AP SEC FORM 17-A (Annual Report 2011) CLEAN COPYdisclosures.aboitizpower.com/20120417054940.pdf · In December 1978, ACO divested its ownership interests in the Ormoc Electric Light

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ANNUAL REPORT 2011

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 2011 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, 2011) 7,358,604,307 Total Debt (as of December 31, 2011) P73, 197,511, 000.00 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 2011, aggregate voting stock of registrant held outside of its affiliates and/or officers and employees totaled 1,492,129 shares (for details please refer to the attached notes to financial statements and Schedule H of this report) while its average market price per share was P29.82. 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 P44,495,286.78.

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 March 30, 2012.

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, through its wholly owned subsidiary, Therma Power, Inc. (TPI), entered into a memorandum of agreement with Taiwan Cogeneration International Corporation (TCIC) to collaborate in the building and operation of an independent coal‐fired power plant in the Subic Bay Freeport Zone (SBFZ). In May 2007 Redondo Peninsula Energy, Inc. (RP Energy) was incorporated as the project company that will undertake the Subic Coal Project. In June 2011, TPI entered into a Shareholders Agreement with TCIC and Meralco PowerGen Corporation (MPGC) to formalize MPGC’s participation in the Subic Coal Project. On July 22, 2011, MPGC acquired a majority interest in RP Energy through a Share Purchase Agreement with TCIC and TPI. MPGC took the controlling interest in RP Energy, while TCIC and TPI maintained their remaining stake equally. Commercial operations of the Subic Coal Project is projected to commence in 2014.

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 Philippines). 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 P5.80 per share in exchange for the foregoing equity interests in MEZ, BEZ and SEZ.

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.

In August 2007, the Company, together with Vivant Energy Corporation (Vivant) 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 3 x 82 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 (Cebu Energy), a joint venture company among Global Power, Formosa Heavy Industries and Abovant, broke ground last January 2008 and started full commercial operations on February 26, 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 P92 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 2008, AboitizPower bought the 40% equity ownership of Tsuneishi Holdings (Cebu), Inc. (THC) in BEZ for approximately P178 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 Mobile 1 and Mobile 2 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. Mobile 2 and Mobile 1 are moored at Nasipit, Agusan del Norte and Barangay San Roque, Maco, Compostela Valley, respectively. Prior to AboitizPower’s acquisition of the barges, Mobile 1 was referred to as Power Barge (PB) 118 while Mobile 2 was referred to as PB117.

On May 27, 2011, Therma Mobile, Inc. (Therma Mobile), a wholly‐owned subsidiary of AboitizPower, acquired four barge‐mounted floating power plants, including their respective operating facilities from Duracom Mobile Power Corporation and East Asia Diesel Power Corporation.

The Company plans to implement 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 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 “C” 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, 2011, 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, 2011.

Generation Companies

Energy Sold

Generation

Energy Sold

Generation

Energy Sold

Generation

Revenue

Revenue

Revenue

2011 2010 2009 2011 2010 2009

(In GWh) (in Mn Pesos) APRI 1 3,310 3,483 1,886 14,721 16,383 6,843 Hedcor, Inc. 170 155 171 853 704 703 LHC 251 282 324 633 935 1,223 Hedcor Sibulan 205 108 N/A 1,056 529 N/A SNAP ‐ Magat 615 673 1,150 12,572 7,804 3,971 SNAP ‐ Benguet 330 265 413 4,028 2,828 1,063 TLI 2 3,402 3,540 767 17,595 22,426 2,801 Cebu Energy 3 1,336 561 N/A 7,511 N/A N/A STEAG 1,456 1,553 1,384 7,549 6,577 6,206 WMPC 443 498 220 1,352 1,319 1,207 SPPC 268 315 226 707 707 688 CPPC 110 246 318 1,551 2,043 2,119 EAUC 95 224 202 993 1,741 1,382 TMI 4 517 767 N/A 5,110 4,898 N/A Davao Light 5 0 41 4 Revenue

neutral Revenue neutral

Revenue neutral

Cotabato Light 6 0 5 1 Revenue neutral

Revenue neutral

Revenue neutral

TOTAL 12,508 12,716 7,069 76,231 74,937 28,206 (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 Cebu Energy 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) Mobile 1 and Mobile 2 were turned over to TMI on 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. (6) Ibid.


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 16 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 42.2 MW.

• 100% 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 210 MW Ambuklao‐Binga Hydroelectric Power Plant Complex in Northern Luzon.

• 100% equity interest in Hedcor Sibulan, Inc. (Hedcor Sibulan), which operates the 42.5 MW Sibulan Hydroelectric Plants 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 467 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. On December 26, 2011, APRI, together with its affiliates, TLI, signed a letter agreement with the PSALM, the NPC and the Manila Electric Company (MERALCO) for the extension of the term of the respective load allocations of APRI and TLI. The extension, which was pursuant to the one‐year extension of the MERALCO‐NPC Transition Supply Contract (TSC) dated November 22, 2006 extended APRI’s load allocation for a period of 12 months effective December 26, 2011. 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 P10.1 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 for the period of 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.

The half‐life refurbishment of Unit No. 4 of SNAP‐Magat was completed in 2011, 47 days ahead of schedule. With Unit 4 under refurbishment from January to April 2011, SNAP‐Magat Plant generated 522.413 GWh, registered forced outage hour of 88.74 and its plant availability factor was 98.85%.


Continual high capability of SNAP‐Magat due to low water utilization and high dam elevation increased the capacity approval of SNAP‐Magat in 2011 compared to 2010. The refurbishment of SNAP‐Magat Unit 4 increased the capacity nominated to AS from 285 MW to 380 MW (or an increase of 95 MW). The capability of SNAP‐Magat as AS provider was re‐certified in July 2011. In 2011, Magat delivered 2,376,450 MWh of AS amounting to P9.9 bn.

SNAP‐Magat is looking at a two‐phase Expansion Project composed of: (1) the optimization of the Maris Reservoir Project that aims to increase the storage capacity of the Maris Reservoir (used as a re‐regulating dam to regulate the releases from the Magat HEPP); and (2) the Magat‐Pumped Storage Project which intends to install up to 115 MW of pumped storage generating capacity in addition to the existing 360 MW Magat HEPP. An MOU for the technical cooperation in the pre‐development of the Maris Optimization was entered into by SNAP‐Magat and NIA on July 15, 2011. Currently, the Project is in its final feasibility stage and is in the process of securing its Environmental Compliance Certificate (ECC) from the DENR‐EMB.

The first phase of the efficient water use campaign DALOY Magat or “Dependable Agriculture and Livelihood through Optimized Water Use Yearlong in Magat” was also implemented. After only eight months of implementation, water use in the target areas in the South High Canal and Oscariz Main Canal exhibited a decrease of 17.94 million cubic meters (MCM) of water consumption by farmers and fishpond operators. Data showed that from January to August of 2011, the water consumed by the target communities averaged 37.63 MCM while water consumption for the same period in 2009 averaged 55.57 MCM.

The Magat Plant retained its quality management system certification with its successful first surveillance audit for QMS ISO 9001. It also passed its second surveillance audit for its health and management system (OHSAS 18001). Aside from the QMS ISO Certification, SNAP‐Magat also received several awards in the year 2011. The Magat Plant received an award in December 2011 from the Department of Labor and Employment (DOLE) for its 2010 record of no Lost Time Incident (LTI) of 303,680 man‐hours. Since SNAP ‐ Magat took over in 2006, the Magat Plant accumulated 1,524,039 man hours LTI free as of December 31, 2011. The Magat Plant also received a Silver Award for Independent Power Producer of the Year at the 2011 Asian Power Awards in Malaysia. Further, its management committee was also a finalist in the Best Executive Leadership category at the 2011 Asia CEO Awards held in Makati.

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 USD 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.

The rehabilitation of the Ambuklao Plant commenced in late 2008, after under going preservation since 1999 due to damage from the 1990 earthquake. As of July 2010, all three units were in operation. As of start of testing and commissioning, each unit was already generating revenues due to the timely processing and issuance of provisional COC’s for each unit.

On June 2, 2011, the new Ambuklao started commercial operations of Unit No. 3 after 12 years of shutdown. The final COC was secured from ERC on August 31, 2011. The re‐operation of Ambuklao was marked by the national and local inauguration ceremonies on October 26 and 27, 2011, respectively. The refurbishment of the Binga Pant 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 Binga Plant is currently undergoing refurbishment of its four units to increase capacity from 100 MW to 120 MW. Replacement of Unit No. 4 main inlet valve (MIV) was done from April 21 to May 1, 2011. The completion of the MIV replacement triggered the start of rehabilitation and upgrading of Unit No. 4 which started on May 2, 2011. The rehabilitation and upgrading of Unit No. 4 from 25 MW to 31.5 MW was completed on December 20, 2011 and was put on trial and commercial operation on December 21, 2011. SNAP Benguet received its Certificate of Compliance (COC) from the ERC on March 26, 2012. The COC is valid for five years starting March 12, 2012.

With the Binga Plant’s Unit 4 under refurbishment, Binga Plant generated 25.047 GWh, registered forced outage hour of 41.64 and its plant availability factor was 72.94%. On the other hand, Ambuklao Plant generated 319.999 GWh, registered a forced outage hour of 63.47 and availability factor of 85.50%

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.

The capability of Binga as AS provider was re‐certified in June 2011. Only units 1, 2, and 3 were tested since Unit No. 4 was under refurbishment. In 2011, Binga delivered 624,159 MWh of AS amounting to P2.4 bn. The Ambuklao Plant was successfully tested as provider of ancillary services in September 2011. Both Ambuklao Plant and Binga Plant received numerous awards in the year 2011. In December 2011, both plants were awarded by the DOLE for its 2010 record of no LTI of 372,305 man‐hours and 503,095.50 man‐hours, respectively. Since SNAP took over in 2008, Ambuklao accumulated 1,385,531 man hours LTI free as of Dec. 31, 2011 while Binga posted 1,539,920 man‐hours LTI free in the same period for a combined total of 2,925,451 man‐hours LTI‐ free.


Both plants were registered as Clean Development Mechanism (CDM) projects by the United Nations Framework Convention on Climate Change (UNFCCC). Collectively, the plants will produce an average of 180,000 carbon emission reduction credits (CERs) per year. The CDM registration is the first of its kind in the Philippines at the time of the issuance. Binga Plant received its management system certification for QMS ISO 9001 and passed its first surveillance audit for OHSAS 18001. Further, the Binga Plant won a Silver Award in the Independent Power Producer of the Year category and the resurgent Ambuklao Plant garnered a Silver Award in the Renewable Energy Power Plant category. In 2011, SNAP‐Benguet won a Gold Award as Environmental Company of the Year. Its management committee was also a finalist in the Best Executive Leadership category at the 2011 Asia CEO Awards held in Makati. 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 Cleanergy, 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. The electricity generated from Hedcor’s hydro plants are taken up by NPC, APRI, Davao Light, Benguet Electric Cooperative (BENECO) pursuant to power purchase agreements with the said offtakers and sold to the Wholesale Electricity Spot Market (WESM). 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) Up until May 10, 2011, LHC was 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. Effective May 10, 2011, ARI assumed full ownership and control of LHC upon fulfillment of certain conditions in the MOA. The total transaction value was 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 September 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 P4.0856/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 CDM project with the UNFCC under the Kyoto Protocol. The project is expected to generate carbon credits that will eventually be traded in the carbon market. 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) to settle the dispute on the Tamugan water rights. Originally planned as a 27.5 MW run‐of‐river facility, Hedcor Tamugan proposed the construction of an 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, the municipality of Sabangan and the Mountain Province in


February, March and July 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.

Hedcor Sabangan obtained an ECC in October 2011, while the other permits required for the project, such as the water rights and the Special Land‐Use Permit (SLUP), are currently being processed. The two‐year construction period is expected to commence in the fourth 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 Tudaya 1 and Tudaya 2 run‐of‐river hydropower projects with combined capacity of 13.7 MW 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.

Most of the permits required for the project, such as ECC have been obtained, while the water rights is currently being processed. The two‐year construction period is expected to commence in March 2012. 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 Mobile 2 and Mobile 1, barge‐mounted power plants, each with a generating capacity of 100 MW.

• 26% effective interest in Cebu Energy, which operates a 3 x 82 MW coal‐fired power plant in Toledo City, Cebu.

• 25% equity interest in RP Energy, the project company that proposes to build and operate a 600 MW coal‐fired power plant in Redondo Peninsula in the 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.

• 100% equity interest in Vesper Industrial and Development Corporation, the project company that proposes to build a coal plant in Bato, Toledo, Cebu. Vesper is currently applying for the change of its corporate name to Therma Visayas, Inc. with the SEC.

• 100% equity interest in Therma Mobile, owner of four barge‐mounted power plants in Navotas Fishport, Manila.


AboitizPower plans to implement 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 TPI, 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. On December 26, 2011, TLI, together with its affiliate, APRI, signed a Letter Agreement with the PSALM, the NPC and MERALCO for the extension of the term of the respective load allocations of APRI and TLI. The extension, which was pursuant to the one year extension of the MERALCO ‐ NPC Transition Supply Contract (TSC) dated November 22, 2006, extended TLI’s load allocation for up to 12 months starting December 26, 2011, subject to the finalization of a power supply agreement (PSA) to be executed by and between MERALCO and TLI. On February 29, 2012, TLI signed a PSA with MERALCO which shall be effective upon approval by the Energy Regulatory Commission (ERC).

Therma Marine, Inc. (TMI) TMI is a wholly owned subsidiary of TPI. It owns and operates Power Barges Mobile 1 (previously known as PB 118) and Mobile 2 (previously known as PB 117) and has a total generating capacity of 200 MW. Mobile 1 is currently moored at Barangay San Roque, Maco, Compostela Valley while Mobile 2 is moored at Barangay Sta. Ana, Nasipit, Agusan del Norte. TMI assumed ownership of Mobile 1 and Mobile 2 from PSALM last February 6, 2010 and March 1, 2010, respectively, after the successful conclusion of the USD30 mn negotiated bid for the barges last July 31, 2009. TMI signed a one‐year Ancillary Service Procurement Agreements (ASPA) with the NGCP to supply ancillary services consisting of contingency reserve, dispatchable reserve, reactive power support and blackstart capacity for the Mindanao Grid. The ASPA of each of the Power Barges is for the supply 50 MW of ancillary power to NGCP. The contracts have been extended up to June 2012, and may still be


renewed, subject to the agreement of the parties. In the event the ASPA are not renewed by NGCP, TMI may opt to offer ancillary services to distribution and industrial customers in Mindanao. On December 5, 2011, TMI signed Energy Supply Agreements with various cooperatives, industrial and commercial customers in Mindanao for a total of 109.2 MW. Of the 109.2 MW, 86.2 MW were already effective, 17 MW are awaiting provisional approval from ERC, and 6 MW are due for filing with the ERC. Therma Mobile, Inc. (Therma Mobile)

Therma Mobile is a wholly owned subsidiary of TPI. On May 27, 2011, Therma Mobile acquired four barge‐mounted floating power plants located at Navotas Fishport, Manila from Duracom Mobile Power Corporation and East Asia Diesel Power Corporation. The barge‐mounted floating power plants have a total generating capacity of 242 MW.

The power barges are currently undergoing rehabilitation.

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. 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 six‐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.

STEAG’s COC has been renewed by the ERC until May 2016.


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 Energy Power Purchase Agreement (EPPA), with the Philippine Economic Zone Authority (PEZA) which took effect on April 26, 2011, PEZA shall purchase from EAUC for 22 MW of electric power or equivalent to two engines. EAUC also signed an EPPA with BEZ for the supply of power equivalent to 5.255 MW for a period of five years starting May 25, 2011 until May 25, 2016.

On December 26, 2010, EAUC started supplying power to the WESM. 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, 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. Effective December 26, 2010, CPPC started selling its excess capacity to the WESM. Abovant Holdings, Inc. (Abovant) and Cebu Energy Development Corporation (Cebu Energy)

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. (Global Formosa), a joint venture between Global Business Power Corporation of the Metrobank Group and Formosa Heavy Industries, Inc. formed Cebu Energy. Cebu Energy is the owner of a new 3 x 82 MW coal‐fired power plant situated within the 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 shall provide for the 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), the modular fabrication facility of Metaphil International, and the newest locator in WCIP, Austal Philippines Pty. Limited. The power plant which cost approximately USD450 mn, was completed and started full commercial operations in the first quarter of 2011. Cebu Energy had signed an EPPA with VECO for the supply of 105 MW of electricity 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 the 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 the 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 originally owned by AboitizPower and TCIC equally. On July 22, 2011, Meralco PowerGen Corporation acquired a majority interest in RP Energy by virtue of a Share Purchase Agreement with TPI, a wholly‐owned subsidiary of AboitizPower and TCIC, retaining an equal ownership interest of 25% each less one share. In view of increasing power demand in the Luzon Grid and with the entry of Meralco PowerGen, RP Energy plans to expand its original proposal to build and operate a 300‐MW coal‐fired power plant in Redondo Peninsula within the SBFZ into a 2 x 300‐MW (net) power plant upon approval of an amendment to its existing ECC. RP Energy has also completed the voluntary relocation of all affected residents in the site in accordance with existing Philippine rules and regulations and accepted international standards, and it is now the in the final stages of completing the site preparation works, such as clearing, grubbing, balanced cut and fill to a grade of six meters above sea level. In November 2011, RP Energy designated the suppliers of the circulating‐fluidized‐bed boilers, steam turbines, generators, and supporting auxiliaries that ultimately will be engaged as subcontractors by the selected Engineering, Procurement and Construction (EPC) contractor. 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. In May 2011, RP Energy issued Invitations to Bid to three reputable international EPC contractors for the execution of the project. The EPC Contract is projected to be awarded during the second quarter of 2012. The estimated completion of the first unit will be 36 months after award of the EPC contract or mid‐2015. Completion of the second unit will follow within six months thereafter. The total cost of the project is estimated at approximately USD1.2 bn.

Therma South, Inc. (Therma South) Incorporated in November 18, 2008, Therma South is a wholly‐owned subsidiary of TPI and is the project company for the construction of the 300‐MW circulating fluidized‐bed coal‐fired power plant in Barangay Binugao, Toril District, Davao City and Barangay Inayawan, Sta. Cruz, Davao del Sur. The power project initially received resistance from some sectors of the community. But through Therma South’s information drives, road shows and close consultation and engagement with the affected localities, the power project received strong recommendations from the host barangays, the business sector, professional organizations and other institutions in Mindanao. Ultimately, the power project received endorsements from the local government units of Davao City and the municipality of Sta. Cruz in Davao del Sur. Therma South also secured the necessary permits and clearances from various national government agencies for the power project. On September 9, 2011 the DENR‐EMB issued the ECC for the power project.


On August 2011, Therma South acquired the remaining properties that will become the site of the power project. The power project is expected to be on line by late 2014, thereby providing Mindanao with much needed baseload power that is affordable, reliable and will cause the least adverse effect to the environment. 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 71 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 5,305 square kilometers. Collectively, AboitizPower’s distribution utilities contributed approximately 10% of its net income for 2011. The distribution utilities had a total customer base of 740,833 in 2011, 714,423 in 2010, and 685,378 in 2009.


The table below summarizes the key operating statistics of the distribution utilities for 2011 and the previous two years. Company

Electricity Sold (MWh) Peak Demand (MW) No. of Customers 2011 2010 2009 2011 2010 2009 2011 2010 2009

VECO 2,120,454 1,994,237 1,829,500 407 378 336 327,587 316,845 304,002 Davao Light

1,582,928 1,548,155 1,459,161 288 293 276 294,159 281,234 268,708

SFELAPCO 456,121 446,513 421,139 88 83 80 83,312 81,891 79,669 Cotabato Light

117,726 129,788 120,186 23 24 24 32,929 31,611 30,171

SEZ 408,240 405,038 372,391 99 83 97 2,738 2,734 2,724 MEZ 132,927 138,128 117,014 23 22 23 76 77 76 BEZ 116,378 90,174 60,376 32 27 21 32 31 28

Total 4,934,774 4,752,033 4,379,767 960 910 857 740,833 714,423 685,378

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 1.73 mn. To date, VECO has 16 substations that serves the electrical power needs of the cities Cebu, Mandaue, Talisay and Naga, the municipalities of Minglanilla, San Fernando, Consolacion and Liloan and 232 barangays all electrified in the island and province of Cebu. 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 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. For the second regulatory year, VECO also filed its application for approval of the translation into rates for different customer classes in March 2011. It was approved in July 25, 2011 and implemented in August 2011. VECO will file an application with the ERC for the approval of the recalculated maximum average price for the regulatory year 2013. It will also apply for approval of the translation into distribution‐related rates of different customer classes with the ERC, for the third regulatory year of its annual revenue requirement under the PBR for the regulatory period 2011 to 2014. 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 in 1946. Currently, AboitizPower owns 99.93% of the shares in the electric distribution utility. 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 the National Power Corporation (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 the utility’s power requirements through its 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 the company 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 bidprice of P4.0856 per kWh and the next lowest bid was approximately P1.0129 per kWh. Over the life of the supply contract, the differential will amount to approximately P4.9 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 he existing contracted energy supply under the 10‐year contract with the NPC for 1,363,375 MWH and the 12‐year contract with Hedcor. Davao Light’s approach to help local economies sustain robust growth is by ensuring power reliability. By plowing back a significant percentage of its annual earnings to prudent investments that upgrade its distribution network, the utility company has been able to address the increasing demand for power in spite of declining power supply in Mindanao. Robust economic growth in its franchise areas can be gleaned through the sprouting of malls, condominiums, and other commercial centers. At the start of 2012, eight distribution substations have undergone preventive maintenance using innovative ways to attain maximum efficiency while incurring the least possible costs. Davao Light has not implemented any rotating service interruptions unlike other electric utilities or cooperatives, even after being subjected to power curtailments by NGCP, Mindanao’s transmission concessionaire. In 2011, NGCP declared Mindanao grid under yellow and red alerts translated into 94 times warning of power shortages at levels below the island’s required reserve capacity of 13.8% and average demand of 1,167 MW, respectively. Contingencies designed to respond to energy deficiency which were tested during the 2010 Mindanao power crisis are still in place. These include tapping of embedded generators directly connected to the distribution facilities which are synchronized to the grid. In the event of a power crisis, Davao Light’s 54.8‐MW Bunker C‐fired standby plant with a rated capacity of 58 MW can provide 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 supply from Hedcor Sibulan’s 42.5 MW and Hedcor’s Talomo 4 MW hydroelectric plants likewise augment the power requirements of Davao Light’s 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 add to its power reserve capacity, on March 21, 2011 Davao Light entered into a power supply contract with TMI for 15 MW which was approved by the ERC on May 30, 2011. It was essentially a wet year for Davao Light in 2011. This resulted to a lower power consumption for all customer classes, residential, commercial, industrial, and even street lights, on a per capita basis from an average of 467 kWh to 458 kWh (as of December 2011). Banana plantations, for example, reduced its aggregate energy usage by (27% as of December 2011) due to curtailment of its water pumping needs. Davao Light was also able to achieve modest operational milestones in 2011. Its total kWh revenue grew by 2.25% (as of December 2011) compared to that of last year. The growth in sales can be attributed to the modest increase in new connections by 12,925 (as of December 2011). Highest demand recorded was 288 MW (as of December 2011), or a 1.06% decrease versus that of the same period last year. New service connections grew by 4.60%, increasing the number of customers to 294,159 (as of December 2011). Now entering its third year of PBR, Davao Light sees the prospect to increase its sales in pesos due to a hike in rates by P0.09/kWh or 7% on the distribution charges by July 2012. One of Davao Light’s approaches to keep rates at reasonable levels is by maintaining its systems losses well within the government mandated cap of 8.5%. Benchmarking against best practices in the industry, Davao Light established a Revenue Protection Department whose aim is to reduce the company’s systems losses by focusing on the following: Technical loss analysis and simulations; Systems loss segregation; Pilferage apprehension; Pilferage differential billing preparation and collection; and Standards, procedures, and practices assessment if such are prone to loses. Aside from the monthly monitoring, the power firm hired the services of Ateneo de Davao University’’s Social Research Training and Development Office to undertake a full‐blown Customer Satisfaction Survey for the second time. The survey is intended to determine if the customers’ perception about the electric company’s service level has improved or deteriorated. To add convenience to its paying customers, Davao Light partnered with the country’s top payment service providers, EC Pay and CIS Bayad Center. This innovation added a combined 107 payment facilities in strategic locations. 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 130 different payment venues to choose from, 63 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 lines 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 engines with a total of 20 MW generating capacity were overhauled. Comprehensive maintenance and servicing on five distribution facilities were undertaken to ensure continuous operation of its sub‐stations. At the same time three 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 P100 mn CC&B system is an integrated customer care software that is to replace the various in–house developed systems currently used. On May 20, 2011, Davao Light adopted a 500‐hectare government forest land in Upper Kibalang, Marilog, Davao City for the purpose of implementing permanent reforestation site. It is also the company’s way of supporting the government’s National Greening Program. Together with Therma South, Davao Light signed a 25‐year Memorandum of Agreement (MOA) with the Department of Environment and Natural Resources (DENR) to adopt an area to be used as permanent tree planting site for the two Aboitiz companies. Last August 13, 2011, over 300 company employees planted 5,200 indigenous and fruit bearing tree seedlings in the area. Davao Light’s social responsibility goes beyond giving and is grounded on its commitment to make host communities partners on the road to progress and development. To date, 32 school buildings with a total of 105 classrooms have been constructed and turned over to deserving public schools since 1996. Davao Light has also funded the academic scholarships of over 400 deserving college and high school students, all of whom are dependents of its customers since the program’s inception in 1996. It also contributed classrooms for kindergarten students to help fulfill the 50 units commitment of the Aboitiz Group to the Aklat Gabay at Aruga tungo sa Pag‐angat at Pag‐asa (AGAPP) program of President Aquino to jumpstart the K to 12 basic public education curriculum. Last September 2011, the Davao Light Employees Union (DLEU) and Management sealed a historic 5‐year Collective Bargaining Agreement. As a result, most company‐wide activities, such as sports, recognition day, and tree planting, are undertaken through a Labor‐Management Council (LMC) wherein representatives from both sides are represented. Through the years Davao Light has been consistently cited as the biggest business taxpayer of Davao City. In 2011, it paid P56 mn to the city government of Davao.

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 2011, it has a customer base of 32,996, 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 99.94% of Cotabato Light. As of 2011, Cotabato Light has four substations, consisting of two 10 MVA, one 12 MVA and one 15 MVA. Its substations are served by two 69‐kV transmission lines, that provide redundancy in case one transmission line fails. Cotabato Light’s distribution voltage is 13.8 kV. Cotabato Light maintains a standby 7‐MW Bunker C‐fired plant capable of supplying approximately 30% of its franchise area requirements. The existence of a standby power plant, which is capable of supplying electricity in cases of supply problems with PSALM/NGCP and for the stability of voltage whenever necessary, is another benefit to Cotabato Light’s customers. During the Mindanao power crisis in 2010, Cotabato Light’s franchise area experienced one of the lowest rotating power outages due to its back‐up power plant. 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. In May of 2011, Cotabato Light also implemented the Oracle’s CC&B system, which is a world class billing, collection and customer service related systems utilized also by other Distribution Utilities. Managing its systems loss is a challenge for Cotabato Light. With system losses capped by ERC at 8.5%, Cotabato Light aims to lower its systems losses through various measures, most of which aim to address pilferage, the primary cause of its higher‐than‐cap systems losses. The implementation of Meter on Post (MOP) or Elevated Meter Centers (EMC) will continue to be implemented in 2012 to further reduce its systems loss. The ERC issued its final determination on Cotabato Light’s application for approval of its ARR and Performance Incentive Scheme under the PBR scheme covering a 4‐year regulatory period which commenced on April 1, 2009 until March 30, 2013. Cotabato Light filed on December 15, 2010 the third Regulatory Year Maximum Average Price (MAP) recalculation and rate translation to be implemented from April 2011 to March 2012.

San Fernando Electric Light and Power Company, Inc. (SFELAPCO) Incorporated on May 17, 1927, SFELAPCO was a grantee of a municipal franchise in 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. Prior to the expiration of its legislative franchise, Republic Act 9967 lapsed into law on February 6, 2010 extending the franchise of SFELAPCO for another 25 years from the date of its effectivity or on March 10, 2010.


SFELAPCO’s franchise in the City of San Fernando, Pampanga covers an area of 202,733 square kilometers with approximately 314.21 circuit‐kilometers on its 13.8 kV and 608.21 circuit‐kilometers on its 240 volt distribution lines. A total of 35 barangays in the City of San Fernando and two contiguous barangays in Bacolor, namely, San Isidro and Cabalantian, are currently being supplied by SFELAPCO under its existing franchise. SFELAPCO also serves 25 barangays in the municipality of Floridablanca and two barangays in Guagua. This area covers 124.219 square kilometers with around 89.24 circuit‐kilometers of 13.8 kV and 144.69 circuit‐kilometers on its 240 volt distribution lines. On November 11, 2009, SFELAPCO signed a PSA with APRI. Under the PSA, APRI will supply additional energy required by SFELAPCO that cannot be supplied by NPC from December 25, 2009 to September 25, 2010. Thereafter, APRI became 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 currently under the four‐year regulatory period starting 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 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 P92 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 its service to its customers. In January, SEZ 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. In March 2011, SEZ formally launched and implemented the Customer Care & Billing (CC&B) system as part of its continuing effort to improve customer service. In April 2011, SEZ installed Automatic Circuit Reclosers (ACRs) on its distribution network to provide electric service continuity by removing a faulted circuit from the system brought about by natural causes. In May 2011, SEZ installed an additional 69 kV SF6 Circuit Breaker to its SEZ 100 MVA Substation to increase the flexibility and reliability of the substation’s 69kV line supplying its Maritan and Cubi substations. SEZ also completed the preventive maintenance of all its substations namely: Remy Field Substation, SEZ Substation, Cubi Substation, Maritan Substation, and SBIP Substation. SEZ is part of the fourth batch (Group D) of private utilities to enter PBR. The ERC released on July 6, 2011 its final determination on SEZ’s application for approval of its MAP, ARR, and Performance Incentive Scheme for the period covering October 2011 to September 2015. The approved MAP for the first regulatory year, as translated into new per customer class rates, has started implementation in January 2012.

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 P609.5 mn in exchange for AboitizPower’s common shares issued at the initial public offering price of P5.80 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 the first quarter of 2011, MEZ mounted three more sets of Automatic Voltage Regulator (AVR) to its old substation to improve voltage levels to locators. To further provide world‐class customer service, MEZ transferred their main administration office within the zone where they operate, MEPZ II, by leasing an office space through a lease agreement with Aboitizland, Inc. The MEZ control room was also renovated and expanded to improve the efficiency of operation. The construction of warehouse for slow‐moving items last September 2011 and the battery room construction last October 2011, and continuous replacement of wooden poles under 69 kV were also 2011’s highlights. And to avail of the opportunities in the competitive electricity market, MEZ is now a direct participant of the WESM starting January 2011. For the 2011 operating period, MEZ also transferred its NGCP metering to its substation in order to minimize line losses and further improve the voltage quality. MEZ accomplished numerous projects and activities in the year 2011, including but not limited to, deployment of CC & B system, launching of safety program and installation of line disconnect switches feeder lines for systems reliability and flexibility. Balamban Enerzone Corporation (BEZ) BEZ was incorporated in January 2007 when Cebu Industrial Park Developers, Inc. (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 and recently, to Austal Philippines Pty. Limited 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 P266.9 mn in exchange for AboitizPower’s common shares issued at the initial public offering price of P5.80 per share. On March 7, 2008, AboitizPower purchased THC’s 40% equity in BEZ for approximately P178 mn. The acquisition brought AboitizPower’s total equity in BEZ to 100%. In 2009, with the continued expansions of THI in its ship building business and the construction of additional facilities within the WCIP, BEZ constructed and energized the 25/33 MVA, 69 kV/13.8 kV Buanoy power substation equipped with an MR on load tap changer, strategically located near the THI shipbuilding factories to provide additional substation capacity.


Last September 25, 2009, 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 the fast and slow moving warehouses within their Buanoy and Arpili substations, respectively. In January 2011, BEZ secured firm contracts with Green Core Geothermal Incorporated (GCGI), Cebu Energy and EAUC power suppliers to ensure sufficient power supply to the different industries within the WCIP ‐ SEZ. In same period, BEZ became a direct member of the Philippine Electricity Market Corporation (PEMC) to avail of the power available at the WESM. The implementation of the Supervisory Control and Data Acquisition (SCADA) last March 11, 2011 and the installation of the closed circuit televisions at the different strategic locations by the first quarter of 2011 has greatly improved the operation of BEZ as both substations located two kilometers, apart were remotely controlled and monitored. In addition, numerous sectionalisers were also installed to provide more flexibility and reliability of the BEZ power system. For the year 2011, BEZ power sales increased by 29%. BEZ accomplished numerous projects and activities in the year 2011, including but not limited to, deployment of CC & B system, launching of safety program and installation of line disconnect switches feeder lines for systems reliability and flexibility. 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 (Open Access) 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 (WA) (issued on January 26, 2007). AboitizPower also offers a range of electricity‐related services through AESI. These services are designed to help AESI’s customers improve the efficiency, cost and reliability of their electric equipment and optimize their electricity consumption.

AESI is the organization which provides value added technical services to the various customers of the AboitizPower Generation group. It provides a variety of services which include power quality analysis, thermal scanning and power factor evaluation and correction. This allows power supply customers to properly assess their power consumption profile leading to a more efficient management. Aside from providing technical assistance in power quality analysis, AESI is also involved in project management services for Transmission Line and Substations. This operation enables the wide variety of AboitizPower


customers, from distribution utilities to large industrial manufacturing firms, to source a comprehensive service for their power requirements. From power supply to technical support, AESI provides the one stop convenience shop in dealing with a single supplier for these customers. As the era of Open Access begins, this same service currently enjoyed by existing AboitizPower generation customers will now be made available by AESI to the new retail supply customers. This will positively impact the efficiency and use of power of these industrial and residential customers in the years ahead. Prism Energy, Inc. (Prism Energy)

Prism Energy was incorporated in March 2009, as joint venture company between AboitizPower and Vivant. It is in the process of securing a RES license from ERC.

AdventEnergy, Inc. (AdventEnergy)

Incorporated in August 2008, AdventEnergy is a licensed RES, duly authorized by the ERC to sell, broker, market, or aggregate electricity to end‐users. (ii) Sales Comparative amounts7 of revenue, profitability and identifiable assets are as follows:

2011 2010 2009 Gross Income 54,476 59,551 23,174 Operating Income 20,355 26,232 5,456 Total Assets 153,528 134,557 111,341

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 amounts8 of revenue contribution by business grouping are as follows:

Business Segment

2011 2010

2009

Power Generation 41,499 74% 46,982 78% 12,466 53% Power Distribution 14,351 25% 13,065 22% 10,734 46% Services 528 1% 465 0% 296 1% Total Revenue 56,384 100% 60,512 100% 23,496 100% Less: Eliminations (1,908) (961) (322) Net Revenue 54,476 59,551 23,174

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

_________________________________________________________________________ 7 Amounts in millions. 8 Ibid.

(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. 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 Mobile 1 and Mobile 2 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. 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, 23 kV and 69 kV while smaller industrial, commercial and residential customers receive electricity at 240 V or 480 V. All of Aboitiz Power’s Distribution Utilities have entered into transmission service contracts with NGCP for the use of NGCP’s transmission facilities to receive power from their respective Independent Power Producers and NPC/PSALM for distribution to their respective customers. VECO owns a 138kV tie‐line that connects to Cebu Energy power plant. All customers that connect to the Distribution Utilities distribution lines are required to pay a tariff approved by the ERC. (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 in determining 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 harness the kinetic energy from the flow of water on rivers, located at the power plant sites, 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 utilize the energy from a certain volume of water from the applicable source of the water flow. Under the APA between APRI and PSALM for the Tiwi‐MakBan complex, the management and operation of the geothermal fields which supply steam to the power generation units, remains with Chevron Geothermal Philippines Holdings, Inc. (Chevron). The terms of the steam supply is governed by a Transition Agreement (TA) under which APRI reimburses capital expenditures and operating expenses and pays service fees to Chevron. The TA will take effect no more than four years from the date of the


turnover of Tiwi‐MakBan to APRI . Upon fulfilment of preconditions:Chevron becomes a Philippine corporation; and completion of the rehabilitation of MakBan units 5 and 6; the TA will be replaced by a Geothermal Resource Service Contract (GRSC). Under the GRSC, 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. SPPC and WMPC get fuel supplies from NPC pursuant to the terms of their respective ECAs with NPC. EAUC and CPPC each have a fuel supply agreement with Petron; while TMI has existing fuel supply agreements with Shell and Petron for Mobile 1 and Mobile 2, respectively. The fuel prices under these agreements are pegged to the Mean of Platts Singapore (MOPS) index. 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 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, 2012

758,088 Yes ERC approved NPC rate plus ERC approved adjustments

Davao Light NPC‐ 10 years; expiring in December 2015

1,363,375 Yes ERC approved NPC rate plus ERC approved adjustments

Cotabato Light NPC ‐ 10 years; expiring in December 2015


MEZ NPC ‐ 10 years; expiring in September 2015


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 are approved by the ERC. 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. To add to its power reserve capacity, Davao Light has entered into a three‐year power supply contract with Therma Marine for 15 MW last March 21, 2011 and provisionally approved by ERC on May 30, 2011.

VECO has PPAs pursuant to which it purchases 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 Cebu Energy for the supply of 105 MW for 25 years to address VECO’s long‐term power supply requirement. VECO also signed a 5‐year contract for the supply of power from Green Core Geothermal Inc. (GCGI) for 60 MW at 100% load factor. GCGI started supplying VECO on December 26, 2010. This supply of power replaced NPC’s reduction in contract in 2011.

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 54.8 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 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 enter into transactions with its parent, associates and other related parties, principally consisting of: (a) AEV provides human resources, internal audit, legal, treasury and corporate finance services, among

others, to the Group 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 amounted to P424.80 mn in 2011, P293.70 mn in 2010 and P409.40 mn in 2009, respectively.

(b) 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‐Magat and SNAP‐Benguet in the amount of P2.50 bn in 2011, P1.70 bn in 2010 and P1.80 bn in 2009.

