2011-perc-annual-report

W I N D

G E OT HE RM A L

P E T R O L EU M

2011 Annual Report

Table of C ontents

05 19 22 23 25 31 92 93 94

Message from the Chairman and the President Financial Highlights Statement of Management’s Responsibility for Financial Statements Independent Auditors’ Report Financial Reports Notes to Financial Statements Board of Directors Officers Corporate Directory

ABOUT THE COVER 2

PETROENERGY

T

hree ventures comprise PetroEnergy’s core operations. Each venture taps an energy endowment in different realms of the earth – beneath the seas for petroleum, beneath the land for geothermal, and the atmosphere for wind. That our petroleum operation is at the base signifies that our expansion into renewable energy is founded on the profits and lessons gained from our Gabon and Philippine oil business. Efficient and responsible development of these energy sources will propel our Company and our Country to greater heights of growth and success.

2011 ANNUAL REPORT

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4

PETROENERGY

Message from the Chairman and the President

DEAR FELLOW STOCKHOLDERS,

I

n a year marked by continuing economic turmoil and social unrest in many parts of the world, sluggish growth at home, and volatile foreign exchange prices, our Company performed well in 2011. Underlying this healthy turnout is high world crude oil price during the year, averaging above US$ 100 per barrel.

Our Gabon operations reached a significant milestone in 2011, producing a cumulative 65 Million barrels of oil since the start of commercial crude production in 2002.

Total oil production for the year reached 8.06 Million barrels, a 10% increase over our 2010 level of 7.33 Million barrels. Due to average oil selling price of US$ 111.31 per barrel, total oil revenue for 2011 from the Gabon (Etame) concession reached US$ 13.54 Million, the highest in the Company’s history.

Our net income for the year amounted to US$ 3.67 Million compared to last year’s US$ 3.50 Million. The slight improvement in our net income, despite record revenues, stemmed from lower cost recovery rates, higher royalty payment to the Gabonese government, and higher provision for income tax this year relative to 2010. The Company enjoyed a significant reduction in taxes in 2010 because of net foreign exchange losses incurred last year. Our earnings per share in 2011 of US$ 0.013 were little changed from the previous year’s US$ 0.017 and our book value per share inched down from US$ 0.187 in 2010 to US$ 0.149 in 2011, due to the impact of the 1:1 stock rights offering in July 2010.

Our renewable energy (RE) projects under development also achieved significant milestones. The 20 MW Maibarara geothermal power project in Sto Tomas, Batangas was declared by the Department of Energy (DOE) as “commercial” making it the first RE service contract to achieve commerciality under the 2008 RE Law. On the other hand, the technical viability of a 50 MW wind farm in our Nabas-Malay service contract

in Aklan was confirmed by initial studies of the Danish engineering firm, COWI A/S. The Company’s good governance was rewarded with a Silver Award in Corporate Governance by the Institute of Corporate Directors, the first time the Company has been so honored. Unfortunately, this outstanding year for PetroEnergy was marred by the untimely demise of our beloved Chairman, Rizalino S. Navarro.

Oil Revenue US$ MILLION

15.00 13.54 10.00

10.78 8.68

5.00

0 2009

Net Income US$ MILLION

2010

2011

4 3.50

3

3.67

2 1

1.72

0 2009

2010

2011

2011 ANNUAL REPORT

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Ebouri Oil Field (Gamba)

Etame Oil Field (Gamba)

GABON OPERATIONS

T

he Gabon-Etame concession has surpassed expectations by producing 65 Million barrels of oil cumulative up to 2011, far more than the estimated reserves at the beginning of production in 2002. Our daily production of 21,000-22,000 barrels of oil per day combined with fewer production downtimes and higher oil prices led the Consortium to post record revenues for the year. But 2011 was not just a banner year in terms of oil production. The Etame joint venture partners also devoted significant resources and time to several efforts aimed at enhancing long-term production and profitability.

SE Etame Discovery (Gamba)

North Tchibala Discovery (Dentale)

Avouma Oil Field (Gamba) South Tchibala

Etame Expansion Project (EEP) The EEP is an on-going effort led by the block Operator – VAALCO Energy, Inc. – to evaluate the possibility of increasing production up to 30,000 barrels per day.

Tapping both internal Consortium technical resources and external third-party Consultants, the EEP comprises four separate but related investigations: 1) Subsurface simulation study to determine remaining recoverable reserves in low, mid, and high cases, 2) Drilling and completion review to ascertain drilling costs, duration, and design modifications for future well drilling and completion, 3) Facilities evaluation of thirteen potential development options that led to the identification of six hybrid development concepts, and 4) Commercial and economic modeling of the six development concepts to assess execution duration, risks, and profitability.

In 2011, the EEP team recommended two options to be carried further into the pre-front end engineering design (Pre-FEED) stage. These are the “Etame Production Platform” option and the “Nautipa” option. The former will entail the construction of a full production platform in the central Etame producing field. The other, more preferred, scheme will continue to utilize the current floating production, storage and offloading (FPSO) vessel Petroleo Nautipa throughout the field life combined with a new wellhead platform in Etame. Both cases are now the subject of pre-FEED analysis.

Avouma and Ebouri Platform Upgrades In anticipation of additional drilling and higher crude extraction, several rehabilitation and construction works were implemented in the two production platforms the Consortium operates in the Avouma and Ebouri producing fields. Both platforms’ decks were extended and the Avouma living quarters expanded to accommodate more equipment and personnel.

Etame Marin Permit Area

Production Field Shallow water exploration leads Deep water leads

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PETROENERGY

Additional slot for a fourth well were installed in both platforms. The electrical systems in both platforms were likewise upgraded to better support the electrical submersible pumps in the platform wells. Lastly, a major and on-going work in the Avouma platform is the addition of a water knock-out facility for enhanced water removal of Avouma wells fluid output and thus increase the amount of produced crude piped onto the FPSO. All these repairs and refurbishments were done without any significant production downtime.

FPSO Integrity Assessment The Petroleo Nautipa is a FPSO vessel that the Etame Consortium leases from the owner Tinworth Pte Ltd. On site for nearly 10 years now, the vessel has a ship design capacity of about 1.1 Million barrels of oil and an operational handling capacity of 30,000 barrels of total fluids per day. Given the Consortium’s plan of higher and longer crude production, a study was started in 2011 to determine whether it is technically possible and economically viable to continue using the Petroleo Nautipa until 2022. Results of the study contracted to Bennett and Associates and to Alliance Marine Services will be completed in 2012.

Shallow Water Exploration Project (SWEP) Current production in our Gabon concession is limited to known fields lying at the center of the permit area in about 80 m of water. The goal of SWEP is to identify petroleum prospects for future drilling in the northern and northeastern parts of the concession close to the shore where water depths are 30m or less.

The SWEP kicked off in 2011 with the interpretation of existing 3D seismic data acquired in 1997. Geological analyses were also performed on boreholes within the Etame permit block and from wells in adjoining blocks via data trade with other Operators. The Partners then carried out a new 3D seismic data acquisition from late October to mid November, 2011 over a 240 sq. km area. The newly acquired 3D data are currently being processed for interpretation work from late 2012 to early 2013.

2012 Drilling Program

Libreville

GABON

Port Gentil

Due to the tight availability of offshore drilling rigs worldwide and conflict with on-going construction works in the Ebouri and Avouma platforms, the 2011 drilling program had to be moved to 2012. A drilling rig has been engaged by the Partners and is set for mobilization to the site by late June 2012. The drilling campaign will start in Ebouri, where two wells, including a pilot hole, will be drilled. In Avouma, the rig will drill a development well followed by a work-over of an existing well. Once these firm well commitments are completed by around December 2012, the JV Partners may extend the rig on site to drill two option wells – an appraisal well in the North Tchibala area and an exploration target in Southeast Etame.

2011 ANNUAL REPORT

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PetroEnergy’s Petroleum Service Contracts 120° E

122° E

14° N

W E ST PH I L I PPI N E S E A

124° E

126° E

128° E 14° N

L U Z O N

MINDORO

PH I L I PPI N E S E A

SC 6A OCTON

SAMAR

12° N

12° N

SC 14C2 WEST LINAPACAN SC 47 OFFSHORE MINDORO

PA N AY

CEBU

N

SC 51 EASTERN VISAYAN BASIN

A

10° N

LEYTE

P

A

L

A

W

NEGROS

10° N

BOHOL

SULU SEA

MINDANAO

8° N

8° N 120° E

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PETROENERGY

122° E

124° E

126° E

128° E

PHILIPPINE OIL PROJECTS

O

ur Philippine petroleum service contracts saw several developments during the year with mixed results. Much of the activities in these blocks were farm-out efforts by the respective Operators to obtain financing for eventual exploration or production drilling. But in one block actual drilling took place with disappointing outcome.

Service Contract 6A – Octon, Northwest Palawan Following the departure of Vitol GPC from the SC6A Consortium in late 2010, Pitkin Petroleum Plc, a UKregistered company, signed in July 2011 a farm-in agreement with the consortium members for a 70% participating interest in the block. As farminee, Pitkin committed to spend, at its own cost, about US$ 5 Million to acquire, process, and interpret 500 sq. km of 3D seismic data in Octon. Should it elect to exercise its options, Pitkin may drill up to two production wells at no cost to the farming-out consortium members.

On December 6, 2011, the DOE approved the Deed of Assignment transferring the Operatorship and 70% of the service contract interest to Pitkin. Consequently, PetroEnergy’s interest in the block was reduced from 16.67% to 5.001% but our Company will be carried free in all subsequent exploration costs up to the drilling of two Octon wells.

Service Contract 14C2 – West Linapacan, Northwest Palawan Earlier plans by Operator Pitkin Petroleum Plc to drill West Linapacan by 2011 failed to materialize due to unresolved technical questions on the reservoir character of the field. Instead, Pitkin farmed-out half of its 58.29% interest in SC14C2 to RMA (HK) Ltd., a subsidiary of Resource Management Associates Pty Ltd of Australia. The Deed of Assignment for this farm-out filed on April 13, 2011 was subsequently approved by the DOE on July 4, 2011. The farm-out has no effect on PetroEnergy’s 1.03% interest and status as free-carried up to the drilling of one well.

to-reservoir migration study. PNOC-EC repeated the extension request in August, 2011 but no official DOE response had been received by the end of 2011. In the meantime, PNOC-EC is completing the reservoir study, preparing the program for the additional 500 km 2D seismic survey, and discussing farm-in opportunities with potential investors.

Service Contract 51 – East Visayan Basin As a DOE commitment for the Consortium’s Sub-Phase 3 (SP3) work program, the on-shore vertical exploratory well Duhat-1 was spudded in San Isidro, northwest Leyte on April 20, 2011 to test the hydrocarbon potential of our service contract’s northern block. After it was sidetracked, the well (Duhat-1A) reached a total depth of 321 m but had to be abandoned on May 25 after persistent mechanical drilling problems. Although the well failed short of reaching its 1,000 m programmed total depth, the Operator/Farminee NorAsian Energy Ltd (NAEL) obtained DOE approval to consider Duhat-1A as satisfying the Consortium’s SP3 work commitment.

However, this well will not be considered as an “earning” well by the farmors– Alcorn Gold, Trans-Asia Oil, and PetroEnergy.

Service Contract 47 – Offshore Mindoro and Panay

NAEL’s application on February 3, 2011 with the DOE for the approval of Perth-based SWAN Oil and Gas Ltd farmin for 40% participating interest in SC51 was approved by the DOE on July 1, 2011. On August 31, 2011, the DOE also approved the consortium’s entry into Sub-Phase 4 (Aug. 1, 2011 to July 31, 2012) with a revised work commitment of acquiring and interpreting 100 line-km of 2D seismic data in northwest Leyte at a budget of US$ 3.0 Million. In November, 2011, NAEL completed the scouting survey for this planned 2D seismic study.

It subsequently engaged BGP SE Asia to conduct the 2D seismic survey at a slightly expanded budget of US$ 4.3 Million. Seismic acquisition and interpretation are expected to be completed by the first quarter of 2012.

The DOE approved a one-year extension of the Consortium’s Sub-Phase 2 (SP2) work program deadline to July 10, 2011. This would enable the Operator, PNOC Exploration Corporation (PNOC-EC), to finish the evaluation of 2D seismic data acquired by the Partners in 2010. PNOC-EC’s evaluation identified at least six potential leads, most of which were in deep water. To further de-risk these leads and enable the Partners to attract potential farminees, PNOC-EC requested the DOE on June 21, 2011 for a further one-year extension of SP2 to carry out a 500-km 2D seismic survey and a source-

In December 2011, the SC51 partners reached an internal agreement to revise the farm-in terms to: 1) divide the SC51 contract area into a northern (northwest Leyte) and southern (offshore Cebu) blocks, 2) the assignment of NAEL’s putative 40% interest in the south block to Swan thus relinquishing all its interest in offshore Cebu, 3) the drilling of a second on-shore well in northwest Leyte to complete NAEL’s farm-in, and 4) a deadline of April 30, 2012 for SWAN to commit to the drilling of the offshore Argao prospect in Cebu, or forfeit all its interests and rights in SC 51.

Contingent on the results of a comprehensive reservoir simulation study to be undertaken in early 2012, a well may be drilled by end of 2012.

2011 ANNUAL REPORT

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PETROENERGY

RENEWABLE ENERGY PROJECTS Maibarara Geothermal Power Project

T

he confirmation of commerciality for our Maibarara project by the DOE on November 11, 2011 capped a productive and impressive year for Maibarara Geothermal Inc. (MGI), the joint-venture company we formed with partners Trans-Asia Oil and PNOC Renewables Corporation. Over an 11-month period, MGI completed rig mobilization, work-over drilling, well discharge testing, reserves confirmation, and initiated civil works in the steamfield and power plant sites; agreements or contracts for carbon credit sale, transmission grid connection, electricity sales, engineering, procurement and construction (EPC) as well as operations and maintenance (O&M) for the 20 MW power plant, multi-stakeholder environmental monitoring, local government permits, and project loan financing were also signed and secured

Mobilization of DESCO Rig 30 in Maibarara which started in December, 2010 was completed by January 11, 2011 when we commenced the work-over drilling of existing wells Mai-6D, Mai-9D, and Mai-11D in pad A. The discharge flow-testing of production wells Mai6D and Mai-9D and capacity testing of reinjection well Mai-11D followed from early March to late May, 2011.

These tests confirmed an aggregate output of 15 MW from the two production wells and sufficient injection capacity for Mai-11D to handle separated brine. The ensuing resource assessment, reserves estimation, and conceptual engineering design report prepared

by MGI staff were validated by Sinclair Knight Merz (SKM), a well-regarded and experienced New Zealand geothermal engineering consulting outfit. In its August 2011 third-party review, SKM validated the project development scheme of MGI and confirmed that the site has sufficient proven geothermal reserves to sustain a 20 MW power plant for 25 years.

During the period of operations for work-over drilling, flow-testing and resource assessment, MGI in parallel negotiated, secured, and signed several key agreements critical in the commercial development and eventual operation of the project. Among these were: 1) an emissions reduction purchase agreement, in January 2011 with the Spanish firm Endesa Carbono for the carbon credits to be generated by the project under the UN Clean Development Mechanism, 2) the transmission service and connection agreements in August, 2011 with the National Grid Corporation of the Philippines

(NGCP) following the latter’s release of the grid impact study for Maibarara in March, 2011, and 3) electricity sales agreement (ESA) in September, 2011 with wholesale aggregator Trans-Asia Oil. The SKM third-party validation of the size and commercial nature of the Maibarara geothermal reserves triggered the signing by MGI of the 20 MW power plant EPC contract with EEI Corp. and the O&M contract with Fuji Electric, both on September 2, 2011. MGI then started the initial civil works for the power plant site in the first week of September. Shortly thereafter, MGI secured a P2.4 Billion project loan facility to fund the construction of the power plant and related transmission facilities with lenders Rizal Commercial Banking Corp.

(RCBC) and Bank of the Philippine Islands (BPI) on September 26, 2011.

The Maibarara project is intended to deliver clean, indigenous and renewable geothermal power to the Luzon grid by late 2013. For 2012, MGI has set four major goals: 1) completion of the necessary steam supply and injection capacities by drilling two new wells, 2) expedite the construction of the power plant and the steamfield pipeline system, 3) secure the right-of-way and start the construction of the transmission facilities, and 4) develop and fortify our relationship with the host community by implementing an acceptable, feasible, and sustainable social assistance program.

2011 ANNUAL REPORT

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MILESTONES

January to February 2011 December 2010 February 2010

Award by DOE of Maibarara Service Contract to PERC.

Construction of pad A deep cellar to maximize space for future facilities.

Work-over drilling of three wells

December 2011

Power plant site development & contractor mobilization

September 2011

Signing of EPC contract with EEI Corp. and O&M contract with Fuji Electric

September 2011

Perspective on completion in 2013

Signing of P2.4 Billion loan facility with RCBC/BPI March 2011

Successful discharge of wells Mai-6D and Mai-9D.

20 MW Maibarara Geothermal Power Project

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PETROENERGY

Nabas and Sual Wind Power Projects

F

ollowing one year of wind data recording in our Nabas (Aklan) and Sual (Pangasinan) wind service contract areas last February, 2011, initial micrositing and annual energy production analyses were prepared by COWI, our contracted Danish engineering consultant. COWI reported in May 2011 that the Sual site has only a fair to modest wind resource potential and unlikely to be commercially viable. This result prompted PetroEnergy to relinquish the Sual wind service contract. The DOE formally approved our relinquishment on October 28, 2011.

In contrast to Sual, COWI reported in July 2011 that the Nabas project site can sustain a 50 MW wind farm. This encouraging result led us to start obtaining the first set of development permits and conducting initial engineering studies. SMEC Philippines (SMEC) was engaged in September, 2011 to undertake the environmental baseline survey of Nabas needed to obtain the project’s environmental compliance certificate (ECC). The initial environmental examination report was submitted on December 6, 2011 by SMEC to the DENR-Region 6 office for data screening. In November 2011, we applied with the National Commission on Indigenous Peoples (NCIP) for a Certificate of NonOverlap (CNO) attesting that our project site does not overlap with any existing indigenous peoples’ ancestral domain claims. We also filed with the National Grid Corporation of the Philippines (NGCP) for the conduct of the grid impact study (GIS) which will determine the feasibility of interconnecting our Nabas wind project to

the Visayas Grid. A detailed topographic survey of the likely development areas of the project, including an inventory of existing private and public lots was likewise undertaken. Finally, on November 8, 2011, we secured DOE’s approval for the Deed of Assignment transferring PetroEnergy’s rights and responsibilities over the Nabas wind service contract to our wholly-owned subsidiary PetroGreen Energy Corporation (PGEC).

The Company will defer final investment decision on Nabas until the Energy Regulatory Commission (ERC) approves the feed-in-tariff (FiT) rates for renewable energy. In the meantime, PetroGreen has signed nondisclosure agreements (NDAs) with several potential equity partners, wind turbine suppliers, and construction contractors to expedite the processes of joint-venture partner selection, contracts bidding, and project development in the event that the approved FiT rates are economically acceptable.

2011 ANNUAL REPORT

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PETROENERGY

CORPORATE SOCIAL RESPONSIBILITY

W

e continued to translate our corporate belief in uplifting the communities hosting our energy operations through a number of on-going and new social assistance projects. Support for public education at the primary and secondary levels remain as the focus of our corporate social responsibility (CSR) efforts in three localities.

Puerto Princesa, Palawan Our Teachers Training Program for elementary and high school teachers, which was started in 2008 in partnership with Malayan Colleges Laguna (MCL), entered its final year in 2011. The program, aimed at building teaching competency in English, Science, and Mathematics instruction, benefitted thirty-three (33) high school and forty-five (45) elementary teachers in two high schools and four elementary schools in Puerto Princesa. The beneficiary institutions were Marcelino Abadiano Javarez National High School, San Rafael National High School, F. Austria Elementary School, Manalo Elementary School, San Rafael Elementary School, and Concepcion Elementary School.

The Company’s Student Assistance Program to selected Puerto Princesa national high schools and elementary schools to subsidize transportation costs of students from rural barangays also entered its final year. The program made it easier for children to go to school thus reducing absenteeism and drop-out rates.

Finally, PetroEnergy sponsored MCL Scholarship to seven underprivileged but highly deserving high school seniors from Puerto Princesa.

Laguna and Batangas The final year of our Adopt-A-School Program in Laguna and Batangas, in partnership with the Department of Education (DepEd), the ABS-CBN Foundation Inc. (AFI), and MCL, culminated in the publication and distribution of the PetroEnergy’s High School Handbook. This volume is a teacher’s guide for stimulating instruction of Physics, Chemistry, and Mathematics using inexpensive

and readily available laboratory materials. It is also the fruit of nearly three years of workshops and feedbacks involving hundreds of secondary school teachers from Laguna and Batangas. Copies of the handbook were turned over to 112 public high schools in the two provinces last Sept., 2011, enlarging the pool of users beyond those who participated in the PetroEnergy workshops and ensuring the continued use of teaching insights after the end of our Adopt-A-School Program.

Even as we ended the teachers’ training in 2011, we started new CSR initiatives focused on the host barangay and town of our Maibarara geothermal power project in Sto. Tomas, Batangas. Our initial goodwill effort was the donation of a medical ambulance to Barangay San Rafael and the conduct of a medical mission with the assistance of the Philippine General Hospital in Sitio Capuz, Barangay San Rafael last June, 2011.

