 40,507,744 Accumulated Depreciation At January 1 2,641,485 728,708 17,965 – – 3,388,158 Additions 2,410,206 544,807 – 995,741 – 3,950,754 At December 31 5,051,691 1,273,515 17,965 995,741 – 7,338,912 Net Book Value P=12,151,900 P=2,097,858 P=– P=18,919,074 P=– P=33,168,832

In 2010, the disposals on property and equipment were made at book value.

9. Investment Property

Investment property pertains to land not used in operations. The assessed value per Real Property Tax Declaration of the investment property amounted to P=10.0 million as of December 31, 2010 and 2009.

10. Computer Software License

In 2010, the Company acquired computer software license amounting to P=5.7 million and recognized related amortization amounting to P=0.3 million.

11. Bank Loans

Floating Rate Bank Loan - $81.0 million On November 13, 2007, the Company obtained an unsecured short-term US dollar-denominated loan amounting to $81.0 million from local banks to finance the purchase of 34% in STEAG. The loan bears interest rate at London Interbank Offered Rates (LIBOR) plus a certain spread which shall be payable monthly. Annual interest rates ranged from 1.75% to 2.63 %, 1.75% to 4.24 % and 3.28% to 5.79% in 2010, 2009 and 2008, respectively. Total interest expense charged to the

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*SGVMC409382*

parent company statements of income amounted to P=17.9 million in 2010, P=110.3 million in 2009 and P=190.00 million in 2008. In March 2010, the Company paid $64.3 million of the loan while the remaining $16.7 million was fully paid in April 2010. Fixed Rate Bank Loans - P=1.1 billion In 2009, the Company obtained a short-term peso loan from local banks for working capital requirements. Annual interest rates ranged from 2.24% to 5.10% in 2010 and 5.10% to 5.50% in 2009. Total interest expense charged to the parent company statements of income amounted to P=43.4 million in 2010 and P=49.2 million in 2009. The Company made a full payment on the loan in June 2010. Fixed Rate Bank Loans - P=1.3 billion In 2010, the Company obtained short-term peso loan from local banks for working capital requirements. As of December 31, 2010, P=1.3 billion are still outstanding with maturity date of January 21, 2011. Annual interest rates ranged from 2.24% to 5.10% in 2010. Total interest expense charged to the parent company statements of income amounted to P=1.8 million in 2010. The Company fully paid the amount on the maturity date.

12. Long-term Debts Fixed Rate Notes - P=3.89 billion On December 18, 2008 (issue date), the Company availed a total of P=3.89 billion from the Notes Facility Agreement it signed on December 15, 2008 with BDO Capital & Investment Corporation, BPI Capital Corporation, First Metro Investment Corporation (FMIC), and ING Bank N.V. -Manila Branch as Joint Lead Managers, the proceeds of which were used to finance its subsidiaries and associates’ acquisitions as well as for other general corporate purposes. The Notes Facility Agreement provided for the issuance of 5-year and 7-year corporate notes in private placements to not more than 19 institutional investors pursuant to Section 9.2 of the Securities Regulation Code (SRC) and Rule 9.2(2) (B) of the SRC Rules. Total interest expense charged to the parent company statements of income amounted to P=352.7 million in 2010, P=263.2 million in 2009 and P=12.5 million in 2008, respectively.

NOTES ISSUED Interest

Rate Payment Schedule 2010 2009 Tranche 1 or 5-year

corporate note 8.78% Quarterly interest payments

beginning 3 months after issue date; principal maturity is 60

months after issue date

P=3,330,000,000 P=3,330,000,000

Tranche 2 or 7-year corporate note

9.33% Quarterly interest payments beginning 3 months after issue

date; annual principal installments of P=5.6 million starting December 31, 2009

then full payment of the remaining balance on

December 18, 2015

548,800,000 554,400,000

3,878,800,000 3,884,400,000

Less deferred financing costs 32,549,827 41,012,287 3,846,250,173 3,843,387,713

Less current portion 5,600,000 5,600,000 P=3,840,650,173 P=3,837,787,713

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*SGVMC409382*

Prior to the maturity date, the Company may redeem in whole the relevant outstanding notes on the 12th interest payment date for Tranche 1 note and on the 16th interest payment date for Tranche 2 note. The amount payable in respect of such early redemption shall be the accrued interest on the outstanding principal amount, the outstanding principal amount and a prepayment penalty of 2% of the outstanding principal amount.

Under the Notes Facility Agreement, the Company shall not permit its Debt-to-Equity (DE) ratio to exceed 2:1 calculated based on the Company’s year-end audited financial statements. For the purpose of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of corporate guarantees in favor of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009. Retail Bonds - P=3.0 billion On November 20, 2008, the Company’s BOD authorized the issuance of 5-year and 7-year peso-denominated bonds worth P=3.0 billion, with an option to upsize depending on market demand. This was approved by the SEC in March 2009. The bonds were offered to the general public commencing April 15, 2009. On April 30, 2009, the Company registered and issued the bonds worth P=3.0 billion. The proceeds were used to partially finance APRI’s acquisition of Tiwi-Makban Geothermal Power Plants. As provided in the Underwriting Agreement, the three-year bonds bear interest on principal amount from and including issue date at 8.0% per annum. The five-year bonds bear interest on principal amount from and including issue date at 8.7% per annum. Total interest expense charged to the parent company statements of income amounted to P=263.8 million and P=260.6 million in 2010 and 2009, respectively. The Bonds have been rated PRS AAA by Philippine Rating Services Corporation. The rating is subject to regular annual reviews, or more frequently as market developments may dictate, for as long as the bonds are outstanding.

Bonds Issued Interest

Rate Payment Schedule 2010 2009 3-year bond 8.00% Quarterly interest payments

beginning 3 months after issue date; will be redeemed at par (or 100%) on maturity

date or April 30, 2012

P=705,580,000 P=705,580,000

5-year bond 8.70% Quarterly interest payments beginning 3 months after

issue date; will be redeemed at par (or 100%) on maturity

date or May 1, 2014

2,294,420,000 2,294,420,000

3,000,000,000 3,000,000,000

Less deferred financing costs 24,386,774 32,175,194 P=2,975,613,226 P=2,967,824,806 Prior to the maturity date, the Company may redeem in whole and not a part of any of the relevant outstanding 5-year bonds on the 12th interest payment date. The amount payable to the bondholders in respect of such early redemption shall be calculated based on the principal amount of the bonds being redeemed, as the sum of (i) one hundred two percent (102%) of the principal

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*SGVMC409382*

amount of the 5-year bonds being earlier redeemed; and (ii) any accrued interest on the principal amount of the 5-year bonds being earlier redeemed. Under the Bond Trust Agreement, the Company shall not permit its DE ratio to exceed 2:1 calculated based on the Company’s year-end audited financial statements. For the purposes of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of corporate guarantees in favor of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009. Fixed Rate Notes - P=5.0 billion On September 28, 2009 (issue date), the Company availed a total of P=5.0 billion from the Notes Facility Agreement it signed on September 18, 2009, with FMIC as Issue Manager, the proceeds of which were used by the Company to finance its investments in various projects, including capital expenditures and acquisitions. The Notes Facility Agreement provided for the issuance of 5-year corporate notes in a private placement to not more than 19 institutional investors pursuant to Section 9.2 of the SRC and Rule 9.2(2) (B) of the SRC Rules. Total interest expense charged to the parent company statements of income amounted to P=399.2 million in 2010 and P=101.1 million in 2009.

Note Issued Interest

Rate Payment Schedule 2010 2009 5-year note 8.2254% Quarterly interest payments

beginning 3 months after issue date; maturity date 5

years after issue date or September 28, 2014

P=5,000,000,000 P=5,000,000,000

Less deferred financing costs 39,174,059 47,691,110 P=4,960,825,941 P=4,952,308,890

Prior to the maturity date, the Company may redeem in whole and not a part only, of the relevant outstanding notes on the 12th interest payment date. The amount payable in respect of such early redemption shall be the accrued interest on the outstanding principal amount, the outstanding principal amount and a prepayment penalty of 2% of the outstanding principal amount. Under the Bond Trust Agreement, the Company shall not permit its DE ratio to exceed 2:1 calculated based on the Company’s year-end audited financial statements. For the purposes of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of corporate guarantees in favor of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009.

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*SGVMC409382*

13. Equity a. Capital Stock

2010 2009

Authorized - P=1 par value Preferred shares - 1,000,000,000 shares

Common shares - 16,000,000,000 shares Issued Common shares - 7,358,604,307 shares P=7,358,604,307 P=7,358,604,307

There are no preferred shares issued and outstanding as of December 31, 2010 and 2009. Preferred shares are non-voting, non-participating, non-convertible, redeemable, cumulative, and may be issued from time to time by the BOD in one or more series. The BOD is authorized to issue from time to time before issuance thereof, the number of shares in each series, and all the designations, relative rights, preferences, privileges and limitations of the shares of each series. Preferred shares redeemed by the Company may be reissued. Holders thereof are entitled to receive dividends payable out of the unrestricted retained earnings of the Company at a rate based on the offer price that is either fixed or floating from the date of the issuance to final redemption. In either case, the rate of dividend, whether fixed or floating, shall be referenced, or be a discount or premium, to market-determined benchmark as the BOD may determine at the time of issuance with due notice to the SEC. In the event of any liquidation or dissolution or winding up of the Company, the holders of the preferred stock shall be entitled to be paid in full the offer price of their shares before any payment in liquidation is made upon the common stock.

b. Retained Earnings

On February 6, 2008, the BOD approved the declaration of cash dividends of P=0.18 a share (P=1.32 billion) to all stockholders of record as of February 21, 2008. The cash dividends were subsequently paid on March 3, 2008. On February 11, 2009, the BOD approved the declaration of cash dividends of P=0.20 a share (P=1.47 billion) to all stockholders of record as of February 26, 2009. The cash dividends were subsequently paid on March 23, 2009. On March 10, 2010, the BOD approved the declaration of cash dividends of P=0.30 a share (P=2.21 billion) to all stockholders of record as of March 24, 2010. The cash dividends were subsequently paid on April 16, 2010. On March 3, 2011, the BOD approved the declaration of cash dividends of P=1.32 a share (P=9.71 billion) to all stockholders of record as of March 17, 2011. The cash dividends are payable on April 5, 2011.

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14. Personnel Costs

2010 2009 2008

Salaries and wages P=74,815,636 P=36,641,816 P=23,363,932 Director’s fees and security services 13,111,000 20,667,835 13,457,455 Employee benefits 17,845,423 9,728,897 5,693,310 Retirement costs (see Note 15) 17,211,073 5,362,670 2,300,326

P=122,983,132 P=72,401,218 P=44,815,023

15. Retirement Costs

The Company has a defined benefit pension plan covering substantially all of its regular employees. The benefits are based on the years of service and percentage of latest monthly salary. Total retirement costs charged to operations amounted to P=17.2 million in 2010, P=5.4 million in 2009 and P=2.3 million in 2008. The following tables summarize the components of net benefit expense recognized in the parent company statements of income and the funded status and amounts recognized in the parent company balance sheets for the plan:

Net benefit expense

2010 2009 2008

Current service cost P=7,432,700 P=822,557 P=2,491,698 Interest cost on benefit obligation 12,086,250 11,500,515 3,927,625 Expected return on plan assets (6,469,600) (6,147,369) (4,118,997) Net actuarial loss (gain) recognized in the year 4,161,723 (813,033) – P=17,211,073 P=5,362,670 P=2,300,326 Actual return on plan assets P=3,521,198 P=3,398,791 P=1,599,044

Pension liability (asset)

2010 2009

Defined benefit obligation P=183,476,000 P=134,740,702 Unrecognized net actuarial loss (91,425,000) (67,576,373) Fair value of plan assets (149,849,527) (64,696,229) (P=57,798,527) P=2,468,100

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Changes in the present value of the defined benefit obligation are as follows:

2010 2009

Opening defined benefit obligation P=134,740,702 P=35,627,371 Actuarial losses on obligation 25,061,948 85,050,900 Interest cost 12,086,250 11,500,515 Current service cost 7,432,700 822,557 Transfer from subsidiaries 4,154,400 2,003,100 Benefits paid – (263,741) Closing defined benefit obligation P=183,476,000 P=134,740,702

Changes in the fair value of plan assets are as follows:

2010 2009

Opening fair value of plan assets P=64,696,229 P=55,885,177 Contributions by employer 77,477,700 3,672,902 Expected return on plan assets 6,469,600 6,147,369 Transfer from subsidiaries 4,154,400 2,003,100 Actuarial losses on plan assets (2,948,402) (2,748,578) Benefits paid – (263,741) Closing fair value of plan assets P=149,849,527 P=64,696,229

The Company expects to make the same contribution in 2011 as in 2010. The principal assumptions used as of January 1 to determine retirement benefits as of December 31, 2010, 2009, and 2008 are as follows:

2010 2009 2008

Discount rate 8.97% 32.28% 8.11% Expected rate of return on assets 10.00% 11.00% 8.00% Future salary increase 8.00% 9.00% 10.00%

As of December 31, 2010, discount rate used is 8.24% with a salary increase rate of 6% and expected rate of return on plan assets of 7%, based on the latest actuarial valuation of the Company’s retirement benefits. Amounts for the current and previous four periods follow:

2010 2009 2008 2007 2006 Defined benefit obligation P=183,476,000 P=134,740,702 P=35,627,371 P=48,429,411 P=404,836 Fair value of plan assets 149,849,527 64,696,229 55,885,177 51,487,461 – Surplus (deficit) (33,626,473) (70,044,473) 20,257,806 3,058,050 (404,836) Experience adjustments on

pension liabilities 25,061,948 85,050,900 (19,678,981) (3,507,975) 16,933 Experience adjustments on

pension asset (2,948,402) (2,748,578) (2,519,953) 1,535,702 –

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Major categories of plan assets are the following:

2010 2009

Commercial papers P=142,254,464 P=56,172,385 Others 7,595,063 8,523,844 P=149,849,527 P=64,696,229

16. Income Tax

Details of provision for (benefit from) income tax are as follows:

2010 2009 2008

Current Corporate income tax P=23,775,054 P=14,535,971 P=17,645,312 Final 17,636,611 53,767,097 64,065,063

41,411,665 68,303,068 81,710,375 Deferred 82,962,486 (232,027,190) 24,071,594 P=124,374,151 (P=163,724,122) P=105,781,969

The provision for corporate income tax represents MCIT in 2010 and 2009 and regular income tax in 2008. The reconciliation of income tax computed at the statutory tax rate to the provision for income tax reported in the parent company statements of income is as follows:

2010 2009 2008

At statutory rate of 30% for 2010 and 2009 and 35% for 2008 P=306,186,425 P=436,984,553 P=1,822,098,579

Additions to (reductions in) income tax resulting from:

Unrecognized deferred income tax asset on: NOLCO 114,822,403 – – MCIT 23,775,054 – – Final tax on interest income 17,636,611 53,767,097 64,065,063 Nondeductible interest expense 8,825,291 29,144,651 55,262,247 Expired MCIT 2,643,079 – – Interest income already subjected to

final tax at a lower rate (26,743,307) (88,317,125) (131,576,780) Dividend income (322,771,405) (594,879,704) (1,696,272,748) Effect of change in tax rate – – (7,331,167) Others – (423,594) (463,225)

P=124,374,151 (P=163,724,122) P=105,781,969

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The components of the Company’s net deferred income tax assets are as follows:

2010 2009

Deferred income tax assets: NOLCO P=93,873,663 P=97,849,087 Unamortized past service cost 21,699,980 – MCIT 14,535,971 17,179,050 Unrealized foreign exchange loss – 80,257,961 Pension liability – 2,779,146 130,109,614 198,065,244 Deferred income tax liabilities:

Accrual of pension cost (17,339,558) – Unrealized foreign exchange gain (1,332,171) – Unamortized past service cost – (3,664,873) (18,671,729) (3,664,873) P=111,437,885 P=194,400,371

As of December 31, 2010, the Company has MCIT that can be claimed as deduction from regular income tax liability as follows:

Period of Recognition Availment Period Amount Applied Expired Balance 2007 2008-2010 P=2,643,079 P=– P=2,643,079 P=– 2009 2010-2012 14,535,971 – – 14,535,971 2010 2011-2013 23,775,054 – – 23,775,054 P=40,954,104 P=– P=2,643,079 P=38,311,025

As of December 31, 2010, the Company has NOLCO which can be claimed as deduction against the regular taxable income as follows: Period of Recognition Availment Period Amount Applied Expired Balance 2009 2010-2012 P=326,163,623 P=– P=– P=326,163,623 2010 2011-2013 369,489,930 – – 369,489,930 P=695,653,553 P=– P=– P=695,653,553

As of December 31, 2010, the Company did not recognize its deferred income tax assets from MCIT amounting to P=23,775,054 incurred in 2010 and NOLCO amounting to P=369,489,930 and P=13,251,413 incurred in 2010 and 2009, respectively. The management expects that it will not generate sufficient taxable income in the future that will be available to allow part of the deferred income tax assets to be utilized. Republic Act (RA) No. 9337 was enacted into law amending various provisions in the existing 1997 National Internal Revenue Code. Among the reforms introduced by the said RA, which became effective on November 1, 2005, are as follows:

• Increase in the corporate income tax rate from 32% to 35% with a reduction thereof to 30% beginning January 1, 2009;

• Grant of authority to the Philippine President to increase the 10% VAT rate to 12%, effective February 1, 2006, subject to compliance with certain economic conditions;

• Revised invoicing and reporting requirements for VAT; • Expanded scope of transactions subject to VAT; and, • Provision of thresholds and limitations on the amounts of VAT credits that can be claimed.

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17. Financial Risk Management Objectives and Policies

Risk Management Structure BOD The BOD is mainly responsible for the overall risk management approach and for the approval of risk strategies and principles of the Company. It also has the overall responsibility for the development of risk strategies, principles, frameworks, policies and limits. It establishes a forum of discussion of the Company’s approach to risk issues in order to make relevant decisions.

Financial Risk Management The Company’s principal financial instruments comprise of cash and cash equivalents, receivables from related parties, other receivables, derivative asset and liability, accounts payable and accrued expenses, amounts owed to related parties, bank loan and long-term debt. The main purpose of these financial instruments is to raise financing for the Company’s operations. The Company has various other financial assets and liabilities which arise directly from its operations. The main risks arising from the Company’s financial instruments are credit risk involving possible exposure to counter party default on its cash and cash equivalents, receivables and derivative asset; liquidity risk in terms of the proper matching of the type of financing required for specific investments; and foreign exchange risk in terms of foreign exchange fluctuations that may significantly affect its foreign currency denominated placements. Credit risk Credit risk refers to the risk that counterparty will default on its contractual obligations resulting in financial loss to the Company. The Company’s credit risk on cash in banks, short-term investments, receivables from related parties, other receivables and derivative asset pertains to possible default by the counterparty, with a maximum exposure equal to the carrying amount of these assets. With respect to cash in banks and short-term investments, the risk is mitigated by the short-term and/or liquid nature of its short-term investments mainly in bank deposits and placements, which are placed with financial institutions of high credit standing. With respect to receivables from related parties, other receivables and derivative asset, credit risk is controlled by the application of credit approval, limit and monitoring procedures. It is the Company’s policy that all debtors who wish to trade on credit terms are subject to credit procedures. In addition, receivable balances are monitored on an ongoing basis with the result that the Company’s exposure to bad debts is not significant. The Company has no significant concentration risk to a counterparty or group of counterparties. The credit quality per class of financial assets as of December 31 is as follows (amounts in thousands): 2010

Neither past due nor impaired Past due

Total but not

High Medium Low impaired Cash and cash equivalents P=11,081,930 P=– P=– P=– P=11,081,930 Receivables: Related parties 10,542,198 – – 16,298 10,558,496 Others 132,339 – – – 132,339 Derivative asset 7,670 – – – 7,670 Total P=21,764,137 P=– P=– P=16,298 P=21,780,435

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2009

Neither past due nor impaired Past due

Total but not

High Medium Low impaired Cash and cash equivalents P=74,768 P=– P=– P=– P=74,768 Receivables: Related parties 2,773,180 – – 20,670,675 23,443,855 Others 12,044 – – 3 12,047 Total P=2,859,992 P=– P=– P=20,670,678 P=23,530,670

High credit quality class pertains to receivables from customers with good favorable credit standing. Receivables from customers that slide beyond the credit terms but pay a week after being past due are classified under Medium. Low credit quality class pertains to accounts with payment habits that extend beyond the approved credit terms because their funds are not sufficient to conduct their operations. The aging analyses of financial assets as of December 31 are as follows (amounts in thousands): 2010

Total

Neither past due nor

impaired

Past due but not impaired

30 days 30 - 60 More than

days 60 days Cash and cash equivalents P=11,081,930 P=11,081,930 P=– P=– P=– Receivables:

Related parties 10,558,496 10,542,198 – 13,304 2,994 Others 132,339 132,339 – – –

Derivative asset 7,670 7,670 – – – Total P=21,780,435 P=21,764,137 P=– P=13,304 P=2,994 2009

Total


impaired


30 days 30 - 60 More than

days 60 days Cash and cash equivalents P=74,768 P=74,768 P=– P=– P=– Receivables:

Related parties 23,443,855 2,773,180 298,428 58,363 20,313,884 Others 12,047 12,044 – 2 1

Total P=23,530,670 P=2,859,992 P=298,428 P=58,365 P=20,313,885

The credit quality of the Company’s financial assets that are neither past due nor impaired is considered to be of good quality and expected to be collectible without incurring any credit losses. Liquidity risk Liquidity risk is the potential of not meeting obligations as they come due because of an inability to liquidate assets or obtain adequate funding.

The Company maintains sufficient cash and cash equivalents to finance its operations. Any excess cash is invested in short-term money market placements. These placements are maintained to meet maturing obligations and pay dividend declarations. The Company, in general, matches the appropriate long-term funding instruments with the general nature of its equity instruments.

In managing its short-term fund requirements, the Company’s policy is to ensure that there are sufficient working capital inflows to match repayments of short-term borrowings. With regard to its long-term financing requirements, the Company’s policy is that not more than 25% of long-term borrowings should mature in any 12-month period.

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The following tables summarize the maturity profile of the Company’s financial liabilities based on contractual undiscounted payments as of December 31(amounts in thousands): 2010

Total Contractual undiscounted payments Carrying On Less than

Value Total Demand 1 year 1 to 5 years Bank loans P=1,290,000 P=1,293,386 P=– P=1,293,386 P=– Long-term debt 11,782,689 15,324,086 – 1,030,674 14,293,412 Amounts owed to related parties 3,243,662 3,243,662 3,243,662 – – Accounts payable and accrued

expenses 110,405 110,405 – 110,405 – Total P=16,426,756 P=19,971,539 P=3,243,662 P=2,434,465 P=14,293,412

2009

Total Carrying

Value Total

Contractual undiscounted payments On

Demand Less than 1

year 1 to 5 years More than 5

years

Bank loans P=4,801,700 P=4,812,413 P=– P=4,812,413 P=– P=– Long-term debt 11,763,521 16,389,669 – 1,005,644 14,807,810 576,215 Amounts owed to related parties 1,165,897 1,165,897 1,165,897 – – – Accounts payable and accrued

expenses 87,098 87,098 – 87,098 – – Derivative liability 3,130 3,130 – 3,130 – – Total P=17,821,346 P=22,458,207 P=1,165,897 P=5,908,285 P=14,807,810 P=576,215

Foreign exchange risk The foreign exchange risk of the Company pertains to its foreign currency-denominated cash and cash equivalents, receivables from related parties and bank loans. The foreign currency-denominated monetary assets and liability and their Philippine Peso equivalents follow:

2010 2009

US Dollar Peso Equivalent US Dollar Peso Equivalent

Financial assets Cash and cash equivalents 6,583,731 288,630,777 6,040,979 279,093,240

Receivables from related parties 224,705 9,851,063 4,013,397 185,418,944

6,808,436 298,481,840 10,054,376 464,512,184

Financial liability Bank loans – – (81,000,000) (3,742,200,000)

6,808,436 298,481,840 (70,945,624) (3,277,687,816)

As of December 31, 2010 and 2009, the exchange rates were P=43.84 per US$1 and P=46.20 per US$1, respectively. As a result of the translation of these foreign currency denominated assets and liabilities, the Company reported net unrealized foreign exchange gain of P=272.0 million in 2010 and net unrealized foreign exchange loss of P=399.0 million in 2009.

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The following tables demonstrate the sensitivity to a reasonably possible change in the US dollar exchange rates, with all other variables held constant, of the Company’s income before income tax as of December 31, 2010 and 2009 (amounts in thousands).

Increase (decrease) in

US dollar

Effect on income before tax

2010 US dollar-denominated accounts 5% P=14,924 US dollar-denominated accounts (5%) (14,924)

2009 US dollar-denominated accounts 5% (P=163,884) US dollar-denominated accounts (5%) 163,884)

There is no other impact on the Company’s equity other than those already affecting the parent company statements of income. Capital management The primary objective of the Company’s capital management is to ensure that it maintains a strong credit rating and healthy capital ratios in order to support its business and maximize shareholder value. The Company considers equity as its capital. The Company manages its capital structure and makes adjustments to it, in light of changes in economic conditions. To maintain or adjust the capital structure, the Company may adjust the dividend payment to shareholders, return capital to shareholders or issue new shares. No changes were made in the objectives, policies or processes during the periods ending December 31, 2010 and 2009. The Company monitors capital using a gearing ratio, which is net debt divided by equity plus net debt. Its policy is to keep the gearing ratio at 70% or below. The Company determines net debt as the sum of interest-bearing short-term and long-term loans less cash and short-term deposits and interest bearing advances to related parties. Gearing ratios of the Company are as follows:

2010 2009

Long term debt P=11,777,089,340 P=11,757,921,409 Current portion of long term debt 5,600,000 5,600,000 Bank loans 1,290,000,000 4,801,700,000 Cash and cash equivalents (11,081,929,955) (74,803,016) Net debt (a) 1,990,759,385 16,490,418,393 Equity 24,060,045,449 25,371,379,474 Equity and net debt (b) P=26,050,804,834 P=41,861,797,867 Gearing ratio (a/b) 7.64% 39.39%

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18. Financial Instruments Classification of Financial Instruments

Cash Financial asset

at FVPL Loans and

receivables Other financial

liabilities 2010

Total Assets Cash and cash equivalents P=155,000 P=– P=11,081,774,955 P=– P=11,081,929,955 Receivables

Related parties – – 10,558,496,070 – 10,558,496,070 Others – – 132,339,408 – 132,339,408

Derivative asset – 7,669,730 – – 7,669,730 P=155,000 P=7,669,730 P=21,772,610,433 P=– P=21,780,435,163 Liabilities Bank loans P=– P=– P=– P=1,290,000,000 P=1,290,000,000 Long-term debt – – – 11,782,689,340 11,782,689,340 Amounts owed to related parties – – – 3,243,661,786 3,243,661,786 Accounts payable and accrued

expenses – – – 110,405,245 110,405,245 P=– P=– P=– P=16,426,756,371 P=16,426,756,371

Cash Loans and

receivables

Financial liability

at FVPL Other financial

liabilities 2009 Total

Assets Cash and cash equivalents P=35,000 P=74,768,016 P=– P=– P=74,803,016 Receivables

Related parties – 23,443,855,144 – – 23,443,855,144 Others – 12,047,216 – – 12,047,216

P=– P=23,530,705,376 P=– P=– P=23,530,705,376 Liabilities Bank loans P=– P=– P=– P=4,801,700,000 P=4,801,700,000 Long-term debt – – – 11,763,521,409 11,763,521,409 Amounts owed to related parties – – – 1,165,897,085 1,165,897,085 Accounts payable and accrued

expenses – – – 87,098,039 87,098,039 Derivative liability – – 3,130,290 – 3,130,290 P=– P=– P=3,130,290 P=17,818,216,533 P=17,821,346,823

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Fair Value of Financial Instruments Set out below is a comparison by category of carrying amounts and fair value of all of the Company’s financial instruments that are carried in the financial statements as of December 31, 2010 and 2009 (amounts in thousands).

2010 2009

Carrying Fair Carrying Fair

Amount Value Amount Value

Financial Assets Cash and cash equivalents P=11,081,930 P=11,081,930 P=74,803 P=74,803

Receivables: Related parties 10,558,496 10,558,496 23,443,855 23,443,855

Others 132,339 132,339 12,047 12,047 Derivative asset 7,670 7,670 – –

Financial Liabilities Bank loans P=1,290,000 P=1,290,000 P=4,801,700 P=4,801,700

Accounts payable and accrued expenses 110,405 110,405 87,098 87,098 Amounts owed to related parties 3,243,662 3,243,662 1,165,897 1,165,897 Long-term debt 11,782,689 12,839,105 11,763,521 12,165,281 Derivative liability – – 3,130 3,130

Fair value is defined as the amount at which the financial instruments could be exchanged in a current transaction between knowledgeable willing parties in an arm’s length transaction, other than in a forced liquidation or sale. Fair values are obtained from quoted market prices, discounted cash flows models and option pricing models, as appropriate. Cash and cash equivalents, receivables, bank loans, accounts payable and accrued expenses, and amounts owed to related parties The carrying amounts of cash and cash equivalents, receivables, bank loan, accounts payable and accrued expenses and amounts owed to related parties approximate fair value due to the relatively short-term maturity of these financial instruments. Derivative asset and liability The fair value is calculated by reference to prevailing interest rate differential and spot exchange rate as of valuation date, taking into account its remaining term to maturity. Long-term debt The fair value of long-term debt is based on the discounted value of future cash flows using the applicable rates for similar types of loans. Discounts rates used range from 8.00% to 9.33% in 2010 and 6.77% to 8.36% in 2009. Derivative Financial Instruments The Company enters into short-term forward contracts with counterparty banks to manage foreign currency risks associated with foreign currency-denominated liabilities and purchases. As of December 31, 2010, the Company has outstanding buy Dollar and sell Peso forward exchange contracts with counterparty banks with an aggregate notional amount of $56.4 million and remaining maturities of less than 1 month to 8 months. As at December 31, 2010, the forward rates related to the forward contracts range from P=43.84 to P=44.13 per US$1. The Company recognized derivative asset relating to these contracts amounting to P=5.4 million.