(c) Energy fees billed by HI to SFELAPCO amounted to nil in 2011 and 2010 and P19.60 mn in 2009. (d) Energy fees billed by CPPC to VECO amounted to P1.37 bn in 2011, P2.04 bn in 2010 and P2.10 bn in

2009. (e) Energy fees billed by TLI to SNAP‐Magat in 2011 amounted to P22.10 mn. (f) Energy fees billed by Therma Marine to Pilmico Foods Corporation (PFC) amounted to P29.80 mn in

2011 and P47.40 in 2010. PFC is a subsidiary of AEV.


(g) Energy fees billed by BEZC to affiliates (ACO subsidiaries and associates) amounted to P702.60 mn

in 2011, P521.90 mn in 2010 and P287.70 mn in 2009. BEZ also purchased energy from associates amounting to P288.90 mn in 2011.

(h) Aviation services rendered by AEV Aviation, Inc., an associate to the Group, amounted to P37.50 mn

in 2011, P32.70 mn in 2010 and P24.80 mn in 2009. (i) Lease of commercial office units by the Group from CPDC for a period of three years. Rental

expense amounted to P57.30 mn in 2011, P69.40 mn in 2010 and P48.20 mn in 2009. CPDC is a wholly owned Subsidiary of AEV.

(j) The Company provides services to certain associates, such as technical and legal assistance for

various projects and other services. Total technical and service fee income from associates amounted to P105.80 mn in 2011, P93.70 mn in 2010 and P2.20 mn in 2009.

(k) Cash deposits with Union Bank of the Philippines, Inc. (UBP) earn interest at prevailing market rates.

Total cash deposits of the Group amounted to P7.61 bn and P4.87 bn as of December 31, 2011 and 2010, respectively. Total interest earned on deposits with UBP amounted to P209.50 mn in 2011 and P125.90 mn in 2010. UBP is an associate of AEV.

(l) Amounts owed to/by related parties, both interest and non‐interest‐bearing, payable on demand.

Interest‐bearing balances are based on annual interest rates ranging from 1.50% to 6.50% in 2011, 1.80% to 8.25% in 2010 and 3.00% to 9.25% in 2009. Net interest expense incurred on these balances amounted to P0.1 mn in 2011 and P1.50 mn in 2010. Net interest income earned on these balances amounted to P55.80 mn in 2009.

(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 Philippine Grid Code and Philippine Distribution Code.


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. Aboitiz Power’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. Although an IPP‐Administrator such as TLI is not required to obtain a COC, it is nevertheless required, along with all entities owning and operating generation facilities to comply with technical, financial and environmental standards provided in existing laws and regulations in their operations. In Department Circular No. DC 2010‐03‐0003 dated February 26, 2010 of the DOE, generation companies are enjoined to ensure the availability of its generation facilities at all times subject only to technical constraints duly communicated to the system operator in accordance with existing rules and procedures. For this purpose, generation companies shall have the following responsibilities, among others:

a. All generation companies shall operate in accordance with their maximum available

capacity which shall be equal to the registered maximum capacity of the (aggregate) unit less (1) forced unit outages, (2) scheduled unit outages, (3) de‐rated capacity due to technical constraints which include (i) plant equipment‐related failure and ambient temperature, (ii) hydro constraints which pertain to limitation on the water elevation/turbine discharge and megawatt output of the plant and (iii) geothermal constraints which pertains to capacity limitation due to steam quality, steam pressure and temperature variation, well blockage and limitation on steam and brine collection and disposal system;

b. Oil‐based generation companies shall maintain an adequate in‐country stocks of fuel

equivalent to at least 15‐days running inventory which includes shipments in transit; c. Coal power plants shall ensure the required 30‐day coal running inventory which includes

shipments in transit; d. During scheduled maintenance of the Malampaya natural gas facilities, all affected

generation companies shall maintain at least 15‐days running inventory of the alternative fuel and shall operate at full capacity;


e. All generation companies with natural gas fired, geothermal and hydroelectric generating plants shall submit to the DOE a monthly report on the current status and forecast of the energy sources of its generating plants;

f. All generation companies must notify and coordinate with the system operator of any

planned activity such as shutdown of its equipment; g. All generation companies must immediately inform the DOE of any unexpected shutdown

or derating of the generating facility or unit thereof; and h. Generating companies shall seek prior clearance from the DOE regarding any plans for

deactivation or mothballing of existing generating units or facilities critical to the reliable operation of the grid.

The Generation Companies and Davao Light and Cotabato Light possess COCs for their generation businesses, as follows:

Title of Document

Issued under the name of:

Power Plant

Date of Issuance

Type

Location

Capacity

Fuel

Years OfService

COC No. 08‐11‐GXT 33‐0033L

Hedcor, Inc.

Hydro Irisan – Tadlangan, Benguet

1.20 MW Hydro 10

November 5, 2008

Hydro Bineng 1 – Bineng, La Trinidad, Benguet

3.20 MW Hydro 10

Hydro Bineng 2 – La Trinidad, Benguet

1.80 MW Hydro 10

Hydro Bineng 2B – Bineng, La Trinidad, Benguet

0.75 MW Hydro 10

Hydro Bineng 3 – Bineng, La Trinidad, Benguet

4.50 MW Hydro 10

Hydro Ampohaw – Banengbeng, Sablan, Benguet

8.00 MW Hydro 10

Hydro Sal‐angan – Ampucao, Itogon, Benguet

2.40 MW Hydro 10

COC No. 11‐05‐GXT 286b‐0331M

Hedcor, Inc. (Talomo

Hydroelectric Power Plant)

Hydro

Talomo 1 – Calinan, Davao City

1,000 kW

Hydro

20

May 9, 2011 Hydro Talomo 2 – Mintal

Proper, Davao City 600 kW Hydro

20

Hydro Talomo 2A – Upper Mintal, Davao City

650 kW Hydro 20

Hydro Talomo 2B – Upper Mintal, Davao City

300 kW Hydro 20


Hydro Talomo 3 – Catalunan, Pequeño, Davao City

1,920 kW Hydro 20

COC No. 08‐11‐GXT 32‐0032L

Hedcor, Inc.

Hydro FLS Plant – Poblacion, Bakun, Benguet

5.90 MW Hydro 10

November 5, 2008 Hydro Lower Labay –

Ampusongan, Bakun, Benguet

2.40 MW Hydro 10

Hydro Lon‐Oy – Poblacion, Bakun, Benguet

3.60 MW Hydro 10

COC No. 11‐07‐GXT 17273‐17584M

Hedcor Sibulan

‐ Darong

Diesel Engine

Brgy. Darong, Sta. Cruz, Davao del Sur

363 kW

Diesel

15

July 7, 2011

COC No. 11‐07‐GXT 17272‐17583M

Hedcor Sibulan

‐ Tibolo

Diesel Engine Brgy. Tibolo, Sta. Cruz, Davao del Sur

323 kW Diesel

15 July 7, 2011

COC No. 11‐07‐GXT 17269‐17580M

Hedcor, Inc. – Talomo 2

Diesel Engine Proper Mintal, Davao City

20 kW Diesel 15 July 7, 2011

COC No. 11‐07‐GXT 17271‐17582L

Hedcor, Inc. – La Trinidad (Beckel)

Diesel Engine 214 Beckel, La Trinidad, Benguet

216 kW Diesel 15 July 7, 2011

COC No. 11‐07‐GXT 17270‐17581M

Hedcor, Inc. – Talomo 3

Diesel Engine Brgy. Catalunan, Pequeño, Davao City

20 MW Diesel 15 July 7, 2011

COC No. 10‐08‐GN‐56‐16881

Hedcor Sibulan Hydroelectric Power Plant A

Hydro Brgy. Sibulan, Sta. Cruz, Davao del Sur

16.328 MW Hydro 25 August 9, 2010

COC No. 10‐05‐GN 54‐16816

Hedcor Sibulan Incorporated (Plant B)

Hydro

Brgy. Sibulan, Sta. Cruz, Davao del Sur

26.257 kW

Hydro

25 May 24, 2010

COC No. 08‐07‐GXT 17‐0017

LHC Hydro Amilongan Alilem, Ilocos Sur

70 MW Hydro ‐

July 29, 2008 Stand‐by Power

Amilongan Alilem, Ilocos Sur

280 kW Diesel ‐

COC No. 10‐12‐GXT 13701‐13728M

Davao Light Bunker C Fired

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

58.7 kW Blended Fuel

25

December 1, 2010

Blackstart Generator

Sets

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

105.60 kW Diesel 25

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

80 kW Diesel 25


80 kW Diesel 25


41.6 kW Diesel 25

COC No. 11‐12‐GXT 15911‐16153M

Cotabato Light Bunker C‐Fired Diesel

Engine

CLPCI Compound, Sinsuat Ave., Cotabato City

9.927 MW Diesel/ Bunker C 25

December 5, 2011 Blackstart CLPCI Compound,

Sinsuat Ave., Cotabato City

10 kW Diesel 25


COC No. 08‐06‐GXT2‐0002

EAUC

Diesel Engine

Mactan Export Processing Zone 1, Lapulapu City, Mactan, Cebu

49.90 MW

‐

‐

June 10, 2008

COC No. 08‐06‐GXT1‐0001

CPPC

Diesel Engine

Old VECO Compound, Brgy. Ermita, Cebu City

75.296 MW

‐

‐

June 3, 2008

COC No. 08‐08‐GXT20‐0020

WMPC

Diesel

Barangay Sangali, Zamboanga City

113 MW

Bunker‐C/ Diesel

‐

August 7, 2008

COC No. 08‐08‐GXT21‐0021

SPPC

Diesel

Barangay Baluntay, Alabel, Sarangani Province

55 MW

Bunker‐C/ Diesel

‐

August 7, 2008

COC No. 10‐11‐GXT 2860‐13433L

SNAP‐Magat

(Magat Hydroelectric Power Plant)

Hydro electric Magat River, Brgy. Aguinaldo, Ramon, Isabela

360 MW Hydro 23

November 22, 2010 Blackstart Generator

Set

Magat River, Brgy. Aguinaldo, Ramon, Isabela

320 kW Diesel 23

COC No. 05‐11‐GXT 2860‐13433

SNAP‐Magat Hydro Electric turbine

Brgy. Aguinaldo Ramon, Isabela

360 MW ‐ ‐

January 28, 2008 Stand‐by

Diesel Genset Brgy. Aguinaldo Ramon, Isabela

350 kW Diesel ‐

COC No. 10‐11‐GXT 286M‐13429L

SNAP‐Benguet (Binga

Hydroelectric Power Plant)

Hydro Electric

Brgy. Binga, Tinongdan, Itogon, Benguet

100 MW Hydro 5

November 15, 2010 Blackstart Generator

Set

Brgy. Binga, Tinongdan, Itogon, Benguet

355.40 kW Diesel 5

COC No. 11‐08‐GN 87‐17671L

SNAP‐Benguet (Ambuklao

Hydroelectric Power Plant

Hydro Brgy. Ambuklao, Bokod, Benguet

104.55 MW Hydro 50

August 31, 2011 Blackstart Brgy. Ambuklao,

Bokod, Benguet 2.28 MW Diesel 20

COC No. 12‐03‐GXT 286m‐13429U4L

SNAP‐Benguet (Unit 4, Binga

HEPP)

Hydroelectric Brgy. Tinongdan, Itogon, Benguet

31.45 MW Hydro 50

March 12, 2012

COC No. 11‐05 GN 16‐15880M

STEAG Power

Coal fired

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

232 MW Coal 50

May 30, 2011 Emergency

Generating Set

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

1.25 MW Diesel 25


COC No. 10‐05‐GXT286e‐7833

APRI (Makban

Geothermal Power Plant)

Geothermal

Brgy. Bitin, Bay, Laguna

Plant A 126.40 MW

Geothermal

20

May 31, 2010

Brgy. Bitin, Bay, Laguna

Plant D – 40 MW

Steam ‐

Brgy. Limao, Tamlong, Calauan, Laguna

Plant B – 126.40 MW

‐

‐

Brgy. Limao, Tamlong, Calauan, Laguna

Plant C ‐ 126.4 MW

‐ ‐

Brgy. Sta. Elena, Sto. Tomas, Batangas

Plant E – 40 MW ‐ ‐

COC No. 10‐12‐GXT 286r‐13736L

APRI (Tiwi

Geothermal Power Plant)

Geothermal

Brgy. Cale, Tiwi, Albay

234 MW

Steam

10

December 1, 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 MW

Steam

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

COC No. 11‐04‐GXT 286gg‐15074M

Therma Marine

[Mobile 1 (M1)]

Bunker C Fired

Brgy. San Roque, Maco, Compostela Valley

100.33 MW Bunker C/ Diesel 30

April 4, 2011 Blackstart Brgy. San Roque,

Maco, Compostela Valley

1.75 MW Diesel 30

COC No. 11‐040GXT 286bb‐14632M

Therma Marine

[Mobile 2 (M2)]

Bunker C Fired

Nasipit, Agusan del Norte

100.33 MW Bunker C/ Diesel

30 April 4, 2011

Blackstart Nasipit, Agusan del Norte

1.75 MW Diesel 30

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:

Distribution Company Expiration Date

VECO 2030

Davao Light 2025

Cotabato Light 2014

SFELAPCO 2035

SEZ9 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 and Prism, obtained separate licenses to act as Retail Electricity Suppliers and Wholesale Aggregators. ________________________________________________________________________________________ 9Distribution Service Management with the Subic Bay Metropolitan Authority.


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

Cleanergy (Class No. 42)

Aboitiz Power Corporation

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. The 5th year Anniversary Declaration of Actual Use (DAU) was filed last December 27, 2011 with IPO.

Cleanergy and Device (Class No. 42)


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. The 3rd year Anniversay Declaration of Actual Use (DAU) was filed last June 28, 2005 with IPO.

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


April 23, 2010

4‐2010‐004383 November 11, 2010

Application for trademark "A Better Future.”

Original Certificate of Registration was issued on November 11, 2010.

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


April 23, 2010

4‐2010‐004384 November 11, 2010

Application for Trademark "Better Solutions".


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


April 23, 2010

4‐2010‐004381 November 11, 2010

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, and 42)


April 23, 2010

4‐2010‐004385 November 11, 2010

Application for Trademark "AboitizPower word Mark".


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


April 23, 2010

4‐2010‐004382 November 11, 2010

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)


April 23, 2010

4‐2010‐004380 February 11, 2011

The representation of a spiral rendered in blue.

Original Certificate of Registration was issued on February 11, 2011.

AboitizPower and Device (Class 39, 40 and 42)


April 23, 2010

4‐2010‐004379 February 11, 2011

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.


Alterspace (Class 9, 39, and 40)


April 6, 2011 4‐2011‐003968 Application for trademark “ALTERSPACE” word mark under Class No. 9 – computer software, internet application, Class No. 39 – energy distribution and Class No. 40 – energy generation.

The trademark application has been allowed and its publication in the Official Gazette has been approved in IPO’s notice of allowance dated December 14, 2011 for the purposes of opposition.

Alterspace and Device (Class 9, 39 and 40)


May 31, 2011 4‐2011‐006291 Application for trademark “Alterspace and Device”. A globe with the words

The trademark application has been allowed and its publication in the Official Gazette has been




“alter” and “space” inside and an arrow circling the globe and separating the two words. The globe is rendered in forest green, while the words and arrow are rendered in lime green. Filed under class no. 9 – computer software, internet application, class no. 39 – energy distribution and class no. 40 – energy generation.

approved in the IPO’s Notice of Allowance dated November 4, 2011.

Aboitiz Energy Solutions, & Device (Class No. 42)

Aboitiz Energy Solutions, Inc.

January 25, 2007

4‐2007‐000784 September 3, 2007

Application for trademark ABOITIZ ENERGY SOLUTIONS and Device.

Original Certificate of Registration was issued on September 3, 2007. The 3rd year Anniversary Declaration of Actual use (DAU) was filed with the IPO last February 4, 2010.

Power One (wordmark) (Class No. 42)


July 29, 2002

4‐2002‐006232 February 19, 2007

This is an application for trademark “Power One”

Original Certificate of Registration was issued on February 19, 2007. The 3rd year Anniversary Declaration of Actual use (DAU) was filed with the IPO last July 29, 2005.

Power One and Device (Class No. 42)


February 17, 1999

4‐1999‐001121 September 18, 2006

Application for trademark “Power One and Device “

Original Certificate of Registration was issued on September 18, 2006. The 3rd year Anniversary Declaration of Actual use (DAU) was filed with the IPO last August 13, 2002.

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

Subic Enerzone Corporation

July 6, 2006 4‐2006‐07306 August 20,2007

Trademark Application for Subic Enerzone Corporation and Logo (blue & yellow). The mark

Original Certificate of Registration was issued on August 20, 2007. The 3rd year Anniversary Declaration of Actual Use




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.

(DAU) was filed with IPO last July 6, 2009.

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


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

Original Certificate of Registration was issued on August 20, 2007. The 3rd year Anniversary Declaration of Actual use (DAU) was filed last January 6, 2010 with IPO.

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


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. The 3rd year Anniversary Declaration of Actual Use (DAU) was filed last July 6, 2009 with IPO.




RP Energy and Device (Class No. 39)

Redondo Peninsula Energy, Inc.

July 6, 2006 4‐2008‐009737 April 13, 2009

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

Original Certificate of Registration was issued on April 13, 2009

Aboitiz Energy Solutions & Device (Class No. 42)


January 25, 2007

4‐2007‐000784 September 3, 2007

Application for trademark ABOITIZ ENERGY SOLUTIONS and device.

Original Certificate of Registration was issued on September 3, 2007.

The 3rd year Anniversary Declaration of Actual Use (DAU) was filed with the IPO last February 4, 2010.

Power One (wordmark) (Class No. 42)


July 29, 2002

4‐2002‐006232 February 19, 2007

This is an application for trademark “Power One”


The 3rd year Anniversary Declaration of Actual Use (DAU) was filed with the IPO last July 29, 2005.

Power One and Device (Class No. 42)


February 17, 1999

4‐1999‐001121 September 18, 2006

Application for trademark “Power One and Device”

Original Certificate of Registration was issued on September 18, 2006.

The 3rd year Anniversary Declaration of Actual use (DAU) was filed with the IPO last August 13, 2002.

(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. Among the provisions of the EPIRA which have had or will have considerable impact on Aboitiz Power’s businesses relate to 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 for the cost‐efficient dispatch of power through an economic merit order; (b) create reliable price signals to assist participants in weighing sell and purchase options; and (c) provide a fair and level playing field for suppliers and buyers of electricity, wherein prices are driven by market forces.

The WESM provides avenue 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 Open Access 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 provided in the EPIRA, Open Access shall be implemented in phases. The WESM began operations in Luzon in June 2006 and, in the Visayas, in December 2010. In 2011, the ERC motu proprio initiated proceedings to determine whether Open Access may already be declared in Luzon and Visayas. Following various public hearings, the ERC declared December 26, 2011 as the Open Access Date when full operations of the competitive retail electricity market in Luzon and Visayas shall commence. All electricity end‐users with an average monthly peak demand of one (1) MW for the twelve (12) months preceding December 26, 2011, as certified by the Commission to be contestable customers, were given the right to choose their own electricity suppliers. However, on


October 24, 2011, upon the request of the Manila Electric Company (MERALCO), the Private Electric Power Operators Association (PEPOA) and the Philippine Rural Electric Cooperatives Association, Inc. (PHILRECA) for the re‐evaluation of the feasibility of the December 26, 2011 Open Access Date, the ERC declared the deferment of the implementation of Open Access in Luzon and Visayas in light of the inadequacy of rules, systems, preparations and infrastructure required therefore. The implementation of Open Access will potentially result in various contracts entered into by utilities or suppliers being “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. In Mindanao, a truly competitive environment required by Open Access is not expected in the near future because the largest generating asset owned by NPC in Mindanao has yet to be privatized.

Unbundling of Rates and Removal of Subsidies The EPIRA mandated the unbundling of distribution and wheeling charges from retail rates with such unbundled rates reflecting the respective costs of providing each service. It also mandated the removal of cross subsidies other than the lifeline rate for marginalized end‐users which shall subsist for a period of 20 years, unless extended by law. The lifeline rate is a socialized pricing mechanism set by the ERC for low‐income, captive electricity consumers who cannot afford to pay the full cost of electricity.

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, setting out the manner in which this new PBR rate‐setting mechanism for distribution‐related charges will be implemented. PBR replaces the Return on Rate Base (RORB) mechanism which has historically determined the distribution charges paid by customers. Under PBR, the distribution‐related charges that distribution utilities can collect from customers over a 4‐year regulatory period is 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 as 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 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. Cotabato Light is entering the last Regulatory Year of its current Regulatory Period covering April 1, 2009 to March 31, 2013, for which the ERC has previously approved in its Final Determination the 4‐year Annual Revenue Requirements and Performance Incentive Scheme. On December 2011, Cotabato Light


filed with the ERC an application for rates translation, which will effectively be charged to its customers for the 4th Regulatory Year April 1, 2012 to March 31, 2013. Likewise, Cotabato Light is already preparing for the upcoming reset process of its next Regulatory Period April 1, 2013 to March 31, 2017. The activities will include asset revaluation, forecasting operation and maintenance and capital expenditures, setting the new performance targets, among others. On March 2011, VECO and Davao Light filed their rate translation application for the second Regulatory Year July 1, 2011 to June 30, 2012. Since implementation by VECO of the rate translation in the first Regulatory Year was delayed by one month, recovery for the under‐recovery was included in its application for the second Regulatory Year. On June 29, 2011, the ERC rendered its decision setting the distribution, supply and metering charges of Davao Light and VECO. For SEZ and SFELAPCO, ERC has issued last August 2011 the respective Final Determinations for the distribution utilities’ 4‐year Annual Revenue Requirement and Performance Incentive Scheme covering the Regulatory Period October 1, 2011 to September 30, 2015. Both SEZ and SFELAPCO have filed their respective applications for rates translation for the first Regulatory Year October 1, 2011 to September 30, 2012. The decision for SEZ was released last December 2011 and the effective rates resulting therefrom have been implemented starting this January 2012. The one for SFELAPCO is expected to be resolved by February 2012. The resulting under‐recoveries from the lag starting from October 1, 2011 can be recovered in the rates filing on the second Regulatory Year. The PBR rules allow such mechanism in its Maximum Average Price (MAP) formula. Reduction of Taxes and Royalties on Indigenous Energy Resources To equalize prices between imported and indigenous fuels, 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, former 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 and its implementing rules and regulations. Some of the proposed amendments are discussed below.

(a) Disallowance of the recovery of Stranded Contract costs; (b) Requiring 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) Exclusion 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) Prohibition of 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) Prohibiting 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) Adding 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) Exemption or deferral of some assets of NPC from privatization, such as the Unified Leyte

(Tongonan) Geothermal Complexes, Agus and Polangui Complexes, and the Angat Dam; (h) Expansion of 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;

(i) Requiring distribution utilities to pay a franchise tax equivalent to 3% of the distribution

utility’s gross income in lieu of all taxes; (j) Exemption of a distribution utilitiy or a company holding its shares or its controlling

stockholders from the mandory divestment rule provided under Section 28 of the EPIRA, if the shares of the distribution utility, its parent company or its controlling stockholders are listed in the PSE at the time of the effectivity of RA 9136.


The Renewable Energy Act of 2008 Republic Act No. 9513, the Renewable Energy Act of 2008 (RE Law) was signed into law by the former president, Gloria M. Arroyo, on December 16, 2008 and became effective in January on 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 overall costs of energy, and reduce, if not prevent, harmful emissions to promote a healthy 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 except for indigenous geothermal energy which shall be at a rate of 1.50% of gross income. Micro‐scale projects for communal purposes and non‐commercial operations with capacities not exceeding 100 kW will not be subject to this government share. The RE Law offers fiscal and non‐fiscal incentives to RE developers, including developers of hybrid systems, subject to a certification from the DOE, in consultation with the Board of Investments (BOI). These incentives include income tax holiday for the first seven years of commercial operations; duty‐free importations of RE machinery, equipment and materials effective within ten 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 from intermittent RE resources are given the option to pay transmission and wheeling charges on a per kilowatt‐hour basis at a cost equivalent to the average per kilowatt‐hour rate of all other electricity transmitted through the grid. On the other hand, electricity generated from emerging RE resources such as wind, solar, ocean, run‐of‐river hydropower and biomass are likewise given priority dispatch. Electricity generated from RE resources for the generator’s own consumption and/or for free distribution in off‐grid areas are exempt from the universal charge. The RE Law further 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. DO2009‐05‐008 dated May 25,2009 (Rules and Regulations 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 its issuance, formulate the necessary mechanism and/or guidelines to implement the entitlement to the general incentives and privileges of qualified RE developers. However, as of this date, no specific guidelines or regulations has been issued by the relevant implementing agencies. Such being the case, the renewable energy companies of AboitizPower, such as APRI, LHC, Hedcor Sibulan, Hedcor Tamugan, SNAP‐Magat and SNAP‐Benguet filed on 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, the exploration and development of RE sources and their conversion into power. To date, the said request is still pending with the BIR Law Division. On May 16, 2011, the National Renewable Energy Board (NREB) filed in the ERC a petition for the adoption of the feed‐in tariff (FIT) for the emerging RE resources, namely, wind, solar, ocean, run‐of‐river hydropower and biomass. The proposed FITs are as follows: (a) wind – P10.37/kWh; (b) solar – P17.95/kWh; (c) run‐of‐river hydropower – P6.15; (d) ocean – P17.65/kWh; and (e) biomass – P7.00/kWh. As of date, hearings are being held before the ERC for the determination of the justness and reasonableness of the proposed FITs. NREB is likewise in the process of preparing the Renewable Portfolio Standards which, under the RE Law, shall be a market‐based policy requiring electricity suppliers to source an agreed portion of their energy supply from eligible RE resources. It is further in the process of drafting rules enabling the net metering program for RE which shall govern distributed generation.

New ERC Regulation on Systems Loss Cap Reduction Under ERC Resolution No. 17, Series of 2008, 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, particularly, as an Operation and Maintenance expense in the PBR applications. In December 2009, VECO and Cotabato Light filed separate petitions in the ERC for the deferment of the implementation of the new system loss cap of 8.5%, citing circumstances peculiar to their franchise and beyond the control of VECO and Cotabato Light, which affect the system loss incidence in their areas. (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 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. Standard regulations that govern business operations other than Clean Air Act are Ecological Solid Waste Management Act (Republic Act No. 9003), Clean Water Act (Republic Act No. 9275), Toxic Chemical Substances and Hazardous Waste Act (Republic Act No. 6969), Philippine Environmental Impact Statement System (Presidential Decree No. 1586). Designated pollution control officers in the different business units closely monitor compliance to the requirements of these regulations. In 2011, AboitizPower earned DENR Award for Philippine Environmental Partnership Program, the only power generation company in the country to receive three awards simultaneously. Specifically, AboitizPower’s business units HEDCOR and APRI were cited as companies that ‘give premium to environmental protection as an integral business concern’. To win the awards, these companies did not have cases filed against them with the Pollution Adjudication Board of DENR for three years and have fully complied with applicable environmental laws, rules and regulations and have proven record of superior environmental performance. 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 Energy Act of 2008 (Republic Act No. 9513) has encountered issues related to FIT that slowed down its full implementation. However, pending implementation, RE Bill continues to outline opportunities for the industry and for companies like AboitizPower. 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 2011 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 118 employees as of February 29, 2012, composed of executive, supervisory, and rank and file staff. There is no existing collective bargaining agreement covering AboitizPower employees.

As of February 29, 2012, the Company, its consolidated subsidiaries, LHC, VECO, SNAP ‐ Benguet, SNAP‐Magat, EAUC and MORE employed a total of 560 employees.

The following table provides a breakdown of total employee headcount on a per company basis, divided by function, as of February 29, 2012.

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.

Business Unit Number of Employees Unionized

Employees Expiry of

CBA Total Executives Managers Supervisors Rank & File AboitizPower 118 35 17 20 46 N/A N/A

AESI 24 1 1 4 18 N/A N/A BEZ 8 0 0 1 7 N/A N/A MEZ 13 1 1 2 19 N/A N/A ARI 0 0 0 0 0 N/A N/A

APRI 335 7 21 59 248 N/A

CBA negotiation still ongoing

CPPC 45 0 2 12 31 N/A N/A EAUC 44 1 2 12 29 N/A N/A LHC 38 0 3 5 30 N/A N/A MORE 41 10 17 14 0 N/A N/A

SEZ 52 2 3 4 43 N/A N/A SNAP‐Magat 36 1 0 14 21 N/A N/A SNAP‐Benguet 51 2 1 20 28 N/A N/A

STEAG 198 3 17 42 136 N/A N/A WMPC 78 0 4 20 54 N/A N/A SPPC 66 0 4 17 45 N/A N/A

Cotabato Light 74 1 2 16 55 46 June 30, 2014

Davao Light 396 14 27 175 180 180 June 15, 2016

Hedcor, Inc. 288 8 12 28 240 139 September 19, 2013

VECO 350 6 15 39 290 263

December 31, 2011 (CBA negotiation still ongoing)

SFELAPCO 89 5 12 6 66 66 May 9, 2014

TOTAL NO. OF EMPLOYEES 2,344


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) for compulsory arbitration.

On June 30, 2011, the NLRC dismissed the charge of unfair labor practice against VECO for lack of merit, and declared legal the dismissal of the Union president. The Union moved to reconsider the adverse decision of the NLRC, but the motion was denied. Consequently, on October 18, 2011, the Union filed a petition for certiorari with the Court of Appeals, where the appeal is pending. (xiv) Major Risk/s Involved in the Business An integral part of AboitizPower’s Enterprise Risk Management efforts is to anticipate, understand and address the risks that it might encounter in the businesses in which it is involved. Certain risks, however, 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 most valuable asset. It is a competitive advantage that enables the Company to earn the trust of its shareholders and other stakeholders. The Company is cognizant of the fact that the reputation it has today took generations to firm up and is therefore something that must be protected, built and enhanced continuously.

Managing the Company’s reputation requires understanding of its reputational terrain, which has expanded from the general public to its very own team members, partners, shareholders, lenders, communities it operates in, NGOs, regulators, advocacy groups, and those in traditional and social media. The views of these various stakeholders and their perception of the image that the Company communicated over time determine its Employer, Societal, Regulatory, Customer and Shareholder Brand. The Company’s Corporate Communications and Branding Teams, established in 2009, have the primary task of ensuring that reputation, the Company’s vital asset, is not only protected but also enhanced.

Competition Risk AboitizPower is facing pivotal changes in the power industry for the next few years. Over 70% of the generating assets and IPP contracts of NPC have been privatized. The WESM is operational in Luzon and Visayas, and will be operational in Mindanao soon. Investments in Greenfield projects by competitors are starting to pour in, with new players coming into the game. The power industry is now moving into a situation where there will be adequate or even, as some fear, an oversupply of electricity across all grids.


The Company’s strength lies in the diversified portfolio of its generation assets. Within the year, AboitizPower is looking to break ground on its coal Greenfield projects in Subic, Pagbilao and Davao. The Company will likewise break ground in five small hydro projects namely Tudaya 1 and 2 in Sibulan, Sita and Simod in Bukidnon and Sabangan in Luzon.

The Company has also demonstrated its ability to acquire the skill and talent necessary to operate its newly acquired plants at their expected level of operating standards. It has an experienced management team and continuously beefs up its talents for plants that will be constructed in the future. Concerns on succession have been actively addressed by identifying talents from within and staging the necessary training and intervention efforts to ensure the continuity in operations. Trading Risks Power spot prices are subject to significant volatility from supply and demand changes. Both long‐term and short‐term power prices may also fluctuate substantially due to the factors outside of the Company’s control, which include the following: forced outages, transmission constraints, disruptions in the delivery chain, weather conditions, and changes in fuel price. These factors have caused and are expected to cause fluctuation or instability in the operating results of the Generation Companies, particularly Generation Companies that sell substantial portions of the electricity they generate to the WESM.

AboitizPower plans to manage these risks by having a balanced portfolio of contracted and spot capacity. In particular, it intends to contract a majority of its base load and diesel capacity under price‐stable bilateral contracts, and offer most of its hydro‐electric capacity for peaking and ancillary services. Regulatory Risk AboitizPower’s Generation and Distribution businesses are subject to constantly evolving regulations. Regulators are tightening their scrutiny and the public has become more vigilant and involved in the power debate. To respond proactively to potential fundamental changes that can impact its businesses, AboitizPower’s regulatory team works very closely with its Generation and Distribution Companies and maintains open lines of communications with regulatory agencies. This includes actively participating in the consultative processes that lead to the development of new rules and policies covering the power industry. The Company’s regulatory team has also developed a strategy anchored on long‐term views of expected or anticipated changes in the regulatory field. The Company’s approach integrates understanding how regulations will affect its businesses, and planning and preparing for expected changes in regulation, rather than waiting for regulations to be imposed.

Business Interruption due to Natural Calamities and Critical Equipment Breakdown Loss of critical functions and equipment caused by natural calamities such as earthquakes, windstorms, typhoons and floods could result in a significant interruption of the Company’s 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.

Regular preventive maintenance of the Company’s facilities are being strictly observed and loss prevention controls are continually being evaluated and strengthened. To ensure the continuity of operations in the event of a business interruption, AboitizPower has started developing a Business Continuity and Crisis Management Plan in 2011. Business Interruption insurance has also been procured to cover the potential loss in gross profits in the event of a major damage to the Group’s critical facilities and assets. Financial Risks In the course of operation of the 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 measures to mitigate them are discussed in the notes to the financial statements.

Fuel Supply Risk AboitizPower has several thermal plants – TLI, STEAG Power and Cebu Energy which use coal, and CPPC, EAUC, and TMI which use Bunker C fuel. These fuel types are subject to significant fluctuation in fuel prices and supply issues.

For TLI, STEAG and Cebu Energy, their bilateral contracts allow for their fuel cost to be recovered from their tariffs. Meanwhile, SPPC and WMPC’s 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.

On the supply side, CPPC, EAUC and TMI each has entered into 2011 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 has finalized in 2011 a new supply contract. Cebu Energy has long term coal contracts with various coal suppliers, while STEAG had entered into an alternate coal supply agreement to allow it to diversify its fuel supply. TLI locked in the prices of its coal supply at a fixed price for 2011. TLI has also entered into a long term coal supply agreement with different suppliers of performance and blending coal to help ensure stability of supply.


Project Risks The rebirth of the Company’s Ambuklao Complex, the ongoing rehabilitation efforts of its facilities in Tiwi, Makban and Binga and its four power barges exposed the Company to significant project risks in 2011. For 2012, given the Company’s focus on Greenfield projects for its coal plants in Subic, Davao and Pagbilao, its small hydro projects, Tudaya 1 and 2 in Sibulan, Sita Simod in Bukidnon and Sabangan in Luzon, the Company is expecting more uncertainty relating to these projects scheduled to break ground in 2012. Given the magnitude and duration of these projects, there are inherent issues and risks, such as completion of these projects within specifications, budget and timelines. To assure the success of these projects, AboitizPower is partnering with contractors and suppliers of established reputations. As it deals with uncertain events and conditions that might have positive or negative effect on its project objectives, the Company will be implementing a project risk management framework and program based on the Project Management Book of Knowledge (PMBOK) standards in 2012. 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, Kasambagan, Cebu City, Philippines. The premises are leased from an Affiliate, CPDC.

On a consolidated basis, the 2011 total Property, Plant and Equipment of AboitizPower were valued at P78.71 bn as compared to P74.29 bn for 2010. The breakdown is as follows:

Property, Plant and Equipment as of December 31, 2011 and 2010 (in thousand pesos).

Property, Plant and Equipment 2011 2010

Land 608,026 114,336

Buildings, Warehouses and Improvements 2,714,222 951,281

Powerplant, Equipment and Steamfield Assets 74,301,864 73,370,137

Transmission, Distribution and Substation Equipment 5,422,567 4,998,903

Transportation Equipment 543,696 459,746

Office Furniture, Fixtures and Equipment 262,265 159,951

Leasehold Improvements 102,753 204,563

Electrical Equipment 1,935,569 1,642,611

Meter and Laboratory Equipment 472,776 383,765

Tools and Others 690,656 375,433

Construction in Progress 4,413,888 1,552,872

Less: Accumulated Depreciation and Amortization 12,760,164 9,921,834

TOTAL 78,708,118 74,291,764


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

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

equipment and machineries Sinsuat Avenue, Cotabato City In use for

operations Davao Light Industrial land, buildings/plants,

equipment and machineries P. Reyes Street, Davao City; Bajada, Davao City

In use for operations

Hedcor 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


Therma Marine Barge‐mounted diesel power plants

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


Therma Mobile Barge‐mounted diesel power plants

Navotas Fishport, Manila Under rehabilitation

Therma South Land Davao City; Davao del Sur For plant site

Vesper Land Bato, Toledo, Cebu For plant site

Item 3. Legal Proceedings Material Pending Legal Proceedings 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 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. In Jeanu A. Du, et. al. vs. VECO, the complainants moved to reconsider the Court of Appeal’s decision dismissing their case. The appeal remains pending with the Court of Appeals.


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 Province of Cebu elevated the case to the Court of Appeals. Both parties’ Memorandum were noted and admitted and the case is now submitted for resolution. 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. LHC filed its Memorandum on January 10, 2012. The Province of Benguet filed its Memorandum on January 17, 2012. The case is deemed submitted for decision.


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‐2398 RTC Br. 63, La Trinidad, Benguet January 4, 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 HEDC and Cleanergy (formerly, Northern Mini Hydro Corporation) 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 Cleanergy 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 Cleanergy, and as such, it cannot be made liable for whatever obligation, if any, as may pertain to HEDC and/or Cleanergy. 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 Cleanergy 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 Cleanergy. Hedcor only acquired the hydroelectric power plants, which are the subject of the assessed national wealth tax, from HEDC and Cleanergy 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. 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, subject of Memorandum of Agreement for signing of Hedcor, HEDC, Cleanergy, and the Province of Benguet. On April 25, 2011 Hedcor paid the National Wealth Tax assessment of the court as per Official Receipt No. BGT‐2556264 in the amount of P8,605,647.68. The case has been temporarily suspended until the filing of the signed memorandum of agreement with the court and the submission of a Joint Motion to Dismiss.