2011 ANNUAL REPORT

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And in order to implement a feasible, acceptable, and sustainable community assistance program, PetroEnergy conducted comprehensive community profiling of Barangay San Rafael and workshops with its residents.

These interactions were meant to determine the inherent resources, strengths, and problems within the host barangay as input to the proper formulation of a sustainable community development assistance which will be set-up in 2012.

Nabas, Aklan PetroEnergy and DepEd-Kalibo signed a Memorandum of Agreement (MOA) last May, 2011; the Company committed to build a perimeter fence around the Pawa Primary School in Nabas to secure the school grounds.

The fencing project commenced on April 15 and was completed on June 17, 2011. We also took it upon ourselves to repaint the one-room school building, cement a foot pathway, repaired the flagpole and playground, and donated steel-framed bookshelves and books for the students.

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PETROENERGY

Poised for Greater Heights Your continuing support and understanding as shareholders over the years have allowed our dedicated officers and staff to expand the Company’s frontiers and increase its value. PetroEnergy’s achievements in 2011, built with our Partners in Gabon and in the Philippines, have positioned us for greater heights of growth and profitability in the coming years. Be assured that the anticipated rewards of these expansion efforts will benefit you, our shareholders. We thus close 2011 by acknowledging with gratitude your belief and trust in our vision, stewardship, and performance.

Helen Y. Dee Chairman

Milagros V. Reyes President

Financial Highlights (In thousand US dollars, except per share, crude oil price and ratio values)

C O N S O L I D AT E D

PA R E N T

2011

2010

2011

2010

Change

Assets

60,565

40,488

42,164

39,874

5.74%

Liabilities

17,510

1,603

1,448

1,567

-7.59%

Stockholder’s Equity

43,055

38,884

40,716

38,307

6.29%

Oil Revenue

13,544

10,784

13,544

10,784

25.59%

Operating Income

6,257

4,942

6,257

4,942

26.61%

Net Income

2,926

2,788

3,670

3,500

4.86%

Book Value per Share

0.157

0.189

0.149

0.187

-20.32%

Earning per Share

0.011

0.014

0.013

0.017

-23.53%

8.68:1

17.99:1

16.58:1

16.48:1

0.407:1

0.041:1

0.036:1

0.041:1

$111.31

$78.07

$111.31

$78.07

Current ratio

Debt-to-Equity ratio

Average Crude Oil Price

42.58%

2011 ANNUAL REPORT

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CONSOLIDATED FINANCIAL STATEMENTS

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Statement of Management’s Responsibility for Financial Statements February 16, 2012 Securities and Exchange Commission SEC Building, Edsa Greenhills Mandaluyong, Metro Manila The management of PetroEnergy Resources Corporation is responsible for the preparation and fair presentation of the consolidated financial statements for the years ended December 31, 2011 & 2010, including the additional components attached therein, in accordance with the prescribed financial reporting framework indicated therein. This responsibility includes designing and implementing internal controls relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error, selecting and applying appropriate accounting policies, and making accounting estimates that are reasonable in the circumstances.

The Board of Director reviews and approves the consolidated financial statements and submits the same to the stockholders or members.

SyCip, Gorres, Velayo & Co., the independent auditors appointed by the stockholders has examined the consolidated financial statements of the Company in accordance with the Philippine Standards on Auditing, and its report to the stockholders or members, has expressed its opinion on the fairness of presentation upon completion of such examination.

Helen Y. Dee Chairman of the Board

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PETROENERGY

Milagros V. Reyes President

Yvonne S. Yuchengco Treasurer

Independent Auditors’ Report

The Stockholders and the Board of Directors PetroEnergy Resources Corporation 7th Floor, JMT Building ADB Avenue, Ortigas Center, Pasig City We have audited the accompanying consolidated financial statements of PetroEnergy Resources Corporation and Subsidiaries, which comprise the consolidated statements of financial position as at December 31, 2011 and 2010, and the consolidated statements of income, statements of comprehensive income, statements of changes in equity and statements of cash flows for each of the three years in the period ended December 31,2011, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Philippine Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Philippine Standards on Auditing. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

2011 ANNUAL REPORT

23

Independent Auditors’ Report

Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of PetroEnergy Resources Corporation and Subsidiaries as at December 31, 2011 and 2010, and their financial performance and their cash flows for each of the three years in the period ended December 3I, 2011 in accordance with Philippine Financial Reporting Standards.

Emphasis of Matter Without qualifying our opinion, we draw attention to Note 8 to the consolidated financial statements. The suspension of the production activities in the West Linapacan Oilfield raises uncertainties as to the profitability of the petroleum operations. In addition, the farm-out of the Group’s participating interest in Service Contract No. 14 may result in a potential reduction in its share of future revenues. The profitability of petroleum operations and the full recovery of unamortized cost of wells, platforms and other facilities and the deferred oil exploration costs (see Note 9) incurred in connection with the Group’s participation in the acquisition and exploration of petroleum concessions are dependent upon additional discoveries of oil in commercial quantities and the success of future development thereof.

SYCIP GORRES VELAYO & CO.

J. Carlitos G. Cruz Partner CPA Certificate No. 49053 SEC Accreditation No. 0072-AR-2 (Group A), February 11, 2010, valid until February 10, 2013 Tax Identification No. 102-084-648 BIR Accreditation No. 08-001998-14-2009, June 1, 2009, valid until May 31, 2012 PTR No. 3174589, January 2, 2012, Makati City February 16, 2012

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PETROENERGY

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Financial Position (In U.S. Dollars) December 31 2011

2010

ASSETS Current Assets Cash and cash equivalents (Notes 4 and 22) Financial assets at fair value through profit or loss (Notes 5 and 22) Receivables (Notes 3, 6 and 22) Crude oil inventory (Note 3) Advances, prepaid expenses and other current assets (Notes 7, 14 and 22)

Total Current Assets

$21,904,284 109,018 2,076,016 447,499 7,564,099 32,100,916

$16,084,484 1,552,246 2,744,309 201,611 244,772 20,827,422

21,297,963 5,831,668 − 82,203 31,417 1,221,213 28,464,464 $60,565,380

12,104,365 6,012,163 1,283,953 228,402 31,417 − 19,660,300 $40,487,722

Current Liabilities Accounts payable and accrued expenses (Notes 13, 16 and 22) Income tax payable (Notes 16 and 18)

Total Current Liabilities

$3,455,507 243,474 3,698,981

$736,141 421,301 1,157,442

Noncurrent Liabilities Loans payable (Notes 7, 14 and 16) Accrued retirement liability (Notes 3, 16 and 17) Asset retirement obligation (Notes 3, 15 and 16)

Total Noncurrent Liabilities Total Liabilities

13,295,139 41,862 474,293 13,811,294 17,510,275

− 43,217 402,793 446,010 1,603,452

6,321,533 25,244,737

6,321,533 25,244,737

2,055,555 5,637,881 (56,228) 39,203,478 3,851,627 43,055,105 $60,565,380

2,055,555 3,972,684 59,163 37,653,672 1,230,598 38,884,270 $40,487,722

Noncurrent Assets Property, plant and equipment (Notes 3 and 8) Deferred oil exploration costs (Notes 3 and 9) Deferred geothermal costs (Notes 3 and 10) Deferred tax assets (Notes 3 and 18) Investment property (Notes 3 and 11) Advances and other noncurrent assets (Notes 7 and 14)

Total Noncurrent Assets

LIABILITIES AND EQUITY

Equity Attributable to equity holders of the Parent Company Capital stock (Note 16) Additional paid-in capital (Note 16) Retained earnings

Appropriated (Note 16) Unappropriated Cumulative translation adjustment (Notes 3 and 16) Noncontrolling interest (Notes 16 and 25) Total Equity

See accompanying Notes to Consolidated Financial Statements.

2011 ANNUAL REPORT

25

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Income (In U.S. Dollars)

Years Ended December 31 2011 $13,544,412

2010 $10,784,257

2009 (Note 2) $8,682,063

Oil production operating expenses (Note 19)

5,432,149

4,321,258

3,250,940

Depletion (Note 8)

1,855,082

1,521,188

1,836,158

7,287,231

5,842,446

5,087,098

GROSS INCOME

6,257,181

4,941,811

3,594,965

GENERAL AND ADMINISTRATIVE EXPENSES (Notes 7, 8, and 20)

2,692,091

2,495,376

1,338,120

524,558

389,101

91,892

95,112

767,877

20,637

OIL REVENUES COSTS OF SALES

OTHER INCOME (CHARGES) Interest income Net unrealized foreign exchange gain Net gain (loss) on fair value changes on financial assets at fair value through profit or loss (Note 5)

(79,588)

5,856

9,786

Accretion expense (Note 15)

(62,433)

(75,420)

(67,860)

Miscellaneous income (expense)

1,428

(4,497)

4,180

479,077

1,082,917

58,635

INCOME BEFORE INCOME TAX

4,044,167

3,529,352

2,315,480

1,337,986 $2,706,181

857,870 $2,671,482

592,701 $1,722,779

Equity holders of the Parent Company

$2,926,268

$2,787,723

$1,722,779

Noncontrolling interest (Note 25) NET INCOME

(220,087) $2,706,181

(116,241) $2,671,482

− $1,722,779

$0.011

$0.014

$0.013

PROVISION FOR INCOME TAX (Note 18) NET INCOME NET INCOME (LOSS) ATTRIBUTABLE TO:

EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF THE PARENT COMPANY - BASIC AND DILUTED (Note 24) See accompanying Notes to Consolidated Financial Statements.

26

PETROENERGY

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (In U.S. Dollars)

Years Ended December 31

NET INCOME

2011

2010

2009

$2,706,181

$2,671,482

$1,722,779

(115,391)

59,163

−

$2,590,790

$2,730,645

$1,722,779

$2,810,877

$2,846,886

$1,722,779

(220,087)

(116,241)

−

$2,590,790

$2,730,645

$1,722,779

OTHER COMPREHENSIVE INCOME (LOSS) Movement in cumulative translation adjustment (Notes 3 and 16) TOTAL COMPREHENSIVE INCOME TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interest (Note 25)

See accompanying Notes to Consolidated Financial Statements.

2011 ANNUAL REPORT

27

28

PETROENERGY − −

− −

Increase in noncontrolling interest stock issuances (Note 25)

$3,358,068

Balances as of January 1, 2010

$3,358,068

Balances as of January 1, 2009

$13,390,875

−

−

−

–

$13,390,875

$25,244,737

−

11,853,862

−

−

−

$13,390,875

Unappropriated Retained Earnings

Cumulative Translation Adjustment

$5,637,881

(1,261,071)

−

2,926,268

−

2,926,268

$3,972,684

$3,972,684

(1,237,503)

–

2,787,723

–

2,787,723

$2,422,464

$2,055,555

−

−

−

–

$2,055,555

$2,422,464

(569,398)

1,722,779

−

1,722,779

$1,269,083

–

$–

–

–

–

–

$–

$59,163

–

–

59,163

59,163

For the Year Ended December 31, 2009

$2,055,555

−

–

−

–

–

$2,055,555

$–

($56,228)

−

−

(115,391)

(115,391)

−

$59,163

For the Year Ended December 31, 2010

$2,055,555

−

−

−

−

−

$2,055,555

For the Year Ended December 31, 2011

See accompanying Notes to Consolidated Financial Statements.

$3,358,068

−

Balances as of December 31, 2009

−

Cash dividends (Note 16)

−

Other comprehensive income

Total comprehensive income

–

Net Income

Comprehensive Income (loss)

$6,321,533

−

Cash dividends (Note 16)

Balances as of December 31, 2010

2,963,465

Stock issuances (Note 16)

−

−

Movement in cumulative translation adjustment

Total comprehensive income

−

Net income

Comprehensive income (loss)

$6,321,533

Balances as of December 31, 2011 $25,244,737

−

−

Cash dividends (Note 16)

−

−

−

Total comprehensive income

−

Movement in cumulative translation adjustment

$25,244,737

$6,321,533

Net income

Comprehensive income (loss)

Balances as of January 1, 2011

Additional Paid-in Capital

Capital Stock Total

$21,226,962

(569,398)

1,722,779

−

1,722,779

$20,073,581

$37,653,672

(1,237,503)

14,817,327

2,846,886

59,163

2,787,723

$21,226,962

$39,203,478

(1,261,071)

−

2,810,877

(115,391)

2,926,268

$37,653,672

Attributable to Equity Holders of the Parent Company Appropriated Retained Earnings (Note 16)

$−

−

−

−

−

$−

$1,230,598

–

1,346,839

(116,241)

–

(116,241)

$−

$3,851,627

−

2,841,116

(220,087)

−

(220,087)

$1,230,598

Noncontrolling Interest

$21,226,962

(569,398)

1,722,779

−

1,722,779

$20,073,581

$38,884,270

(1,237,503)

16,164,166

2,730,645

59,163

2,671,482

$21,226,962

$43,055,105

(1,261,071)

2,841,116

2,590,790

(115,391)

2,706,181

$38,884,270

Total

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Changes in Equity (In U.S. Dollars)

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows (In U.S. Dollars)

Years Ended December 31 2011

2010

2009 (Note 2)

$4,044,167

$3,529,352

$2,315,480

2,003,389

1,673,030

1,934,946

62,433

75,420

67,860

(524,558)

(389,101)

(91,892)

79,588

(5,856)

(9,786)

(95,112)

(767,877)

(20,637)

(1,355)

(2,192)

(6,672)

Loss on sale of financial assets at fair value through profit or loss

–

6,500

5,467

Gain on sale of property, plant and equipment

–

–

(9,285)

5,568,552

4,119,276

4,185,481

502,844

(958,169)

(236,284)

Crude oil inventory

(247,087)

(70,308)

177,636

Advances, prepaid expenses and other current assets

(486,341)

(38,063)

(12,894)

Increase (decrease) in accounts payable and accrued expenses

2,711,323

261,305

(21,952)

Cash generated from operations

8,049,291

3,314,041

4,091,987

684,443

193,206

45,814

(1,369,614)

(663,670)

(676,966)

7,364,120

2,843,577

3,460,835

(8,775,750)

(1,375,627)

(109,649)

–

–

(1,471,995)

–

76,510

821,838

1,363,640

503,355

1,551

CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax Adjustments for: Depletion, depreciation and amortization (Notes 7 and 8) Accretion expense (Note 15) Interest income Net loss (gain) on fair value changes on financial assets at fair value through profit or loss (Note 5) Net unrealized foreign exchange gain Increase in accrued retirement liability

Operating income before working capital changes Decrease (increase) in: Receivables

Interest received Income taxes paid Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of: Property, plant and equipment (Note 8) Financial assets at fair value through profit or loss Disposals of: Property, plant and equipment (Note 8) Financial assets at fair value through profit or loss (Forward)

2011 ANNUAL REPORT

29

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows (In U.S. Dollars)

Years Ended December 31 2011

2010

2009 (Note 2)

$–

($1,203,953)

$–

(6,862,760)

–

–

(996,291)

(2,265,635)

(1,634,441)

(15,271,161)

(4,265,350)

(2,392,696)

13,724,563

–

–

–

14,817,327

–

Payment of deferred financing cost

(1,612,743)

–

–

Dividends paid (Note 16)

(1,243,767)

(1,209,080)

(549,285)

2,841,116

1,346,839

–

13,709,169

14,955,086

(549,285)

17,672

661,392

22,316

5,819,800

14,194,705

541,170

16,084,484

1,889,779

1,348,609

$21,904,284

$16,084,484

$1,889,779

Increase in deferred geothermal costs (Note 10) Advances to contractor Increase in deferred oil exploration costs (Notes 8 and 9) Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt (Note 14) Proceeds from stock rights offering (Note 16)

Additional capital from noncontrolling interest (Note 25) Net cash provided by (used in) financing activities EFFECT OF FOREIGN EXCHANGE RATE CHANGES IN CASH AND CASH EQUIVALENTS NET INCREASE IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 4) See accompanying Notes to Consolidated Financial Statements.

30

PETROENERGY

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements (In U.S. Dollars)

1. Corporate Information a.

Organization PetroEnergy Resources Corporation (the Parent Company) was incorporated in the Philippines on September 29, 1994 and started commercial operations in 1995. The registered office address of the Company is 7th Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City. PetroEnergy Resources Corporation and its subsidiaries are involved in the exploration and development of petroleum, geothermal and wind energy resources. The Parent Company’s shares of stock are listed and are currently traded at the Philippine Stock Exchange (PSE).

On July 22, 2009, the Board of Directors (BOD) and Stockholders approved the amendment of articles of incorporation of the Parent Company to include the business of generating power from conventional sources such as coal, fossil fuel, natural gas, nuclear and other traditional sources of power and from renewable sources such as, but not limited to, biomass, hydro, solar, wind, geothermal, ocean and such other renewable sources of power. The amendment was approved by the Philippine Securities and Exchange Commission (SEC) on September 23, 2009.

On February 23, 2010, the BOD approved the creation of a wholly owned subsidiary, PetroGreen Energy Corporation (“PetroGreen or PGEC”) that shall carry out the renewable energy projects for the Parent Company. The SEC approved the incorporation of PetroGreen on March 31, 2010.

On May 19, 2010, PetroGreen signed a Joint Venture Agreement (JVA) with Trans-Asia Oil and Energy Development Corporation (“Trans-Asia”) and PNOC Renewables Corporation (“PNOC-RC”) (collectively the “JV Partners”), whereby the JV Partners agreed to pool their resources together and enter into a joint venture to develop and operate the Maibarara Geothermal Field through the formation of a joint venture named Maibarara Geothermal, Inc. (MGI). On August 11, 2010, the SEC approved the incorporation of MGI, whose principal business is to develop and operate geothermal steam fields and power plants. Pursuant to the JVA, PetroGreen holds a 65% interest in MGI, while Tran-Asia and PNOC-RC hold 25% and 10%, respectively.

MGI is effectively, a subsidiary of the Parent Company through PetroGreen, since the Parent Company wholly owns PetroGreen and PetroGreen owns more than half of the voting power of MGI. The Parent Company, PetroGreen and MGI are collectively referred to as the Group.

b.

Nature of Operations The Group’s three (3) main energy businesses are petroleum, wind and geothermal energy. Petroleum production is on-going in the Etame (Gabon) concession, while the other petroleum concessions in the Philippines (northwest Palawan, offshore Mindoro, eastern Visayas) are still in the advanced exploration stages or pre-development stages. The wind project in Nabas, Aklan is in the 3rd and final year of feasibility studies while the other wind service contract in Sual was dropped due to low potential. The geothermal project is the 20 MW Maibarara project in Sto. Tomas Batangas where MGI is now constructing the power plant for commercial operations by late 2013.

In 2011, the highlights of the Maibarara Geothermal Power Project (MGPP) are as follows: • • • • • •

Work over of MAI-6D, MAI-9D & MAI-11D wells; Discharge testing of MAI-6D and MAI-9D wells; Third-party validation of steam reserves; Confirmation of commerciality of the MGPP; Securing a P2.4 billion project loan facility; and Entering into agreements with different parties, as follows: o Electricity Sales Agreement; o Certified Emission Reductions Purchase Agreement; 2011 ANNUAL REPORT

31

o o o o

Engineering, Procurement and Construction (EPC) contract for the power plant construction; Remote Monitoring System and Technical Advisory Services (for the power plant operations and maintenance) Agreement; Transmission Service Agreement; and Connection Agreement.

The accompanying consolidated financial statements were approved and authorized for issue by the BOD on February 16, 2012.

2. Summary of Significant Accounting and Financial Reporting Policies Basis of Preparation The accompanying consolidated financial statements of the Group have been prepared on a historical cost basis, except for financial assets at fair value through profit and loss (FVPL) and crude oil inventory that have been measured at fair value. The consolidated financial statements are presented in United States (US) Dollar ($), which is the Parent Company’s functional currency.

Basis of Consolidation The consolidated financial statements include the accounts of the Parent Company and the following subsidiaries. All subsidiaries are incorporated and are operating in the Philippines.

Percentage of Ownership 2011 2010 100% 100%

PGEC MGI

65%

65%

2009 − −

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 when such control ceases. The financial statements of the subsidiary are prepared for the same reporting period as the Parent Company, using consistent accounting policies. All intra-group balances, transactions, unrealized gains and losses resulting from intra-group transactions and dividends are eliminated in full.

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 a 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 recognised in other comprehensive income to profit or loss or retained earnings, as appropriate.

The Group measures the noncontrolling interest in the subsidiary at the proportionate share of the subsidiary’s identifiable net assets.

Statement of Compliance The consolidated financial statements of the Group have been prepared in accordance with Philippine Financial Reporting Standards (PFRS).

32

PETROENERGY

Changes in Accounting Policies and Disclosures The accounting policies adopted are consistent with those of the previous financial year except for the following new and amended PFRSs and Philippine Interpretations based on International Financial Reporting Interpretation Committee (IFRIC) interpretations which were adopted as of January 1, 2011.

Title Philippine Accounting Standards (PAS) 24 (Amended), Related Party Disclosures

Effective Date (Annual Periods Beginning on or After) January 1, 2011

PAS 32 Amendment, Classification of Rights Issues

February 1, 2010

Philippine Interpretation IFRIC-14 Amendment Prepayments of a Minimum Funding Requirement

January 1, 2011

Philippine Interpretation IFRIC-19, Extinguishing Financial Liabilities with Equity Instruments 2010 Improvements to PFRSs

July 1, 2010 Various*

The above list is intended for existing PFRS users and does not include issuances effective December 31, 2011 that are applicable to first-time adopters of PFRS such as PFRS 1, Limited Exemption from Comparative PFRS 7 Disclosures for First-time Adopters. *The amendments in the 2010 Improvements to PFRSs are effective for annual periods beginning on or after July 1, 2010, except for the amendments to PFRS 1, PFRS 7, PAS 1, PAS 34 and Philippine Interpretation IFRIC-13 which are effective for annual periods beginning on or after January 1, 2011. An entity may early adopt any of the amendments in the 2010 Improvements to PRFSs individually.