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As of December 31, 2010, the Company also has outstanding non-deliverable sell US Dollar buy EURO short-term forward exchange contracts with a counterparty bank with an aggregate notional amount of €0.84 million and remaining maturities of 2 month to 8 months. As at December 31, 2010, the forward rates related to the forward contracts amounted to €1.3413 to €1.3421per US$1. The Company recognized derivative asset relating to these contracts amounting to P=2.3 million. As of December 31, 2009, the Company has outstanding non-deliverable buy Dollar and sell Peso forward exchange contracts with counterparty bank with an aggregate notional amount of $25.0 million and remaining maturities of less than 1 month to 10 months. As at December 31, 2009, the forward rates related to the forward contracts range from P=46.40 to P=47.14 per US$1. The Company recognized derivative liability relating to these contracts amounting to P=3.1 million. The movements in fair value changes of all derivative instruments for the year ended December 31, 2010 and 2009 are as follows:

2010 2009 At beginning of year (P=3,130,290) P=– Net changes in fair value of derivatives not

designated as accounting hedges (45,153,092) (3,130,290) Fair value of settled instruments 55,953,112 – At end of year P=7,669,730 (P=3,130,290)

The loss from the net fair value changes relating to the forward contracts amounting to P=45.2 million in 2010 and P=3.1 million in 2009 are included under “Foreign exchange gains (losses) - net” in the parent company statements of income.

Fair Value Hierarchy The Company uses the following hierarchy for determining and disclosing the fair value of financial instruments by valuation technique: Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities Level 2: other techniques for which all inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly Level 3: techniques which use inputs which have a significant effect on the recorded fair value that are not based on observable market data. Only the Company’s derivative instruments, which are classified under Level 2, are measured at fair value. During the reporting period ending December 31, 2010 and 2009, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfers into and out of Level 3 fair value measurements were made.

19. Electric Power Industry Reform Act (EPIRA) of 2001

RA No. 9136 was signed into law on June 8, 2001 and took effect on June 26, 2001. The law provides for the privatization of National Power Corporation (NPC) and the restructuring of the electric power industry. The Implementing Rules and Regulations (IRR) were approved by the Joint Congressional Power Commission on February 27, 2002.

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R.A. No. 9136 and the IRR impact the industry as a whole. The law also empowers the ERC to enforce rules to encourage competition and penalize anti-competitive behavior. R.A. Act No. 9136, the EPIRA, and the covering IRR provides for significant changes in the power sector, which include among others: i. The unbundling of the generation, transmission, distribution and supply and other disposable

assets of a company, including its contracts with independent power producers and electricity rates;

ii. Creation of a Wholesale Electricity Spot Market; and iii. Open and non-discriminatory access to transmission and distribution systems. The law also requires public listing of not less than 15% of common shares of generation and distribution companies within 5 years from the effectivity date of the EPIRA. It provides cross ownership restrictions between transmission and generation companies and a cap of 50% of its demand that a distribution utility is allowed to source from an associated company engaged in generation except for contracts entered into prior to the effectivity of the EPIRA. There are also certain sections of the EPIRA, specifically relating to generation companies, which provide for a cap on the concentration of ownership to only 30% of the installed capacity of the grid and/or 25% of the national installed generating capacity.

20. Renewable Energy Act of 2008 On January 30, 2009, RA No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energy Resources and for Other Purposes, which shall be known as the “Renewable Energy Act of 2008” (the Act), became effective. The Act aims to (a) accelerate the exploration and development of renewable energy resources such as, but not limited to, biomass, solar, wind, hydro, geothermal and ocean energy sources, including hybrid systems, to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels and thereby minimize the country’s exposure to price fluctuations in the international markets, the effects of which spiral down to almost all sectors of the economy; (b) increase the utilization of renewable energy by institutionalizing the development of national and local capabilities in the use of renewable energy systems, and promoting its efficient and cost-effective commercial application by providing fiscal and non-fiscal incentives; (c) encourage the development and utilization of renewable energy resources as tools to effectively prevent or reduce harmful emissions and thereby balance the goals of economic growth and development with the protection of health and environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws. As provided for in the Act, renewable energy (RE) developers of RE facilities, including hybrid systems, in proportion to and to the extent of the RE component, for both power and non-power applications, as duly certified by the Department of Energy (DOE), in consultation with the Board of Investments (BOI), shall be entitled to incentives, such as, income tax holiday, duty-free importation of RE machinery, equipment and materials, zero percent VAT rate on sale of power from RE sources, and tax exemption of carbon credits, among others. The Company expects that the Act may have significant effect on the operating results of some of its subsidiaries and associates that are RE developers. Impact on the operating results is expected to arise from the effective reduction in taxes.

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21. Supplementary Information Required Under Revenue Regulations (RR) 15-2010

The Company also reported and/or paid the following types of taxes for the year:

Value-added tax (VAT)

The Company’s sales are subject to output value added tax (VAT) while its importations and purchases from other VAT-registered individuals or corporations are subject to input VAT. The VAT rate is 12.0%.

a. Net Receipts and Output VAT declared in the Company’s VAT returns in 2010

Net Sales/

Receipts Output

VAT Taxable Sales: Sales of services P=329,894,347 P=39,587,322 Zero-rated sales 120,000 – P=330,014,347 P=39,587,322

The Company’s sales that are subject to VAT are reported under the following accounts:

Service Income - Management fee Miscellaneous Income - Operating Miscellaneous Income - Non-operating

Zero-rated sales consist of Operational and Management charges to SEZ, a Freeport zone-registered subsidiary, whose VAT treatments are provided under Revenue Memorandum Circular No. 50-2007. Zero-rated sales to SEZ amounted to P=10,000 per month.

The Company’s sales of services are based on actual collections received, hence, may not be the same as amounts accrued in the parent company statement of income.

b. Input VAT for 2010 Balance at January 1 P=12,125,927 Current year’s domestic purchases/payments for: Goods other than for resale or manufacture 1,185,623 Capital goods subject to amortization 1,291,107 Services lodged under the other accounts 11,560,920 26,163,577 Claims for tax credit/refund and other adjustments (20,899,961) Balance at December 31 P=5,263,616

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Other taxes and licenses

Taxes and licenses, local and national, include real estate taxes, licenses and permit fees for 2010:

License and permit fees P=1,929,642Fringe benefit taxes 1,041,097Documentary stamp taxes Loan instruments 759,863 Others 375Real estate taxes 112,446Others 7,979,643 P=11,823,066

Withholding taxes

Final withholding taxes P=68,546,456 Withholding taxes on compensation and benefits 22,558,709 Expanded withholding taxes 15,837,352 P=106,942,517

*SGVMC409381*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Amounts in Thousands, Except Earnings Per Share Amounts) Years Ended December 31 2010 2009 2008

OPERATING REVENUES Sale of power (Notes 20 and 30)

Generation P=46,313,904 P=12,359,479 P=2,880,719 Distribution 13,064,593 10,734,427 9,227,696

Services 62,524 61,598 61,065 Technical, management and other fees (Note 31) 110,437 18,761 73,500 59,551,458 23,174,265 12,242,980

OPERATING EXPENSES Cost of generated power (Note 22) 15,882,326 5,030,277 1,695,894 Cost of purchased power (Note 21) 10,001,570 8,032,562 6,625,385 Depreciation and amortization (Notes 11 and 12) 3,003,977 1,412,900 511,154 Operations and maintenance (Note 24) 2,437,928 1,336,987 653,104 General and administrative (Note 23) 1,986,826 1,902,428 1,102,574 Cost of services 7,251 2,944 2,364 33,319,878 17,718,098 10,590,475

FINANCIAL INCOME (EXPENSES) Interest income (Notes 4, 13 and 31) 224,158 409,972 607,540 Interest expense and other financing costs (Note 32) (6,678,293) (2,813,978) (378,536) (6,454,135) (2,404,006) 229,004

OTHER INCOME (CHARGES) Share in net earnings of associates (Note 9) 4,625,883 2,535,386 2,784,511 Other income - net (Note 27) 1,600,399 813,411 376,692 6,226,282 3,348,797 3,161,203

INCOME BEFORE INCOME TAX 26,003,727 6,400,958 5,042,712

PROVISION FOR INCOME TAX - Net (Note 28) 920,697 631,190 618,384

NET INCOME P=25,083,030 P=5,769,768 P=4,424,328

Attributable to: Equity holders of the parent P=25,041,116 P=5,658,581 P=4,333,613 Non-controlling interests 41,914 111,187 90,715 P=25,083,030 P=5,769,768 P=4,424,328

EARNINGS PER COMMON SHARE (Note 29) Basic and diluted, for income for the year attributable to

ordinary equity holders of the parent P=3.40 P=0.77 P=0.59 See accompanying Notes to Consolidated Financial Statements.

*SGVMC409381*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Amounts in Thousands) Years Ended December 31 2010 2009 2008

NET INCOME ATTRIBUTABLE TO: Equity holders of the parent P=25,041,116 P=5,658,581 P=4,333,613 Non-controlling interests 41,914 111,187 90,715

25,083,030 5,769,768 4,424,328 OTHER COMPREHENSIVE INCOME (LOSS) Share in net unrealized valuation gains on AFS investments of

an associate (Note 9) 78,118 – – Share in movement in cumulative translation adjustment of

associates (Note 9) (57,324) 133,668 557,554 Income tax effect on other comprehensive income – – –

Total other comprehensive income for the year, net of tax 20,794 133,668 557,554 TOTAL COMPREHENSIVE INCOME P=25,103,824 P=5,903,436 P=4,981,882 Attributable to: Equity holders of the parent P=25,061,910 P=5,792,249 P=4,891,167 Non-controlling interests 41,914 111,187 90,715 P=25,103,824 P=5,903,436 P=4,981,882 See accompanying Notes to Consolidated Financial Statements.

*SGVMC409381*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008 (Amounts in Thousands, Except Dividends Per Share Amounts) Attributable to Equity Holders of the Parent

Capital Stock

(Note 19a)Additional

Paid-in Capital

Share in Net Unrealized

Valuation Gainson AFS

Investments of an Associate

(Note 9)

Share in Cumulative Translation

Adjustments of Associates

(Note 9)

Acquisition of Non-controlling

Interests

Retained Earnings (Note 19b)

Non-controlling Interests Total

Balances at January 1, 2010 P=7,358,604 P=12,588,894 P=– P=115,246 (P=259,147) P=14,672,262 P=571,068 P=35,046,927 Net income for the year – – – – – 25,041,116 41,914 25,083,030 Other comprehensive income (loss) – – 78,118 (57,324) – – – 20,794 Total comprehensive income (loss) for the year – – 78,118 (57,324) 25,041,116 41,914 25,103,824 Cash dividends - P=0.30 a share (Note 19b) – – – – – (2,207,581) – (2,207,581) Cash dividends paid to non-controlling interests – – – – – – (94,240) (94,240) Change in non-controlling interests – – – – – – (114,720) (114,720) Balances at December 31, 2010 P=7,358,604 P=12,588,894 P=78,118 P=57,922 (P=259,147) P=37,505,797 P=404,022 P=57,734,210

Balances at January 1, 2009 P=7,358,604 P=12,588,894 P=– (P=18,422) (P=259,147) P=10,485,401 P=536,333 P=30,691,663 Net income for the year – – – – – 5,658,581 111,187 5,769,768 Other comprehensive income – – – 133,668 – – – 133,668 Total comprehensive income for the year – – – 133,668 – 5,658,581 111,187 5,903,436 Cash dividends - P=0.20 a share (Note 19b) – – – – – (1,471,720) – (1,471,720) Cash dividends paid to non-controlling interests – – – – – – (76,401) (76,401) Change in non-controlling interests – – – – – – (51) (51) Balances at December 31, 2009 P=7,358,604 P=12,588,894 P=– P=115,246 (P=259,147) P=14,672,262 P=571,068 P=35,046,927

(Forward)

*SGVMC408219*

- 2 - Attributable to Equity Holders of the Parent

Capital Stock

(Note 19a)Additional

Paid-in Capital

Share in Net |Unrealized

Valuation Gains on AFS

Investments of an Associate

Share in Cumulative Translation

Adjustments of Associates

(Note 9)

Acquisition of Non-controlling

Interests

Retained Earnings (Note 19b)

Non-controlling Interests Total

Balances at January 1, 2008 P=7,358,604 P=12,588,894 P=– (P=575,976) (P=107,163) P=7,476,337 P=619,427 P=27,360,123 Net income for the year – – – – – 4,333,613 90,715 4,424,328 Other comprehensive income – – – 557,554 – – – 557,554 Total comprehensive income for the year – – – 557,554 – 4,333,613 90,715 4,981,882 Cash dividends - P=0.18 a share (Note 19b) – – – – – (1,324,549) – (1,324,549) Cash dividends paid to non-controlling interests – – – – – – (148,848) (148,848) Acquisition of non-controlling interests – – – – (151,984) – (25,962) (177,946) Change in non-controlling interests – – – – – – 1,001 1,001 Balances at December 31, 2008 P=7,358,604 P=12,588,894 P=– (P=18,422) (P=259,147) P=10,485,401 P=536,333 P=30,691,663 See accompanying Notes to Consolidated Financial Statements.

*SGVMC409381*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in Thousands) Years Ended December 31 2010 2009 2008

CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax P=26,003,727 P=6,400,958 P=5,042,712 Adjustments for:

Interest expense and other financing costs (Note 32) 6,678,293 2,813,978 378,536

Depreciation and amortization (Notes 11 and 12) 3,003,977 1,412,900 511,154 Write-off of project costs and assets 42,217 – 5,254 Gain on sale of property, plant and equipment (75) (2,865) (2,965) Unrealized fair valuation losses (gains) on derivatives (22,977) 15,630 – Interest income (Notes 4, 13 and 31) (224,158) (409,972) (607,540) Net unrealized foreign exchange losses (gains) (1,504,650) (27,468) 49,084 Share in net earnings of associates (Note 9) (4,625,883) (2,535,386) (2,784,511) Dividend income – – (33)

Operating income before working capital changes 29,350,471 7,667,775 2,591,691 Decrease (increase) in:

Trade and other receivables (2,399,871) (2,608,352) 42,128 Inventories (734,948) (547,968) 42,579 Other current assets (448,445) (20,600) (136,977) Other noncurrent assets 410,269 (922,143) 13,008

Increase (decrease) in: Trade and other payables 1,685,285 2,651,669 (169,543) Customers’ deposits 223,268 210,024 197,162

Net cash generated from operations 28,086,029 6,430,405 2,580,048 Income and final taxes paid (770,382) (516,772) (634,654) Service fees paid (Note 12) (40,000) (40,000) (40,000) Net cash flows from operating activities 27,275,647 5,873,633 1,905,394

CASH FLOWS FROM INVESTING ACTIVITIES Cash dividends received (Note 9) 1,818,359 833,187 1,930,244 Interest received 215,259 451,683 595,220 Proceeds from sale of property, plant and equipment 1,778 18,604 5,995 Additions to:

Intangible assets - service concession rights (Note 12) (104,250) (70,259) (227,401) Property, plant and equipment

(Notes 11 and 35) (4,208,027) (3,274,390) (2,623,993) Additional investments in associates (Notes 9) (1,031,232) (2,526,754) (3,779,977) Net collection of (additional) advances to associates

(Note 9) (1,060,396) 813,221 (1,687,932) Acquisition of Tiwi-Makban Geothermal Power Plants

(Note 8) – (20,198,774) – Net cash flows used in investing activities (4,368,509) (23,953,482) (5,787,844) (Forward)

*SGVMC409381*

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CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from availment of long-term debt - net of

transaction costs (Note 16) P=870,000 P=9,762,893 P=5,712,664 Payments to a preferred shareholder of a subsidiary

(Note 18) (31,070) (31,070) (31,070) Changes in non-controlling interests (208,960) (158,142) 221,276 Payments of:

Long-term debt (Note 16) (442,564) (48,446) (1,000) Finance lease obligation (1,118,880) – –

Interest paid (1,622,023) (1,468,820) (299,216) Cash dividends paid (Note 19b) (2,207,581) (1,471,721) (1,324,549) Net availments (payment) of bank loans (Note 15) (3,597,038) 1,136,900 949,000 Acquisitions of non-controlling interests – – (177,946) Net cash flows from (used in) financing activities (8,358,116) 7,721,594 5,049,159

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 14,549,022 (10,358,255) 1,166,709

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (62,083) (160,515) 460,864

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 3,814,906 14,333,676 12,706,103

CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 4) P=18,301,845 P=3,814,906 P=14,333,676

See accompanying Notes to Consolidated Financial Statements.

*SGVMC409381*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Amounts in Thousands, Except Share and Exchange Rate Data and When Otherwise Indicated) 1. Corporate Information

General Information Aboitiz Power Corporation (the Company) and its subsidiaries (collectively referred to as “the Group”) were incorporated in the Republic of the Philippines. The Company is a publicly-listed holding company of the entities engaged in power generation and power distribution in the Aboitiz Group. The Company is a 76.40%-owned subsidiary of Aboitiz Equity Ventures, Inc. (AEV, also incorporated in the Philippines). The ultimate parent of the Company is Aboitiz & Company, Inc. (ACO). The registered office address of the Company is Aboitiz Corporate Center, Gov. Manuel A. Cuenco Avenue, Cebu City. The consolidated financial statements of the Group as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010, were authorized for issue by the Board of Directors (BOD) of the Company on March 3, 2011.

2. Basis of Preparation, Statement of Compliance and Summary of Significant Accounting

Policies Basis of Preparation The consolidated financial statements of the Group have been prepared on a historical cost basis, except for derivative financial instruments and quoted available-for-sale (AFS) investments which have been measured at fair value. The consolidated financial statements are presented in Philippine Peso which is the Company’s functional currency and all values are rounded to the nearest thousand except for earnings per share and exchange rates and otherwise indicated. Statement of Compliance The consolidated financial statements of the Group have been prepared in compliance with Philippine Financial Reporting Standards (PFRS). Changes in Accounting Policies The accounting policies adopted are consistent with those of the previous financial year, except for the adoption of the following new and amended PFRS and Philippine Interpretations effective beginning January 1, 2010: • PFRS 3 (Revised), Business Combinations, and Philippine Accounting Standard (PAS) 27

(Amended), Consolidated and Separate Financial Statements PFRS 3 (Revised) introduces significant changes in the accounting for business combinations occurring after becoming effective. Changes affect the valuation of non-controlling interest, the accounting for transaction costs, the initial recognition and subsequent measurement of a contingent consideration and business combinations achieved in stages. These changes will impact the amount of goodwill recognized, the reported results in the period that an acquisition occurs and future reported results.

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*SGVMC409381*

PAS 27 (Amended) requires that a change in the ownership interest of a subsidiary (without loss of control) is accounted for as a transaction with owners in their capacity as owners. Therefore, such transactions will no longer give rise to goodwill, nor will it give rise to a gain or loss. Furthermore, the amended standard changes the accounting for losses incurred by the subsidiary as well as the loss of control of a subsidiary. The changes by PFRS 3 (Revised) and PAS 27 (Amended) affect acquisitions or loss of control of subsidiaries and transactions with non-controlling interests after January 1, 2010.

Adoption of the following changes in PFRS and Philippine Interpretations did not have any significant impact on the Group’s consolidated financial statements.

• PFRS 2, Share-based Payment (Amendment) - Group Cash-settled Share-based Payment

Transactions • PAS 39, Financial Instruments: Recognition and Measurement (Amendment) - Eligible

Hedged Items • Philippine Interpretation IFRIC 17, Distributions of Non-cash Assets to Owners

Improvements to PFRS Improvements to PFRS, an omnibus of amendments to standards, deal primarily with a view to removing inconsistencies and clarifying wording. There are separate transitional provisions for each standard. The adoption of the following amendments resulted in changes to accounting policies but did not have any impact on the financial position or performance of the Group. • PFRS 8, Operating Segments: Clarifies that segment assets and liabilities need only be

reported when those assets and liabilities are included in measures that are used by the chief operating decision maker. As the Group’s chief operating decision maker does review segment assets and liabilities, the Group has continued to disclose this information in Note 30.

• PAS 7, Statement of Cash Flows: States that only expenditure that results in recognizing an asset can be classified as a cash flow from investing activities. This amendment will impact the presentation in the statement of cash flows.

• PAS 39, Financial Instruments: Recognition and Measurement: Clarifies that a prepayment option is considered closely related to the host contract when the exercise price of a prepayment option reimburses the lenders up to the approximate present value of lost interest for the remaining term of the host contracts. As a result, prepayment penalties identified as embedded derivatives may no longer be required to be accounted as such as they are now considered closely related to the host contract.

Other amendments resulting from the Improvements to PFRS to the following standards did not have any impact on the accounting policies, financial position or performance of the Group: Issued in May 2008 • PFRS 5, Non-current Assets Held for Sale and Discontinued Operations

Issued in April 2009 • PAS 36, Impairment of Assets • PFRS 2, Share-based Payment • PAS 1, Presentation of Financial Statements • PAS 17, Leases • PAS 34, Interim Financial Reporting

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*SGVMC409381*

• PAS 38, Intangible Assets • Philippine Interpretation IFRIC 9, Reassessment of Embedded Derivatives • Philippine Interpretation IFRIC 16, Hedge of a Net Investment in a Foreign Operation

Basis of Consolidation The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as of December 31 of each year. Percentage of Ownership Nature of 2010 2009 2008 Business Direct Indirect Direct Indirect Direct Indirect

Aboitiz Energy Solutions, Inc. (AESI) Energy related service provider

100.00 – 100.00 – 100.00 –

Davao Light & Power Company, Inc. (DLP) Power distribution 99.93 – 99.93 – 99.92 –

Cotabato Light & Power Company (CLP) Power distribution 99.94 – 99.93 – 99.91 –

Subic Enerzone Corporation (SEZ) Power distribution 65.00 34.97 65.00 34.97 65.00 34.97

Mactan Enerzone Corporation (MEZ) Power distribution 100.00 – 100.00 – 100.00 –

Balamban Enerzone Corporation (BEZ) Power generation 100.00 – 100.00 – 60.00 –

Aboitiz Renewables, Inc. (ARI; formerly Philippine Hydropower Corporation) and Subsidiaries **

Power generation 100.00 – 100.00 – 100.00 –

Cleanergy Inc. *** Power generation – 100.00 – 100.00 – 100.00

Hedcor Tamugan, Inc. (HTI) *** Power generation – 100.00 – 100.00 – 100.00

Hedcor, Inc. (HI) Power generation – 100.00 – 100.00 – 100.00

Kookaburra Equity Ventures, Inc. *** Holding company – 60.00 – 60.00 – 60.00

Hedcor Sibulan, Inc. (HSI) Power generation – 100.00 – 100.00 – 100.00

Hydro Electric Development Corporation *** Power generation – 99.97 – 99.97 – 99.97

AP Renewables, Inc. (APRI) Power generation – 100.00 – 100.00 – 100.00

Hedcor Benguet, Inc. (HBI) *** Power generation – 100.00 – 100.00 – –

Therma Power, Inc. (TPI) and Subsidiaries Power generation 100.00 – 100.00 – 100.00 –

Thema Power-Visayas, Inc. (TPVI) *** Power generation – 100.00 – 100.00 – 100.00

Therma Luzon, Inc. (TLI) * Power generation – 100.00 – 100.00 – 100.00

Therma Marine, Inc. (Therma Marine) * Power generation – 100.00 – 100.00 – 100.00

Therma Mobile, Inc. (Therma Mobile) *** Power generation – 100.00 – 100.00 – 100.00

Therma Pagbilao, Inc. (Therma Pagbilao) *** Power generation – 100.00 – 100.00 – 100.00

Abovant Holdings, Inc. Holding company – 60.00 – 60.00 – 60.00

Cebu Private Power Corporation (CPPC) Power generation 60.00 – 60.00 – 60.00 –

Adventenergy, Inc. *** Retail electricity supplier

100.00 – 100.00 – 100.00 –

* TPVI, TLI Therma Marine, Therma Mobile and Therma Pagbilao were incorporated in 2008. HBI was incorporated in 2009. ** On March 23, 2010, the Philippine Securities and Exchange Commission (SEC) approved the change in corporate name of Philippine Hydropower Corporation to ARI. ***No commercial operations as of December 31, 2010.

Basis of consolidation from January 1, 2010 The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at December 31 of each year. The financial statements of the subsidiaries are prepared for the same reporting year as the Company using consistent accounting policies. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. All intra-group balances, transactions, income and expenses and profits and losses resulting from intra-group transactions that are recognized in assets, are eliminated in full. The results of subsidiaries acquired or disposed of during the year are included in the consolidated statement of income from the date of acquisition or up to the date of disposal, as appropriate.

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*SGVMC409381*

Losses within a subsidiary are attributed to the non-controlling interest even if that results in a deficit balance. A change in the ownership interest of a subsidiary, without loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it: • Derecognizes the assets (including goodwill) and liabilities of the subsidiary • Derecognizes the carrying amount of any non-controlling interest • Derecognizes the cumulative translation differences recorded in equity • Recognizes the fair value of the consideration received • Recognizes the fair value of any investment retained • Recognizes any surplus or deficit in profit or loss • Reclassifies the parent’s share of components previously recognized in other comprehensive

income to profit or loss or retained earnings, as appropriate. Basis of consolidation prior to January 1, 2010 Whenever applicable, the above requirements were applied on a prospective basis. The following differences, however, are carried forward in certain instances from the previous basis of consolidation: • Losses incurred by the Group were attributed to the non-controlling interest until the balance

was reduced to nil. Any further excess losses were attributed to the parent, unless the non-controlling interest had a binding obligation to cover these. Losses prior to January 1, 2010 were not reallocated between non-controlling interest and the parent shareholders.

• Upon loss of control, the Group accounted for the investment retained at its proportionate share of net asset value at the date control was lost. The carrying value of such investment at January 1, 2010 has not been restated.

Transactions with non-controlling interests Non-controlling interests represent the portion of net income or loss and net assets in the subsidiaries not held by the Group and are presented separately in the consolidated statement of income and within equity in the consolidated balance sheet, separately from the equity attributable to equity holders of the parent. Transactions with non-controlling interests are accounted for as equity transactions. On acquisitions of non-controlling interests, the difference between the consideration and the book value of the share of the net assets acquired is reflected as being a transaction between owners and recognized directly in equity. Gain or loss on disposals of non-controlling interest is also recognized directly in equity. Summary of Significant Accounting Policies Business Combination and Goodwill Business combinations from January 1, 2010 Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. For each business combination, the acquirer measures the non-controlling interest in the acquiree either at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses.

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*SGVMC409381*

When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss. Any contingent consideration to be transferred by the acquirer will be recognized at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration which is deemed to be an asset or liability, will be recognized in accordance with PAS 39 either in profit or loss or as a change to other comprehensive income. If the contingent consideration is classified as equity, it should not be remeasured until it is finally settled within equity. Goodwill is initially measured at cost being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognized directly in profit or loss. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Where goodwill forms part of a cash-generating unit and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash-generating unit retained. Business combinations prior to January 1, 2010 In comparison to the abovementioned requirements, the following differences applied: Business combinations were accounted for using the purchase method. Transaction costs directly attributable to the acquisition formed part of the acquisition costs. The non-controlling interest (formerly known as minority interest) was measured at the proportionate share of the acquiree’s identifiable net assets. Business combinations achieved in stages were accounted for as separate steps. Any additional acquired share of interest did not affect previously recognized goodwill. When the Group acquired a business, embedded derivatives separated from the host contract by the acquiree were not reassessed on acquisition unless the business combination resulted in a change in the terms of the contract that significantly modified the cash flows that otherwise would have been required under the contract. Contingent consideration was recognized if, and only if, the Group had a present obligation, the economic outflow was more likely than not and a reliable estimate was determinable. Subsequent adjustments to the contingent consideration were recognized as part of goodwill.