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 August 20,2012. 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. LHC appealed the assessment 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. The Province of Benguet, through the Office of the Governor, and LHC, engaged in negotiations to arrive at a possible settlement. On December 2009, NPC moved for the issuance of a decision based on a compromise agreement. Benguet opposed NPC’s motion and prayed that CBAA continue hearing the case and resolve the same on the merits. LHC filed its reply to Benguet’s opposition. As of March 30, 2012, the parties are awaiting further action by the CBAA.

Annual Report 2010 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. LHC appealed directly to the CBAA, where the trial of the case is ongoing. The next hearing is set on April 27, 2012.

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 March 6, 2009 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 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. Due to the on‐going negotiations between both parties, the court suspended all scheduled hearings to give the parties ample time to submit a compromise agreement. The compromise agreement has been signed by the parties and submitted to the court for approval on May 12, 2011 hearing. During the September 20, 2011 hearing, the Joint Motion for Judgment based on Compromise Agreement was deemed submitted for resolution, subject to the determination by the court on whether to require a BOI representative to testify on the regularity of the issuance or the validity of SNAP‐Magat’s BOI Certificate of Registration.


SNAP‐Magat filed for compliance, a copy of the judgment rendered on the Compromise Agreement on October 20, 2011. 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 2009 to 2012 were as follows:

2012 2011 2010 2009

High Low High Low High Low High Low First Quarter 31.90 28.75 31.60 26.20 12.75 8.60 4.65 3.90 Second Quarter NA NA 32.10 28.00 19.25 12.25 6.00 4.65 Third Quarter NA NA 32.60 27.00 21.80 18.00 6.70 5.30 Fourth Quarter NA NA 30.10 28.50 35.80 20.90 8.90 6.40

As of March 30, 2012, AboitizPower has 532 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 30, 2012 is P33.90 per share. (2) The top 20 stockholders of AboitizPower as of March 30, 2012 are as follows:

Name Number of Shares Percentage 1. ABOITIZ EQUITY VENTURES, INC. 5,653,763,954 76.83% 2. PCD NOMINEE CORPORATION (Filipino) 768,959,590 10.44% 3. PCD NOMINEE CORPORATION (Foreign) 595,024,478 8.09% 4. ABOITIZ & COMPANY, INC. 151,112,722 2.05% 5. BAUHINIA MANAGEMENT, INC. 9,845,000 0.13% 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. SABIN M. ABOITIZ 6,050,985 0.08% 11. RAMON ABOITIZ FOUNDATION, INC. 3,900,000 0.05% 12. IKER M. ABOITIZ 3,177,545 0.04% 13. HAWK VIEW CAPITAL, INC. 2,905,000 0.04% PORTOLA INVESTORS, INC. 2,905,000 0.04% 14. TRA MANAGEMENT & DEVELOPMENT CORPORATION 2,561,882 0.03% 15. TRIS MANAGEMENT CORPORATION 2,490,091 0.03% 16. UBP T/A 4B1‐153‐09 2,484,698 0.03% 17. GITANA MANAGEMENT & DEVELOPMENT CORPORATION 2,465,591 0.03%


TINKERBELL MANAGEMENT CORPORATION 2,465,591 0.03% 18. CAL MANAGEMENT CORPORATION 2,465,590 0.03% 19. NUSKI MANAGEMENT CORPORATION 2,387,492 0.03% 20. LMM HOMES MANAGEMENT & DEVELOPMENT CORP. 2,376,335 0.03 % (3) The cash dividends declared by AboitizPower to common stockholders from 2010 to 2012 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 5‐year corporate notes for P3.330 bn issued last December 18, 2008 was pre‐terminated and paid on December 19, 2011.

The 7‐year peso denominated corporate notes were issued to the following institutional investors:

NOTEHOLDERS (7‐Year Notes) AMOUNT DUE BDO PRIVATE BANK INC. WEALTH ADVISORY AND TRUST GROUP 19,400,000.00 BDO TRUST AND INVESTMENT GROUP 19,400,000.00 FIRST GUARANTEE LIFE ASSURANCE COMPANY, INC. 19,400,000.00 THE INSULAR LIFE ASSURANCE COMPANY, LTD. 485,000,000.00

TOTAL PRINCIPAL DUE 543,200,000.00

The total underwriting fees paid to the Joint Lead Managers for the issuance of the P3.89 bn corporate notes was P18.82 mn.

Year Cash Dividend Per Share Total Declared Record Date 2012 P1.32 P9.71 bn 3/16/2012 2011 P1.32 P9.71 bn 3/17/2011 2010 P 0.30 P2.21 bn 3/24/2010


(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:

NOTEHOLDERS (5‐Year Notes) AMOUNT DUE

METROPOLITAN BANK & TRUST GROUP 1,500,000,000.00 BDO PRIVATE BANK WEALTH ADVISORY & TRUST GROUP 1,058,000,000.00 THE INSULAR LIFE ASSURANCE CO., LTD. 700,000,000.00 PHILIPPINE SAVINGS BANK 500,000,000.00 UNITED COCONUT PLANTERS BANK 100,000,000.00 UNITED COCONUT PLANTERS BANK 100,000,000.00 UNITED COCONUT PLANTERS BANK 100,000,000.00 UNITED COCONUT PLANTERS BANK 100,000,000.00 UNITED COCONUT PLANTERS BANK 100,000,000.00 METROBANK 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 50,000,000.00 SOCIAL SECURITY SYSTEM PROVIDENT FUND 100,000,000.00 DEUTSCHE 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 100,000,000.00 PIONEER LIFE, INC. 50,000,000.00 FIRST 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.

(c) On April 14, 2011, AboitizPower issued a 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 in accordance with Section 9.2 of the 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 5‐year peso denominated corporate notes were issued to the following institutional investors:

NOTEHOLDERS AMOUNT DUE

BDO PRIVATE BANK INC. WEALTH ADVISORY & TRUST GROUP 960,000,000.00 METROPOLITAN BANK & TRUST COMPANY – TRUST BANKING GROUP AS TRUSTEE

800,000,000.00

FIRST METRO INVESTMENT CORPORATION 500,000,000.00 METROPOLITAN BANK & TRUST COMPANY 500,000,000.00 BPI ASSET MANAGEMENT & TRUST GROUP AS TRUSTEE 410,000,000.00 ALFM PESO BOND FUND, INC. REPRESENTED BY BPI INVESTMENT MANAGEMENT, INC. AS FUND MANAGER

40,000,000.00

BANCO DE ORO UNIBANK, INC. – TRUST & INVESTMENTS GROUP AS TRUSTEE 400,000,000.00 PHILIPPINE SAVINGS BANK 320,000,000.00 RIZAL COMMERCIAL BANKING CORPORATION 220,000,000.00 CHINA BANKING CORPORATION – TRUST GROUP AS TRUSTEE 215,000,000.00 ALLIED BANKING CORPORATION 200,000,000.00 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 50,000,000.00 SOCIAL SECURITY SYSTEM PROVIDENT FUND 100,000,000.00 DEUTSCHE 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 100,000,000.00 PIONEER LIFE, INC. 50,000,000.00 FIRST LIFE FINANCIAL COMPANY, INC. 10,000,000.00

TOTAL PRINCIPAL DUE 5,000,000,000.00

Item 6. Management’s Discussion and Analysis or Plan of Action MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Year Ended December 31, 2011 vs. Year Ended December 31, 2010 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 criticial 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, 2011 compared with the year ended December 31,


2010, the year ended December 31, 2010 compared with the year ended December 31, 2009 and the year ended December 31, 2009 compared with the year ended December 31, 2008. The following discussion and analysis of the Company’s consolidated financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes thereto as well as the accompanying schedules and disclosures set forth elsewhere in this report. Top Five Key Performance Indicators Management uses the following indicators to evaluate the performance of registrant Aboitiz Power Corporation and its subsidiaries (the Company and its subsidiaries are hereinafter collectively referred to as the “Group”):

1. Share in Net Earnings of Associates. Share in net earnings (losses) of associates represents the Group’s share in the undistributed earnings or losses of its investees for each reporting period subsequent to acquisition of said investment, 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 the investee at the date of acquisition. Share in Net Earnings of Associates indicates profitability of the investment and investees’ contribution to the group’s net income.

Manner of Computation: Associate’s Net Income (Loss) x Investor’s % ownership ‐ Goodwill

Impairment Cost

2. Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA). The Company computes EBITDA as earnings before extra‐ordinary items, net finance expense, income tax provision, depreciation and amortization. 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 capital. This aids management in identifying the impact on cash flow when the Group’s activities are in a state of growth or decline, and in evaluating management’s efforts to control the impact.

4. Current Ratio. Current ratio is a measurement of liquidity, calculated by dividing total

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

5. Debt–to–Equity Ratio. Debt‐to‐Equity ratio 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 debt by stockholders’ equity.


Year ended December 31, 2011 vs. Year ended December 31, 2010

Key Performance Indicators 2011 2010

Amounts in thousands of πs, except for financial ratios

SHARE IN NET EARNINGS OF ASSOCIATES 8,436,906 4,625,883

EBITDA 32,845,838 34,361,919

CASH FLOW GENERATED: Net cash flows from operating activities Net cash flows (used in) investing activities Net cash flows (used in) financing activities

22,642,117 (4,979,319) (12,575,210)

26,865,378 (3,958,240) (8,358,116)

Net Increase in Cash & Cash Equivalents 5,087,588 14,549,022

Cash & Cash Equivalents, Beginning 18,301,845 3,814,906

Cash & Cash Equivalents, End 23,391,561 18,301,845

CURRENT RATIO 3.46 2.58

DEBT‐TO‐EQUITY RATIO 1.19 1.33

The Company’s Share in net earnings of associates for the year rose significantly as compared to last year. The increase can be attributed to the contributions from the following associates:

• SN Aboitiz Power‐Magat, Inc.’s (SNAP‐Magat) increased acceptance of its nominated capacities to the National Grid Corporation of the Philippines (NGCP), SNAP‐Magat led to the significant jump in its ancillary revenues during the year.

• STEAG State Power Inc. (STEAG), the operator of a 232‐megawatt (MW) coal plant in

Misamis Oriental, higher revenues coming from the effects of an increase in a major index in its pricing formula. STEAG also booked a non‐recurring gain on collections of prior years’ cost reimbursements from the National Power Corporation (NPC) relating to its fuel importation.

• Cebu Energy Development Corporation’s (Cebu Energy) fresh earnings contributions

following the start of the commercial operations of its 246 MW Coal Plant in Toledo, Cebu last February 2011.

• Visayan Electric Company, Inc.’s (VECO), higher earnings contribution from higher margins

as a result of the implementation of its approved distribution tariff under the Performance Based Regulation (PBR) scheme.


Current ratio improved from 2.58:1 in 2010 * to 3.46:1 in 2011 * due to the significant upsurge in current assets coupled with a decrease in current liabilities versus 2010 yearend levels. The growth in cash, trade and other receivables, and other current assets account for the increase in current assets. Debt to equity ratio also improved from 1.33:1 as of December 31, 2010 to 1.19:1 as of December 31, 2011. This is mainly due to the buildup of equity which exceeds the increase in liabilities. Results of Operations The Company posted a consolidated net income of π21.61 bn, 14% lower than the P 25.04 bn realized in the prior year. This year’s results translate to an earnings per share of P2.94. After adjusting for non‐recurring items, the Company’s core net income for 2011 amounted to P21.10 bn, 14% lower than that of the previous year. Core net income for the year was arrived at after adjusting for the effects of the revaluation of consolidated dollar denominated loans and placements which led to a P164 mn non‐recurring loss. The Company also recognized P663 mn in one off‐gains relating to (1) the revenue adjustments at a wholly owned subsidiary resulting from a favorable ruling by the industry regulator on its tariff structure for an ancillary services contract; (2) the reversal of the 2010 accrued expenses relating to an IPPA contract at a subsidiary; (3) cost reimbursements relating to fuel importation realized by one of the Company’s associates; and (4) non‐recurring fees that were expensed by the Company relating to a prepayment of an outstanding loan in the last quarter of the year. Power Generation The Generation Companies continue to be a dependable contributor to the earnings of the Company accounting for 89% of the Company’s earnings. This year the Generation Companies contributed P20.4 bn, a 16% decline from last year’s contribution of P24.39 bn. The Generation Companies’ lower contributions can be attributed to both demand and supply factors. Demand for electricity remained relatively flat during the year, while on the supply side, there was a significant reduction of plant outages in 2011 for the Luzon based power plants. Both these factors led to a softening of spot market prices which translated to lower average selling prices for the group resulting in the drop by 7% as compared to previous years. Volume sold also declined by 3% as compared to last year’s sales. Net generation for the year was 9,422 GWh versus 9,762 GWh in 2010. As a result of low prices that prevailed in the WESM, lower spot market transactions were made during the year. Therma Luzon Inc. (TLI), the IPP administrator of the Pagbilao coal‐fired power plant, experienced a margin squeeze as fuel costs increased. The increase in coal prices during the period affected TLI as majority of its bilateral contracts are currently pegged to NPC Time‐of‐Use rates which does not allow for a full pass through of its fuel costs. For the period under review, ancillary service revenues of SNAP‐Magat and SNAP‐Benguet went up by 81% over last year. Higher water levels enhanced the plants’ capability to provide ancillary services, and higher level of acceptance of nominated capacities by NGCP. The significant contribution, particularly of


SNAP‐Magat, cushioned the impact of the decline for the Power Generation group resulting from selling price and volume variances. Further mitigating the lower earnings are as follows: (1) higher contributions from Therma Marine Inc. (TMI) resulting from tariff adjustments approved by the Energy Regulatory Commission (ERC) in the early part of this year, (2) the full year contributions from Hedcor Sibulan, (3) the earnings from Cebu Energy upon full commercial operations, and (4) the robust contribution from STEAG due to higher margins over coal and costs recoveries on its fuel importations. Power Distribution The Distribution Utilities contributed P2.41 bn from a prior year contribution of P1.93 bn. The Distriution Utilities’ 25% increase in income contribution came as a result of higher electricity sales and average gross margins. Total attributable electricity sales grew by 3% from 3,606 GWh to 3,727 GWh, mostly from growth coming from its industrial segment. Average gross margins meanwhile went up by 15% to P1.44 per kWh resulting from the implementation of the approved distribution tariffs of some of the Company’s Distribution Utilities under the Performance Based Regulation. Davao Light also had higher contributions this year due to a significant reduction in its operating costs. The higher availability of power supply to its franchise area did not require Davao Light to run its back up power plant leading, to a decrease in plant related expenses. Material Changes in Line Items of Registrant’s Statements of Income and Comprehensive Income Consolidated Statements of Income Consolidated net income attributable to equity holders of the Parent decreased by 14% from P25.04 bn in 2010 to P21.61 bn in 2011. The various movements in the revenue and expense items are shown below to account for the decrease:

Consolidated Net Income Attributable to Equity Holders of the Parent for 2010 P25,041,116

Decrease in Operating Revenues (5,075,821)Increase in Operating Expenses (800,344)

Increase in Share in Net Earnings of Associates 3,811,023Increase in Interest Income 637,363Increase in Interest Expense (667,282)Increase in Other Income (907,550)

Higher Provision for Income Taxes (196,512)Increase in Net Income Attributable to Non‐controlling Interests (233,740)

Total (3,199,123)


Operating Revenues (9% decrease from P59.55 bn to P54.48 bn)


TLI’s revenues declined by 22% to P4.83 bn. This is mainly due to a decrease in its average selling prices which went down by 18% YoY as a result of the lower WESM prices during the year, as well as a 4% decline in volume sold. AP Renewables, Inc. (APRI) likewise experienced a drop in its revenues by 10% to P1.66 bn. Average selling prices went down by 5%, while volume sold decreased by the same percentage compared to prior year. The decrease enumerated above was partly tempered by the P633 mn in fresh revenues from newly consolidated subsidiary Luzon Hydro Corp. (LHC), as well as from higher revenues from Distribution Utilities. Operating Expenses The 2% increase in Operating Expenses mainly came from higher cost of generated power as fuel costs increased particularly for TLI, a coal‐fired power plant. Share in Net Earnings of Associates (82% increase from P4.63 bn to P8.44 bn) The combined contributions of SNAP‐Magat and SNAP‐Benguet rose by 81% compared to last year’s contributions, driven by higher revenues arising from increased acceptance ancillary service nominations. The biggest slice of the contribution came from SNAP‐Magat which managed to double its earnings contributions from prior years. Higher coal margins and a non recurring fuel cost reimbursement allowed STEAG to increase its contributions to its share in net earnings. Higher margins from improved tariffs under the Performance Based Regulation (PBR) scheme as approved by the ERC allowed VECO to post higher earnings contributions for the year. Rounding up the net earnings from associates are the fresh income contributions of Cebu Energy, which started full commercial operations in February of 2011. Interest Income (284% increase from P224 mn to P862 mn) During the year, the average cash balances held by the Company, as well as at its subsidiaries, were higher than the average balances carried during most of 2010. The robust cash position resulted in the increase in Interest Income recognized for the period in review. Interest Expense (10% increase from P6.68 bn to P7.35 bn)


Over half of the increase in Interest Expense is due to higher accreted interest on the finance lease obligation of TLI. The remaining increase is due to higher interest expenses for the Company in 2011 as it managed to raise P5 bn in fixed rate notes in the first half of the year. Other Income (57% decrease from P1.60 bn to P693 mn) The large swing in Other Income by P907 mn is mainly due to an unrealized foreign exchange (FX) loss of P164 mn in 2011 as compared to the P1.01 bn unrealized FX gains last year. The significant decrease in unrealized FX gains was the result of the restatement of the dollar‐denominated portion of TLI ‘s finance lease. TLI recorded a large FX gain due to a higher peso appreciation. Net Income Attributable to Non‐controlling Interests The 558% increase in Net Income Attributable to Non‐controlling Interests was largely due to the increase in Abovant Holdings, Inc.’s (AHI) earnings for the period of which 40% is for the account of the minority shareholders. AHI’s associate, Cebu Energy started its full commercial operations in 2011. The balance of the increase is due to the recognition by the Company of the 40% minority shareholder’s participation in Cebu Private Power Corporation’s increase in net income. Consolidated Statements of Comprehensive Income Consolidated Comprehensive Income Attributable to Equity Holders of the Parent declined 16% YoY, from P25.06 bn to P20.94 bn. This was mainly due to the decline in the consolidated net income for the period under review. Changes in Registrant’s Resources, Liabilities and Shareholders’ Equity Assets Total assets as of December 31, 2011 in the amount of P153.53 bn increased by 14% versus total assets as of December 31, 2010 of P134.56 bn. The major changes in the balance sheet accounts are discussed below:

a) Cash and Cash Equivalents increased by 28% (from P18.30 bn ending December 2010 to P23.39 bn ending December 2011). The robust cash flows from operations of TLI and ARI resulted to large cash balances held at both companies at year end. The Company also consolidates for the first time, the cash held by newly consolidated company LHC. These increases mitigated the decline in cash at Parent level following the prepayment of the P3.33 bn fixed rate notes prior to year end.


b) Trade and Other Receivables increased by 40% (from P6.81 bn as of December 31, 2010 to P9.51 bn as of December 31, 2011). This is due to the P2.5 bn in dividends receivable from one of the Company’s associates. The remaining increase is attributable to higher Trade Receivables at TMI as it awaits the collection of receivables arising from its tariff adjustments and the recognition of the Trade Receivables of newly consolidated LHC.

c) The 18% (P328 mn) increase in Inventories is primarily due to higher cost of fuel inventories

at TLI and TMI, as global fuel prices increased during the year.

d) Other Current Assets increased by 15% (from P959 mn in December 31, 2010 to P1.11 bn in December 31, 2011) mainly due to build‐up of input VAT by power generation subsidiaries during the period in review.

e) The 6% increase in Property, Plant and Equipment is mostly due to the recent acquisition by

Therma Mobile of four barge‐mounted floating power plants in May 2011. APRI’s cost of plant rehabilitation and the capital expenditures of the distribution group also accounted for some of the increase. The increase is net of depreciation expense booked during the period under review.

f) As a result of the consolidation of the accounts of the newly qualified subsidiary, LHC, the

Intangible Asset ‐ Service Concession Rights account went up by P3.22 bn. LHC’s power plant is recorded as an intangible asset under IFRIC 12. The intangible asset is amortized using the straightline method over 25 years, which is the service concession period, and assessed for impairment whenever there is an indication of that the asset is impaired.

g) Deferred Income Tax Assets increased by P27 mn mainly due to the consolidation of the

deferred tax assets of newly qualified subsidiary, LHC. h) Other Noncurrent Assets increased by 223% (from P1.23 bn as of December 31, 2010 to

P3.95 bn as of December 31, 2011) mainly due to the P2.24 bn advance payments made to suppliers for the purchase of turbines and other related costs by Therma South, Inc.

Liabilities Consolidated liabilities increased by 8% from P76.82 bn as of December 31, 2010 to P83.34 bn as of December 31, 2011. The significant accounts contributing to the increase are as follows:

a) Bank Loans decreased (from P1.98 bn in December 31, 2010 to P1.61 bn in December 31,2011). During the year AP Parent paid its P1.29 bn short term bank loans. On the other hand, the Company’s wholly owned subsidiary Hedcor and certain Distribution Utilities availed of short term bank loans to meet their respective working capital requirements. All of the above resulted to the 18% decrease in bank loans by year end.


b) Income Tax Payable increased by 21% (from P180 mn in December 31, 2010 to P143 mn in December 31, 2011), mainly due to the higher current tax provision of the Group.

c) Payable to Preferred Shareholders of a Subsidiary inclusive of current portion decreased by

18% or P14 mn as payments to preferred shareholders were made during the year. d) Long‐term Debt had a net increase of P2.10 bn resulting from the following financing

activities during the year.

• The Company’s issuance of P5 bn corporate fixed rate notes. The Company likewise prepaid P3.33 bn in fixed rate corporate notes in the last quarter of the year.

• First time consolidation P521 mn of outstanding LHC long‐term debt. • P565 mn new long‐term loan availed by Subic Enerzone Corporation net of the P119 mn

payment of an old debt. The 13% increase in long‐term debt is net of timely amortization payments on existing loans.

e) Finance Lease Obligations recognized at TLI, increased by 9% or P4.41 bn as accreted interest expenses on the finance lease obligation exceeds the amount of monthly payments made to PSALM.

f) The bulk of the P160 mn increase in Customer Deposits was mainly due to new connections

in the franchise area of Davao Light resulting from the growth in its customer base. g) Deferred Income Tax Liability increased due to TLI’s recognition of corresponding income

tax provision on the unrealized FX gains on TLI’s dollar obligations to PSALM beyond its income tax holiday period.

Equity Equity attributable to equity holders of the Parent increased from P57.33 bn as of December 2010 to P68.56 bn as December 31, 2011. This increase is mainly due to the increase in retained earnings by P11.89 bn as a result of the consolidated net income recorded for the period under review of P21.61 bn net of the dividend payment of P9.71 bn in April 5, 2011.


Material Changes in Liquidity and Cash Reserves of Registrant

Cash and cash equivalents grew by 28% from P18.30 bn as of December 31, 2010 to P23.39 bn as of December 31, 2011. Cash generated from the Group’s operations was the largest source of cash inflow bringing in P22.64 bn during the year. This amount is lower by 16% when compared to the cash generated by operations in the prior year as the Group recognized lower income before income tax during the year. The cash used in the Group’s investing activities went primarily to investments in the acquisition, purchase or construction of new assets which increased the Group’s property, plant and equipment portfolio by P7.46 bn for the year. Advances were also made to a supplier for a major part on an on‐going construction of a power plant. These outflows were partly mitigated by cash dividends received totaling P3.98 bn. There was a significant amount of cash used in financing activites as the Group paid P9.71 bn in dividends during the year. Payments for long‐term debt totaling P4.21 bn were also made during the year, as well as payments on the Finance Lease Obligation of P1.09 bn. Interest payments on existing obligations were timely made and short term bank loans were likewise paid. The outflows for these financing activities were cushioned by the availment of a long term debt resulting to a cash inflow of P5.52 bn. The above activities resulted to an upward change in cash of P5.09 bn. Financial Ratios Current ratio improved from 2.58x in 2010 to 3.46x in 2011 due to the significant increase in current assets coupled with a slight decrease in current liabilities versus 2010 year end levels. The significant growth in cash, trade and other receivables, inventories and other current assets account for the increase in current assets. Debt to equity ratio also improved from 1.33 as of December 31, 2010 to 1.19 as of December 31, 2011. This is mainly due to the buildup of equity which exceeded the increase in liabilities. 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 2012. 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:


Power Generation Business 1. Continued growth in the Company’s attributable capacity AboitizPower ended 2011 with a 15% YoY expansion in its total attributable generating capacity, from 2,051 MW to 2,350 MW. The capacity growth was mainly due to the following:

‐ Assumption of full ownership and control of LHC In May 2011, AboitizPower’s 100% owned ARI assumed full ownership and control of LHC after meeting all conditions set out in a Memorandum of Agreement with PHBI. PHBI, a wholly owned subsidiary of Pacific Pty Ltd of Australia is the joint venture partner of ARI in LHC, which owns and operates the 70 MW Bakun run‐of‐river hydropower plant in Ilocos Sur. As a result of having full control and ownership in LHC, an additional 35 MW of attributable capacity was added to AboitizPower’s portfolio of generation assets. ‐ Acquisition of the 242 MW Navotas Power Barges In May 2011, Therma Mobile a wholly owned subsidiary of AboitizPower, acquired four barge‐mounted floating power plants including their respective operating facilities from Duracom Mobile Power Corporation and East Asia Diesel Power Corporation. Upon turnover, rehabilitation works commenced with scheduled date of completion by the fourth quarter of 2011 for 123 MW and the balance estimated within 2012. ‐ Completion of the rehabilitation project of the Ambuklao Hydro Power Facility In September 2011, SNAP‐Benguet was awarded by the ERC a COC for the operation of the Ambuklao hydropower plant. The COC, which was approved on August 31, 2011, shall be effective for a period of five years. Upon the turnover of the facility by the PSALM to SNAP‐Benguet in 2008, rehabilitation works were implemented on the Ambuklao hydrowpower facility. Its completion resulted to the increase in generation capacity, from 75 MW to 105 MW. AboitizPower has an effective stake of 50% in this facility. ‐ Partial completion of the rehabilitation of the Binga Hydro Power Plant Rehabilitation works on one of the units in the Binga hydropower facility was completed in the fourth quarter of 2011. As a result, total capacity of the Binga hydropower plant increased by 5 MW, from 100 MW to 105 MW. AboitizPower has an effective stake of 50% in this facility.


‐ Completion of the 4 MW Irisan Hydro Power Greenfield project AboitizPower’s wholly owned subsidiary Hedcor completed the construction of the 4 MW Irisan hydropower plant in Tuba, Benguet. The plant was commissioned in September 2011.

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

‐ Completion of the rehabilitation of the Binga Hydro Power Plant In 2011, AboitizPower, together with its partner SN Power, commenced the programmed rehabilitation of the 100 MW Binga hydropower plant, which is consisted of four units with a capacity of 25 MW each. To date, the program involves the rehabilitation of three units, given the completion of the works done on the first unit in December 2011. Works on the second unit have commenced and are expected to be completed in June 2012. Rehabilitation of the remaining two units will commence thereafter. Full completion will result to Binga’s total capacity reaching 120 MW, from the current 105 MW. AboitizPower has an effective stake of 50% in this facility. ‐ 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. Works on the Tiwi facilities are targeted for completion by the third quarter of 2012, while those for Makban are seen to be finished by first quarter of 2013. Enhancements in the plants’ availability rate are expected following the completion of the refurbishment, rehabilitation and resource improvements. ‐ Greenfield and Brownfield developments 600 MW Coal‐fired Power Plant in Subic. This is a project by RP Energy, a joint venture company formed by AboitizPower’s wholly owned subsidiary TPI and TCIC. In June 2011, Meralco’s wholly owned subsidiary, MPGC, announced its decision to acquire an ownership interest in the project. On July 22, 2011, MPGC, TPI and TCIC signed a shareholder agreement under which MPGC took a controlling interest in RP Energy, with TPI and TCIC owning the remaining stake equally. The project involves the construction and operation of a 2x300 MW circulating‐fluidized‐bed coal‐fired power plant in the Subic Bay Freeport Zone. In January 2012, RP Energy submitted to the DENR an application to amend the existing ECC to cover two high‐efficiency 300‐MW units with main steam reheat systems. Site preparation and the finalization of the EPC contract are anticipated to take place in the second quarter of 2012. Completion of the first unit is targeted by the second half of 2015, with the second unit to follow 6 months thereafter. 300 MW Coal‐fired Power Plant in Davao. AboitizPower, through 100%‐owned subsidiary TSI, is planning to put up a 2x150 MW coal‐fired power plant in Davao, which is the biggest load center in the island of Mindanao. TSI acquired the project site in August 2011. The DENR issued the


ECC for the project on September 9, 2011. The company is currently in the process of obtaining all necessary permits and government clearances in addition to the ECC. Once done, construction will commence immediately. The first generating unit (150 MW) is expected to be completed 34 months after, with the second unit (150 MW) to follow in 3 months. 400 MW Coal‐fired Power Plant in Pagbilao, Quezon. On September 27, 2011, AboitizPower signed a Memorandum of Understanding with Marubeni Corporation (Marubeni) to formalize their intention to jointly develop, construct and operate a coal‐fired power plant with a capacity of approximately 400 MW. The proposed location will be within the premises of the existing 700 MW Pagbilao Unit I and II Coal Fired Thermal Power Plant in Quezon. The terms and conditions of the joint investment will be finalized in a definitive agreement to be agreed upon by the parties. Marubeni is part‐owner of Team Energy Corporation, which owns and operates the Pagbilao Power Plant under a build‐operate‐transfer contract with the NPC. On the other hand, AboitizPower, through wholly owned subsidiary TLI, is the IPP of the Pagbilao Power Plant under the IPP Administration Agreement with PSALM. 150 MW Coal‐fired Power Plant in Misamis Oriental. On June 28, 2010, AboitizPower and its partners in STEAG Power, 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 putting up another unit. 13.7 MW Tudaya 1 and 2 Hydro Power Plant Project. AboitizPower’s 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 plants, tapping the same water resource, which are the Sibulan and Baroring rivers. The two plants will have a combined capacity of 13.7 MW. The project has been issued its ECC and endorsed by the local communities. Hedcor Tudaya is currently working on obtaining the water permits and awaiting finalization of its RE contract. Target groundbreaking is by May 2012. Construction is estimated to be completed in 22 months. 13.2 MW Sabangan Hydro Power Plant Project. This involves the construction and operation of a hydropower plant facility in Mt. Province, a province located in Northern Luzon. This project will be undertaken by a wholly owned subsidiary of AboitizPower, Hedcor Sabangan. The project was already granted an ECC by the DENR. Engineering and design are underway. Groundbreaking is targeted in the fourth quarter of 2012, with completion expected after a 2‐year construction period. 11.5 MW Hedcor Tamugan Hydro Power Plant Project. In 2010, wholly owned subsidiary, Hedcor Tamugan, Inc. (Hedcor Tamugan), has reached an agreement with the Davao City Water District


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 Davao 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 facility 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.

• 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 plants with capacities ranging from 5 MW to 50 MW. When the projects pass the evaluation stage and once permits are secured, the two‐year construction period for the hydropower plant facilities will commence.

2. Participation in the Government’s Privatization Program for its Power Assets AboitizPower 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 AboitizPower 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 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 31, 2013. The company is currently in its 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 that shifted to PBR, which implemented their approved rate structures in August 2010. Both companies implemented their approved rates for the second year of its regulatory period in August 2011. SFELAPCO and SEZ are part of the fourth batch (Group D) of private distribution utilities to enter PBR. In July 2011, the ERC released the final determination on the applications for annual revenue requirements and performance incentive schemes for the regulatory period October 2011 to September 2015. Implementation of the approved rate structures of SEZ and SFELAPCO took place in January 2012 and March 2012, respectively. All under‐recoveries since October 2011 are allowed to be recouped in the next regulatory year. Market and Industry Developments Open Access and Retail Competition Per EPIRA, the conditions for the commencement of the Open Access 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.

Under Open Access, 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 Open Access presents a big opportunity for AboitizPower, as it has two wholly owned subsidiaries (i.e. AESI and AdventEnergy ) 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. In June 2011, the ERC declared December 26, 2011 as the Open Access Date to mark the commencement of the full operations of the competitive retail electricity market in Luzon and Visayas. However, after careful deliberation, the ERC acknowledged that not all the necessary rules, systems and infrastructures required for the implementation of the Open Access have been put in place to meet the contemplated timetable for implementation. In October 2011, the ERC announced the deferment of the Open Access Date. A definitive timeline leading to the eventual implementation will be issued by the ERC after consultation with all the stakeholders. Year ended December 31, 2010 vs. Year ended December 31, 2009

The table below shows the comparative figure of the top 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 2,535,386 EBITDA 34,361,919 9,866,532 CASH FLOW GENERATED: Net cash flows from operating activities 27,275,647 5,873,633 Net 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.


Increase in Operating Revenues 36,377,193Increase in Operating Expenses (15,601,780)

Increase in Share in Net Earnings of Associates 2,090,497Decrease 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 in 2010.

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.

94 • SEC Form 17-A

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. 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 2,784,511 EBITDA 9,866,532 5,406,974 CASH 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.


Item 7. Financial Statements The consolidated financial statements of AboitizPower are incorporated herein by reference. The schedules listed in the accompanying Index to Supplementary Schedules are filed as part of this SEC 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 2011 2010 Audit Fees P315,000

P300,000

Tax Fees P50,000 All Other Fees ‐‐ ‐‐ Total P315,000

P300,000

As a policy, the Board Audit Committee makes recommendations to the Board of Directors concerning the choice of external auditor and pre–approves audit plans, scope and frequency before the audit is conducted.

Audit services of SGV & Co. for the 2011 and 2010 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 13 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 13 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 February 29, 2012, the Board Audit Committee of AboitizPower 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 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 have submitted engagement proposals to act as AboitizPower’s external auditor for 2012.

PART III – CONTROL AND COMPENSATION INFORMATION

Item 9. Directors and Executive Officers of the Issuer Below is a list of AboitizPower’s directors for 2011‐2012 with their corresponding positions and offices held for the past five years. The directors assumed their directorship during AboitizPower’s annual stockholders’ meeting in 2011 for a term of one year.

ENRIQUE M. ABOITIZ, JR. Chairman of the Board of Directors Chairman – Board Risk Management Committee Mr. Enrique M. Aboitiz, Jr., 58 years old, Filipino, has served as Director and Chairman of the Board of Directors of AboitizPower since 2009. He is currently a Director and Senior Vice‐President of AEV and Aboitiz & Company, Inc. 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. 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 Chairman ‐ Board Corporate Governance Committee Mr. Jon Ramon Aboitiz, 63 years old, Filipino, has been a Director of AboitizPower since 1998 and served as Chairman of the Board of AboitizPower from 1998 to 2008. Mr. Aboitiz began his career with the Aboitiz Group in 1970. From manager of the Aboitiz Shipping Corporation, Mr. Aboitiz was promoted to President of the company in 1976 and became President of Aboitiz & Company in 1991 until 2008. He is also Chairman of the Board of Directors of Aboitiz & Company, Inc., Aboitiz Equity Ventures, Inc. and Aboitiz Jebsen Company, Inc.; Director of City Savings Bank, Inc. and International Container Terminal Services, Inc. Mr. Aboitiz is also the Vice Chairman of the Board of Directors of Union Bank of the Philippines. He is Chairman of the bank’s Executive Committee, Risk Management Committee and Corporate Governance Committee, including the latter’s Compensation and Remuneration, and Nominations Sub‐Committees. He is President of the Aboitiz Foundation, Inc., Trustee and Vice President of the 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 of the Association of Foundations as well as The Coca Cola Export Corporation in the Philippines. Mr. Aboitiz holds a B.S. Commerce degree, Major in Management from the Santa Clara University, California.