The adoption of the standards or interpretations is described below: •

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.

•

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.

•

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 amendment of the interpretation has no effect on the financial position nor performance of the Group.

Improvements to PFRSs (issued 2010) Improvements to PFRSs, 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.

2011 ANNUAL REPORT

33

•

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 July 1, 2011.

•

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 22.

•

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 statements of changes in equity or in the notes to the financial statements.

Other amendments resulting from the 2010 Improvements to PFRSs 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)) • 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 and amendments issued but not yet effective up to the date of issuance of the Group’s financial statements are listed below. The Group will adopt these standards and amendments when these become effective.

Except as otherwise indicated, the Group does not expect the adoption of these new and amended standards and interpretations to have significant impact on its financial statements.

• 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.

•

34

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 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 always be measured on a sale basis of the asset. The amendment becomes effective for annual periods beginning on or after January 1, 2012.

PETROENERGY

•

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.

•

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 statements of financial position; c) The net amounts presented in the statements 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. 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, Consolidated and Separate Financial Statements 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 2011 ANNUAL REPORT

35

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.

36

•

PFRS 11, Joint Arrangements PFRS 11 replaces PAS 31, Interests in Joint Ventures and SIC-13, Jointly-controlled Entities - Nonmonetary 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 Interests 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.

•

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 first half of 2012. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

•

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 impact of the amendments to PAS 32.

•

Philippine Interpretation IFRIC 15, Agreements for the Construction of Real Estate This interpretation covers accounting for revenue and associated expenses by entities that undertake the construction of real estate directly or through subcontractors. The interpretation requires that revenue on construction of real estate be recognized only upon completion, except when such contract qualifies as construction contract to be accounted for under PAS 11, Construction Contracts, or involves rendering of services in which case revenue is recognized based on stage of completion. Contracts involving provision of services with the construction materials and where the risks and reward of ownership are transferred to the buyer on a continuous basis will also be accounted for based on stage of completion. The SEC and the Financial Reporting Standards Council (FRSC) have deferred the effectivity of this interpretation until the final Revenue standard is issued by International Accounting Standards Board and an evaluation of the requirements of the final Revenue standard against the practices of the Philippine real estate industry is completed.

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Philippine Interpretation IFRIC 20, Stripping Costs in the Production Phase of a Surface Mine This interpretation applies to waste removal costs that are incurred in surface mining activity during the production phase of the mine (“production stripping costs”) and provides guidance on the recognition of production stripping costs as an asset and measurement of the stripping activity asset. This interpretation becomes effective for annual periods beginning on or after January 1, 2013.

Summary of Significant Accounting Policies Revenue Revenue is recognized to the extent that it is probable that the economic benefits will flow to the Group and the income can be reliably measured. The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent. The Group has concluded that it is acting as principal in all of its revenue arrangements. The following specific recognition criteria must also be met before revenue is recognized: Oil Revenues Revenues from producing oil wells are recognized as income at the time of production.

Interest Income Interest income is recognized as the interest accrues taking into account the effective yield on the asset.

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 from the dates of acquisition and that are subject to an insignificant risk of change in value.

Financial Assets Financial assets within the scope of PAS 39, Financial Instruments: Recognition and Measurement, are classified as financial assets at FVPL, loans and receivables, held-to-maturity (HTM) investments, available-for-sale (AFS) financial assets or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The classification depends on the purpose for which the investments were acquired. Management determines the classification of its investments at initial recognition and re-evaluates this designation at every reporting date.

Financial assets are recognized initially at fair value plus transaction costs directly attributable to their acquisition, in the case of all financial assets not carried at FVPL. All regular way purchases and sales of financial assets are recognized on the trade date, which is the date that the Group commits to purchase the asset. Regular way purchases or sales are purchases or sales of financial assets that require delivery of assets within the period generally established by regulation or convention in the marketplace.

Assets under this category are classified as current assets if maturity is within 12 months from the reporting date and as noncurrent assets if maturity date is more than a year from the reporting date. a.

Financial Assets at FVPL. This includes financial assets held for trading and financial assets designated upon initial recognition as at FVPL. Financial assets are classified as held for trading if they are acquired for the purpose of selling in the near term.

Financial assets at FVPL are recorded in the consolidated statements of financial position at fair value with unrealized marked-to-market gains and losses reported as part of the current year operations under “Net gain (loss) on fair value changes on financial assets at FVPL” in the consolidated statements of income. Interest earned or incurred is recorded as interest income or expense, respectively, while dividend income is recorded under “Miscellaneous income” in the consolidated statements of income when the right of payment has been established. Derivatives, including separated embedded derivatives are also classified as FVPL unless they are designated as effective hedging instruments or a financial guarantee contract.

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Classified as financial assets at FVPL are the Group’s marketable debt and equity securities held for trading purposes and investment in golf club shares (see Note 5). 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. After initial measurement, loans and receivables are carried at amortized cost using the effective interest method less any allowance for impairment. Gains and losses are recognized in the consolidated statements of income when the loans and receivables are derecognized or impaired, as well as through the amortization process.

Classified under this category are the Group’s cash and cash equivalents, restricted cash, receivables and interest receivable (see Notes 4, 6 and 7).

c.

HTM Investments. HTM investments are non-derivative financial assets with fixed or determinable payments and fixed maturities for which the Group’s management 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. Gains and losses are recognized in the consolidated statements of income when the investments are derecognized or impaired, as well as through the amortization process.

The Group has no HTM investments as at December 31, 2011 and 2010.

d.

AFS Financial Assets. AFS financial assets are those non-derivative financial assets that are designated as AFS or are not classified in any of the three preceding categories. After initial measurement, AFS financial assets are measured at fair value with unrealized gains or losses recognized directly in equity until the investment is derecognized or determined to be impaired at which time the cumulative gain or loss previously recorded in equity is recognized in the consolidated statements of income.

The Group has no AFS financial assets as at December 31, 2011 and 2010.

e.

Derivative Financial Instruments. Derivatives are recorded at fair value and carried as assets when their fair value is positive and as liabilities when their fair value is negative. Changes in the fair value of derivatives are included in the consolidated statements of income.

Derivatives embedded in other financial instruments are treated as separate derivatives and recorded at fair value if their economic characteristics and risks are not closely related to those of the host contract, and the host contract is not itself held for trading or designated at FVPL. 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 contract and accounted for as a derivative if all of the following conditions are met: a) the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract; b) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and c) the hybrid or combined instrument is not recognized 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.

Subsequent reassessment is prohibited unless there is change in the terms of the contract that significantly modifies the cash flows that otherwise would be required under the contract, in which case reassessment is required. The Group determines whether a modification to cash flows is significant by considering the extent to which the expected future cash flows associated with embedded derivative, the host contract or both have changed and whether the change is significant relative to the previously expected cash flow on the contract.

The Group has no derivative financial instruments as at December 31, 2011 and 2010.

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Determination of Fair Value The fair value of financial instruments that are traded in active markets at each reporting date is determined by reference to quoted market prices or dealer price quotations (bid price for long positions and ask price for short positions), without any deduction for transaction costs.

For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques. Such techniques may include using recent arm’s length market transactions; reference to the current fair value of another instrument that is substantially the same; a discounted cash flow analysis or other valuation models.

Day 1 Profit Where the transaction price in a non-active market is different to the fair value from 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 profit) in the consolidated statements of income, unless it qualifies for recognition as some other type of asset.

In cases where use is made of data which is not observable, the difference between the transaction price and model value is only recognized in the consolidated statements 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 profit amount.

Financial Liabilities Financial liabilities within the scope of PAS 39 are classified as financial liabilities at FVPL and other financial liabilities, as appropriate. The Group determines the classification of its financial liabilities at initial recognition. a.

Financial Liabilities at FVPL - Financial liabilities at FVPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as at FVPL. Derivatives, including separated embedded derivatives, are also classified as FVPL, unless they are designated as effective hedging instruments.

Financial liabilities are classified as held for trading if they are acquired for the purpose of selling in the near term. Gains or losses on liabilities held for trading are recognized in the consolidated statements of income.

The Group has not designated any financial liabilities as at FVPL as at December 31, 2011 and 2010.

b.

Other Financial Liabilities - Other financial liabilities are non-derivative financial liabilities with fixed or determinable payments that are not quoted in an active market. These liabilities are carried at cost or amortized cost in the consolidated statements of financial position. Amortization is determined using the effective interest method.

Gains and losses are recognized in the consolidated statements of income, when the liabilities are derecognized as well as through the amortization process.

Classified under this category are Group’s accounts payable and accrued expenses and loans payable (see Notes 13 and 14).

Offsetting of Financial Instruments Financial assets and financial liabilities are offset and the net amount reported in the consolidated statements of financial position if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is no intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

Impairment of Financial Assets The Group assesses at each reporting date whether there is any objective evidence that a financial asset or a 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 objective evidence of impairment as a result of one or more events that has occurred after the 2011 ANNUAL REPORT

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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.

Loans and Receivables The Group first assesses whether objective evidence of impairment exists individually for financial assets that are individually significant, or collectively for financial assets that are not individually significant. If the Group determines that no objective evidence of impairment exists for individually assessed financial asset, whether significant or not, it includes the asset in a group of financial assets with similar credit risk characteristics and collectively assesses for impairment. Those characteristics are relevant to the estimation of future cash flows for groups of such assets by being indicative of the debtors’ ability to pay all amounts due according to the contractual terms of the assets being evaluated. 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 for impairment.

If there is objective evidence that an impairment loss on assets 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 expected 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 is reduced through use of an allowance account. The amount of the loss shall be recognized in the consolidated statements of income.

If in a subsequent period, the amount of the estimated 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, to the extent that the carrying value of the asset does not exceed its amortized cost at the reversal date. Any subsequent reversal of an impairment loss is recognized in the consolidated statements of income.

In relation to the Group’s receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor) that the Group will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of the receivable is reduced through the use of an allowance account. Impaired receivables are derecognized when they are assessed as uncollectible.

Derecognition of Financial Assets and Financial Liabilities Financial Assets A financial asset or, where applicable, a part of a financial asset or a part of a group of similar financial assets, is derecognized when: • •

the rights to receive cash flows from the asset have expired; or the Group has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows in full without material delay to a third party under a ‘pass-through’ arrangement; 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.

When the Group has transferred its rights to receive cash flows from an asset or has entered into a pass-through arrangement, it evaluates if and to what extent it has retained the risks and rewards of ownership. When it has neither transferred nor retained substantially all of 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. In that case, the Group also recognizes an associated liability. The transferred asset and the associated liability are measured on a basis that reflects the rights and obligations that the Group has retained.

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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 Group could be required to repay.

Financial Liabilities A financial liability is derecognized when the obligation under the liability is discharged or cancelled or has expired.

When 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 statements of income.

Crude Oil Inventory Crude oil inventory is stated at fair market value.

Advances, Prepaid Expenses and Other Current Assets Advances, prepaid expenses and other current assets pertain to resources controlled by the Group as a result of past events and from which future economic benefits are expected to flow to the Group.

Property, Plant and Equipment Property, plant and equipment, except for land, are stated at cost less accumulated depletion, depreciation and amortization and any accumulated impairment losses. Land is stated at cost less any accumulated impairment losses. The initial cost of the property, plant and equipment consists of its purchase price, including any import duties, taxes and any directly attributable costs of bringing the assets to its working condition and location for its intended use and abandonment costs.

Expenditures incurred after the fixed assets have been put into operation, such as repairs and maintenance, are normally charged to income in the period in which the costs are incurred. In situations where it can be clearly demonstrated that the expenditures have resulted in an increase in the future economic benefits expected to be obtained from the use of an item of property, plant and equipment beyond its originally assessed standard of performance, the expenditures are capitalized as an additional cost of property, plant and equipment.

Depreciation of an item of property, plant and equipment begins when it becomes available for use, i.e., when it is in the location and condition necessary for it to be capable of operating in the manner intended by management. Depreciation ceases at the earlier of the date that the item is classified as held for sale (or included in a disposal group that is classified as held for sale) in accordance with PFRS 5, Non-current Assets Held for Sale and Discontinued Operations, and the date the asset is derecognized.

When the assets are retired or otherwise disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in the consolidated statements of income.

Wells, platforms and other facilities are depleted using the units-of-production method computed based on estimates of proved reserves. The depletion base includes the exploration and development cost of the producing oilfields.

Fluid collection and re-injection system (FCRS) and production wells - geothermal are depreciated using the straight line method over the useful lives of the assets. The useful life of these assets shall be determined once in the condition necessary for these assets to be capable of operating in the manner intended by management.

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Other property, plant and equipment are depreciated and amortized using the straight-line method over the estimated useful lives of the assets as follows: Office condominium units and improvements Transportation equipment Office furniture and other equipment Land improvements

15 years 5 years 3 - 5 years 5 years

Wells in progress pertain to those development costs relating to the Service Contract (SC) where oil in commercial quantities are discovered and are subsequently reclassified to “Wells, platforms and other facilities” shown under “Property, plant and equipment” account in the consolidated statements of financial position upon commercial production. Depletion of wells in progress commences upon transfer to property, plant and equipment and related main assets are in the condition necessary for it to be capable of operating in the manner intended by management.

The useful lives and depletion, depreciation and amortization methods are reviewed periodically to ensure that the period and method of depletion, depreciation and amortization are consistent with the expected pattern of economic benefits from items of property, plant and equipment.

Construction in progress represents property, plant and equipment under construction and is stated at cost. This includes the cost of construction to include materials, labor, professional fees, borrowing costs and other directly attributable costs. Construction in progress is not depreciated until such time the construction is completed.

Deferred Oil Exploration Costs The Group follows the full cost method of accounting for exploration costs determined on the basis of each SC area. Under this method, all exploration costs relating to each SC are tentatively deferred pending determination of whether the area contains oil reserves in commercial quantities.

The exploration costs relating to the SC where oil in commercial quantities are discovered are subsequently reclassified to “Wells, platforms and other facilities” shown under “Property, plant and equipment” in the consolidated statements of financial position upon substantial completion of the development stage. On the other hand, all costs relating to an abandoned SC are written off in the year the area is permanently abandoned.

SCs are considered permanently abandoned if the SCs have expired and/or there are no definite plans for further exploration and/or development.

Deferred Geothermal Costs All costs incurred in the geological and geophysical activities such as costs of topographical, geological and geophysical studies; rights of access to properties to conduct those studies; salaries and other expenses of geologists, geophysical crews, or others conducting those studies are charged to profit or loss in the year such costs are incurred.

If the results of initial geological and geophysical activities reveal the presence of geothermal resource that will require further exploration and drilling, subsequent exploration and drilling costs are accumulated and deferred under the “Deferred geothermal costs” account in the consolidated statements of financial position.

These costs include the following: • Costs associated with the construction of temporary facilities; • Costs of drilling exploratory and exploratory type stratigraphic test wells, pending determination of whether the wells can produce proved reserves; and • Costs of local administration, finance, general and security services, surface facilities and other local costs in preparing for and supporting the drill activities, etc. incurred during the drilling of exploratory wells.

If tests conducted on the drilled exploratory wells reveal that these wells cannot produce proved reserves, the capitalized costs are charged to expense except when management decides to use the unproductive wells for

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recycling or waste disposal.

Once the project’s technical feasibility and commercial viability to produce proved reserves are established, the exploration and evaluation assets shall be reclassified to property, plant and equipment.

Investment Property Investment property consists of land held for capital appreciation or rental to others. Land is stated at cost less any impairment in value.

The initial cost of the investment property comprises of purchase price and any directly attributable costs of bringing the asset to its working condition. Expenditures incurred after the investment property has been put into operation, such as repairs and maintenance, are normally charged to expense in the year when costs are incurred.

In situations where it can be clearly demonstrated that the expenditures have resulted in an increase in the future economic benefits expected to be obtained from the use of an item of investment property beyond its originally assessed standard of performance, the expenditures are capitalized as an additional cost of investment property.

Investment property is derecognized when either it has been disposed of or when the investment property is permanently withdrawn from use and no future economic benefit is expected from its disposal. Any gains or losses on the retirement or disposal of an investment property are recognized in the consolidated statements of income in the year of retirement or disposal.

Transfers are made to investment property when, and only when, there is a change in use, evidenced by the end of owner-occupation, commencement of an operating lease to another party or by the end 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 sell.

Interest in Joint Venture Operations A jointly controlled operation involves the use of assets and other resources of the Group and other venturers rather than the establishment of a corporation, partnership or other entity. The Group accounts for the assets it controls and the liabilities it incurs, the expenses it incurs and the share of income that it earns from the sale of crude oil by the joint venture.

Impairment of Nonfinancial Assets The Group assesses at each reporting date whether there is an indication that an asset (e.g. property, plant and equipment, investment property, deferred oil exploration costs, deferred geothermal costs) may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group estimates 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 group 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. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators.

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 Group makes an estimate of recoverable amount. 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 statements of income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase.

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Equity The Group records common stocks at par value and additional paid-in capital in excess of the total contributions received over the aggregate par values of the equity shares. When the Group issues more than one class of stock, a separate account is maintained for each class of stock and the number of shares issued. Incremental costs incurred directly attributable to the issuance of new shares are shown in equity as a deduction from proceeds, net of tax. When any member of the Group purchases the Group’s capital stock (treasury shares), the consideration paid, including any attributable incremental costs, is deducted from equity attributable to the Group’s equity holders until the shares are cancelled, reissued or disposed of. Where such shares are subsequently sold or reissued, any consideration received, net of any directly attributable incremental transaction costs and the related tax effects is included in equity.

Retained earnings represent accumulated earnings (losses) of the entities within the Group less dividends declared and with consideration of any changes in accounting policies and errors applied retroactively. The retained earnings of the Parent Company and its subsidiaries are available for dividends only upon approval and declaration of each of their respective Board of Directors. The Parent Company’s retained earnings available for dividend declaration as of December 31, 2011, 2010 and 2009 amounted to $6.40 million, $4.83 million, and $2.58 million, respectively.

Costs and Expenses Oil production operating expenses are costs incurred to sell crude oil inventories, including transportation, storage and loading, among others. General and administrative expenses constitute costs of administering the business. Costs and expenses are recognized as incurred.

Asset Retirement Obligation Provision for asset retirement obligation is recognized when the recognition criteria for a provision are met. Asset retirement obligation are recorded based on the present value of costs expected to settle a legal or constructive obligation to retire an asset. Accretion expense on asset retirement obligation is included in the consolidated statement of comprehensive income. The estimated future costs of dismantling costs are reviewed annually and adjusted as appropriate.

Retirement Costs The retirement cost is actuarially determined using the projected unit credit method. Under this method, the current service cost is the present value of retirement benefits payable in the future with respect to services rendered in the current period. The liability recognized in the consolidated statements of financial position with respect to defined benefit pension plans is the present value of the defined benefit obligation at the reporting date less fair value of plan assets, if any, together with any adjustments for unrecognized actuarial gains and losses and past service cost. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rate on government bonds that have terms to maturity approximating the terms of the related retirement liability.

Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions are charged or credited to income when the net cumulative unrecognized actuarial gains and losses at the end of the previous period 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 retirement 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 and the aggregate of cumulative unrecognized net actuarial losses and past service cost

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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.

Income Tax Current Income Tax Current 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 at the reporting date.

Deferred Income Tax Deferred income tax is provided, using the liability method, on all temporary differences at the reporting 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.

Deferred income tax assets are recognized for all deductible temporary differences, carryforward of unused tax credits from excess minimum corporate income tax (MCIT) over regular corporate income tax and unused net operating losses carryover (NOLCO), to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carryforward of unused tax credits from excess MCIT and unexpired NOLCO can be utilized.

The carrying amount of deferred income tax assets is reviewed at each reporting 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 reporting 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 tax income 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 at the reporting date.

Deferred income tax assets and liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Leases The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at inception date, whether fulfillment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset, even if that right is not explicitly specified in an arrangement.

Group as a Lessee Finance leases which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the commencement of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognized in the consolidated statements of income.

An asset under finance lease is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.

Operating lease payments are recognized as an operating expense in the consolidated statements of income on a straight-line basis over the lease term.

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Group as Lessor Leases in which the Group does not transfer substantially all the risks and benefits of ownership of the asset are classified as operating leases. Initial direct costs incurred in negotiating an operating lease are added to the carrying amount of the leased asset and recognized over the lease term on the same bases as rental income.

Research and Development Costs Research costs are expensed as incurred. Development expenditures on an individual project are recognized as an intangible asset when the Group can demonstrate all of the following: • • • • •

the technical feasibility of completing the intangible asset so that it will be available for use or sale; its intention to complete and its ability to use or sell the asset; how the asset will generate future economic benefits; the availability of resources to complete the asset; and the ability to measure reliably the expenditure during development.

Provisions Provisions are recognized when (a) the Group has a present obligation (legal or constructive) as a result of a past event, (b) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and (c) a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pretax rate that reflects current market assessment 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 consolidated financial statements. They 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 benefit is probable.