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*SGVMC409381*

Impairment of goodwill Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment, annually or more frequently, if events or changes in circumstances indicate that the carrying value may be impaired. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the combination, irrespective of whether other assets or liabilities of the Group are assigned to those units or groups of units. Impairment is determined by assessing the recoverable amount of the cash-generating unit or group of cash-generating units, to which the goodwill relates. Where the recoverable amount of the cash-generating unit or group of cash-generating units is less than the carrying amount, an impairment loss is recognized. Investments in Associates The Group’s investments in associates are accounted for under the equity method of accounting. An associate is an entity in which the Group has significant influence and which is neither a subsidiary nor a joint venture. Under the equity method, the investment in the associate is carried in the consolidated balance sheet at cost plus post-acquisition changes in the Group’s share of net assets of the associate. Goodwill relating to an associate is included in the carrying amount of the investment and is not amortized. After application of the equity method, the Group determines whether it is necessary to recognize any additional impairment loss with respect to the Group’s net investment in the associates. The consolidated statement of income reflects the share of the results of operations of the associates. Where there has been a change recognized directly in the equity of the associate, the Group recognizes its share of any changes and discloses this, when applicable, in the consolidated statement of changes in equity. The share of profit of associates is shown on the face of the consolidated statement of income. This is the profit attributable to equity holders of the associate and therefore is profit after tax and non-controlling interest in the subsidiaries of the associates. The reporting dates of the associates and the Group are identical, and the associates’ accounting policies conform to those used by the Group for like transactions and events in similar circumstances. Foreign Currency Translation Each entity in the Group determines its own functional currency and items included in the financial statements of each entity are measured using that functional currency. Transactions in foreign currencies are initially recorded in the functional currency at the rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange ruling at the balance sheet date. All differences are taken to the consolidated statement of income. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

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*SGVMC409381*

The functional currency of Luzon Hydro Corporation (LHC), Western Mindanao Power Corporation (WMPC), Southern Philippines Power Corporation (SPPC) and STEAG State Power, Inc. (STEAG), associates, is the United States (US) Dollar. As at the reporting date, the assets and liabilities of these entities are translated into the presentation currency of the Group (the Philippine peso) at the rate of exchange ruling at the balance sheet date and their statements of income are translated at the weighted average exchange rates for the year. The exchange differences arising on the translation are taken directly to other comprehensive income. On disposal of the associate, the deferred cumulative amount recognized in other comprehensive income relating to that particular entity is recognized in the consolidated statement of income.

Cash and Cash Equivalents Cash and cash equivalents in the consolidated balance sheet consist of cash in banks and on hand and short-term deposits with an original maturity of three months or less from dates of placements and that are subject to insignificant risk of changes in value. For the purpose of the consolidated statement of cash flows, cash and cash equivalents consist of cash and cash equivalents as defined above. Inventories Materials and supplies are valued at the lower of cost and net realizable value (NRV). Cost is determined on weighted average method. NRV is the current replacement cost. An allowance for inventory obsolescence is provided for slow-moving, defective or damaged goods based on analyses and physical inspection. Financial Instruments The Group recognizes a financial instrument in the consolidated balance sheet when it becomes a party to the contractual provisions of the instrument. All financial instruments are initially recognized at fair value. Transaction costs, if any, are included in the initial measurement of all financial instruments, except for financial instruments measured at fair value through profit or loss (FVPL). All regular way purchases and sales of financial assets are recognized on the trade date, which is the date that the Group commits to purchase the asset. Regular way purchases or sales are purchases and sale of financial assets that require delivery of assets within the period generally established by regulation or convention in the marketplace. Derivatives are also recognized on a trade basis. Financial instruments are classified into the following categories: Financial assets or financial liabilities at FVPL, loans and receivables, held-to-maturity (HTM) investments, AFS financial assets and other financial liabilities. The classification depends on the purpose for which the investments were acquired and whether they are quoted in an active market. The Group determines the classification at initial recognition and, where allowed and appropriate, re-evaluates such designation at every reporting date. (a) Financial assets or financial liabilities at FVPL

Financial assets and liabilities at FVPL include financial assets and liabilities held for trading purposes and financial assets and liabilities designated upon initial recognition as at FVPL. Financial assets and liabilities are classified as held for trading if they are acquired for the purpose of selling and repurchasing in the near term. Derivatives, including separated

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*SGVMC409381*

embedded derivatives, are also classified as held for trading unless they are designated and considered as hedging instruments in an effective hedge. Financial assets and liabilities may be designated at initial recognition as at FVPL if the following criteria are met: (i) the designation eliminates or significantly reduces the inconsistent treatment that would otherwise arise from measuring the assets or liabilities, or recognizing gains or losses on them on a different basis; (ii) the assets and liabilities are part of a group of financial assets, liabilities or both, which are managed and their performance evaluated on a fair value basis, in accordance with a documented risk managing strategy; or (iii) the financial instruments contains an embedded derivative that would need to be recorded separately, unless the embedded derivative does not significantly modify the cash flow or it is clear, with little or no analysis, that it would not be separately recorded. Where a contract contains one or more embedded derivatives, the entire hybrid contract may be designated as financial asset or financial liability at FVPL, except where the embedded derivative does not significantly modify the cash flows or it is clear that separation of the embedded derivative is prohibited. Financial assets and liabilities at FVPL are recorded at the consolidated balance sheet at fair value. Subsequent changes in fair value are recognized in the consolidated statement of income. Interest earned or incurred is recorded as interest income or expense, respectively, while dividend income is recorded as other income when the right to receive payments has been established. The Group’s derivative assets and derivative liabilities are classified as financial assets and financial liabilities at FVPL, respectively (see Note 33).

(b) Loans and receivables

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. These are not entered into with the intention of immediate or short-term resale and are not classified or designated as AFS investments or financial assets at FVPL. Loans and receivables are carried at amortized cost less allowance for impairment. Amortization is determined using the effective interest rate method. Amortized cost is calculated by taking into account any discount or premium on acquisition and fees that are integral to the effective interest rate. Gains and losses are recognized in the consolidated statement of income when the loans and receivables are derecognized or impaired, as well as through the amortization process. Loans and receivables are included in current assets if maturity is within twelve months from the balance sheet date. Otherwise, these are classified as noncurrent assets. Included under this category are the Group’s cash and cash equivalents, trade and other receivables, amounts owed by related parties and restricted cash (see Note 33).

(c) HTM investments HTM investments are quoted non-derivative financial assets which carry fixed or determinable payments and fixed maturities and which the Group has the positive intention and ability to hold to maturity. After initial measurement, HTM investments are measured at amortized cost using the effective interest method. This method uses an effective interest rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to the net carrying amount of the financial asset. Amortized cost is calculated by taking into account

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any discount or premium on acquisition and fees that are integral to the effective interest rate. Where the Group sells other than an insignificant amount of HTM investments, the entire category would be tainted and would have to be reclassified as AFS investments. Gains and losses are recognized in the consolidated statement of income when the investments are derecognized or impaired, as well as through the amortization process. The Group does not have any HTM investment as of December 31, 2010 and 2009.

(d) AFS investments AFS investments are non-derivative financial assets that are either designated as AFS or not classified in any of the other categories. They are purchased and held indefinitely, and may be sold in response to liquidity requirements or changes in market conditions. Quoted AFS investments are measured at fair value with gains or losses being recognized as other comprehensive income, until the investments are derecognized or until the investments are determined to be impaired at which time, the accumulated gains or losses previously reported in other comprehensive income are included in the consolidated statement of income. Unquoted AFS investments are carried at cost, net of impairment. Interest earned or paid on the investments is reported as interest income or expense using the effective interest rate. Dividends earned on investments are recognized in the consolidated statement of income when the right of payment has been established. These financial assets are classified as noncurrent assets unless the investment matures or management intends to dispose it within twelve months after the end of the reporting period. The Group’s AFS investments as of December 31, 2010 and 2009 include investments in unquoted shares of stock (see Note 33).

(e) Other financial liabilities This category pertains to financial liabilities that are not held for trading or not designated as at FVPL upon the inception of the liability. These include liabilities arising from operations or borrowings. Other financial liabilities are recognized initially at fair value and are subsequently carried at amortized cost, taking into account the impact of applying the effective interest method of amortization (or accretion) for any directly attributable transaction costs. Gains and losses are recognized in the consolidated statement of income when liabilities are derecognized, as well as through amortization process. Included under this category are the Group’s trade and other payables, amounts owed to related parties, customers’ deposits, bank loans, payable to a preferred shareholder of a subsidiary, finance lease obligation, long-term obligation on power distribution system, and long-term debts.

Determination of fair value The fair value for financial instruments traded in active markets at the balance sheet date is based on their quoted market price or dealer price quotations (bid price for long positions and ask price for short positions), without any deduction for transaction costs. When current bid and asking prices are not available, the price of the most recent transaction provides evidence of the current fair value as long as there has not been a significant change in economic circumstances since the time of the transaction.

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For all other financial instruments not listed in an active market, the fair value is determined by using appropriate valuation techniques. Valuation techniques include net present value techniques, comparison to similar instruments for which market observable prices exist, options pricing models, and other relevant valuation models. ‘Day 1’ difference Where the transaction price in a non-active market is different from the fair value of other observable current market transactions in the same instrument or based on a valuation technique whose variables include only data from observable market, the Group recognizes the difference between the transaction price and fair value (a ‘Day 1’ difference) in the consolidated statement of income unless it qualifies for recognition as some other type of asset. In cases where unobservable data is used, the difference between the transaction price and model value is only recognized in the consolidated statement of income when the inputs become observable or when the instrument is derecognized. For each transaction, the Group determines the appropriate method of recognizing the ‘Day 1’ difference amount. Derivative financial instruments Derivative financial instruments, including embedded derivatives, are initially recognized at fair value on the date in which a derivative transaction is entered into or bifurcated, and are subsequently remeasured at FVPL, unless designated as effective hedge. Changes in fair value of derivative instruments not accounted as hedges are recognized immediately in the consolidated statement of income. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. The Group assesses whether embedded derivatives are required to be separated from host contracts when the Group first becomes party to the contract. An embedded derivative is separated from the host financial or non-financial contract and accounted for as a separate derivative if all of the following conditions are met: • the economic characteristics and risks of the embedded derivative are not closely related to the

economic characteristics of the host contract; • a separate instrument with the same terms as the embedded derivative would meet the

definition of a derivative; and, • the hybrid or combined instrument is not recognized as at FVPL. Reassessment only occurs if there is a change in the terms of the contract that significantly modifies the cash flows that would otherwise be required. Embedded derivatives that are bifurcated from the host contracts are accounted for either as financial assets or financial liabilities at FVPL. As of December 31, 2010 and 2009, the Group has freestanding derivatives in the form of non-deliverable foreign currency forward contracts entered into to economically hedge its foreign exchange risk (see Note 33). In 2010 and 2009, the Group did not apply hedge accounting treatment on its derivative transactions. The Group has not bifurcated any embedded derivatives as of December 31, 2010 and 2009.

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Classification of financial instruments between liability and equity A financial instrument is classified as liability if it provides for a contractual obligation to: • deliver cash or another financial asset to another entity; or • exchange financial assets or financial liabilities with another entity under conditions that are

potentially unfavorable to the Group; or • satisfy the obligation other than by the exchange of a fixed amount of cash or another financial

asset for a fixed number of own equity shares. If the Group does not have an unconditional right to avoid delivering cash or another financial asset to settle its contractual obligation, the obligation meets the definition of a financial liability. Financial instruments are classified as liabilities or equity in accordance with the substance of the contractual arrangement. Interest, dividends, gains and losses relating to a financial instrument or a component that is a financial liability, are reported as income or expense. Distributions to holders of financial instruments classified as equity are charged directly to equity net of any related income tax benefits. The components of issued financial instruments that contain both liability and equity elements are accounted for separately, with the equity component being assigned the residual amount after deducting from the instrument as a whole the amount separately determined as the fair value of the liability component on the date of issue. Derecognition of Financial Assets and Liabilities Financial assets A financial asset (or, where applicable a part of a financial asset or part of a group of similar financial assets) is derecognized where: • the rights to receive cash flows from the asset expires; • the Group retains the right to receive cash flows from the asset, but has assumed an obligation to

pay them in full without material delay to a third party under a ‘pass-through’ arrangement; or • the Group has transferred its rights to receive cash flows from the asset and either (a) has

transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

Where the Group has transferred its rights to receive cash flows from an asset and has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the asset is recognized to the extent of the Group’s continuing involvement in the asset. Financial liabilities A financial liability is derecognized when the obligation under the liability is discharged, cancelled or expires. Where an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognized in the consolidated statement of income.

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Impairment of Financial Assets The Group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if and only if, there is an objective evidence of impairment as a result of one or more events that has occurred after the initial recognition of the asset (an incurred ‘loss event’) and that loss event has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtors or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganization and where observable data indicate that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults. Assets carried at amortized cost The Group first assesses whether objective evidence of impairment exists individually for financial assets that are individually significant, and individually or collectively for financial assets that are not individually significant. If it is determined that no objective evidence of impairment exists for an individually assessed financial asset, whether significant or not, the asset is included in a group of financial assets with similar credit risk characteristics and that group of financial assets is collectively assessed for impairment. Assets that are individually assessed for impairment and for which an impairment loss is or continues to be recognized are not included in a collective assessment of impairment. If there is an objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset’s original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset shall be reduced either directly or through use of an allowance account. The amount of the loss shall be recognized in the consolidated statement of income. If in case, the receivable has proven to have no realistic prospect of future recovery, any allowance provided for such receivable is written off against the carrying value of the receivable. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed. Any subsequent reversal of an impairment loss is recognized in the consolidated statement of income, to the extent that the carrying value of the asset does not exceed its amortized cost at the reversal date. AFS investments For AFS investments, the Group assesses at each balance sheet date whether there is objective evidence that an investment or group of investments is impaired. In the case of equity investments classified as AFS, objective evidence of impairment would include a significant or prolonged decline in the fair value of the investments below its cost. Where there is evidence of impairment, the cumulative loss (measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in the consolidated statement of income) is removed from other comprehensive income and recognized in the consolidated statement of income. Impairment losses on equity investments are not reversed through the consolidated statement of income. Increases in fair value after impairment are recognized directly in other comprehensive income.

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In the case of debt instruments classified as AFS, impairment is assessed based on the same criteria as financial assets carried at amortized cost. Future interest income is based on rate of interest used to discount future cash flows for measuring impairment loss. Such accrual is recorded as part of “Interest income” in the consolidated statement of income. If, in subsequent period, the fair value of a debt instrument increased and the increase can be objectively related to an event occurring after the impairment loss was recognized in the consolidated statement of income, the impairment loss is reversed through the consolidated statement of income.

Offsetting Financial Instruments Financial assets and financial liabilities are offset and the net amount is reported in the balance sheet if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the asset and settle the liability simultaneously. This is not generally the case with master netting agreements whereby the related assets and liabilities are presented gross in the consolidated balance sheet. Property, Plant and Equipment Except for land, property, plant and equipment are stated at cost, excluding the cost of day-to-day servicing, less accumulated depreciation and accumulated impairment in value. Such cost includes the cost of replacing parts of such property, plant and equipment when that cost is incurred if the recognition criteria are met. Repairs and maintenance costs are recognized in the consolidated statement of income as incurred. Land is stated at cost less any accumulated impairment in value. Except for the power plant machinery and equipment of CPPC, which is depreciated over the shorter of its Co-operation Period of 15 years (see Note 20) or the estimated useful lives of the assets, depreciation of the other property, plant and equipment is computed using the straight-line method over the estimated useful lives of the assets as follows:

Category Estimated Useful

Life (in years) Buildings, warehouses and improvements 20 Power plant equipment 9-40 Transmission, distribution and substation equipment

Power transformers 30 Poles and wires 30 Other components 12

Transportation equipment 3-5 Office furniture, fixtures and equipment 2-5 Electrical equipment 5 Meters and laboratory equipment 12 Tools and others 3 Steam field assets 20-25

Leasehold improvements are amortized over the shorter of the lease term or the life of the asset. The carrying values of property, plant and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying values may not be recoverable. Fully depreciated assets are retained in the accounts until these are no longer in use. When assets are retired or otherwise disposed of, both the cost and related accumulated depreciation and amortization and any allowance for impairment losses are removed from the accounts and any resulting gain or loss is credited or charged to current operations. An item of property, plant and

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equipment is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the consolidated statement of income in the year the asset is derecognized. The assets’ residual values, useful lives and depreciation method are reviewed, and adjusted if appropriate, at each financial year-end. When each major inspection is performed, its cost is recognized in the carrying amount of the property, plant and equipment as a replacement if the recognition criteria are satisfied. Construction in progress represents structures under construction and is stated at cost. This includes cost of construction and other direct costs. Borrowing costs that are directly attributable to the construction of property, plant and equipment are capitalized during the construction period. Arrangement Containing a Lease The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement and requires an assessment of whether the fulfillment of the arrangement is dependent on the use of a specific asset or assets and the arrangement conveys a right to use the asset. A reassessment is made after inception of the lease only if one of the following applies: (a) there is a change in contractual terms, other than a renewal or extension of the arrangement; (b) a renewal option is exercised or extension granted, unless the term of the renewal or

extension was initially included in the lease term; (c) there is a change in the determination of whether fulfillment is dependent on a specific asset;

or (d) there is a substantial change to the asset. Where a reassessment is made, lease accounting shall commence or cease from the date when the change in circumstances gives rise to the reassessment for scenarios (a), (c) or (d) above, and at the date of renewal or extension period for scenario (b). Finance lease Finance leases, which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Obligations arising from plant assets under finance lease agreement are classified in the balance sheet as finance lease obligation. Lease payments are apportioned between financing charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Financing charges are charged directly against income. Capitalized leased assets are depreciated over the estimated useful life of the assets when there is reasonable certainty that the Group will obtain ownership by the end of the lease term. Operating lease Leases where the lessor retains substantially all the risks and benefits of ownership of the asset are classified as operating lease. Operating lease payments are recognized as an expense in the consolidated statement of income on a straight-line basis over the lease term.

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Service Concession Arrangements Public-to-private service concession arrangements where: (a) the grantor controls or regulates what services the entities in the Group must provide with the infrastructure, to whom it must provide them, and at what price; and (b) the grantor controls-through ownership, beneficial entitlement or otherwise-any significant residual interest in the infrastructure at the end of the term of the arrangement, are accounted for under the provisions of Philippine Interpretation IFRIC 12, Service Concession Arrangements. Infrastructures used in a public-to-private service concession arrangement for its entire useful life (whole-of-life assets) are within the scope of this Interpretation if the conditions in (a) are met. This Interpretation applies to both: (a) infrastructure that the entities in the Group constructs or acquires from a third party for the purpose of the service arrangement; and (b) existing infrastructure to which the grantor gives the entity in the Group access for the purpose of the service arrangement. Infrastructures within the scope of this Interpretation are not recognized as property, plant and equipment of the Group. Under the terms of contractual arrangements within the scope of this Interpretation, an entity acts as a service provider. An entity constructs or upgrades infrastructure (construction or upgrade services) used to provide a public service and operates and maintains that infrastructure (operation services) for a specified period of time. An entity recognizes and measures revenue in accordance with PAS 11, Construction Contracts, and PAS 18, Revenue, for the services it performs. If an entity performs more than one service (i.e. construction or upgrade services and operation services) under a single contract or arrangement, consideration received or receivable shall be allocated by reference to the relative fair values of the services delivered, when the amounts are separately identifiable. When an entity provides construction or upgrades services, the consideration received or receivable by the entity is recognized at its fair value. An entity accounts for revenue and costs relating to construction or upgrade services in accordance with PAS 11. Revenue from construction contracts is recognized based on the percentage-of-completion method, measured by reference to the percentage of costs incurred to date to estimated total costs for each contract. The applicable entities account for revenue and costs relating to operation services in accordance with PAS 18. An entity recognizes a financial asset to the extent that it has an unconditional contractual right to receive cash or another financial asset from or at the direction of the grantor for the construction services. An entity recognizes an intangible asset to the extent that it receives a right (a license) to charge users of the public service. When the applicable entities have contractual obligations it must fulfill as a condition of its license (a) to maintain the infrastructure to a specified level of serviceability or (b) to restore the infrastructure to a specified condition before it is handed over to the grantor at the end of the service arrangement, it recognizes and measures these contractual obligations in accordance with PAS 37, Provisions, Contingent Liabilities and Contingent Assets, i.e., at the best estimate of the expenditure that would be required to settle the present obligation at the balance sheet date. Borrowing cost attributable to the construction of the asset if the consideration received or receivable is an intangible asset, is capitalized during the construction phase. In all other cases, borrowing costs are expensed as incurred.

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Intangible Assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is fair value as at the date of the acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and any accumulated impairment losses. Internally generated intangible assets, excluding capitalized development costs, are not capitalized and expenditure is reflected in the consolidated statement of income in the year in which the expenditure is incurred. The useful lives of intangible assets are assessed to be either finite or indefinite. Software and licenses Software and licenses are initially recognized at cost. Following initial recognition, the software and licenses are carried at cost less accumulated amortization and any accumulated impairment in value. The software development costs is amortized on a straight-line basis over its estimated useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization commences when the software development costs is available for use. The amortization period and the amortization method for the software development costs are reviewed at each financial year-end. Changes in the estimated useful life is accounted for by changing the amortization period or method, as appropriate, and treating them as changes in accounting estimates. The amortization expense is recognized in the consolidated statement of income in the expense category consistent with the function of the software development costs. Service concession right The Group’s intangible asset - service concession right pertains mainly to its right to charge users of the public service in connection with the service concession and related arrangements. This is recognized initially at the fair value of the construction services. Following initial recognition, the intangible asset is carried at cost less accumulated amortization and any accumulated impairment losses. The intangible asset - service concession right is amortized using the straight-line method over the estimated useful economic life which is the service concession period, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The estimated useful life is 25 years. The amortization period and the amortization method are reviewed at least at each financial year-end. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset is accounted for by changing the amortization period or method, as appropriate, and are treated as changes in accounting estimates. The amortization expense is recognized in the consolidated statement of income in the expense category consistent with the function of the intangible asset. Gains or losses arising from derecognition of an intangible asset - service concession right are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in the consolidated statement of income when the asset is derecognized. Project development costs Project development costs include power plant projects in the development phase which meet the “identifiability” requirement under PAS 38, Intangible Assets, as they are separable and susceptible to individual sale and are carried at acquisition cost. These assets are transferred to “Property, Plant and Equipment” when construction of each power plant commences.

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Research and Development Expenditure The Group’s policy is to record research expenses in the consolidated statement of income in the period when they are incurred. Development costs are recognized as an intangible asset on the balance sheet if the Group can identify them separately and show the technical viability of the asset, its intention and capacity to use or sell it, and how it will generate probable future economic benefits. Following initial recognition of the development expenditure as an asset, the cost model is applied requiring the asset to be carried at cost less any accumulated amortization and accumulated impairment losses. Amortization of the asset begins when development is complete and the asset is available for use. It is amortized over the period of expected future benefit. During the period of development, the asset is tested for impairment annually. Investment Property Investment property pertains to land not used in operations. Initially, investment property is measured at cost including transaction costs. Subsequent to initial recognition investment property is stated at cost less any impairment in value. Investment property is derecognized when it has either been disposed of or when the investment property is permanently withdrawn from use and no future benefit is expected from its disposal. Any gain or loss on the derecognition of an investment property is recognized in the consolidated statement of income in the year of derecognition. Transfers are made to investment property when, and only when, there is a change in use, evidenced by ending of owner-occupation, commencement of an operating lease to another party or ending of construction or development. Transfers are made from investment property when, and only when, there is a change in use, evidenced by commencement of owner-occupation or commencement of development with a view to sale.

For a transfer from investment property to owner-occupied property or inventories, the deemed cost of property for subsequent accounting is its fair value at the date of change in use. If the property occupied by the Group as an owner-occupied property becomes an investment property, the Group accounts for such property in accordance with the policy stated under property, plant and equipment up to the date of change in use. For a transfer from inventories to investment property, any difference between the fair value of the property, plant and equipment at that date and its previous carrying amount is recognized in the consolidated statement of income. When the Group completes the construction or development of a self-constructed investment property, any difference between the fair value of the property at that date and its previous carrying amount is recognized in the consolidated statement of income. Impairment of Non-financial Assets Other current assets, property, plant and equipment, intangible asset, investment property, and investment in and advances to associates The Group assesses at each reporting date whether there is an indication that an asset may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group makes an estimate of the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cash-generating unit’s fair value less costs to sell and its value in use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the

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time value of money and the risks specific to the asset. Impairment losses of continuing operations are recognized in the consolidated statement of income in those expense categories consistent with the function of the impaired asset. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the consolidated statement of income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Capital Stock Capital stock is measured at par value for all shares issued. When the Company issues more than one class of stock, a separate account is maintained for each class of stock and the number of shares issued. Capital stock includes common stock and preferred stock. When the shares are sold at premium, the difference between the proceeds and the par value is credited to the “Additional paid-in capital” account. When shares are issued for a consideration other than cash, the proceeds are measured by the fair value of the consideration received. In case the shares are issued to extinguish or settle the liability of the Company, the shares shall be measured either at the fair value of the shares issued or fair value of the liability settled, whichever is more reliably determinable.

Direct costs incurred related to equity issuance, such as underwriting, accounting and legal fees, printing costs and taxes are debited to the “Additional paid-in capital” account. If additional paid-in capital is not sufficient, the excess is charged against an equity reserve account. Revenue Recognition Revenue is recognized to the extent that it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable, taking into account contractually defined terms of payment and excluding discounts, rebates and other sales taxes or duties. The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as a principal or an agent. The Group assesses whether it is acting as a principal in all of its revenue arrangements. The following specific recognition criteria must also be met before revenue is recognized: Sale of power Revenue from power distribution is recognized upon supply of power to the customers. Revenue from power generation is recognized in the period actual capacity is generated and earned. In the case of ancillary services, revenue for scheduled capacity without energy dispatched is recognized as the scheduled time for the approved reserved capacity occurs. For scheduled capacity with energy dispatched, revenue is recognized as the actual dispatch is performed. Dividend income Dividend income is recognized when the Group’s right to receive payment is established.

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Services Service fees which are primarily earned from the installation of electrical power-saving devices are recognized when the Group’s share of power-saving income is determined. Technical, management and other fees Technical, management and other services fees are recognized when the related services are rendered. Interest income Interest is recognized as it accrues taking into account the effective interest method. Expenses Expenses are decreases in economic benefits during the accounting period in the form of outflows or decrease of assets or incurrence of liabilities that result in decreases in equity, other than those relating to distributions to equity participants. Expenses are recognized when incurred. Pension Benefits The Group has defined benefit pension plans which require contributions to be made to separately administered funds. The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit actuarial valuation method. Actuarial gains and losses are recognized as income or expense when the net cumulative unrecognized actuarial gains and losses for each individual plan at the end of the previous reporting year exceeded 10% of the higher of the defined benefit obligation and the fair value of plan assets at that date. These gains or losses are recognized over the expected average remaining working lives of the employees participating in the plans. The past service cost is recognized as an expense on a straight-line basis over the average period until the benefits become vested. If the benefits are already vested immediately following the introduction of, or changes to, a pension plan, past service cost is recognized immediately. The defined benefit liability is the aggregate of the present value of the defined benefit obligation and actuarial gains and losses not recognized reduced by past service cost not yet recognized and the fair value of plan assets out of which the obligations are to be settled directly. If such aggregate is negative, the asset is measured at the lower of such aggregate or the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan. If the asset is measured at the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan, net actuarial losses of the current period and past service cost of the current period are recognized immediately to the extent that they exceed any reduction in the present value of those economic benefits. If there is no change or an increase in the present value of the economic benefits, the entire net actuarial losses of the current period and past service cost of the current period are recognized immediately. Similarly, net actuarial gains of the current period after the deduction of past service cost of the current period exceeding any increase in the present value of the economic benefits stated above are recognized immediately if the asset is measured at the aggregate of cumulative unrecognized net actuarial losses and past service cost and the present value of any economic benefits available in the form of refunds from the plan or reductions in the future contributions to the plan. If there is no change or a decrease in the present value of the economic benefits, the entire net actuarial

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gains of the current period after the deduction of past service cost of the current period are recognized immediately. Borrowing Costs Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period they occur. Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. Taxes Current income tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted as of the balance sheet date. Deferred income tax Deferred income tax is provided using the balance sheet liability method on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognized for all taxable temporary differences, except: • where the deferred income tax liability arises from the initial recognition of goodwill or of an

asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and

• in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred income tax assets are recognized for all deductible temporary differences, carryforward benefits of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carryforward benefits of unused tax credits and unused tax losses can be utilized except: • where the deferred income tax asset relating to the deductible temporary difference arises from

the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and

• in respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred income tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become probable that future taxable profit will allow the deferred income tax asset to be recovered.

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Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted as of the balance sheet date. Income tax relating to items recognized directly in other comprehensive income is also recognized in other comprehensive income and not in the consolidated statement of income. Deferred income tax assets and deferred income tax liabilities are offset, if a legally enforceable right exists to set off current income tax assets against current income tax liabilities and the deferred income taxes relate to the same taxable entity and the same taxation authority. Sales tax Revenues, expenses and assets are recognized net of the amount of sales tax except: • where the sales tax incurred on a purchase of assets or services is not recoverable from the

taxation authority, in which case the sales tax is recognized as part of the cost of acquisition of the asset or as part of the expense item as applicable; and

• receivables and payables that are stated with the amount of sales tax included. The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the consolidated balance sheet. Provisions Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the consolidated statement of income net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as a borrowing cost. Contingencies Contingent liabilities are not recognized in the consolidated financial statements. These are disclosed unless the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognized in the consolidated financial statements but disclosed when an inflow of economic benefits is probable. Events After the Reporting Period Post year-end events that provide additional information about the Group’s position at balance sheet date (adjusting events) are reflected in the consolidated financial statements. Post year-end events that are not adjusting events are disclosed when material. Earnings Per Common Share Basic earnings per common share are computed by dividing net income for the year attributable to the common shareholders of the Company by the weighted average number of common shares issued and outstanding during the year, after giving retroactive effect for any stock dividends declared and stock rights exercised during the year.

