2013-perc-annual-report by Philippine Integrated Advertising Agency, Inc.

A NNUA L R E P OR T

2013 FORGING AHEAD

ABOUT THE COVER PetroEnergy’s achievements this year are characterized by strong steady progress in its various energy ventures. Like blocks fused together, the Company’s oil and renewable energy projects when viewed as one represents the Company’s solid foundation of creating value for its shareholders. With steadfast leadership and corporate governance, valuable contribution from its staff, and unwavering support from its shareholders, PetroEnergy remains firm in its mission to move ahead and grow into one of the most profitable publicly-listed energy companies in the country.

Construction of New Etame Platform

Table of Contents

Financial Highlights

Message from the Chairman & President

Statement of Management’s Responsibility for Financial Statements

Independent Auditor’s Report

Financial Reports

Notes to Financial Statements

Board of Directors

118

Corporate Directory

120

Construction of Platform Support

Financial Highlights 04 |

FORGING AHEAD | ANNUAL REPORT 2013

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

C ON S OLI DAT E D 2013 2012

(as restated)

2013

PA R E NT 2012 C HANGE

(as restated)

AS S E TS

115,518

91,446

58,522

43,866

33.41%

L iabilities

64,564

44,316

12,230

1,049

1,065.87%

Stockholder’ s E quit y

50,954

47,130

46,292

42,817

8.12%

O il R e venue

13,717

11,990

13,717

11,990

14.40%

Operating I ncome

7,105

5,342

7,105

5,342

33.00%

NET INCO M E B E FO R E TAX

3, 287

3,236

5,596

4,275

30.90%

Net I ncome

1,523

2,336

3,832

3,376

13.51%

Boo k Value per S hare

0.151

0.169

0.156

8.33%

Earnings per S hare

0.008

0.009

0.014

0.012

13.51%

C urrent R atio

3.39:1

5.90:1

2.83:1

17.04:1

Debt- to E qu i ty R ati o

1.27:1

0.94:1

0.26:1

0.02:1

Average C rude O il P rice

$107.53

$111.31

Oil Production B AR R E L S

6,244

7,045

(I N THOUSA N DS)

$107.53 $111.31 6,244

7,045

-3.40% -11.37%

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Message from the Chairman & President

FORGING AHEAD | ANNUAL REPORT 2013

Dear Fellow Stockholders, The year 2013 was a banner year for your Company. True to its commitment of fostering steady growth, PetroEnergy has managed to increase oil revenues by 14.4%, net income by 13.51%, and earnings per share by 13.51%. Production from our Gabon oil operations totaled 6.24 million barrels (mmbo), with average crude oil price of $107.53/bbl. While these are 11.37% and 3.40% lower compared to that in 2012, our income before income tax still soared by 30.90%. These arose from higher average cost recovery from expansion activities conducted during the year such as construction of two new production platforms, facility upgrades in the existing platforms, and further exploration campaigns, all aimed at increasing and sustaining oil production in the future. In order to increase its presence in the local oil industry, your Company acquired a 15% participating interest in Service Contract No. 75 Northwest Palawan together with Philex Petroleum Corporation (50%) and PNOC Exploration Corporation (35%). Geological and Geophysical studies will be conducted in the contract area during the initial sub-phase of this project.

field and power plant development, has the prestige of being the first geothermal facility in the country to be commissioned and operated since 2007, and the first under the Renewable Energy Act of 2008.

Aside from developments in the upstream oil industry, your Company’s entry into the downstream energy business through Maibarara Geothermal, Inc. (MGI) and PetroWind Energy, Inc. (PWEI) has already materialized from a mere vision into a very promising aggregation of new and environment-friendly energy ventures.

Indeed, your Company has now transformed from a low-key upstream petroleum player into a diversified energy company whose portfolio includes power generation projects from clean sources, as well.