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 costs 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.

Foreign Currency Translation The consolidated financial statements are presented in US Dollars, which is the Parent Company’s functional and presentation currency. Each entity in the Group determines its own functional currency and items included in the consolidated financial statements of each entity are measured using that functional currency. Transactions in foreign currencies are initially recorded in the functional currency rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency closing rate at the reporting date.

All differences are taken to the consolidated statements of income with the exception of differences on foreign currency borrowings that provide, if any, a hedge against a net investment in a foreign entity. These are taken directly to equity until disposal of the net investment, at which time they are recognized in the consolidated statements of income. Non-monetary items that are measured in terms of historical cost in foreign currency are translated using the exchange rates as at the dates of 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 the Parent Company’s immediate subsidiary, PGEC, and PGEC’s subsidiary, MGI, is Philippine Peso. As at reporting date, the assets and liabilities of these subsidiaries are translated into the presentation currency of the Group (the US Dollars) at the exchange rate at the reporting date and the consolidated statements of income accounts are translated at weighted average exchange rates for the year. The

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exchange differences arising on the translation are taken directly to “Cumulative translation adjustment” account in the equity section of the consolidated statements of financial position. Upon disposal of a subsidiary, the deferred cumulative translation adjustment amount recognized in equity relating to that particular subsidiary is recognized in the consolidated statements of income.

Basic/Diluted Earnings Per Share Basic earnings per share are computed on the basis of the weighted average number of shares outstanding during the year after giving retroactive effect for any stock dividends declared in the current year.

Diluted earnings per share are computed on the basis of the weighted average number of shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion of all the dilutive potential ordinary shares into ordinary shares.

Segment Information The Group’s businesses are organized and managed separately according to the nature of products. Financial information on business segments are presented in Note 23 to the consolidated financial statements.

Events after the Reporting Period Post year-end events that provide additional information about the Group’s situation at the reporting date (adjusting events) are reflected in the consolidated financial statements, if any. Post year-end events that are not adjusting events are disclosed in the notes to consolidated financial statements when material.

3. Significant Accounting Judgments, Estimates and Assumptions The preparation of the consolidated financial statements in accordance with PFRS requires the Group to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, income and expenses and the disclosure of contingent assets and contingent liabilities, at the reporting date. However, uncertainty about these assumptions and estimates could result in outcomes that could require a material adjustment to the carrying amount of the asset or liability affected in the future.

Judgments In the process of applying the Group’s accounting policies, management has made the following judgments, apart from those involving estimations, which has the most significant effect on the amounts recognized in the consolidated financial statements: Determination of Functional Currency The entities within the Group determine the functional currency based on economic substance of underlying circumstances relevant to each entity within the Group. The Parent Company’s functional currency is the US Dollar. The functional currency of PGEC and MGI, is Philippine Peso.

As of December 31, 2011 and 2010, the Group’s cumulative translation adjustment amounted to ($56,228) and $59,163, respectively.

Capitalization of Development Costs Initial capitalization of costs is based on management’s judgment that technical, economic and commercial feasibility is confirmed, usually when a product development project has reached a defined milestone according to an established project management model.

The Group has determined that all costs incurred for the Geothermal Energy Project (excluding the general and administrative expenses and research costs in the consolidated statements of income and those that are recognized under property, plant and equipment in the consolidated statements of financial position) are treated as deferred geothermal costs in the consolidated statements of financial position. As of December 31, 2010, deferred geothermal costs amounted to $1.28 million (see Note 10).

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47

Estimates and Assumptions The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

Impairment of Receivables The Group reviews its receivables to assess impairment at least on an annual basis. In determining whether an impairment loss should be recorded in the consolidated statements of income, the Group makes judgments as to whether there is any observable data indicating that there is a measurable decrease in the estimated future cash flows from its receivables. This evidence normally includes direct information about the financial condition and historical payments of the borrower.

No impairment losses were recognized in 2011 and 2010. The allowance for impairment losses as of December 31, 2011 and 2010 are carryover from prior years.

As of December 31, 2011 and 2010, the carrying value of receivables amounted to $2.08 million and $2.74 million, respectively. Accumulated impairment losses amounted to $61,187 as of December 31, 2011 and 2010 (see Note 6).

Estimating Geothermal Field Reserves MGI performed volumetric reserve estimation and numerical modeling to determine the reserves of the Maibarara geothermal field. As a requirement for project financing, MGI also engaged at its own cost the New Zealand firm Sinclair Knight Merz (SKM) to undertake a comprehensive third-party technical review of the Maibarara geothermal field. This review included analysis of the resource assessment performed in-house by MGI as well as a separate SKM reserve estimation and numerical modeling of the Maibarara reserves.

MGI’s simulation indicated a mean (P50) proven reserves of 27.8 MW for 25 years. In contrast, SKM calculated the P50 reserves at 46 MW. At 90% probability (P90), the reserves calculated are 28 MW and 12 MW by SKM and MGI, respectively. SKM concluded that the approach taken by MGI is conservative as it limits reservoir thickness to depths where a maximum thickness of 280°C will be encountered although the measured temperature reached as high as 324°C. There is reasonable confidence that the 20 MW (gross) plant development is feasible as the P90 level appears also conservative as with MGI’s approach.

In addition, SKM identified indicated reserves, translating to 10 MW-26 MW in the area south of and outside the current area of development. Since this area is not being tapped at the moment for the 20 MW project, MGI preferred not to estimate such reserves at the moment; however, this provides additional confidence for future project capacity expansion.

The results of the reserves calculation are given below.

Reserves Type Proven

Probability P90

MW Generation Capacity for 25 Years Probability P50 Probability P10

MGI

12

28

51

SKM

28

44

66

SKM

10

16

26

MGI

-

-

-

Indicated

Estimating Proved Group Oil Reserves The Group assesses its estimate of proved reserves on an annual basis based on the report from an independent party hired by the consortium operator to estimate the oil reserves. The independent party estimates the reserves

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of oil in accordance with accepted volumetric methods, specifically the probabilistic method of estimation.

Probabilistic method uses known geological, engineering and economic data to generate a range of estimates and their associated probabilities.

Estimating Useful Lives of Property, Plant and Equipment The Group reviews on an annual basis the estimated useful lives of property, plant and equipment based on expected asset utilization as anchored on business plans and strategies that also consider expected future technological developments and market behavior.

It is possible that future results of operations could be materially affected by changes in these estimates brought about by changes in the factors mentioned. A reduction in the estimated useful lives of property and equipment would increase the recorded depreciation and amortization expense and decrease noncurrent assets.

As of December 31, 2011 and 2010, the Group’s property, plant and equipment amounted to $21.30 million and $12.10 million, respectively (see Note 8).

Impairment of Nonfinancial Assets The Group assesses impairment on its nonfinancial assets (e.g., property, plant and equipment and investment property) whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Among others, the factors that the Group considers important which could trigger an impairment review on its nonfinancial assets include the following: For property, plant and equipment, investment property and crude oil inventory, an impairment loss is recognized whenever the carrying amount of an asset exceeds its recoverable amount. The recoverable amount is the higher of an asset’s net selling price and value in use. The net selling price is the amount obtainable from the sale of an asset in an arm’s length transaction while value in use is the present value of estimated future cash flows expected to arise from the continuing use of an asset and from its disposal at the end of its useful life.

In determining the present value of estimated future cash flows expected to be generated from the continued use of property, plant and equipment and investment property, the Group is required to make estimates and assumptions that can materially affect the consolidated financial statements.

As discussed in Note 8, production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last fourteen (14) years. The investment in WLO included in “Wells, Platforms and Other Facilities” account under property, plant and equipment in the consolidated statements of financial position amount to $6.7 million as of December 31, 2011 and 2010. Management assessed that the said investment is fully recoverable as SC 14-C is not yet expired, with the 15-year extension of the SC as approved by the Department of Energy (DOE), from December 18, 2010 to December 18, 2025 and the existing redevelopment activities led by Pitkin Petroleum Ltd. (Pitkin). Thus, no impairment was recognized for 2011 and 2010.

As of December 31, 2011 and 2010, the carrying value of property, plant and equipment amounted to $21.30 million and $12.10 million, respectively (see Note 8); and the carrying value of investment property amounted to $31,417 (see Note 11).

As of December 31, 2011 and 2010, the carrying value of the Group’s crude oil inventory amounted to $0.45 million and $0.20 million, respectively, which represents its fair market value.

Impairment of Deferred Oil Exploration Costs The Group assesses impairment on deferred oil exploration costs when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount. Until the Group has sufficient data to determine technical feasibility and commercial viability, deferred oil exploration costs need not be assessed for impairment.

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Facts and circumstances that would require an impairment assessment as set forth in PFRS 6, Exploration for and Evaluation of Mineral Resources, are as follows: • The period for which the Group has the right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed; • Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; • Exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and • Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

As of December 31, 2011 and 2010, the carrying value of deferred oil exploration costs amounted to $5.8 million and $6.0 million, respectively (see Note 9). There was no impairment recognized by the Group in 2011 and 2010 based on the assessment of the criteria above.

Impairment of Deferred Geothermal Costs The Group determines impairment of projects based on the technical assessment of its consultants in various disciplines or based on management’s decision not to pursue any further commercial development of its exploration projects.

As of December 31, 2010, deferred geothermal costs amounted to $1.28 million (see Note 10). There was no impairment recognized by the Group in 2010 based on its assessment.

Accrued Retirement Liability and Retirement Expense The determination of the Group’s accrued retirement obligation and annual retirement expense is dependent on the selection of certain assumptions used in the actuarial calculations. Those assumptions include, among others, discount rates, expected return on plan assets and salary increase rates (see Note 17).

While the Group believes that the assumptions are reasonable and appropriate, significant differences between actual experiences and assumptions may materially affect the Group’s accrued retirement obligation and annual retirement expense.

As of December 31, 2011 and 2010, accrued retirement liability amounted to $41,862 and $43,217, respectively (see Note 17).

Asset Retirement Obligation - Oil Production Plug and abandonment costs are based on estimates made by the service contract operator. The timing and amount of future expenditures are reviewed annually. Liability and capitalized costs included in property, plant and equipment is equal to the present value of the Group’s proportionate share in the total plug and abandonment costs of the consortium on initial recognition.

The amount of asset retirement obligation in the consolidated statements of financial position is increased by the accretion expense charged to operations using the fifteen percent (15%) effective interest method over the estimated remaining term of the obligation.

As of December 31, 2011 and 2010, asset retirement obligation amounted to $474,293 and $402,793, respectively (see Note 15).

Asset Retirement Obligation - Wind Energy and Geothermal Energy Projects In determining the amount of provisions for dismantling, removal and restoration costs, assumptions and estimates are required in relation to the expected costs of dismantle, remove or restore sites and infrastructure

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when such obligation exists. As of December 31, 2011 and 2010, the Group made an assessment that such obligation does not exist yet in the current stage of operations of the wind energy and geothermal energy projects.

Deferred Tax Assets The Group reviews the carrying amounts of deferred tax assets at each reporting date and reduces them to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax assets to be utilized. The Group believes that it will generate sufficient future taxable profit to allow all of the deferred tax assets to be utilized.

As of December 31, 2011 and 2010, deferred tax assets amounted to $0.08 million and $0.23 million, respectively. As of December 31, 2011 and 2010, the Group did not recognize deferred tax assets amounting to $0.19 million and $0.09 million because the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized (see Note 18).

Determination of Fair Values of Financial Assets and Liabilities The fair value determinations for financial assets and liabilities are based generally on listed market prices or broker or dealer price quotations. If prices are not readily determinable or if liquidating the positions is reasonably expected to affect market prices, fair value is based on either internal valuation models or management’s estimate of amounts that could be realized under current market conditions, assuming an orderly liquidation over a reasonable period of time (please see Note 22 for the fair value of financial assets and liabilities).

4. Cash and Cash Equivalents This account consists of:

Short-term investments Cash on hand and in banks

2011 $20,961,432

2010 $15,900,971

942,852 $21,904,284

183,513 $16,084,484

Cash in banks earn interest at the prevailing bank deposit rates. Short-term deposits are made for varying periods of up to three months depending on the immediate cash requirements of the Group, and earn interest at the prevailing short-term deposit rates.

5. Financial Assets at FVPL This account consists of:

Marketable equity securities Investment in golf club shares Marketable debt securities

2011 $98,069

2010 $97,609

10,949

13,572

− $109,018

1,441,065 $1,552,246

Net gain (loss) on fair value changes on financial assets at FVPL included in consolidated statements of income amounted to ($79,588), $5,856 and $9,786 in 2011, 2010 and 2009, respectively.

2011 ANNUAL REPORT

51

Marketable debt securities outstanding in 2010 matured on February 15, 2011.

6. Receivables This account consists of: 2011

2010

$2,096,717

$2,608,834

4,476

767

36,010

195,895

2,137,203

2,805,496

61,187 $2,076,016

61,187 $2,744,309

Accounts receivable from: Consortium operator Others Interest receivable Less allowance for impairment losses

The Group’s receivables are mainly due from consortium operator and are due within one year. Carrying values as of year-end approximate fair values (see Note 22).

The table below shows the disclosure of reconciliation of allowance for impairment losses for receivables from a consortium operator:

Balance at beginning of year

2011 $61,187

2010 $58,062

Effect of foreign currency translation Balance at end of year

− $61,187

3,125 $61,187

7. Advances, Prepaid Expenses and Other Current Assets This account consists of :

Advances to contractor - current portion

2011 $5,991,040

2010 $−

Deferred financing costs - undrawn portion (Note 14)

862,218

−

Input value added tax (VAT)

452,374

133,226

Prepaid expenses

169,188

25,323

63,125

63,125

239

1,905

25,915 $7,564,099

21,193 $244,772

Restricted cash Software licenses Others

Advances to contractor pertains to the downpayment for the EPC contract with EEI Corporation on the construction of power plant in the MGPP (see Note 8). This will be applied against future billings in the course of construction. The total amount of advances is $6.86 million. The current portion of $5.99 million, which is estimated to be applied against progress billings within one year from reporting date is classified under “Advances, prepaid expenses and other current assets”. The non-current portion of $0.87 million, which is

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estimated to be applied against progress billings beyond one year from reporting date is classified under the account “Advances and other noncurrent assets”.

Input VAT is recoverable in future periods.

Prepaid expenses include prepaid insurance and professional fees.

Restricted cash represents the Parent Company’s share in the escrow fund to secure payment and discharge of Parent Company’s obligations and liabilities under the Floating Production Storage and Offloading (FPSO) contract. The amount was deducted from the Parent Company’s share on lifting proceeds during the first lifting made by Etame in November 2002 and will be paid back to the Parent Company’s at the end of the contract.

Software licenses is presented net of accumulated amortization amounting to $4,603 and $2,403 in 2011 and 2010, respectively. “Others” pertain to advances to employees, supplies and deposits.

2011 ANNUAL REPORT

53

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Net book value

Balance at end of year

$11,745,026

8,391,972

–

1,521,188

Depletion, depreciation

Disposals

6,870,784

20,136,998

–

327,142

1,237,321

$18,572,535

Wells, Platforms and Other Facilities

Balance at beginning of year

Accumulated depletion and depreciation

Balance at end of year

Disposals

Reclassification from deferred oil exploration costs (Note 9)

Additions (Note 15)

Balance at beginning of year

Cost

Net book value

$5,223,832

–

$11,294,017

–

1,855,082 10,247,054

Depletion and depreciation

Balance at end of year

–

5,223,832

21,541,071

8,391,972

5,223,832

–

227,287

1,176,786

$–

$20,136,998

FCRS and Production Wells - Geothermal

Balance at beginning of year

Accumulated depletion and depreciation

Balance at end of year

Reclassification from deferred oil exploration and geothermal costs (Note 9)

Additions (Note 15)

Balance at beginning of year

Cost

Wells, Platforms and Other Facilities

$130,526

98,232

36,434

61,798

$228,758

–

60,514

$168,244

Transportation Equipment

$120,649

506,714

–

50,672

456,042

627,363

–

–

10,480

$616,883

Office Condominium Units and Improvements

2010

$178,008

546,465

39,751

506,714

724,473

–

97,110

$627,363

Office Condominium Units and Improvements

2011

$106,446

61,798

–

27,611

34,187

168,244

–

–

59,711

$108,533

Transportation Equipment

$163,571

199,415

69,922

129,493

362,986

–

101,249

$261,737

Office Furniture and Other Equipment

8. Property, Plant and Equipment The roll forward analyses of this account as of December 31, 2011 and 2010 are as follows:

$3,440,337

–

–

–

3,440,337

–

3,440,337

$–

Construction in progress

$132,244

129,493

(485)

71,156

58,822

261,737

(76,995)

–

164,357

$174,375

Office Furniture and Other Equipment

$867,672

–

–

–

867,672

–

867,672

$–

Land and land improvements

$12,104,365

9,089,977

(485)

1,670,627

7,419,835

21,194,342

(76,995)

327,142

1,471,869

$19,472,326

Total

$21,297,963

11,091,166

2,001,189

9,089,977

32,389,129

6,400,618

4,794,169

$21,194,342

Total

Depletion of wells, platform and other facilities is part of oil production.

Foreign Operations Gabon, West Africa In December 2008, appraisal and development drilling in the Ebouri, the third oil field, in the Etame Block began. Two jack up drilling rigs, the GSF Adriatic VI and the Pride Cabinda were in operation as of December 31, 2008. The first horizontal development well, the Ebouri-2H, was completed on December 15, 2008 while the appraisal well North Ebouri-1 was also successfully drilled, confirming a wider reservoir area. Consequent to this finding, a sidetrack well, the North Ebouri-ST-1, was initiated at year-end of 2008 to confirm the revised Ebouri oil field map and to locate an optimal position for a second horizontal production well. The North Ebouri sidetrack encountered substantial oil-filled Gamba sandstone and established significant additional reserves north of the originally mapped field development outline. Two prospects, the North Etame and the South East Etame, were intended to be drilled back to back by the Pride Cabinda after drilling the appraisal well North Ebouri-1.

The North Etame well, however, encountered water bearing sands and has been abandoned.

The third prospect, the South East Etame, was spudded on May 18, 2010 and was declared a “discovery” well.

The Ebouri production platform that was installed on site in the third quarter of 2008 received the first oil from the first production well in January 2009 and from the second production well in April 2009.

Seven (7) wells were drilled in 2010 using the jack up rig Sapphire Driller of Vantage Drilling Co. Four (4) were exploration wells and three (3) were development wells.

The daily production from the three (3) oilfields (Etame, Avouma and Ebouri) in 2011 averaged 22,100 barrels.

Twelve (12) liftings (sales) were made during the year with an average lifting volume of 610,797 barrels.

Etame Expansion Project (EEP) The EEP is an on-going effort led by the block Operator – VAALCO Energy, Inc – to evaluate the possibility of increasing production to 25,000-30,000 barrels per day. Tapping both internal Consortium technical resources and external third-party Consultants, the EEP comprises four separate but related investigations: 1) Subsurface simulation study to determine remaining recoverable reserves in low, mid, and high cases; 2) Drilling and completion review to ascertain drilling costs, duration, and design modifications for future well drilling and completion; 3) Facilities evaluation of thirteen potential development options that led to the identification of six hybrid development concepts; and 4) Commercial and economic modeling of the six development concepts to assess execution duration, risks, and profitability.

In 2011, the EEP team recommended two options to be carried further into the pre-front end engineering design (Pre-FEED) stage. These are the “Etame Production Platform” option and the “Nautipa” option. The former will entail the construction of a full production platform in the central Etame producing field. The other, more preferred, scheme will continue to utilize the current FPSO vessel Petroleo Nautipa throughout the field life combined with a new wellhead platform in Etame. Both cases are now the subject of pre-FEED analysis.

Avouma and Ebouri Platform Repairs In anticipation of additional drilling and higher crude extraction, several rehabilitation and upgrade works were implemented in the Avouma and Ebouri production platforms. Both platform decks were extended to accommodate more equipment and personnel and these were completed in the last quarter of 2011. The upgrade of the electrical system to better support the electrical submersible pumps in both platforms were started in 2011 and expected to be completed by middle of 2012.

One facility being installed in the Avouma platform is the water knock out facility which will process the crude with high water content before they are transferred onto the FPSO. Thus, the FPSO will be able to handle bigger volume of oil and increase daily production. This work was started in the second quarter of 2011 and is expected to be operational by middle of 2012.

2011 ANNUAL REPORT

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FPSO Integrity Assessment The Petroleo Nautipa is a FPSO vessel that the Etame Consortium leases from the owner Tinworth Pte Ltd. On site for nearly 10 years now, the vessel has a ship design capacity of about 1.1 million barrels of oil and an operational handling capacity of 30,000 barrels of total fluids per day. Given the Consortium’s plan of higher and longer crude production, a study was started in 2011 to determine whether it is technically feasible and economically viable to continue using the Petroleo Nautipa until 2022. Results of the study contracted to Bennett and Associates, LLC and to Alliance Marine Services will be completed in 2012.

Shallow Water Exploration Project (SWEP) Current production in the Gabon concession is limited to known fields lying at the center of the permit area in about 80 meters of water. The goal of SWEP is to identify petroleum prospects for future drilling in the northern and northeastern parts of the concession close to the Gabon shore where water depths are 30 meters or less.