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Diluted earnings per share amounts are calculated by dividing the net income for the year attributable to the common shareholders of the parent by the weighted average number of common shares outstanding during the year plus the weighted average number of common shares that would be issued for outstanding common stock equivalents. The Group does not have dilutive potential common shares. Dividends on Common Shares Dividends on common shares are recognized as a liability and deducted from retained earnings when approved by the respective shareholders of the Group and its subsidiaries. Dividends for the year that are approved after the balance sheet date are dealt with as an event after the reporting period. Operating Segments For management purposes, the Group is organized into two major operating segments (power generation and power distribution) according to the nature of the services provided, with each segment representing a significant business segment. The Group’s identified operating segments, which are consistent with the segments reported to the BOD which is the Group’s Chief Operating Decision Maker (CODM). Financial information on the operating segment is presented in Note 30. Future Changes in Accounting Policies

The Group will adopt the following standards and interpretations and assess their impact when these become effective. Except as otherwise indicated, the Group does not expect the adoption of these standards and interpretations to have significant impact on its consolidated financial statements.

Effective in 2011

• PAS 24, Related Party Disclosures (Amended) The amended standard is effective for annual periods beginning on or after January 1, 2011. It clarified the definition of a related party to simplify the identification of such relationships and to eliminate inconsistencies in its application. The revised standard introduces a partial exemption of disclosure requirements for government-related entities. The Group does not expect any impact on its financial position or performance. Early adoption is permitted for either the partial exemption for government-related entities or for the entire standard.

• PAS 32, Financial Instruments: Presentation (Amendment) - Classification of Rights Issues The amendment to PAS 32 is effective for annual periods beginning on or after February 1, 2010 and amended the definition of a financial liability in order to classify rights issues (and certain options or warrants) as equity instruments in cases where such rights are given pro rata to all of the existing owners of the same class of an entity’s non-derivative equity instruments, or to acquire a fixed number of the entity’s own equity instruments for a fixed amount in any currency.

• Philippine Interpretation IFRIC 14 (Amendment) - Prepayments of a Minimum Funding Requirement The amendment to Philippine Interpretation IFRIC 14 is effective for annual periods beginning on or after January 1, 2011, with retrospective application. The amendment provides guidance on assessing the recoverable amount of a net pension asset. The amendment permits an entity to treat the prepayment of a minimum funding requirement as an asset.

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• Philippine Interpretation IFRIC 19 - Extinguishing Financial Liabilities with Equity Instruments Philippine Interpretation IFRIC 19 is effective for annual periods beginning on or after July 1, 2010. The interpretation clarifies that equity instruments issued to a creditor to extinguish a financial liability qualify as consideration paid. The equity instruments issued are measured at their fair value. In case that this cannot be reliably measured, the instruments are measured at the fair value of the liability extinguished. Any gain or loss is recognized immediately in the consolidated statement of income.

Effective in 2012

• PFRS 7, Financial Instruments: Disclosures (Amendments) - Disclosures - Transfers of Financial Assets The amendments to PFRS 7 are effective for annual periods beginning on or after July 1, 2011. The amendments will allow users of financial statements to improve their understanding of transfer transactions of financial assets (for example, securitizations), including understanding the possible effects of any risks that may remain with the entity that transferred the assets. The amendments also require additional disclosures if a disproportionate amount of transfer transactions are undertaken around the end of a reporting period.

• PAS 12, Income Taxes (Amendment) - Deferred Tax: Recovery of Underlying Assets

The amendment to PAS 12 is effective for annual periods beginning on or after January 1, 2012. It provides a practical solution to the problem of assessing whether recovery of an asset will be through use or sale. It introduces a presumption that recovery of the carrying amount of an asset will, normally, be through sale.

• Philippine Interpretation IFRIC 15, Agreement for Construction of Real Estate This Interpretation, effective for annual periods beginning on or after January 1, 2012, covers accounting for revenue and associated expenses by entities that undertake the construction of real estate directly or through subcontractors. The Interpretation requires that revenue on construction of real estate be recognized only upon completion, except when such contract qualifies as construction contract to be accounted for under PAS 11, or involves rendering of services in which case revenue is recognized based on stage of completion. Contracts involving provision of services with the construction materials and where the risks and reward of ownership are transferred to the buyer on a continuous basis will also be accounted for based on stage of completion.

Effective in 2013

• PFRS 9, Financial Instruments: Classification and Measurement PFRS 9, as issued in 2010, reflects the first phase of the work on the replacement of PAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in PAS 39. The standard is effective for annual periods beginning on or after January 1, 2013. In subsequent phases, hedge accounting and derecognition will be addressed. The completion of this project is expected in the second quarter of 2011. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Group’s financial assets. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

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Improvements to PFRS 2010 Improvements to PFRS is an omnibus of amendments to PFRS. The amendments have not been adopted as they become effective for annual periods on or after either July 1, 2010 or January 1, 2011. The amendments listed below are considered to have a reasonable possible impact on the Group: • PFRS 3, Business Combinations • PFRS 7, Financial Instruments: Disclosures • PAS 1, Presentation of Financial Statements • PAS 27, Consolidated and Separate Financial Statements

3. Significant Judgments, Estimates and Assumptions The preparation of the Group’s consolidated financial statements require management to make judgments, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities and the disclosures of contingent liabilities. However, uncertainty about these assumptions could result in outcomes that require a material adjustment to the carrying amount of the asset or liability affected in the future periods. Judgments In the process of applying the Group’s accounting policies, management has made judgments, apart from those involving estimations, which have the most significant effect on the amounts recognized in the consolidated financial statements: Determining functional currency Based on the economic substance of the underlying circumstances relevant to the companies in the Group, the functional currency of the companies in the Group has been determined to be the Philippine Peso except for certain associates whose functional currency is the US Dollar. The Philippine peso is the currency of the primary economic environment in which the companies in the Group operates and it is the currency that mainly influences the sale of power and services and the costs of power and of providing the services. The functional currency of the Group’s associates is the Philippine Peso except for LHC, STEAG, SPPC and WMPC whose functional currency is the US Dollar. Service concession arrangements - Companies in the Group as Operators Based on management’s judgment, the provisions of Philippine Interpretation IFRIC 12 apply to SEZ’s Distribution Management Service Agreement (DMSA) with Subic Bay Metropolitan Authority (SBMA) and MEZ’s Built-Operate-Transfer (BOT) agreement with Mactan Cebu International Airport Authority (MCIAA). SEZ and MEZ’s service concession agreements were accounted for under the intangible asset model. The Company’s associates, LHC and STEAG, have also determined that the provisions of Philippine Interpretation IFRIC 12 apply to their power purchase agreements with NPC. LHC and STEAG’s service concession agreements were accounted for under the intangible asset and financial asset models, respectively. Refer to the accounting policy on service concession arrangements for the discussion of intangible asset and financial asset models. Determining fair value of customers’ deposits In applying PAS 39, Financial Instruments: Recognition and Measurement, on transformer and lines and poles deposits, the Group has made a judgment that the timing and related amounts of future cash flows relating to such deposits cannot be reasonably and reliably estimated for purposes of establishing their fair values using alternative valuation techniques since the expected

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timing of customers’ refund or claim for these deposits cannot be reasonably estimated. These customers’ deposits, which are therefore stated at cost, amounted to P=2.00 billion and P=1.78 billion as of December 31, 2010 and 2009, respectively (see Note 17). Finance lease - Company in the Group as the lessee In accounting for its Independent Power Producer (IPP) Administration Agreement with the Power Sector Asset and Liabilities Management Corporation (PSALM), the Group’s management has made a judgment that the IPP Administration Agreement of TLI is an arrangement that contains a lease. The Group’s management has made a judgment that TLI has substantially acquired all the risks and rewards incidental to ownership of the power plant. Accordingly, the Group accounted for the agreement as a finance lease and recognized the power plant and finance lease obligation at the present value of the agreed monthly payments to PSALM (see Note 35). The power plant is depreciated over its estimated useful life, as there is reasonable certainty that the Group will obtain ownership by the end of the lease term. As of December 31, 2010 and 2009, the carrying value of the power plant amounted to P=43.43 billion and P=44.52 billion , respectively (see Notes 11 and 35). The carrying value of finance lease obligation amounted to P=48.31 billion and P=45.59 billion as of December 31, 2010 and 2009, respectively (see Note 35). Determining whether the Power Purchase Agreement (PPA) Contains a Lease. The PPA with Visayan Electric Company (VECO) qualifies as a lease on the basis that CPPC sells substantially all its output to VECO. The agreement requires that CPPC guarantee the availability of the power plant. This arrangement is determined to be an operating lease where a significant portion of the risks and rewards of ownership of the asset are retained by CPPC. Accordingly, the power plant assets are recorded as part of the cost of property, plant and equipment and the fixed capacity fees and fixed operating and maintenance fees billed to VECO are recorded as operating revenues on a straight-line basis over the term of the PPA (see Note 20). Accounting for acquisitions of Power Barges (PB) In 2010, the Group took ownership of PB 118 and PB 117. The Group has made a judgment that the transactions represent acquisitions of assets, and accordingly, accounted for the acquisitions in accordance with PAS 16, Property, Plant and Equipment (see Note 11). Classification of financial instruments The Group exercises judgment in classifying a financial instrument, or its component parts, on initial recognition as either a financial asset, a financial liability or an equity instrument in accordance with the substance of the contractual arrangement and the definition of a financial asset, a financial liability or an equity instrument. The substance of a financial instrument, rather than its legal form, governs its classification in the consolidated balance sheet. Estimation Uncertainty The key assumptions concerning the future and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: Acquisition accounting The Group accounts for acquired businesses using the purchase method of accounting which requires that the assets acquired and the liabilities assumed be recorded at the date of acquisition at their respective fair values.

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The application of the purchase method requires certain estimates and assumptions especially concerning the determination of the fair values of acquired intangible assets and property, plant and equipment as well as liabilities assumed at the date of the acquisition. Moreover, the useful lives of the acquired intangible assets, and property, plant and equipment have to be determined. The judgments made in the context of the purchase price allocation can materially impact the Group’s future results of operations. Accordingly, for significant acquisitions, the Group obtains assistance from third party valuation specialists. The valuations are based on information available at the acquisition date (see Note 8). Estimating allowance for impairment losses on investments in and advances to associates Investments in and advances to associates are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. There are no impairment indicators in 2010, 2009 and 2008 based on management’s assessment. The carrying amounts of the investments in and advances to associates amounted to P=28.80 billion and P=24.80 billion as of December 31, 2010 and 2009, respectively. No allowance for impairment losses was recognized in 2010, 2009 and 2008 (see Note 9). Assessing impairment of goodwill The Group determines whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires the Group to make an estimate of the expected future cash flows from the cash-generating unit and also to choose a suitable discount rate in order to calculate the present value of those cash flows. The carrying amount of goodwill as of December 31, 2010 and 2009 amounted to P=996.0 million (see Note 10). No impairment of goodwill was recognized in 2010, 2009 and 2008. Estimating useful lives of property, plant and equipment The Group estimates the useful lives of property, plant and equipment based on the period over which assets are expected to be available for use. The estimated useful lives of property, plant and equipment are reviewed periodically and are updated if expectations differ from previous estimates due to physical wear and tear, technical or commercial obsolescence and legal or other limits on the use of the assets. In addition, the estimation of the useful lives of property, plant and equipment is based on collective assessment of internal technical evaluation and experience with similar assets. It is possible, however, that future results of operations could be materially affected by changes in estimates brought about by changes in the factors and circumstances mentioned above. As of December 31, 2010 and 2009, the net book values of property, plant and equipment amounted to P=74.29 billion and P=72.90 billion, respectively (see Note 11). Estimating residual value of property, plant and equipment The residual value of the Group’s property, plant and equipment is estimated based on the amount that would be obtained from disposal of the asset, after deducting estimated costs of disposal, if the asset is already of the age and in the condition expected at the end of its useful life. Such estimation is based on the prevailing price of property, plant and equipment of similar age and condition. The estimated residual value of each asset is reviewed periodically and updated if expectations differ from previous estimates due to changes in the prevailing price of a property, plant and equipment of similar age and condition. As of December 31, 2010 and 2009, the aggregate net book values of property, plant and equipment amounted to P=74.29 billion and P=72.90 billion, respectively (see Note 11).

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Estimating useful lives of intangible asset - service concession rights The Group estimates the useful lives of intangible asset arising from service concessions based on the period over which the asset is expected to be available for use which is 25 years. The Group has not included any renewal period on the basis of uncertainty, as of balance sheet date, of the probability of securing renewal contracts at the end of the original contract term. As of December 31, 2010 and 2009, the aggregate net book values of intangible asset - service concession rights amounted to P=937.0 million and P=882.3 million, respectively (see Note 12). Assessing impairment of nonfinancial assets The Group assesses whether there are any indicators of impairment for nonfinancial assets at each reporting date. These nonfinancial assets (property, plant and equipment, intangible asset - service concession rights, investment property, and other current and noncurrent assets) are tested for impairment when there are indicators that the carrying amounts may not be recoverable. Determining the recoverable amount of non-financial assets, which requires the determination of future cash flows expected to be generated from the continued use and ultimate disposition of such assets, requires the Group to make estimates and assumptions that can materially affect its consolidated financial statements. Future events could cause the Group to conclude that the property, plant and equipment, intangible asset - service concession rights, investment property, and other current and noncurrent assets are impaired. Any resulting impairment loss could have a material adverse impact on the consolidated balance sheet and consolidated statement of income. As of December 31, 2010 and 2009, the aggregate net book values of these assets amounted to P=77.42 billion and P=75.85 billion, respectively (see Notes 7, 11, 12 and 13). No impairment losses were recognized in 2010, 2009 and 2008. Estimating allowance for impairment of trade and other receivables The Group maintains allowance for impairment of trade and other receivables at a level considered adequate to provide for potential uncollectible receivables. The level of this allowance is evaluated by management on the basis of the factors that affect the collectibility of the accounts. These factors include, but are not limited to, the Group’s relationship with its clients, client’s current credit status and other known market factors. The Group reviews the age and status of receivables and identifies accounts that are to be provided with allowance either individually or collectively. The amount and timing of recorded expenses for any period would differ if the Group made different judgment or utilized different estimates. An increase in the Group’s allowance for impairment of trade and other receivables will increase the Group’s recorded expenses and decrease current assets. As of December 31, 2010 and 2009, allowance for impairment of trade and other receivables amounted to P=376.9 million and P=106.2 million, respectively. Trade and other receivables, net of allowance for impairment, amounted to P=6.81 billion and P=4.48 billion as of December 31, 2010 and 2009, respectively (see Note 5). Estimating allowance for inventory obsolescence The Group estimates the allowance for inventory obsolescence based on the age of inventories. The amounts and timing of recorded expenses for any period would differ if different judgments or different estimates are made. An increase in allowance for inventory obsolescence would increase recorded expenses and decrease current assets. No allowance for inventory obsolescence was recognized in 2010 and 2009. The carrying amount of the inventories amounted to P=1.85 billion and P=1.11 billion as of December 31, 2010 and 2009, respectively (see Note 6). Recognition of deferred income tax assets The Group reviews the carrying amounts of deferred income tax assets at each balance sheet date and reduces deferred income tax assets to the extent that it is no longer probable that sufficient income will be available to allow all or part of the deferred income tax assets to be utilized. The

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Group has net deferred income tax assets amounting to P=199.8 million and P=250.0 million as of December 31, 2010 and 2009, respectively. As of December 31, 2010, no deferred income tax assets were recognized on the Company’s net operating loss carryover (NOLCO) and minimum corporate income tax (MCIT) amounting to P=114.8 million and P=23.8 million, respectively, since management expects that it will not generate sufficient taxable income in the future that will be available to allow all of the deferred income tax assets to be utilized. There were no unrecognized deferred income tax assets as of December 31, 2009 (see Note 28). Pension benefits The determination of the Group’s obligation and cost of pension is dependent on the selection of certain assumptions used by actuaries in calculating such amounts. Those assumptions are described in Note 26, Pension Benefit Plans, and include, among others, discount rates, expected rates of return on plan assets and rates of future salary increase. In accordance with PAS 19, Employee Benefits, actual results that differ from the Group’s assumptions are accumulated and amortized over future periods and therefore, generally affect the Group’s recognized expenses and recorded obligation in such future periods. While management believes that its assumptions are reasonable and appropriate, significant differences in the actual experience or significant changes in the assumptions may materially affect the Group’s pension and other post-employment obligations. Retirement benefit expense amounted to P=68.5 million in 2010 and P=22.2 million in 2008. Retirement benefit income amounted to P=4.8 million in 2009. The Group’s pension liabilities amounted to P=16.0 million and P=28.2 million as of December 31, 2010 and 2009, respectively. Pension assets amounted to P=173.4 million and P=37.2 million as of December 31, 2010 and 2009, respectively (see Note 26). Fair value of financial instruments Where the fair value of financial assets and financial liabilities recorded in the consolidated balance sheet cannot be derived from active markets, their fair value is determined using valuation techniques which includes the discounted cash flow model and other generally accepted market valuation model. The inputs for these models are taken from observable markets where possible, but where this is not feasible, a degree of judgment is required in establishing fair values. The judgments include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in assumptions about these factors could affect the reported fair value of financial instruments. The fair values of the Group’s financial instruments are presented under Note 33. Legal contingencies The estimate of probable costs for the resolution of possible claims has been developed in consultation with outside counsels handling the Group’s defense in these matters and is based upon an analysis of potential results. No provision for probable losses arising from legal contingencies was recognized in the Group’s consolidated financial statements as of December 31, 2010 and 2009.

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4. Cash and Cash Equivalents

2010 2009 Cash on hand and in banks P=3,055,662 P=2,255,660 Short-term investments 15,246,183 1,559,246 P=18,301,845 P=3,814,906

Cash in banks earn interest at floating rates based on daily bank deposit rates. Short-term investments are made for varying periods of between one day and three months depending on the immediate cash requirements of the Group and earn interest at the respective short-term deposit rates. Interest income earned from cash and cash equivalents including restricted cash, classified under “Other noncurrent assets” (see Note 13), amounted to P=149.0 million in 2010, P=348.9 million in 2009, and P=459.0 million in 2008.

5. Trade and Other Receivables

2010 2009 Trade receivables - net of allowance for impairment

of P=376,912 in 2010 and P=106,170 in 2009 (see Note 32) P=5,897,292 P=3,606,224

Others (see Note 31) Accrued revenue 192,194 154,740 Non-trade 139,155 137,978 Advances to various projects 102,180 – Advances to contractors 9,509 151,040 Dividends receivable – 225,002 Others 465,461 201,044 P=6,805,791 P=4,476,028

Trade and non-trade receivables are non-interest bearing and are generally on 10 - 30 days’ term. The rollforward analysis of allowance for impairment of receivables, which pertains to trade receivables of the power distribution segment, is presented below:

2010 2009 January 1 P=106,170 P=8,098 Provisions (see Note 23) 292,065 136,474 Write-off/reversals (21,323) (38,402) December 31 P=376,912 P=106,170

Trade receivables of the power distribution segment that were written off but not covered by an allowance for impairment amounted to nil and P=1.1 million (see Note 23) in 2010 and 2009, respectively. Allowance for impairment as of December 31, 2010 and 2009 pertain to receivables that are individually determined to be impaired at balance sheet date. These relate to debtors that are in significant financial difficulties and have defaulted on payments and accounts under dispute and legal proceedings. These receivables are not secured by any collateral or credit enhancements.

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6. Inventories - at cost

2010 2009 Fuel and lube oil P=1,325,290 P=541,759 Plant spare parts and supplies 349,029 316,745 Transmission and distribution supplies 150,220 179,082 Other parts and supplies 21,048 73,053 P=1,845,587 P=1,110,639

The cost of inventories recognized as part of cost of generated power in the consolidated statements of income amounted to P=11.55 billion in 2010, P=2.65 billion in 2009 and P=1.62 billion in 2008 (see Note 22). The cost of inventories recognized as part of operations and maintenance in the consolidated statements of income amounted to P=619.9 million in 2010, P=222.3 million in 2009 and P=151.4 million in 2008 (see Note 24).

7. Other Current Assets

2010 2009 Input value-added tax (VAT) P=680,139 P=385,889 Prepaid tax 171,218 87,446 Prepaid expenses 46,522 5,104 Prepaid rent (see Note 35) 27,581 25,800 Others 33,893 8,445 P=959,353 P=512,684

8. Business Combinations

a. Acquisition of the 747 Megawatt (MW) Tiwi-MakBan Geothermal Power Plant

(“Tiwi-MakBan Power Plant”)

In August 2008, PSALM issued the Notice of Award and Certificate of Effectivity to APRI officially declaring it as the winning bidder for the 289MW Tiwi MakBan Power Plant located in Tiwi, Albay and the 458 MW Makiling-Banahaw (MakBan) Geothermal Plant located in Laguna and Batangas Provinces.

On May 25, 2009, following the completion of the conditions precedent and the execution of

the respective Certificates of Closing, the control and possession of the purchased assets were successfully turned over and transferred by PSALM to APRI. APRI started the commercial operations of the Tiwi-MakBan Power Plant on May 26, 2009. APRI accounted for the purchase of the Tiwi-MakBan Power Plant as acquisition of a business using purchase method.

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The provisional fair value of the identifiable assets of the Tiwi-MakBan Power Plant as of the date of acquisition follows:

Property, plant and equipment (see Note 11) Steam field assets P=11,910,223 Machinery and equipment 6,106,985 Electrical equipment 1,290,397 Other land improvements 150,779 Buildings 509,858 Inventories 237,774 Deferred income tax liability (7,242) Total consideration P=20,198,774

No complete comparable information is available with respect to the carrying amounts of each of the assets acquired in the books of PSALM immediately before the acquisition. The accounting for the business combination that was effected in 2009 was determined provisionally as APRI had incomplete information as of report date with respect to possible recognition of intangible assets and deferred income tax assets arising from the acquisition. In 2010, the accounting for the business combination was finalized and no changes were made on the purchase price allocation that was provisionally computed. Included in the APA is the transfer of bilateral power supply contract quantities (BCQs) to APRI from NPC (see Note 20). These BCQs were initially identified as potential source of intangible assets, however, there is no history or evidence of exchange transactions for the same or similar assets, and otherwise estimating fair value would be dependent on immeasurable variables. The management provisionally did not recognize the intangible assets from the BCQs as it is not possible to measure reliably the fair value of the intangible assets. The total cost of the business combination was P=20.20 billion, consisting of the purchase price of P=19.90 billion and costs directly attributable to the acquisition of P=298.5 million. The APA originally required APRI to deliver at least 40% of the US$435.4 million purchase price as upfront payment payable on or before the closing date. The balance of 60%, comprising the deferred payments, will be paid in 14 equal semi-annual payments with an interest of 12% per annum compounded semi-annually. On closing date, APRI paid PSALM P=8.29 billion representing the 40% upfront payment. The payment of the 60% balance of P=11.61 billion was accelerated on September 30, 2009 using proceeds from advances from ARI. APRI paid interest amounting to P=514.1 million covering the period May 26 to September 30, 2009. No segment of the Tiwi-MakBan Power Plant operation has been disposed as a result of the acquisition. From the date of acquisition up to December 31, 2009, the Tiwi-MakBan Power Plant has contributed P=2.07 billion to the net income of the Group.

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b. Significant Acquisition by an Associate Acquisition of the 175 MW Ambuklao-Binga Hydroelectric Power Plant Complex (Ambuklao-Binga HEPPC) On November 28, 2007, SN Aboitiz Power-Benguet, Inc., (SNAP B), associate of Manila-Oslo Renewable Enterprise, Inc. (MORE), won the auction for the Ambuklao-Binga HEPPC with a bid of US$325.0 million. On July 10, 2008, PSALM turned over the possession and control of the Ambuklao-Binga HEPPC to SNAP B, following payment by SNAP B of 70% of the purchase price to PSALM. SNAP B started the commercial operations of the Binga Power Plant on July 11, 2008. The Ambuklao Power Plant is currently undergoing rehabilitation. SNAP B accounted for the purchase of the Ambuklao-Binga HEPPC under the purchase method. In 2008, the amount of the power plants’ net income since acquisition date that is included in the Group’s consolidated net income through share in net earnings in associates is P=22.0 million.

9. Investments in and Advances to Associates

2010 2009 Acquisition cost:

Balance at beginning of the year P=18,914,669 P=16,387,915 Additions during the year 1,031,232 2,526,754 Disposals during the year (796,949) – Balance at end of year 19,148,952 18,914,669

Accumulated equity in net earnings: Balance at beginning of the year 4,966,140 3,263,941 Share in net earnings 4,625,883 2,535,386 Effect of redemption of preferred shares by an associate (353,662) – Cash dividends (1,593,357) (833,187) Balance at end of year 7,645,004 4,966,140

26,793,956 23,880,809 Share in cumulative translation adjustments of associates 57,922 115,246 Share in unrealized valuation gain on AFS investment of an

associate 78,118 – Investments in associates at equity 26,929,996 23,996,055 Advances to associates - net 1,869,374 804,246 P=28,799,370 P=24,800,301

In 2010, additional P=1.03 billion was invested in MORE to support SNAP B’s plant rehabilitation and refurbishment. In 2009, the Group contributed P=2.38 billion as additional investment in Cebu Energy Development Corporation (CEDC).

Following the approval by SEC of the amendments on East Asia Utilities Corporation’s (EAUC) Articles of Incorporation on September 27, 2010, EAUC effected the conversion of its outstanding 90 million common shares to 900,000 Series A redeemable preferred shares (RPS). Fifty percent (50%) of the shares converted or 45 million shares is attributable to the Company. In October 2010, EAUC redeemed 392,210 Series A RPS attributable to the Company.

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The Group’s associates and the corresponding equity ownership are as follows:

Percentage of Ownership Nature of Business 2010 2009 2008

MORE Holding company 83.33 83.33 83.33

VECO Power distribution 55.19 55.18 55.11

LHC Power generation 50.00 50.00 50.00

EAUC Power generation 50.00 50.00 50.00

Bakun Power Line Corporation* Energy related service provider

50.00 50.00 50.00

Redondo Peninsula Energy, Inc. (RP Energy)* Power generation 50.00 50.00 50.00

SN Aboitiz Power-Magat, Inc. (SNAP M) Power generation 50.00 50.00 50.00

SNAP B Power generation 50.00 50.00 50.00

Hijos de F. Escaño, Inc. (HIJOS) Holding company 46.73 46.73 46.66

San Fernando Electric Light & Power Co., Inc. (SFELAPCO)

Power distribution 43.78 43.78 43.78

Pampanga Energy Ventures, Inc. (PEVI) Holding company 42.84 42.84 42.84

Cordillera Hydro Corporation* Power generation 35.00 35.00 35.00

STEAG Power generation 34.00 34.00 34.00

CEDC* Power generation 26.40 26.40 26.40

SPPC Power generation 20.00 20.00 20.00

WMPC Power generation 20.00 20.00 20.00 *No commercial operations as of December 31, 2010.

All ownership percentages presented in the table above are direct ownership of the Group except for the following: • SNAP M and SNAP B - MORE has direct ownership in SNAP M and SNAP B of 60% each

while the Group’s direct ownership in MORE is 83% resulting to the Group’s effective ownership in SNAP M and SNAP B of 50%.

• VECO - HIJOS has direct ownership in VECO of 25.15% in 2010, 2009 and 2008 while the Group’s direct ownership in VECO is 43.44% in 2010, 43.43% in 2009 and 43.37% in 2008 resulting to the Group’s effective ownership in VECO of 55.19% in 2010, 55.18% in 2009 and 55.11% in 2008.

• SFELAPCO - PEVI has direct ownership in SFELAPCO of 54.83% while the Group’s direct ownership in SFELAPCO is 20.29% resulting to the Group’s effective ownership in SFELAPCO of 43.78%.

The Group does not consolidate MORE because of absence of control resulting from the shareholders’ agreement, which among others stipulate the management and operation of MORE. Management of MORE is vested in its BOD and the affirmative vote of the other shareholder is required for the approval of certain corporate actions which include financial and operating undertakings. The Group also does not consolidate VECO as the other shareholders’ group have the control over the financial and operating policies of VECO.