ERRAMON I. ABOITIZ President and Chief Executive Officer Member – Board Corporate Governance Committee and Board Risk Management Committee Mr. Erramon I. Aboitiz, 55 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 a Director of AEV 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 Aboitiz & Company, Inc.; Chairman of the Board of Directors of 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., SN Aboitiz Power‐Benguet, Inc., Aboitiz Renewables, Inc., Therma Marine, Inc., Therma Power, Inc., Visayan Electric Company, Inc. and City Savings Bank, Inc.; and Director of STEAG State Power Inc., Union Bank of the Philippines and Pilmico Foods Corporation. He is also Chairman of Aboitiz Foundation, Inc. and a director of the Family Business Development Center (Ateneo de Manila University). He holds a degree in Bachelor of Science in Business Administration, Major in Accounting and Finance from Gonzaga University, Spokane, U.S.A. MIKEL A. ABOITIZ Director Member ‐ Board Audit Committee Mr. Mikel A. Aboitiz, 57 years old, Filipino, has been a Director of AboitizPower since 1998. He is also the Senior Vice President‐Chief Information Officer and Chief Strategy Officer of AEV; Director and Senior Vice President for Strategy of Aboitiz & Company, Inc.; President & Chief Executive Officer of City Savings Bank, Inc., Inc.; Director of Visayan Electric Company, Inc., Cotabato Light & Power Company, Davao Light & 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 Executive Vice President & Chief Operating Officer ‐ Power Distribution Group; Member ‐ Board Audit Committee Mr. Jaime Jose Y. Aboitiz, 50 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 Director and Executive Vice President and Chief Operating Officer of Visayan Electric Company, Inc.; President and Chief Executive Officer of Cotabato Light & Power Company, 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. and Hedcor, 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 Mr. Antonio R. Moraza, 55 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, Cebu Private Power 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 Aboitiz & Company, Inc.; President and Chief Executive Officer of Abovant Holdings, Inc., Therma Luzon, Inc., and Aboitiz Renewables, Inc.; President of Manila‐Oslo Renewable Enterprise, Inc., Therma Marine, Inc. and Therma Power, Inc.; and Director of SN Aboitiz Power‐Benguet, Inc., SN Aboitiz Power‐ Magat, Inc., Luzon Hydro Corporation, Southern Philippines Power Corporation, STEAG State Power Inc., and Western Mindanao 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 and Board Risk Management Committee Mr. Jose R. Facundo, 73 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 was 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 and Board Corporate Governance Committee

Mr. Romeo L. Bernardo, 57 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 and Board Risk Management Committee Mr. Jakob G. Disch, 57 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 with Rule 38 of the Securities Regulation Code (SRC Rule 38), AboitizPower’s Amended By‐Laws and AboitizPower’s Guidelines . The 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, 2012, as provided for in Section 2 of the Guidelines and the table for nominations was closed on February 15, 2012, 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, 2012 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 G. 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. Attached as Annexes “A”, “A‐1” and “A‐2” are the Certifications of Qualification of the Nominees for Mr. Facundo, Bernardo and Disch, respectively. AboitizPower stockholders Joy E. Ornopia, Joanna Marie S. Abay and Esmeralda C. Daño 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 nor 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 2012‐2013:

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 21, 2012 or not later than April 27, 2012. All other information regarding the positions and offices by the abovementioned nominees are integrated in Item 5 (a)(1) hereof. Officers for 2011 ‐2012

Below is a list of AboitizPower’s officers for 2011‐2012 with their corresponding positions and offices held for the past five years. The officers assumed their positions during AboitizPower’s annual organizational meeting in 2011 for a term of one year. ERRAMON I. ABOITIZ President and Chief Executive Officer Member – Board Corporate Governance Committee and Board Risk Management Committee


Mr. Erramon I. Aboitiz, 55 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 a Director of AEV 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 Aboitiz & Company, Inc.; Chairman of the Board of Directors of 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., SN Aboitiz Power‐Benguet, Inc., Aboitiz Renewables, Inc., Therma Marine, Inc., Therma Power, Inc., Visayan Electric Company, Inc. and City Savings Bank, Inc.; and Director of STEAG State Power Inc., Union Bank of the Philippines and Pilmico Foods Corporation. He is also Chairman of Aboitiz Foundation, Inc. and a director of the Family Business Development Center (Ateneo de Manila University). He holds a degree in Bachelor of Science 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 Mr. Antonio R. Moraza, 55 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, Cebu Private Power 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 Aboitiz & Company, Inc.; President and Chief Executive Officer of Abovant Holdings, Inc., Therma Luzon, Inc., and Aboitiz Renewables, Inc.; President of Manila‐Oslo Renewable Enterprise, Inc., Therma Marine, Inc. and Therma Power, Inc.; and Director of SN Aboitiz Power‐Benguet, Inc., SN Aboitiz Power‐ Magat, Inc., Luzon Hydro Corporation, Southern Philippines Power Corporation, STEAG State Power Inc., and Western Mindanao 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. Jaime Jose Y. Aboitiz, 50 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 Director and Executive Vice President and Chief Operating Officer of Visayan Electric Company, Inc.; President and Chief Executive Officer of Cotabato Light & Power Company, 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. and Hedcor, 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. Juan Antonio E. Bernad, 55 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; and 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. Luis Miguel O. Aboitiz, 47 years old, Filipino, has been AboitizPower’s Senior Vice President – Power Marketing and Trading since 2009. He is currently AEV’s First Vice President; President and Chief Executive Officer of Aboitiz Energy Solutions, Inc. and Adventenergy, Inc.; Director and Senior Vice President – Business Development of Hedcor, Inc.; and Director of Aboitiz Renewables, Inc., Therma Power, Inc., Aboitiz & Company, Inc., Pilmico Animal Nutrition Corporation, Pilmico Foods Corporation, Manila‐Oslo Renewable Enterprise, Inc., Therma Luzon, Inc., AP Renewables, Inc., and Hedcor Sibulan, Inc. 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. GABRIEL T. MAÑALAC Senior Vice President – Treasurer Mr. Gabriel T. Mañalac, 55 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 of AEV 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. 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. Iker M. Aboitiz, 39 years old, Filipino, has been AboitizPower’s First Vice President and Chief Financial Officer since 2007. He is currently a Director and Chief Financial Officer of Abovant Holdings, Inc.; Director and Chief Financial Officer and Treasurer of Hijos de F. Escaño, Inc.; Director of Cotabato Light & Power Company, Therma Power, 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. RAYMOND E. CUNNINGHAM First Vice President for Business Development Mr. Raymond E. 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. Manuel R. Lozano, 41 years old, Filipino, has been Chief Financial Officer of the Power Generation Group of AboitizPower since 2009. He is currently the Director and Chief Financial Officer of Hedcor, Inc. and Hedcor Sibulan, Inc. He is concurrently Chief Financial Officer/Treasurer of AP Renewables, Inc. and Therma Luzon, Inc. He is Director and Treasurer of Therma Marine, Inc. He was the Chief Financial Officer and Director of Paxys, Inc., a PSE‐listed company focused on the BPO industry and other IT‐related sectors within the Asia Pacific region, before he joined the Aboitiz Group. He has a wide range of experience working in several financial institutions. He earned his Bachelor of Science in Business Administration from the University of the Philippines Diliman and his MBA from The Wharton School of the University of Pennsylvania. MANUEL M. ORIG First Vice President ‐ Mindanao Affairs Mr. Manuel M. Orig, 70 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, Inc. He was Executive Vice President of Davao Light & Power Company, Inc. prior to his appointment in AboitizPower. He was instrumental in transforming Davao Light & Power Company, Inc. 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 Colegio de 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. Ma. Chona Y. Tiu, 54 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, Inc., Subic Enerzone Corporation and Mactan Enerzone Corporation. . ALVIN S. ARCO Vice President ‐ Regulatory Affairs Mr. Alvin S. Arco, 51 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. Wilfredo R. Bacareza, Jr., 34 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 300 MW coal‐fired power plant project in Subic Bay, Philippines, acquisition of two 100 MW power barges located in Mindanao and the 700 MW 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 for Engineering ‐ Power Distribution Group Mr. Raul C. Lucero, 44 years old, Filipino, has been Vice President for 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 & Power Company, Inc. in 2000. He was involved in the successful bid by AEV for the management of Subic Bay Metropolitan Authority’s distribution system in the Subic Bay Freeport Zone in 2003. He was promoted to Senior Vice President of Davao Light & Power Company, Inc. 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 for Special Projects

Mr. Anastacio D. Cubos, Jr., 61 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 Light & Power Company, Inc. He was also Davao Light & Power Company, Inc.’s Vice President – Engineering from 1998 to 2000 and its 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 & Power Company. 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 for Business Development Mr. Thomas J. Sliman, Jr., 52 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 USA. After working for 20 years in the USA 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. WILLIAM L. RUCCIUS Vice President for Business Development Mr. William L. Ruccius, 60 years old, American, was appointed as Vice President for Business Development of AboitizPower in June 2011. He has over 15 years experience throughout Asia in the


energy business and was President and Chief Executive Officer of AES Orient in Hong Kong from 1998 to 2003. Before joining AboitizPower, Mr. Ruccius was the Managing Director of Asia Energy Products. Mr. Ruccius earned his degree in Bachelor of Science in Chemical Engineering from Lehigh University and his Masters of Business Administration from the University of Houston. KENTON E. HEUERTZ Vice President for Asset Management ‐ Power Generation Group Mr. Kenton E. Heuertz, 55 years old, American, was appointed as Vice President for Asset Management ‐ Power Generation Group of AboitizPower in February 2012. He has extensive experience in developing, implementing and administering natural gas pipeline safety, loss control, environmental, damage prevention and risk management programs acquired from working with natural gas pipeline companies and electric power generation, transmission and distribution companies in the USA. Before joining AboitizPower, Mr. Heuertz was previously the Project Manager – Gas Engineering and Director, Risk and Insurance Management of MidAmerican Energy Holdings Company. He is a graduate of Bachelor of Arts and Sciences in Business Administration from William Penn University, Oskaloosa, Iowa, USA. He holds numerous certificates from Texas A&M University and University of Texas ‐ Austin Petroleum Extension Services, University of Nebraska – Lincoln, NE College of Mechanical Engineering, and from Central Community College – Hastings, NE Computer Sciences. He is a member of the American Society of Safety Engineers. ROLAND U. GAERLAN Vice President for Marketing Mr. Roland U. Gaerlan, 49 years old, Filipino, has been Vice President for Marketing of AboitizPower since 2010. He has extensive Sales and Marketing experience and expertise from a diverse number of industries including fast moving consumer goods, mobile telecommunications, financial services and business process outsourcing (BPO). Before joining Aboitiz Power, he served as Vice President ‐ Business Development for a leading Philippine contact center and was marketing to clients in the USA, United Kingdom, India, South East Asia and the Middle East. 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. Bienamer D. 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 School of Urban and Regional Planning from the University of the Philippines‐ Diliman.


CRISTINA BRIONES‐ BELORIA Assistant Vice President ‐ Controller Ms. Cristina Briones‐Beloria, 49 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., CPAs 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 in Illinois, USA. PAQUITA S. TIGUE‐ RAFOLS Assistant Vice President for Accounting ‐ Power Generation (Mindanao) Ms. Paquita S. Tigue‐Rafols, 46 years old, Filipino, was appointed Assistant Vice President for 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 Marine, Inc. 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 for Accounting ‐ Power Generation (Luzon)

Ms. Arazeli L. Malapad, 43 years old, Filipino, was appointed Assistant Vice President ‐ Accounting Power Generation (Luzon) in 2010. She has 21 years of extensive experience performing finance, external audit 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. Carlos Copernicus S. Payot, 47 years old, Filipino, a Certified Public Accountant, 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 Aboitiz & Company, Inc. He worked with SGV & Co. after graduating from University of San Carlos where he earned his Bachelor’s degree in Commerce, Major in Accounting (Cum Laude). CLOVIS B. RACHO Assistant Vice President for Procurement and Logistics ‐ Power Distribution Group Mr. Clovis B. Racho, 47 years old, Filipino, has been Assistant Vice President for 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 & Power Company, Inc. in 2004. He is the 2011 Gawad Sinop Supply Management Practitioner of the Year. He is a graduate of Bachelor of Science in Industrial Engineering and Bachelor of Science in Mechanical Engineering from Cebu Institute of Technology University. He is a Registered Mechanical Engineer. ALADINO B. BORJA, JR. Assistant Vice President for Information Services ‐ Power Distribution Group Mr. Aladino B. Borja, Jr., 49 years old, Filipino, has been Assistant Vice President for 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 University. RONALD ENRICO V. ABAD Assistant Vice President ‐ Project Development Mr. Ronald Enrico V. Abad, 41 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 for Human Resource and Quality ‐ Power Generation Group Ms. Ma. Kristina C.V. Rivera, 41 years old, Filipino, has been Assistant Vice President for Human Resource and Quality ‐ Power Generation Group 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. Roberto V. Orozco, 47 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. To date, he has over 26 years of experience in civil, structural and foundation engineering both locally and internationally. He has been involved in various projects such as


power plants, industrial plants, gas distribution lines, refinery and petrochemical plants, oil and gas facilities, airport facilities, high‐rise buildings, roads, highway and railway infrastructures, environmental structures, and land development. His expertise are in the field of technical engineering, construction management and engineering services, construction supervision, quality assurance, research and development. ANA LIZA M. ALETA Assistant Vice President & IT Director ‐ Power Generation Group Ms. Ana Liza M. Aleta, 43 years old, Filipino, has been Assistant Vice President & IT Director ‐ Power Generation Group of AboitizPower since 2009. She joined the Aboitiz Group in 1989 as a marketing assistant of Aboitiz & Company, Inc. 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 22 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 for Power Economics & Distribution System Planning Mr. Crisanto R. Laset, Jr., 53 years old, Filipino, has been Assistant Vice President for 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. Juan Manuel J. Gatmaitan, 40 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. Susan S. Policarpio, 55 years old, 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 ATS Consolidated, Inc. (ATSC) (formerly Aboitiz Transport System (ATSC) Corporation) since 2003. She was also Executive Director of Domestic Shipping Association from 2001 to 2003, and


Executive Director of the Honorary Investments and Trade Representatives of the Department of Trade and Industry from 1998 to 2001. She is currently a member of the Philippine Chamber of Commerce and Industry. She is a graduate of Bachelor of Arts in Communication from St. Paul College. IRWIN C. PAGDALIAN Assistant Vice President for Special Projects ‐ AP Distribution Mr. Irwin C. Pagdalian, 54 years old, Filipino, was appointed Assistant Vice President for Special Projects ‐ AP Distribution on June 2011. He joined the Aboitiz Group in 1980 as a staff engineer of Davao Light & Power Company, Inc., where he rose from the ranks and eventually co‐led Davao Light & Power Company, Inc.’s Engineering Group. He also served as the Assistant Vice President for Power Systems Design of Visayan Electric Company, Inc. Prior to his appointment in AboitizPower, he was the Assistant Vice President/General Manager of Mactan Enerzone Corporation and Balamban Enerzone Corporation. Mr. Pagdalian is a licensed engineer and a life member of the Institute of Integrated Electrical Engineers. He has a degree in Bachelor of Science in Electrical Engineering from Cebu Institute of Technology University and studied Management Programs at the Asian Institute of Management. M. CARMELA N. FRANCO Assistant Vice President ‐ Investor Relations Ms. M. Carmela N. Franco, 40 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. ATR 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. Katrina M. Platon, 45 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 Banking and Finance Law from the Boston University ‐ School of Law in Boston, Massachusetts, USA.


DENNIS DE LA SERNA Assistant Vice President ‐ Regulatory Affairs Mr. Dennis de la Serna, 38 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. 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. Nestor F. Aliman, 59 years old, Filipino, has been Assistant Vice President ‐ Business Development since 2010. He organized and headed the Electricity Trading of SN Aboitiz Power‐ Magat, Inc. (formerly SN Aboitiz Power, Inc.). Prior to that, he was the Electricity Trading Manager of Power Sector Assets and Liabilities Management Corporation and initial member of Philippine Electricity Market Corporation’s Rules Change Committee. He earned his degree in Mechanical Engineering from the University of San Carlos, and finished his Master in Management degree from the Asian Institute of Management. He also took graduate studies in Industrial Engineering and Operations Research from the University of the Philippines. SOCORRO L. PATINDOL Assistant Vice President for Environmetal Management ‐ Power Generation Group Ms. Socorro L. Patindol, 52 years old, Filipino, was appointed Assistant Vice President for Environmental Management – Power Generation Group last January 2012. Ms. Patindol joined the Aboitiz Group as Assistant Vice President for Environmental, Health and Safety of AP Renewables, Inc. She gained extensive experience in environmental policy and planning when she worked for various companies all over the Philippines and across Asia, including the Asian Development Bank and the World Bank. Ms. Patindol is a graduate of Bachelor of Science in Human Ecology from the University of the Philippines, Los Baños, and earned her Master of Science in Environmental Studies from the same school. She also holds a masters degree in Environmental Resource Management from the University College Dublin ‐ National University of Ireland, Dublin and doctorate degree in Environmental Science from the University of the Philippines, Diliman.

MARIA P. GARCIA Assistant Vice President – Trading Ms. Maria P. Garcia, 56 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 Power Sector Assets and Liabilities Management Corporation. 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. Katrina Michaela D. Calleja, 34 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 for Human Resources ‐ Power Distribution Group Ms. Ma. Cielita C. Añiga, 55 years old, Filipino, has been Assistant Vice President for 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. MA. CYNTHIA C. HERNANDEZ Assistant Vice President – Finance Ms. Cynthia C. Hernandez, 37 years old, Filipino, was appointed as Assistant Vice President ‐ Finance of AboitizPower in February 2012. She was previously connected with AES Philippines as Financial Planning and Analysis Manager and with Ernst and Young Transaction Advisory Services, Inc., as Project Finance/Mergers and Acquisitions Director, prior to joining AboitizPower. She also worked for various companies where she gained extensive experience in financial planning and analysis, mergers and acquisitions and corporate finance, with specialization in the field of energy and utilities. She earned her Bachelor of Science in Metallurgical Engineering from the University of the Philippines, College of Engineering, and is a licensed Professional Metallurgical Engineer. She also holds a Masters Degree in Development Economics from the University of the Philippines, School of Economics. M. JASMINE S. OPORTO Corporate Secretary and Compliance Officer; Ex‐Officio Member ‐ Board Corporate Governance Committee Ms. M. Jasmine S. Oporto, 52 years old, Filipino, has been the Corporate Secretary of AboitizPower since 2007. She is also the First Vice President ‐ Chief Legal Officer, Corporate Secretary and Chief Compliance Officer of AEV. She is Vice President for Legal Affairs of Davao Light & Power Company, Inc.; the Corporate Secretary of Visayan Electric Company, Inc., Luzon Hydro Corporation and Hijos de F. Escaño,


Inc. 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. Joseph Trillana T. Gonzales, 45 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 Aboitiz & Company, Inc. He is a graduate of Bachelor of Arts, 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 O. 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 O. Aboitiz. .


Involvement in Certain Legal Proceedings as of March 30, 2012 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 (City Prosecutor) of Makati to conduct a preliminary investigation against Mr. Aboitiz. In the preliminary investigation, Mr. Aboitiz explained 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. In a Resolution dated August 23, 2010, the City Prosecutor dismissed the case against Mr. Aboitiz (and three other respondents) for lack of probable cause. The City Prosecutor, however, ordered the filing of a criminal case against the five remaining respondents. Renato Francisco and Ramon Mapa, who were among the five remaining respondents criminally charged, filed a motion with the City Prosecutor to reconsider the charges against them. Finding no compelling reason to warrant the reconsideration, the City Prosecutor issued an Order dated January 7, 2011 denying the motion of Messrs. Francisco and Mapa, and ordering the filing of the information against them with the MTC. 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 or bankruptcy petition or has been convicted by final judgment, or being subject to any order, judgment or decree or violated the securities or commodities law in any court or government agency in the Philippines or elsewhere, for the past five years and the preceding years until March 30, 2012, 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 of Executive Officers

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 officers and directors during the last two completed fiscal years and the ensuing fiscal year are as follows:

NAME AND PRINCIPAL POSITION PERIOD/YEAR SALARY BONUS OTHER ANNUAL COMPENSATION

TOP FIVE HIGHLY‐COMPENSATED EXECUTIVES: 1. ERRAMON I. ABOITIZ ‐ Director/President & Chief Executive Officer 2. ANTONIO R. MORAZA ‐ Director/Executive Vice President and Chief Operating Officer‐Power Generation Group

3. JAIME JOSE Y. ABOITIZ ‐ Director/Executive Vice President and Chief

Operating Officer ‐ Power Distribution Group 4. RAYMOND E. CUNNINGHAM

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

‐ Vice President ‐ Business Development

All above‐named officers as a group

Actual 2011 P 30,650,000 P 1,400,,000 P 8,150,000

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

Projected 2012 P 32,790,000 P 1,500,000 P 8,280,000

All other directors and officers as a group unnamed

Actual 2011 P 75,490,000 P 4,150,000 P 21,640,000

Actual 2010 P 31,790,000 P 2,350,000 P 14,290,000 Projected 2012 P 80,780,000 P 4,440,000 P 22,110,000

(2) Compensation of Directors (i) Standard Arrangements In 2011, all of AboitizPower’s directors received a monthly allowance of P100,000 except for the Chairman of the Board who received a monthly allowance of P150,000. 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 P100,000 P150,000

Type of Meeting Committee Members Chairman of the Committee

Committee Meeting P80,000 P100,000 (ii) Other Arrangements Other than payment of a director’s allowance and per diem as stated above, 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 March 30, 2012:

Title of Class

Name, Address of Record

Owner and Relationship with Issuer

Name of Beneficial Owner and Relationship with Record

Owner

Citizenship

No. of Shares

Percent

Common

1. Aboitiz Equity Ventures, Inc.10 Aboitiz Corporate Center Gov. Manuel A. Cuenco Avenue, Kasambagan, Cebu City 6000 (Stockholder)

Aboitiz Equity

Ventures, Inc.11

Filipino

5,653,763,954 (Record and Beneficial)

76.83%

10.94%

Common

2. PCD Nominee Corporation 12 G/F MSE Bldg. Ayala Ave., Makati City (Stockholder)

PCD

participants acting for

themselves of for their

customers13

Filipino

768,959,590

(Record)

10.44%

Common

3. PCD Nominee Corporation14 G/F MSE Bldg. Ayala Ave., Makati City (Stockholder)

PCD

participants acting for

themselves of for their

customers15

Non‐Filipino

595,024,478

(Record)

8.09%

______________________________________________________________________________ 10

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.

11 AEV is the parent company of AboitizPower.

12The PCD is not related to the Company. 13 Each beneficial owner of shares through a PCD participant is the beneficial owner of such number of shares he owns in his account with the PCD participant. AboitizPower has no record relating to the power to decide how the shares held by PCD are to be voted. As advised to the Company, none of the customers under a PCD participant beneficially owns more than 5% of the Company’s common shares.

14 Supra note 12. 15 Supra note 13.


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 March 30, 2012, 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

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

Filipino

2,735, 600,915

(Record and Beneficial)

49.54%

Common

2. PCD Nominee Corporation G/F MSE Bldg. Ayala Ave., Makati City

Filipino

915,928,680 (Record)

16.59%

Common 2. PCD Nominee Corporation G/F MSE Bldg. Ayala Ave., Makati City

Non‐Filipino 452,828,551 (Record)

8.20%

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

Filipino 420,915,863 (Record and Beneficial)

7.62%

(2) Security Ownership of Management as of March 30, 2012 (Record and Beneficial)

Title of Class

Name of Beneficial Owner and Position

No. of Shares and Nature

of Ownership (Direct or Indirect)

Citizenship

Percent of Ownership

Common

Mr. Enrique M. Aboitiz, Jr. Chairman of the Board of Directors

686,758

Direct

Filipino

0.01%

Common Mr. Jon Ramon Aboitiz Vice Chairman of the Board

33,001 Direct Filipino 0.00% 10,086,820 Indirect 0.14%

Common Mr. Erramon I. Aboitiz Director/President and Chief Executive Officer

1 Direct Filipino 0.00%

18,901,446 Indirect 0.26%

Common Mr. Jaime Jose Y. Aboitiz Director/Executive Vice President and Chief Operating Officer – Power Distribution Group

5,367,397 Direct Filipino 0.07%

1,738,594 Indirect 0.02%

Common Mr. Mikel A. Aboitiz Director

1 Direct Filipino 0.00%

13,283,959 Indirect 0.18% Common Mr. Antonio R. Moraza

Director/Executive Vice President and Chief 1 Direct Filipino 0.00%


Operating Officer ‐ Power Generation Group 31,281,046 Indirect 0.42% 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 G. Disch Independent Director

1,000 Direct Swiss National

0.00%

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


121,623 Indirect 0.00%

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


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


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


2,007,343 Indirect 0.03%

Common Mr. Manuel R. Lozano First Vice President/ Chief Financial Officer ‐ Power Generation Group


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

83,995 Direct American 0.00%

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


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


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

0 N/A American 0.00%

N/A Mr. William L. Ruccius Vice President – Business Development


Common Mr. Alvin S. Arco Vice President – Regulatory Affairs


N/A Mr. Kenton E. Huertz Vice President for Asset Management – Power Generation Group


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

0 N/A Filipino 0.00%

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


Common Ms. Ma. Chona Y. Tiu Vice President and Chief Financial Officer ‐ Power Distribution Group


50,000 Indirect 0.00% Common Mr. Roland U. Gaerlan

Vice President ‐ Marketing 12,000 Direct Filipino 0.00%

Common Mr. Bienamer D. Garcia Vice President ‐ Distribution Customer Services

5,398 Indirect Filipino 0.00%


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


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


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


Common Mr. Carlos Copernicus S. Payot Assistant Vice President and 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 for 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 and Distribution System Planning


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


Common Ms. Analiza M. Aleta Assistant Vice President and IT Director ‐ Power Generation Group


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


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


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


Common 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 Presidentfor 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


N/A Ms. Ma. Cynthia C. Hernandez Assistant Vice President ‐ Finance


N/A Ms. Socorro L. Patindol Assistant Vice President for Environmental Management – Power Generation Group


Common Mr. Irwin C. Pagdalian Assistant Vice President for Special Projects – Power Distribution Group


Common Ms. M. Jasmine S. Oporto Corporate Secretary


Common Mr. Joseph Trillana T. Gonzales Assistant Corporate Secretary


TOTAL

95,313,043

1.30%

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. The Group extends and/or avails of temporary interest‐bearing advances to and from ACO, AEV and certain affiliates for working capital requirements. These are made to enhance the lending parent companies’ and affiliates’ yield on their 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 March 30, AEV owns 76.83% of AboitizPower. In turn, Aboitiz & Company, Inc. (ACO) owns, as of March 30, 2012, 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, PSE and the Institute of Corporate Directors (ICD) 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 2011, the Board held nine regular and special meetings. Below is a summary of the attendance of the Directors:

Legend: P ‐ Present A ‐ Absent

DIRECTORS

Regular and Special Meetings 2011

24‐Jan special

(executiv

e

strategy

sessions)

4‐Feb

regular

3‐Mar

special

30‐Mar

regular

16‐May

regular

27‐July

regular

30‐Sept

regular

11‐Nov

special

board

strategy

9‐Dec

regular

Enrique M. Aboitiz, Jr.

P P P P P P P P P

Jon Ramon Aboitiz P P P P P P P P P Erramon I. Aboitiz P P P P P P P P P Antonio R. Moraza P P P A P P P P P Mikel A. Aboitiz P P P P P P P P P Jaime Jose Y. Aboitiz

P P P P P P P P P

Jose R. Facundo (Independent Director)

P P P P P P P P P

Romeo L. Bernardo (Independent Director)

P P P P P P P P P

Jakob Disch (Independent Director)

P P P P P P P P A

TOTAL NO. OF DIRECTORS PRESENT

9 9 9 8 9 9 9 9 8

PERCENTAGE NO. OF DIRECTORS PRESENT IN EACH MEETING

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


Corporate Governance Initiatives Going beyond mere compliance and box‐ticking, the Company regularly updates its corporate governance policies to ensure that they are relevant to the needs of the organization, and at the same time, at par with global best practices. In February 2009, the Board of Directors of AboitizPower approved the creation of additional board committees and the consolidation of existing ones. In the same year, the Investor Relations Committee was dissolved and the Board Nominations and Compensation Committee merged with the Board Corporate Governance Committee. On May 17, 2010, the Board approved an amendment to the Company’s Amended Manual on Corporate Governance, folding in of the responsibility of the Board Strategy Committee under the functions of the Board of Directors. The reorganization aimed 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. More recently, on February 2012, management proposed before the Board Risk Management and the Board Corporate Governance Committees to remove the reputation oversight function of the Board from the Board Corporate Governance Committee and fold it in the Board Risk Management Committee. This is in line with the recognition of the Company that its reputation is its most valuable asset. Both committees approved the proposed reorganization. To implement the reorganization, the Board Risk Committee will revise and update its Board Risk Management Committee Charter and the Board Corporate Governance Committee will amend the Company’s Amended Manual on Corporate Governance for submission and approval of the Board. Upon approval by the Board, the Company will submit for the approval of the SEC, the amendment to its Amended Manual of Corporate Governance.

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: Jon Ramon Aboitiz; Members: Erramon I. Aboitiz, Jose R. Facundo, Romeo

L. Bernardo, Jakob G. Disch; Ex‐Officio Members: M. Jasmine S. Oporto, Susan V. Valdez, 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 G. 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: Enrique M. Aboitiz, Jr.; Members: Erramon I. Aboitiz, Jose R. Facundo, Jakob G.

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 AboitizPower on SEC Form 17‐C from May 2011 to March 2012 are as follows: Date Disclosure DetailsMay 5, 2011 First Quarter 2011 Financial and Operating ResultsMay 10, 2011 Closing of the Luzon Hydro Corporation Buy-outMay 10, 2011 Settlement of Cases between Aboitiz Renewables, Inc. and Pacific Hydro

Bakun, Inc. May 16, 2011 Result of the Annual Stockholders’ MeetingMay 16, 2011 Result of the Organizational MeetingMay 27, 2011 Acquisition of Navotas Power BargesJune 2, 2011 Start of Commercial Operations of Unit 3 of the Ambuklao Plant June 3, 2011 Appointment of Mr. Irwin C. Pagdalian as Assistant Vice President for

Special Projects - AP Distribution June 24, 2011 Appointment of Officer - William L. Ruccius as Vice President for Business

Development June 27, 2011 Meralco PowerGen approval of investment in Redondo Peninsula

Energy, Inc. July 22, 2011 Signing of Shareholders' Agreement with Meralco PowerGen

Corporation and Taiwan Cogeneration International Corporation – Philippine Branch

July 26, 2011 Appointment of External AuditorJuly 28, 2011 First Half 2011 Financial and Operating ResultsJuly 29, 2011 PRS Aaa issue ratings for AboitizPower's corporate notes and bonds September 27, 2011 Signing of Memorandum of Understanding with Marubeni Corporation October 26, 2011 Signing of Power Supply Agreement with Benguet Corporation November 3, 2011 Third Quarter 2011 Financial and Operating Results December 19, 2011 Appointment of New Stock and Transfer AgentDecember 26, 2011 Extension of the Term of the Meralco TSC Load Allocation January 13, 2012 Appointment of Ms. Socorro L. Patindol as Assistant Vice President for

Environmental Management – Power Generation Group February 1, 2012 Appointment of Mr. Kenton E. Heuertz February 6, 2012 Purchase of 31,650,900 AP common shares by AEV February 9, 2012

Appointment of Ms. Ma. Cynthia C. Hernandez as Assistant Vice President – Finance

February 22, 2012 Final List of Candidates for the Board of DirectorsFebruary 27, 2012 Meralco Board Approval on Power Supply Agreement signing with Therma

Luzon, Inc.February 29, 2012 Therma Luzon, Inc. signing of Power Supply Agreement with Meralco March 1, 2012 Full Year 2011 Financial and Operating ResultsMarch 1, 2012 Matters Approved by the BoardMarch 26, 2012 Interdepartmental Transfer of OfficersMarch 26, 2012 Energy Regulatory Commission issuance of Certificate of Compliance for

SNAP-Binga March 28, 2012 Early Redemption of Five-Year Peso Fixed Rate BondsMarch 30, 2012 Retirement of Mr. Anastacio D. Cubos, Jr. as Vice President – Special

Projects

DISTRIBUTION RES

COTABATO LIGHT & POWER CO. (99.94%)

SUBIC ENERZONE CORP. (99.97%)

SAN FERNANDO ELECTRIC & POWER CO., INC. (43.78%)

VISAYAN ELECTRIC CO., INC. (55.24%)

ABOITIZ ENERGY SOLUTIONS, INC. (100.00%)

ADVENTENERGY, INC. (100.00%)

PRISM ENERGY, INC. (60.00%)

THERMA LUZON, INC. (100.00%)

THERMA MARINE, INC. (100.00%)

THERMA MOBILE, INC. (100.00%)

HEDCOR, INC. (100.00%)

AP RENEWABLES, INC. (100.00%)

LUZON HYDRO CORP. (100.00%)

HEDCOR SIBULAN, INC. (100.00%)

THERMA POWER, INC. (100.00%)

ABOITIZ RENEWABLES, INC. (100.00%)

CEBU PRIVATE POWER CORP. (60.00%)

GENERATION

ABOITIZ POWER CORPORATION

DAVAO LIGHT & POWER CO. INC. (99.93%)

MACTAN ENERZONE CORP. (100.00%)

BALAMBAN ENERZONE CORP. (100.00%)

CEBU ENERGY DEVT. CORP. (44.00%)

REDONDO PENINSULA ENERGY, INC. (25.00%)

ABOVANT HOLDINGS, INC. (60.00%)

EAST ASIA UTILITIES CORP. (50.00%)

STEAG STATE POWER INC. (34.00%)

SOUTHERN PHILIPPINES POWER CORP. (20.00%)

WESTERN MINDANAO POWER CORP. (20.00%)

SN ABOITIZ POWER – MAGAT, INC. (60.00%)

MANILA-OSLO RENEWABLE ENTERPRISE, INC.

(83.33%)

SN ABOITIZ POWER – RES, INC. (60.00%)

SN ABOITIZ POWER – BENGUET, INC.

(60.00%)

THERMA SOUTH, INC. (100.00%)

HEDCOR TAMUGAN, INC. (100.00%)

HEDCOR SABANGAN, INC. (100.00%)

HEDCOR TUDAYA, INC. (100.00%)

THERMA POWER VISAYAS, INC. (100.00%)

THERMA SUBIC, INC. (100.00%)

THERMA SOUTHERN MINDANAO, INC. (100.00%)

THERMA CENTRAL VISAYAS, INC. (100.00%)

CLEANERGY, INC. (100.00%)

HEDCOR BOKOD, INC. (100.00%)

HEDCOR BUKIDNON, INC. (100.00%)

ANNEX “A”

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*SGVMC409382*

PAS 32, Financial Instruments: Presentation (Amendment) The amendment alters the definition of a financial liability in PAS 32 to enable entities to classify rights issues and certain options or warrants as equity instruments. The amendment is applicable if the rights are given pro rata to all of the existing owners of the same class of an entity’s non-derivative equity instruments, to acquire a fixed number of the entity’s own equity instruments for a fixed amount in any currency. The amendment has had no effect on the financial position or performance of the Company because the Company does not have these types of instruments. Philippine Interpretation IFRIC 14, Prepayments of a Minimum Funding Requirement (Amendment) The amendment removes an unintended consequence when an entity is subject to minimum funding requirements and makes an early payment of contributions to cover such requirements. The amendment permits a prepayment of future service cost by the entity to be recognized as a pension asset. The Company is not subject to minimum funding requirements in the Philippines; therefore, the amendment of the interpretation has no effect on the financial position or performance of the Company. Improvements to PFRS (issued 2010) 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. • PFRS 3, Business Combinations: The measurement options available for non-controlling

interest (NCI) were amended. Only components of NCI that constitute a present ownership interest that entitles their holder to a proportionate share of the entity’s net assets in the event of liquidation should be measured at either fair value or at the present ownership instruments’ proportionate share of the acquiree’s identifiable net assets.

• PFRS 7, Financial Instruments - Disclosures: The amendment was intended to simplify the

disclosures provided by reducing the volume of disclosures around collateral held and improving disclosures by requiring qualitative information to put the quantitative information in context.

• PAS 1, Presentation of Financial Statements: The amendment clarifies that an entity may present an analysis of each component of other comprehensive income maybe either in the statement of changes in equity or in the notes to the parent company financial statements.

Other amendments resulting from the 2010 Improvements to PFRS to the following standards did not have any impact on the accounting policies, financial position or performance of the Company:

• PFRS 3, Business Combinations (Contingent consideration arising from business combination

prior to adoption of PFRS 3 (as revised in 2008)) • PFRS 3, Business Combinations (Un-replaced and voluntarily replaced share-based payment

awards) • PAS 27, Consolidated and Separate Financial Statements • PAS 34, Interim Financial Statements

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*SGVMC409382*

The following interpretation and amendments to interpretations did not have any impact on the accounting policies, financial position or performance of the Company: • Philippine Interpretation IFRIC 13, Customer Loyalty Programmes (determining the fair value

of award credits) • Philippine Interpretation IFRIC 19, Extinguishing Financial Liabilities with Equity

Instruments

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 listing of standards and interpretations issued are those that the Company reasonably expects to have an impact on disclosures, financial position or performance when applied at a future date. The Company intends to adopt these standards when they become effective.

• PAS 1, Financial Statement Presentation - Presentation of Items of Other Comprehensive

Income (OCI) The amendments to PAS 1 change the grouping of items presented in OCI. Items that could be reclassified (or “recycled”) to profit or loss at a future point in time (for example, upon derecognition or settlement) would be presented separately from items that will never be reclassified. The amendment affects presentation only and has therefore no impact on the Company’s financial position or performance. The amendment becomes effective for annual periods beginning on or after July 1, 2012.

• PAS 12, Income Taxes - Recovery of Underlying Assets

The amendment clarified the determination of deferred tax on investment property measured at fair value. The amendment introduces a rebuttable presumption that deferred tax on investment property measured using the fair value model in PAS 40, Investment Property should be determined on the basis that its carrying amount will be recovered through sale. Furthermore, it introduces the requirement that deferred tax on non-depreciable assets that are measured using the revaluation model in PAS 16, Property, Plant and Equipment always be measured on a sale basis of the asset. The amendment becomes effective for annual periods beginning on or after January 1, 2012.

• PAS 19, Employee Benefits (Amendment)

Amendments to PAS 19 range from fundamental changes such as removing the corridor mechanism and the concept of expected returns on plan assets to simple clarifications and re-wording. The Company is currently assessing the impact of the amendment to PAS 19. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

• PAS 27, Separate Financial Statements (as revised in 2011) As a consequence of the new PFRS 10, Consolidated Financial Statement and PFRS 12, Disclosure of Interests in Other Entities, what remains of PAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in separate financial statements. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

• PAS 28, Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the new PFRS 11, Joint Arrangements and PFRS 12, PAS 28 has been renamed PAS 28, Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

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*SGVMC409382*

• PFRS 7, Financial Instruments: Disclosures - Enhanced Derecognition Disclosure Requirements The amendment requires additional disclosure about financial assets that have been transferred but not derecognized to enable the user of the Company’s financial statements to understand the relationship with those assets that have not been derecognized and their associated liabilities. In addition, the amendment requires disclosures about continuing involvement in derecognized assets to enable the user to evaluate the nature of, and risks associated with, the entity’s continuing involvement in those derecognized assets. The amendment becomes effective for annual periods beginning on or after July 1, 2011. The amendment affects disclosures only and has no impact on the Company’s financial position or performance.

• PFRS 7, Financial instruments: Disclosures - Offsetting Financial Assets and Financial

Liabilities These amendments require an entity to disclose information about rights of set-off and related arrangements (such as collateral agreements). The new disclosures are required for all recognized financial instruments that are set off in accordance with PAS 32. These disclosures also apply to recognized financial instruments that are subject to an enforceable master netting arrangement or “similar agreement”, irrespective of whether they are set-off in accordance with PAS 32. The amendments require entities to disclose, in a tabular format unless another format is more appropriate, the following minimum quantitative information. This is presented separately for financial assets and financial liabilities recognized at the end of the reporting period: a) The gross amounts of those recognized financial assets and recognized financial liabilities; b) The amounts that are set off in accordance with the criteria in PAS 32 when determining

the net amounts presented in the statement of financial position; c) The net amounts presented in the statement of financial position; d) The amounts subject to an enforceable master netting arrangement or similar agreement

that are not otherwise included in (b) above, including: i. Amounts related to recognized financial instruments that do not meet some or all

of the offsetting criteria in PAS 32; and ii. Amounts related to financial collateral (including cash collateral); and

e) The net amount after deducting the amounts in (d) from the amounts in (c) above. The amendments to PFRS 7 are to be retrospectively applied for annual periods beginning on or after January 1, 2013. The amendment affects disclosures only and has no impact on the Company’s financial position or performance.