Million US$

MGI’s 20MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas was successfully connected to the Luzon Grid, in late 2013 and in early February 2014, already started commercial operation. The MGPP, which is an integrated steam

On the other hand, PWEI’s Nabas Wind Power Project (NWPP) in Nabas and Malay, Aklan is now in full development swing, following the declaration of its commerciality by the Department of Energy (DOE), financial closure with the Development Bank of the Philippines, and the entry of CapAsia ASEAN Wind Holdings Cooperatief, U.A. and EEI Power Corporation as equity partners. The NWPP is among the leading contenders for the first 200 MW Feed-in-Tariff (FIT) allocation set by the DOE and the Energy Regulatory Commission (ERC).

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Gabon Operations 2013 Overall Crude Production

Etame Expansion Project

Total crude produced in 2013 reached 6.24 Million barrels (mmbo), with oil production ranging from 11,400 – 19,700 barrels of oil per day (bopd) from three oil fields – Etame, Avouma, and Ebouri. The new production well EAVOM-3H was put on-line on April 9, 2013 and is now contributing ~1,600 bopd to the overall daily production from the Avouma platform.

On December 27, 2012, the Gabonese Government approved the platform construction for Etame and Southeast Etame/ North Tchibala (SEENT) expansion program, covering a 15-18 month construction period. This program primarily aims to bring production from 25, 000 to 30, 000 BOPD and to improve the ultimate recoverable reserves.

Due to the natural depletion of the field, increased gas and water contents in some of the wells, successive drilling activities in the Avouma and Ebouri platforms, and transient production downtimes, the average daily production was reduced to ~17,000 bopd compared to 2012’s average of ~18,000-19,000 bopd. Nonetheless, our consortium managed 15 liftings for the year resulting in a net crude export of 6.31 mmbo. Crude oil prices for the year averaged US$107.53 per barrel.

The platform topsides facilities design and fabrication were undertaken in 2013, while the transport and installation of parts will be done in 2014. The Gabonese Government has put on hold the approval of the production drilling until next year, pending the presentation of budget and the number and location of the production wells. By end of 2013, most of the long lead items for the Etame and SEENT expansion program had been purchased, while structural fabrication is on-going in Galveston, Texas. Transportation and Installation which have been awarded to EMAS in July 2013 will commence in April 2014. Installation of the platforms is scheduled in June-July 2014.

Aside from the current production activities in the three fields, the Etame consortium pursued the expansion of the existing Etame field. Two new production platforms were fabricated alongside major facilities upgrades in the existing platforms of Ebouri and Avouma fields. All these efforts are geared towards increased oil production and the extension of economic life of the fields.

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FORGING AHEAD | ANNUAL REPORT 2013

Platform Installation Vessel

Brownfield Projects Upgrade The Avouma Water Knock-Out System was installed and hooked-up during the First Quarter of 2013. The system, which will increase crude output going to the Floating Production Storage and Offloading (FPSO) vessel by enhancing the platform’s capacity to separate water from the oil, was fully operational since August 2013.

Ebouri Crude Sweetening Project

Platform’s Main Crane

The Ebouri wells EEBOM-3H and EEBOM-4H, which contribute ~2,000 bopd, have been shut-in since July 2012 due to high H2S. For safety purposes, these wells have been serviced for temporary abandonment in June 2013, and H2S detection devices were installed in the platform. The consortium then conducted a Crude Sweetening Process Study and is currently in the pre-front end engineering (pre-FEED) phase. Results are expected first quarter of 2014.

Drilling Campaign for 2013-14

Construction of New Etame Platform

The Ben Rinnes jack-up rig of KCA Deutag mobilized from Port Gentil to the Avouma Platform in late-December 2012 and started the drilling of EAVOM-3P well on January 21, 2013. Successful tagging of oil-bearing Gamba reservoirs led to the drilling of the horizontal drain EAVOM-3H, which served as the new production well from Avouma. After reaching ~2,900 meters on March 8, 2013, the rig skidded to nearby EAVOM-2H and ETBSM-1H wells on March, 26, 2013 to perform work-over procedures to replace their Electric Submersible Pumps (ESP). The Ben Rinnes rig then moved to the Ebouri Platform on May 20, 2013 and commenced drilling of EEBOM-5P well on May 27, 2013. The 34-day operation yielded negative results. The rig skidded to EEBOM-3H and EEBOM-4H for well service procedures after the temporary abandonment of these wells. The rig was skidded to EEBOM-2H well on July 4, 2013 to replace its two ESP units.