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The carrying values of investments in associates, which are accounted for under the equity method follows:

2010 2009 MORE P=13,336,441 P=10,109,764 STEAG 6,445,009 5,909,444 CEDC 2,396,218 2,417,898 LHC 1,181,164 1,232,222 VECO 1,090,460 962,627 HIJOS 905,828 871,571 WMPC 465,002 421,960 EAUC 335,563 1,375,712 PEVI 285,292 226,106 SPPC 230,453 251,256 SFELAPCO 228,626 177,491 Others 29,940 40,004 P=26,929,996 P=23,996,055

Following is the summarized financial information of significant associates:

2010 2009 2008 MORE Total current assets P=234,714 P=278,313 P=125,849 Total noncurrent assets 16,013,675 12,037,113 10,685,237 Total current liabilities 241,362 276,057 238,040 Total noncurrent liabilities 3,298 490 253 Gross revenue 4,084,202 1,270,474 832,142 Operating profit 3,836,899 1,096,944 723,172 Depreciation and amortization 10,007 9,571 7,033 Interest income - net 377 325 220 Income tax - net 13,373 1,941 – Net income 3,911,204 1,102,475 716,448 LHC Total current assets P=382,808 P=332,448 P=364,594 Total noncurrent assets 3,965,135 4,496,366 4,954,809 Total current liabilities 1,468,097 1,593,142 456,638 Total noncurrent liabilities 517,517 771,228 2,218,420 Gross revenue 934,710 1,223,189 1,088,083 Operating profit 581,919 749,635 682,124 Depreciation and amortization 264,349 280,022 262,123 Interest expense - net 66,992 123,999 147,113 Income tax expense (benefit) - net 85,973 158,373 (97,876) Net income 339,521 467,264 1,080,494 VECO* Total current assets P=3,251,473 P=1,424,236 P=1,602,279 Total noncurrent assets 7,878,006 7,532,706 6,775,561 Total current liabilities 2,513,044 1,902,036 1,340,521 Total noncurrent liabilities 3,939,339 2,546,256 2,434,584 Gross revenue 13,405,730 10,830,879 9,899,115 Operating profit 609,522 140,657 396,922 Depreciation and amortization 424,777 433,387 370,382 Interest expense - net 29,945 15,101 42,886 Income tax - net 253,158 124,936 269,690 Net income 609,526 315,082 509,527

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2010 2009 2008 WMPC Total current assets P=1,031,813 P=718,455 P=819,909 Total noncurrent assets 1,584,896 1,792,574 2,043,482 Total current liabilities 148,542 192,535 277,785 Total noncurrent liabilities 143,422 181,783 357,740 Gross revenue 1,324,460 1,206,970 1,283,784 Operating profit 769,956 558,505 670,579 Depreciation and amortization 309,802 468,476 441,171 Interest income (expense) - net (6,597) 3,260 (13,382) Income tax - net 201,779 55,171 318,255 Net income 851,962 548,359 415,925 SPPC Total current assets P=580,253 P=491,448 P=321,885 Total noncurrent assets 999,546 1,305,583 1,614,027 Total current liabilities 120,986 105,383 147,627 Total noncurrent liabilities 302,659 427,259 160,496 Gross revenue 709,774 687,843 691,420 Operating profit 244,499 229,501 241,364 Depreciation and amortization 284,503 302,145 277,586 Interest income (expense) - net 9,865 (9,323) (9,992) Income tax - net 45,226 46,312 139,646 Net income 227,719 248,749 128,069 SFELAPCO * Total current assets P=669,949 P=454,647 P=360,099 Total noncurrent assets 1,103,853 1,064,917 1,109,581 Total current liabilities 466,986 406,246 346,871 Total noncurrent liabilities 334,181 349,027 350,541 Gross revenue 3,048,028 2,564,866 2,327,357 Operating profit 121,876 43,169 74,617 Depreciation and amortization 144,784 141,855 113,350 Interest income - net 1,574 1,175 2,047 Income tax - net 30,710 11,932 31,739 Net income 267,483 72,024 33,472 STEAG Total current assets P=5,624,376 P=8,029,261 P=7,081,353 Total noncurrent assets 11,129,719 10,924,231 12,129,785 Total current liabilities 1,659,345 2,307,605 3,189,506 Total noncurrent liabilities 3,348,866 6,880,704 8,573,835 Gross revenue 6,507,354 6,205,924 6,265,242 Operating profit 3,131,010 3,118,338 3,850,860 Depreciation and amortization 70,881 79,064 85,511 Interest expense - net 366,944 473,298 667,937 Income tax - net 108,887 154,223 90,705 Net income 1,754,369 2,602,400 3,216,793 EAUC Total current assets P=552,025 P=697,187 P=428,112 Total noncurrent assets 1,002,340 3,122,061 3,128,757 Total current liabilities 166,788 255,217 282,265 Total noncurrent liabilities 10,861 9,565 8,160 Gross revenue 1,741,244 1,381,633 1,579,424 Operating profit 283,349 186,597 106,568 Depreciation and amortization 118,857 120,619 120,055 Interest income (expense) - net (727) 5,005 10,597 Income tax - net 16,337 11,570 9,244 Net income 252,754 286,577 126,927

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*Amounts are based on appraised values which are adjusted to historical amounts upon equity take-up of the Group. Using cost method in accounting for property, plant and equipment, depreciation and amortization amounted to P=245.7 million, P=216.9 million and P=290.7 million in 2010, 2009, and 2008, respectively, for VECO; and P=72.0 million, P=73.9 million, P=62.7 million and P=57.7 million in 2010, 2009 and 2008, respectively, for SFELAPCO. Under the same method, net income amounted toP=734.9 million, P=467.8 million, and P=565.3 million in 2010, 2009 and 2008, respectively, for VECO; and P=132.7 million, P=119.6 million and P=66.4 million in 2010, 2009 and 2008, respectively, for SFELAPCO.

10. Impairment Testing of Goodwill Goodwill acquired through business combinations have been attributed to individual cash-generating units. The carrying amount of goodwill follows:

2010 2009 MEZ P=538,373 P=538,373 BEZ 237,404 237,404 HI 220,228 220,228 P=996,005 P=996,005

The recoverable amounts of the investments have been determined based on a value-in-use calculation using cash flow projections based on financial budgets approved by senior management covering a five-year period. Key assumptions used in value-in-use calculation for December 31, 2010 and 2009 The following describes each key assumption on which management has based its cash flow projections to undertake impairment testing of goodwill. Discount rates and growth rates The discount rates applied to cash flow projections are from 8.22% to 8.39% in 2010 and from 9.58% to 11.70% in 2009, and cash flows beyond the five-year period are extrapolated using a zero percent growth rate. Revenue assumptions Revenue assumptions are based on the expected electricity to be generated and sold. In 2010, revenue growth of 5% for four years and 6% in year 5 was applied to MEZ; 5% for BEZ; and 15% in year 1, 3% in year 2, 2% for years 3 and 4 and 4% in year 5 for HI. In 2009, revenue growth of 17% in year 1, 11% in year 2 and 2% from years 3 to 5 was applied to MEZ; 8% in year 1, 10% in year 2, 9% in year 3, no growth in year 4 and 4% in year 5 for BEZ; and -6% in year 1, -2% in year 2 and no growth in years 3 to 5 for HI. Materials price inflation The assumption used to determine the value assigned to the materials price inflation is 4.4% in 2011, which then increases by 20 and 40 basis points on the second and third year, respectively. It then remains steady at 5% until the fifth year. The starting point of 2011 is consistent with external information sources.

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Based on the impairment testing, no impairment was recognized on goodwill in 2010 and 2009. With regard to the assessment of value-in-use of MEZ, BEZ and HI, management believes that no reasonably possible change in any of the above key assumptions would cause the carrying value of the goodwill to materially exceed its recoverable amount.

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11. Property, Plant and Equipment As of December 31, 2010

Land

Buildings, warehouses and

improvements

Power plant equipment

and steam field assets

Transmission, distribution and

substation equipment

Transportation equipment

Office furniture, fixtures and

equipment Leasehold

improvements Electrical

equipment

Meters and laboratory equipment

Tools and others

Construction in progress Total

COST Beginning Balance P=125,774 P=898,699 P=66,628,765 P=4,553,427 P=386,970 P=111,304 P=183,302 P=1,651,908 P=358,801 P=326,462 P=4,633,416 P=79,858,828 Additions 7 5,485 1,498,217 296,882 82,421 56,049 21,261 14,855 25,314 53,941 2,295,838 4,350,270 Disposals – (2,214) (37,280) (99) (9,645) (8,167) – (24,152) – (1,763) (4,619) (87,939) Reclassifications and others (11,445) 49,311 5,280,435 148,693 – 765 – – (350) (3,207) (5,371,763) 92,439 Ending Balance 114,336 951,281 73,370,137 4,998,903 459,746 159,951 204,563 1,642,611 383,765 375,433 1,552,872 84,213,598

ACCUMULATED DEPRECIATION AND AMORTIZATION Beginning Balance – 91,389 3,289,899 2,327,647 261,304 86,375 128,383 324,916 246,432 201,454 – 6,957,799 Additions – 19,099 2,480,905 194,431 49,241 37,598 16,965 105,160 12,794 38,087 – 2,954,280 Disposals – (2,033) (36,068) (789) (8,478) (4,577) – (23,922) – (1,689) – (77,556) Reclassifications and others

– 7,595 56,744 2,644 (2,710) 28,539 (2,544) – 19 (2,976)

– 87,311

Ending Balance – 116,050 5,791,480 2,523,933 299,357 147,935 142,804 406,154 259,245 234,876 – 9,921,834 NET BOOK VALUE P=114,336 P=835,231 P=67,578,657 P=2,474,970 P=160,389 P=12,016 P=61,759 P=1,236,457 P=124,520 P=140,557 P=1,552,872 P=74,291,764

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As of December 31, 2009

Land

Buildings, warehouses and

improvements

Power plant equipment

and steam field assets

Transmission, distribution and

substation equipment

Transportation equipment

Office furniture, fixtures and

equipment Leasehold

improvements Electrical

equipment

Meters and laboratory equipment

Tools and others

Construction in progress Total

COST Beginning Balance P=100,148 P=174,066 P=3,426,377 P=4,248,386 P=303,994 P=426,067 P=122,668 P=54,160 P=291,449 P=196,297 P=2,578,376 P=11,921,988 Acquisitions through a

business combination (Note 8) – 660,637 18,017,208 – – – 1,290,397 – – – 19,968,242

Additions 22,068 38,698 45,300,656 298,639 80,072 17,546 25,847 18,141 28,090 54,430 2,184,161 48,068,348 Disposals – – (48,231) (5,004) (16,376) (1,490) – (536) – (3,718) – (75,355) Reclassifications and others 3,558 25,298 (67,245) 11,406 19,280 (330,819) 34,787 289,746 39,262 79,453 (129,121) (24,395) Ending Balance 125,774 898,699 66,628,765 4,553,427 386,970 111,304 183,302 1,651,908 358,801 326,462 4,633,416 79,858,828

ACCUMULATED DEPRECIATION AND AMORTIZATION Beginning Balance – 76,198 2,364,240 2,135,880 217,539 388,623 111,585 33,415 209,760 127,105 – 5,664,345 Additions – 15,519 987,191 190,394 41,694 11,117 8,976 71,383 16,946 26,273 – 1,369,493 Disposals – – (39,313) (418) (14,105) (1,327) – (339) – (3,738) – (59,240) Reclassifications and others – (328) (22,219) 1,791 16,176 (312,038) 7,822 220,457 19,726 51,814 – (16,799) Ending Balance – 91,389 3,289,899 2,327,647 261,304 86,375 128,383 324,916 246,432 201,454 – 6,957,799 NET BOOK VALUE P=125,774 P=807,310 P=63,338,866 P=2,225,780 P=125,666 P=24,929 P=54,919 P=1,326,992 P=112,369 P=125,008 P=4,633,416 P=72,901,029

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Acquisition of PB 118 and PB 117 On July 31, 2009, Therma Marine and Therma Mobile, subsidiaries, won the negotiated bid with the Power Sector Assets and Liabilities Management Corporation (PSALM) for the barge-mounted diesel-powered generation plants, the 100 MW PB 118 and 100 MW PB 117, with bid prices of US$14 million (P=651.23 million) and US$16 million (P=739.47 million), respectively. PB 118 is moored in Barangay San Roque, Maco, Compostela Valley in Mindanao. PB 117 is moored in Barangay Sta. Ana, Nasipit, Agusan Del Norte. Under the terms of the APA, Therma Marine and Therma Mobile is required to deliver at least 40% of the purchase price upon closing of the acquisition. The remaining 60% is payable over a period not to exceed seven years. On February 5, 2010 and February 26, 2010, Therma Marine fully paid PSALM the total bid prices of PB118 and PB117, respectively. On February 16, 2010, Therma Marine entered into an Assignment Agreement with Therma Mobile. Under the agreement, Therma Mobile transferred all of its rights and obligations under the APA as buyer of PB 117. Therma Marine has become, for all intents and purposes, the buyer of PB 117. The control and possession of PB 118 and PB 117 were successfully turned-over and transferred to Therma Marine on February 6, 2010 and March 1, 2010, respectively. Therma Marine started the commercial operations of the power barges on the turn-over dates. The Group accounted for the acquisitions as purchases of assets in accordance with PAS 16. Specific borrowing costs capitalized as part of construction in progress amounted to P=151.9 million and P=227.3 million in 2010 and 2009, respectively (see Note 16). The rate used to determine the amount of borrowing costs eligible for capitalization was 8.52%, which is the effective interest rate for the related specific borrowings in 2010 and 2009. The reclassifications made in 2010 and 2009 pertain mostly to completed projects of the Group. Property, plant and equipment with carrying amounts of P=5.59 billion and P=4.94 billion as of December 31, 2010 and 2009, respectively, are used to secure the Group’s long-term debts (see Note 16). Fully depreciated transmission and distribution equipment and distribution transformers and substation equipment with gross carrying amount of P=2.46 billion and P=1.36 billion as of December 31, 2010 and 2009 are still in use. Fully depreciated power generation property, plant and equipment with gross carrying amount of P=147.6 million and P=121.1 million as of December 31, 2010 and 2009 are still in use.

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12. Intangible Asset - Service Concession Rights

2010 2009 Cost:

At January 1 P=1,045,054 P=973,532 Additions 104,385 71,522

1,149,439 1,045,054 Accumulated amortization:

At January 1 162,746 119,339 Amortization 49,697 43,407

212,443 162,746 P=936,996 P=882,308

Service concession arrangements entered into by the Group are as follows: a. On May 15, 2003, the SBMA, AEV and DLP entered into a DMSA for the privatization of the

SBMA Power Distribution System (PDS) on a rehabilitate-operate-and-transfer arrangement; and to develop, construct, lease, lease out, operate and maintain property, structures, and machineries in the Subic Bay Freeport Zone (SBFZ).

Under the terms of the DMSA, SEZ was created to undertake the rehabilitation, operation and maintenance of the PDS (the Project), including the provision of electric power service to the customers within the Subic Bay Freeport Secured Areas of the SBFZ as well as the collection of the relevant fees from them for its services and the payment by SBMA of the service fees throughout the service period pursuant to the terms of the DMSA. In compliance with the terms of the DMSA, the SBMA shall turn over to SEZ full possession of the Project and any and all improvements, spare parts, inventories, vehicles, works and structures constructed, improved and introduced by the SBMA in the Project and land, roads and any land rights of any description including, without any limitations, easements, access, rights-of-way, leases, licenses and covenants belonging to the SBMA or otherwise appertaining to the Project, or to be acquired by or granted to SEZ by the SBMA or any relevant Governmental Instrumentalities for purposes of implementing the Project on, through, above or below the ground on which any part of the Project is located, maintained and managed, including, without limitation to, arrangements for the disposal of waste materials. The SBMA shall also turnover all records, files and/or contracts pertinent to the PDS. The SBMA shall remain the owner of the Project including all its assets and improvements. The DMSA shall be effective for a 25-year period commencing on the turnover date and consisting of two phases: (a) the 5-year rehabilitation period and (b) the 20-year operation, management and maintenance period. Total estimated rehabilitation costs committed by SEZ under the DMSA amounted to P=368.6 million. SEZ is subject to the rate making regulations and regulatory policies of the Energy Regulatory Commission. The DMSA provides that there will be no change in the basic power supply and power distribution rates for the first 5 years from the turnover date. For and in consideration of the services and expenditures of SEZ for it to undertake the rehabilitation, operation, management and maintenance of the Project, it shall be paid by the SBMA the service fees in such amount equivalent to all the earnings of the Project, provided, however, that SEZ shall remit the amount of P=40.0 million to the SBMA at the start of every 12-month period throughout the service period regardless of the total amount of all earnings of the Project. The said remittance may be reduced by the outstanding power receivables from the SBMA,

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including streetlights power consumption and maintenance, for the immediately preceding year. Since SBMA controls ownership of the equipment at the end of the agreement, the PDS are treated as intangible assets and are amortized over a period of 25 years up to year 2028, in accordance with Philippine Interpretation IFRIC 12.

Management believes that, based on the assessment performed, the intangible asset - service concession rights are not impaired. Specific borrowing costs amounting to P=19.1 million and P=22.6 million that were directly attributable to the rehabilitation of the PDS were capitalized in 2010 and 2009, respectively. The rates used to determine the amount of borrowing costs eligible for capitalization ranged from 8.26% to 10.02%, representing the effective interest rates for the related specific borrowings in 2010 and 2009.

b. AboitizLand, Inc. (ALI), the Developer-Operator of Mactan Export Processing Zone II

(MEPZ II), entered into a BOT agreement with MCIAA. Under the terms of the agreement, MCIAA will provide the land, while ALI will undertake the development of MEPZ II. The project has a term of 25 years, with an option to extend the lease for another 25 years. Under the agreement, ownership of permanent structures within MEPZ II will be transferred to MCIAA after termination of the agreement.

On February 20, 2007, MEZ signed a Deed of Assignment with ALI wherein ALI transferred its power distribution assets with a net book value of P=68.66 billion in exchange for 6.25 billion shares of the Company.

MEZ entered into a Tripartite Memorandum of Agreement with National Power Corporation (NPC) and ALI, wherein ALI assigned its rights, title and interests in the power supply contract with NPC to the Company. Under the agreement, ALI assigns to MEZ all its rights and obligations under the Supply of Electric Energy it entered into with NPC, which will expire on September 25, 2015.

The transmission and distribution equipment of MEZ are located within MEPZ II. Since MCIAA controls ownership of the equipment at the end of the agreement, the equipment are treated as intangible assets and are amortized over a period of 21 years up to year 2028, in accordance with Philippine Interpretation IFRIC 12.

13. Other Noncurrent Assets

2010 2009 Input VAT and tax credit receivable P=629,860 P=433,486 Prepaid rent - net of current portion (see Note 35) 522,817 532,830 Intangible assets:

Project development costs 41,394 – Software and licenses 22,400 1,153

Restricted cash – 560,423 Others 9,012 17,140 P=1,225,483 P=1,545,032

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Restricted cash Cash equivalents, presented as “Restricted cash”, pertains to a US$12.2 million amount held to secure a long-term loan of an associate that matured in 2010. The related long-term loan was fully paid in 2010. Accordingly, the restricted cash was reclassified to “Cash and cash equivalents”. Interest income from these cash equivalents is reported as part of interest income in the consolidated statements of income (see Note 4). Intangible assets Rollforward of intangible assets follow:

2010 2009

Project development

costs Software

and licenses

Project development

costs

Software and

licenses Balance at beginning of year P=– P=1,153 P=– P=– Additions 75,154 21,247 – 1,153 Transfers (see Note 11) (33,040) – – – Write-off (720) – – – Balance at end of year P=41,394 P=22,400 P=– P=1,153

14. Trade and Other Payables

2010 2009 Trade payables (see Note 21) P=2,063,082 P=1,765,531 Output VAT 1,609,331 357,332 Amounts due to contractors and other third parties 1,485,755 1,457,340 Accrued energy fees and fuel purchase 486,644 – Accrued taxes and fees 424,043 312,609 Accrued interest 220,048 202,742 Related parties - nontrade (see Note 31) 129,999 1,145,253 Unearned revenues 42,423 38,612 Accrued insurance 37,026 32,508 Others (see Note 31) 455,479 710,610 P=6,953,830 P=6,022,537

Trade payables are non-interest bearing and generally on 30-day terms. Accrued taxes and fees represent accrual of real property tax, transfer tax and other fees. Other liabilities include withholding taxes, other amounts owed to related parties, other non-trade payables and other accrued expenses.

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15. Bank Loans

Interest Rate 2010 2009 Peso loans - financial institutions - unsecured Company 2.24% in 2010;

5.10% to 5.50% in 2009 P=1,290,000 P=1,059,500

DLP

3.50% in 2010; 5.10% to 8.75% in 2009

250,000 794,100

CLP 3.50% in 2010; 5.10% to 5.75% in 2009

220,000 184,300

SEZ 3.50% to 3.75% in 2010 196,600 – HI 3.50% in 2010 23,200 – BEZ 5.10% to 5.75% in 2009 – 40,000 AESI 5.38% to 6.75% in 2009 – 8,000 1,979,800 2,085,900 Dollar loans - financial institutions - unsecured Company 5.10% to 5.75% in 2009 – 3,742,200 P=1,979,800 P=5,828,100

Bank loans represent unsecured interest-bearing short-term loans obtained from various local banks to meet the Group’s working capital requirements. They are covered by the respective borrower entities’ existing credit lines with the banks and are not subject to any significant covenants and warranties. The Company’s outstanding peso loans as of December 31, 2010 were fully paid on January 3, 2011, while the US dollar loan was fully paid in April 2010. Interest expense on bank loans amounted to P=145.1 million in 2010, P=236.9 million in 2009 and P=234.0 million in 2008 (see Note 32).

16. Long-term Debts

Interest Rate 2010 2009 Company

Financial and non-financial institutions - unsecured 2008 5-year corporate note 8.78% P=3,330,000 P=3,330,000 2008 7-year corporate note 9.33% 548,800 554,400

2009 5-year corporate note 8.23% 5,000,000 5,000,000 Retail bonds - unsecured

3-year bonds 8.00% 705,580 705,580 5-year bonds 8.70% 2,294,420 2,294,420

HSI Financial institutions - secured 8.52% 3,570,000 3,570,000

CPPC Financial institutions - unsecured 6.68% to 6.71% 640,000 –

HI Financial institution - secured 8.36% 549,100 613,700 SEZ Financial institution - secured 8.26% in 2010;

8.26% to 10.02% in 2009

119,090 331,454

BEZ Financial institution - unsecured 7.50% 70,000 – 16,826,990 16,399,554 Less deferred financing costs 123,877 147,019 16,703,113 16,252,535 Less current portion - net of deferred financing costs 555,495 101,200 P=16,147,618 P=16,151,335

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Company Retail Bonds On April 30, 2009, the Company registered and issued unsecured bonds worth P=3.00 billion with three-year and five-year terms. The proceeds were used to partially finance APRI’s acquisition of the Tiwi-MakBan Geothermal Power Plant. As provided in the Underwriting Agreement, the three-year bonds bear interest on its principal amount from and including issue date at 8.0% per annum. The five-year bonds bear interest on its principal amount from and including issue date at 8.7% per annum. The bonds have been rated PRS AAA by the Philippine Rating Services Corporation. The rating is subject to regular annual reviews, or more frequently as market developments may dictate, for as long as the bonds are outstanding. Prior to the maturity date, the Company may redeem in whole the relevant outstanding bonds on the 12th interest payment date. The amount payable in respect of such early redemption shall be the accrued interest on the principal amount, the principal amount and a prepayment penalty of 2.0% on the outstanding principal amount. Unless previously redeemed, the principal amount of the bonds shall be payable on a lump sum basis on the respective maturity date at its face value. Under the bond trust agreement, the Company shall not permit its Debt-to-Equity (DE) ratio to exceed 2:1 calculated based on the Company’s year-end audited parent company financial statements. For the purposes of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of corporate guarantees in favour of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009. Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=24.4 million in 2010 and P=32.1 million in 2009. 2009 Fixed Rate Corporate Notes On September 28, 2009 (issue date), the Company availed a total of P=5.00 billion from the Notes Facility Agreement it signed on September 18, 2009, with First Metro Investment Corporation as Issue Manager, the proceeds of which were used by the Company to finance its investments in various projects including capital expenditures and acquisitions. The Notes Facility Agreement provided for the issuance of 5-year corporate notes in a private placement to not more than 19 institutional investors pursuant to Section 9.2 of the Securities Regulation Code (SRC) and Rule 9.2(2) (B) of the SRC Rules. Prior to the maturity date, the Company may redeem in whole the relevant outstanding notes on the 12th interest payment date. The amount payable in respect of such early redemption shall be the accrued interest on the principal amount, the principal amount and a prepayment penalty of 2.0% on the outstanding principal amount. Unless previously redeemed, the notes shall be redeemable on a lump sum basis on the respective maturity date at its face value. Under the Notes Facility Agreement, the Company shall not permit its DE ratio to exceed 2:1 calculated based on the Company’s year-end audited parent company financial statements. For the purposes of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of

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corporate guarantees in favour of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009. Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=39.2 million in 2010 and P=47.7 million in 2009. 2008 Fixed Rate Corporate Notes

On December 18, 2008 (issue date), the Company availed a total of P=3.89 billion from the Notes Facility Agreement it signed on December 15, 2008, with Banco De Oro (BDO) Capital and Investment Corporation, Bank of the Philippine Islands Capital Corporation, First Metro Investment Corporation and ING Bank N.V. - Manila Branch as Joint Lead Managers, the proceeds of which were used by the Company to finance its acquisitions as well as for other general corporate purposes. The Notes Facility Agreement provided for the issuance of 5-year and 7-year corporate notes in a private placement to not more than 19 institutional investors pursuant to Section 9.2 of the SRC and Rule 9.2(2) (B) of the SRC Rules. Prior to the maturity date, the Company may redeem in whole the relevant outstanding notes on the 12th interest payment date for the 5-year note and on the 16th interest payment date for the 7-year note. The amount payable in respect of such early redemption shall be the accrued interest on the outstanding principal amount, the outstanding principal amount and a prepayment penalty of 2.0% of the outstanding principal amount. Unless previously redeemed, the notes shall be redeemable on a lump sum basis on the respective maturity dates at their face values. Under the Notes Facility Agreement, the Company shall not permit its DE ratio to exceed 2:1 calculated based on the Company’s year-end parent company audited financial statements. For the purposes of determining compliance with the required ratio, the outstanding preferred shares and contingent liabilities of the Company, including but not limited to the liabilities in the form of corporate guarantees in favour of any person or entity shall be included in the computation of debts. The Company is in compliance with the debt covenant as of December 31, 2010 and 2009. Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=32.5 million in 2010 and P=41.0 million in 2009. HSI On May 21, 2008, HSI and ARI entered into an agreement with local banks for a loan facility in the aggregate principal amount of up to P=3.57 billion to partially finance the design, development, procurement, construction, operation and maintenance of the 42.5 MW Sibulan hydro-electric power plant. Repayment terms of the loan are as follows: • 70% of the principal amount of the loan is payable in semi-annual installments within 12 years

commencing on the 30th month from September 1, 2008. • A balloon payment equivalent to 30% of the loan principal on the final principal amortization

date.

HSI has the option to prepay the loan at par without premium or penalty beginning on the fourth year from the initial advance.

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Interest on the loan for the first five years is fixed at 8.52%. For the remaining seven-year period interest rate will be fixed at the prevailing seven-year PDST- F interest rate for the day immediately preceding the fixed interest setting date plus 1.125%. Under the loan agreements, HSI is required to maintain Debt Service Coverage Ratio (DSCR) of at least 1.1x, at all times, until fulfillment payment of the obligations and a DSCR of at least 1.2x for the release of funds from the Project Accounts. Other loan covenants include, among others, the establishment and maintenance of certain project accounts depositories under the control of appointed trustees of the lenders and submission of certain reports. HSI is in compliance with the loan covenants as of December 31, 2010 and 2009. The loan is secured by real estate and chattel mortgages on real assets and all machineries, equipment and other properties, actually located at the project site or plant site used in the project with carrying value of P=5.20 billion and P=4.28 billion as of December 31, 2010 and 2009, respectively. Interest on the loan capitalized as construction in progress amounted to P=151.9 million in 2010 and P=227.3 million in 2009 (see Note 11). Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=23.7 million in 2010 and P=25.6 million in 2009. CPPC On January 27, 2010, CPPC availed a total of P=800.0 million from the Notes Facility Agreement with SB Capital Investment Corporation (P=400.0 million) and BDO Capital and Investment Corporation (P=400.0 million), the proceeds of which were used by CPPC to finance advances made to stockholders. The Notes Facility Agreement provided for the issuance of 3-year notes which bear interest rate at the PDST-F rate for three months plus a 2.25% spread. The notes are to be paid in 15 principal payments amounting to P=53.3 million each quarter starting May 2, 2010. In accordance with the notes facility agreement, CPPC’s DE ratio shall not exceed 3:1, provided that upon redemption of redeemable preferred shares, DE ratio shall not exceed 5:1. As of December 31, 2010, CPPC’s debt-to-equity ratio is at 2:1. CPPC is in compliance with the debt covenant as of December 31, 2010. Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=3.6 million in 2010. HI The loan availed by HI from BDO is a five-year loan of which P=450.0 million is payable at P=1.0 million per year starting 2006 with the remaining balance fully payable on January 28, 2010, and P=200.0 million is subject to a balloon payment on October 20, 2010. It bears interest at 2 1/4 % over the applicable three-month treasury securities as displayed on MART 1 page of Bloomberg of the rate setting day plus gross receipts tax, reviewable and payable quarterly. On February 28, 2009, HI, amended the terms of its long-term loans with BDO. Maturity dates of the loans were changed from January 31, 2010 to February 28, 2016 for the P=450.0 million long-term loans and from October 20, 2010 to February 28, 2016 for the P=200.0 million long-term loans. The amended terms also changed interest rates from floating to fixed at 8.36% per annum. The loan is secured by a chattel mortgage over the machineries and improvements of the Benguet and Davao hydropower plants of HI and a suretyship of ARI.