• PFRS 10, Consolidated Financial Statements PFRS 10 replaces the portion of PAS 27 that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12, Consolidation - Special Purpose Entities. PFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by PFRS 10 will require management to exercise significant judgment to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in PAS 27. This standard becomes effective for annual periods beginning on or after January 1, 2013.

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*SGVMC409382*

• PFRS 11, Joint Arrangements PFRS 11 replaces PAS 31, Interests in Joint Ventures and SIC-13, Jointly-Controlled Entities Non-monetary Contributions by Venturers. PFRS 11 removes the option to account for jointly-controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 12, Disclosure of Involvement with Other Entities PFRS 12 includes all of the disclosures that were previously in PAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in PAS 31 and PAS 28. These disclosures relate to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 13, Fair Value Measurement PFRS 13 establishes a single source of guidance under PFRS for all fair value measurements. PFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under PFRS when fair value is required or permitted. The Company is currently assessing the impact that this standard will have on the financial position and performance. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PAS 32, Financial Instruments: Presentation - Offsetting Financial Assets and Financial Liabilities These amendments to PAS 32 clarify the meaning of “currently has a legally enforceable right to set-off” and also clarify the application of the PAS 32 offsetting criteria to settlement systems (such as central clearing house systems) which apply gross settlement mechanisms that are not simultaneous. While the amendment is expected not to have any impact on the net assets of the Company, any changes in offsetting is expected to impact leverage ratios and regulatory capital requirements. The amendments to PAS 32 are to be retrospectively applied for annual periods beginning on or after January 1, 2014. The Company is currently assessing impact of the amendments to PAS 32.

• PFRS 9, Financial Instruments: Classification and Measurement PFRS 9 as issued reflects the first phase 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, 2015. In subsequent phases, hedge accounting and impairment of financial assets will be addressed with the completion of this project expected on the latter half of 2012. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Company’s financial assets, but will potentially have no impact on classification and measurements of financial liabilities. The Company will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

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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 Instruments The Company recognizes financial instruments in the parent company balance sheet on the date when it becomes a party to the contractual provisions of the instrument. All regular way purchases and sales of financial assets are recognized on trade date, which is the date that the Company commits to purchase the asset. Regular way purchases or sales of financial assets are purchases or sales of financial assets that require delivery of assets within the period generally established by regulation or convention in the marketplace. Derivatives are recognized on a trade date basis. Initial recognition of financial instruments All financial instruments are recognized initially 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). Determination of fair value The fair value of investments held that are actively traded in organized financial markets is determined by reference to quoted market bid prices at the close of business on the balance sheet date. For investments where there is no active market, fair value is determined using valuation techniques. Such techniques include using recent arm’s length market transactions; reference to the current market value of another instrument, which are substantially the same; discounted cash flow analysis and other valuation models.

For all other financial instruments not listed in an active market, the fair value is determined by using appropriate valuation methodologies. Valuation methodologies include net present value techniques, comparison to similar instruments for which market observable prices exist, options pricing models, and other relevant valuation models. 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 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.

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Financial instruments are classified into the following categories: financial asset or financial liability at FVPL, loans and receivables, held-to-maturity (HTM) investments, AFS investments and other financial liabilities. The Company determines the classification at initial recognition and where allowed and appropriate, re-evaluates such designation at every reporting date. 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 hedging instruments in an effective hedge. 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. 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 in the parent company balance sheet at fair value. Subsequent changes in fair value are recognized in the parent company 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 payment has been established. Included under this category is the Company’s derivative asset and derivative liability (see Note 20).

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 are not entered into with the intention of immediate or short-term resale and are not reclassified or designated as AFS investments or financial assets at FVPL. After initial measurement, loans and receivables are subsequently carried at amortized cost using the effective interest method less any allowance for impairment. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in the parent company 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, they are classified as non-current assets. Included under this category are the Company’s cash and cash equivalents (excluding cash on hand) and trade and other receivables and amounts owed by related party.

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c. HTM investments HTM investments are quoted non-derivative financial assets which carry fixed or determinable payments and fixed maturities and which the Company has the positive intention and ability to hold to maturity. After the 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 any discount or premium on acquisition and fees that are integral to the effective interest rate. Where the Company sells other than an insignificant amount of HTM investments, the entire category would be tainted and reclassified as AFS investments. Gains and losses are recognized in the parent company statement of income when the investments are derecognized or impaired, as well as through the amortization process. The Company does not have any HTM investments at December 31, 2011 and 2010.

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 Company does not have any AFS investments at December 31, 2011 and 2010.

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, trade and other payables and long-term debts.

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‘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. 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 parent company statement of income. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. The Company assesses whether embedded derivatives are required to be separated from host contracts when the Company 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, 2011 and 2010, the Company has freestanding derivatives in the form of non-deliverable foreign currency forward contracts entered into to economically hedge its foreign exchange risk (see Note 19). In 2011 and 2010, the Company did not apply hedge accounting treatment on its derivative transactions. The Company has not bifurcated any embedded derivatives as of December 31, 2011 and 2010. 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.

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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. 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.

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Impairment of Financial Assets The Company 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 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 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 the use of an allowance account. The amount of the loss shall be recognized in the parent company 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 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. AFS investments For AFS investments, the Company 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 parent company statement of income) is removed from the parent company other comprehensive income and recognized in the parent company statement of income. Impairment losses on equity investments are not reversed through the parent company statement of income. Increases in fair value after impairment are recognized directly in the parent company 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 parent company 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 parent company statement of income, the impairment loss is reversed through the parent company statement of income. Offsetting Financial Instruments Financial assets and financial liabilities are offset and the net amount is reported in the parent company 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 parent company balance sheet. Investments in and advances to 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. Investments in and advances to 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 or establishes a right to receive 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.

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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 and amortization 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.

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 parent company statement of income in the year in which the expenditure is incurred. Computer software license Computer software license is initially recognized at cost. Following initial recognition, the computer software license cost is carried at cost less accumulated amortization and any accumulated impairment in value. The computer software license is amortized on a straight-line basis over its estimated useful economic life of three to five years and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization commences when the computer software license is available for use. The amortization period and the amortization method for the license are reviewed at each financial year end. Changes in the estimated useful life is accounted

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for by changing the amortization period or method, as appropriate, and treated as changes in accounting estimates. The amortization expense is recognized in the parent company statement of income in the expense category consistent with the function of the computer software license. Gains or losses arising from derecognition of an intangible asset are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in the parent company statement of income when the asset is derecognized. 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 and amortization, 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. Capital Stock Capital stock is measured at par value for all shares issued. Incremental costs incurred directly attributable to the issuance of new shares are shown in equity as deduction from proceeds, net of tax. Proceeds and/or fair value of consideration received in excess of par value, if any, are recognized as additional paid-in capital.

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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 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. 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 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.

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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. 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 net operating loss carryover (NOLCO) and excess 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 unused NOLCO and excess 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

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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 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.

Retained Earnings The amount included in retained earnings includes accumulated earnings of the Company and reduced by dividends on capital stock. Dividends on capital stock are recognized as a liability and deducted from equity when they are approved by the BOD. Dividends for the year that are approved after the financial reporting date are dealt with as an event after the financial reporting date. Retained earnings may also include effect of changes in accounting policy as may be required by the transition provisions of new and amended standards. Provisions 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. Contingencies 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.

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3. Significant Judgments, Assumptions 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. 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. Estimating allowance for impairment of trade and other 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 collectability 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, 2011 and 2010. As of December 31, 2011 and 2010, the Company’s receivables amounted to P=273.4 million and P=329.2 million, respectively (see Note 5). Assessing 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

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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 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, 2011, the carrying values of investments in and advances to subsidiaries, investments in and advances to associates, investment property, property and equipment, computer software license and prepaid taxes and other current assets amounted to P=49.8 billion, P=7.2 billion, P=10.0 million, P=33.7 million, P=4.8 million and P=128.8 million, respectively. 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. No impairment losses were recognized in 2011 and 2010 (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 16, 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, 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=21.6 million, P=17.2 million and P=5.4 million in 2011, 2010 and 2009, respectively. The Company has pension asset amounting to P=48.9 million and P=57.8 million as of December 31, 2011 and 2010, respectively (see Note 16). 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. Where the fair values of certain financial assets and financial liabilities recorded in the parent company balance sheet cannot be derived from active markets, the fair values 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. Changes in assumptions about these factors could affect the reported fair values of the financial instruments. The fair values of the Company’s financial instruments are presented in Note 20 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.

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This budget is based on the Company’s past results and future expectations on revenue and expenses. As of December 31, 2011 and 2010, gross deferred income tax assets amounted to P=127.5 million and P=130.1 million, respectively. No deferred income tax assets were recognized for MCIT amounting to P=7.1 million and P=23.8 million incurred in 2011 and 2010, respectively and for NOLCO amounting to P=352.1 million and P=369.5 million incurred in 2011 and 2010, respectively (see Note 17). 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, 2011 and 2010.

4. Cash and Cash Equivalents

2011 2010 Cash on hand and in banks P=721,617,480 P=549,464,555 Short-term investments 7,178,397,385 10,532,465,400 P=7,900,014,865 P=11,081,929,955

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=433.8 million in 2011, P=89.1 million in 2010 and P=294.4 million in 2009.

5. Trade and Other Receivables

2011 2010 Trade P=114,345,915 P=205,559,739 Interest 64,904,155 18,806,110 Dividends 55,004,284 – Nontrade 30,273,074 102,179,930 Others 8,899,740 2,613,525 P=273,427,168 P=329,159,304

Trade receivables are non-interest bearing and are generally on 30 days’ term.

Nontrade receivables are various project-related costs incurred by the Company which are collectible within a year and pending allocation to various affiliates.

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6. Investments in and Advances to Subsidiaries

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

2011 2010 Aboitiz Renewables, Inc. (ARI) P=35,890,338,814 P=5,750,185,722 Therma Power, Inc. (TPI) 8,596,664,390 5,000 Davao Light & Power Co., Inc. (DLPC) 738,348,601 738,348,601 Mactan Enerzone Corporation (MEZC) 609,532,287 609,532,287 Balamban Enerzone Corporation (BEZC) 444,869,161 444,869,161 Subic Enerzone Corporation (SEZC) 227,000,000 227,000,000 Cotabato Light & Power Co. (CLPC) 214,040,236 214,040,236 Aboitiz Energy Solutions, Inc. (AESI) 21,000,000 21,000,000 Cebu Private Power Corporation (CPPC) 17,806,608 17,806,608 Adventenergy, Inc. (AI) 625,000 625,000 46,760,225,097 8,023,412,615 Deposit for future subscription in ARI – 3,426,882,661 46,760,225,097 11,450,295,276 Advances to subsidiaries 2,997,069,717 –

P=49,757,294,814 P=11,450,295,276

In November 2011, ARI increased its capital stock from P=1.0 billion to P=4.1 billion, consisting of 1.0 billion common shares at P=1.0 per share and 3.1 billion redeemable preferred shares with a par value of P=1.0 per share. The Company acquired the 2.8 billion redeemable preferred shares for P=2.8 billion. Also in November 2011, TPI increased its capital stock from P=20,000 to P=860 million, consisting of 86 million common shares with a par value of P=1 per share and P=774 million redeemable preferred shares with a par value of P=1 per share. The Company acquired 86.0 million common shares for P=86.0 million and 773.7 million redeemable preferred shares for P=773.7 million. The Company’s subsidiaries (all incorporated in the Philippines) and the corresponding percentage equity ownership are as follows:

2011 2010

Name of Company Nature of Business Direct Indirect Direct Indirect Aboitiz Renewables Inc. (ARI) Holding company 100.00% – 100.00% – Therma Power, Inc. (TPI) Holding company 100.00% – 100.00% – 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% – 99.94% – 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% – Prism Energy, Inc. (Prism) Retail electricity

supplier 60.00% – 60.00% – *No commercial operations as of December 31, 2011 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.

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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):

2011 2010 ARI and Subsidiaries Total current assets P=36,518,966 P=3,821,238 Total noncurrent assets 117,719,008 41,655,475 Total current liabilities 10,789,289 12,241,577 Total noncurrent liabilities 72,887,403 3,813,683 Gross revenue 54,850,548 17,615,717 Net income 21,883,907 13,691,582 TPI and Subsidiaries Total current assets P=16,800,518 P=13,571,434 Total noncurrent assets 53,447,992 48,387,897 Total current liabilities 6,401,308 4,907,823 Total noncurrent liabilities 53,093,663 47,512,080 Gross revenue 22,705,523 27,323,737 Net income 3,891,284 9,655,195 DLP Total current assets P=989,620 P=820,455 Total noncurrent assets 4,987,232 4,498,321 Total current liabilities 2,297,421 1,113,311 Total noncurrent liabilities 2,195,744 2,055,815 Gross revenue 9,556,203 8,983,027 Net income 1,290,130 831,076 SEZ Total current assets P=524,922 P=443,401 Total noncurrent assets 1,566,356 953,074 Total current liabilities 373,765 516,187 Total noncurrent liabilities 932,151 497,358 Gross revenue 2,493,095 1,816,962 Net income 105,823 143,549 CLP Total current assets P=253,083 P=288,827 Total noncurrent assets 403,322 369,389 Total current liabilities 392,325 347,725 Total noncurrent liabilities 94,631 88,351 Gross revenue 693,596 801,159 Net income 32,585 44,325 CPPC Total current assets P=831,205 P=903,989 Total noncurrent assets 339,991 489,496 Total current liabilities 493,401 400,116 Total noncurrent liabilities 259,032 488,162 Gross revenue 1,551,319 2,042,950 Net income 223,017 126,315 (Forward)

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MEZ Total current assets P=124,053 P=157,372 Total noncurrent assets 151,166 114,517 Total current liabilities 56,627 60,056 Total noncurrent liabilities 48,905 45,612 Gross revenue 736,690 747,433 Net income 77,928 94,759

BEZ Total current assets P=167,339 P=118,573 Total noncurrent assets 146,592 124,500 Total current liabilities 83,346 66,147 Total noncurrent liabilities 74,158 77,673 Gross revenue 913,409 704,611 Net income 68,251 49,534 AESI Total current assets P=42,032 P=31,738 Total noncurrent assets 26,553 29,013 Total current liabilities 7,805 5,497 Noncurrent liabilities 44 227 Gross revenue 51,917 62,524 Net income 5,708 21,809

7. Investments in and Advances to Associates

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

2011 2010 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 Co., Inc. (VECO) 658,153,465 657,505,435 AEV Aviation, Inc. (AEV AVI) 291,400,000 – Western Mindanao Power Corporation (WMPC) 263,664,589 263,664,589 East Asia Utilities Corporation (EAUC) 217,550,994 217,550,994 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 7,232,365,896 6,940,317,866 Advances to associates 560,856 –

P=7,232,926,752 P=6,940,317,866

In 2011, the Company subscribed and paid for 242,631 common shares and 291,157 redeemable preferred shares of AEV Aviation, including additional paid-in capital of P=290.9 million. The par value of the common and redeemable preferred shares is P=1 per share.

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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 2011 2010 VECO* Power distribution 43.46% 43.44% EAUC Power generation 50.00% 50.00% AEV AV Service 49.25% – 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 2011 and 2010. Accordingly, the Company has effective ownership in VECO of 55.21% in 2011 and 55.19% in 2010, 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 2011 and 2010. Accordingly, the Company has effective ownership in SFELAPCO of 43.78% in 2011 and 2010.

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):

2011 2010VECO

Total current assets P=2,680,499 P=3,251,473Total noncurrent assets 8,196,538 7,878,006Total current liabilities 2,310,321 2,513,044Total noncurrent liabilities 3,824,243 3,939,339Gross revenue 16,296,842 13,405,730Net income 820,535 609,526

EAUC Total current assets P=615,356 P=552,025Total noncurrent assets 234,515 1,002,339Total current liabilities 129,358 166,788Total noncurrent liabilities 15,020 10,861Gross revenue 992,763 1,741,244Net income 325,998 252,754

(Forward)

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2011 2010AEV AV

Total current assets P=68,598 P=54,423Total noncurrent assets 521,953 255,463Total current liabilities 1,434 162Total noncurrent liabilities – 171Gross revenue 63,327 47,295Net income (loss) (2,536) 4,165

SFELAPCO Total current assets P=799,680 P=669,949Total noncurrent assets 2,055,184 1,103,853Total current liabilities 614,313 466,986Total noncurrent liabilities 593,237 334,181Gross revenue 3,276,602 3,048,028Net income 101,387 267,483

STEAG Total current assets P=5,097,440 P=5,624,376Total noncurrent assets 10,456,899 11,129,719Total current liabilities 1,821,445 1,659,345Total noncurrent liabilities 2,891,763 3,348,866Gross revenue 7,548,941 6,507,354Net income 3,662,955 1,754,369

SPPC Total current assets P=726,142 P=580,253Total noncurrent assets 884,948 999,546Total current liabilities 109,955 120,986Total noncurrent liabilities 269,157 302,659Gross revenue 707,339 709,774Net income 234,836 227,719

WMPC Total current assets P=1,371,351 P=1,031,813Total noncurrent assets 1,372,340 1,584,896Total current liabilities 147,292 148,541Total noncurrent liabilities 127,113 143,422Gross revenue 1,352,280 1,324,461Net income 819,405 851,962

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8. Property and Equipment

December 31, 2011

Transportation

Equipment Office and Tools

Equipment Communication

Equipment Leasehold

Improvements Total Cost At January 1 P=27,071,498 P=9,360,448 P=236,869 P=20,437,410 P=57,106,225 Additions 2,871,786 3,964,964 387,264 1,105,449 8,329,463 Disposals – – – (5,474,416) (5,474,416)

At December 31 29,943,284 13,325,412 624,133 16,068,443 59,961,272

Accumulated Depreciation At January 1 9,717,750 3,161,977 57,562 2,987,222 15,924,511 Additions 6,643,725 4,059,732 148,920 83,710 10,936,087 Disposals – – – (621,491) (621,491)

At December 31 16,361,475 7,221,709 206,482 2,449,441 26,239,107

Net Book Value P=13,581,809 P=6,103,703 P=417,651 P=13,619,002 P=33,722,165

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

In 2011 and 2010, the disposals on property and equipment were made at book value.

There are no restrictions on the title and no property and equipment are pledged as security for liabilities.

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, 2011 and 2010.

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10. Computer Software License

2011 2010 Cost January 1 P=5,686,820 P=– Addition – 5,686,820 December 31 5,686,820 5,686,820 Accumulated amortization January 1 331,731 Additions 568,682 331,731 December 31 900,413 331,731 Net book values P=4,786,407 P=5,355,089

11. Trade and Other Payables

2011 2010 Accrued Interest P=116,222,342 P=62,023,446 Non-trade Payables 49,174,331 – Trade Payables 26,717,852 14,121,896 Accrued taxes and fees 12,224,835 6,556,233 Output VAT 11,785,996 20,733,733 Others 154,435 6,969,937 P=216,279,791 P=110,405,245

12. Bank Loans

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 was still outstanding with a 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=3.5 million and P=1.8 million in 2011 and 2010, respectively. The Company fully paid the amount on the maturity date. 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. Total interest expense charged to the parent company statements of income amounted to nil in 2011 and P=43.4 million in 2010. The Company made a full payment on the loan in June 2010. 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 bore an interest rate at London Interbank Offered Rates (LIBOR) plus a certain spread which was payable monthly. Annual interest rates ranged from 1.75% to 2.63 % and 1.75% to 4.24% in

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*SGVMC409382*

2010 and 2009, respectively. Total interest expense charged to the parent company statements of income amounted to nil in 2011, P=17.9 million in 2010 and P=110.3 million in 2009.

In March 2010, the Company paid $64.3 million of the loan while the remaining $16.7 million was fully paid in April 2010.

13. Long-term Debts

Interest Rate 2011 2010Financial and non-financial institutions - unsecured 2011 5-year corporate note 6.17% P=5,000,000,000 P=– 2009 5-year corporate note 8.23% 5,000,000,000 5,000,000,000 2008 7-year corporate note 9.33% 543,200,000 548,800,000 2008 5-year corporate note 8.78% – 3,330,000,000Retail bonds - unsecured 3-year bonds 8.00% 705,580,000 705,580,000 5-year bonds 8.70% 2,294,420,000 2,294,420,000 13,543,200,000 11,878,800,000Less deferred financing costs 86,522,381 96,110,660 13,456,677,619 11,782,689,340Less current portion - net of deferred financing costs 710,105,174 5,600,000 P=12,746,572,445 P=11,777,089,340

Fixed Rate Notes - P=5.0 billion On April 14, 2011 (issue date), the Company availed a total of P=5.0 billion from the Notes Facility Agreement it signed on April 12, 2011, with First Metro Investment Corporation (FMIC) as Issue Manager, the proceeds of which were used by the Company for general corporate purposes and refinancing. 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. Prior to 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 amount calculated by the Notes Facility Agent, as accrued interest on the principal amount of the Notes being earlier redeemed up to the Early Redemption Date plus the Breakage Cost, calculated as the present value of the remaining principal amortizations and payments of interest on the Notes discounted at the sum of the comparable benchmark tenor yield. Under the Notes Facility Agreement, the Company shall not permit its Debt-to-Equity (DE) ratio to exceed 2.5:1 calculated based on the Company’s year-end audited parent company financial statements. The Company is in compliance with the debt covenant as of December 31, 2011. Total interest expense charged to the parent company statements of income amounted to P=221.2 million in 2011. Unamortized deferred financing costs reduced the carrying amount of long-term debt by P=36.3 million as of December 31, 2011. 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.

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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, 2011 and 2010. Total interest expense charged to the parent company statements of income amounted to P=394.1 million in 2011, P=399.2 million in 2010, and P=101.1 million in 2009. Unamortized deferred financing costs reduced the carrying amount of long-term debt by P=29.9 million and P=39.2 million as of December 31, 2011 and 2010, respectively. 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.

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. 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, 2011 and 2010. In December 2011, the P=3.3 billion 5-year fixed-rate note was redeemed incurring P=66.6 million of prepayment penalty charges. Total interest expense charged to the parent company statements of income amounted to P=347.7 million in 2011, P=352.7 million in 2010 and P=263.2 million in 2009. Unamortized deferred financing costs reduced the carrying amount of long-term debt by P=4.5 million and P=32.5 million as of December 31, 2011 and 2010, respectively.

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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.

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.

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 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, 2011 and 2010.

Total interest expense charged to the parent company statements of income amounted to P=300.2 million, P=263.8 million and P=260.6 million in 2011, 2010 and 2009, respectively. Unamortized deferred financing costs reduced the carrying amount of long-term debt by P=15.9 million and P=24.4 million as of December 31, 2011 and 2010, respectively.

14. Equity

a. Capital Stock

2011 2010 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, 2011 and 2010.

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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. On July 16, 2007, the Company listed with the PSE its common stock, wherein it offered 1,787,664,000 shares to the public at issue price of P=5.80 per share. The total proceeds from the issuance of new shares amounted to P=10.37 billion. The Company incurred transaction costs incidental to the IPO amounting to P=412.4 million, which is charged against “Additional paid-in capital” in the balance sheet. As of December 31, 2011, 2010 and 2009, the Company has 530,483 and 498 shareholders, respectively.

b. Retained Earnings

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. On March 1, 2012, 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 16, 2012. The cash dividends are payable on April 3, 2012.

15. Personnel Costs

2011 2010 2009 Salaries and wages P=135,027,109 P=74,815,636 P=36,641,816 Employee benefits 30,026,735 17,845,423 9,728,897 Retirement costs (see Note 16) 21,568,626 17,211,073 5,362,670

P=186,622,470 P=109,872,132 P=51,733,383

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16. 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=21.6 million in 2011, P=17.2 million in 2010 and P=5.4 million in 2009. 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

2011 2010 2009 Current service cost P=12,641,000 P=7,432,700 P=822,557 Interest cost 15,118,422 12,086,250 11,500,515 Expected return on plan assets (10,489,467) (6,469,600) (6,147,369) Net actuarial loss (gain) recognized in the year 4,298,671 4,161,723 (813,033) P=21,568,626 P=17,211,073 P=5,362,670 Actual return on plan assets P=8,709,300 P=3,521,198 P=3,398,791

Pension liability (asset)

2011 2010 Defined benefit obligation P=281,131,100 P=183,476,000 Unrecognized net actuarial loss (156,273,575) (91,425,000) Fair value of plan assets (173,728,426) (149,849,527) (P=48,870,901) (P=57,798,527)

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

2011 2010 Opening defined benefit obligation P=183,476,000 P=134,740,702 Actuarial losses on obligation 67,367,051 25,061,948 Interest cost 15,118,422 12,086,250 Current service cost 12,641,000 7,432,700 Transfer from subsidiaries 2,528,627 4,154,400 Closing defined benefit obligation P=281,131,100 P=183,476,000

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

2011 2010 Opening fair value of plan assets P=149,849,527 P=64,696,229 Contributions by employer 12,641,000 77,477,700 Expected return on plan assets 10,489,467 6,469,600 Transfer from subsidiaries 2,528,599 4,154,400 Actuarial losses on plan assets (1,780,167) (2,948,402) Closing fair value of plan assets P=173,728,426 P=149,849,527

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The Company expects to make the same contribution in 2012 as in 2011. The principal assumptions used as of December 31 to determine retirement benefits are as follows:

2011 2010 2009 Discount rate 6.32% 8.24% 8.97% Expected rate of return on assets 7.00% 7.00% 10.00% Future salary increase 6.00% 6.00% 8.00%

Amounts for the current and previous four periods follow:

2011 2010 2009 2008 2007 Defined benefit obligation P=281,131,100 P=183,476,000 P=134,740,702 P=35,627,371 P=48,429,411 Fair value of plan assets 173,728,426 149,849,527 64,696,229 55,885,177 51,487,461 Surplus (deficit) (107,402,674) (33,626,473) (70,044,473) 20,257,806 3,058,050 Experience adjustments on

pension liabilities 67,367,051 25,061,948 85,050,900 (19,678,981) (3,507,975) Experience adjustments on

pension asset (1,780,195) (2,948,402) (2,748,578) (2,519,953) 1,535,702

Major categories of plan assets are the following:

2011 2010 Commercial papers P=166,874,855 P=142,254,464 Others 6,853,571 7,595,063 P=173,728,426 P=149,849,527

17. Income Tax

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

2011 2010 2009 Current

Corporate income tax P=7,083,083 P=23,775,054 P=14,535,971 Final 85,676,619 17,636,611 53,767,097

92,759,702 41,411,665 68,303,068 Deferred 1,994,983 82,962,486 (232,027,190) P=94,754,685 P=124,374,151 (P=163,724,122)

The provision for corporate income tax represents MCIT in 2011, 2010 and 2009.

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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:

2011 2010 2009

At statutory rate of 30% P=11,266,573,939 P=306,186,425 P=436,984,553 Additions to (reductions in) income tax

resulting from: Unrecognized deferred income tax asset on:

NOLCO 352,109,510 114,822,403 – MCIT 7,083,083 23,775,054 – Final tax on interest income 85,676,619 17,636,611 53,767,097 Nondeductible interest expense 42,944,351 8,825,291 29,144,651 Expired MCIT – 2,643,079 – Interest income already subjected to

final tax at a lower rate (130,134,396) (26,743,307) (88,317,125) Dividend income (11,529,498,421) (322,771,405) (594,879,704) Others – – (423,594)

P=94,754,685 P=124,374,151 (P=163,724,122)

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

2011 2010 Deferred income tax assets: NOLCO P=93,873,663 P=93,873,663 Unamortized past service cost 19,133,992 21,699,980 MCIT 14,535,971 14,535,971 127,543,626 130,109,614 Deferred income tax liabilities: Accrual of pension cost (14,661,270) (17,339,558) Unrealized foreign exchange gain (3,439,454) (1,332,171) (18,100,724) (18,671,729) P=109,442,902 P=111,437,885

As of December 31, 2011, 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

2009 2010-2012 P=14,535,971 P=– P=– P=14,535,971 2010 2011-2013 23,775,054 – – 23,775,054 2011 2012-2014 7,083,083 – – 7,083,083

P=45,394,108 P=– P=– P=45,394,108

As of December 31, 2011, 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 2011 2012-2014 352,109,510 – – 352,109,510

P=1,047,763,063 P=– P=– P=1,047,763,063

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The Company did not recognize deferred income tax assets from MCIT amounting to P=7.1 million and P=23.8 million as of December 31, 2011 and 2010, respectively, and NOLCO amounting to P=352.1 million and P=369.5 million as of December 31, 2011 and 2010, 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.

18. Related Party Disclosures

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: CLP,

Cotabato Ice Plant, Inc. (CIPI), DLP, CPPC, SEZ and HI, for which it is entitled to management fees. Management fees charged to related parties amounted to P=262.5 million in 2011, P=242.4 million in 2010 and P=215.5 million in 2009.

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 ARI. As a guarantor, the Company received a guarantee fee amounting to nil in 2011 and 2010, and P=3.1 million in 2009 (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, 2011, the Company provided SBLC’s for APRI and SNAP B in the amount of P=2.5 billion; guarantee on the bank loans of CLP, DLP, HI and SEZ in the amount of P=1.6 billion. As at December 31, 2010, the Company provided SBLC’s for STEAG, LHC, SNAPM, SNAPB, HI and 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.

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=207.9 million in 2011, P=143.7 million in 2010 and P=2.2 million in 2009.

d. Technical and management fees charged by AEV to the Company amounted to nil in 2011 and 2010, and P=40.0 million in 2009.

e. Share in information technology project costs of AEV amounted to nil in 2011 and 2010, and P=32.5 million in 2009.

f. Cash deposits with Unionbank of the Philippines (UBP) at prevailing market terms. UBP is an associate of AEV. Total cash deposit amounted to P=1.6 billion and P=2.7 billion as of December 31, 2011 and 2010, respectively. Total interest income earned on deposits with UBP amounted to P=72.1 million, P=38.0 million and P= 139.9 million in 2011, 2010 and 2009, respectively.

g. Unsecured advances to ACO and AEV for operational charges earn interest at 4% per annum,

with no fixed payment terms. Advances amounted to nil and P=15.7 million as of December 31, 2011 and 2010, respectively. Interest income earned on these deposits amounted to P=0.2 million in 2011, P=0.7 million in 2010 and P=0.01 million in 2009.

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h. Interest bearing advances are payable within one year. Interest income earned on these advances amounted to P=4.0 million in 2011, P=19.9 million in 2010 and P=84.8 million in 2009.

i. Lease of commercial office units by the Company for a period of one year renewable at the

end of term and use of function rooms and staff house from Cebu Praedia Development Corporation (CPDC). Total expenses amounted to P=5.1 million in 2011, P=3.7 million in 2010 and P=1.4 million in 2009. CPDC is a subsidiary of AEV.

j. Aviation services rendered by AEV AVI, a subsidiary of AEV, to the Company. Total expenses amounted to P=16 million in 2011, P=6.4 million in 2010 and P=4.9 million in 2009.

k. Total compensation and benefits of key management personnel of the Company are as follows: 2011 2010 2009 Short-term benefits P=132,901,182 P=73,009,329 P=51,840,857 Post employment benefits 8,568,818 5,590,671 4,509,143 P=141,470,000 P=78,600,000 P=56,350,000

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

Receivables from Related Parties

Amounts Owed by a related party

Amounts Owed to Related Parties

Name of Company 2011 2010 2011 2010 2011 2010 Parents:

AEV (Immediate) P=373,610 P=15,428,990 P=– P=– P=– P=– ACO (Ultimate) – 319,560 – – – – Subsidiaries:

TPI 6,450 – – – – 3,113,662,486 ARI 161 – – 10,361,676,174 – – TLI 21,802,867 21,086,208 – – – – APRI 21,589,636 20,602,766 – – – – DLP 19,374,903 16,307,874 – – – – CLP 1,256,035 1,245,184 – – – – TPVI 918,050 903,739 – – – – Therma Marine 580,619 17,043,318 – – – – SEZ 301,076 154,307 – – – – AESI 270,619 191,259 – – – – Abovant 1,141 – – – – – HI – 21,957,814 – – – – Prism Energy, Inc. 73,368 792,454 – – – – AI 26,653 – – – – – Therma South, Inc. 521,068 – – – – – CPPC 38,012 – – – – – MEZ 28,988 – – – – – Therma Mobile 19,924 – – – – – BEZ 1,671 – – – – – CIPI 155,733 – – – – –

Associates:

CEDC 36,520,000 45,100,000 – – – –

MORE 894,103 4,860,500 – – – – VECO 351,167 9,341,766 – – – – SNAPM 79,913 4,860,500 – – – – SNAPB 178,699 – – – – – EAUC 20,646 2,825 – – 18,415,300 129,999,300 RPEI 17,227 15,782,252 – – – – SFELAPCO 38,203 – – – – – Mazzaraty Energy Corporation – 560,856 – – – –

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19. Financial Risk Management Objectives and Policies The Company’s principal financial instruments comprise of cash and cash equivalents 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 instruments such as trade and other receivables, amounts owed by related parties, trade and other payables, amounts owed to related parties, bank loans and long-term debts, which arise directly from its operations.

The Company 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 20). Financial risk committee The Financial Risk Committee 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. Treasury Service Group The Treasury Service Group is responsible for the comprehensive monitoring, evaluating and analyzing of the Company’s risks in line with the policies and limits. 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, trade and other 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 and cash equivalents, trade and other receivables, amounts owed by a related party 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 cash equivalents, 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.

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The credit quality per class of financial assets as of December 31 is as follows (amounts in thousands): 2011

Neither past due nor impaired Past due

Total but not

High Grade Standard Sub-standard impaired Cash and cash equivalents P=7,900,015 P=– P=– P=– P=7,900,015 Trade and other receivables 261,543 – – 11,884 273,427 Total P=8,161,558 P=– P=– P=11,884 P=8,173,442

2010

Neither past due nor impaired Past due

Total but not

High Grade Standard Sub-standard impaired Cash and cash equivalents P=11,081,930 P=– P=– P=– P=11,081,930 Trade and other receivables 312,862 – – 16,297 329,159 Amounts owed by a related party 10,361,676 – – – 10,361,676 Derivative asset 7,670 – – – 7,670 Total P=21,764,138 P=– P=– P=16,297 P=21,780,435

High grade - pertain to receivables from customers with good favorable credit standing and have no history of default. Standard grade - pertain to those customers with history of sliding beyond the credit terms but pay a week after being past due. Sub-standard grade - pertain to those customers with payment habits that normally extend beyond the approved credit terms, and has high probability of being impaired. The aging analyses of financial assets as of December 31 are as follows (amounts in thousands): 2011

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=7,900,015 P=7,900,015 P=– P=– P=– Trade and other receivables 273,427 261,543 – 1,996 9,888 Total P=8,173,442 P=8,161,558 P=– P=1,996 P=9,888 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=– Trade and other receivables 329,159 312,862 – 13,303 2,994 Amounts owed by a related party 10,361,676 10,361,676 – – – Derivative asset 7,670 7,670 – – – Total P=21,780,435 P=21,764,138 P=– P=13,303 P=2,994

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

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placements. These placements are maintained to meet maturing obligations and pay dividend declarations.

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. 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):

2011

Total Contractual undiscounted payments Carrying On Less than

Value Total Demand 1 year 1 to 5 yearsLong-term debts P=13,456,678 P=14,358,520 P=– P=726,299 P=13,632,221 Amounts owed to related parties 18,415 18,415 18,415 – – Trade and other payables 192,115 192,115 192,115 – – Derivative Liability 736 736 736 – – Total P=13,667,944 P=14,569,786 P=211,266 P=726,799 P=13,632,221

2010

Total Contractual undiscounted payments Carrying On Less than

Value Total Demand 1 year 1 to 5 yearsBank loans P=1,290,000 P=1,293,386 P=– P=1,293,386 P=– Long-term debts 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 – – Trade and other payables 76,145 76,145 – 76,145 – Total P=16,392,496 P=19,937,279 P=3,243,662 P=2,400,205 P=14,293,412

Market Risk The risk of loss, immediate or over time, due to adverse fluctuations in the price or market value of instruments, products, and transactions in the Company’s overall portfolio (whether on or off-balance sheet) is market risk. These are influenced by foreign and domestic interest rates, foreign exchange rates and gross domestic product growth.

Foreign exchange risk The foreign exchange risk of the Company pertains to its foreign currency-denominated cash and cash equivalents and receivables from related parties.

The foreign currency-denominated monetary assets and liability and their Philippine Peso equivalents follow:

2011 2010

US Dollar Peso Equivalent US Dollar Peso Equivalent Financial assets Cash and cash equivalents $9,523,160 P=417,495,351 $6,583,731 P=288,630,767 Receivables from related parties – – 224,705 9,851,067

$9,523,160 P=417,495,351 $6,808,436 P=298,481,834

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The exchange rate for both December 31, 2011 and 2010 is P=43.84 per US$1. As a result of the translation of these foreign currency denominated assets, the Company reported net unrealized foreign exchange gain of P=7.0 million and P=272.0 million in 2011 and 2010, respectively.

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, 2011 and 2010 (amounts in thousands).

Increase (decrease) in

US dollar

Effect on income before tax

2011 US dollar-denominated accounts 5% P=20,875 US dollar-denominated accounts (5%) (20,875)

2010 US dollar-denominated accounts 5% P=14,924 US dollar-denominated accounts (5%) (14,924)

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 years ended December 31, 2011 and 2010. 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:

2011 2010 Long-term debts P=12,746,572,445 P=11,777,089,340 Current portion of long-term debts 710,105,174 5,600,000 Bank loans – 1,290,000,000 Cash and cash equivalents (7,900,014,865) (11,081,929,955) Net debt (a) 5,556,662,754 1,990,759,385 Equity 51,807,179,542 24,060,045,449 Equity and net debt (b) P=57,363,842,296 P=26,050,804,834 Gearing ratio (a/b) 9.69% 7.64%

The Company is also subject to externally imposed capital requirements (see Note 13).