Flexible Platform Pipelines

Operations in the Ebouri platform were completed on July 22, 2013, after which the rig moved to the location of open-water exploration well EOVKM-1 – the Ovoka Prospect, to test the prospectivity of the deeper sedimentary horizons. This turned out to have poor reservoir quality of sands. The well was plugged and abandoned as a dry hole on August 30, 2013. After the drilling of EOVKM-1, the Ben Rinnes jack-up rig was then handed over to Tullow Oil Plc on September 9, 2013 for a two-well drilling program in Tullow Oil’s Kiasserny block. The rig returned to the Etame block on December 20, 2013 to drill the Dimba exploration well (EDMBM-1) in the shallower portion of the concession area.

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SC 6A OCTON SC 75 NORTHWEST PALAWAN

SC 14C2 WEST LINAPACAN

SC 47 OFFSHORE MINDORO

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FORGING AHEAD | ANNUAL REPORT 2013

SC 51 EASTERN VISAYAN BASIN

PetroEnergy's Petroleum Service Contracts

Philippine Oil Projects Activities in our Philippine petroleum blocks were mostly carried out by farmors in our various Service Contracts. For 2013, focus was on the conduct of further geological and geophysical studies in several areas, alongside an onshore exploration drilling. PetroEnergy also added a new petroleum block in its acreage by taking in a 15% participating interest in Service Contract 75 (SC 75) in NorthWest Palawan. The Consortium of Philex Petroleum (50%), PNOC Exploration Corporation (35%), and PetroEnergy Resources Corp. (15%) was awarded with SC 75 by the DOE on December 27, 2013.

SERVICE CONTRACT 6A – Octon, Northwest Palawan After the conduct of Information, Education and Communication (IEC) activities and upon securing the necessary endorsements from the Palawan local government units (Palawan Council for Sustainable Development and the Sangguniang Panlalawigan of Palawan) in February to June 2013, Operator Pitkin Petroleum Plc secured DOE approval for the conduct of the 3D seismic survey for Phase 1. On July 30, 2013, the consortium granted Pitkin’s request for a one year extension of time within which to complete Phase 1. The seismic vessel M/V Voyager Explorer commenced the acquisition of 508 sq.km of 3D seismic data on October 5, 2013 and 48.5 line-km of 2D seismic data tying the Bantac-1 well in SC 57 and the Malajon-1 well in SC 6A. The survey was completed on November 6, 2013. In consideration of the time needed for seismic interpretation, the consortium agreed with Pitkin to seek DOE approval to extend Phase 1 of the work program for four months, from August 31, 2014 to December 31, 2014. To date, the DOE reply is still forthcoming.

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Dolphin Sighting During the Survey

SERVICE CONTRACT 14C2 – West Linapacan, Northwest Palawan On January 3, 2013, Operator RMA (HK) Ltd. applied to the DOE for a transfer of operatorship of SC 14C2 from RMA (HK) Ltd to its newly formed Singapore-based subsidiary RMA West Linapacan Pte Ltd., which request the DOE approved on May 24, 2013. By the first half of 2013, RMA continued its review work for reserves certification and reservoir simulation, alongside further mapping of the West Linapacan field for additional leads and prospects. In parallel, well trajectory and drilling objective planning were also conducted towards early production and full field development in West Linapacan. RMA sent the final Independent Expert Report (Gaffney Cline & Associates) of the West Linapacan “A” Reserves on September 5, 2013. The WLA field has Proved (1P) oil reserves of 11.6 MMBO and a Proved + Probable (2P) reserves estimate of 18.2 MMBO. This is based on a three-multilateral well development program scheduled in 2014-15. PetroEnergy’s participating interest in SC 14-C2 is 1.03425%, but your Company will be carried free in all exploration and development costs up to attainment of first commercial oil.