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Carrying value of machineries and improvements of the Benguet and Davao hydropower plants mortgaged with BDO to secure loans amounted to P=392.5 million and P=488.9 million as of December 31, 2010 and 2009, respectively (see Note 11). Loan covenant includes, among others, maintenance of debt service cover ratio of at least 1.1x and DE ratio of 75:25, and restrictions such as not to declare or pay dividends to its stockholders if debt service cover ratio is less than 1.2x nor shall it redeem or repurchase or retire or otherwise acquire for value any of its capital stock. HI is in compliance with the debt covenants as of December 31, 2010 and 2009. BEZ On June 28, 2010, BEZ availed of a P=70.0 million ten-year loan from the Metropolitan Bank and Trust Company to finance the acquisition, construction and installation of a new substation and for working capital requirements. The loan is payable in quarterly installments starting September 28, 2012. Interest on the loan for the first five years is fixed at 7.50%. For the remaining five-year period interest rate will be fixed at the prevailing five-year PDST- F interest rate for the day immediately preceding the fixed interest setting date plus 1.00%. Loan covenant includes, among others, restrictions such as not to declare or pay dividends to its stockholders if there are payments to the bank that are in arrears, permit any indebtedness to be secured in violation of the executed deed of negative pledge nor shall it redeem or repurchase or retire or otherwise acquire for value any of its capital stock. BEZ is in compliance with the loan covenant as of December 31, 2010. SEZ a. The loan availed of by SEZ in 2005 pertains to a term loan for assistance in the financing of

the Phase 1 rehabilitation of the SBMA PDS. The P=185.0 million clean loan fully drawn from the facility in 2007 was refinanced on June 26, 2008, with a term loan facility of up to a total amount of P=285.0 million. As of June 26, 2008, SEZ has drawn P=210.0 million from the facility. The refinanced loan is payable in twelve years (inclusive of a one year grace period on principal repayment) in twenty-two equal semi-annual installments commencing on December 26, 2009. It bears an interest of 10.02%, which is fixed for the first seven years. For the succeeding five years, the interest will be fixed based on the applicable five-year PDST-R1 on the first day of the eighth year plus 100 basis points.

On December 23, 2010, the P=210.0 million was pre-terminated. The total amount SEZC paid on this pre-termination of loan is P=202.5 million including interest and gross receipts tax.

b. On September 24, 2008, SEZ availed of a term loan of P=131.0 million to finance the

acquisition of subtransmission assets and to enhance the rehabilitation and expansion of the SBMA PDS. The loan is payable in twelve years (inclusive of a one-year grace period on principal repayment) in twenty-two equal semi-annual installments commencing on March 24, 2010. It bears an interest of 8.26%, which is fixed for the first seven years. For the succeeding five years, the interest will be fixed based on the applicable five-year PDST-R1 on the first day of the eighth year plus 100 basis points.

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The P=131.0 million loan is secured by surety of the stockholders and assignment of rights and benefits of SEZ related to revenue receivable and new equipment and assets to be purchased and used in the SBMA PDS. The term loan agreement prohibits SEZ to make or permit a material change in the character, ownership or control of its business, to secure any indebtedness, to sell, lease, transfer or dispose of all or substantially all of its properties, assets and investments. The agreement also does not permit SEZ to exceed the allowed DE ratio nor be less than the allowed ratio of current assets to current liabilities. The adoption of Philippine Interpretation IFRIC 12 in 2008 caused its DE ratio to exceed the maximum 3:1 limit as required by the above term loans. Prior to adopting and upon assessing the financial impact of the Interpretation on its financial statements, SEZ’s management initiated talks and negotiations with creditor bank on securing a waiver on the DE requirement as contained in the loan agreements. In December 2008, the creditor bank agreed to revise the DE ratio. On January 30, 2009, the creditor bank confirmed that the DE ratio of SEZ for the year 2008 may go up to 4:1. On January 14, 2010, the creditor bank approved and allowed the DE ratio for the year 2009 up to 2011 to go up to a maximum of 3.5:1. SEZ is in compliance with the debt covenant as of December 31, 2010 and 2009.

Unamortized deferred debt issuance cost reduced the carrying amount of long-term debt by P=0.5 million in 2010 and by P=0.6 million in 2009.

17. Customers’ Deposits

2010 2009 Transformers P=854,669 P=751,317 Lines and poles 766,738 692,427 Bill and load 382,977 337,372 P=2,004,384 P=1,781,116

Transformers and lines and poles deposits are obtained from certain customers principally as cash bond for their proper maintenance and care of the said facilities while under their exclusive use and responsibility. These deposits are noninterest-bearing and are refundable only after their related contract is terminated and the assets are returned to the Group in their proper condition and all obligations and every account of the customer due to the Group shall have been paid. Bill deposit serves to guarantee payment of bills by a customer which is estimated to equal one month’s consumption or bill of the customer. With regard to the interest rate on customer deposits, while the Implementing Guidelines of the Magna Carta provided that the interest rate on meter deposits shall be at 6% for contracts of service entered into prior to the effectivity of the then Energy Regulatory Board (ERB) Resolution No. 95-21, it was silent on the corresponding interest rate for bill deposits of residential customers for the same period. ERB Resolution No. 95-21 was issued by the then ERB on August 3, 1995 adopting a 10% interest on customers’ deposits. Pursuant to the Magna Carta, the rate of interest on bill deposits shall be equivalent to the interest incorporated in the power distribution companies’ weighted average cost of capital, otherwise, the rate shall be “based on the prevailing interest rate on savings deposit as approved by the Bangko Sentral ng Pilipinas (BSP)”. In the case of non-residential customers, the Distribution Services and Open Access Rules (DSOAR) likewise provides that the power distribution companies shall pay interest on bill deposits at the rate equivalent to the prevailing interest rate for savings deposits as approved by the BSP. The DSOAR superseded ERB Resolution No. 95-21, as amended, in its entirety.

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Both the Magna Carta and DSOAR also provide that residential and non-residential customers, respectively, must pay a bill deposit to guarantee payment of bills equivalent to their estimated monthly billing. The amount of deposit shall be adjusted after one year to approximate the actual average monthly bills. A customer who has paid his electric bills on or before due date for three consecutive years, may apply for the full refund of the bill deposit, together with the accrued interests, prior to the termination of his service; otherwise, bill deposits and accrued interests shall be refunded within one month from termination of service, provided all bills have been paid. In cases where the customer has previously received the refund of his bill deposit pursuant to Article 7 of the Magna Carta, and later defaults in the payment of his monthly bills, the customer shall be required to post another bill deposit with the distribution utility and lose his right to avail of the right to refund his bill deposit in the future until termination of service. Failure to pay the required bill deposit shall be a ground for disconnection of electric service. Interest expense on customers’ deposits amounted to P=3.8 million in 2010, P=5.7 million in 2009 and P=5.5 million in 2008 (see Note 32). The Group classified customers’ deposit under noncurrent assets due to the expected long-term nature of these deposits.

18. Payable to a Preferred Shareholder of a Subsidiary

The preferred shares of CPPC, a subsidiary, are voting, non-convertible, cumulative, non-participating and have no preemptive rights. The preferred shares shall be issued only to VECO who, as holder of the preferred shares, shall be entitled to receive cash dividends thereon at an annual rate of 20.713% and, payable out of available surplus or net profits of CPPC before any dividend shall be declared, set apart for or paid upon the common stock of CPPC. The guaranteed minimum amount of annual dividends on these preferred shares is P=31.1 million, which is payable within 60 days from end of each contract year starting November 25, 1998 to November 25, 2013. Any unpaid dividend shall be subject to interest equivalent to the rate of a 91-day Treasury Bill plus 5% per annum prevailing as of the preferred dividends accrual date.

After payment of the cumulative cash dividends on the preferred shares, the said preferred shares shall have no further right to participate in any dividends which may be declared to the common shareholders unless and until the aggregate of all cash dividends already declared and paid to the common shares has resulted in the holders of the common shares having recovered the agreed internal rate of return on their total equity investment in common shares. The common shareholders and VECO shall then be entitled to participate in such residual dividends at 77.0% and 23.0%, respectively. PAS 32, Financial Instruments: Presentation, and PAS 39 require reclassification of the preferred shares amounting to P=150.0 million as a financial instrument containing a liability and an equity component. The liability component was remeasured at present value by discounting the minimum guaranteed dividend payments. The difference between the present value and the carrying amount of P=18.5 million pertains to the equity component attributable to the non-controlling interests. The discounted liability is accreted to maturity values using the effective interest rate method. Accretions are recognized in the consolidated statements of income as part of interest expense. Total interest expense arising from the accretion amounted to P=19.8 million in 2010, P=21.9 million in 2009 and P=23.6 million in 2008 (see Note 32).

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Future minimum guaranteed dividend payments are as follows:

2010 2009 Due within one year P=31,070 P=31,070 More than one year but not more than five years 93,210 124,280 Future minimum guaranteed dividends 124,280 155,350 Less accrued interest expense 47,513 67,320 Future minimum guaranteed dividends – net 76,767 88,030 Less current portion 13,797 11,263 Noncurrent portion P=62,970 P=76,767

19. Equity

a. Capital Stock

2010 2009 Authorized - P=1 par value Preferred shares - 1,000,000,000 shares Common shares - 16,000,000,000 shares Issued Common shares - 7,358,604,307 shares P=7,358,604 P=7,358,604 There are no preferred shares issued and outstanding as of December 31, 2010 and 2009. Preferred shares are non-voting, non-participating, non-convertible, redeemable, cumulative, and may be issued from time to time by the BOD in one or more series. The BOD is authorized to issue from time to time before issuance thereof, the number of shares in each series, and all the designations, relative rights, preferences, privileges and limitations of the shares of each series. Preferred shares redeemed by the Company may be reissued. Holders thereof are entitled to receive dividends payable out of the unrestricted retained earnings of the Company at a rate based on the offer price that is either fixed or floating from the date of the issuance to final redemption. In either case, the rate of dividend, whether fixed or floating, shall be referenced, or be a discount or premium, to market-determined benchmark as the BOD may determine at the time of issuance with due notice to the SEC. In the event of any liquidation or dissolution or winding up of the Company, the holders of the preferred stock shall be entitled to be paid in full the offer price of their shares before any payment in liquidation is made upon the common stock.

b. Retained Earnings

On February 6, 2008, the BOD approved the declaration of cash dividends of P=0.18 a share (P=1.32 billion) to all stockholders of record as of February 21, 2008. The cash dividends were subsequently paid on March 3, 2008. On February 11, 2009, the BOD approved the declaration of cash dividends of P=0.20 a share (P=1.47 billion) to all stockholders of record as of February 26, 2009. The cash dividends were subsequently paid on March 23, 2009.

On March 10, 2010, the BOD approved the declaration of cash dividends of P=0.30 a share (P=2.21 billion) to all stockholders of record as of March 24, 2010. The cash dividends were subsequently paid on April 16, 2010.

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On March 3, 2011, the BOD approved the declaration of cash dividends of P=1.32 a share (P=9.71 billion) to all stockholders of record as of March 17, 2011. The cash dividends are payable on April 5, 2011.

20. Sale of Power

Sale from Distribution of Power

a. The Uniform Rate Filing Requirements on the rate unbundling released by the ERC on October 30, 2001, specified that the billing for sale and distribution of power and electricity will have the following components: Generation Charge, Transmission Charge, System Loss Charge, Distribution Charge, Supply Charge, Metering Charge, the Currency Exchange Rate Adjustment and Interclass and Lifeline Subsidies. National and local franchise taxes, the Power Act Reduction (for residential customers) and the Universal Charge are also separately indicated in the customer’s billing statements.

b. Pursuant to Section 43(f) of Republic Act (R.A.) No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001 (EPIRA), and Rule 15, section 5(a) of its Implementing Rules and Regulations (IRR), the ERC promulgated the Distribution Wheeling Rates Guidelines on December 10, 2004. These were subsequently updated and released on July 26, 2006 as the Rules for Setting Distribution Wheeling Rates for Privately Owned Utilities entering Performance Based Regulation (Second Entry Point).

In accordance with the Rules for the Setting of Distribution Wheeling Rates and the Position Paper, DLP and CLP filed various information and data relating to the requirements for the Regulatory Reset Process. Following its consideration of the submissions received, the discussions at the public consultation and further evidence presented by the distribution utilities, the ERC prepared its Final Determination dated December 15, 2008 for CLP and March 8, 2010 for DLP.

Details of the Performance-based Regulation (PBR) application for the first regulatory period are as follows: CLP DLPDate of application January 26, 2009 April 26, 2010First regulatory period April 1, 2009 to

March 31, 2013July 1, 2010 toJune 30, 2014

Date of ERC approval of application March 30, 2009 June 15, 2010Date of implementation of approved

distribution supply and metering charges May 1, 2009 August 1, 2010

Subsequently, CLP filed with ERC on December 18, 2009 its application for approval of: (a) the revised X-factor, smoothed Maximum Average Price (MAP) and Performance Incentive Scheme (PIS) for the Second Regulatory Period; (b) the recalculated MAP for the Regulatory Year 2011; and (c) the translation into distribution-related rates of different customer classes for the second regulatory year of the ERC-approved annual revenue requirement (ARR) under PBR for the regulatory period 2009 to 2013. After subsequent hearings of the case, CLP’s application was approved, with modifications, by the ERC on February 22, 2010 and CLP implemented the new rates effective April 1, 2010. Moreover, CLP filed with ERC on December 15, 2010 its application for approval of: (a) the recalculated MAP for regulatory year 2012; and (b) the translation into distribution related rates of different customer classes for the third regulatory year of the ERC-approved ARR for the

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regulatory period 2009 to 2013. The initial hearing, expository presentation, pre-trial conference and evidentiary hearing were held at the ERC Mindanao Field Office on January 17, 2011. As of March 3, 2011, CLP is awaiting ERC’s final decision on its application.

Sale from Generation of Power

a. Energy Trading through the Philippine Wholesale Electricity Spot Market (WESM)

As approved by the Philippine Electricity Market Corporation (PEMC), effective on various dates in 2009, certain companies in the Group are trading participants and direct members under the generator sector of the WESM. The companies are allowed to access the WESM Market Management System through its Market Participant Interface (MPI). The MPI is the facility that allows the trading participants to submit and cancel bids and offers, and to view market results and reports. Under its price determination methodology as approved by the ERC, locational marginal price method is used in computing prices for energy bought and sold in the market on a per node, per hour basis. In the case of bilateral power supply contracts, however, the involved trading participants settle directly with their contracting parties. On November 26, 2010, the Department of Energy (DOE) issued the Department Circular No. 2010-11-0012 which announced the commercial operations of the WESM in the Visayas Grid starting December 26, 2010 and its integration with the Luzon Grid.

Total sale of power to WESM amounted to P=14.94 billion, P=1.96 billion and nil in 2010, 2009 and 2008 respectively.

b. Power Supply Agreements

i. Power Supply Contracts assumed under APA and IPP Administration Agreement

Revenue recognition for customers under the power supply contracts assumed under the APA and IPP Administration Agreements are billed based on the contract price which is calculated based on the pricing structure approved by the ERC. Rates are calculated based on the time-of-use pricing schedule with corresponding adjustments using the Generation Rate Adjustment Mechanism (GRAM) and the Incremental Currency Exchange Rate Adjustment (ICERA).

ii. Power Purchase/Supply Agreement (PPA/PSA)

On February 7, 1997, VECO, an associate, entered into a PPA for the purchase of electric energy from CPPC, a subsidiary, effective for a period of 15 years (Co-operation Period) from the commercial operations of the latter (November 25, 1998), unless terminated in accordance with the provisions of the PPA but in no event to extend beyond the term of the present franchise of VECO. The PPA may be renewed or extended subject to the mutual agreement of the parties to the terms and conditions applicable to any such renewal. Upon expiration of the 15-year cooperation period, CPPC shall transfer, convey and assign the power plant to VECO without cost, except for applicable taxes thereon which shall be for the account of VECO. Among the salient features of the contract is that the electricity price shall not exceed 98% of the effective NPC billing rate to VECO based on contracted demand and energy. VECO shall also be entitled to a prompt payment discount equal to 3% of any amount paid to CPPC on or before the 15th day of the calendar month following the preceding billing period.

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On September 1, 2006, a Supplement to the 1997 PPA was executed by VECO and CPPC. Some of the salient provisions of the Supplement included the removal of the prompt payment discount, removal of the minimum off-take, and a pricing arrangement that changed CPPC’s billing to VECO from an energy based, NPC pegged rate to Demand-Energy Pricing Scheme. This in effect allows CPPC to bill capacity-based fees based on CPPC’s guaranteed contractual capacity. The Energy Pricing of this Supplement allows CPPC to pass on risks related to fuel prices. While waiting for the ERC approval on the Supplement to the 1997 PPA, VECO filed a motion to extend its cash cost arrangement with CPPC which was approved by the ERC in the latter’s decision dated August 10, 2008. On December 28, 2006, the ERC approved the Supplement to the 1997 PPA, which was implemented on the billing period ending January 26, 2008, the first billing cycle immediately after the approval of the ERC.

Total sale of power under power supply contracts amounted to P=31.37 billion in 2010, P=10.40 billion in 2009 and P=2.88 billion in 2008.

21. Purchased Power

Distribution

DLP, CLP and SEZ entered into contracts with NPC for the purchase of electricity. Pursuant to Section 8 of RA No. 9136, National Transmission Corporation (TransCo) was created and assumed the electrical transmission functions of the NPC. Pursuant to Section 8 of R.A. No. 9136, TransCo was created and assumed the electrical transmission functions of NPC. The TransCo concession contract was bid out on December 12, 2007, and the functions of TransCo were assumed by NGCP starting January 15, 2009. The material terms of the contract are as follows:

Term of Agreement

with NPC Contract Energy

(megawatt hours/year) DLPC Ten years; expiring in December 2015 1,238,475 CLPC Ten years; expiring in December 2015 116,906 SEZC Two-and-a-half years; renewed in March 2008

expiring in March 2011 90,000

Total power purchases from the NPC and NGCP, net of discounts, amounted to P=6.61 billion in 2010, P=7.12 billion in 2009, and P=5.83 billion in 2008. The outstanding payable to the NPC and NGCP on purchased power, presented as part of the “Trade and other payables” account in the consolidated balance sheets amounted to P=468.1 million and P=601.1 million as of December 31, 2010 and 2009, respectively (see Note 14).

Generation

Purchased power takes place during periods when power generated from power plants are not sufficient to meet customers’ required power as stated in the power supply contracts. Insufficient supply of generated energy results from the shutdowns due to scheduled maintenance or an emergency situation. The Group purchases power from WESM to ensure uninterrupted supply of power and meet the requirements in the power supply contracts. Total purchases from WESM amounted to P=858.5 million in 2010, P=32.5 million in 2009 and nil in 2008, respectively.

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22. Cost of Generated Power

2010 2009 2008 Fuel costs P=11,551,522 P=2,645,484 P=1,615,971 Steam supply costs (see Note 36) 3,542,807 2,207,504 – Energy fees 706,040 112,835 – Ancillary charges 53,831 51,545 46,366 Wheeling expenses 28,126 6,098 6,220 Others – 6,811 27,337 P=15,882,326 P=5,030,277 P=1,695,894

23. General and Administrative

2010 2009 2008 Personnel costs (see Note 25) P=517,814 P=369,216 P=262,202 Provision for impairment and write-off of

trade receivables (see Note 5) 292,065 137,595 67,398 Outside services (see Note 31) 287,975 469,439 146,728 Taxes and licenses 151,267 104,246 99,093 Market service and administrative fees

(see Note 31) 125,775 50,717 – Transportation and travel (see Note 31) 92,862 77,051 59,921 Repairs and maintenance 53,843 92,805 55,564 Corporate social responsibility (CSR)

(see Note 38g) 40,634 130,249 16,698 Professional fees (see Note 31) 37,770 131,264 121,400 Information technology and

communication 36,614 91,466 51,331 Rent 22,329 10,942 4,931 Advertisements 17,867 5,126 3,919 Training 8,939 8,038 5,053 Freight and handling 5,759 1,404 1,831 Entertainment, amusement and recreation 5,598 4,846 3,559 Guard services 5,498 6,111 4,648 Research and development 4,682 28,175 29,723 Insurance 3,657 29,732 7,322 Gasoline and oil 1,219 2,172 2,736 Others 274,659 151,834 158,517 P=1,986,826 P=1,902,428 P=1,102,574

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24. Operations and Maintenance

2010 2009 2008 Personnel costs (see Note 25) P=534,582 P=334,509 P=249,759 Fuel and lube oil 393,052 47,588 77,040 Taxes and licenses 377,356 295,730 136 Repairs and maintenance 286,009 212,090 175,339 Materials and supplies 226,808 174,701 74,366 Insurance 197,893 93,006 4,391 Outside services 69,483 120,448 32,403 Transportation and travel 30,081 11,081 11,681 Rent (see Note 35) 234 12,024 270 Others 322,430 35,810 27,719 P=2,437,928 P=1,336,987 P=653,104

25. Personnel Costs

2010 2009 2008 Salaries and wages P=856,063 P=553,695 P=345,945 Employee benefits (see Note 26) 196,333 150,030 166,016 P=1,052,396 P=703,725 P=511,961

26. Pension Benefit Plans

Most of the companies in the Group have funded defined benefit pension plans covering all regular and permanent employees. The benefits are based on employees’ projected salaries and number of years of service. The following tables summarize the components of net benefit expense recognized in the consolidated statements of income and the funded status and amounts recognized in the consolidated balance sheets. Net benefit expense (income) (recognized as part of personnel costs under operations and maintenance and general and administrative):

2010 2009 2008 Current service cost P=41,612 P=7,669 P=14,829 Interest cost on benefit obligation 41,099 32,787 17,237 Past service cost 287 230 230 Net actuarial loss (gain) recognized 10,006 (2,672) (608) Expected return on plan assets (24,524) (22,626) (17,676) Net pension asset in excess of limit – (20,180) 8,193 P=68,480 (P=4,792) P=22,205

Actual return on plan assets is P=49.5 million in 2010, P=65.6 million in 2009, and P=1.6 million in 2008. The Group expects to contribute P=106.4 million to their retirement fund in 2011. The overall expected return on plan assets is determined based on the market expectations prevailing on that date, applicable to the period over which the obligation is to be settled.

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As of December 31, 2010, HSI, APRI, TLI and Therma Marine are in net pension liability position while the rest of the companies in the Group are in net pension asset position. As of December 31, 2009, DLP, SEZ, AESI and CPPC are in net pension asset position while the rest of the companies in the Group are in net pension liability position. Pension assets

2010 2009 Fair value of plan assets P=491,467 P=137,466 Defined benefit obligation 528,041 203,243 Unfunded obligation (36,574) (65,777) Unrecognized past service cost 1,786 2,074 Unrecognized net actuarial losses 208,230 100,889 P=173,442 P=37,186

Pension liabilities

2010 2009 Defined benefit obligation P=18,134 P=224,246 Fair value of plan assets – 107,756 Unfunded obligation 18,134 116,490 Unrecognized net actuarial losses (2,133) (88,332) P=16,001 P=28,158

Changes in the present value of the defined benefit obligation are as follows:

2010 2009 Opening defined benefit obligation P=427,489 P=124,107 Actuarial losses 56,159 280,159 Current service cost 41,612 7,669 Interest cost on benefit obligation 41,099 32,787 Benefits paid (6,772) (19,338) Fund transfers to (from) affiliates (13,412) 2,105 Closing defined benefit obligation P=546,175 P=427,489

Changes in the fair value of plan assets are as follows:

2010 2009 Opening fair value of plan assets P=245,222 P=205,052 Contribution by employer 216,894 8,982 Actuarial gains 25,011 25,795 Expected return on plan assets 24,524 22,626 Benefits paid (6,772) (19,338) Fund transfer to (from) affiliates (13,412) 2,105 Closing fair value of plan assets P=491,467 P=245,222

The principal assumptions used in determining the pension obligations for the Group’s plans are shown below:

2010 2009 Discount rate 7.80% - 10.92% 9.97% - 37.56% Expected rate of return on assets 7.00% - 10.00% 9.00% - 11.00% Future salary increase 6.00% - 8.00% 8.00% - 11.00%

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As of December 31, 2010, discount rates used has decreased to 7.80% to 10.00% with salary increase rates of 7.00% to 10.00% and expected rates of return on plan assets of 6.00% to 10.00%, based on the latest actuarial valuation of retirement benefits of each of the entity in the Group. Amounts for the current and previous four periods are as follows: 2010 2009 2008 2007 2006 Defined benefit obligation P=546,175 P=427,489 P=124,107 P=191,777 P=179,652 Plan assets 491,467 245,222 205,052 228,609 153,019 Surplus (deficit) (54,708) (182,267) 80,945 36,832 (26,633) Experience adjustment on plan liability 49,759 23,911 (8,408) (7,143) (56,688) Experience adjustment on pension asset 25,011 22,256 (16,123) (6,231) 18,381

The major categories of plan assets as a percentage of the fair value of the total plan assets are as follows:

2010 2009 2008 Commercial papers 76% 67% 54% Marketable securities 22% 26% 38% Others 2% 7% 8%

27. Other Income - Net

2010 2009 2008 Net foreign exchange gains (see Note 33) P=1,142,158 P=348,815 P=11,603 Non-utility operating income 168,786 174,586 174,557 Surcharges 101,626 82,368 87,658 Wheeling fees 50,751 51,957 46,705 Others (see Notes 36 and 38) 137,078 155,685 56,169 P=1,600,399 P=813,411 P=376,692

Others include adjustments to monthly payments under the IPPA of TLI and reversal of NPC claims against CPPC in 2010 and 2009, respectively.

28. Income Tax

The provision for income tax account consists of:

2010 2009 2008 Current P=591,785 P=840,222 P=577,071 Deferred 328,912 (209,032) 41,313 P=920,697 P=631,190 P=618,384

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Reconciliation between the statutory income tax rate and the Group’s effective income tax rates follows:

2010 2009 2008 Statutory income tax rate 30.00% 30.00% 35.00% Tax effects of:

Nondeductible interest expense 5.90 5.79 – Nondeductible depreciation expense 1.26 1.28 – Interest income subjected to final tax at

lower rates - net (0.21) (0.71) (1.88) Nontaxable share in net earnings of

associates (5.34) (11.88) (19.85) Income under income tax holiday (ITH) (29.72) (9.99) – Others 1.65 (4.63) (1.62) 3.54% 9.86% 11.65%

Deferred income taxes of the companies in the Group that are in deferred income tax assets and liabilities position consist of the following at December 31:

2010 2009 Deferred income tax assets: NOLCO P=141,619 P=137,867 Allowances for impairment and probable losses 27,611 82,172 Unamortized past service cost 23,256 2,487 MCIT 16,417 19,074 Unrealized foreign exchange losses 5,455 1,589 Pension liability (asset) (17,768) 5,950 Others 3,232 870 Net deferred income tax assets P=199,822 P=250,009

2010 2009 Deferred income tax liabilities: Unrealized foreign exchange gains P=319,631 P=860 Pension asset 28,684 10,702 Unamortized customs duties and taxes capitalized 18,324 17,015 Unamortized streetlight donations capitalized 6,249 3,869 Capitalized interest expense 5,565 4,195 MCIT – 2,169 Unamortized past service cost (21,127) (361) Allowances for doubtful accounts

and probable losses (32,196) (444) Others (4,009) – Net deferred income tax liabilities P=321,121 P=38,005

In computing for deferred income tax assets and liabilities, the rates used were 30% and 10%, which are the rates expected to apply to taxable income in the years in which the deferred income tax assets and liabilities are expected to be recovered or settled and considering the tax rate for renewable energy (RE) developers as allowed by the Renewable Energy Act of 2008 (see Note 38f).

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As of December 31, 2010, no deferred income tax assets were recognized on the Company’s NOLCO and MCIT amounting to P=114.8 million and P=23.8 million, respectively, since management expects that it will not generate sufficient taxable income in the future that will be available to allow all of the deferred income tax assets to be utilized. There were no unrecognized deferred income tax assets as of December 31, 2009. There are no income tax consequences to the Group attaching to the payment of dividends to its shareholders.

29. Earnings Per Common Share Earnings per common share amounts were computed as follows:

2010 2009 2008 a. Net income attributable to equity

holders of the parent P=25,041,116 P=5,658,581 P=4,333,613 b. Weighted average number of

common shares issued and outstanding 7,358,604,307 7,358,604,307 7,358,604,307

Earnings per common share (a/b) P=3.40 P=0.77 P=0.59

There are no dilutive potential common shares as of December 31, 2010, 2009 and 2008. 30. Business Segment Information

Operating segments are components of the Group that engage in business activities from which they may earn revenues and incur expenses, whose operating results are regularly reviewed by the Group’s CODM to make decisions about how resources are to be allocated to the segment and assess their performances, and for which discrete financial information is available.

For purposes of management reporting, the Group’s operating businesses are organized and managed separately according to services provided, with each segment representing a strategic business segment. The Group identified operating segments, which are consistent with the segments reported to the BOD, which is the Group’s CODM, as follows:

• “Power Generation” segment, which is engaged in the generation and supply of power to

various customers under power supply contracts, ancillary service procurement agreements and for trading in WESM;

• “Power Distribution” segment, which is engaged in the distribution and sale of electricity to the end-users; and

• “Parent Company and Others”, which includes the operations of the Company and electricity-related services of the Group such as installation of electrical equipment.

The Group has only one geographical segment as all of its assets are located in the Philippines. The Group operates and derives principally all of its revenue from domestic operations. Thus, geographical business information is not required.

Management monitors the operating results of its segments separately for the purpose of making decisions about resource allocation and performance assessment. Segment revenue and segment expenses are measured in accordance with PFRS. The presentation and classification of segment revenue and segment expenses are consistent with the consolidated statement of income. Interest

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expense and financing charges, depreciation and amortization expense and income taxes are managed on a per segment basis.

The Group has inter-segment revenues in the form of management fees as well as inter-segment sales of electricity which are eliminated in consolidation. The transfers are accounted for at competitive market prices on an arm’s-length transaction basis. Segment assets do not include deferred income tax assets, pension asset and other noncurrent assets. Segment liabilities do not include deferred income tax liabilities, income tax payable and pension liability. Capital expenditures consist of additions of property, plant and equipment and intangible asset - service concession rights. Adjustments as shown below include items not presented as part of segment assets and liabilities.