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20. Financial Instruments Classification of Financial Instruments 2011

Cash Financial liability

at FVPL Loans and

receivables Other financial

liabilities

Total Assets Cash and cash equivalents P=440,000 P=– P=7,899,574,865 P=– P=7,900,014,865 Trade and other receivables – – 273,427,168 – 273,427,168 P=440,000 P=– P=8,173,002,033 P=– P=8,173,442,033 Liabilities Long-term debts P=– P=– P=– P=13,456,677,619 P=13,456,677,619 Amounts owed to related parties – – – 18,415,300 18,415,300 Trade and other payables – – – 216,279,791 216,279,791 Derivative liability – 736,250 – – 736,250 P=– P=736,250 P=– P=13,691,372,710 P=13,692,108,960

2010

Cash Financial asset

at FVPL Loans and

receivables Other financial

liabilities

Total Assets Cash and cash equivalents P=155,000 P=– P=11,081,774,955 P=– P=11,081,929,955 Trade and other receivables – – 329,159,304 – 329,159,304 Amounts owed by a related party – – 10,361,676,174 – 10,361,676,174 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 debts – – – 11,782,689,340 11,782,689,340 Amounts owed to related parties – – – 3,243,661,786 3,243,661,786 Trade and other payables – – – 110,405,245 110,405,245 P=– P=– P=– P=16,426,756,371 P=16,426,756,371

Fair Value of Financial Instruments Set out below is a comparison by category of the carrying amounts and fair value of all of the Company’s financial instruments that are carried in the financial statements as of December 31, 2011 and 2010 (amounts in thousands).

2011 2010 Carrying Fair Carrying Fair Amount Value Amount Value

Financial Assets Cash and cash equivalents P=7,900,015 P=7,900,015 P=11,081,930 P=11,081,930 Trade and other receivables 273,427 273,427 329,159 329,159 Amounts owed by a related party – – 10,361,676 10,361,676 Derivative asset – – 7,670 7,670 Financial Liabilities Bank loans – – 1,290,000 1,290,000 Trade and other payables 192,115 192,115 110,405 110,405 Amounts owed to related parties 18,415 18,415 3,243,662 3,243,662 Long-term debts 13,456,678 14,271,998 11,777,089 12,802,396 Derivative liability 736 736 – –

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.

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*SGVMC409382*

Cash and cash equivalents, trade and other receivables, amounts owed by a related party, bank loans, trade and other payables, and amounts owed to related parties The carrying amounts of cash and cash equivalents, trade and other receivables, amounts owed by a related party, bank loan, trade and other payables 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 debts 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 6.17% to 9.33% in 2011 and 8.00% to 9.33% in 2010. 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, 2011, the Company has outstanding buy Dollar and sell Peso forward exchange contracts with counterparty banks with an aggregate notional amount of $0.3 million and remaining maturities of 1 month. As at December 31, 2011, the forward rates related to the forward contracts range from P=43.84 to P=44.81 per US$1. The Company recognized derivative asset relating to these contracts amounting to P=0.2 million. As of December 31, 2011, 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 €0.30 million and remaining maturities of 1 month. As at December 31, 2011, the forward rates related to the forward contracts amounted to €1.2950 to €1.3050 per US$1. The Company recognized derivative liability relating to these contracts amounting to P=0.9 million. As of December 31, 2010, the Company has outstanding non-deliverable buy Dollar and sell Peso forward exchange contracts with counterparty bank 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. 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 months to 8 months. As at December 31, 2010, the forward rates related to the forward contracts amounted to €1.3413 to €1.3421 per US$1. The Company recognized derivative asset relating to these contracts amounting to P=3.1 million.

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*SGVMC409382*

The movements in fair value changes of all derivative instruments for the years ended December 31, 2011 and 2010 are as follows:

2011 2010 At beginning of year P=7,669,730 (P=3,130,290) Net changes in fair value of derivatives not

designated as accounting hedges (8,893,542) (45,153,092) Fair value of settled instruments 487,562 55,953,112 At end of year (P=736,250) P=7,669,730

The loss from the net fair value changes relating to the forward contracts amounting to P=8.9 million in 2011 and P=45.2 million in 2010 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, 2011 and 2010, 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.

21. 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. 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.

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*SGVMC409382*

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.

22. 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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*SGVMC409382*

23. Supplementary Tax Information Required Under Revenue Regulations (RR) 19-2011

On December 9, 2011, the BIR issued RR No. 19-2011 prescribing the new income tax forms to be used effective calendar year 2011. In the case of corporations using BIR Form 1702, the taxpayer is now required to include as part of its notes to the audited financial statements, which will be attached to the income tax return, schedules and information on taxable income and deductions taken. The schedule and information of taxable income and deductions taken for 2011 are as follows: a. Schedule of Sales/Revenues/Receipts/Fees

Regular Rate Sale of services P=470,388,576

b. Cost of Services

Regular Rate Direct charges - salaries and wages P=70,175,913 Direct charges – SSS, HDMF & PHIC Contribution 951,628 Direct charges – Contribution paid to Retirement Fund 11,015,040 Direct charges – other benefits 12,738,041 Direct charges - materials, supplies and communication 2,931,475 Direct charges – depreciation 5,979,226 Direct charges – rental 3,969,168 Direct charges – outside services 15,477,609 Direct charges – others 3,237,649 P=126,475,749

c. Non-operating and Taxable Other Income Not Subjected to Final Tax

Regular Rate Interest Income not subject to final tax P=4,237,686 Others 6,003,638 P=10,241,324

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*SGVMC409382*

d. Itemized Deductions

Regular Rate Salaries and wages P=94,019,924 Fringe benefits 369,720 Rental 3,668,000 Professional Fees 4,711,588 Director's Fees 9,591,631 Janitorial and Messengerial Services 126,933 Other Outside Services 45,021,882 Advertising 22,694,601 Research and development 12,772,387 Interest 1,212,088,472 Insurance 3,361,235 Repairs and maintenance 666,347 Representation and entertainment 1,868,404 Transportation and travel 49,884,025 Communication, Light and Water 3,527,808 Supplies & Communication 2,709,045 Freight & Handling 645,600 Taxes and licenses 3,087,677 Depreciation 5,252,414 Amortization of intangibles 273,128 Bidding Expenses 1,076,971 Charitable contribution 23,715,635 Realized foreign exchange loss 11,232,234 Miscellaneous 15,486,856 P=1,527,852,517

24. 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=504,409,392 P=60,529,127 Zero-rated sales 120,000 – P=504,529,392 P=60,529,127

The Company’s sales that are subject to VAT are reported under the following accounts:

Service Income - Management fees Service Income - Professional fees Service Income - Technical fees

*SGVMC410781*

- 2 -

December 31 2011 2010 Equity Attributable to Equity Holders of the Parent Capital stock (Note 19a) P=7,358,604 P=7,358,604 Additional paid-in capital 12,588,894 12,588,894 Share in net unrealized valuation gains on AFS investments

of an associate (Note 9) 73,952 78,118 Cumulative translation adjustments (57,668) – Share in cumulative translation adjustments of associates (Note 9) (546,753) 57,922 Acquisition of non-controlling interests (259,147) (259,147) Retained earnings (Note 19b) 49,400,692 37,505,797 68,558,574 57,330,188 Non-controlling Interests 1,633,643 404,022 Total Equity 70,192,217 57,734,210 TOTAL LIABILITIES AND EQUITY P=153,527,939 P=134,556,872 See accompanying Notes to Consolidated Financial Statements.

*SGVMC410781*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Amounts in Thousands, Except Earnings Per Share Amounts) Years Ended December 31 2011 2010 2009

OPERATING REVENUES Sale of power (Notes 20 and 30):

Generation P=39,944,982 P=46,313,904 P=12,359,479 Distribution 14,356,619 13,064,593 10,734,427

Services 51,917 62,524 61,598 Technical, management and other fees (Note 31) 122,119 110,437 18,761 54,475,637 59,551,458 23,174,265

OPERATING EXPENSES Cost of generated power (Note 22) 15,082,003 15,882,326 5,030,277 Cost of purchased power (Note 21) 11,205,168 10,001,570 8,032,562 Depreciation and amortization (Notes 11, 12 and 13) 3,345,782 3,003,977 1,412,900 Operations and maintenance (Note 24) 2,218,047 2,437,928 1,336,987 General and administrative (Note 23) 2,259,831 1,986,826 1,902,428 Cost of services 9,391 7,251 2,944 34,120,222 33,319,878 17,718,098

FINANCIAL INCOME (EXPENSES) Interest income (Notes 4 and 31) 861,521 224,158 409,972 Interest expense and other financing costs (Note 32) (7,345,575) (6,678,293) (2,813,978) (6,484,054) (6,454,135) (2,404,006)

OTHER INCOME Share in net earnings of associates (Note 9) 8,436,906 4,625,883 2,535,386 Other income - net (Note 27) 692,849 1,600,399 813,411 9,129,755 6,226,282 3,348,797

INCOME BEFORE INCOME TAX 23,001,116 26,003,727 6,400,958

PROVISION FOR INCOME TAX - net (Note 28) 1,117,209 920,697 631,190

NET INCOME P=21,883,907 P=25,083,030 P=5,769,768

Attributable to: Equity holders of the parent P=21,608,253 P=25,041,116 P=5,658,581 Non-controlling interests 275,654 41,914 111,187 P=21,883,907 P=25,083,030 P=5,769,768

EARNINGS PER COMMON SHARE (Note 29) Basic and diluted, for income for the year attributable to

ordinary equity holders of the parent P=2.94 P=3.40 P=0.77 See accompanying Notes to Consolidated Financial Statements.

*SGVMC410781*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Amounts in Thousands) Years Ended December 31 2011 2010 2009

NET INCOME ATTRIBUTABLE TO: Equity holders of the parent P=21,608,253 P=25,041,116 P=5,658,581 Non-controlling interests 275,654 41,914 111,187 21,883,907 25,083,030 5,769,768

OTHER COMPREHENSIVE INCOME (LOSS) Share in net unrealized valuation gains (losses) on AFS

investments of an associate (Note 9) (4,166) 78,118 – Movement in cumulative translation adjustments (57,668) – – Share in movement in cumulative translation adjustment of

associates (Note 9) (604,675) (57,324) 133,668 Total other comprehensive income for the year, net of tax (666,509) 20,794 133,668 TOTAL COMPREHENSIVE INCOME P=21,217,398 P=25,103,824 P=5,903,436

Attributable to: Equity holders of the parent P=20,941,744 P=25,061,910 P=5,792,249 Non-controlling interests 275,654 41,914 111,187 P=21,217,398 P=25,103,824 P=5,903,436 See accompanying Notes to Consolidated Financial Statements.

*SGVMC410781*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009 (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

Gains on AFS Investments of

an Associate (Note 9)

Movement in Cumulative Translation

Adjustments

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, 2011 P=7,358,604 P=12,588,894 P=78,118 P=– P=57,922 (P=259,147) P=37,505,797 P=404,022 P=57,734,210 Net income for the year – – – – – 21,608,253 275,654 21,883,907 Other comprehensive loss – – (4,166) (57,668) (604,675) – – – (666,509) Total comprehensive income (loss) for the year – – (4,166) (57,668) (604,675) – 21,608,253 275,654 21,217,398 Cash dividends - P=1.32 a share (Note 19b) – – – – – – (9,713,358) – (9,713,358) Cash dividends paid to non-controlling

interests – – – – – – – (79,633) (79,633) Change in non-controlling interests – – – – – – – 1,033,600 1,033,600 Balances at December 31, 2011 P=7,358,604 P=12,588,894 P=73,952 (P=57,668) (P=546,753) (P=259,147) P=49,400,692 P=1,633,643 P=70,192,217

Balances at January 1, 2010 P=7,358,604 P=12,588,894 P=– 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=– P=57,922 (P=259,147) P=37,505,797 P=404,022 P=57,734,210

(Forward)

*SGVMC410781*

- 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, 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 See accompanying Notes to Consolidated Financial Statements.

*SGVMC410781*

ABOITIZ POWER CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in Thousands) Years Ended December 31 2011 2010 2009

CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax P=23,001,116 P=26,003,727 P=6,400,958 Adjustments for:

Interest expense and other financing costs (Note 32) 7,345,575 6,678,293 2,813,978

Depreciation and amortization (Notes 11 and 12) 3,339,445 3,003,977 1,412,900 Amortization of software 6,337 – – Write-off of project costs and assets – 42,217 – Loss (gain) on sale of property, plant and equipment 81 (75) (2,865) Unrealized fair valuation losses (gains) on derivatives (5,991) (22,977) 15,630 Interest income (Notes 4 and 31) (861,521) (224,158) (409,972) Net unrealized foreign exchange gains (2,565) (1,504,650) (27,468) Share in net earnings of associates (Note 9) (8,436,906) (4,625,883) (2,535,386) Gain on sale of investments in shares of stock (16,612) – –

Operating income before working capital changes 24,368,959 29,350,471 7,667,775 Decrease (increase) in:

Trade and other receivables 186,876 (2,399,871) (2,608,352) Inventories (328,030) (734,948) (547,968) Other current assets (147,686) (448,445) (20,600)

Increase (decrease) in: Trade and other payables (470,868) 1,685,285 2,651,669 Customers’ deposits 159,811 223,268 210,024

Net cash generated from operations 23,769,062 27,675,760 7,352,548 Income and final taxes paid (1,086,945) (770,382) (516,772) Service fees paid (Note 12) (40,000) (40,000) (40,000) Net cash flows from operating activities 22,642,117 26,865,378 6,795,776

CASH FLOWS FROM INVESTING ACTIVITIES Cash dividends received (Note 9) 3,982,322 1,818,359 833,187 Interest received 792,989 215,259 451,683 Proceeds from sale of property, plant and equipment 8,449 1,778 18,604 Proceeds from sale of investments in shares of stock 50,000 – – Additions to:

Intangible assets - service concession rights (Note 12) (64,860) (104,250) (70,259) Property, plant and equipment

(Notes 11 and 35) (7,462,398) (4,208,027) (3,274,390) Additional investments in associates (Note 9) (1,148,266) (1,031,232) (2,526,754) Net collection of (additional) advances to associates

(Note 9) 367,565 (1,060,396) 813,221 Acquisition of Tiwi-Makban Geothermal Power Plants

(Note 8) – – (20,198,774) Net cash received on step acquisition to subsidiary

(see Note 8) 314,852 – – Advances to contractors (2,353,605) – – Decrease (increase) in other noncurrent assets 533,633 410,269 (922,143) Net cash flows used in investing activities (4,979,319) (3,958,240) (24,875,625)

(Forward)

*SGVMC410781*

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Years Ended December 31 2011 2010 2009

CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from availment of long-term debt - net of

transaction costs (Note 16) P=5,520,966 P=870,000 P=9,762,893 Payments to a preferred shareholder of a subsidiary

(Note 18) (31,070) (31,070) (31,070) Changes in non-controlling interests (870,470) (208,960) (158,142) Payments of:

Long-term debt (Note 16) (4,205,685) (442,564) (48,446) Finance lease obligation (1,094,845) (1,118,880) –

Interest paid (1,815,548) (1,622,023) (1,468,820) Cash dividends paid (Note 19b) (9,713,358) (2,207,581) (1,471,721) Net availments (payment) of bank loans (Note 15) (365,200) (3,597,038) 1,136,900 Net cash flows from (used in) financing activities (12,575,210) (8,358,116) 7,721,594

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 5,087,588 14,549,022 (10,358,255)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS 2,128 (62,083) (160,515)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 18,301,845 3,814,906 14,333,676

CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 4) P=23,391,561 P=18,301,845 P=3,814,906

See accompanying Notes to Consolidated Financial Statements.

*SGVMC410781*

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, 2011 and 2010 and for each of the three years in the period ended December 31, 2011, were approved and authorized for issue by the Board of Directors (BOD) of the Company on March 1, 2012.

2. Basis of Preparation, Statement of Compliance and Summary of Significant Accounting

Policies Basis of Preparation The consolidated financial statements of the Group are prepared on a historical cost basis, except for derivative financial instruments which are 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 when otherwise indicated. Statement of Compliance The consolidated financial statements of the Group are prepared in compliance with Philippine Financial Reporting Standards (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 PFRS and Philippine Interpretations which were adopted as at January 1, 2011. • PAS 24, Related Party Transactions (Amendment)

PAS 24 clarifies the definitions of a related party. The new definitions emphasize a symmetrical view of related party relationships and clarify the circumstances in which persons and key management personnel affect related party relationships of an entity. In addition, the amendment introduces an exemption from the general related party disclosure requirements for transactions with government and entities that are controlled, jointly controlled or significantly influenced by the same government as the reporting entity. The adoption of the amendment did not have any impact on the financial position or performance of the Group.

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*SGVMC410781*

• PAS 32, Financial Instruments: Presentation (Amendment) The amendment alters the definition of a financial liability in PAS 32 to enable entities to classify rights issues and certain options or warrants as equity instruments. The amendment is applicable if the rights are given pro rata to all of the existing owners of the same class of an entity’s non-derivative equity instruments, to acquire a fixed number of the entity’s own equity instruments for a fixed amount in any currency. The amendment has had no effect on the financial position or performance of the Group because the Group does not have these types of instruments.

• Philippine Interpretation IFRIC 14, Prepayments of a Minimum Funding Requirement

(Amendment) The amendment removes an unintended consequence when an entity is subject to minimum funding requirements and makes an early payment of contributions to cover such requirements. The amendment permits a prepayment of future service cost by the entity to be recognized as a pension asset. The Group is not subject to minimum funding requirements in the Philippines; therefore, the amendment of the interpretation has no effect on the financial position or performance of the Group.

Improvements to PFRS (issued 2010) 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 3, Business Combinations: The measurement options available for non-controlling

interest (NCI) were amended. Only components of NCI that constitute a present ownership interest that entitles their holder to a proportionate share of the entity’s net assets in the event of liquidation should be measured at either fair value or at the present ownership instruments’ proportionate share of the acquiree’s identifiable net assets. All other components are to be measured at their acquisition date fair value.

The amendments to PFRS 3 are effective for annual periods beginning on or after 1 July 2011. The Group, however, adopted these as of January 1, 2011 and changed its accounting policy accordingly as the amendment was issued to eliminate unintended consequences that may arise from the adoption of PFRS 3.

• PFRS 7, Financial Instruments - Disclosures: The amendment was intended to simplify the

disclosures provided by reducing the volume of disclosures around collateral held and improving disclosures by requiring qualitative information to put the quantitative information in context. The Group reflects the revised disclosure requirements in Note 33.

• PAS 1, Presentation of Financial Statements: The amendment clarifies that an entity may

present an analysis of each component of other comprehensive income maybe either in the statement of changes in equity or in the notes to the financial statements. The Group provides this analysis in the statement of changes in equity.

Other amendments resulting from the 2010 Improvements to PFRS to the following standards did not have any impact on the accounting policies, financial position or performance of the Group: • PFRS 3, Business Combinations (Contingent consideration arising from business combination

prior to adoption of PFRS 3 (as revised in 2008))

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• PFRS 3, Business Combinations (Un-replaced and voluntarily replaced share-based payment awards)

• PAS 27, Consolidated and Separate Financial Statements • PAS 34, Interim Financial Statements

The following interpretation and amendments to interpretations did not have any impact on the accounting policies, financial position or performance of the Group: • Philippine Interpretation IFRIC 13, Customer Loyalty Programmes (determining the fair value

of award credits) • Philippine Interpretation IFRIC 19, Extinguishing Financial Liabilities with Equity

Instruments

Standards Issued but not yet Effective Standards issued but not yet effective up to the date of issuance of the Group’s financial statements are listed below. This listing of standards and interpretations issued are those that the Group reasonably expects to have an impact on disclosures, financial position or performance when applied at a future date. The Group intends to adopt these standards when they become effective. • PAS 1, Financial Statement Presentation - Presentation of Items of Other Comprehensive

Income The amendments to PAS 1 change the grouping of items presented in OCI. Items that could be reclassified (or”recycled”) to profit or loss at a future point in time (for example, upon derecognition or settlement) would be presented separately from items that will never be reclassified. The amendment affects presentation only and has therefore no impact on the Group’s financial position or performance. The amendment becomes effective for annual periods beginning on or after July 1, 2012.

• PAS 12, Income Taxes - Recovery of Underlying Assets The amendment clarified the determination of deferred tax on investment property measured at fair value. The amendment introduces a rebuttable presumption that deferred tax on investment property measured using the fair value model in PAS 40, Investment Property should be determined on the basis that its carrying amount will be recovered through sale. Furthermore, it introduces the requirement that deferred tax on non-depreciable assets that are measured using the revaluation model in PAS 16, Property, Plant and Equipment always be measured on a sale basis of the asset. The amendment becomes effective for annual periods beginning on or after January 1, 2012.

• PAS 19, Employee Benefits (Amendment)

Amendments to PAS 19 range from fundamental changes such as removing the corridor mechanism and the concept of expected returns on plan assets to simple clarifications and re-wording. The Group is currently assessing the impact of the amendment to PAS 19. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

• PAS 27, Separate Financial Statements (as revised in 2011) As a consequence of the new PFRS 10, Consolidated Financial Statement and PFRS 12, Disclosure of Interests in Other Entities, what remains of PAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in separate financial statements. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

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• PAS 28, Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the new PFRS 11, Joint Arrangements and PFRS 12, PAS 28 has been renamed PAS 28, Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The amendment becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 7, Financial Instruments: Disclosures - Enhanced Derecognition Disclosure Requirements The amendment requires additional disclosure about financial assets that have been transferred but not derecognized to enable the user of the Group’s financial statements to understand the relationship with those assets that have not been derecognized and their associated liabilities. In addition, the amendment requires disclosures about continuing involvement in derecognized assets to enable the user to evaluate the nature of, and risks associated with, the entity’s continuing involvement in those derecognized assets. The amendment becomes effective for annual periods beginning on or after July 1, 2011. The amendment affects disclosures only and has no impact on the Group’s financial position or performance.

• PFRS 7, Financial instruments: Disclosures - Offsetting Financial Assets and Financial

Liabilities These amendments require an entity to disclose information about rights of set-off and related arrangements (such as collateral agreements). The new disclosures are required for all recognized financial instruments that are set off in accordance with PAS 32. These disclosures also apply to recognized financial instruments that are subject to an enforceable master netting arrangement or “similar agreement”, irrespective of whether they are set-off in accordance with PAS 32. The amendments require entities to disclose, in a tabular format unless another format is more appropriate, the following minimum quantitative information. This is presented separately for financial assets and financial liabilities recognized at the end of the reporting period: a) The gross amounts of those recognized financial assets and recognized financial liabilities; b) The amounts that are set off in accordance with the criteria in PAS 32 when determining

the net amounts presented in the statement of financial position; c) The net amounts presented in the statement of financial position; d) The amounts subject to an enforceable master netting arrangement or similar agreement

that are not otherwise included in (b) above, including: i. Amounts related to recognized financial instruments that do not meet some or all of

the offsetting criteria in PAS 32; and ii. Amounts related to financial collateral (including cash collateral); and

e) The net amount after deducting the amounts in (d) from the amounts in (c) above. The amendments to PFRS 7 are to be retrospectively applied for annual periods beginning on or after January 1, 2013. The amendment affects disclosures only and has no impact on the Group’s financial position or performance.

• PFRS 10, Consolidated Financial Statements PFRS 10 replaces the portion of PAS 27 that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12, Consolidation - Special Purpose Entities. PFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by PFRS 10 will require management to exercise significant judgment to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that

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were in PAS 27. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 11, Joint Arrangements PFRS 11 replaces PAS 31, Interests in Joint Ventures and SIC-13, Jointly-Controlled Entities Non-monetary Contributions by Venturers. PFRS 11 removes the option to account for jointly-controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 12, Disclosure of Involvement with Other Entities PFRS 12 includes all of the disclosures that were previously in PAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in PAS 31 and PAS 28. These disclosures relate to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PFRS 13, Fair Value Measurement

PFRS 13 establishes a single source of guidance under PFRS for all fair value measurements. PFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under PFRS when fair value is required or permitted. The Group is currently assessing the impact that this standard will have on the financial position and performance. This standard becomes effective for annual periods beginning on or after January 1, 2013.

• PAS 32, Financial Instruments: Presentation - Offsetting Financial Assets and Financial Liabilities These amendments to PAS 32 clarify the meaning of “currently has a legally enforceable right to set-off” and also clarify the application of the PAS 32 offsetting criteria to settlement systems (such as central clearing house systems) which apply gross settlement mechanisms that are not simultaneous. While the amendment is expected not to have any impact on the net assets of the Group, any changes in offsetting is expected to impact leverage ratios and regulatory capital requirements. The amendments to PAS 32 are to be retrospectively applied for annual periods beginning on or after January 1, 2014. The Group is currently assessing the impact of the amendments to PAS 32.

• PFRS 9, Financial Instruments: Classification and Measurement PFRS 9 as issued reflects the first phase 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, 2015. In subsequent phases, hedge accounting and impairment of financial assets will be addressed with the completion of this project expected on the latter half of 2012. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Group’s financial assets, but will potentially have no impact on classification and measurements of financial liabilities. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

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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 2011 2010 2009 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 – 99.93 –

Cotabato Light and Power Company (CLP) Power distribution 99.94 – 99.94 – 99.93 –

Cotabato Ice Plant, Inc. Manufacturing – 100.00 – 100.00 – 100.00

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 distribution 100.00 – 100.00 – 100.00 –

Aboitiz Renewables, Inc. (ARI; formerly Philippine Hydropower Corporation) and Subsidiaries

Power generation 100.00 – 100.00 – 100.00 –

AP Renewables, Inc. (APRI) Power generation – 100.00 – 100.00 – 100.00

Bakun Power Line Corporation * Power generation – 100.00 – – – –

Cleanergy, Inc. * Power generation – 100.00 – 100.00 – 100.00

Cordillera Hydro Corporation * Power generation – 100.00 – – – –

Hydro Electric Development Corporation * Power generation – 99.97 – 99.97 – 99.97

Hedcor Benguet, Inc. (HBI) * Power generation – 100.00 – 100.00 – 100.00

Hedcor Bokod, Inc. * Power generation – 100.00 – – – –

Hedcor Bukidnon, Inc. * Power generation – 100.00 – – – –

Hedcor, Inc. (HI) Power generation – 100.00 – 100.00 – 100.00

Hedcor Sabangan, Inc. * Power generation – 100.00 – – – –

Hedcor Sibulan, Inc. (HSI) Power generation – 100.00 – 100.00 – 100.00

Hedcor Tamugan, Inc. (HTI) * Power generation – 100.00 – 100.00 – 100.00

Hedcor Tudaya, Inc. * Power generation – 100.00 – – – –

Kookaburra Equity Ventures, Inc. Holding company – 100.00 – – – –

Luzon Hydro Corporation (see Note 8) Power generation – 100.00 – – – –

Tagoloan Hydro Corporation * Power generation – 100.00 – – – –

Therma Power, Inc. (TPI) and Subsidiaries 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 South, Inc. (TSI, formerly Therma Pagbilao, Inc.) * Power generation – 100.00 – 100.00 – 100.00

Therma Power-Visayas, Inc. (TPVI) * Power generation – 100.00 – 100.00 – 100.00

Therma Central Visayas, Inc. (TCVI) * Power generation – 100.00 – – – –

Therma Southern Mindanao, Inc. (TSMI) * Power generation – 100.00 – – – –

Therma Subic, Inc. (Therma Subic) * Power generation – 100.00 – – – –

Vesper Industrial and Development Corporation (VIDC) * Power generation – 100.00 – – – –

Abovant Holdings, Inc. Holding company – 60.00 – 60.00 – 60.00

Teraqua, Inc. (TI) Holding company – 60.00 – 60.00 – 60.00

Cebu Private Power Corporation (CPPC) Power generation 60.00 – 60.00 – 60.00 –

Prism Energy, Inc. (PEI) * Retail electricity

supplier 60.00 – 60.00 – 60.00 –

Adventenergy, Inc. * Retail electricity supplier

100.00 – 100.00 – 100.00 –

1 HBI, TI, and PEI were incorporated in 2009. Hedcor Bokod, Inc., Hedcor Bukidnon, Inc., Hedcor Sabangan, Inc., Hedcor Tudaya, Inc., TCVI, TSMI, and Therma Subic were incorporated in 2011. 2 On March 23, 2010, the Philippine Securities and Exchange Commission (SEC) approved the change in corporate name of Philippine Hydropower Corporation to ARI. 3 On March 17, 2011, SEC approved the change in corporate name of Therma Pagbilao, Inc. to TSI. * No commercial operations as of December 31, 2011.

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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. 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.

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Summary of Significant Accounting Policies Business Combination and Goodwill Common control business combination Business combination of entities under common control is accounted for similar to pooling of interest method, which is scoped out of PFRS 3, Business Combination. Under the pooling of interest method, any excess of acquisition cost over the net asset value of the acquired entity is recorded in equity. Business combinations from January 1, 2010 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 pertaining to instruments that represent present ownership interests and entitle the holders to a proportionate share of the net assets in the event of liquidation either at fair value or at the proportionate share of the acquiree’s identifiable net assets. All other components of non-controlling interest are measured at fair value unless another measurement basis is required by PFRS. Acquisition-related costs incurred are expensed and included in administrative expenses. 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.

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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. 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.

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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. The functional currency of Luzon Hydro Corporation (LHC), a subsidiary, 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 balance sheet 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 statement 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).

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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 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).

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(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 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, 2011 and 2010.

(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, 2011 and 2010 include investments in unquoted shares of stock (see Note 33).

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(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 (see Note 33).

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. 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.

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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, 2011 and 2010, the Group has freestanding derivatives in the form of non-deliverable foreign currency forward contracts entered into to economically hedge its foreign exchange risk. In 2011 and 2010, the Group did not apply hedge accounting treatment on its derivative transactions. The Group has not bifurcated any embedded derivatives as of December 31, 2011 and 2010. 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.

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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 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 consolidated statement of income. 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.

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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. 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. The initial cost of property, plant and equipment comprises its purchase price, including import duties, if any, and nonrefundable taxes and any directly attributable costs of bringing the asset to its working condition and location for its intended use. 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.

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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 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 10-20 Power plant equipment 9-38 Transmission, distribution and substation equipment

Power transformers 30 Poles and wires 30 Other components 12

Transportation equipment 5 Office furniture, fixtures and equipment 2-5 Electrical equipment 5-20 Meters and laboratory equipment 12 Tools and others 2-10 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 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.

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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. 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.

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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. 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. 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.

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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 which consists of the cost of construction services and the fair value of future fixed fee payments in exchange for the license or right. 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 economic useful 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 economic useful life is ranging from 18 to 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. 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. During the period of development, the asset is tested for impairment annually.

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.

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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 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 balance sheet 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

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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 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. 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.

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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 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.

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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. 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.

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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. 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.

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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 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.

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 subsidiary and 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 subsidiaries and 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); MEZ’s Built-Operate-Transfer (BOT) agreement with Mactan Cebu International Airport Authority (MCIAA) and LHC’s Power Purchase Agreement (PPA) with the National Power Corporation (NPC). SEZ, MEZ and LHC’s service concession agreements were accounted for under the intangible asset model. The Company’s associate, STEAG, have also determined that the provisions of Philippine Interpretation IFRIC 12 apply to their PPA with NPC. STEAG’s service concession agreements were accounted for under the financial asset models. Refer to the accounting policy on service concession arrangements for the discussion of intangible asset and financial asset models

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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 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=2.16 billion and P=2.00 billion as of December 31, 2011 and 2010, 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, 2011 and 2010, the carrying value of the power plant amounted to P=42.33 billion and P=43.43 billion, respectively (see Notes 11 and 35). The carrying value of finance lease obligation amounted to P=52.71 billion and P=48.31 billion as of December 31, 2011 and 2010, 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.

Accounting for acquisitions of Power Barges (PB) In 2011 and 2010, the Group took ownership of Barge 1, Barge 2, Barge 3 and Barge 4, and PB 118 and PB 117, respectively. 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.

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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 acquisition 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. The application of the acquisition 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 2011, 2010 and 2009 based on management’s assessment. The carrying amounts of the investments in and advances to associates amounted to P=29.12 billion and P=28.80 billion as of December 31, 2011 and 2010, respectively. No allowance for impairment losses was recognized in 2011, 2010 and 2009 (see Note 9).

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, 2011 and 2010 amounted to P=996.0 million (see Note 10). No impairment of goodwill was recognized in 2011, 2010 and 2009. 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, 2011 and 2010, the net book values of property, plant and equipment amounted to P=78.71 billion and P=74.29 billion, respectively (see Note 11).

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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, 2011 and 2010, the aggregate net book values of property, plant and equipment amounted to P=78.71 billion and P=74.29 billion, respectively (see Note 11). 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, 2011 and 2010, the aggregate net book values of intangible asset - service concession rights amounted to P=4.16 billion and P=937.0 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 balance sheet 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, 2011 and 2010, the aggregate net book values of these assets amounted to P=87.94 billion and P=77.42 billion, respectively (see Notes 7, 11, 12 and 13). No impairment losses were recognized in 2011, 2010 and 2009. 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, 2011 and 2010, allowance for impairment of trade and other receivables amounted to P=314.6 million and P=376.9 million, respectively. Trade and other receivables, net of allowance for impairment, amounted to P=9.51 billion and P=6.81 billion as of December 31, 2011 and 2010, respectively (see Note 5).

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*SGVMC410781*

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. As of December 31, 2011 and 2010, allowance for inventory obsolescence amounted to P=1.6 million and P=53.1 million, respectively. The carrying amount of the inventories amounted to P=2.17 billion and P=1.85 billion as of December 31, 2011 and 2010, 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 Group recognize deferred taxes based on enacted or substantially enacted tax rates for renewable of 10% and for non-renewable of 30%. The Group has net deferred income tax assets amounting to P=226.9 million and P=199.8 million as of December 31, 2011 and 2010, respectively. The Company did not recognize deferred income tax assets on minimum corporate income tax (MCIT) amounting to P=30.9 million and P=23.8 million as of December 31, 2011 and 2010, respectively, and NOLCO amounting to P=220.5 million and P=114.8 million as of December 31, 2011 and 2010, 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 (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=75.4 million in 2011 and P=68.5 million in 2010. Retirement benefit income amounted to P=4.8 million in 2009. The Group’s pension liabilities amounted to P=27.0 million and P=16.0 million as of December 31, 2011 and 2010, respectively. Pension assets amounted to P=168.3 million and P=173.4 million as of December 31, 2011 and 2010, 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.

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*SGVMC410781*

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, 2011 and 2010.

4. Cash and Cash Equivalents

2011 2010 Cash on hand and in banks P=3,406,187 P=3,055,662 Short-term investments 19,985,374 15,246,183 P=23,391,561 P=18,301,845

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 investments rates. Interest income earned from cash and cash equivalents amounted to P=854.0 million in 2011, P=149.0 million in 2010 and P=348.9 million in 2009.

5. Trade and Other Receivables

2011 2010 Trade receivables - net of allowance for impairment

of P=314,629 in 2011 and P=376,912 in 2010 (see Note 32) P=6,266,348 P=5,897,292

Others (see Note 31) Dividends receivable 2,500,000 – Accrued revenue 262,048 192,194 Non-trade 45,744 139,155 Advances to various projects – 102,180 Advances to contractors – 9,509 Others 431,638 465,461 P=9,505,778 P=6,805,791

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, is presented below:

2011 2010 January 1 P=376,912 P=106,170 Provisions (reversal) (see Note 23) (32,349) 292,065 Write-off (29,934) (21,323) December 31 P=314,629 P=376,912

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*SGVMC410781*

Trade receivables of the power distribution segment that were written off but not covered by an allowance for impairment amounted to P=1.1 million (see Note 23) in 2009. Allowance for impairment as of December 31, 2011 and 2010 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.

For collective assessment, allowances are assessed for receivables that are not individually significant and for individually significant receivables where there is no objective evidence yet of individual impairment. Impairment losses are estimated by taking into consideration the age of the receivables, past collection experience and other factors that may affect collectibility.

6. Inventories - at cost

2011 2010 Fuel and lube oil P=1,606,367 P=1,325,290 Plant spare parts and supplies 362,722 349,029 Transmission and distribution supplies 196,174 150,220 Other parts and supplies 8,354 21,048 P=2,173,617 P=1,845,587

The cost of inventories recognized as part of cost of generated power in the consolidated statements of income amounted to P=10.99 billion in 2011, P=11.55 billion in 2010 and P=2.65 billion in 2009 (see Note 22). The cost of inventories recognized as part of operations and maintenance in the consolidated statements of income amounted to P=151.7 million in 2011, P=619.9 million in 2010 and P=222.3 million in 2009 (see Note 24).

7. Other Current Assets

2011 2010 Input value-added tax (VAT) P=750,561 P=680,139 Prepaid tax 211,339 171,218 Prepaid expenses 106,113 46,522 Prepaid rent (see Note 35) 23,436 27,581 Others 15,590 33,893 P=1,107,039 P=959,353

8. Business Combinations

a. Step-acquisition of LHC

LHC, a company primarily engaged in power generation, manages and operates the 70-megawatt hydroelectric power generating facility in Bakun River in Benguet and Ilocos Sur Provinces on a build-operate-transfer scheme. Under the Power Purchase Agreement (PPA) it entered into with the National Power Corporation (NPC), LHC shall deliver to NPC all electricity generated over a cooperation period of 25 years until February 5, 2026.