The SWEP kicked off in 2011 with the interpretation of existing 3D seismic data acquired in 1997. Geological analyses were also performed on boreholes within the Etame permit block and from wells in adjoining blocks via data trade with other Operators. The Partners carried out a new 3D seismic data acquisition from late October to mid November 2011 over a 240 square kilometer area. The newly acquired 3D data are currently being processed for interpretation work from late 2012 to early 2013.

2012 Drilling Program Due to the tight availability of offshore drilling rigs worldwide and conflict with on-going construction works in the Ebouri and Avouma platforms, the 2011 drilling program had to be moved to 2012. A drilling rig has been engaged by the JV Partners and is set for mobilization to the site by late June 2012. The drilling campaign will start in Ebouri, where two wells, including a pilot hole, will be drilled. In Avouma, the rig will drill a development well followed by a work-over of an existing well. Once these firm well commitments are completed by around December 2012, the JV Partners may extend the rig on site to drill two option wells – an appraisal well in the North Tchibala area and an exploration target in Southeast Etame.

Philippine Operations SC 14-C2 – West Linapacan, Northwest Palawan The Parent Company has a working interest in Block “C” of SC 14 situated in offshore Northwest Palawan where oil discoveries were made.

On December 15, 1975, pursuant to Section 7 of the Oil Exploration and Development Act of 1972, the JV partners entered into a service contract with the Philippine Government through the DOE for the exploration, exploitation and development of contract area in offshore Northwest Palawan, Philippines, which was amended from time to time.

Production activities in the West Linapacan Oil field (WLO) remained on suspension mode for the last fourteen (14) years. The investment in WLO included in “Wells, platforms and other facilities” account under “Property, Plant and Equipment” in the consolidated statements of financial position amounted to $6.7 million as of December 31, 2011 and 2010. Management assessed that the said investment is fully recoverable as SC 14-C is not yet expired, with the 15-year extension of the SC as approved by the DOE, from December 18, 2010 to December 18, 2025, and the existing redevelopment activities led by Pitkin Petroleum PLC (Pitkin).

Pitkin completed during the first quarter of 2008 a farm-in to SC 14-C (WLO) on the following terms: • To earn 58.29% participating interest in consideration of $1.5 million and to pay the cost of a Geological and Geophysical(G & G) Work Program; • Option to fund the drilling of one well; and • Option to fund the development costs of the oilfield attributable to the participating interest of the Farmors.

As part of the farm-in obligations of Pitkin to maintain the SC in good standing, Pitkin obtained from DOE the 15-year final extension of SC 14-C (WLO), from December 18, 2010 to December 18, 2025 in line with

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similar extensions granted to other SCs in Palawan, (e.g., SC 6-A Octon and Cadlao). The extension carries the following financial obligation to the DOE: 1) One-time development assistance of $30,000; 2) One-time scholarship fund of $20,000; and 3) Yearly training fund of $20,000 during exploration period and $50,000 during production period.

The aforementioned obligations may be treated as operating expenses that are cost-recoverable during production. Pitkin continues to seek funding from foreign investors in order to pursue its redevelopment of SC 14-C (WLO).

Earlier plans by Operator Pitkin to drill West Linapacan by 2011 failed to materialize due to unresolved technical questions on the reservoir character of the field. Instead, Pitkin farmed-out half of its 58.29% interest in SC14C2 to RMA (HK) Ltd, a subsidiary of Resource Management Associates Pty Ltd of Australia. The Deed of Assignment for this farm-out filed on April 13, 2011 was subsequently approved by the DOE on July 4, 2011.

The farm-out has no effect on the Parent Company’s 1.034% interest and status as free-carried up to the drilling of one well.

Contingent on the results of a comprehensive reservoir simulation study to be undertaken in early 2012, a well may be drilled by end of 2012.

Galoc Oilfield Team Oil (TEAM) and Cape Energy (CAPE) (collectively referred to as “the Parties”), both foreign companies, signed a memorandum of agreement (MOA) dated September 23, 2004 with the participants of SC 14-C regarding the development of a portion of SC 14-C, Galoc area. The Parties will shoulder the development cost in exchange for 75% of the participating interest. The implementation of this MOA is subject to the satisfaction of certain conditions. On August 22, 2005, the Parties assigned their rights and obligations to Galoc Production Co., WLL (GPC), a corporation organized in Bahrain with Vitol, a European oil trading company, as majority stockholder.

On October 7, 2007, the development of the Galoc oil field began, which involved the construction of two subsea horizontal production wells under a so-called “batch drilling” program. Two production wells, Galoc-3 and Galoc-4 were drilled and later tied back to the FPSO facility via a seabed pipeline and mid-water riser system.

Drilling of the Galoc-3 and Galoc-4 development wells was finalized in late January 2008 and completion activities for production proceeded. During the middle of the year 2008, a series of typhoons crossed the area.

This hampered subsea operations and even damaged critical subsea equipment. On October 9, 2008, oil was made to flow from the field and onto the production facility. Since then, three cargoes totaling 604,683 barrels of oil, the last being on December 30, 2008 with 198,000 barrels, were offloaded to a buyer’s tanker.

During the first quarter of 2009, a series of bad weather in the offshore Palawan area adversely affected operations and resulted to damage in the production facilities. Continued delays in production and mounting repair and services costs prodded the Group’s decision to withdraw from the joint venture on June 30, 2009.

Farm-in Agreement (FA) On September 23, 2004, TEAM and CAPE entered into a FA with the SC No. 14-C (Galoc) JV partners for the development of the Galoc Field. The FA was concluded in a Deed of Assignment (DOA) dated August 22, 2005 where TEAM and CAPE designated GPC as the special-purpose company to accept the assigned participating interest and to act as operator of the Galoc production area.

Under the FA and DOA, GPC will pay 77.72% of the cost to develop the Galoc Field in exchange for a 58.29% participating interest in the area. Other significant terms and conditions of the FA are as follows: 1) That GPC, together with the other paying party (Nido Petroleum), be allowed to first recover their share of the development cost from crude oil sales proceeds from the Galoc Field after production expenses.

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2) That GPC be assigned its pro-rata share of the $68.0 million historical cost recovery of the Galoc block equivalent to $34.0 million to be recovered pursuant to the terms of the Block C agreement below.

3) That GPC will reimburse the joint venture partners (except GPC and Nido Petroleum) for expenditures previously incurred in relation to the Galoc Field as follows: a) b)

$1.5 million payable out of 50% of GPC’s share of the Filipino Participation Incentive Allowance (FPIA); and $1.5 million payable upon reaching a cumulative production of 35.0 million barrels of oil from the Galoc Field.

Joint venture partners as of December 31, 2007 consist of GPC (58.291%), Nido Petroleum (22.279%), The Philodrill Corporation (Philodrill) (7.018%), Alcorn Gold Resources Corporation (1.531%), Forum Energy Philippines Corporation (2.276%), Oriental Petroleum and Minerals Corporation (4.965%), Linapacan Oil Gas and Power Corporation (2.607%) and the Parent Company (1.034%).

Extended Production Test (EPT) Agreement On August 10, 2006, an EPT agreement was made and entered into by the DOE and GPC and its partners (referred to as “contractors” under the EPT agreement). The purpose of the EPT is to obtain dynamic performance data for the Galoc reservoir and to confirm the presence and continuity of at least 2 significant channel sandbodies by undertaking an EPT of a well designed to probe each channel.

In consideration of the risk and undertaking assumed by the contractor under the EPT agreement, the contractor, shall market crude produced and saved from the EPT and is allowed to retain the gross proceeds for the recovery of 100% of all operating expenses incurred in the EPT. Any amount of gross proceeds in excess of the cost of the EPT shall be subject to 60-40 sharing in favor of the Philippine Government through the DOE. The duration of the EPT is a minimum of 90 days of actual crude flow from at least one well excluding delays which arise from breakdowns, repairs or replacements, well conditions or other conditions. The EPT will be terminated upon the earliest of 182 days of actual crude production or when sufficient data has been obtained or viability of the Galoc Field has been established by the contractor in conjunction with the DOE. On termination, the contractor shall either declare commerciality of the field and commit to undertake development, or declare field to be noncommercial for further development or production and commence abandonment and demobilization of the EPT facilities.

Joint Operating Agreement (JOA) On September 12, 2006, the joint venture partners entered into a JOA, amending the existing JOA, for the purposes of regulating the joint operations in the Galoc Block. The JOA shall continue for as long as: 1) the provisions in SC 14 in respect of the Galoc Block remain in force; and 2) until all properties acquired or held for use in connection with the joint operations has been disposed of and final settlement has been made between the parties in accordance with their respective rights and obligations in the Galoc Block; and without prejudice to the continuing obligations of any provisions of the JOA which are expressed to or by their nature would be required to apply after such final settlement.

Block C Agreement In 2006, Block C Agreement was entered into by the joint venture partners (the Galoc Block Owners) of SC 14-C Galoc to specify gross proceeds allocation as well as the rights and obligations relating to their respective ownership interests in the Galoc Block (the “Galoc Contract Area Rights”) and their respective ownership interests in the Remaining Block (except for GPC).

The agreement also clarifies how GPC and Philodrill, which are the designated Operator of the Galoc Block and the Remaining Block, respectively, shall work together to perform their obligations and exercise their rights as Operator.

The Allocation of Contract Area Rights under Section 3 of the Block C Agreement provides that:

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1) GPC shall be entitled to the FPIA, Production Allowance, Recovery of Operating Expenses and the Net Proceeds of the SC 14 insofar as it relates to the Galoc Block.

2) The portion of the Galoc Contract Area Rights allocable as FPIA, Production Allowance and Net Proceeds shall be distributed as follows: a) b) c)

GPC shall be allocated an amount equal to its participating interest in the Galoc Block which is currently 58.29%.

Nido and Philodrill shall be allocated an amount equal to 17.50% and 4.38%, respectively.

The balance of 19.83% shall be allocated to the Remaining Block (except GPC) in accordance with item number 5 below.

3) The portion of the Galoc Contract Area Rights allocable to recovery of operating expenses (the reimbursement amount) shall be distributed as follows: a) An amount equal to the operating expenses incurred by the Galoc Block Owners in respect of production costs on and from the date of the 2nd Galoc well being brought on stream shall be allocated to each Galoc Block Owner in accordance with each Galoc Block Owner’s participating interest. b) An amount equal to the Operating Expenses incurred by GPC and Nido in respect of the Galoc Block (excluding the $68.0 million historical cost assigned to the Galoc Block pursuant to the FA) shall be allocated 77.72% to GPC and the balance of 22.28% to Nido. c) Any reimbursement amount remaining after applying the provisions of 3a and 3b above shall be allocated 58.29% to GPC, 17.5% to Nido, 4.38% to Philodrill and 19.83% to the Galoc Block Owners (except GPC but including Nido and Philodrill only in relation to its remaining 4.78% interest and its 2.02% interest in the Galoc Block, respectively) until all the Galoc Block Owners have received in aggregate a total of $34.0 million in accordance with this provision. The 19.83% allocated to the Galoc Block Owners (except GPC) shall be distributed by GPC in accordance with item number 5 below. d) Any reimbursement amount remaining after applying the provisions of 3a, 3b and 3c above shall be allocated 38.86% to GPC and 17.50% to Nido and the balance of 43.64% to the Galoc Block Owners (except GPC but including Nido only in relation to its remaining 4.78% interest in the Galoc Block) until all the Galoc Block Owners have received in aggregate a total of $34.0 million in accordance with this provision. The 43.64% allocated to the Galoc Block Owners (except GPC) shall be distributed by GPC in accordance with item number 5 below.

4) After the provisions in Clause 3.3 of the Block C Agreement (as detailed in item number 3 above) have been satisfied, all the Galoc Block Owners shall share the reimbursement amount in accordance with each Galoc Block Owner’s participating interest as follows: a) b)

GPC, Nido and Philodrill shall receive 58.29%, 17.50% and 4.38%, respectively; and The balance of 19.83% shall be distributed by GPC to the Galoc Block Owners (except Galoc but including Nido and Philodrill only in relation to remaining 4.78% interest and its 2.02% interest in the Galoc Block, respectively) in accordance with Clause 5 of the Block C Agreement (see item number 5 below).

5) All amounts due to the Galoc Block Owners (except GPC) pursuant to Clauses 3.2, 3.3c, 3.3d and 3.4 (see numbers 2, 3c, 3d and 4 above) (the “Outstanding Balance”), shall be distributed by GPC in accordance with written instructions to distribute the Outstanding Balance authorized by all the other Galoc Block Owners.

The Block C agreement shall terminate when SC 14 terminates.

Lifting Agreement In 2008, GPC and its partners entered into a lifting agreement which provides for the lifting procedures to be 2011 ANNUAL REPORT

59

applied by GPC to ensure that: 1) 2) 3) 4) 5)

each lifter is able to lift its Lifting Entitlement on a timely basis; each lifter receives its Actual Lifting Proceeds; overlift and underlift position of each party are monitored and settled; each lifter pays its Actual Lifting Deduction Payment to the GPC; and GPC has sufficient funds in the Joint Account to pay the Government and the Filipino Company Entitlement.

The terms of the Block C Agreement shall prevail in the event of a conflict with terms of this agreement.

The agreement shall terminate when SC 14 terminates, unless terminated earlier by the unanimous written agreement by the parties.

Decommissioning Agreement (DA) On December 12, 2008, GPC and its partners entered into a decommissioning agreement which provides for the terms upon which the wells, offshore installations, offshore pipelines and the FPSO facility used in connection with the joint operations in respect of the Galoc Development shall be decommissioned and abandoned in accordance with the laws of the Philippines including all regulations issued pursuant to the Oil Exploration and Development Act of 1972.

In accordance with the DA, each party has a liability to fund a percentage of the decommissioning costs (to be determined at a later date), which shall be equal to the party’s percentage interest. The funding of the decommissioning costs shall commence on the date (“Funding Date”) GPC issues a written notice to the DOE after completion of the EPT, specifying the date of commencement of commercial operations from the Galoc Block. The decommissioning cost, as funded, shall be kept in escrow with a bank of international standing and repute to be appointed by GPC. The DA shall terminate when SC 14 terminates.

Assignment of Interest (AI) On June 30, 2009, the Parent Company, with the approval of the DOE, proportionately assigned its entire 1.03% participating interest in the Galoc Block to other joint venture partners. Under the agreement, the Parent Company relinquishes its rights over the Galoc Block in consideration for the joint venture partners’ reimbursement of costs incurred by the Parent Company corresponding to the Galoc Block. As a result of the assignment of interest, the Group received net proceeds of $782,215 from other joint venture partners.

The profitability of petroleum operations and the full recovery of unamortized costs of wells, platforms and other facilities are dependent upon the favorable outcome of the Study Agreement, the discoveries of additional oil in commercial quantities and the success of future development thereof.

As of December 31, 2011 and 2010, the Parent Company has 1.034% participation in SC 14-C (West Linapacan).

MGPP On September 2, 2011, MGI entered into an EPC contract with EEI Corporation (EEI) in which the latter shall design, procure and construct the 20 MW Maibarara Geothermal Power Plant project, composed of the main plant and balance of plant at the Maibarara project site in Brgy. San Rafael, Sto. Tomas, Batangas. EEI shall acquire the services of Fuji Electric Co., Ltd. (“Fuji Electric”) to design the main plant. Fuji Electric shall supply all major permanent equipment such as steam/turbine generator, cooling tower, condenser, etc.

The contract price is a fixed price amounting to $37 million. The construction shall be completed within 24 months from the issuance of notice to proceed.

The power plant site had been leveled during the fourth quarter of 2011 in preparation for EEI mobilization by

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January 2012. There also have been pre-construction activities done in 2011, in preparation for the construction of Fluid Collection and Reinjection System (FCRS) such as construction of access roads within the project site, preparation of the cold re-injection pad, and construction of branchline trench.

Expenditures for the progress billing from the EPC contract, power plant site leveling and FCRS pre-construction activities are included in the “Construction in Progress” account.

Borrowing cost In 2011, MGI capitalized borrowing costs relating to finance charges incurred in the construction of the power plant. The construction is expected to be completed in 2013. Capitalized borrowing costs amounted to $17,279 in 2011. The rate used to determine the amount of borrowing costs eligible for capitalization is 7.97%, which is the effective interest rate of loans.

Land In 2011, MGI acquired parcels of land from Science Park of the Philippines, Inc. and Philtown Properties, Inc. amounting to $0.6 million and $0.2 million, respectively, to be used as power plant site in the Maibarara Project Area in Sto. Tomas, Batangas.

9. Deferred Oil Exploration Costs The movements in deferred oil exploration costs follow:

Balance at beginning of year Internal development Reclassification to wells, platforms and other facilities (Note 8) Balance at end of year

2011 $6,012,163

2010 $4,073,670

996,291

2,265,635

(1,176,786) $5,831,668

(327,142) $6,012,163

Under the SCs entered into with the DOE covering certain petroleum contract areas in various locations in the Philippines, the participating oil companies (collectively known as Contractors) are obliged to provide, at their sole risk, the services, technology and financing necessary in the performance of their obligations under these contracts. The Contractors are also obliged to spend specified amounts indicated in the contract in direct proportion to their work obligations.

However, if the Contractors fail to comply with their work obligations, they shall pay to the government the amount they should have spent but did not in direct proportion to their work obligations. The participating companies have Operating Agreements among themselves which govern their rights and obligations under these contracts.

The accumulated costs incurred in connection with the exploration contracts are shown under “Deferred oil exploration costs” account in the consolidated statements of financial position. The full recovery of these deferred costs is dependent upon the discovery of oil in commercial quantities from any of the petroleum concessions and the success of future development thereof.

SC 51 - East Visayas On August 5, 2005, a Farm-in Agreement (FIA) was signed by the SC 51 members, including the Parent Company, as Assignors, with Australasian Energy Limited, a corporation existing under the laws of the Isle of Man, and Ottoman Energy Limited, a company organized under the laws of Western Australia as Assignees. The Assignors assigned 80% of their participating interest to the assignees in SC 51 in consideration for the work obligation including funding, at the Assignees’ sole cost of a seismic survey program. The farminee submitted to the DOE a work program composed of drilling one well and acquisition of seismic data.

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In 2008, the 3D seismic data gathered the previous year were processed by CGG-Veritas and were used to produce the prospect maps of two potential trapping structures the Argao and Cabilao. Technical surveys over the drilling sites were also conducted in 2008.

In 2010, the Operator NorAsian Energy Ltd. (NorAsian) presented its drilling program for an onshore well in San Isidro, Northern Leyte, in lieu of an exploration well that would be drilled in the Offshore Cebu. As part of its fund raising activity, it proposed to amend the FIA to accommodate a new Australian Investor, Swan Oil and Gas Ltd. (Swan). The amendment defines the onshore Leyte area or the North Block, where the two farminees intend to drill an exploration well at their sole cost and consequently be assigned a 40% interest each on the block.

Their interests are retained when a second onshore well is drilled. On both cases, the farmors (including the Parent Company) are carried free.

The South or the Offshore Area that covers the Argao prospect is also defined. Either of NorAsian or Swan or both can opt to drill the Argao Prospect and earn 80% interest in the whole SC 51 contract area. The farmor partners, Alcorn Gold Resources Corporation (Alcorn), Trans-Asia Oil and Energy Development Corporation (TransAsia) and the Parent Company, approved the proposed amendment. A final draft of the Amended FIA is being prepared by NorAsian for signature of all the parties.

In the meantime, NorAsian prepared for the drilling of the Duhat-1 exploration well in San Isidro, onshore Northwest Leyte in the second quarter of 2011 when the drilling rig is released from a geothermal project in mid to end of February 2011.

As a DOE commitment for the Consortium’s Sub-Phase 3 (SP3) work program, the on-shore vertical exploratory well Duhat-1 was spudded in San Isidro, Northwest Leyte on April 20, 2011 to test the hydrocarbon potential of service contract’s northern block. After it was sidetracked, the well (Duhat-1A) reached a total depth of 321m but had to be abandoned on May 25, 2011 after persistent mechanical drilling problems. Although the well failed short of reaching its 1,000 m programmed total depth, the Operator/Farminee NorAsian Energy Ltd (NAEL) obtained DOE approval to consider Duhat-1A as satisfying the Consortium’s SP3 work commitment. However, this well will not be considered as an “earning” well by the farmors - Alcorn, Trans-Asia, and the Parent Company.

NorAsian’s application on February 3, 2011 with the DOE for the approval of Swan’s farm-in for 40% participating interest in SC 51 was approved by the DOE on July 1, 2011. On August 31, 2011, the DOE also approved the consortium’s entry into Sub-Phase 4 (August 1, 2011 to July 31, 2012) with a revised work commitment of acquiring and interpreting 100 line-km of 2D seismic data in northwest Leyte at a budget of US$3.0 Million. In November 2011, NorAsian completed the scouting survey for this planned 2D seismic study.

It subsequently engaged BGP SE Asia to conduct the 2D seismic survey at a slightly expanded budget of $4.3 million. Seismic acquisition and interpretation are expected to be completed by the first quarter of 2012.

In December 2011, the SC 51 partners reached an internal agreement to revise the farm-in terms to: 1) divide the SC 51 contract area into a northern (northwest Leyte) and southern (offshore Cebu) blocks; 2) the assignment of NorAsian’s putative 40% interest in the south block to Swan thus relinquishing all of NorAsian’s interest in offshore Cebu; 3) the drilling of a second on-shore well in northwest Leyte to complete NorAsian’s farm-in; and 4) a deadline of April 30, 2012 for Swan to commit to the drilling of the offshore Argao prospect in Cebu, or forfeit all its interests and rights in SC 51.