Revenue is recognized to the extent that it is probable that economic benefits will flow to the Group, and that the revenue can be reliably measured. Sale of power to Manila Electric Company accounted for 31% and 30% of the power generation revenues of the Group in 2010 and 2009, respectively; while sale of power to VECO accounted for 17% and 81% of the power generation revenues of the Group in 2009 and 2008, respectively.

Financial information on the operations of the various business segments are summarized as follows: 2010

Power

Generation Power

Distribution

Parent Company/

Others Eliminations and

Adjustments Consolidated

REVENUE External P=46,313,904 P=13,064,593 P=172,961 P=– P=59,551,458 Inter-segment 668,500 – 292,314 (960,814) –

Total Revenue P=46,982,404 P=13,064,593 P=465,275 (P=960,814) P=59,551,458

Segment results P=24,726,557 P=1,400,678 P=146,562 P=– P=26,273,797 Unallocated corporate income - net 1,208,074 379,240 (29,132) – 1,558,182

INCOME FROM OPERATIONS 25,934,631 1,779,918 117,430 – 27,831,979 Interest expense (5,463,077) (100,913) (1,133,262) 18,959 (6,678,293) Interest income 120,306 12,956 109,855 (18,959) 224,158 Share in net earnings of associates 4,153,369 472,514 26,102,448 (26,102,448) 4,625,883 Provision for income tax (354,867) (432,115) (133,715) – (920,697)

NET INCOME P=24,390,362 P=1,732,360 P=25,062,756 (P=26,102,448) P=25,083,030

OTHER INFORMATION Investments in Associates P=24,269,963 P=2,543,397 P=51,660,757 (P=51,544,121) P=26,929,996

Capital Expenditures P=3,487,167 P=791,791 P=33,319 P=– P=4,312,277

Segment Assets P=111,352,105 P=8,874,380 P=73,641,432 (P=59,311,045) P=134,556,872

Segment Liabilities P=65,915,598 P=4,319,612 P=16,432,358 (P=9,844,906) P=76,822,662

Depreciation and amortization P=2,658,121 P=328,976 P=16,880 P=– P=3,003,977

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2009

Power

Generation Power

Distribution

Parent Company/





Segment results P=4,362,774 P=1,196,104 (P=102,711) P=– P=5,456,167 Unallocated corporate income - net 379,117 369,535 64,759 – 813,411

INCOME FROM OPERATIONS 4,741,891 1,565,639 (37,952) – 6,269,578 Interest expense (1,884,802) (106,097) (852,759) 29,680 (2,813,978) Interest income 47,656 12,583 379,413 (29,680) 409,972 Share in net earnings of associates 2,227,256 308,130 6,021,174 (6,021,174) 2,535,386 Benefit from (provision for) income tax (413,892) (376,376) 159,078 – (631,190)

NET INCOME P=4,718,109 P=1,403,879 P=5,668,954 (P=6,021,174) P=5,769,768





Depreciation and amortization P=1,069,904 P=330,696 P=12,300 P=– P=1,412,900

2008

Power

Generation Power

Distribution

Parent Company/





Segment results P=513,914 P=1,121,082 P=17,509 P=– P=1,652,505 Unallocated corporate income (expenses) (85,677) 338,121 124,248 – 376,692

INCOME FROM OPERATIONS 428,237 1,459,203 141,757 – 2,029,197 Interest expense (91,234) (89,198) (242,166) 44,062 (378,536) Interest income 149,810 15,550 486,242 (44,062) 607,540 Share in net earnings of associates 2,437,729 346,782 4,079,893 (4,079,893) 2,784,511 Provision for income tax (101,011) (401,848) (115,525) – (618,384)

NET INCOME P=2,823,531 P=1,330,489 P=4,350,201 (P=4,079,893) P=4,424,328





Depreciation and amortization P=179,349 P=324,726 P=7,079 P=– P=511,154

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31. Related Party Disclosures

Parties are considered to be related if one party has the ability to control, directly or indirectly, the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also considered to be related if they are subject to common control or common significant influence. Related parties may be individuals or corporate entities. The Group enters into transactions with its parent, associates and other related parties, principally consisting of the following: a. Up until December 31, 2008, the Group had service contracts with ACO for corporate center

services rendered, such as human resources, internal audit, legal, treasury and corporate finance, among others. With the transfer of all ACO employees to AEV in January 2009, AEV is now providing these same services and shares with the member companies the business expertise of its highly qualified professionals. Transactions are priced on a cost recovery basis, and billed costs are always benchmarked on third party rates to ensure competitive pricing. Service Level Agreements are in place to ensure quality of service. This arrangement enables the Group to maximize efficiencies and realize cost synergies. Management, professional, legal and other service fees paid by the Group to AEV and ACO amounted to P=293.7 million in 2010, P=409.4 million in 2009, and P=362.6 million in 2008, respectively (see Note 23).

b. Management and other service contracts of certain subsidiaries with ACO at fees based on agreed rates. Management and other service fees paid by the Group to ACO amounted to nil in 2010 and 2009 and P=40.7 million in 2008 (see Note 23).

c. The Company also obtained standby letters of credit (SBLC) and is acting as surety for the

benefit of certain subsidiaries and associates in connection with loans and credit accommodations. The Company provided SBLC for STEAG, LHC, SNAP M and SNAP B in the amount of P=1.70 billion in 2010 and P=1.80 billion in 2009 and 2008.

d. Energy fees billed by HI to SFELAPCO amounted to nil in 2010, P=19.6 million in 2009 and P=17.3 million in 2008.

e. Energy fees billed by CPPC to VECO amounted to P=2.04 billion in 2010, P=2.10 billion in

2009 and P=2.35 billion in 2008 (see Note 20).

f. Energy fees billed by TLI to SNAP M in 2010 amounted to P=22.1 million.

g. Energy fees billed by Therma Marine to Pilmico Foods Corporation (PFC) in 2010 amounted to P=47.4 million. PFC is a subsidiary of AEV.

h. Energy fees billed by BEZC to affiliates (ACO subsidiaries and associates) amounted to

P=521.9 million in 2010, P=287.7 million in 2009 and P=181.5 million in 2008.

i. Aviation services rendered by AEV Aviation, Inc., a subsidiary of AEV, to the Group. Total expenses amounted to P=32.7 million in 2010, P=24.8 million in 2009 and P=19.9 million in 2008. AEV Aviation is a subsidiary of AEV (see Note 23).

j. Lease of commercial office units by the Group from Cebu Praedia Development Corporation (CPDC) for a period of three years. Rental expense amounted to P=69.4 million in 2010, P=48.2 million in 2009 and P=32.2 million in 2008. CPDC is a subsidiary of AEV.

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k. The Company provides services to certain subsidiaries and associates such as technical and legal assistance for various projects and other services. Total technical and service fee income from associates amounted to P=93.7 million in 2010, P=2.2 million in 2009 and P=9.4 million in 2008 (see Note 27).

l. Cash deposits with Union Bank of the Philippines and City Savings Bank, associate and

subsidiary, respectively, of AEV (see Note 4).

m. Amounts owed to/by related parties, both interest and noninterest-bearing, payable on demand. Interest-bearing balances are based on annual interest rates ranging from 1.80% to 8.25% in 2010, 3.00% to 9.25% in 2009 and 3.00% to 10.40% in 2008. Net interest expense incurred on these balances amounted to P=1.5 million in 2010. Net interest income earned on these balances amounted to P=55.8 million in 2009 and P=142.7 million in 2008 (see Note 32).

Significant outstanding account balances with related parties (see Notes 5 and 14) as of December 31, 2010 and 2009 are as follows:

Amounts Owed by Related Parties Amounts Owed to Related Parties 2010 2009 2010 2009 Ultimate Parent and Parent ACO P=– P=– P=– P=10,124 AEV – – 63,848 20,645 Associates VECO 133,906 229,848 – – CEDC 45,100 – – – RP Energy 15,782 – – – SFELAPCO 84 4,058 – – STEAG – 225,002 – – EAUC – – 129,999 1,145,253 Other Related Parties Tsuneishi Heavy Industries, (Cebu)

Inc. (THICI) 49,681 32,955 – – PFC 3,375 – – –

THICI is an associate of ACO.

Compensation of BOD and key management personnel of the Group follows:

2010 2009 2008 Short-term benefits P=144,279 P=125,451 P=70,642 Post-employment benefits 6,634 3,832 3,634 P=150,913 P=129,283 P=74,276

32. Financial Risk Management Objectives and Policies

The Group’s principal financial instruments comprise cash and cash equivalents and long-term debts. The main purpose of these financial instruments is to raise finances for the Group’s operations. The Group has various other financial instruments such as trade and other receivables, AFS investments, restricted cash, bank loans, trade and other payables, finance lease obligation, payable to preferred shareholder of a subsidiary, long-term obligation on power distribution system and customers’ deposits, which arise directly from its operations.

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The Group also enters into derivative transactions, particularly foreign currency forwards, to economically hedge its foreign currency risk from foreign currency denominated liabilities and purchases (see Note 33). The main risks arising from the Group’s financial instruments are liquidity risk, interest rate risk, foreign exchange risk, and credit risk. The BOD reviews and agrees on policies for managing each of these risks and they are summarized below.

Liquidity risk Liquidity risk is the risk of not meeting obligations as they become due because of the inability to liquidate assets or obtain adequate funding. The Group maintains sufficient cash and cash equivalents to finance its operations. Any excess cash is invested in short-term money market placements. These placements are maintained to meet maturing obligations and pay any dividend declarations. In managing its long-term financial requirements, the Group’s policy is that not more than 25% of long term borrowings should mature in any twelve-month period. 2.49% of the Group’s debt will mature in less than one year as of December 31, 2010 (2009: 3.74%). For its short-term funding, the Group’s policy is to ensure that there are sufficient working capital inflows to match repayments of short-term debt. The financial assets that will be principally used to settle the financial liabilities presented in the following table are from cash and cash equivalents and trade and other receivables that have contractual undiscounted cash flows amounting to P=18.30 billion and P=6.81 billion as of December 31, 2010 and P=3.81 billion and P=4.48 billion as of December 31, 2009, respectively (see Notes 4 and 5). Cash and cash equivalents can be withdrawn anytime while trade and other receivables are expected to be collected/realized within one year. The following tables summarize the maturity profile of the Group’s financial liabilities as of December 31, 2010 and 2009 based on contractual undiscounted payments: December 31, 2010

Total carrying

value

Contractual undiscounted payments

Total On

demand <1 year 1 to 5 years > 5 years Trade and other payables P=4,748,034 P=4,748,034 P=1,126,819 P=3,621,215 P=– P=– Due to related parties 129,999 129,999 129,999 – – – Customers’ deposits 2,004,384 2,019,151 100 41,402 37,888 1,939,761 Bank loans 1,979,800 2,002,575 – 2,002,575 – – Payable to a preferred

shareholder of a subsidiary 76,767 124,280 – 31,070 93,210 –

Finance lease obligation 48,305,116 111,394,573 – 1,102,080 24,146,573 86,145,920 Long-term obligation on

power distribution system 282,559 680,000 – 40,000 200,000 440,000

Long-term debts 16,703,113 26,552,968 – 2,184,947 21,344,452 3,023,569 Derivative liabilities 323 323 – 323 – – Total P=74,230,095 P=147,651,903 P=1,256,918 P=9,023,612 P=45,822,123 P=91,549,250

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December 31, 2009

Total carrying

value

Contractual undiscounted payments

Total On

demand <1 year 1 to 5 years > 5 years Trade and other payables P=4,168,731 P=4,168,731 P=1,126,819 P=3,041,912 P=– P=– Due to related parties 1,145,253 1,145,253 1,145,253 – – – Customers' deposits 1,781,116 1,789,335 – 59,164 27,270 1,702,901 Bank loans 5,828,100 5,845,599 – 5,845,599 – – Payable to a preferred

shareholder of a subsidiary 88,030 155,350 – 31,070 124,280 –

Finance lease obligation 45,586,164 115,387,464 – 1,130,400 25,897,464 88,359,600 Long-term obligation on

power distribution system 287,460 720,000 – 40,000 200,000 480,000

Long-term debts 16,252,535 23,904,868 – 1,449,483 17,580,706 4,874,679 Derivative liabilities 16,476 16,476 – 16,476 – – Total P=75,153,865 P=153,133,076 P=2,272,072 P=11,614,104 P=43,829,720 P=95,417,180 Interest rate risk The Group’s exposure to market risk for changes in interest rates relates primarily to its long-term debt obligations. To manage this risk, the Group determines the mix of its debt portfolio as a function of the level of current interest rates, the required tenor of the loan, and the general use of the proceeds of its various fund raising activities. As of December 31, 2010, 4% of the Group’s long-term debt had floating interest rates ranging from 6.68% to 6.71%, and 96% have fixed interest rates ranging from 7.50% to 8.26%. As of December 31, 2009, all of the Group’s long-term debt had fixed interest rates ranging from 8.23% to 10.02%. The following tables set out the carrying amounts, by maturity, of the Group’s financial instruments that are exposed to cash flow interest rate risk:


<1 year 1-5 years >5 years Total Floating rate - long-term debt P=213,333 P=423,100 P=– P=636,433 Floating rate - payable to a preferred

shareholder of a subsidiary 13,797 62,970 – 76,767 Total P=227,130 P=486,070 P=– P=713,200


<1 year 1-5 years >5 years Total Floating rate - payable to a preferred

shareholder of a subsidiary P=11,263 P=76,767 P=– P=88,030

Interest on financial instruments classified as floating rate is repriced at intervals of less than one year. Interest on financial instruments classified as fixed rate is fixed until the maturity of the instrument. The other financial instruments of the Group that are not included in the above tables are non-interest-bearing and are therefore not subject to interest rate risk. The Group’s derivative assets and liabilities are subject to fair value interest rate risk (see Note 33).

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The following table demonstrates the sensitivity to a reasonably possible change in interest rates, with all other variables held constant, of the Group’s income before tax (through the impact on floating rate borrowings):

Increase (decrease) in basis points

Effect on income before tax

December 2010 100 (P=6,364) (50) 3,182 December 2009 100 –

(50) – December 2008 100 (6,470) (50) 3,235

The Group’s sensitivity to an increase/decrease in interest rates pertaining to floating rate borrowings was expected to be insignificant in 2009 due to the immateriality of payable to a preferred shareholder of a subsidiary relative to the total liabilities of the Group. The Group’s sensitivity to an increase/decrease in interest rates pertaining to derivative instruments is expected to be insignificant in 2010 and 2009 due to their short-term maturities and immateriality relative to the total assets and liabilities of the Group. There is no other impact on the Group’s equity other than those already affecting the consolidated statements of income. The interest expense and other finance charges recognized during the period according to source are as follows:

2010 2009 2008 Finance lease obligation (see Note 35) P=5,115,549 P=1,234,905 P=– Bank loans and long-term debt (see Notes 15 and 16) 1,481,765 1,515,519 307,515 Long-term obligation on power distribution system (see Note 12) 35,099 35,644 36,128 Amounts owed to related parties

(see Note 31) 22,305 322 5,867 Payable to a preferred shareholder of subsidiary (see Note 18) 19,807 21,876 23,564 Customers’ deposits (see Note 17) 3,768 5,712 5,462 P=6,678,293 P=2,813,978 P=378,536

Foreign exchange risk The foreign exchange risk of the Group pertains significantly to its foreign currency denominated obligations. To manage its foreign exchange risk, stabilize cash flows and improve investment and cash flow planning, the Group enters into foreign currency forward contracts aimed at reducing and/or managing the adverse impact of changes in foreign exchange rates on financial performance and cash flows. As of December 31, 2010 and December 31, 2009, foreign currency denominated borrowings account for 37% and 41%, respectively, of total consolidated borrowings.

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Presented below are the Group’s foreign currency denominated financial assets and liabilities as of December 31, 2010 and 2009, translated to Philippine Peso:

December 31, 2010 December 31, 2009

US Dollar Philippine Peso

equivalent1 US Dollar Philippine Peso

equivalent2 Loans and receivables

Cash US$8,019 P=351,553 US$8,270 P=382,089 Trade and other receivables 963 42,218 3,510 162,175 Advances to associates 13,402 587,544 1,402 64,767 Restricted cash – – 12,131 560,423 Total financial assets 22,384 981,315 25,313 1,169,454 Other financial liabilities

Bank loans – – 81,000 3,742,200 Trade and other payables 5,682 249,099 4,176 192,925 Finance lease obligation 563,388 24,698,930 521,455 24,091,225

Total financial liabilities 569,070 24,948,029 606,631 28,026,350 Total net financial liabilities (US$546,686) (P=23,966,714) (US$581,318) (P=26,856,896)

1$1 = P=43.840 2$1 = P=46.200

The following table demonstrates the sensitivity to a reasonably possible change in the US dollar exchange rates, with all other variables held constant, of the Group’s income before tax as of December 31, 2010 and 2009:

Increase/ (decrease) in US DollarEffect on income

before tax December 31, 2010

US dollar denominated accounts US Dollar strengthens by 5% (P=1,198,336) US dollar denominated accounts US Dollar weakens by 5% 1,198,336

December 31, 2009

US dollar denominated accounts US Dollar strengthens by 5% (P=1,342,845) US dollar denominated accounts US Dollar weakens by 5% 1,342,845

The increase in US Dollar rate represents the depreciation of the Philippine Peso while the decrease in US Dollar rate represents appreciation of the Philippine Peso. The Group’s sensitivity to an increase/decrease in foreign currency pertaining to derivative instruments is expected to be insignificant in 2010 and 2009 due to their short-term maturities and immateriality relative to the total assets and liabilities of the Group. There is no other impact on the Group’s equity other than those already affecting the consolidated statements of income. Credit risk For its cash investments (including restricted portion), AFS investments and receivables, the Group’s credit risk pertains to possible default by the counterparty, with a maximum exposure equal to the carrying amount of these investments. With respect to cash investments and AFS investments, the risk is mitigated by the short-term and/or liquid nature of its cash investments mainly in bank deposits and placements, which are placed with financial institutions and entities of high credit standing. With respect to receivables, credit risk is controlled by the application of credit approval, limit and monitoring procedures. It is the Group’s policy to only enter into

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transactions with credit-worthy parties to mitigate any significant concentration of credit risk. The Group ensures that sales are made to customers with appropriate credit history and it has internal mechanisms to monitor the granting of credit and management of credit exposures. The Group has no significant credit concentration risk to counterparty or group of counterparties. Credit risk concentration of the Group’s receivables according to the customer category as of December 31, 2010 and 2009 is summarized in the following table:

2010 2009 Power distribution Residential P=308,887 P=228,942 Commercial 164,468 96,799 Industrial 420,154 296,444 City street lighting 8,619 10,465 Power generation Spot market 1,702,790 975,729 Power supply contracts 3,669,286 2,104,015 P=6,274,204 P=3,712,394

The above receivables were provided with allowance for doubtful accounts amounting to P=376.9 million in 2010 and 106.2 million in 2009 (see Note 5). The credit quality per class of financial assets is as follows: December 31, 2010 Neither past due nor impaired

High Grade Standard Sub-standard

Past due or individually

impaired Total Cash and cash equivalents

Cash on hand and in banks P=3,055,662 P=– P=– P=– P=3,055,662 Short-term investments 15,246,183 – – – 15,246,183

18,301,845 – – – 18,301,845 Trade receivables

Residential 33,379 41,169 131,839 102,500 308,887 Commercial 67,500 55,419 28,691 12,858 164,468 Industrial 277,993 12,072 34,467 95,622 420,154 City street lighting 1,208 3,699 3,025 687 8,619 Spot market 592,030 266,795 – 843,965 1,702,790 Power supply contracts 2,379,450 451,867 – 837,969 3,669,286

3,351,560 831,021 198,022 1,893,601 6,274,204 Advances to suppliers, officers and

employees 8,849 7,281 – 2,739 18,869 Other receivables 801,852 35,303 3,944 48,531 889,630 AFS investments 3,744 – – – 3,744 Derivative assets 7,670 – – – 7,670 Total P=22,475,520 P=873,605 P=201,966 P=1,944,871 P=25,495,962

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December 31, 2009

Neither past due nor impaired

High Grade Standard Sub-standard

Past due or individually

impaired Total Cash and cash equivalents

Cash on hand and in banks P=2,255,660 P=– P=– P=– P=2,255,660 Short-term investments 1,559,246 – – – 1,559,246

3,814,906 – – – 3,814,906 Trade receivables

Residential 26,864 34,016 101,736 66,326 228,942 Commercial 13,519 37,380 28,614 17,286 96,799 Industrial 230,247 16,957 27,259 21,981 296,444 City street lighting 3,247 3,829 3,071 318 10,465 Spot market – 967,268 – 8,461 975,729 Power supply contracts 826,685 1,034,897 42,462 199,971 2,104,015

1,100,562 2,094,347 203,142 314,343 3,712,394 Advances to suppliers, officers

and employees 158,050 – – 2,227 160,277 Other receivables 144,591 81,039 6,771 477,126 709,527 AFS investments 3,744 – – – 3,744 Derivative assets 846 – – – 846 Restricted cash 560,423 – – – 560,423 Total P=5,783,122 P=2,175,386 P=209,913 P=793,696 P=8,962,117 High grade receivables pertain to receivables from customers with good favorable credit standing and have no history of default. Receivables from customers with history of sliding beyond the credit terms but pay a week after being past due are classified under standard quality. Sub-standard quality pertains to those customers with payment habits that normally extend beyond the approved credit terms, and has high probability of being impaired. Trade and other receivables that are individually determined to be impaired at the balance sheet date relate to debtors that are in significant financial difficulties and have defaulted on payments and accounts under dispute and legal proceedings.

The Group evaluated its cash and cash equivalents and restricted cash as high quality financial assets since these are placed in financial institutions of high credit standing. With respect to advances to suppliers, advances to related parties, other receivables, AFS investment and derivative assets, the Group evaluates the counterparty’s external credit rating in establishing credit quality. Advances to officers and employees are considered high grade as these are automatically deductible from the officers and employees’ salaries and wages.

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The tables below show the Group’s aging analysis of financial assets: December 31, 2010


Total


impaired Less than

30 days 31 days to

60 days Over 60

days Individually

impaired Cash and cash equivalents

Cash on hand and in banks P=3,055,662 P=3,055,662 P=– P=– P=– P=– Short-term investments 15,246,183 15,246,183 – – – –

18,301,845 18,301,845 – – – – Trade receivables

Residential 308,887 206,387 62,558 10,735 14,974 14,233 Commercial 164,468 151,610 7,770 1,436 1,972 1,680 Industrial 420,154 324,532 16,127 13,891 58,453 7,151 City street lighting 8,619 7,932 483 3 5 196 Spot market 1,702,790 858,825 89,468 102,215 348,801 303,481 Power supply contracts 3,669,286 2,831,317 279,155 212,663 296,676 49,475

6,274,204 4,380,603 455,561 340,943 720,881 376,216 Advances to suppliers, officers

and employees 18,869 16,130 1,525 522 692 – Other receivables 889,630 841,099 7,927 4,008 35,900 696 AFS investments 3,744 3,744 – – – – Derivative assets 7,670 7,670 – – – – Total P=25,495,962 P=23,551,091 P=465,013 P=345,473 P=757,473 P=376,912 December 31, 2009 Past due but not impaired

Total


impaired Less than

30 days 31 days to 60

days Over 60

days Individually

impaired Cash and cash equivalents

Cash on hand and in banks P=2,255,660 P=2,255,660 P=– P=– P=– P=– Short-term investments 1,559,246 1,559,246 – – – –

3,814,906 3,814,906 – – – – Trade receivables

Residential 228,942 162,616 41,300 5,264 15,041 4,721 Commercial 96,799 79,513 9,350 1,597 5,595 744 Industrial 296,444 274,463 12,170 2,139 1,531 6,141 City street lighting 10,465 10,147 22 21 92 183 Spot market 975,729 967,268 122 36 187 8,116 Power supply contracts 2,104,015 1,904,044 111,124 588 2,688 85,571

3,712,394 3,398,051 174,088 9,645 25,134 105,476 Advances to suppliers,

officers and employees 160,277 158,050 161 1,877 189 – Other receivables 709,527 232,401 147,466 73,079 255,887 694 AFS investments 3,744 3,744 – – – – Derivative assets 846 846 – – – – Restricted cash 560,423 560,423 – – – – Total P=8,962,117 P=8,168,421 P=321,715 P=84,601 P=281,210 P=106,170 Capital management Capital includes equity attributable to the equity holders of the parent. The primary objective of the Group’s capital management is to ensure that it maintains a strong credit rating and healthy capital ratios in order to support its business and maximize shareholder value. The Group manages its capital structure and makes adjustments to it, in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may adjust the

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dividend payment to shareholders, return capital to shareholders or issue new shares. The Group monitors capital using a gearing ratio, which is net debt divided by equity plus net debt. The Group’s policy is to keep the gearing ratio at 70% or below. The Group determines net debt as the sum of interest-bearing short-term and long-term loans (comprising long-term debt, finance lease obligation and payable to a preferred shareholder of a subsidiary) less cash and short-term deposits and temporary interest bearing advances to related parties.

Gearing ratios of the Group as of December 31, 2010 and 2009 are as follows:

2010 2009 Bank loans P=1,979,800 P=5,828,100 Long-term debt 65,084,996 61,926,729 Cash and cash equivalents (18,301,845) (3,814,906) Net debt (a) 48,762,951 63,939,923 Equity 57,734,210 35,046,927 Equity and net debt (b) P=106,497,161 P=98,986,850 Gearing ratio (a/b) 45.79% 64.59%

Certain entities within the Group that are registered with the BOI are required to raise a minimum amount of capital in order to avail of their registration incentives. As of December 31, 2010 and 2009, these entities have complied with the requirement as applicable (see Note 37). No changes were made in the objectives, policies or processes during the years ended December 31, 2010 and 2009.

33. Financial Instruments

Set out below is a comparison by category of the carrying amounts and fair values of all of the Group’s financial instruments.

2010 2009

Carrying Amounts

Fair Values

Carrying Amounts

Fair Values

FINANCIAL ASSETS Loans and Receivables Cash and cash equivalents

Cash on hand and in banks P=3,055,662 P=3,055,662 P=2,255,660 P=2,255,660 Short-term investments 15,246,183 15,246,183 1,559,246 1,559,246

18,301,845 18,301,845 3,814,906 3,814,906 Trade and other receivables

Trade 5,897,988 5,897,988 3,606,224 3,606,224 Others 907,803 907,803 869,804 869,804

6,805,791 6,805,791 4,476,028 4,476,028 Restricted cash – – 560,423 560,423 25,107,636 25,107,636 8,851,357 8,851,357 Financial Assets at FVPL Derivative assets 7,670 7,670 846 846 AFS Financial Assets 3,744 3,744 3,744 3,744 25,119,050 25,119,050 P=8,855,947 P=8,855,947

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2010 2009

Carrying Amounts

Fair Values

Carrying Amounts

Fair Values

FINANCIAL LIABILITIES Other Financial Liabilities Bank loans P=1,979,800 P=1,979,800 P=5,828,100 P=5,828,100 Long-term debt Floating - long-term debt 636,433 636,433 – – Fixed rate - long-term debt 16,066,680 17,953,303 16,252,535 17,410,976 Payable to a preferred shareholder of a subsidiary 76,767 76,767 88,030 88,030 Finance lease obligation 48,305,116 58,268,048 45,586,164 52,946,954 67,064,796 78,914,351 67,754,829 76,274,060 Customers’ deposits

Bill deposits 382,977 382,977 337,372 337,372 Transformers, lines and poles 1,621,407 1,621,407 1,443,744 1,443,744

2,004,384 2,004,384 1,781,116 1,781,116 Long-term obligation on power

distribution system 282,559 413,057 287,460 376,639 Trade and other payables

Trade payables 2,063,082 2,063,082 1,765,531 1,765,531 Accrued expenses 706,692 706,692 202,742 202,742 Related parties 129,999 129,999 1,145,253 1,145,253 Other liabilities 1,978,260 1,978,260 2,200,458 2,200,458

5,160,592 5,291,090 5,601,444 5,690,623 74,229,772 86,209,825 75,137,389 83,745,799 Financial Liability at FVPL Derivative liabilities 323 323 16,476 16,476 74,230,095 86,210,148 P=75,153,865 P=83,762,275 As of December 31, 2010 and December 31, 2009, the Group does not have any investment in foreign securities. The Group has registered and issued P=3.00 billion worth of peso denominated fixed rate retail bonds on April 30, 2009. Fair Value of Financial Instruments Fair value is defined as the amount for which an asset could be exchanged or a liability settled between knowledgeable willing parties in an arm’s-length transaction, other than in a forced liquidation or sale. Fair values are obtained from quoted market prices, discounted cash flow models and option pricing models, as appropriate. A financial instrument is regarded as quoted in an active market if quoted prices are readily available from an exchange, dealer, broker, pricing services or regulatory agency and those prices represent actual and regularly occurring market transactions on an arm’s length basis. For a financial instrument with an active market, the quoted market price is used as its fair value. On the other hand, if transactions are no longer regularly occurring even if prices might be available and the only observed transactions are forced transactions or distressed sales, then the market is considered inactive. For a financial instrument with no active market, its fair value is determined using a valuation technique (e.g. discounted cash flow approach) that incorporates all factors that market participants would consider in setting a price.