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LHC was 50% owned by ARI, a wholly owned subsidiary of the Company and 50% owned by Pacific Hydro Bakun, Inc. (PHBI), a wholly owned subsidiary of Pacific Hydro Pty Ltd, a company incorporated in Australia. On May 9, 2011, LHC redeemed all its issued and outstanding Series “B” Redeemable Preferred Shares and Series “C” Redeemable Preferred Shares held by PHBI. Immediately thereafter, the redeemed shares were permanently retired. As a result of the said redemption, LHC became a wholly owned subsidiary of ARI beginning May 9, 2011. The accounting for this business combination was determined provisionally as ARI is still finalizing the fair valuation of the intangible assets acquired. This will be finalized in 2012 as allowed by PFRS. The provisional fair values of the identifiable assets of LHC as at the date of acquisition follow:

Fair value recognized

on acquisition Assets: Cash and cash equivalents P=314,852 Receivables 29,501 Prepayments and other current assets 7,458 Property, plant, and equipment 2,238 Intangible asset - service concession right 3,376,973 Deferred tax assets 72,699 Other assets 37,574 3,841,295 Liabilities: Payables 178,434 Derivative liability 16,205 Advances from shareholders 1,794,859 Long-term debt (net of deferred financing cost) 716,971 2,706,469 Total identifiable net assets at fair value 1,134,826 Fair value of previously-held interest in LHC 942,977 Excess of fair value of identifiable net assets over

the fair value of previously-held interest P=191,849

Cash flow on acquisition: Net cash acquired with the subsidiary P=314,852 Remeasurement of the previously-held interest in LHC as at the date of acquisition follows: Carrying value of the previously held interest in LHC P=1,134,826 Fair value of previously-held interest in LHC (942,977) Loss on the remeasurement of previously held interest P=191,849

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*SGVMC410781*

The excess of the fair value of identifiable net assets over the fair value of previously-held interest is included in other income in the consolidated statement of income, net of the loss on the remeasurement of previously held interest. From the date of acquisition, the additional interest in LHC has contributed P=68.2 million to the net income of the Group. This newly-qualified subsidiary has likewise contributed P=633.0 million in revenue to the Group.

b. Acquisition of the 747 Megawatt (MW) Tiwi-MakBan Geothermal Power Plant (“Tiwi-MakBan Power Plant” or “Plant”)

In August 2008, APRI, a subsidiary, was officially declared as the winning bidder for the 289 MW Tiwi Geothermal Power Plant located in Tiwi, Albay and the 458 MW Makiling-Banahaw (MakBan) Geothermal Plant located in Laguna and Batangas Provinces. APRI took over the control and possession of the Plant on May 25, 2009, and started its commercial operation the following day. APRI accounted for the purchase of the Plant as acquisition of a business using purchase method. 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. 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. The accounting for the business combination that was effected in 2009 was determined provisionally as the Company has 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.

9. Investments in and Advances to Associates

2011 2010 Acquisition cost: Balance at beginning of the year P=19,148,952 P=18,914,669 Additions during the year 1,148,266 1,031,232 Step-acquisition to subsidiary (1,048,251) – Disposals during the year (27,749) (796,949) Balance at end of year 19,221,218 19,148,952 Accumulated equity in net earnings: Balance at beginning of the year 7,645,004 4,966,140 Share in net earnings 8,436,906 4,625,883 Effect of redemption of preferred shares

by an associate – (353,662)

(Forward)

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*SGVMC410781*

2011 2010 Step-acquisition to subsidiary (P=196,402) P=– Disposals during the year (5,639) – Cash dividends received or receivable (6,482,322) (1,593,357) Balance at end of year 9,397,547 7,645,004 28,618,765 26,793,956 Share in cumulative translation adjustments

of associates (546,753) 57,922 Share in unrealized valuation gain on AFS investment

of an associate 73,952 78,118 Investments in associates at equity 28,145,964 26,929,996 Advances to associates 975,729 1,869,374 P=29,121,693 P=28,799,370

As of December 31, 2011 and 2010, the undistributed earnings of the associates included in the Group’s retained earnings amounting to P=9.40 billion and P=7.65 billion, respectively, are not available for distribution to the stockholders unless declared by the associates. In 2011, the Company subscribed and paid for 242,631 common shares and 291,157 redeemable preferred shares of AEV Aviation including additional paid-in capital of P=290.9 million, representing 49.25% interest. The par value of the common and redeemable preferred shares is P=1 per share. The Group contributed P=856.2 million and P=1.03 billion as additional investment in MORE in 2011 and 2010, respectively, to support SNAP B’s plant rehabilitation and refurbishment. 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 Series A shares is attributable to the Company. In October 2010, EAUC redeemed 392,210 Series A RPS attributable to the Company. The Group’s associates and the corresponding equity ownership are as follows: Percentage of Ownership Nature of Business 2011 2010 2009

MORE Holding company 83.33 83.33 83.33

VECO Power distribution 55.21 55.19 55.18

LHC (see Note 8) Power generation – 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

Redondo Peninsula Energy, Inc. (RP Energy)* Power generation 25.00 50.00 50.00

SN Aboitiz Power-Magat, Inc. (SNAP M) Power generation 50.00 50.00 50.00

SN Aboitiz Power-Benguet, Inc. (SNAP B) Power generation 50.00 50.00 50.00

(Forward)

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*SGVMC410781*

Percentage of Ownership Nature of Business 2011 2010 2009

Hijos de F. Escaño, Inc. (HIJOS) Holding company 46.73 46.73 46.73

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

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

AEV Aviation, Inc. (AAI) Service 49.25 – –

**No commercial operations as of December 31, 2011. ** Declared pre-commercial operations on January 26, 2011 and started commercial operation on February 26, 2011. 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 83.33% 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 2011, 2010 and 2009 while the Group’s direct ownership in VECO is 43.46% in 2011, 43.44% in 2010 and 43.43% in 2009 resulting to the Group’s effective ownership in VECO of 55.21% in 2011, 55.19% in 2010, and 55.18% in 2009.

• 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. The carrying values of investments in associates, which are accounted for under the equity method follows:

2011 2010 MORE P=15,409,338 P=13,336,441 STEAG 5,943,448 6,445,009 CEDC 2,913,576 2,396,218 VECO 1,171,734 1,090,460 HIJOS 928,649 905,828

(Forward)

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2011 2010 WMPC P=493,857 P=465,002 PEVI 293,004 285,292 AAI 290,152 – SPPC 246,396 230,453 SFELAPCO 235,283 228,626 EAUC 229,486 335,563 LHC (see Note 8) – 1,181,164 Others (8,959) 29,940 P=28,145,964 P=26,929,996

Following is the summarized financial information of significant associates:

2011 2010 2009 MORE Total current assets P=3,233,366 P=234,714 P=278,313 Total noncurrent assets 18,515,998 16,013,675 12,037,113 Total current liabilities 3,252,121 241,362 276,057 Total noncurrent liabilities 6,594 3,298 490 Gross revenue 201,600 4,084,202 1,270,474 Operating profit 7,027,048 3,836,899 1,096,944 Depreciation and amortization 10,002 10,007 9,571 Interest income - net 430 377 325 Income tax - net 2,982 13,373 1,941 Net income 7,024,077 3,911,204 1,102,475 VECO* Total current assets 2,680,499 3,251,473 1,424,236 Total noncurrent assets 8,196,538 7,878,006 7,532,706 Total current liabilities 2,310,321 2,513,044 1,902,036 Total noncurrent liabilities 3,824,244 3,939,339 2,546,256 Gross revenue 16,296,842 13,405,730 10,830,879 Operating profit 740,532 609,522 140,657 Depreciation and amortization 434,750 424,777 433,387 Interest expense - net 46,743 29,945 15,101 Income tax - net 343,088 253,158 124,936 Net income 820,535 609,526 315,082 LHC (see Note 8) Total current assets N/A 382,808 332,448 Total noncurrent assets N/A 3,965,135 4,496,366 Total current liabilities N/A 1,468,097 1,593,142 Total noncurrent liabilities N/A 517,517 771,228 Gross revenue N/A 934,710 1,223,189 Operating profit N/A 581,919 749,635 Depreciation and amortization N/A 264,349 280,022 Interest expense - net N/A 66,992 123,999 Income tax expense (benefit) - net N/A 85,973 158,373 Net income N/A 339,521 467,264

(Forward)

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*SGVMC410781*

2011 2010 2009 WMPC Total current assets P=1,368,406 P=1,031,813 P=718,455 Total noncurrent assets 1,353,884 1,584,896 1,792,574 Total current liabilities 125,891 148,542 192,535 Total noncurrent liabilities 127,113 143,422 181,783 Gross revenue 1,352,280 1,324,460 1,206,970 Operating profit 701,144 769,956 558,505 Depreciation and amortization 365,311 309,802 468,476 Interest income (expense) - net 20,328 (6,597) 3,260 Income tax - net 168,799 201,779 55,171 Net income 819,405 851,962 548,359 SPPC Total current assets 725,741 580,253 491,448 Total noncurrent assets 883,448 999,546 1,305,583 Total current liabilities 108,054 120,986 105,383 Total noncurrent liabilities 269,157 302,659 427,259 Gross revenue 707,339 709,774 687,843 Operating profit 274,904 244,499 229,501 Depreciation and amortization 213,266 284,503 302,145 Interest income (expense) - net 1,360 9,865 (9,323) Income tax - net 76,485 45,226 46,312 Net income 248,809 227,719 248,749 SFELAPCO * Total current assets 799,680 669,949 454,647 Total noncurrent assets 2,055,184 1,103,853 1,064,917 Total current liabilities 614,313 466,986 406,246 Total noncurrent liabilities 593,237 334,181 349,027 Gross revenue 3,276,602 3,048,028 2,564,866 Operating profit 133,393 121,876 43,169 Depreciation and amortization 125,541 144,784 141,855 Interest income - net 165 1,574 1,175 Income tax - net 38,037 30,710 11,932 Net income 101,387 267,483 72,024 STEAG Total current assets 5,097,440 5,624,376 8,029,261 Total noncurrent assets 10,546,899 11,129,719 10,924,231 Total current liabilities 1,821,445 1,659,345 2,307,605 Total noncurrent liabilities 2,891,763 3,348,866 6,880,704 Gross revenue 7,548,941 6,507,354 6,205,924 Operating profit 4,089,380 3,131,010 3,118,338 Depreciation and amortization 65,536 70,881 79,064 Interest expense - net 111,434 366,944 473,298 Income tax - net 95,135 108,887 154,223 Net income 3,662,955 1,754,369 2,602,400 EAUC Total current assets 486,253 552,025 697,187 Total noncurrent assets 725,230 1,002,340 3,122,061 Total current liabilities 129,349 166,788 255,217 Total noncurrent liabilities 15,030 10,861 9,565 Gross revenue 992,763 1,741,244 1,381,633 Operating profit 265,798 283,349 186,597 Depreciation and amortization 102,211 118,857 120,619 Interest income (expense) - net 7,197 (727) 5,005 Income tax - net 12,477 16,337 11,570 Net income 271,488 252,754 286,577

(Forward)

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*SGVMC410781*

2011 2010 2009 CEDC Total current assets P=5,476,678 P=4,380,848 P=5,116,664 Total noncurrent assets 18,707,517 17,424,792 12,455,401 Total current liabilities 1,068,297 1,488,622 1,731,783 Total noncurrent liabilities 16,504,126 14,895,479 10,345,410 Gross revenue 7,511,443 – – Operating profit 2,565,171 (76,969) (41,307) Depreciation and amortization 640,773 15,157 4,689 Interest income (expense) - net 1,334,177 2,889 1,322 Income tax - net 32,427 (52,818) – Net income 1,200,223 (73,282) (48,915)

*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=262.3 million, P=245.7 million and P=216.9 million in 2011, 2010, and 2009, respectively, for VECO; and P=73.7 million, P=72.0 million and P=73.9 million in 2011, 2010 and 2009, respectively, for SFELAPCO. Under the same method, net income amounted to P=941.3 million, P=734.9 million and P=467.8 million in 2011, 2010 and 2009, respectively, for VECO; and P=140.1 million, P=132.7 million and P=119.6 million in 2011, 2010 and 2009, 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:

2011 2010 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, 2011 and 2010 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 9.39% to 11.63% in 2011 and from 8.22% to 8.39% in 2010, and cash flows beyond the five-year period are extrapolated using a zero percent growth rate.

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Revenue assumptions Revenue assumptions are based on the expected electricity to be sold. In 2011, revenue growth of 5% for four years and 2% in year 5 was applied to MEZ; 0% for BEZ; and 5% in year 1 and 0% for the next five years for HI. 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. Materials price inflation The assumption used to determine the value assigned to the materials price inflation is 4.75% in 2012. It then decreases to 4.50% in 2013 and remains steady until the fifth year. The starting point of 2012 is consistent with external information sources. Based on the impairment testing, no impairment was recognized on goodwill in 2011 and 2010. 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

December 31, 2011

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=114,336 P=951,281 P=73,370,137 P=4,998,903 P=459,746 P=159,951 P=204,563 P=1,642,611 P=383,765 P=375,433 P=1,552,872 P=84,213,598 Additions 494,790 13,665 2,802,729 428,639 81,211 43,923 3,830 156,108 89,011 455,649 2,892,843 7,462,398 Acquisition of a subsidiary – – – – 6,426 15,162 – – – – – 21,588 Disposals – – (16,215) – (10,973) (1,663) (106,755) – – (76) – (135,682) Reclassifications and others (1,100) 1,749,276 (1,854,787) (4,975) 7,286 44,892 1,115 136,850 – (140,350) (31,827) (93,620) Ending Balance 608,026 2,714,222 74,301,864 5,422,567 543,696 262,265 102,753 1,935,569 472,776 690,656 4,413,888 91,468,282 Accumulated Depreciation

and Amortization Beginning Balance – 116,050 5,791,480 2,523,933 299,357 147,935 142,804 406,154 259,245 234,876 – 9,921,834 Additions – 80,680 2,465,062 214,796 59,354 33,978 12,282 122,756 16,237 28,822 – 3,033,967 Acquisition of a subsidiary – – – – 3,801 14,508 – – – – – 18,309 Disposals – – (14,504) – (10,414) (930) (101,228) – – (76) – (127,152) Reclassifications and others – 885,444 (855,311) (50,844) 3,239 (39,857) (6,060) 84,898 (39) (108,264) – (86,794) Ending Balance – 1,082,174 7,386,727 2,687,885 355,337 155,634 47,798 613,808 275,443 155,358 – 12,760,164 Net Book Value P=608,026 P=1,632,048 P=66,915,137 P=2,734,682 P=188,359 P=106,631 P=54,955 P=1,321,761 P=197,333 P=535,298 P=4,413,888 P=78,708,118

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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Acquisition of Power Barges 1-4 On May 27, 2011, Therma Mobile acquired four barge-mounted floating power plants, with a total power generating capacity of 242 MW, from Duracom Mobile Power Corporation and East Asia Diesel Power Corporation. The power barges are currently undergoing rehabilitation. The amount of rehabilitation cost included in the carrying amount of the power barges amounted to P=443.8 million. 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=651.2 million) and US$16 million (P=739.5 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. On February 5, 2010 and February 26, 2010, Therma Marine fully paid PSALM the total bid prices of PB118 and PB117, respectively. Within the same month, Therma Mobile transferred all of its rights and obligations as buyer of PB 117 to Therma Marine, officially making the latter 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 these 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=5.44 billion and P=5.59 billion as of December 31, 2011 and 2010, respectively, are used to secure the Group’s long-term debts (see Note 16).

12. Intangible Asset - Service Concession Rights

2011 2010 Cost:

At January 1 P=1,149,439 P=1,045,054 Step acquisition of LHC (see Note 8) 3,376,973 – Additions from internal development 64,860 104,385 Effect of translation 89,417 –

4,680,689 1,149,439 Accumulated amortization:

At January 1 212,443 162,746 Step acquisition of LHC (see Note 8) 252,111 – Amortization 53,367 49,697

517,921 212,443 P=4,162,768 P=936,996

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The amortization of intangible asset is included in “Depreciation and amortization” under the Operating Expenses in the consolidated statement of income. Service concession arrangements entered into by the Group are as follows: a. On November 24, 1996, LHC entered into a PPA with NPC, its sole customer, for the

construction and operation of a 70-megawatt hydroelectric power generating facility (the Power Station) in Bakun River in Benguet and Ilocos Sur Provinces on a build-operate-transfer scheme. Under the PPA, LHC shall deliver to NPC all electricity generated over a cooperation period of 25 years until February 5, 2026. On the Transfer Date, as defined in the PPA, LHC shall transfer to NPC, free from any lien or encumbrance, all its rights, title and interest in and to the Power Station and all such data as operating manuals, operation summaries/transfer notes, design drawings and other information as may reasonably be required by NPC to enable it to operate the Power Station. Since NPC controls the ownership of any significant residual interest of the Power Station at the end of the PPA, the PPA is accounted for under the intangible asset model as LHC has the right to charge users for the public service under the service concession arrangement. The Power Station is treated as intangible assets and is amortized over a period of 25 years, which is the service concession period. The intangible asset was used as collateral to secure LHC’s long-term debt (see Note 16).

b. 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. The DMSA shall be effective for 25- year period commencing on 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 remittances may be reduced by the outstanding power receivables from SBMA, including streetlights power consumption and maintenance, for the immediate 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. Specific borrowing costs amounting to nil and P=19.1 million that were directly attributable to the rehabilitation of the PDS were capitalized in 2011 and 2010, respectively.

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c. 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

2011 2010 Advances to contractors P=2,353,605 P=– Input VAT and tax credit receivable 898,198 629,860 Prepaid rent - net of current portion (see Note 35) 421,510 522,817 Intangible assets: Project development costs 125,599 41,394 Software and licenses 9,359 22,400 Others 144,174 9,012 P=3,952,445 P=1,225,483

Advances to contractor pertains to payments covering the purchase price of two units of steam turbine generators of Therma South, Inc.

Intangible assets Rollforward of intangible assets follow: 2011 2010

Project development

costs Software

and licenses

Project development

costs

Software and

licenses Balance at beginning of year P=41,394 P=22,400 P=– P=1,153 Additions 86,599 5,423 75,154 21,247 Amortization – (6,337) – – Transfers (see Note 11) – – (33,040) – Write-off (2,394) (12,127) (720) – Balance at end of year P=125,599 P=9,359 P=41,394 P=22,400

14. Trade and Other Payables

2011 2010 Trade payables (see Note 21) P=2,950,149 P=2,063,082 Output VAT 1,568,934 1,609,331 Accrued energy fees and fuel purchase 755,226 486,644 Accrued taxes and fees 464,622 424,043 Accrued interest 323,795 220,048 Unearned revenues 299,056 42,423 Accrued materials and supplies cost 245,419 – Amounts due to contractors and other third parties 180,113 1,485,755 Accrued insurance 29,741 37,026 Related parties - nontrade (see Note 31) 18,415 129,999 Others (see Note 31) 286,284 455,479 P=7,121,754 P=6,953,830

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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 non-trade payables and other accrued expenses.

15. Bank Loans

Interest Rate 2011 2010 Peso loans - financial institutions - unsecured Company 2.24% in 2010 P=– P=1,290,000 DLP

4.25% in 2011; 3.50% in 2010

1,160,000 –

– 250,000

CLP 4.00% to 4.25% in 2011; 3.50% in 2010

283,200 –

– 220,000

SEZ 3.50% to 3.75% in 2010 – 196,600 HI 4.10% in 2011; 3.50% in 2010 171,400

– –

23,200 P=1,614,600 P=1,979,800

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. Interest expense on bank loans amounted to P=55.2 million in 2011, P=145.1 million in 2010 and P=236.9 million in 2009 (see Note 32).

16. Long-term Debts

Interest Rate 2011 2010 Company

Financial and non-financial institutions - unsecured 2011 5-year corporate note 6.17% P=5,000,000 P=– 2009 5-year corporate note 8.23% 5,000,000 5,000,000

2008 7-year corporate note 9.33% 543,200 548,800 2008 5-year corporate note 8.78% – 3,330,000

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% 3,306,947 3,570,000

CPPC 3.06% - 6.08% in 2011 Financial institutions - unsecured 6.68% - 6.71% in 2010 426,667 640,000

HI Financial institution - secured 8.36% 484,500 549,100 LHC Financial institutions - secured 2.44% to 2.50% 521,257 – SEZ Fixed rate corporate notes Financial institution – secured 3.68% in 2011;

8.26% in 2010 565,000

– –

119,090

BEZ Financial institution - unsecured 7.50% 70,000 70,000 18,917,571 16,826,990 Less deferred financing costs 112,589 123,877 18,804,982 16,703,113 Less current portion - net of deferred financing costs 1,504,800 555,495 P=17,300,182 P=16,147,618

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Company 2011 Fixed Rate Corporate Notes On April 14, 2011, the Company availed a total of P=5.00 billion from the Notes Facility Agreement it signed on April 12, 2011, with First Metro Investment Corporation (FMIC) as Issue Manager, the proceeds of which were used by the Company for general corporate purposes and refinancing. 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. 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 Debt-to-Equity (DE) ratio to exceed 2.5:1 calculated based on the Company’s year-end audited parent company financial statements. The Company is in compliance with the debt covenant as of December 31, 2011. Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=36.3 million as of December 31, 2011. 2009 Fixed Rate Corporate Notes On September 28, 2009, the Company availed a total of P=5.00 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 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. The Company is in compliance with the debt covenant as of December 31, 2011 and 2010. Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=29.9 million and P=39.2 million as of December 31, 2011 and 2010, respectively.

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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, FMIC 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. The Company is in compliance with the debt covenant as of December 31, 2011 and 2010. In December 2011, the P=3.33 billion 5-year corporate notes were redeemed incurring P=66.6 million in prepayment penalty charges. Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=4.5 million and P=32.5 million as of December 31, 2011 and 2010, respectively. 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.

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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 parent company financial statements. The Company is in compliance with the debt covenant as of December 31, 2011 and 2010. Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=15.9 million and P=24.4 million as of December 31, 2011 and 2010, respectively. 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. 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, with 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. 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. HSI is in compliance with the loan covenants as of December 31, 2011 and 2010. 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=5.04 billion and P=5.06 billion as of December 31, 2011 and 2010, respectively. Interest on the loan capitalized as construction in progress amounted to nil in 2011 and P=0.2 million in 2010 (see Note 11). Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=20.7 million and P=23.7 million as of December 31, 2011 and 2010, respectively. 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.

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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. CPPC is in compliance with the debt covenant as of December 31, 2011 and 2010. Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=1.6 million and P=3.6 million as of December 31, 2011 and 2010, respectively. 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 paid 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. Carrying value of machineries and improvements of the Benguet and Davao hydropower plants mortgaged with BDO to secure loans amounted to P=403.4 million and P=392.5 million as of December 31, 2011 and 2010, 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, 2011 and 2010.

LHC The debt represents the balance of the refinanced US dollar loan availed in November 21, 2006. Under the agreement LHC signed with local banks, the refinancing was accounted for as a simple extension of its old debt. The final maturity will be on October 31, 2014. Remaining principal payments are as follows: $4.51 million in 2012, $4.10 million in 2013 and $3.28 million in 2014. It bears interest at base rate (sum of LIBOR for the interest period) plus margin, payable and to be reviewed semi-annually in arrears calculated on the basis of a 360-day year and actual day elapsed. The loan is collateralized by certain assets of LHC (see Note 12). The Agreement provides for certain financial ratios and negative covenants with respect to, among others, indebtedness, investments, mergers, leases and abandonment. It also includes a provision allowing payments of dividends or return of any capital only under certain circumstances. The loan covenant also requires the maintenance of DE ratio of 70:30. LHC is in compliance with the debt covenants as of December 31, 2011 and 2010.

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Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=3.8 million as of December 31, 2011. SEZ a. On July 7, 2011, SEZ issued P=565.0 million worth of fixed rate notes outstanding anytime to

Metropolitan Bank and Trust Company (MBTC). The Note is priced at 100% of its face value, divided equally into ten equal notes of P=56.5M each maturing every year from issue date. The net proceeds will be used to refinance existing loans, capital expenditure, and general corporate purposes. Interest rate is based on Benchmark Rate plus a spread of four tenths of one percent (0.40%) per annum. If the Benchmark Rate plus spread of four tenths of one percent (0.40%) is lower than three and half percent (3.50%) then the latter shall be used. The loan covenant requires, among others, the maintenance of DE ratio of not more than 3:1. As of December 31, 2011, SEZ is in compliance with the debt covenant.

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. 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 provides, among others, for the maintenance of a minimum current ratio and a maximum DE ratio of 3.5:1. SEZ is in compliance with the debt covenant as of December 31, 2010.

Unamortized deferred financing cost reduced the carrying amount of long-term debt by P=0.5 million as of December 31, 2010. On March 24, 2011, the P=131.0 million term loan was pre-terminated. The Company paid pre-termination costs amounting to P=125.2 million including interest and gross receipts tax.

BEZ On June 28, 2010, BEZ availed of a P=70.0 million ten-year loan from MBTC 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%.

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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, 2011 and 2010.

17. Customers’ Deposits

2011 2010 Transformers P=984,557 P=854,669 Lines and poles 779,130 766,738 Bill and load 400,508 382,977 P=2,164,195 P=2,004,384

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. 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=2.0 million in 2011, P=3.8 million in 2010 and P=5.7 million in 2009 (see Note 32). The Group classified customers’ deposit under noncurrent assets due to the expected long-term nature of these deposits.

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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=17.3 million in 2011, P=19.8 million in 2010 and P=21.9 million in 2009 (see Note 32). Future minimum guaranteed dividend payments are as follows:

2011 2010 Due within one year P=31,070 P=31,070 More than one year but not more than five years 62,140 93,210 Future minimum guaranteed dividends 93,210 124,280 Less accrued interest expense 30,240 47,513 Future minimum guaranteed dividends - net 62,970 76,767 Less current portion 16,902 13,797 Noncurrent portion P=46,068 P=62,970

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19. Equity a. Capital Stock

2011 2010 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, 2011 and 2010. 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. On July 16, 2007, the Company listed with the PSE its common stock, wherein it offered 1,787,664,000 shares to the public at issue price of P=5.80 per share. The total proceeds from the issuance of new shares amounted to P=10.37 billion. The Company incurred transaction costs incidental to the IPO amounting to P=412.4 million, which is charged against “Additional paid-in capital” in the consolidated balance sheet. As of December 31, 2011, 2010 and 2009, the Company has 530, 483 and 498 shareholders, respectively.

b. Retained Earnings

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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On March 1, 2012, 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 16, 2012. The cash dividends are payable on April 3, 2012.

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, CLP and SEZ 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 for DLP, CLP and SEZ.

Details of the Performance-based Regulation (PBR) application for the first regulatory period are as follows:

CLP DLP SEZ First regulatory period April 1, 2009 to

March 31, 2013 July 1, 2010 to June 30, 2014

October 1, 2011 to September 30, 2015

Date of implementation of

approved distribution supply and metering charges

May 1, 2009 August 1, 2010 November 26, 2011

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

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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.

Total sale of power to WESM amounted to P=4.92 billion, P=14.94 billion and P=1.96 billion in 2011, 2010 and 2009, 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 and Energy Supply Agreement (PPA/PSA and ESA)

Certain subsidiaries have negotiated contracts with NPC, Private Distribution Utilities, Electric Cooperatives and Commercial and Industrial Consumers referred to as PPA, PSA or ESA. These contracts provide a tariff that allows these companies to charge for capacity fees, fixed operating fees and energy fees.

Total sale of power under power supply contracts amounted to P=35.02 billion in 2011, P=31.37 billion in 2010 and P=10.40 billion in 2009.

21. Purchased Power

Distribution

DLP, CLP, SEZ, and MEZ entered into contracts with NPC for the purchase of electricity. The material terms of the contract are as follows:

Term of Agreement

with NPC Contract Energy

(megawatt hours/year) DLP Ten years; expiring in December 2015 1,238,475 CLP Ten years; expiring in December 2015 116,906 MEZ Ten years; expiring in September 2015 114,680 SEZ Two-and-a-half years; expired in March 2011 139,154

The Group’s distribution utilities also entered into Transmission Service Agreements with NGCP for the transmission of electricity. Total power purchases from the NPC and NGCP, net of discounts, amounted to P=6.99 billion in 2011, P=6.61 billion in 2010 and P=7.12 billion in 2009. 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=584.5 million and P=468.1 million as of December 31, 2011 and 2010, respectively (see Note 14).

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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=2.01 billion in 2011, P=858.5 million in 2010 and P=32.5 million in 2009.

22. Cost of Generated Power

2011 2010 2009 Fuel costs P=10,990,762 P=11,551,522 P=2,645,484 Steam supply costs (see Note 36) 3,724,310 3,542,807 2,207,504 Energy fees 269,746 706,040 112,835 Wheeling expenses 52,846 28,126 6,098 Ancillary charges 44,339 53,831 51,545 Others – – 6,811 P=15,082,003 P=15,882,326 P=5,030,277

23. General and Administrative

2011 2010 2009 Personnel costs (see Note 25) P=647,975 P=517,814 P=369,216 Outside services (see Note 31) 389,289 287,975 469,439 Corporate social responsibility (CSR)

(see Note 38e) 320,236 40,634 130,249 Taxes and licenses 238,343 151,267 104,246 Transportation and travel (see Note 31) 135,847 92,862 77,051 Repairs and maintenance 85,567 53,843 92,805 Professional fees (see Note 31) 59,126 37,770 131,264 Market service and administrative fees

(see Note 31) 58,279 125,775 50,717 Information technology

and communication 54,143 36,614 91,466 Insurance 38,219 3,657 29,732 Training 35,225 8,939 8,038 Rent (see Note 35) 33,966 22,329 10,942 Provision for (reversal of ) impairment

and write-off of trade receivables (see Note 5) (32,349) 292,065 137,595

Advertisements 23,677 17,867 5,126 Research and development 12,772 4,682 28,175 Entertainment, amusement and recreation 8,083 5,598 4,846 Guard services 6,110 5,498 6,111 Gasoline and oil 1,912 1,219 2,172 Freight and handling 1,870 5,759 1,404 Others 141,541 274,659 151,834 P=2,259,831 P=1,986,826 P=1,902,428

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24. Operations and Maintenance

2011 2010 2009 Personnel costs (see Note 25) P=659,728 P=534,582 P=334,509 Repairs and maintenance 521,495 286,009 212,090 Taxes and licenses 276,032 377,356 295,730 Insurance 257,877 197,893 93,006 Outside services 207,741 69,483 120,448 Materials and supplies 133,470 226,808 174,701 Rent (see Note 35) 29,534 234 12,024 Fuel and lube oil 18,229 393,052 47,588 Transportation and travel 16,128 30,081 11,081 Others 97,813 322,430 35,810 P=2,218,047 P=2,437,928 P=1,336,987

25. Personnel Costs

2011 2010 2009 Salaries and wages P=977,669 P=856,063 P=553,695 Employee benefits (see Note 26) 330,034 196,333 150,030 P=1,307,703 P=1,052,396 P=703,725

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):

2011 2010 2009 Current service cost P=55,251 P=41,612 P=7,669 Interest cost on benefit obligation 45,706 41,099 32,787 Past service cost 290 287 230 Net actuarial loss (gain) recognized 9,490 10,006 (2,672) Expected return on plan assets (35,324) (24,524) (22,626) Net pension asset in excess of limit – – (20,180) P=75,413 P=68,480 (P=4,792)

Actual return on plan assets is P=30.8 million in 2011, P=49.5 million in 2010 and P=65.6 million in 2009. The Group expects to contribute P=45.9 million to their retirement fund in 2012.

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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. As of December 31, 2011, HSI, APRI, TLI, Therma Mobile, Therma Marine and TSI 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, 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. Pension assets

2011 2010 Fair value of plan assets P=577,141 P=491,467 Defined benefit obligation 753,837 528,041 Unfunded obligation (176,696) (36,574) Unrecognized past service cost 3,028 1,786 Unrecognized net actuarial losses 341,967 208,230 P=168,299 P=173,442

Pension liabilities

2011 2010 Defined benefit obligation P=59,923 P=18,134 Fair value of plan assets 6,145 – Unfunded obligation 53,778 18,134 Unrecognized net actuarial losses (26,813) (2,133) P=26,965 P=16,001

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

2011 2010 Opening defined benefit obligation P=546,175 P=427,489 Actuarial losses 164,554 56,159 Current service cost 55,251 41,612 Interest cost on benefit obligation 45,706 41,099 Benefits paid (9,557) (6,772) Increase from step-acquisition (see Note 8) 7,568 – Past service cost 1,531 – Fund transfers to (from) affiliates 2,529 (13,412) Closing defined benefit obligation P=813,757 P=546,175

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

2011 2010 Opening fair value of plan assets P=491,467 P=245,222 Contribution by employer 56,887 216,894 Actuarial gains 35,320 25,011 Expected return on plan assets (9,557) 24,524 Increase from step-acquisition (see Note 8) 7,294 – Benefits paid 2,529 (6,772) Fund transfer from affiliates (445) (13,412) Closing fair value of plan assets P=583,495 P=491,467

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The principal assumptions used in determining the pension obligations for the Group’s plans are shown below:

2011 2010 Discount rate 6.20% - 10.92% 7.80% - 10.92% Expected rate of return on assets 7.00% - 11.00% 7.00% - 10.00% Future salary increase 6.00 - 11.00% 6.00% - 8.00%

As of December 31, 2011, discount rates used has decreased to 5.99% to 7.02% with salary increase rates of 6.00% and expected rates of return on plan assets of 7.00%, 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: 2011 2010 2009 2008 2007 Defined benefit obligation P=813,757 P=546,175 P=427,489 P=124,107 P=191,777 Plan assets 583,495 491,467 245,222 205,052 228,609 Surplus (deficit) (230,262) (54,708) (182,267) 80,945 36,832 Experience adjustment on plan liability 63,728 49,759 23,911 (8,408) (7,143) Experience adjustment on pension asset 132 25,011 22,256 (16,123) (6,231)

The major categories of plan assets as a percentage of the fair value of the total plan assets are as follows:

2011 2010 2009 Commercial papers 79% 76% 67% Marketable securities 20% 22% 26% Others 1% 2% 7%

27. Other Income - net

2011 2010 2009 Recovery of payments to PSALM P=187,382 P=113,408 P=– Non-utility operating income 151,837 168,786 174,586 Surcharges 123,067 101,626 82,368 Net foreign exchange gains (losses) (see Note 32) (31,381) 1,142,158 348,815 Wheeling fees 15,358 50,751 51,957 Others 246,586 23,670 155,685 P=692,849 P=1,600,399 P=813,411

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28. Income Tax The provision for income tax account consists of:

2011 2010 2009 Current: Corporate income tax P=825,256 P=548,509 P=775,563 Final tax 164,608 43,276 64,659 989,864 591,785 840,222 Deferred 127,345 328,912 (209,032) P=1,117,209 P=920,697 P=631,190

Reconciliation between the statutory income tax rate and the Group’s effective income tax rates follows:

2011 2010 2009 Statutory income tax rate 30.00% 30.00% 30.00% Tax effects of:

Nondeductible interest expense 7.36 5.90 5.79 Nondeductible depreciation expense 1.43 1.26 1.28 Interest income subjected to final tax at

lower rates - net (0.34) (0.21) (0.71) Nontaxable share in net earnings of

associates (11.00) (5.34) (11.88) Income under income tax holiday (ITH) (22.39) (29.72) (9.99) Others (0.19) 1.65 (4.63) 4.87% 3.54% 9.86%

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:

2011 2010 Net deferred income tax assets: NOLCO P=118,862 P=141,619 Difference between the carrying amount of nonmonetary assets and the related tax base 61,039 – Allowances for impairment and probable losses 20,103 27,611 Unamortized past service cost 24,599 23,256 MCIT 15,184 16,417 Pension asset (13,484) (17,768) Unrealized foreign exchange losses (gains) (4,407) 5,455 Others 4,976 3,232 Net deferred income tax assets P=226,872 P=199,822

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2011 2010 Net deferred income tax liabilities: Unrealized foreign exchange gains P=399,888 P=319,631 Pension asset 28,920 28,684 Unamortized customs duties and taxes

capitalized 21,742 18,324 Unamortized streetlight donations capitalized 6,676 6,249 Capitalized interest expense 5,508 5,565 Allowances for doubtful accounts

and probable losses (40,215) (32,196) Unamortized past service cost (18,493) (21,127) Others (6,038) (4,009) Net deferred income tax liabilities P=397,988 P=321,121

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 38d). No deferred income tax assets were recognized on the Company’s NOLCO and MCIT amounting to P=220.5 million and P=30.9 million, respectively, as of December 31, 2011 and P=114.8 million and P=23.8 million respectively, as of December 31, 2010, 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 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:

2011 2010 2009 a. Net income attributable to equity

holders of the parent P=21,608,253 P=25,041,116 P=5,658,581 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=2.94 P=3.40 P=0.77

There are no dilutive potential common shares as of December 31, 2011, 2010 and 2009.

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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 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 40%, 31% and 30% of the power generation revenues of the Group in 2011, 2010 and 2009, respectively; while sale of power to VECO accounted for 17% of the power generation revenues of the Group in 2009.

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Financial information on the operations of the various business segments are summarized as follows: 2011

Power

Generation Power

Distribution

Parent Company/

Others Eliminations and

Adjustments Consolidated

REVENUE External P=39,944,982 P=14,356,619 P=174,036 P=– P=54,475,637 Inter-segment 1,554,273 – 354,273 (1,908,546) –

Total Revenue P=41,499,255 P=14,356,619 P=528,309 (P=1,908,546) P=54,475,637

Segment Results P=18,394,147 P=1,909,961 P=51,307 P=– P=20,355,415 Unallocated corporate income - net 332,596 362,764 (2,511) – 692,849

INCOME FROM OPERATIONS 18,726,743 2,272,725 48,796 – 21,048,264 Interest expense (5,901,765) (88,574) (1,355,236) – (7,345,575) Interest income 405,894 17,285 438,342 – 861,521 Share in net earnings of associates 7,854,369 583,785 22,579,435 (22,580,683) 8,436,906 Provision for income tax (431,708) (588,321) (97,180) – (1,117,209)

NET INCOME P=20,653,533 P=2,196,900 P=21,614,157 (P=22,580,683) P=21,883,907

OTHER INFORMATION Investments in Associates P=25,110,504 P=2,628,670 P=70,744,750 (P=70,337,960) P=28,145,964

Capital Expenditures P=6,607,335 P=906,701 P=13,222 P=– P=7,527,258

Segment Assets P=130,059,885 P=9,713,190 P=82,157,724 (P=68,402,860) P=153,527,939

Segment Liabilities P=66,446,087 P=6,029,352 P=13,701,168 (P=2,840,885) P=83,335,722

Depreciation and Amortization P=2,942,432 P=384,190 P=19,160 P=– P=3,345,782

2010

Power

Generation Power

Distribution

Parent Company/



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






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2009

Power

Generation Power

Distribution

Parent Company/



REVENUE External P=12,359,479 P=10,734,427 P=80,359 P=– P=23,174,265 Inter-segment 106,364 – 215,503 (321,867) –

Total Revenue P=12,465,843 P=10,734,427 P=295,862 (P=321,867) P=23,174,265

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






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. AEV provides human resources, internal audit, legal, treasury and corporate finance services,

among others, to the Group 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 amounted to P=424.8 million in 2011, P=293.7 million in 2010 and P=409.4 million in 2009, respectively (see Note 23).

b. 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=2.50 billion in 2011, P=1.70 billion in 2010 and P=1.80 billion in 2009.