SC 6-A - Octon-Malajon Block In March 2007, Vitol GPC Investments S.A. (VGI) negotiated a farm-in to the SC 6-A in offshore Palawan. Under the agreement, Vitol will conduct a study on the prospectivity of the block over a one-year period until March 2008, after which it will decide whether to continue or complete the farm-in process.

GPC Investments SA (formerly Vitol GPC Investments SA) gave notice in November 2010 of its decision not to exercise its option on the farm in interest in SC 6-A. This followed the failure of the Galoc Consortium to commit to the second development phase of the Galoc Field. Thereafter, Philodrill re-assumed the Operatorship of the Octon Block.

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To maintain the validity of the SC, the Octon Joint Venture submitted to the DOE in December, a $546,000 work program for 2011. It consisted of the reprocessing of 400 sq. km. of the 1997 3D seismic data. Reprocessing would enhance the quality of the seismic information, which would enable the mapping of potential structural drilling targets in the northern portion of the contract area.

Following the departure of Vitol GPC from the SC6A Consortium in late 2010, Pitkin Petroleum Plc, a UKregistered company, signed in July 2011 a farm-in agreement with the consortium members for a 70% participating interest in the block. As farminee, Pitkin will spend, at its own cost, about US$5.0 million to acquire, process, and interpret 500 sq. km. of 3D seismic data in Octon. Should it elect to exercise its options, Pitkin may drill up to two production wells at no cost to the farming-out consortium members.

On December 6, 2011, the DOE approved the Deed of Assignment transferring the Operatorship and 70% of the service contract interest to Pitkin. Consequently, the Parent Company’s interest in the block was reduced from 16.67% to 5.001% but the Parent Company will be carried free in all subsequent exploration costs up to the drilling of two Octon wells.

SC 47 - Offshore Mindoro and Panay The DOE approved in January 12, 2011 a one-year extension of the Consortium’s Sub-Phase 2 (SP2) work program deadline to July 10, 2011. This would enable the Operator, PNOC Exploration Corporation (PNOC-EC), to finish the evaluation of 2D seismic data acquired by the Partners in 2010. PNOC-EC’s evaluation identified at least six potential leads, most of which were in deep water. To further de-risk these leads and enable the Partners to attract potential farminees, PNOC-EC requested the DOE on June 21, 2011 for a further one-year extension of SP2 to carry out a 500-km 2D seismic survey and a source-to-reservoir migration study. PNOC-EC repeated the extension request in August 2011 but no official DOE response had been received till the end of 2011. In the meantime, PNOC-EC is completing the reservoir study, preparing the program for the additional 500 km 2D seismic survey, and discussing farm-in opportunities with potential investors.

As of December 31, 2011, 2010 and 2009, the corresponding percentages of the Group’s participation in the various SC areas are as follows: 2011

2010

2009

NW Palawan - SC 6-A

5.001%

16.670%

16.670%

East Visayas - SC 51

4.012%

4.012%

4.012%

Gabonese Oil Concessions

2.525%

2.525%

2.525%

Offshore Mindoro - SC 47

2.000%

2.000%

2.000%

10. Deferred Geothermal Costs Geothermal Renewable Energy Service Contract (GRESC) No. 2010-02-012 On February 1, 2010, the Parent Company signed GRESC No. 2010-02-012 covering the Maibarara Geothermal Field (“the field”) in Laguna and Batangas areas, following a Philippine Energy Contracting Round for Geothermal held by the DOE in November 2009, where the Parent Company emerged as the winning bidder. The field had been previously explored and relevant resource data identified certain portions thereof as having potential stored heat capacity that can produce electricity in commercial quantities.

Under this service contract, the Parent Company committed to perform the following during the first contract year of the pre-development stage: (i) Local Government Units (LGU) and stakeholders coordination; (ii) geologic and geophysical studies and resource assessment; (iii) land rights survey and lease; (iv) obtain DENR and other permits; (v) establish logistics station; (vi) land and water supply preparations; and (vii) well work-over and drilling preparations. The expected minimum expenditures for the first contract year amounts to $560,000.

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On the second contract year, the Parent Company committed to perform (i) work-over of existing wells; (ii) flowtesting and bore output measurements; (iii) engineering and design of steam/brine lines; (iv) grid impact study; and (v) start site preparation and construction of the fluid collection and disposal system and power plant. The expected minimum expenditures is about $17.8 million.

Prior to the development phase, the Parent Company incurred research costs related to its geothermal projects amounting to $22,546 in 2009 which were recorded as “research cost” included under “General and administrative expenses” in the consolidated statements of income.

On January 5, 2011, the DOE approved the Deed of Assignment and Assumption transferring the GRESC from the Parent Company to MGI. Deferred geothermal costs pertain to the development costs incurred for the Geothermal Energy Project. As of December 31, 2011 and 2010, these costs mainly come from development activities, as follows: 2011 $8,151

2010 $3,383

Geologic and geophysical studies and resource assessment

166,337

93,730

Land rights survey and lease

127,662

53,131

Obtainment of DENR and other permits

110,055

53,130

LGU and stakeholder coordination

19,605

17,380

Land and water supply preparations

630,067

296,453

Preparation for well work-over and drilling

217,246

184,918

Work-over of existing wells

2,051,582

225,419

Drilling of new wells

Establishment of logistics station

1,080,823

289,441

Flow-testing and bore output measurements

394,263

38,313

Engineering and design of steam/brine lines

126,946

12,900

18,935

15,755

272,160 $5,223,832

– $1,283,953

Financing, grid impact study and power purchase contract Construction fluid collection

The activities during the development phase are as follows: •

LGU and stakeholder coordination This activity involves coordination with the LGUs in Barangay Puting Lupa in Calamba, Laguna and Barangays San Rafael and San Antonio in Batangas, which has political jurisdiction over the service contract area. It also involves coordinating with the stakeholders such as UP Los Baños in terms of maintaining the Mt. Makiling forest reserve area, among others. This activity is important so as to inform LGUs and the affected stakeholders about the project and enlist their support.

During the second quarter of 2011, several CSR activities were conducted in and around the project area. This include: 1) donation of an ambulance to Brgy. San Rafael on April 25, 2011 2) donation of six flashlights to Brgy. Santiago on May 13, 2011 and 3) conduct of Medical Mission: Operation Circumcision to San Rafael residents on May 23, 2011. Payment for crop damages brought about by the discharge activities were given to affected owners on June 2011.MGI also: (1) conducted two workshops with the community residents to determine the best livelihood projects that MGI can support; and (2) donated Infocus Multimedia Projector and its accessories to Sto. Tomas Philippine National Police on November 9, 2011.

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•

Geologic & geophysical studies and resource assessment This activity involves performing technical studies in the geothermal field such as geologic mapping, reservoir assessment and geochemical sampling. The objective of this activity is to update the resource model as a guide for later drilling and engineering planning.

MGI engaged the services of an independent New Zealand firm, Sinclair, Knight, Merz (SKM), to conduct a technical due diligence review (third-party review) over the Project, primarily focused on reserves estimates.

SKM mentioned that MGI’s own resource assessment is sound and well supported by data; however, SKM’s independent reserves estimates yielded higher generation capacities compared to that of MGI. SKM confirmed a 28 MW resource good for 25 years for the area.

On November 11, 2011, based on the report of SKM (among other factors), the DOE confirmed the commerciality of the Maibarara project.

•

Land rights survey and lease This activity involves determining the total land area needed for the entire project and determining which part of the land area are government and private property. For those land area that are still private property, MGI will either buy those parcels of land or secure a lease agreement with the land owners. MGI engaged New R&E Surveying & Engineering Services to do a detailed inventory of the status of public and private lots within the likely development area. This was followed by a new topographic survey that produced an updated topographic map of the area including the location of existing houses and infrastructures (roads, bridges, etc.).

•

Obtainment of DENR and other permits This involves obtaining the Environmental Clearance Certificate (ECC) from the DENR and other necessary permits. MGI engaged SMEC Philippines to conduct the necessary environmental impact study for the project and ensure the release of the ECC. On August 10, 2010, the ECC was released to MGI by the DENR. As part of the ECC condition, DENR and MGI will forge a memorandum of agreement (MOA) governing a multi-partite monitoring team (MMT). Several discussions were held with the DENR Los Baños office throughout the year regarding this MMT-MOA culminating in the agreements reached last December 2, 2010.

In 2011, the team was formed and the MOA was finalized. The MOA includes provision for an environmental guarantee fund in the form of insurance, environmental guarantee cash fund and environmental monitoring fund. The MOA will be executed upon completion of signature of all the members of the team.

•

Establishment of logistics station Producing geothermal steam for power generation requires the delivery, maintenance and safekeeping of many supplies and equipment, not to mention the services of numerous third-party contractors and organic personnel. A safe, spacious and secure logistics station to address this operational need for the project was established in Sto. Tomas, Batangas.

In March 2010, a lease contract was signed with Mr. Gregorio Nora for his property to serve as logistics station. This has served as the main site delivery point for many drilling-related consumables such as drill pipes, casings, chemicals, etc.

•

Land and water supply preparations This activity involves preparing the land area and securing enough water supply for the work over and drilling activities. After the ECC was granted, civil works for the construction of deep cellar in Pad A commenced in early September 2010 with the engagement of Media Construction. This new deep cellar will maximize the use of the existing space in Pad A by providing slots for future wells, allow pipelines to be trenched inside the cellar, and minimize disturbance in future drilling and civil works operations. While the cellar was being constructed, repair and relining of the drilling sump was also started; both of these were completed in midDecember 2010 in time for the mobilization of the drilling rig.

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Simultaneously, the water source for the drilling and future operations of the field was identified and rehabilitated and alvenius pipes were installed to convey water from the well. The necessary pump from the well was secured, a generator set rented, and water lines connected by late December 2010.

•

Preparation for well work-over and drilling The preparation for well work-over and drilling began with the advanced order for long-lead drilling items like steel casings for relining the wells, drill bits, master valves, and related supplies. It continued with the pullout and reconditioning of wellhead assemblies in wells Mai-6D, Mai-9D and Mai-11D to ensure their safety and integrity for actual operations. The preparations were completed with the fabrication and installation of necessary cellar supports for the drilling rig.

•

Work-over of existing wells Although the actual work-over of the three (3) existing wells commenced only in January 2011, there were tasks done in 2010 to support this 2011 operations. Among these tasks was the engagement of a drilling consultant beginning in July 2010 to oversee the preparations of the work-over drilling program. Other key contracts signed during this stage were those for the drilling rig, milling tools, cementing services, drilling fluids, mud services, pressure-temperature-spinner logging services, and downhole video and caliper tools.

On site, the work-over preparations centered on lowering the wellhead of the three (3) existing wells by cutting down their conductor pipes and casing head flanges. Mobilization to Maibarara of the drilling rig started on December 20, 2010 and was finished by December 31, 2010.

In 2011, three (3) existing wells, Mai-6D, Mai-9D, and Mai-11D, were successfully worked-over. The first two (2) wells are intended as production wells and the third as a re-injection well.

Mai-6D showed very good indications that it will be a good producer because of very good temperature and permeability, as shown in the Heat-up Results. Mai-11D’s completion test showed a very nice kick in temperature, indicating a fast thermal recovery, but with a lower permeability compared to Mai-6D. The important part operationally, however, is its measured capacity to accept fluid, which is about 60 kg/s. When the plant is operated, the required reinjection capacity would be about 58 kg/s. Reinjection is needed in order to contain any potential environmental hazard the brine may carry, and that it will also recharge the reservoir, thereby extending its productive life. As a rule of thumb in geothermal operations, there should be one (1) reinjection well for every two (2) production wells. Mai-9D is less hot than Mai-6D but also showed good permeability.

•

Drilling of new wells In preparation of the planned drilling of two (2) new wells to complete the 20 MW, casing head flanges and expansion spools were already fabricated as early as October 2010. Other long-lead items such as casings, drill bits, valves, etc. were also purchased in advance.

In 2011, the negotiation for rig contract with DESCO was done. The rig’s performance as well as capability was evaluated thoroughly and recommendations to DESCO were forwarded in terms of rig rental and additional auxiliary equipment during drilling. MGI paid $0.3 million as downpayment for the mobilization of the rig.

DESCO has confirmed May 31, 2012 as the earliest date of its mobilization to site. This will move back start of drilling of the production and reinjection wells to June 2012.

•

66

Flow-testing and bore output measurements A well testing supervisor was engaged in early 2010 to identify and, if necessary design all the well testing requirements for the project. Apart from the inventory of the state of the various wellheads and cellars conducted in mid-2010, the preparations for this activity which will take place in early 2011 include: (1) the design and fabrication of portable twin-shock silencer; (2) the design and fabrication of webre separator to

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be used during high-pressure collection of geothermal fluids, and (3) the installation of the discharge set-up, fittings and lines.

On March 5, 2011, wells Mai-6D and Mai-9D were successfully discharged. Based on the results of the discharge testing, the potential output of the wells is 15 MW. •

Engineering design of steam/brine lines The technical complement for the Engineering Design Group (EDG) was formed in the latter part of 2010.

Two (2) civil works consultant and a Computer-Aided Design and Drafting operator were hired to work on the engineering aspects of the steamfield and power plant.

EDG completed in December 2010 the conceptual development plan, the initial heat and mass balance, and the piping and instrumentation diagram of the project. Visits to the power plant site and meetings with potential Engineering, Procurement and Construction (EPC) contractor were also conducted during the second half of 2010.

•

Financing, grid impact study and power purchase contract A project-term consultant was engaged to prepare the documents needed for a Grid Impact Study (GIS) application with the National Grid Corporation of the Philippines (NGCP), which was filed on June 20, 2010.

In 2011, MGI received the final GIS for the project.

In 2010, the MGI also went into negotiation with Endesa Carbono, the carbon trading arm of the major Spanish electric utility firm Endesa, for the sale of the carbon credits to be generated by the project. After months of discussion, MGI agreed in December 2010 on the final draft and terms of the carbon credit contracts in which the Company will sell 100% of the carbon credits to be generated by the project to Endesa Carbono, and the latter guarantees to buy these credits beginning in 2013 to at least 2020. The Emissions Reduction Purchase Agreement was signed in January 2011.

In relation to the agreement with Endesa, MGI engaged the services of AENOR to perform validation of MGPP, in accordance with certain provisions of the Kyoto Protocol. The fee of AENOR is $39,264.

Upon confirmation of commerciality during the latter part of 2011, deferred geothermal costs incurred prior to 2011 amounting to $1.28 million and incurred in 2011 amounting to $3.94 million are reclassified to property plant and equipment under FCRS and production wells - geothermal.

11. Investment Property As of December 31, 2011 and 2010, this account consists of land with carrying value of $31,417.

The fair value of the investment property of the Group amounted to $36,734 as of December 31, 2011 and 2010. The fair values of the Group’s investment property have been determined on the basis of recent sales of similar properties in the same areas as the investment property and taking into account the economic conditions prevailing at the time the valuations were made.

There were neither income earned nor expenses incurred in relation to the investment property in 2011, 2010 and 2009.

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12. Investment in Navy Road Development Corporation (NRDC) As of December 31, 2011 and 2010, this account consists of: $260,388

Acquisition cost

54,032

Advances

314,420 314,420 $–

Less accumulated impairment loss

Investment in NRDC represents investment in subsidiary due to the Group’s holdings in 100% of NRDC’s capital stock.

Below are NRDC’s financial position as of December 31, 2011 and 2010 and results of operation in 2011 and 2010: 2011

2010

$−

$−

Financial Position Current assets

366,193

366,193

(366,193)

(366,193)

−

−

Current liabilities

−

−

Noncurrent liabilities

−

−

−

−

$−

$−

Revenue

$−

$−

Expenses Net profit (loss)

− $−

− $−

Noncurrent assets Allowance for impairment Total Assets

Total Liabilities Net assets Results of Operation

As of December 31, 2011, NRDC has not commenced commercial operations. The management intends to liquidate NRDC and has provided for full impairment losses on investment in NRDC. Under these circumstances, NRDC’s accounts were no longer consolidated into the Group.

13. Accounts Payable and Accrued Expenses This account consists of:

Accounts payable

2011 $2,516,582

2010 $137,027

Accrued expenses

357,397

289,129

Accrued interest payable

234,830

–

Dividend payable

224,911

207,607

121,787 $3,455,507

102,378 $736,141

Others

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PETROENERGY

Accounts payable consist of payable to suppliers and contractor.

Accrued expenses consist of accruals for certain general and administrative expenses such as professional fees, utilities and condominium dues.

Accrued interest payable pertain to accrual for interest on loans (Note 14).

The Group’s accounts payable and accrued expenses are due within one year. Carrying values approximate their fair values as of December 31, 2011 and 2010.

14. Loans Payable As of December 31, 2011, this amount consists of : Loans payable

$13,688,931

Less unamortized deferred financing cost Loans payable

393,792 $13,295,139

On September 26, 2011, MGI together with PNOC Renewables Corporation and Trans-Asia entered into a $54.7 million Omnibus Loan and Security Agreement with RCBC and BPI specifically to partially finance the design, development, procurement, construction, operation and maintenance of its geothermal power plant project.

As of December 31, 2011, MGI has already drawn $13.7 million. The remaining balance will be subsequently drawn based on a certain drawdown schedule.

The loan is payable semi-annually within ten (10) years from and after the date of initial drawdown immediately following the signing date, payments to be made in fourteen (14) semi-annual principal installment commencing on the end of 6th semester from the date of the initial drawdown, inclusive of a grace period of thirty-six (36) months. The amount of loans payable is presented under noncurrent liabilities portion.

The rate of interest applicable to the loan is fixed for the first five (5) years from the initial drawdown date based on the sum of the prevailing fixed benchmark rate on the pricing date and the margin of 2.5% per annum (the “Initial Interest Rate”). After five years from the date of the first initial drawdown, the interest for the remaining 5 years tenor shall be repriced based on the higher of: (i) the sum of the then prevailing fixed benchmark rate plus the margin of 2.25% per annum, or (ii) the Initial Interest Rate.

Deferred financing costs are incidental costs incurred in obtaining the loan which include documentary stamp tax, transfer tax, chattel mortgage, real estate mortgage, professional fees, arrangers fee and other out of pocket expenses. Total deferred financing costs amounted to $1.6 million. As of December 31, 2011, the portion pertaining to the drawn amount of the loan amounting to $393,792 is presented as deduction from the loans payable account and is amortized over the life of the loan using the effective interest rate method. Amortization of deferred financing cost will be capitalized until all necessary activities to prepare the power plant for its intended use are substantially complete. Details of unamortized deferred financing costs follows: Total deferred financing costs on loan drawn

$401,032

Less: amortization for 2011 Unamortized portion

7,240 $393,792

The portion pertaining to the undrawn amount of the loan is presented as an asset in the consolidated statements of financial position. As of December 31, 2011, $862,218 and $349,493 are presented as current asset under “Prepaid expenses and other current assets” account and as noncurrent asset under “Advances and other noncurrent assets” account, respectively.

2011 ANNUAL REPORT

69

MGI has pledged a portion of its land and property plant and equipment amounting to $0.848 million as collateral in connection with the loan. Pledged assets are as follows: • •

Real Assets (land to be used as power plant site, under “Property, plant and equipment”) - $0.77 million; and Chattel (under “Property, plant and equipment”) - $0.078 million.

Below are the additional information on finance cost for 2011 (nil for 2010 and 2009): Loans payable (all capitalized)

$10,039

Amortization (all capitalized)

7,240 $17,279

The loan covenants covering the outstanding debt of MGI include, among others, maintenance of certain level of debt-to-equity and debt-service ratios. As of December 31, 2011 and 2010, MGI is in compliance with the said loan covenants.

15. Asset Retirement Obligation The Group has recognized its share in the abandonment costs associated with the Etame and Avouma and Ebouri oilfields located in Gabon, West Africa.

Movements in this account follow:

Balance at beginning of year Additions during the year (Note 8) Accretion expense Balance at end of year

2011 $402,793

2010 $299,967

9,067

27,406

62,433 $474,293

75,420 $402,793

The provision for the oilfields in Etame maintained the original discount rate at 15% both years.

Additions during the year resulted from the change in the estimate of abandonment costs due to the addition of the estimates for the Avouma and Ebouri oilfield. The estimate was done by the operator of the oilfields in Gabon, West Africa. This was included as additions to “Wells, platforms and other facilities” account under “Property, plant and equipment” in the consolidated statements of financial position (see Note 8).

The provisions for the abandonment costs for Etame, Avouma and Ebouri oilfields are expected to be settled in years 2020 and 2022, respectively.

16. Equity Under the existing laws of the Republic of the Philippines, at least 60% of the Parent Company’s issued capital stock should be owned by citizens of the Philippines for the Group to own and hold any mining, petroleum or renewable energy contract area. As of December 31, 2011, the total issued and subscribed capital stock of the Parent Company is 99.87% Filipino and 0.13% non-Filipino, as compared to 99.72% Filipino and 0.28% nonFilipino as of December 31, 2010 and 99.77% Filipino and 0.23% non-Filipino as of December 31, 2009.

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PETROENERGY

Capital Stock and Additional Paid-in Capital On February 23, 2010, the BOD approved a 1:1 Stock Rights Offering (SRO). Under the SRO, the shares were offered at current market prices. The SRO was undertaken during the period June 28 to July 5, 2010. Total proceeds from the SRO amounted to $14.8 million.