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The following methods and assumptions are used to estimate the fair value of each class of financial instruments: Cash and cash equivalents, trade and other receivables, bank loans and trade and other payables. The carrying amounts of cash and cash equivalents, trade and other receivables and trade and other payables approximate fair value due to the relatively short-term maturity of these financial instruments. Restricted cash. The carrying value of the restricted cash approximates their fair value as they earn interest based on prevailing bank deposit rates. Derivative assets and liabilities. The fair value is calculated by reference to prevailing interest rate differential and spot exchange rate as of valuation date, taking into account its remaining term to maturity. Fixed-rate borrowings. The fair value of fixed rate interest-bearing loans is based on the discounted value of future cash flows using the applicable rates for similar types of loans. Interest-bearing loans were discounted using credit-adjusted interest rates ranging from 6.81% to 9.33% in 2010 and 7.34% to 9.84% in 2009. Floating-rate borrowings. Since repricing of the variable-rate interest bearing loan is done on a quarterly basis, the carrying value approximates the fair value. Finance lease obligation. The fair value of the finance lease obligation was calculated by discounting future cash flows using interest rates of 5.96% to 9.88% in 2010 and 5.00% to 9.00% in 2009 for dollar payments and 2.95% to 10.33% in 2010 and 9.00% to 14.00% in 2009 for peso payments. Long-term obligation on PDS. The fair value of the long-term obligations on power distribution system is calculated by discounting expected future cash flows at prevailing market rates. Discount rates used in discounting the obligation ranges from 2.53% to 7.60% in 2010 and 4.82% to 9.00% in 2009. Customers’ deposits. The fair value of bill deposits approximates the carrying values as these deposits earn interest at the prevailing market interest rate in accordance with regulatory guidelines. The timing and related amounts of future cash flows relating to transformer and lines and poles deposits cannot be reasonably and reliably estimated for purposes of establishing their fair values using an alternative valuation technique. AFS investments. These are carried at cost less impairment because fair value cannot be determined reliably due to the unpredictable nature of cash flows and lack of suitable methods of arriving at reliable fair value. Derivative financial instruments The Group enters into non-deliverable short-term forward contracts with counterparty banks to manage its foreign currency risks associated with foreign currency-denominated liabilities and purchases.

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As of December 31, 2010 and 2009, the Group has outstanding non-deliverable buy Dollar and sell Peso forward exchange contracts with counterparty banks with an aggregate notional amount of $56.4 million and $78.5 million, respectively and remaining maturities of less than1 month to 8 months and 1 month to 10 months, respectively. The forward rates related to the forward contracts ranged from P=43.84 to P=44.13 per US$ and P=46.40 to P=47.14 per US$1 as at December 31, 2010 and 2009, respectively. The Group recognized derivative asset relating to these contracts amounting to P=5.4 million as of December 31, 2010. The Group also recognized derivative asset and liability related to these contracts amounting to P=0.8 million and P=15.3 million, respectively, as of December 31, 2009. As of December 31, 2010 and 2009, the Group also has outstanding non-deliverable sell US Dollar buy EURO short-term forward exchange contracts with a counterparty bank with an aggregate notional amount of €2.24 million and €1.83 million, respectively and remaining maturities of 1 month to 8 months and less than 1 month to 3 months, respectively. As at December 31, 2010 and 2009, the forward rates related to the forward contracts ranges from €1.3291 to €1.3421 per US$1 and €1.4578 per US$1, respectively. As of December 31, 2010, the Group recognized derivative asset and liability relating to these contracts amounting to P=2.3 million and P=0.3 million, respectively. As of December 31, 2009, the Group recognized derivative liability related to these contracts amounting to P=1.2 million. The movements in fair value changes of all derivative instruments for the year ended December 31, 2010 and 2009 are as follows: 2010 2009 At beginning of year (P=15,630) P=– Net changes in fair value of derivatives not

designated as accounting hedges (39,969) (15,630) Fair value of settled instruments 62,946 – At end of year P=7,347 (P=15,630) The loss from the net fair value changes relating to the forward contracts amounting to P=40.0 million in 2010 and P=15.6 million in 2009 are included under “Net foreign exchange gains” in Note 27. Fair Value Hierarchy The Company uses the following hierarchy for determining and disclosing the fair value of financial instruments by valuation technique: Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities Level 2: other techniques for which all inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly Level 3: techniques which use inputs which have a significant effect on the recorded fair value that are not based on observable market data. Only the Group’s quoted AFS investments and derivative instruments, which are classified under Level 1 and Level 2, are measured and carried at fair value. During the reporting periods ending December 31, 2010 and 2009, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfers into and out of Level 3 fair value measurements were made.

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34. Registration with DOE

In accordance with its registration with the DOE under R.A. 7156 known as "Mini Hydro Electric Power Incentives Act" as mini hydro electric power developer HI is entitled to certain incentives among which are the special privilege tax at the rate of 2% on power sales, tax and duty free importation of machinery, equipment and materials, tax credit on domestic capital equipment and ITH. ITH, tax and duty free importation and tax credit on domestic capital equipment on all mini-hydroelectric power plants expired in 2000, except for the four (4) power plants located in Mintal, Tugbok, Davao City, acquired from PSALM, which were transferred on January 18, 2005 and started commercial operations on January 19, 2005. ITH on the four (4) plants started on September 28, 2005.

With the effectivity of R.A. 9136 known as “Electric Power Industry Reforms Act (EPIRA) of 2001”, sales of generated power by HI shall be subject to zero-rated VAT.

35. Lease Agreements TLI

TLI was appointed by PSALM as Administrator under the IPP Administration Agreement, giving TLI the right to receive, manage and control the capacity of the power plant for its own account and at its own cost and risk; and the right to receive the transfer of the power plant at the end of the IPP Administration Agreement for no consideration.

In view of the nature of the IPP Administration Agreement, the arrangement has been considered as a finance lease. Accordingly, TLI recognized the capitalized asset and related liability of P=44.79 billion (equivalent to the present value of the minimum lease payments using TLI’s incremental borrowing rates of 10% and 12% for dollar and peso payments, respectively) in the financial statements as “Power plant” and “Finance lease obligation” accounts, respectively. This is a non-cash acquisition of property, plant and equipment of the Group. The discount determined at inception of the IPP Administration Agreement is amortized over the period of the IPP Administration Agreement and is recognized as interest expense in the consolidated statements of income. Interest expense in 2010 and 2009 amounted to P=5.12 billion and P=1.23 billion, respectively (see Note 32).

Future minimum monthly dollar and peso payments under the IPP Administration Agreement and their present values as of December 31, 2010 and 2009 are as follows:

Dollar

payments

Peso equivalent of dollar

payments1 Peso

payments 2010

Total Within one year $12,000 P=526,080 P=576,000 P=1,102,080 After one year but not

more than five years 262,920 11,526,413 12,620,160 24,146,573 More than five years 938,000 41,121,920 45,024,000 86,145,920 Total contractual payments 1,212,920 53,174,413 58,220,160 111,394,573 Less unamortized discount 649,532 28,475,484 34,613,973 63,089,457 Present value $563,388 P=24,698,929 P=23,606,187 P=48,305,116

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Dollar

payments

Peso equivalent of dollar

payments2 Peso

payments 2009 Total

Within one year $12,000 P=554,400 P=576,000 P=1,130,400 After one year but not

more than five years 274,920 12,701,304 13,196,160 25,897,464 More than five years 938,000 43,335,600 45,024,000 88,359,600 Total contractual payments 1,224,920 56,591,304 58,796,160 115,387,464 Unamortized discount 703,465 32,500,079 37,301,221 69,801,300 Present value $521,455 P=24,091,225 P=21,494,939 P=45,586,164 1$1 = P=43.840 2$1 = P=46.200 APRI On May 25, 2009, APRI entered into a lease agreement with PSALM for a parcel of land owned by the latter on which a portion of the assets purchased under the APA is situated. The lease term is for a period of twenty-five (25) years commencing from the Closing Date as defined in the APA which falls on May 25, 2009. The rental fees for the whole term of 25 years amounting to P=492.0 million were paid in full after the receipt by APRI of the Certificate of Effectivity on the lease (see Notes 7 and 13). Total lease charged to operations amounted to P=19.7 million in 2010 and P=11.5 million in 2009 (see Note 24). HI and HSI HI and HSI entered into contracts with various lot owners for lease of land where their power plants are located. Terms of contract are for a period of 1 to 25 years renewable upon mutual agreement by the parties. Future minimum rental contract provisions are as follows (amounts in millions):

2010 2009 Not later than one year P=9.0 P=6.0 Later than 1 year but not later than 5 years 40.0 25.4 Later than 5 years 119.2 106.6

Total lease charged to operations related to these contracts amounted to P=5.4 million in 2010, P=2.5 million in 2009 and P=2.1 million in 2008, respectively (see Note 24).

36. Agreements Pagbilao IPP Administration Agreement

In August 2009, TLI was declared by PSALM as the winning bidder for the IPP Administration Agreement with a discounted bid price of US$691 million representing the present value of accumulated monthly payments of US$2.5 billion using PSALM’s discount rates. In September 2009, TLI and PSALM executed the IPP Administration Agreement wherein PSALM appointed TLI to manage the 700MW contracted capacity (the “Capacity”) of NPC in the coal-fired power plant in Pagbilao, Quezon. TLI assumed dispatch control of the contracted capacity on October 1, 2009.

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The IPP Administration Agreement includes the following obligations TLI would have to perform until the transfer date of the power plant (or the earlier termination of the IPP Administration Agreement):

a. Supply and deliver all fuel for the power plant in accordance with the specifications of the original Energy Conservation Agreement (ECA); and

b. Pay to PSALM the monthly payments (based on the bid) and energy fees (equivalent to the amount paid by NPC to the IPP).

TLI has the following rights, among others, under the IPP Administration Agreement:

a. The right to receive, manage and control the Capacity of the power plant for its own account and at its own cost and risk;

b. The right to trade, sell or otherwise deal with the Capacity (whether pursuant to the spot market, bilateral contracts with third parties or otherwise) and contract for or offer related ancillary services, in all cases for its own account and its own risk and cost. Such rights shall carry the rights to receive revenues arising from such activities without obligation to account therefore to PSALM or any third party;

c. The right to receive the transfer of the power plant at the end of the IPP Administration Agreement (which is technically the end of the ECA) for no consideration; and

d. The right to receive an assignment of NPC’s interest to existing short-term bilateral Power Supply Contract from the effective date of the IPP Administration Agreement to November 2011 only (see Note 20).

In view of the nature of the IPP Administration Agreement, the arrangement has been accounted for as a finance lease (see Note 35). Agreements with Contractors and Suppliers

a. Among the assumed contracts that APRI received from the APA is the Service Contract with

Chevron Geothermal Philippines Holdings, Inc. (CGPHI) which provides for the following:

i. Exploration and exploitation for APRI on the Geothermal Resources in the Area of Interest described in the Service Contract.

ii. CGPHI shall be the sole contractor responsible to APRI for the execution of services for the exploration and exploitation operations in accordance with the provisions of the Service Contract and, in accordance with the terms hereof, is hereby appointed as the sole contractor of NPC for such purposes in connection with the Area of Interest.

iii. CGPHI shall furnish technical assistance required for the exploration for and exploitation of Geothermal Resources in order to make geothermal steam available for utilization into electric power, and shall recover its operating costs and realize its return solely from the sale of power produced from the Geothermal Energy.

iv. APRI shall provide and defray Philippine currency expenses to the extent hereinafter set forth necessary in the exploration for and exploitation of Geothermal Resources and Utilization of geothermal steam for electric power.

v. APRI shall provide and install at its own expense and with the technological assistance of CGPHI as hereinafter provided, such plants, machineries and auxiliary works as may be necessary for the conversion of geothermal steam into electric power and distribution of such power.

Total steam supply cost incurred by APRI, reported as part of “Cost of generated power” amounted to P=3.54 billion in 2010 and P=2.21 billion in 2009 (see Note 22).

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b. In connection with the Sibulan hydropower project, HSI entered into agreements with various contractors and suppliers. Major agreements entered into as of December 31, 2009 included those for the construction of civil works and electro-mechanical works and project management. Total purchase commitments entered into by the Company from their contracts amounted to P=3.03 billion and $25.0 million as of December 31, 2010 and P=2.74 billion and $24.1million as of December 31, 2009. Total payments made from the commitments amounted to P=2.96 billion and $23.0 million as of December 31, 2010 and P=2.57 billion and $19.8 million as of December 31, 2009. These amounts are presented as part of “Other receivables” and “Construction in progress” in the consolidated balance sheets. In 2010, construction of the power plants has been completed.

c. TLI enters into short-term coal supply agreements. Outstanding coal supply agreements as of December 31, 2010 have aggregate supply amounts of 495,089 MT (equivalent dollar value is $38 million) which are due for delivery from January 10, 2011 to April 7, 2011. Terms of payments are by letter of credit where payment is due at sight against presentation of documents, and by telegraphic transfer where payment is due within 7 days from receipt of original invoice. Outstanding coal supply agreements as of December 31, 2009 have aggregate supply amounts of 202,112 metric tons (equivalent dollar value is $12.5 million) which are due for delivery from January 30, 2010 to March 3, 2010. Terms of payment are by letter of credit where payment is due at sight against presentation of documents, and by telegraphic transfer where payment is due within 7 days from receipt of original invoice.

Agreements with the Government

On October 29, 2007, HTI, a subsidiary, entered into agreements with various barangays in Davao City wherein each barangay gives its consent to HTI to manage, administer, regulate and undertake the construction of HTI’s hydroelectric power plants and other related activities in their respective areas. In consideration thereof, HTI shall pay each of the barangay an annual royalty fee in an amount equivalent to P=0.01 per kWh of electricity sales of the power plant located within their area to be paid annually beginning the first anniversary date of the commencement of HTI’s commercial operations and on every anniversary date thereafter to be increased by P=0.001 every 5 years. In addition to the royalty fee, HTI shall make donations for the undertaking of certain infrastructure projects and provide financial assistance for the various needs of the community. The agreement likewise provides that HTI shall comply with Sec. 5(i) of R.A. No. 7638 as implemented by ER No. 1-94 as amended, prescribing the following annual benefits during the operation of the power stations: a) electrification fund to be distributed to the relevant host LGU equivalent to P=0.0075 per kWh of the total electricity sales; b) development and livelihood fund to be shared by the province, municipality, barangay and region equivalent to P0.00125 per kWh of the total electricity sales; and c) reforestation, watershed management, health and/or environmental enhancement fund to be shared by the resettlement area, barangay, municipality, province and region equivalent to P=1.00125 per kWh of the total electricity sales. The duration of the agreements is for a period of 25 years and renewable for another 25 years as agreed by the Barangay Council of Wines and HTI.

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37. Registration with the Board of Investments (BOI) APRI On June 19, 2009, the BOI approved APRI’s application as a new operator of the Tiwi-MakBan Power Plant and granted APRI a pioneer status under the Omnibus Investments Code of 1987. The following are the incentives granted by BOI to APRI: a. ITH for six (6) years from June 2009 or actual start of commercial operations/selling,

whichever is earlier but in no case earlier than the date of registration. The ITH shall be limited only to sales/revenue generated from the sales of electricity of the Tiwi-MakBan Power Plant. Revenues generated from the sales of carbon emission reduction credits are also entitled to ITH.

b. For the first five (5) years from date of registration, APRI shall be allowed an additional deduction from taxable income of fifty percent (50) of the wages corresponding to the increment in the number of direct labor for skilled and unskilled workers in the year of availment as against the previous year if the project meets the prescribed ratio of capital equipment to the number of workers set by BOI of $10 to one worker and provided that this incentive shall not be availed of simultaneously with the ITH.

c. Employment of foreign nationals may be allowed in supervisory, technical or advisory

positions for five (5) years from date of registration.

d. Importation of consigned equipment for a period of ten (10) years from the date of registration, subject to the posting of re-export bond.

e. APRI may qualify to import capital requirement, spare parts and accessories at zero (0%) duty

rate from the date of registration to June 16, 2011 pursuant to Executive Order No. 528 and its Implementing Rules and Regulations.

The following are the significant specific terms and conditions for the availment of the ITH:

a. APRI shall start commercial operations in June 2009.

b. APRI shall increase its authorized, subscribed and paid-up capital stock to at least

P=5.70 billion and shall submit proof of compliance prior to availment of ITH. This condition was superseded by a BOI letter dated September 18, 2009 clarifying that for the purposes of BOI registration, the BOI has redefined the term equity such that, it shall now cover not only the paid-up capital stock but also other items in the Balance Sheet of the Audited Financial Statements, i.e., additional paid in capital stock and retained earnings. Hence, if APRI has at least 25%of stockholders equity as shown in the Audited Financial Statements, it is deemed complied with the 25% equity requirement and is no longer required to increase its capital stock.

c. APRI shall secure a Certificate of Compliance from ERC prior to start of commercial

operations.

d. APRI is enjoined to undertake Corporate Social Responsibility Projects/Activities.

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TLI On December 23, 2009, the BOI pre-approved TLI’s application for registration as a new operator of the power plant on a non-pioneer status. Once approved, TLI will be entitled with the following incentives:

a. ITH for a period of four (4) years without extension from January 1, 2010 or actual start of

operation, whichever is earlier but in no case earlier than the date of registration. The ITH incentives shall be limited only to the sales/revenue generated from the sale of electricity of the power plant.

b. For the first five (5) years from date of registration, TLI shall be allowed an additional

deduction from taxable income of 50% of the wages corresponding to the increment in number of direct labor for skilled and unskilled workers in the year of availment as against the previous year if the project meets the prescribed ratio of capital equipment to the number of workers set by the Board of US$10 to one (1) worker and provided that this incentive shall not be availed of simultaneously with the ITH.


positions for five (5) years from date of registration. The president, general manager and treasurer of foreign-owned registered firms or their equivalent shall not be subject to the foregoing limitations.

d. Importation of consigned equipment for a period of ten (10) years from date of registration,

subject to the posting of re-export bond.

On February 26, 2010, TLI submitted to BOI all its requirements with a commitment to comply with the 25% minimum equity requirement of P=490.0 million prior to the availment of ITH incentives. As of December 31, 2010, TLI has complied with the minimum equity requirement through deposits for future stock subscriptions received on September 24, 2010. Therma Marine On May 28, 2010, the BOI pre-approved Therma Marine’s application for registration as a new operator of PB118 and PB117. Once approved, Therma Marine will be entitled to the following incentives:

a. ITH for a period of four (4) years without extension from May 1, 2010 or actual start of

operation, whichever is earlier but in no case earlier than the date of registration. The ITH incentives shall be limited only to the sales/revenue generated from the sale of electricity of the power plant.

b. For the first five (5) years from date of registration, Therma Marine shall be allowed an

additional deduction from taxable income of 50% of the wages corresponding to the increment in number of direct labor for skilled and unskilled workers in the year of availment as against the previous year if the project meets the prescribed ratio of capital equipment to the number of workers set by the Board of US$10,000 to one (1) worker and provided that this incentive shall not be availed of simultaneously with the ITH.


positions for five (5) years from date of registration. The president, general manager and treasurer of foreign-owned registered firms or their equivalent shall not be subject to the foregoing limitations.

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d. Importation of consigned equipment for a period of ten (10) years from date of registration, subject to the posting of re-export bond.

In February 2011, Therma Marine submitted to BOI all its requirements with a commitment to comply with all the requirements prior to the availment of ITH incentives. HSI On December 27, 2005, the BOI approved HSI’s application as new operator of the 42 MW Hydroelectric Power Plants and granted HSI a pioneer status under the Omnibus Investments Code of 1987. The BOI issued the Certificate of Registration on the same date which entitled HSI with the following incentives: a. ITH for a period of six years from January 2009 or actual start of commercial operations,

whichever is earlier, but in no case earlier than the date of registration. The ITH incentives shall be limited only to the sales/revenue generated from the sales of electricity. HSI can avail of bonus year in each of the following cases but the aggregate ITH availment (basic and bonus years) shall not exceed 8 years; • The ratio of the total imported and domestic capital equipment to the number of workers

for the project does not exceed US$10,000 to one (1); or

• The net foreign exchange savings or earnings amount to at least US$500,000 annually during the first three (3) years of operation; and

• The indigenous raw materials used in the manufacture of the registered product must at

least be fifty percent (50%) of the total cost of raw materials for the preceding years prior to the extension unless the BOD prescribes a higher percentage.

b. For the first five (5) years from December 27, 2005, HSI shall be allowed an additional

deduction from taxable income of 50% of the wages corresponding to the increment in number of direct labor for skilled and unskilled workers in the year of availment as against the previous year if the project meets the prescribed ratio of capital equipment to the number of workers set by the BOD of US$10,000 to one (1) worker and provided that this incentive shall not be availed of simultaneously with the income tax holiday.

c. Employment of foreign nationals may be allowed in supervisory, technical or advisory positions for five (5) years from date of registration. The president, general manager and treasurer of foreign-owned registered firms or their equivalent shall not be subject to the foregoing limitations.

d. Importation of consigned equipment for a period of ten (10) years from date of registration,

subject to the posting of re-export bond. On May 4, 2009, the BOI granted HSI’s request for the movement of start of commercial operation, as well as the movement of the ITH incentive reckoning date from January 2009 to March 2010. Furthermore, the project’s registered capacity was also amended from 42 MW to 42.5 MW.

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38. Other Matters

a. Therma Marine Case As of December 31, 2010, Therma Marine has outstanding cases with the ERC regarding the approved ancillary service and procurement rates under the ASPAs approved on October 4, 2010. The rates approved by ERC are lower than the rates approved under the provisional authority it granted in March 2010. Consequently, in November 2010, Therma Marine filed a motion for reconsideration with ERC negotiating the increase in rates. While waiting for the ERC decision on the motion for reconsideration, Therma Marine started to recognize revenues using the approved rates by ERC.

b. CPPC and EAUC Cases On August 20, 1999, CPPC and EAUC (the Complainants); a subsidiary and an associate, respectively, filed a complaint before the ERB against NPC for a refund/credit and/or collection of inapplicable/unauthorized tariffs with prayer for a cease and desist order and or preliminary injunction. The Complainants contended, among others, that they need not pay PDS because their facilities are embedded in the power distribution network of VECO. The Power Delivery Service charges are applicable to IPPs using the transmission facilities in transporting power. Consequently, an IPP need not pay Power Delivery Service if its facilities are embedded in the distribution network. On June 28, 2001, the ERB rendered a decision directing, among others, NPC to cease and desist from charging the Complainants the Power Delivery Services and to refund all amounts collected by reason thereof to NPC who, if they so desire, may opt to credit or apply the same to their future billings from the Complainants. NPC filed a motion for reconsideration with the ERC which replaced the then ERB. On March 28, 2003, the ERC issued decisions affirming the June 28, 2001 decisions with certain modifications on some decisions. NPC filed a petition for review with the Court of Appeals (CA). On December 14, 2005, the CA rendered a Decision affirming in toto the Decision dated June 28, 2001 of the ERB as modified by the Order dated March 28, 2003 of the ERC. Further, on December 14, 2006, the Supreme Court (SC) upheld in toto, the Decision dated June 28, 2001 of the ERB as modified by the Order dated March 28, 2003 of the ERC. Further, the instant Petition for Review was denied for lack of merit. Pursuant to Section 8 of RA No. 9136, EPIRA of 2001, TransCo was created and assumed the electrical transmission functions of the NPC. TransCo also assumed the legal responsibilities relative to the aforementioned case.

CPPC and EAUC applied the total contested amounts against TransCo billings from November 26, 2004 to February 25, 2006. However, pending SC’s final and irrevocable decision, CPPC and EAUC continued to accrue its liabilities to NPC for these billing periods. Total accruals for these billing periods amounted to P=98.9 million as of December 31, 2008 and 2007 and are presented as part of trade payables. On October 29, 2008, the SC issued a Notice of Judgment that denied NPC’s petition and affirmed the decision of the CA.

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As of January 23, 2009, CPPC has completed the process of reconciliation with NGCP, which took over the operations of TransCo, the first claim of P=49.5 million. As of March 31, 2010, NGCP and the CPPC are still in the process of reconciling the second claim amounting to P=49.4 million. Although no formal agreement as to the amount for the second claim has been reached yet between the CPPC and NGCP, since the results of the reconciliation process of the first claim did not result to any significant difference, it is expected that the full amount of the second claim can be substantially recovered. With this, as of December 31, 2009, CPPC applied both claims totaling to P=97.3 million against the Power Delivery Service charge accruals presented as part of “Trade and other payables” account and recognized other income of the same amount.

c. DLP Case

On December 7, 1990, certain customers of DLP filed before the then Energy Regulatory Board (ERB) a letter-petition for recovery claiming that with the SC’s decision reducing the sound appraisal value of DLP’s properties, DLP exceeded the 12% Return on Rate Base (RORB). The ERB’s order dated June 4, 1998, limited the computation coverage of the refund from January 19, 1984 to December 14, 1984. No amount was indicated in the ERB order as this has yet to be recomputed. The CA, in Court of Appeals General Register Special Proceeding (CA-GR SP) No. 50771, promulgated a decision dated February 23, 2001 which reversed the order of the then ERB, and expanded the computation coverage period from January 19, 1984 to September 18, 1989. The SC in its decision dated November 30, 2006 per GR150253 reversed the CA’s decision CA-GR SP No. 50771 by limiting the period covered for the refund from January 19, 1984 to December 14, 1984, approximately 11 months. The respondent/customers filed a Motion for Reconsideration with the SC, which was denied with finality by the SC in its Order dated July 4, 2007. The SC, following its decision dated November 30, 2006, ordered the ERC to proceed with the refund proceedings instituted by the respondents with reasonable dispatch. On March 17, 2010, the ERC directed DLP to submit its proposed scheme in implementing the refund to its customers. In compliance with the order, the DLP filed its compliance stating that DLP cannot propose a scheme for implementing a refund as its computation resulted to no refund. A clarificatory meeting was held where DLP was ordered to submit its memoranda. On October 4, 2010, in compliance with the ERC directive, DLP submitted its memoranda reiterating that no refund can be made.

d. LHC Arbitration LHC is a party to a dispute with a contractor regarding the delay in the completion of its Power Station. Under the Turnkey Contract, the contractor shall pay liquidated damages for each day of delay on the following day without the need of demand from LHC. LHC may, without prejudice to any other method of recovery, deduct the amount of such damages from any monies due or to become due to the contractor and/or by drawing on the irrevocable and confirmed standby letters of credit amounting to US$18 million (the Security).

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Due to the delay in the completion of the Power Station, LHC, in 2000 and 2001, withdrew the irrevocable and confirmed standby letters of credit amounting to about $18.0 million which Transfield Philippines, Inc. has constituted as security to LHC as required under the Turnkey Contract. The withdrawal of the standby letters of credit became the subject of court cases in Australia and the Philippines. In 2008, both parties entered into a Settlement Deed (the Settlement) for the purpose of settling all claims and disputes related to the Turnkey Contract, including the Final Award. As a result of the Settlement, all related cases in the Philippines and Australia were dismissed following the parties’ Joint Motion to Dismiss filed with relevant courts.

e. EPIRA of 2001 R.A. No. 9136 was signed into law on June 8, 2001 and took effect on June 26, 2001. The law provides for the privatization of NPC and the restructuring of the electric power industry. The IRR were approved by the Joint Congressional Power Commission on February 27, 2002.

R.A. No. 9136 and the IRR impact the industry as a whole. The law also empowers the ERC to enforce rules to encourage competition and penalize anti-competitive behavior. R.A. Act No. 9136, the EPIRA, and the covering IRR provides for significant changes in the power sector, which include among others: i. The unbundling of the generation, transmission, distribution and supply and other

disposable assets of a company, including its contracts with IPPs and electricity rates; ii. Creation of a WESM; and iii. Open and non-discriminatory access to transmission and distribution systems. The law also requires public listing of not less than 15% of common shares of generation and distribution companies within 5 years from the effectivity date of the EPIRA. It provides cross ownership restrictions between transmission and generation companies and a cap of 50% of its demand that a distribution utility is allowed to source from an associated company engaged in generation except for contracts entered into prior to the effectivity of the EPIRA. There are also certain sections of the EPIRA, specifically relating to generation companies, which provide for a cap on the concentration of ownership to only 30% of the installed capacity of the grid and/or 25% of the national installed generating capacity.

f. Renewable Energy Act of 2008 On January 30, 2009, R.A. No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energy Resources and for Other Purposes, which shall be known as the “Renewable Energy Act of 2008” (the Act), became effective. The Act aims to (a) accelerate the exploration and development of renewable energy resources such as, but not limited to, biomass, solar, wind, hydro, geothermal and ocean energy sources, including hybrid systems, to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels and thereby minimize the country’s exposure to price fluctuations in the international markets, the effects of which spiral down to almost all sectors of the economy; (b) increase the utilization of renewable energy by institutionalizing the development of national and local capabilities in the use of renewable energy systems, and promoting its efficient and cost-effective commercial application by providing fiscal and non-fiscal incentives; (c) encourage the development and utilization of renewable energy resources as tools to effectively prevent or reduce harmful emissions and thereby balance the goals of economic growth and development with the

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protection of health and environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws. As provided for in the Act, renewable energy (RE) developers of RE facilities, including hybrid systems, in proportion to and to the extent of the RE component, for both power and non-power applications, as duly certified by the DOE, in consultation with the BOI, shall be entitled to incentives, such as, income tax holiday, duty-free importation of RE machinery, equipment and materials, zero percent VAT rate on sale of power from RE sources, and tax exemption of carbon credits, among others. The Group expects that the Act may have significant effects on the operating results of some of its subsidiaries and associates that are RE developers. Impact on the operating results is expected to arise from the effective reduction in taxes.

g. CSR Projects The Group has several CSR projects in 2010 and 2009 which are presented as part of “General and administrative expenses” (see Note 23).

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