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c. Energy fees billed by HI to SFELAPCO amounted to nil in 2011 and 2010 and P=19.6 million in 2009.

d. Energy fees billed by CPPC to VECO amounted to P=1.37 billion in 2011, P=2.04 billion in

2010 and P=2.10 billion in 2009.

e. The Group entered into replacement power contracts with SNAP M and SNAP B, associates. Energy fees billed by the Group to SNAP M amounted to P=61.2 million in 2011 and P=66.8 million in 2010. The Group also purchased energy from SNAP B amounting to P=41.2 million in 2011.

f. Energy fees billed by Therma Marine to Pilmico Foods Corporation (PFC) in 2011 amounted to P=29.8 million in 2011 and P=47.4 million in 2010. PFC is a subsidiary of AEV.

g. Energy fees billed by BEZC to affiliates (ACO subsidiaries and associates) amounted to

P=702.6 million in 2011, P=521.9 million in 2010 and P=287.7 million in 2009. BEZC also purchased energy from associates amounting to P=288.9 million in 2011.

h. Aviation services rendered by AAI, an associate, to the Group. Total expenses amounted to P=37.5 million in 2011, P=32.7 million in 2010 and P=24.8 million in 2009.

i. 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=57.3 million in 2011, P=69.4 million in 2010 and P=48.2 million in 2009. CPDC is a subsidiary of AEV.

j. The Company provides services to certain associates such as technical and legal assistance for various projects and other services. Total technical and service fee income from associates amounted to P=105.8 million in 2011, P=93.7 million in 2010 and P=2.2 million in 2009 (see Note 27).

k. Cash deposits with Union Bank of the Philippines (UBP) earn interest at prevailing market

rates (see Note 4). Total cash deposits of the Group amounted to P=7.61 billion in and P=4.87 billion as of December 31, 2011 and 2010, respectively. Total interest earned on deposits with UBP amounted to P=209.5 million in 2011 and P=125.9 million in 2010. UBP is an associate of AEV.

l. 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 1.50% to 6.50% in 2011, 1.80% to 8.25% in 2010 and 3.00% to 9.25% in 2009. Net interest expense incurred on these balances amounted to P=0.1 million in 2011 and P=1.5 million in 2010. Net interest income earned on these balances amounted to P=55.8 million in 2009 (see Note 32).

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Significant outstanding account balances with related parties (see Notes 5 and 14) as of December 31, 2011 and 2010 are as follows:

Amounts Owed by Related Parties Amounts Owed to Related Parties 2011 2010 2011 2010 Parent AEV P=– P=– P=– P=63,848 Associates VECO 141,642 133,906 – – CEDC 36,520 45,100 29,482 – RP Energy 17 15,782 – – SFELAPCO 38 84 – – Aboitiz Construction Group, Inc. (ACGI) – – 102,644 – EAUC – – 32,221 129,999 Other Related Parties Tsuneishi Heavy Industries, (Cebu)

Inc. (THICI) 59,423 49,681 – – PFC – 3,375 – – ACGI is a subsidiary of ACO. THICI is an associate of ACO. Compensation of BOD and key management personnel of the Group follows:

2011 2010 2009 Short-term benefits P=274,300 P=144,279 P=125,451 Post-employment benefits 15,675 6,634 3,832 P=289,975 P=150,913 P=129,283

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. 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). Risk Management Structure The BOD is mainly responsible for the overall risk management approach and for the approval of risk strategies and principles of the Group. Financial risk committee The Financial Risk Committee has the overall responsibility for the development of risk strategies, principles, frameworks, policies and limits. It establishes a forum of discussion of the Group’s approach to risk issues in order to make relevant decisions.

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Treasury service group The Treasury Service Group is responsible for the comprehensive monitoring, evaluating and analyzing of the Group’s risks in line with the policies and limits. The main risks arising from the Group’s financial instruments are 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. 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. 2.06% of the Group’s debt will mature in less than one year as of December 31, 2011 (2010: 2.49%). 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=23.39 billion and P=9.51 billion as of December 31, 2011 and P=18.30 billion and P=6.81 billion as of December 31, 2010, 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, 2011 and 2010 based on contractual undiscounted payments: December 31, 2011

Total carrying Contractual undiscounted payments value Total On demand <1 year 1 to 5 years > 5 years Trade and other payables P=4,770,728 P=4,770,728 P=81,460 P=4,689,268 P=– P=– Due to related parties 18,415 18,415 18,415 – – – Customers’ deposits 2,164,195 2,192,050 – 35,016 53,248 2,103,786 Bank loans 1,614,600 1,616,423 – 1,616,423 – – Payable to a preferred shareholder

of a subsidiary 62,970 93,210 – 31,070 62,140 – Finance lease obligation 52,714,959 110,292,493 – 2,534,784 38,142,989 69,614,720 Long-term obligation on power

distribution system 277,046 640,000 – 40,000 200,000 400,000 Long-term debts 18,804,982 29,311,121 – 2,846,647 18,732,933 7,731,541 Derivative liabilities 7,580 7,580 – 7,580 – – P=80,435,475 P=148,942,020 P=99,875 P=11,800,788 P=57,191,310 P=79,850,047

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December 31, 2010

Total carrying Contractual undiscounted payments value 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 – – P=74,230,095 P=147,651,903 P=1,256,918 P=9,023,612 P=45,822,123 P=91,549,250

Market Risk The risk of loss, immediate or over time, due to adverse fluctuations in the price or market value of instruments, products, and transactions in the Group’s overall portfolio (whether on or off-balance sheet) is market risk. These are influenced by foreign and domestic interest rates, foreign exchange rates and gross domestic product growth. 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, 2011, 5% of the Group’s long-term debt had floating interest rates ranging from 2.44% to 6.08%, and 95% have fixed rates ranging from 3.68% to 9.33%. 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%. 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:

As of December 31, 2011

<1 year 1-5 years >5 years Total Floating rate - long-term debt P=409,153 P=533,429 P=– P=942,582 Floating rate - payable to a preferred

shareholder of a subsidiary 16,902 46,068 – 62,970 Total P=426,055 P=579,497 P=– P=1,005,552 As of December 31, 2010

<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

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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).

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 2011 200 (P=18,852) (100) 9,426 December 2010 100 (P=6,364)

(50) 3,182

December 2009 100 P=– (50) –

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 2011 and 2010 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:

2011 2010 2009 Finance lease obligation (see Note 35) P=5,476,632 P=5,115,549 P=1,234,905 Bank loans and long-term debt (see Notes 15 and 16) 1,800,164 1,481,765 1,515,519 Long-term obligation on power distribution system (see Note 12) 34,487 35,099 35,644 Amounts owed to related parties

(see Note 31) 15,027 22,305 322 Payable to a preferred shareholder of subsidiary (see Note 18) 17,273 19,807 21,876 Customers’ deposits (see Note 17) 1,992 3,768 5,712 P=7,345,575 P=6,678,293 P=2,813,978

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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. Foreign currency denominated borrowings account for 37% of total consolidated borrowings, as of December 31, 2011 and 2010. Presented below are the Group’s foreign currency denominated financial assets and liabilities as of December 31, 2011 and 2010, translated to Philippine Peso: December 31, 2011 December 31, 2010

US Dollar Philippine Peso

equivalent1 US Dollar Philippine Peso

equivalent2 Loans and receivables:

Cash US$13,840 P=606,752 US$8,019 P=351,553 Trade and other receivables 356 15,604 963 42,218 Advances to associates 885 38,781 13,402 587,544 Total financial assets 15,081 661,137 22,384 981,315 Other financial liabilities:

Trade and other payables 8,048 352,827 5,682 249,099 11,890 521,257 – – Finance lease obligation 609,712 26,729,765 563,388 24,698,930

Total financial liabilities 629,650 27,603,849 569,070 24,948,029 Total net financial liabilities (US$614,569) (P=26,942,712) (US$546,686) (P=23,966,714) 1$1 = P=43.840 2$1 = P=43.840 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, 2011 and 2010:

Increase/ (decrease) in US DollarEffect on income

before tax December 31, 2011

US dollar denominated accounts US Dollar strengthens by 5% (P=1,347,136) US dollar denominated accounts US Dollar weakens by 5% 1,347,136

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

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 2011 and 2010 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.

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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 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. Concentration Risk Credit risk concentration of the Group’s receivables according to the customer category as of December 31, 2011 and 2010 is summarized in the following table:

2011 2010 Power distribution: Residential P=312,099 P=308,887 Commercial 126,467 164,468 Industrial 448,805 420,154 City street lighting 6,617 8,619 Power generation: Spot market 741,102 1,702,790 Power supply contracts 4,945,887 3,669,286 P=6,580,977 P=6,274,204

The above receivables were provided with allowance for doubtful accounts amounting to P=314.6 million in 2011 and P=376.9 million in 2010 (see Note 5). Maximum exposure to credit risk after collateral and other credit enhancements The maximum exposure of the Group’s financial instruments is equivalent to the carrying values as reflected in the consolidated balance sheet and related notes, except that the credit risk a associated with the receivables from customers is mitigated because some of these receivables have collaterals. Maximum exposure to credit risk for collateralized loans is shown below:

2011 2010

Carrying Value

Financial Effect of

Collateral in Mitigating

Credit Risk

Maximum Exposure to Credit Risk

Carrying Value

Financial Effect of

Collateral in Mitigating

Credit Risk

Maximum Exposure to Credit Risk

Trade receivables: Power distribution P=893,988 P=893,988 P=– P=902,128 P=902,128 P=–

Financial effect of collateral in mitigating credit risk is equivalent to the fair value of the collateral or the carrying value of the loan, whichever is lower.

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Credit Quality The credit quality per class of financial assets is as follows: December 31, 2011

Neither past due nor impaired Past due or individually

High Grade Standard Sub-standard impaired Total Cash and cash equivalents:

Cash on hand and in banks P=3,406,187 P=– P=– P=– P=3,406,187 Short-term investments 19,985,374 – – – 19,985,374

23,391,561 – – – 23,391,561 Trade receivables:

Residential 36,039 79,680 102,485 93,895 312,099 Commercial 18,607 52,806 25,598 29,456 126,467 Industrial 384,223 20,251 26,160 18,171 448,805 City street lighting 821 3,437 1,148 1,211 6,617 Spot market 45 170,971 – 570,086 741,102 Power supply contracts 3,432,521 – 290 1,513,076 4,945,887

3,872,256 327,145 155,681 2,225,895 6,580,977 Other receivables 3,054,581 51,378 258 133,213 3,239,430 AFS investments 3,744 – – – 3,744 Total P=30,322,142 P=378,523 P=155,939 P=2,359,108 P=33,215,712

December 31, 2010

Neither past due nor impaired Past due or

individually High Grade Standard Sub-standard 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 Other receivables 699,012 42,584 3,944 51,270 796,810 AFS investments 3,744 – – – 3,744 Derivative assets 7,670 – – – 7,670 Total P=22,363,831 P=873,605 P=201,966 P=1,944,871 P=25,384,273

High grade - pertain to receivables from customers with good favorable credit standing and have no history of default. Standard grade - pertain to those customers with history of sliding beyond the credit terms but pay a week after being past due. Sub-standard grade - pertain to those customers with payment habits that normally extend beyond the approved credit terms, and has high probability of being impaired.

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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 other receivables, AFS investment and derivative assets, the Group evaluates the counterparty’s external credit rating in establishing credit quality. The tables below show the Group’s aging analysis of financial assets: December 31, 2011

Neither past Past due but not impaired

Total due nor

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=3,406,187 P=3,406,187 P=– P=– P=– P=– Short-term investments 19,985,374 19,985,374 – – – –

23,391,561 23,391,561 – – – – Trade receivables:

Residential 312,099 218,204 47,920 10,274 20,395 15,306 Commercial 126,467 97,011 17,742 3,563 4,260 3,891 Industrial 448,805 430,634 11,026 2,916 3,321 908 City street lighting 6,617 5,406 1,065 122 21 3 Spot market 741,102 171,016 7,087 25,155 376,394 161,450 Power supply contracts 4,945,887 3,432,811 82,538 138,495 1,158,972 133,071

6,580,977 4,355,082 167,378 180,525 1,563,363 314,629 Other receivables 3,239,430 3,106,217 1,127 6,848 125,238 – AFS investments 3,744 3,744 – – – – Total P=33,215,712 P=30,856,604 P=168,505 P=187,373 P=1,688,601 P=314,629

December 31, 2010

Neither past Past due but not impaired

Total due nor

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 Other receivables 796,810 745,540 9,452 4,530 36,592 696 AFS investments 3,744 3,744 – – – – Derivative assets 7,670 7,670 – – – – Total P=25,384,273 P=23,439,402 P=465,013 P=345,473 P=757,473 P=376,912

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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 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, 2011 and 2010 are as follows:

2011 2010 Bank loans P=1,614,600 P=1,979,800 Long-term debt 71,582,911 65,084,996 Cash and cash equivalents (23,391,561) (18,301,845) Net debt (a) 49,805,950 48,762,951 Equity 70,192,217 57,734,210 Equity and net debt (b) P=119,998,167 P=106,497,161 Gearing ratio (a/b) 41.51% 45.79%

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, 2011 and 2010, 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, 2011 and 2010.

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.

2011 2010

Carrying Amounts

Fair Values

Carrying Amounts

Fair Values

FINANCIAL ASSETS Loans and Receivables Cash and cash equivalents:

Cash on hand and in banks P=3,406,187 P=3,406,187 P=3,055,662 P=3,055,662 Short-term investments 19,985,374 19,985,374 15,246,183 15,246,183

23,391,561 23,391,561 18,301,845 18,301,845

(Forward)

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2011 2010

Carrying Amounts

Fair Values

Carrying Amounts

Fair Values

Trade and other receivables: Trade P=6,266,348 P=6,266,348 P=5,897,988 P=5,897,988 Others 3,239,430 3,239,430 796,810 796,810

9,505,778 9,505,778 6,694,798 6,694,798 32,897,339 32,897,339 24,996,643 24,996,643 Financial Assets at FVPL Derivative assets – – 7,670 7,670 AFS Financial Assets 3,744 3,744 3,744 3,744 P=32,901,083 P=32,901,083 P=25,008,057 P=25,008,057

FINANCIAL LIABILITIES Other Financial Liabilities Bank loans P=1,614,600 P=1,614,600 P=1,979,800 P=1,979,800 Long-term debt: Floating - long-term debt 942,582 942,582 636,433 636,433 Fixed rate - long-term debt 17,862,400 19,467,789 16,066,680 17,953,303 Payable to a preferred shareholder of a subsidiary 62,970 62,970 76,767 76,767 Finance lease obligation 52,714,959 67,291,284 48,305,116 58,268,048 73,197,511 89,379,225 67,064,796 78,914,351 Customers’ deposits:

Bill deposits 400,508 400,508 382,977 382,977 Transformers, lines and poles 1,763,687 1,763,687 1,621,407 1,621,407

2,164,195 2,164,195 2,004,384 2,004,384 Long-term obligation on power

distribution system 277,046 419,789 282,559 413,057 Trade and other payables:

Trade payables 2,950,149 2,950,149 2,063,082 2,063,082 Accrued expenses 1,354,181 1,354,181 706,692 706,692 Related parties 18,415 18,415 129,999 129,999 Other liabilities 466,397 466,397 1,978,260 1,978,260

4,789,142 4,789,142 4,878,033 4,878,033 80,427,894 96,752,351 74,229,772 86,209,825 Financial Liability at FVPL Derivative liabilities 7,580 7,580 323 323 P=80,435,474 P=96,759,931 P=74,230,095 P=86,210,148 As of December 31, 2011 and December 31, 2010, 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.

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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. 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. 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 2.06% to 9.33% in 2011 and 6.81% to 9.33% in 2010. 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 5.83% to 8.37% in 2011 and 5.96% to 9.88% in 2010 for dollar payments and 3.13% to 7.72% in 2011 and 2.95% to 10.33% in 2010 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 1.98% to 6.14% in 2011 and 2.53% to 7.60% in 2010. 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.

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Derivative financial instruments 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. 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. As of December 31, 2011 and 2010, the Group has outstanding non-deliverable buy Dollar and sell Peso forward exchange contracts with counterparty banks with an aggregate notional amount of $0.3 million and $56.4 million, respectively and remaining maturities of less than1 month to 8 months and 1 month to 10 months, respectively. The forward rates related to the forward contracts ranged from P=43.84 to P=44.81 per US$ and P=43.84 to P=44.13 per US$1 as at December 31, 2011 and 2010, respectively. The Group recognized derivative asset relating to these contracts amounting to P=0.2 million and 5.4 million as of December 31, 2011 and 2010, respectively. As of December 31, 2011 and 2010, 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 €4.7 million and €2.24 million, respectively and remaining maturities of less than 1 month to 2 months and less than 1 month to 8 months, respectively. As at December 31, 2011 and 2010, the forward rates related to the forward contracts ranges from €1.2950 to €1.3385 per US$1 €1.3291 to €1.3421 per US$1, respectively. As of December 31, 2011, the Group recognized derivative liability relating to these contracts amounting to P=7.7 million. As of December 31, 2010, the Group recognized derivative asset and liability related to these contracts amounting to P=2.3 million and P=0.3 million, respectively. In 2011 and 2010, the Group did not apply hedge accounting treatment on its derivative transactions. The Group has not bifurcated any embedded derivatives as of December 31, 2011 and 2010. The movements in fair value changes of all derivative instruments for the year ended December 31, 2011 and 2010 are as follows:

2011 2010 At beginning of year P=7,347 (P=15,630) Net changes in fair value of derivatives not

designated as accounting hedges (19,797) (39,969) Fair value of settled instruments 4,870 62,946 At end of year (P=7,580) P=7,347

The loss from the net fair value changes relating to the forward contracts amounting to P=19.8 million in 2011 and P=40.0 million in 2010 are included under “Net foreign exchange gains (losses)” in Note 27.

Fair Value Hierarchy The Group 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

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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, respectively, are measured and carried at fair value. During the reporting periods ending December 31, 2011 and 2010, 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.

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 2011, 2010 and 2009 amounted to P=5.48 billion P=5.12 billion and P=1.23 billion, respectively (see Note 32).

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Future minimum monthly dollar and peso payments under the IPP Administration Agreement and their present values as of December 31, 2011 and 2010 are as follows:

Dollar

payments

Peso equivalent of dollar

payments1 Peso

payments 2011

Total Within one year $27,600 P=1,209,984 P=1,324,800 P=2,534,784 After one year but not more than five years 415,320 18,207,629 19,935,360 38,142,989 More than five years 758,000 33,230,720 36,384,000 69,614,720 Total contractual payments 1,200,920 52,648,333 57,644,160 110,292,493 Unamortized discount 591,208 25,918,569 31,658,965 57,577,534 Present value $609,712 P=26,729,764 P=25,985,195 P=52,714,959

Dollar

payments

Peso equivalent of dollar

payments2 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 1$1 = P=43.840 2$1 = P=43.840 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 2011 and 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):

2011 2010 Not later than one year P=9.4 P=9.0 Later than 1 year but not later than 5 years 45.7 40.0 Later than 5 years 142.7 119.2

Total lease charged to operations related to these contracts amounted to P=9.2 million in 2011, P=5.4 million in 2010 and P=2.5 million in 2009, respectively (see Note 24).

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36. Agreements Pagbilao IPP Administration Agreement

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. 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.

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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=3.72 billion in 2011, P=3.54 billion in 2010 and P=2.21 billion in 2009 (see Note 22).

b. TLI enters into short-term coal supply agreements. As of December 31, 2011, outstanding coal supply agreements have aggregate supply amounts of 410,000 MT (equivalent dollar value is $29 million) which were due for delivery from January 2012 to March 2012 . The coal supply agreements for the past three years had terms of payment 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, 2011 and 2010, TLI has complied with the minimum equity required. Therma Marine, Inc. 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. On January 24, 2011, ERC issued an order granting Therma Marine’s motion for reconsideration to allow an increase in rates higher than what was granted in October 4, 2010.

b. 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.

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c. 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.

d. 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 protection of health and environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws.

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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.

e. CSR Projects The Group has several CSR projects in 2011, 2010 and 2009 which are presented as part of “General and administrative expenses” (see Note 23).

SEC FORM 20 - IS (INFORMATION STATEMENT)

128 Aboitiz Power

INDEPENDENT AUDITORS’ REPORTON SUPPLEMENTARY SCHEDULES

The Stockholders and the Board of DirectorsAboitiz Power Corporation and SubsidiariesAboitiz Corporate CenterGov. Manuel A. Cuenco AvenueKasambagan, Cebu City

We have audited in accordance with Philippine Standards on Auditing, the consolidated financial statements of Aboitiz Power Corporation and its Subsidiaries as at December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011 included in this Form 17-A and have issued our report thereon dated March 1, 2012. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the Index to Financial Statements and Supplementary Schedules are the responsibility of the Company’s management. These schedules are presented for purposes of complying with the Securities Regulation Code Rule 68, as amended (2011) and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements, and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

SYCIP GORRES VELAYO & CO.

Ladislao Z. Avila, Jr.PartnerCPA Certificate No. 69099SEC Accreditation No. 0111-AR-2 (Group A), February 4, 2010, valid until February 3, 2013Tax Identification No. 109-247-891BIR Accreditation No. 08-001998-43-2009, June 1, 2009, valid until May 31, 2012PTR No. 3174866, January 2, 2012, Makati City

March 1, 2012

SyCip Gorres Velayo & Co.6760 Ayala Avenue1226 Makati CityPhilippines

Phone: (632) 891 0307Fax: (632) 819 0872www.sgv.com.ph

BOA/PRC Reg. No. 0001SEC Accreditation No. 0012-FR-2

Balance at Deductions

Beginning Amounts Amounts Ending

Name and Designation of Debtor of Period Additions Collected Written-Off Current Non-Current Balance

Davao Light & Power Co., Inc. 15,786P 258,171P (254,582)P P - 19,375P P - 19,375P

Therma Power, Inc. and Subsidiaries 21,085 14,417,222 (14,121,219) - 317,088 - 317,088

Cotabato Light & Power Company 1,259 15,056 (14,898) - 1,417 - 1,417

Aboitiz Renewables, Inc. and Subsidiaries 20,604 21,073,775 (21,017,779) - 76,600 - 76,600

Subic Enerzone Corporation 20 120 (120) - 20 - 20

58,754P 35,764,344P (35,408,598)P P - 414,500P P - 414,500P

ABOITIZ POWER CORPORATION AND SUBSIDIARIES

SCHEDULE C - AMOUNTS RECEIVABLE FROM RELATED PARTIES

AS OF DECEMBER 31, 2011

(Amounts in Thousands)

WHICH ARE ELIMINATED DURING THE CONSOLIDATION OF FINANCIAL STATEMENTS

- 2 -


SCHEDULE D - INTANGIBLE ASSETS - OTHER ASSETS


(Amount in Thousands)

Beginning D E D U C T I O N S Other Changes

Balance Additions Charged to Costs Charged to Additions Ending

Description At Cost and Expenses Other Accounts (Deductions) Balance

A. Intangibles

Goodwill 996,005P P - P - P - P - 996,005P

Service Concession Rights 936,996 3,441,833 (305,478) - 89,417 4,162,768

Project Development Costs 41,394 86,599 (2,394) - - 125,599

Software and Licenses 22,400 5,423 (6,337) - (12,127) 9,359

T o t a l 1,996,795P 3,533,855P (314,209)P P - 77,290P 5,293,731P

B. Other Noncurrent Assets

Restricted cash P - P - P - P - P - P -

Prepaid rent 522,817 - - - (101,307) 421,510

Deferred input vat and tax credit

receivable 629,860 268,338 - - - 898,198

Advances to contractors - - - - 2,353,605 2,353,605

Others 9,012 - - - 135,162 144,174

T o t a l 1,161,689P 268,338P P - P - 2,387,460P 3,817,487P

T o t a l P3,158,484 P3,802,193 (P314,209) P - P2,464,750 P9,111,218

- 3 -

Amount Amount Amount

Name of Issuer and Authorized Shown as Shown as

Type of Obligation by Indentures Current Long-Term Remarks

Parent Company:

2008 7-year corporate note 538,717P 5,600P 533,117P

2009 5-year corporate note 4,970,098 - 4,970,098

3-year bonds 704,505 704,505 -

5-year bonds 2,279,617 - 2,279,617

2011 5-year corporate note 4,963,740 4,963,740

Subsidiaries:

Hedcor, Inc. 484,500 64,600 419,900

Hedcor Sibulan, Inc. 3,286,223 263,053 3,023,170

Subic Enerzone Corporation 565,000 56,500 508,500

Cebu Private Power Corporation 425,102 213,333 211,769

Balamban Enerzone Corporation 70,000 4,375 65,625

Luzon Hydro Corporation 517,480 192,834 324,646

Total P18,804,982 P1,504,800 P17,300,182



SCHEDULE E - LONG-TERM DEBT


- 4 -

ABOITIZ POWER CORPORATION

SCHEDULE H - CAPITAL STOCK



Number of

Number of Shares Reserved Number of Shares Held By

Number of Shares Issued for Options, Warrants, Directors,

Title of Issue Shares and Conversions, and Affiliates Officers and Others

Authorized Outstanding Other Rights Employees

COMMON SHARES 16,000,000 7,358,604 - 5,781,157 85,318 1,492,129

PREFERRED SHARES 1,000,000 - - - - -

- 5 -

Trade Non-trade Total Sales Rental Advances Terms

Davao Light & Power Co., Inc. P - 19,375P 19,375P 214,393P P - P - 30 days

Therma Power, Inc. and Subsidiaries 295,285 21,803 317,088 414,710 - - 30 days

Cotabato Light & Power Company - 1,417 1,417 16,715 - - 30 days

Aboitiz Renewables, Inc. and Subsidiaries - 76,600 76,600 56,520 - - 30 days

Subic Enerzone Corporation - 20 20 120 - - 30 days

Balances Volume

Related Party


TRADE AND OTHER RECEIVABLES FROM RELATED PARTIES

WHICH ARE ELIMINATED DURING CONSOLIDATION OF FINANCIAL STATEMENTS



- 6 -

Trade Non-trade Total Sales Rental Advances Terms

AP (Parent) P - 119,215P 119,215P 327,547P P - P - 30 days

Aboitiz Renewables, Inc. and Subsidiaries 295,285 - 295,285 374,911 - - 30 days

Related Party

Balances Volume


TRADE AND OTHER PAYABLES FROM RELATED PARTIES

WHICH ARE ELIMINATED DURING CONSOLIDATION OF FINANCIAL STATEMENTS



- 7 -

- 8 -


Aboitiz Corporate Center

Gov. Manuel A. Cuenco Avenue

Cebu City

Reconciliation of Retained Earnings Available for Dividend Declaration

As of December 31, 2011

(Amount in Philippine Currency)

Unappropriated Retained Earnings, as adjusted to available

for dividend distribution, beginning

P=4,112,547,156

Add: Net income actually earned/realized during the

period

Net income during the period closed to Retained Earnings P=37,460,491,778

Less: Movement of deferred income tax assets (346)

Net income actually earned during the period 37,460,491,432

Less:

Dividend declaration during the period (9,713,357,685)

TOTAL RETAINED EARNINGS, END AVAILABLE

FOR DIVIDEND P=31,859,680,903


CONGLOMERATE MAPPINGAs of December 31, 2011

Legend:Ultimate Parent Company

Parent Company

Reporting Company

Co-Subsidiary

Subsidiary

Associate

76.40% 59.32% 100.0% 50.75% [direct]

ABOITIZ POWER CITYSAVINGS PILMICO FOODS 88.38% [beneficial]

CORPORATION BANK CORPORATION AEV AVIATION

INC.

62.50%

ABOITIZ JEBSEN 100.0%

99.93% 100.0% 60.00% 100.0% COMPANY, INC. CEBU PRAEDIA

DAVAO LIGHT & ABOITIZ CEBU PRIVATE ABOITIZ ENERGY (formerly Aboitiz DEVELOPMENT

POWER CO., INC. RENEWABLES, INC. POWER CORPORATION SOLUTIONS, INC. Jebsen Bulk CORPORATIONTransport Corp)

43.46% [direct] 50.00% 100.0%

55.21% [beneficial] EAST ASIA UTILITIES ADVENTENERGY, INC. 100.0%

VISAYAN ELECTRIC 100.0% CORPORATION 62.50% ARCHIPELAGO

CO., INC. AP RENEWABLES, INC. 60.00% ABOITIZ JEBSEN INSURANCE

34.00% PRISM ENERGY, INC. MANPOWER PTE LTD.

99.94% 100.0% STEAG STATE SOLUTIONS INC.

COTABATO LIGHT AND CLEANERGY, INC. POWER, INC.

POWER COMPANY

99.97% 20.00% 62.50%

100.0% HYDRO ELECTRIC SOUTHERN JEBSEN

COTABATO DEVELOPMENT CORP. PHILIPPINES MARITIME, INC.

ICE PLANT, INC. POWER CORP.

40.0% [direct]

20.29% [direct] 100.0% [beneficial] 20.00%

43.78% [beneficial] CORDILLERA HYDRO WESTERN MINDANAO

SAN FERNANDO CORPORATION POWER CORP.

ELECTRIC LIGHT &

POWER CO., INC. 100.0% 100.0%

LUZON HYDRO THERMA

99.97% CORPORATION POWER, INC.

SUBIC ENERZONE

CORPORATION 100.0%

HEDCOR, INC.

100.0% 100.0%

MACTAN ENERZONE 100.0% THERMA LUZON, INC.

CORPORATION HEDCOR

BENGUET, INC. 100.0%

100.0% THERMA SOUTH, INC.

BALAMBAN ENERZONE 100.0%

CORPORATION HEDCOR 100.0%

SIBULAN, INC. THERMA MARINE, INC.

100.0% 100.0%

HEDCOR THERMA MOBILE, INC.

TAMUGAN, INC.

100.0%

100.0% THERMA SUBIC, INC.

HEDCOR

TUDAYA, INC. 100.0%

THERMA POWER

100.0% VISAYAS, INC.

HEDCOR

SABANGAN, INC. 100.0%

THERMA SOUTHERN

100.0% MINDANAO, INC.

HEDCOR

BUKIDNON, INC. 100.0%

THERMA CENTRAL

100.0% VISAYAS, INC.

HEDCOR

BOKOD, INC. 100.0%

VESPER INDUSTRIAL

83.33% DEVELOPMENT CORP.

MANILA OSLO

RENEWABLE 25.00%

ENTERPRISE, INC. REDONDO PENINSULA

ENERGY, INC.

60.00% 60.00%

SNAP MAGAT, INC. TERAQUA, INC.

60.00% 60.00%

SNAP BENGUET, INC. ABOVANT

HOLDINGS, INC.

60.00%

SNAP PANGASINAN, INC. 44.00%

CEBU ENERGY

DEVELOPMENT CORP.

*AP has a 49.25% direct ownership in AEV Aviation, Inc.

ABOITIZ & CO., INC.

ABOITIZ EQUITY VENTURES, INC. [49.54%]

ELECTRICITY BANKING FOOD MANUFACTURING &

TRANSPORT

OTHERS

POWER DISTRIBUTION POWER GENERATION OTHERS

- 9 -


SCHEDULE OF RELEVANT FINANCIAL RATIOS

FORMULA DEC 2011 DEC 2010

LIQUIDITY RATIOS

Current ratio

Current assets

Current liabilities 3.46 2.58

Acid test ratio

Cash + Marketable Securities +

Accounts Receivable+ Other Liquid

Assets

Current liabilities 3.15 2.32

SOLVENCY RATIOS

Debt to equity ratio

Total liabilities

Total equity 1.19 1.33

Asset to equity ratio

Total assets


Net debt to equity ratio

Debt - cash & cash equivalents


Gearing ratio

Debt - cash & cash equivalents

Total equity + (Debt - cash & cash

equivalents) 41.51% 45.79%

Interest coverage ratio

EBIT

Interest expense 4.55 5.03

PROFITABILITY RATIOS

Operating Margin

Operating Profit

Total revenues 37.4% 44.0%

Return on Equity

Net income after tax

Total equity 43.18% 76.30%

- 10 -

Remarks

PFRS 1 First-time Adoption of Philippine Financial Reporting Standards Adopted

PFRS 2 Share-based Payment Not Applicable

PFRS 3 Business Combinations Adopted

PFRS 4 Insurance Contracts Not Applicable

PFRS 5 Non-current Assets Held for Sale and Discontinued Operations Adopted

PFRS 6 Exploration for and Evaluation of Mineral Resources Not Applicable

PFRS 7 Financial Instruments: Disclosures Adopted

PFRS 8 Operating Segments Adopted

PAS 1 Presentation of Financial Statements Adopted

PAS 2 Inventories Adopted

PAS 7 Statement of Cash Flows Adopted

PAS 8 Accounting Policies, Changes in Accounting Estimates and Errors Adopted

PAS 10 Events after the Reporting Period Adopted

PAS 11 Construction Contracts Not Applicable

PAS 12 Income Taxes Adopted

PAS 16 Property, Plant and Equipment Adopted

PAS 17 Leases Adopted

PAS 18 Revenue Adopted

PAS 19 Employee Benefits Adopted

PAS 20Accounting for Government Grants and Disclosure of

Government AssistanceNot Applicable

PAS 21 The Effects of Changes in Foreign Exchange Rates Adopted

PAS 23 Borrowing Costs Adopted

PAS 24 Related Party Disclosures Adopted

PAS 26 Accounting and Reporting by Retirement Benefit Plans Adopted

PAS 27 Consolidated and Separate Financial Statements Adopted

PAS 28 Investments in Associates Adopted

Aboitiz Power Corporation and Subsidiaries

Schedule of Philippine Financial Reporting Standards

Effective as of December 31, 2011

Standards and Interpretations

Philippine Financial Reporting Standards (PFRS)

Philippine Accounting Standards (PAS)

- 11 -

Remarks





PAS 29 Financial Reporting in Hyperinflationary Economies Not Applicable

PAS 31 Interests in Joint Ventures Not Applicable

PAS 32 Financial Instruments: Presentation Adopted

PAS 33 Earnings per Share Adopted

PAS 34 Interim Financial Reporting Adopted

PAS 36 Impairment of Assets Adopted

PAS 37 Provisions, Contingent Liabilities and Contingent Assets Adopted

PAS 38 Intangible Assets Adopted

PAS 39 Financial Instruments: Recognition and Measurement Adopted

PAS 40 Investment Property Adopted

PAS 41 Agriculture Not Applicable

IFRIC 1Changes in Existing Decommissioning, Restoration and

Similar LiabilitiesAdopted

IFRIC 2 Members' Share in Co-operative Entities and Similar Instruments Not Applicable

IFRIC 4 Determining Whether an Arrangement Contains a Lease Adopted

IFRIC 5Rights to Interests Arising from Decommissioning, Restoration

and Environmental Rehabilitation FundsNot Applicable

IFRIC 6Liabilities Arising from Participating in a Specific Market - Waste

Electrical and Electronic EquipmentNot Applicable

IFRIC 7Applying the Restatement Approach under PAS 29, Financial

Reporting in Hyperinflationary EconomiesNot Applicable

IFRIC 9 Reassessment of Embedded Derivatives Adopted

IFRIC 10 Interim Financial Reporting and Impairment Adopted

IFRIC 12 Service Concession Arrangements Adopted

IFRIC 13 Customer Loyalty Programmes Not Applicable

IFRIC 14PAS 19 - The Limit on a Defined Benefit Asset, Minimum

Funding Requirements and their InteractionAdopted

IFRIC 16 Hedges of a Net Investment in a Foreign Operation Not Applicable

IFRIC 17 Distributions of Non-cash Assets to Owners Adopted

IFRIC 18 Transfers of Assets from Customers Adopted

IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments Adopted

SIC 7 Introduction of the Euro Not Applicable

Philippine Interpretations - International Financial Reporting Interpretations Committee (IFRIC)

Philippine Interpretations - Standing Interpretations Committee (SIC)

- 12 -

Remarks





SIC 10Government Assistance - No Specific Relation to Operating

ActivitiesNot Applicable

SIC 12 Consolidation - Special Purpose Entities Not Applicable

SIC 13Jointly Controlled Entities - Non-Monetary Contributions

by VenturersNot Applicable

SIC 15 Operating Leases - Incentives Adopted

SIC 21 Income Taxes - Recovery of Revalued Non-Depreciable Assets Not Applicable

SIC 25Income Taxes - Changes in the Tax Status of an Entity or

its ShareholdersAdopted

SIC 27Evaluating the Substance of Transactions Involving the Legal

Form of a LeaseAdopted

SIC 29 Service Concession Arrangements: Disclosures Adopted

SIC 31 Revenue - Barter Transactions Involving Advertising Services Not Applicable

SIC 32 Intangible Assets - Web Site Costs Adopted

PIC Q&A

2006-01

PAS 18, Appendix, paragraph 9 - Revenue recognition for sales of

property units under pre-completion contractsNot Applicable

PIC Q&A

2006-02

PAS 27.10(d) - Clarification of criteria for exemption from presenting

consolidated financial statementsAdopted

PIC Q&A

2007-03

PAS 40.27 - Valuation of bank real and other properties acquired

(ROPA)Not Applicable

PIC Q&A

2007-04 PAS 101.7 - Application of criteria for a qualifying NPAENot Applicable

PIC Q&A

2008-02

PAS 20.43 - Accounting for government loans with low interest rates

under the amendments to PAS 20Not Applicable

PIC Q&A

2009-01

Framework, paragraph 23 and PAS 1.23 - Financial statements prepared

on a basis other than going concernAdopted

PIC Q&A

2010-01

PAS 39.AG71-72 – Rate used in determining the fair value of

government securitiesAdopted

PIC Q&A

2010-02 PAS 1R.16 – Basis of preparation of financial statementsAdopted

PIC Q&A

2008-01

(Revised)

PAS 19.78 – Rate used in discounting post-employment benefit

obligations

Adopted

PIC Q&A

2011-0 PAS 1 – Requirements for a Third Statement of Financial PositionAdopted

Philippine Interpretations - Questions and Answers (Q&As)

- 13 -

Documents

AP SEC FORM 17-A (Annual Report 2011) CLEAN COPYdisclosures.aboitizpower.com/20120417054940.pdf · In December 1978, ACO divested its ownership interests in the Ormoc Electric Light