As of December 31, 2011 and 2010, capital stock consists of 330,000,000 authorized and 273,824,220 issued and outstanding common shares with par value of $0.0245 per share. As of December 31, 2009, capital stock consists of 330,000,000 authorized and 136,912,110 issued and outstanding common shares with par value per share of $0.0245.

Total capital stock and additional paid-in capital as of December 31, 2011 and 2010 are as follows: Capital stock

Balance at beginning of year

Number of shares 2011 2010 273,824,220 136,912,110

Amount 2011 2010 $6,321,533 $3,358,068

Stock issuances Balance at end of year

− 273,824,220

− $6,321,533

136,912,110 273,824,220

2,963,465 $6,321,533

The Company’s track record of capital stock are as follows:

Listing by way of introduction − August 11, 2004

Number of shares registered

Issue/ offer price

Date of SEC approval

84,253,606

P3/share

August 4, 2004

21,063,402

P1/share

September 6, 2005

31,595,102

P1/share

September 8, 2006

136,912,110

P5/share

May 26, 2010

Number of holders as of year-end

Add (deduct): 25% stock dividend 30% stock dividend 1:1 stock rights offering December 31, 2010

273,824,220

Add (deduct): Movement December 31, 2011

− 273,824,220

2,149 −

−

(26) 2,123

Additional paid-in capital

Balance at beginning of year

2011 $25,244,737

2010 $13,390,875

Stock issuances Balance at end of year

− $25,244,737

11,853,862 $25,244,737

The Parent Company has 2,123 and 2,149 shareholders as of December 31, 2011 and 2010, respectively.

Dividends The BOD approved the declaration of cash dividends as follows:

2011 ANNUAL REPORT

71

2011

2010

2009

$631,951

$–

$–

629,120

–

–

October 21, 2010,10% or $.002 per share cash dividends to all stockholders of record as of November 8, 2010 amounting to $631,295. The dividends were paid on December 2, 2010.

−

631,295

–

February 23, 2010, 20% or $.004 per share cash dividends to all stockholders of record as of March 15, 2010 amounting to $606,208. The dividends were paid on April 5, 2010.

−

606,208

–

− $1,261,071

– $1,237,503

569,398 $569,398

May 17, 2011, 10% or $.002 per share cash dividends to all stockholders of record as of September 20, 2011 amounting to $631,951. The dividends were paid on October 14, 2011.

May 17, 2011, 10% or $.002 per share cash dividends to all stockholders of record as of June 16, 2011 amounting to $629,120. The dividends were paid on July 13, 2011.

July 22, 2009, 20% or $0.004 per share cash dividends to all stockholders of record as of August 5, 2009 amounting to $569,398. The dividends were paid on August 31, 2009.

Appropriated Retained Earnings On January 15, 2008, the BOD approved the appropriation of $492,005 for the development of the Ebouri oilfield in Gabon, in addition to the $563,550 originally appropriated amount.

On July 24, 2008, the BOD approved additional appropriation of retained earnings amounting to $1.0 million for the development of the Ebouri oilfield in Gabon, West Africa.

Total appropriations for the development of Ebouri oilfield as of December 31, 2011 and 2010 amounted to $2.0 million. There are no appropriations of retained earnings made in 2011 and 2010.

Capital Management 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 shareholders’ 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 increase its debt from creditors, adjust the dividend payment to shareholders or issue new shares.

As of December 31, 2011, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity.

As of December 31, 2011 and 2010, the Group’s sources of capital are as follows: Capital stock Additional paid-in capital

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$6,321,533 25,244,737 $31,566,270

The table below demonstrates the debt-to-equity ratio of the Group as of December 31, 2011 and 2010: 2011

2010

Total debt $13,295,139

−

3,455,507

$736,141

Asset retirement obligation

474,293

402,793

Income tax payable

243,474

421,301

41,862 $17,510,275

43,217 $1,603,452

Capital stock

$6,321,533

$6,321,533

Additional paid-in capital

25,244,737

25,244,737

Appropriated

2,055,555

2,055,555

Unappropriated

5,637,881

3,972,684

Loans payable Accounts payable and accrued expenses

Accrued retirement liability Total equity

Retained earnings

(56,228)

59,163

3,851,627 $43,055,105 0.41:1

1,230,598 $38,884,270 0.04:1

Cumulative translation adjustment Noncontrolling interest Debt-to-equity ratio

Based on the Group’s assessment, the capital management objectives were met in 2011, 2010 and 2009, respectively.

17. Retirement Plan The Group has a defined benefit retirement plan (the Plan) for all of its employees. The Plan provides for normal and early retirement, as well as, death and disability benefits.

The retirement expense included under general and administrative expense account for the years ended December 31, 2011, 2010 and 2009 are as follows (see Note 20):

Current service cost Interest cost Expected return on plan assets Recognized actuarial gains

2011 $21,090

2010 $14,039

2009 $15,730

5,635

4,749

5,520

(4,659)

(3,004)

(5,146)

(1,167) $20,899

(2,240) $13,544

(2,372) $13,732

The accrued retirement liability recognized in the consolidated statements of financial position as of December 31, 2011 and 2010 are as follows (see Note 3):

Present value of accrued retirement liability Fair value of plan assets

2011 $125,108

2010 $81,266

(91,536)

(65,758)

33,572

15,508

(Forward) 2011 ANNUAL REPORT

73

2011

2010

Net unrecognized actuarial gains

$15,592

$35,250

Foreign currency translation adjustments

(7,302) $41,862

(7,541) $43,217

The movements in the accrued retirement liability recognized in the consolidated statements of financial position are as follows: 2011 $43,217

2010 $45,409

20,899

13,544

Contributions to retirement plan

(22,272)

(18,049)

Foreign currency translation adjustments Balance at end of year

18 $41,862

2,313 $43,217

2011 $81,266

2010 $47,571

21,090

14,039

5,635

4,749

17,653

11,463

Balance at beginning of year Retirement expense (Note 20)

Changes in the present value of accrued retirement liability follow:

Balance at beginning of year Current service cost Interest cost Actuarial loss on obligation Foreign currency translation adjustments Balance at end of year

(536) $125,108

3,444 $81,266

2011 $65,758

2010 $41,918

Changes in the fair value of the plan assets follow:

Balance at beginning of year

22,272

18,049

Expected return on plan assets

4,659

3,004

Actuarial loss on plan assets

(838)

(81)

Foreign currency translation adjustments

(315)

2,868

$91,536 $3,821

$65,758 $3,009

2011 $55,092

2010 $35,696

36,301

29,998

Actual contributions

Balance at end of year Actual return on plan assets The components of net plan assets are as follows:

Cash and cash equivalents Investments in debt securities Interest receivable Trust fee payable

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285

450

(142) $91,536

(386) $65,758

The principal actuarial assumptions used in determining pension benefit obligation for the Group’s plan are as follows: 2011

2010

Beginning

3.00%

3.00%

Ending

4.20%

3.00%

Beginning

6.85%

9.75%

Ending

5.77%

6.85%

7.00% 7.00%

7.00% 7.00%

Rate of increase in salaries

Discount rate

Expected rate of return Beginning Ending

The overall expected rate of return on assets is determined based on the market expectations prevailing on that date, applicable to the period over which the obligation is to be settled.

Amounts for the current and previous periods are as follows:

Present value of accrued retirement liability

2011

2010

2009

2008

$125,108

$81,266

$47,571

$64,604

91,536 $33,572

65,758 $15,508

41,918 $5,653

73,704 ($9,100)

61,292 $47,805

Fair value of plan assets Deficit (Surplus)

2007 $109,097

Experience adjustments for the current and previous periods are as follows:

Plan obligations Plan assets

2011 ($3,031)

2010 ($2,608)

2009 $2,513

2008 ($11,209)

2007 $16,058

(834)

(84)

(1,510)

515

8,985

The Group expects to contribute to the fund the amount of $1,623,197 in 2012.

18. Income Tax The provision for income tax consists of:

Current - Regular Corporate Income Tax

2011 $1,191,787

2010 $998,907

2009 $785,331

146,199 $1,337,986

(141,037) $857,870

(192,630) $592,701

Deferred: On temporary differences

2011 ANNUAL REPORT

75

The components of the Group’s deferred tax assets are as follows: 2011

2010

Accrued profit share

$77,249

$66,857

Asset retirement obligation

132,016

169,171

Provision for probable losses

17,092

17,092

Accrued retirement liability

10,778

11,609

–

20,758

237,135

285,487

131,754

57,085

23,178

–

154,932 $82,203

57,085 $228,402

Deferred tax assets on:

Unrealized foreign exchange loss Deferred tax liabilities on: Production revenue Unrealized foreign exchange gain

As of December 31, 2011 and 2010 the Group did not recognize deferred tax assets amounting to $193,137 and $85,076, respectively, on the NOLCO of its subsidiaries because the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized. Details of the NOLCO are as follows: PGEC NOLCO Year Incurred 2010

Expiration 2013

In USD $51,127

In PHP P2,241,423

2011

2014

34,215 $85,342

1,499,970 P3,741,393

Year Incurred 2010

Expiration 2013

In USD $ 33,949

In PHP P 1,488,317

2011

2014

73,846 $107,795

3,237,396 P4,725,713

MGI NOLCO

As indicated on the Implementing Rules and Regulations of the Renewable Energy (RE) Act of 2008, the NOLCO of the RE Developer during the first three (3) years from the start of commercial operation shall be carried over as a deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss, subject to the following conditions: a) The NOLCO had not been previously offset as a deduction from gross income; and b) The loss should be a result from the operations and not from the availment of incentives provided for in the RE Act. The Parent Company is subject to the regular corporate income tax rate of 30%, while PetroGreen and MGI are subject to a corporate tax of 10%.

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PETROENERGY

The reconciliation of the statutory tax rate to the effective income tax rate shown in the consolidated statements of income follows: 2011 30.00%

2010 30.00%

2009 30.00%

Loss from entities subjected to lower rate

5.68

6.86

–

Movement in unrecognized deferred tax assets

2.84

3.43

–

Statutory tax rate Add (deduct) reconciling items:

0.26

(0.04)

–

Interest income subjected to final tax

(4.09)

(4.78)

(1.30)

Donations

(0.12)

(0.06)

(0.20)

(1.49) 33.08%

(11.10) 24.31%

(2.90) 25.60%

Unrealized loss (gain) on FVPL

Others Effective income tax rate

As per Republic Act 9337, which was declared as valid by the Supreme Court on October 18, 2005, the corporate income tax, as well as the allowable deduction for interest expense will be reduced to 30% and 33%, respectively, effective January 1, 2009.

19. Oil Production Operating Expenses The costs and expenses incurred related to oil production are as follows:

Production, transportation and related expenses Storage and loading expenses

2011 $4,788,555

2010 $3,677,438

2009 $2,572,374

563,622

581,332

601,544

2,805

3,672

2,938

77,167 $5,432,149

58,816 $4,321,258

74,084 $3,250,940

Supplies and facilities Others

20. General and Administrative Expenses The Group’s general and administrative expenses are as follows: 2011 $999,210

2010 $716,166

2009 $490,652

Professional and other fees

243,084

505,781

105,904

Security and janitorial services

157,576

51,890

7,880

Depreciation and amortization of software cost

148,307

151,842

98,788

Research costs

147,813

114,476

91,101

Donation and contribution

143,272

72,323

96,016

Transportation and travel

142,680

133,594

118,479

Taxes and licenses

119,993

178,569

51,139

Training and seminar

58,627

97,534

45,713

Entertainment, amusement and recreation (EAR)

57,545

48,329

19,358

Salaries, wages and benefits (Notes 17 and 22)

(Forward) 2011 ANNUAL REPORT

77

2011

2010

2009

$55,912

$44,213

$37,682

Gasoline, oil and lubricants

47,101

29,114

18,305

Utilities

46,491

33,125

21,879

Rent expense

43,467

8,922

2,117

Environmental and social expenses

41,079

−

−

Communication

34,465

23,999

15,976

Office supplies

32,323

23,064

17,041

Business meetings

32,226

18,669

17,410

Condominium dues

24,386

17,079

16,223

Repairs and maintenance

24,139

24,816

12,531

Listing fee

12,909

78,835

−

Stock transfer fees

11,884

10,722

9,686

Advertisement

7,653

8,049

12,317

Dues and subscriptions

4,388

5,861

5,862

55,561 $2,692,091

98,404 $2,495,376

26,061 $1,338,120

Insurance

Others

Revenue Regulations 10-2002 defines expenses to be classified as EAR expenses and sets a limit for the amount that is deductible for tax purposes. EAR expenses are limited to 0.5% of net sales for sellers of goods or properties or 1% of net revenue for sellers of services. For sellers of both goods or properties and services, an apportionment formula is used in determining the ceiling on such expenses.

Listing fee in 2010 pertains to the restructuring expenses incurred in relation to the SRO. Others pertain to miscellaneous expenses such as development assistance, notarization and reproduction expenses.

21. Related Party Transactions Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party in making financial and operating decisions or the parties are subject to common control or common significant influence (referred to as ‘Affiliates’). Related parties may be individuals or corporate entities.

Compensation of Key Management Personnel of the Group The Group has a profit sharing plan for directors, officers, managers and employees as indicated in its by-laws.

The amount, the manner and occasion of distribution is at the discretion of the BOD, provided that profit share shall not exceed 5% of the audited income before income tax and bonus.

The remuneration of the Group’s directors and other members of key management are as follows:

Salaries and wages and other short-term benefits (Note 20) Directors’ fees (Note 20) Retirement expense (Note 17)

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2011

2010

2009

$236,978

$239,067

$180,210

142,697

141,880

81,873

4,957 $384,632

3,900 $384,847

5,144 $267,227

22. Financial Instruments The Group’s principal financial instruments include cash and cash equivalents, trading and investment securities (financial assets at FVPL) and receivables. The main purpose of these financial instruments is to fund the Group’s working capital requirements.

Categories and Fair Values of Financial Instruments As of December 31, 2011 and 2010, the carrying amounts of the Group’s financial assets and financial liabilities approximate their fair values except for loans payable. The fair value of the loans payable as of December 31, 2011 amounted to $14,020,798 compared to its carrying value of $13,295,139.

The methods and assumptions used by the Group in estimating the fair value of financial instruments are: Cash and cash equivalents and Receivables

Due to the short-term nature of the instruments, carrying amounts approximate fair values as of the reporting date.

Equity securities

Fair values are based on published quoted prices. Unquoted equity securities are carried at cost less impairment.

Debt securities and Golf club shares

Fair values are based on quoted market prices as at reporting date.

Accounts payable Carrying amounts approximate fair values as at reporting date. and accrued expenses Loans Payable Fair value are based on the discounted value of expected future cash flows using the applicable interest rate for similar type of instruments. The fair value for 2011 is derived at using the projected T-Bond coupon rate of 5 year tenor at 4.674% plus 2.5% credit spread for the first five years and 2.25% for the second five years.

The following tables show financial instruments recognized at fair value as of December 31, 2011 and 2010.

The fair value is based on Level 1 source of valuation as outlined below: • quoted prices in active markets for identical assets or liabilities (Level 1); • those involving inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly (Level 2); and • those with inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).

2011 Level 1

Level 2

Level 3

Fair Value

$98,069

$−

$−

$98,069

10,949 $109,018

$−

$−

10,949 $109,018

Financial assets at FVPL Marketable equity securities Investment in golf club shares

2011 ANNUAL REPORT

79

Level 1

2010 Level 2

Level 3

Fair Value

Financial assets at FVPL Marketable debt securities Marketable equity securities Investment in golf club shares

$1,441,065

$–

$–

$1,441,065

97,609

–

–

97,609

13,572 $1,552,246

– $–

– $–

13,572 $1,552,246

Financial Risk Management Objectives and Policies The Group manages and maintains its own portfolio of financial instruments in order to fund its own operations and capital expenditures. Inherent in using these financial instruments are the following risks on liquidity, market and credit.

Financial Risks The main financial risks arising from the Group’s financial instruments are liquidity risk, market risk and credit risk. a.

Liquidity Risk Liquidity risk is the risk that the Group is unable to meet its financial obligations when due. The Group monitors its cash flow position and overall liquidity position in assessing its exposure to liquidity risk. The Group maintains a level of cash and cash equivalents deemed sufficient to finance its operations and to mitigate the effects of fluctuation in cash flows. To cover its short-term and long-term funding requirements, the Group intends to use internally generated funds as well as to obtain loan from financial institutions.

The tables below summarize the maturity profile of the Group’s financial assets as of December 31, 2011 and 2010 based on contractual undiscounted payments:

On demand

2011 Less than 3 to 3 months 12 months

Total

Financial Assets Financial assets at FVPL

$109,018

$–

$–

$109,018

942,852

–

–

942,852

20,961,432

–

–

20,961,432

2,035,530

–

–

2,035,530

4,476

–

–

4,476

36,010

–

–

36,010

$–

63,125 $24,152,443

2010 Less than 3 to 3 months 12 months

Total

Loans and receivables: Cash on hand and in banks Short-term investments Accounts receivable: Consortium operator Others Interest receivable Restricted Cash

63,125 $24,152,443

On demand

$–

Financial Assets Financial assets at FVPL

$1,552,246

$–

$–

$1,552,246

183,513

–

–

183,513

Loans and receivables: Cash on hand and in banks (Forward)

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PETROENERGY

On demand Short-term investments

2010 Less than 3 to 3 months 12 months

Total

$15,900,971

$–

$–

$15,900,971

2,547,647

–

–

2,547,647

Accounts receivable: Consortium operator Others Interest receivable Restricted cash

767

–

–

767

195,895

–

–

195,895

63,125 $20,444,164

– $–

– $–

63,125 $20,444,164

The tables below summarize the maturity profile of the Group’s financial liabilities as of December 31, 2011 and 2010, based on undiscounted cash flows:

Loans payable

On demand $–

2011 More than 1 year $13,295,139

Accounts payable

2,516,582

–

2,516,582

Accrued expenses

357,397

–

357,397

Accrued interest payable

234,830

Dividend payable

224,911

–

224,911

51,773

–

51,773

70,014 $3,455,507

– $13,295,139

70,014 $16,750,646

On demand $289,129

2010 More than 1 year $–

Total $289,129

Dividend payable

207,607

–

207,607

Accounts payable

137,027

–

137,027

51,773

–

51,773

50,605 $736,141

– $–

50,605 $736,141

Due to NRDC Others

Accrued expenses

Due to NRDC Others

b.

Total $13,295,139

234,830

Market Risk Market risk is the risk of loss on future earnings, on fair values or on future cash flows that may result from changes in market prices. The value of a financial instrument may change as a result of changes in equity prices, foreign currency exchanges rates, interest rates and other market changes.

Equity Price Risk The Group closely monitors the prices of its securities on a daily basis, as well as macroeconomic and entity-specific factors which could directly or indirectly affect the prices of these instruments. In case of an expected decline in its portfolio of equity securities, the Group readily disposes or trades the securities for replacement with more viable and less risky investments.

Such investment securities are subject to price risk due to changes in market values of instruments arising either from factors specific to individual instruments or their issuers, or factors affecting all instruments traded in the market.

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The analysis below is performed for reasonably possible movements in the Philippine Stock Exchange (PSE) index with all other variables held constant, showing the impact on income before tax (due to changes in fair value of equity securities and golf shares whose fair values are recorded in the consolidated statements of income).

Equity securities

% 10%

Golf club shares

3%

Equity securities

% 8%

Golf club shares

2%

2011 Impact on income before tax Increase Decrease $7,671 ($7,671) 2,986 $10,657

(2,986) ($10,657)

2010 Impact on income before tax Increase Decrease $7,926 ($7,926) 2,053 $9,979

(2,053) ($9,979)

There is no other impact on the Group’s equity other than those already affecting net income.

Foreign Exchange Risk Exposure to currency risk arises from sales and purchases in currencies other than the Group’s functional currency which is very minimal since the Group’s oil revenues and costs and expenses are denominated in US Dollar. Currency risk is monitored and analyzed systematically and is managed by the Group.

The analysis below demonstrates the sensitivity to a reasonably possible change in the Philippine Peso exchange rate which is the only source of the Group’s foreign exchange risk, with all other variables held constant, showing the impact on income before tax (due to changes in fair value of currency sensitive to financial assets and liabilities).

2011 Increase/decrease in Php rate +4.20% -4.20%

Impact on income before tax $371,013 (371,013) 2010

Increase/decrease in Php rate +4.20% –4.20%

Impact on income before tax $569,601 (569,601)

There is no other impact on the Group’s equity other than those already affecting net income.

Interest Rate Risk The Group’s exposure to market risk for changes in interest rates relates primarily to the Group’s money market placements, debt securities and loans payable. The table below demonstrates the sensitivity to a reasonably possible change in interest rates, with all other variables held constant, of the Group’s net income:

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2011 Increase/decrease in interest rate (in basis points) +49 -49

Impact on income before tax $457,366 (457,366) 2010

Increase/decrease in interest rate (in basis points) +74 –74

Impact on income before tax $155,507 (155,507)

There is no other impact on the Group’s equity other than those already affecting net income. c.

Credit Risk There are significant concentrations of credit risk within the Group since most of its financial assets are from consortium operator, although credit risk is immaterial.

The table below shows the summary of maximum credit risk exposure on financial instruments as of December 31, 2011 and 2010: 2011

2010

$98,069

$97,609

Financial assets at FVPL: Marketable equity securities Golf club shares Marketable debt securities

10,949

13,572

−

1,441,065

20,961,432

15,900,971

942,852

181,460

2,096,717

2,547,647

Loans and receivables: Short-term investments Cash in bank Accounts receivable:

Consortium operator - net

Others Interest receivable Restricted cash

4,476

767

36,010

195,895

63,125 $24,213,630

63,125 $20,442,111

The Group has a well-defined credit policy and established credit procedures. In addition, receivable balances are being monitored on a regular basis to ensure timely execution of necessary intervention efforts.

The Group determines the credit quality by class for loan-related consolidated statements of financial position lines based on the following: Cash in banks and short-term investments - based on the nature of the counterparties and the reputation of the financial institution.

Receivables - based on the payment behavior of the counterparty. High grade pertains to receivables from consortium operator and interest receivable from short-term investments and standard grade pertains to other receivables. Both are neither past due nor impaired.

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The tables below shows the credit quality by class of asset for loan-related consolidated statements of financial position lines, based on the Group’s credit rating system as of December 31, 2011 and 2010: 2011

Cash in banks

Neither past due nor impaired High grade Standard grade $942,852 $–

Past due and impaired $–

Total $942,852

Short-term investments

20,961,432

–

–

20,961,432

2,035,530

–

61,187

2,096,717

4,476

–

–

4,476

36,010

–

–

36,010

63,125 $24,043,425

– $–

– $61,187

63,125 $24,104,612

Past due and impaired $–

Total $181,460

Accounts receivable: Consortium operator Others Interest receivable Restricted cash

Cash in bank

2010 Neither past due nor impaired High grade Standard grade $181,460 $–

Short-term investments

15,900,971

–

–

15,900,971

2,547,647

–

61,187

2,608,834

767

–

–

767

Accounts receivable: Consortium operator Others Interest receivable Restricted cash

195,895

–

–

195,895

63,125 $18,889,865

– $–

– $61,187

63,125 $18,951,052

As of December 31, 2011 and 2010, the Group has no past due receivables that are not impaired.

Past due and impaired receivable pertains to a long-outstanding receivable from a consortium member which is fully provided with allowance.

With respect to credit risk arising from the other financial assets of the Group, which compose of financial assets at FVPL, cash in bank and short-term investments, the Group’s exposure to credit risk relates to default of the counter party, with a maximum exposure equal to the carrying amounts of these instruments.

23. Segment Information For management purposes, the Group is organized into business units based on their products and has three reportable segments as follows: • The oil segment is engaged in the oil and mineral exploration, development and production.

• The wind energy segment carries out the general business of generating, transmitting, and/or distributing power derived from wind energy sources.

• The geothermal energy segment will develop and operate geothermal steamfields and power plants.

No operating segments have been aggregated to form the above reportable operating segments.

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Management monitors the operating results of its business units separately for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on operating profit or loss and is measured consistently with operating profit or loss in the consolidated financial statements.

Oil Production $13,544,412 3,670,173

Geothermal Energy $– (628,428)

$42,082,175 $82,203 $1,448,453

2011 Wind Energy $– (335,564)

Elimination $– –

Consolidated $13,544,412 2,706,181

$26,965,599 $– $16,047,184

$8,390,174 ($16,954,771) $– $– $19,281 ($4,643)

$60,483,177 $ 82,203 $17,510,275

$6,232,222 (6,045,824) (1,243,767) 1,337,986 $1,543,304

$1,606,518 (15,072,853) 20,016,948 – $9,644,489

($503,680) (5,174,163) 6,052,318 – $6,995

$29,060 11,021,679 (11,116,330) – $–

$7,364,120 (15,271,161) 13,709,169 1,337,986 $11,194,788

$5,831,668

$–

$–

$–

$5,831,668

$1,959,994

$21,366

$22,029

$–

$2,003,389

Oil Production $10,784,257 3,500,037

Wind Energy $– (496,437)

2010 Geothermal Energy $– (332,118)

Elimination $– –

Consolidated $10,784,257 2,671,482

$39,645,704 $228,402 $1,567,283

$2,859,159 $– $198,828

$3,568,811 $– $29,491

($5,814,354) $– ($192,149)

$40,259,320 $228,402 $1,603,453

Operating activities

$3,500,054

($477,534)

($327,414)

$148,471

$2,843,577

Investing activities Financing activities Provision for income tax Capital expenditures Deferred oil exploration costs Deferred geothermal costs Depreciation, depletion and amortization

(6,136,417) 13,608,247 857,870 $1,329,717

(2,635,284) 3,303,495 – $2,597,015

(1,303,591) 3,857,697 – $1,298,891

5,809,942 (5,814,353) – ($311,509)

(4,265,350) 14,955,086 857,870 $4,914,114

$6,012,163

$–

$–

$–

$6,012,163

$–

$–

$1,283,953

$–

$1,283,953

$1,656,563

$13,079

$3,388

$–

$1,673,030

Segment revenue Net income (loss) Other Information Segment assets except deferred tax assets Deferred tax assets Segment liabilities Cash flows arising from: Operating activities Investing activities Financing activities Provision for income tax Capital expenditures Deferred oil exploration costs Depletion, depreciation and amortization

Segment revenue Net Income (loss) Other Information Segment assets except deferred tax assets Deferred tax assets Segment liabilities Cash flows arising from:

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2009 Oil Production $8,682,063 1,722,779

Segment revenue Net Income Other Information Segment assets except deferred tax assets Deferred tax assets Segment liabilities Cash flows arising from:

$21,997,478 $87,365 $857,881 –

Operating activities

$3,460,835

Investing activities Financing activities Provision for income tax Capital expenditures Deferred oil exploration costs Depreciation, depletion and amortization

(2,392,696) (549,285) $592,701 $109,649 $4,073,670 $1,934,946

Intercompany investments, revenues and expenses are eliminated during consolidation.

24. Basic/Diluted Earnings Per Share The computation of the Group’s earnings per share follows: 2011 Net income attributable to equity holders of the Parent Company Weighted average number of shares Basic/diluted earnings per share

2010

2009

$2,926,268

$2,787,723

$1,722,779

273,824,220

205,368,165

136,912,110

$0.011

$0.014

$0.013

25. Noncontrolling Interest Noncontrolling interest represents the 35% shareholdings of Trans-Asia and PNOC-RC in MGI.

26. Renewable Energy Act of 2008 On January 30, 2009, Republic Act No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energy Resources and for Other Purposes, otherwise 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

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environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws.

As provided for in the Act, Renewable Energy (RE) developers of RE facilities, including hybrid systems, in proportion to and to the extent of the RE component, for both power and non-power applications, as duly certified by the DOE, in consultation with the Board of Investments (BOI), shall be entitled to the following incentives, among others: i.

Income Tax Holiday (ITH) - For the first seven (7) years of its commercial operations, the duly registered RE developer shall be exempt from income taxes levied by the National Government; ii.

Duty-free Importation of RE Machinery, Equipment and Materials - Within the first ten (10) years upon issuance of a certification of an RE developer, the importation of machinery and equipment, and materials and parts thereof, including control and communication equipment, shall not be subject to tariff duties; iii. Special Realty Tax Rates on Equipment and Machinery - Any law to the contrary notwithstanding, realty and other taxes on civil works, equipment, machinery, and other improvements of a registered RE developer actually and exclusively used for RE facilities shall not exceed one and a half percent (1.5%) of their original cost less accumulated normal depreciation or net book value; iv.

NOLCO - the NOLCO of the RE developer during the first three (3) years from the start of commercial operation which had not been previously offset as deduction from gross income shall be carried over as deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss; v.

Corporate Tax Rate - After seven (7) years of ITH, all RE developers shall pay a corporate tax of ten percent (10%) on its net taxable income as defined in the National Internal Revenue Code of 1997, as amended by Republic Act No. 9337; vi.

Accelerated Depreciation - If, and only if, an RE project fails to receive an ITH before full operation, it may apply for accelerated depreciation in its tax books and be taxed based on such; vii. Zero Percent VAT Rate - The sale of fuel or power generated from renewable sources of energy the purchase of local goods, properties and services needed for the development, construction and installation of the plant facilities, as well as the whole process of exploration and development of resources up to its conversion into power shall be subject to zero percent (0%) VAT; viii. Cash Incentive of RE Developers for Missionary Electrification - An RE developer, established after the effectivity of the Act, shall be entitled to a cash generation-based incentive per kilowatt-hour rate generated, equivalent to fifty percent (50%) of the universal charge for power needed to service missionary areas where it operates the same; ix. Tax Exemption of Carbon Credits - All proceeds from the sale of carbon emission credits shall be exempt from any and all taxes; and x.

Tax Credit on Domestic Capital Equipment and Services - A tax credit equivalent to one hundred percent (100%) of the value of the VAT and custom duties that would have been paid on the RE machinery, equipment, materials and parts had these items been imported shall be given to an RE operating contract holder who purchases machinery, equipment, materials, and parts from a domestic manufacturer for purposes set forth in the Act. RE developers and local manufacturers, fabricators and suppliers of locally-produced RE equipment shall register with the DOE, through the Renewable Energy Management Bureau (REMB). Upon registration, a certification shall be issued to each RE developer and local manufacturer, fabricator and supplier of locally-produced renewable energy equipment to serve as the basis of their entitlement to the incentives provided for in the Act. All certifications required to qualify RE developers to avail of the incentives provided for under the Act shall be issued by the DOE through the REMB.

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27. Electric Power Industry Reform Act (EPIRA) After emerging from the crippling power crisis that occurred in the early 1990s, the Philippine Government embarked on an industry privatization and restructuring program envisioned to ensure the adequate supply of electricity to energize its developing economy. This restructuring scheme is embodied in RA No. 9136, the EPIRA. Approved on June 8, 2001, the EPIRA seeks to ensure quality, reliable, secure and affordable electric power supply; encourage free and fair competition; enhance the inflow of private capital; and broaden the ownership base of power generation, transmission and distribution.

The Government viewed restructuring and reform as a long-term solution to the problems of the power sector.

The huge investment requirement for new generation capacity and expansion of the necessary transmission and distribution network was estimated at an annual average of $1.0 billion. Given its own fiscal constraints, the Government recognized the need for greater private sector involvement in the power sector. Even though some private sector participation was successfully introduced earlier between the NPC and private investors, this time, the Government is envisioning addressing the power sector inefficiencies and the monopoly in the generation business. EPIRA mandated the overall restructuring of the Philippine electric power industry and called for the privatization of NPC. The restructuring of the electricity industry calls for the separation of the different components of the power sector, namely: generation, transmission, distribution, and supply. On the other hand, the privatization of the NPC involves the sale of the state-owned power firm’s generation and transmission assets (e.g. power plants and transmission facilities) to private investors. These two reforms are aimed at encouraging greater competition and attracting more private-sector investments in the power industry.

A more competitive power industry will in turn result in lower power rates and a more efficient delivery of electricity supply to end-users.

Specifically, the EPIRA has the following objectives: • Achieve transparency with the unbundling of the main components of electricity services, which will be reflected in the consumers’ electricity rates; • Opening up of the electricity market to competition at the wholesale (generation) level to improve efficiency in the operation of power plants and redound to lower electricity prices; • Enhance further inflow of private capital and broaden ownership base in generation, transmission distribution, and supply of electric power; • Establish a strong and independent regulatory body that will balance the interest of both the investors by promoting competition through creation of a level playing field and protect the electricity end-users from any market power abuses and anti-competitive behaviors; and • Accelerate and ensure the total electrification of the country.

28. Commitments a.

Certified Emission Reductions Purchase Agreement On January 31, 2011, MGI entered into a Certified Emission Reductions Purchase Agreement (“ERPA”) with Endesa Carbono S.L. (“Endesa”) of Madrid, Spain. Under the ERPA, MGI shall sell 100% of the Certified Emission Reductions (“CERs”) generated by the Maibarara Geothermal Power Project (the “Project”) in favor of Endesa from the start of its commercial operations in October 2013 until 2020. This will provide MGI with a secondary revenue stream apart from electricity sales. It should be noted that, under the RE Act of 2008, all proceeds from the sale of carbon emission credits shall be exempt from any and all taxes.

The Project is now undergoing registration process required under the UN Clean Development Mechanism (CDM). This includes the preparation of the Project Design Document (PDD), validation conducted by a Designated Operational Entity (“DOE” or “Validator”), application with the Designated National Authority (Department of Environment and Natural Resources for the Philippines), and registration or acceptance of the Project as a CDM Project Activity by the CDM Executive Board (“EB”). The PDD presents information on the essential technical and organizational aspects of the project activity and is a key input in the validation,

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registration and verification of the Project. MGI contracted the Spanish Association for Standardization and Certification (“AENOR”) as the Validator to perform an independent evaluation of the project activity against the requirements of the CDM on the basis of the PDD. Upon commercial operations, MGI shall collect and archive all relevant data necessary for calculating green house gas (GHG) emission reductions, which will then be subjected to periodic independent verification. The EB will issue the CERs equal to the verified GHG emission reductions. b.

Electricity Sales Agreement In 2011, MGI entered into an Electricity Sales Agreement with Trans-Asia Oil and Energy Development Corporation (Trans-Asia) in which the latter offered to purchase all of the facility’s net output. The commercial operation date is expected in 2013, which the Company shall make available and Trans-Asia shall receive all of the Company’s net capacity at delivery point in accordance with the electricity delivery procedures. Trans-Asia shall pay the Company electricity fees at the price agreed upon and subject to an adjustment starting on the second contract year, for charges on foreign exchange and inflation.

29. Wind Energy Service Contract (WESC) On September 14, 2009, the Parent Company was awarded by the DOE with two (2) WESCs (the Wind Energy Projects) covering the areas of Sual, Pangasinan and Nabas, Aklan. These service contracts were awarded pursuant to Republic Act (RA) No. 9513, otherwise known as the “Renewable Energy Act of 2008”.

During the two-year pre-development stage of the contracts, the Parent Company should conduct technical feasibility studies in the contract areas in order to confirm the wind power potential in the two (2) areas. The expected total expenditures for each contract amount to about $420,000.

As part of the technical study, the Parent Company committed to install a 60m wind mast to measure the wind data characteristics and other relevant parameters. The data from the technical feasibility study will determine whether the wind resource is viable for commercial development and operations.

As stated in Note 1, the Parent Company created PGEC to carry out the renewable energy projects of the Parent Company, which includes the wind energy projects.

PGEC purchased a 60m wind mast from US-based manufacturer and distributor, NRG Systems on November 30, 2009. It arrived at the port of Manila on January 23, 2010 and was released from customs by a contractor, Supply Oilfield Services, Inc. (SOS) on January 25, 2010.

Power Dimension, Inc. (PDI), a contractor hired by PGEC, purchased a 60m wind mast from US-based manufacturer and distributor, NRG Systems on November 30, 2009. It arrived at the port of Manila on January 23, 2010 and was released from assembled the mast and related equipment on Nabas site on February 10, 2010. Tower lifting began on February 17, 2010 and the mast was fully raised on February 18, 2010.

During the visit to Nabas on September 9-10, 2010, COWI’s Senior Wind Specialist, Mr. Soren B. Gjerding, recommended the installation of a second mast in Nabas, Aklan to increase confidence in the wind data. PGEC purchased a 60m wind mast from US-based manufacturer and distributor, NRG Systems on November 30, 2009.

It arrived at the port of Manila on January 23, 2010 and was released from ordered a 60 meter meterological mast with NRG Systems on November 29, 2010. The shipment arrived on December 15, 2010 and was turned over the same to PDI for the installation. The Installation of PGEC’s second mast was completed on the first week of January 2011.

PDI mobilized to Sual on January 30, 2010 and began raising and assembling the mast and related equipment.

Tower lifting began on February 17, 2010, after the concrete foundation for the ground anchors was completely set. The mast was fully raised on February 6, 2010.

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Following one year of wind data recording in Nabas (Aklan) and Sual (Pangasinan) wind service contract areas last February 2011, initial micrositing and annual energy production analyses were prepared by COWI, Inc., contracted Danish engineering consultant. COWI reported in May 2011 that the Sual site has only a fair to modest wind resource potential and unlikely to be commercially viable. This result prompted PGEC to relinquish the Sual wind service contract. The DOE formally approved the relinquishment on October 28, 2011.

In contrast to Sual, COWI reported in July 2011 that the Nabas project site can sustain a 50 MW wind farm.

This encouraging result led PGEC to start obtaining the first set of development permits and conducting initial engineering studies. SMEC Philippines (SMEC) was engaged in September 2011 to undertake the environmental baseline survey of Nabas needed to obtain the project’s environmental compliance certificate (ECC). The initial environmental examination report was submitted on December 6, 2011 by SMEC to the DENR - Region 6 office for data screening. In November 2011, PGEC applied with the National Commission on Indigenous Peoples (NCIP) for a Certificate of Non-Overlap (CNO) attesting that the project site does not overlap with any existing indigenous peoples’ ancestral domain claims. PGEC also filed with the National Grid Corporation of the Philippines (NGCP) for the conduct of the grid impact study (GIS) which will determine the feasibility of interconnecting the Nabas wind project to the Visayas Grid. A detailed topographic survey of the likely development areas of the project, including an inventory of existing private and public lots was likewise undertaken.

On November 8, 2011, the DOE approved the Deed of Assignment and Assumption transferring the WESC from the Parent Company to PGEC. The DOE also granted the one-year extension of the pre-development phase from September 13, 2011 to September 13, 2012.

As of December 31, 2011 and 2010, wind data gathering activities are still ongoing. Research costs relating to the Wind Energy Projects amounted to $147,813, $114,476 and $62,934 in 2011, 2010 and in 2009, respectively, and are included as “research costs” under “General and administrative expenses” in the consolidated statements of income.

30. MGI Contracts and Agreements Other major contracts entered into by MGI are as follows: c.

Remote Monitoring System and Technical Advisory Services Agreement On August 19, 2011, MGI entered into an agreement with Fuji Electric to conduct the operation and maintenance of the Maibarara power plant. This will include the monitoring of the power plant operations remotely from Tokyo, Japan through a remote monitoring system to be established by the Fuji Electric. Further, Fuji Electric shall provide site technical services to the power plant in instances wherein the power plant encounters technical problems during emergency situation.

For the remote monitoring services, the fee amounts to ¥3 million. For the technical advisory services, the fee is based on a certain rate per hour and per day. This agreement shall be for a period of one (1) year commencing on the expiry of the warranty period of the EPC contract for the construction of power plant, renewable every year thereafter upon agreement of both parties.

d.

Transmission Service Agreement On August 18, 2011, MGI entered into an agreement with NGCP wherein the latter shall provide the necessary transmission services to MGI, and MGI shall pay the applicable charges for such services in accordance with the Open Access Transmission Service (OATS) rule and the schedules.

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This agreement shall take effect on the day when this agreement and the related agreements shall have been executed. This shall continue to be in full force and effect until July 15, 2021, unless extended or earlier terminated in accordance with this agreement. e.

Connection Agreement On August 18, 2011, MGI entered into an agreement with NGCP wherein the parties acknowledge and agree to a generation facility’s connection point, and MGI shall pay the applicable connection charges based on the OATS rule, the Philippine Grid Code, and all applicable ERC issuances, as may be amended from time to time.

This agreement shall take effect on the day when this agreement and the related agreements shall have been executed. This shall continue to be in full force and effect until July 15, 2021, unless extended or earlier terminated in accordance with this agreement.

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Board of Directors

92

Carlo S. Pablo

Raul M. Leopando

Cesar A. Buenaventura

Basil L. Ong

DIRECTOR

DIRECTOR

DIRECTOR

DIRECTOR

PETROENERGY

Yvonne S. Yuchengco

Helen Y. Dee

Milagros V. Reyes

DIRECTOR

CHAIRMAN

DIRECTOR

Officers and Managers

Milagros V. Reyes PRESIDENT

Francisco G. Delfin, Jr. VICE PRESIDENT

Yvonne S. Yuchengco TREASURER

Atty. Arlan P. Profeta

Atty. Samuel V. Torres

Carlota R. Viray

HEAD, LEGAL & CORPORATE AFFAIRS

CORPORATE SECRETARY

CHIEF FINANCIAL OFFICER

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OFFICERS President: Milagros V. Reyes Vice President: Francisco G. Delfin, Jr. PhD Treasurer: Yvonne S. Yuchengco Corporate Secretary: Samuel V. Torres CORPORATE DIRECTORY Auditors SGV & CO 6760 Ayala Ave, Makati City Bankers RIZAL COMMERCIAL BANKING CORPORATION Ortigas Malayan Plaza Ground Floor corner Opal Road ADB Avenue, Ortigas Business Center Pasig City Transfer Agent RIZAL COMMERCIAL BANKING CORPORATION Ground floor, Grepalife Building 221 Sen. Gil J. Puyat Avenue, Makati City (632) 892.4156; 892.1461 Executive Office PETROENERGY RESOURCES CORPORATION 7th Floor JMT Corporate Building, ADB Ave. Ortigas Business Center, Pasig City Telephone Nos. (632) 637 .2917; 637. 5799; 637. 4032; 637.4362 Fax: (632) 634.6066; 633.8584 Email: petro_energy@petroenergy.com.ph Website: www.petroenergy.com.ph

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PetroEnergy Resources Corporation 7th Floor JMT Corporate Building, ADB Ave. Ortigas Business Center, Pasig City Tel: (632) 637-2917 • 637-5799 • 637-4032 • 637-4362 Fax: (632) 634-6066 • 633-8584 Email: petro_energy@petroenergy.com.ph

www.petroenergy.com.ph