West Linapacan Development Wells

SERVICE CONTRACT 47 – Offshore Mindoro and Panay The consortium has a pending request from the DOE for an extension of SubPhase 2. This request was made by PNOC EC, the operator of the block, in 2012. During the year, farm-out efforts have been carried out by the operator. The farmout terms include seismic processing and drilling of one well. As of end of the year, the farmout process has not been completed. PetroEnergy’s participating interest in SC 47 remains at 2.00%.

SERVICE CONTRACT 51 – East Visayan Basin

Duhat-2 Drilling

On January 28, 2013, the DOE approved the SC 51 North block consortium’s election to enter Subphase 5, which includes drilling of the Duhat-2 well in NW Leyte. After acquiring all the necessary permits from the LGUs and appropriate site preparations in San Isidro, Leyte, Duhat-2 was spudded by Operator Otto Energy Investments Ltd. on July 24, 2013. Upon reaching a depth of 201m on July 26, 2013, voluminous salt water flow occurred. Otto decided to plug and abandon the well to prevent adverse environmental impact to the local community. Similar to the previous Duhat-1 well, the Farmors, Alcorn Energy (now Cosco Capital), TransAsia Oil and

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FORGING AHEAD | ANNUAL REPORT 2013

Development Corp., and PetroEnergy did not credit Duhat-2 as an “earning well”. The DOE for its part declared that Duhat-2 failed to satisfy the work commitment for subphase 5. Otto Energy appealed to the DOE and was given a 6-month extension to conduct further geologic assessment of Duhat-2 for the remainder of Subphase 5.

SERVICE CONTRACT 75 – West Philippine Sea, Northwest Palawan The joint study and bid group consisting of Philex Petroleum Corporation, PNOC-EC and PetroEnergy was notified by the DOE that the group had won the bidding for Area 4 of the Philippine Energy Contracting Round 4 (PECR 4) last February 14, 2013. The block is located in deepwater areas offshore Northwest Palawan, in the West Philippine Sea. After finalization of contract terms, the consortium formally executed Service Contract 75 with the DOE on December 19, 2013. Secretary Petilla then signed on behalf of DOE last December 27, 2013. Under the newly-executed Service Contract, the first Sub-phase with a 24-month duration will consist of Geological & Geophysical (G&G) studies and the conduct of a 2,200 line-km 2D seismic survey over SC 75, at an estimated cost of US$ 3.50 MM. After 16 days of line acquisition, the vessel completed the survey on April 15, 2014. After which the vessel and crew demobilized from Northwest Palawan on April 17, 2014. Philex Petroleum is the Operator of SC 75 with 50% participating interest, PNOC-EC with 35%, and PetroEnergy with 15%. Navigation Panels

Seabird’s M/V Voyager Explorer

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Renewable Energy Maibarara Geothermal Power Project The year 2013 was a productive year for the Maibarara Geothermal Power Project (MGPP), run by our subsidiary MGI. Construction of the Steamfield, Power Plant, Switchyard and Transmission Line facilities was in full-swing. By year-end, these facilities successfully underwent commissioning and testing. As part of the pre-commissioning phase, steam flushing of the steamfield surface facilities was started on May 17, 2013. This activity was followed by system pressurization on June 20, 2013. When the desired operating pressure was attained, the steam was temporarily diverted to the blow-off and rock muffler until such time that the power plant was ready to accept the steam for commissioning and testing. A successful work-over of reinjection well, Mai-11D, was undertaken from September 8-18, 2013. The objective of the work-over was to mechanically drill-out the scales that have developed inside the wellbore after being used as an injector of cooled brine for over two years. An important milestone was achieved when the target plate testing was successfully carried out last August 9, 2013. The two plate tests passed the inspection of the Japanese engineers from Fuji Electric Co. (Japan). After its completion in August, Maibarara’s 115kV Transmission Line system was successfully connected to the existing Meralco line on September 10, 2013. Meanwhile, on October 7, 2013, the Energy Regulatory Commission (ERC) granted MGI the Certificate of Compliance (COC) allowing MGI to operate the Maibarara Geothermal Power Plant. Finally, on November 2, 3013, the valve connecting the steamline and the power plant was opened and initial steam admission took place. The steam admission was followed by grid synchronization on November 4, 2013. During the succeeding commissioning tests, an issue with the turbine’s Main Control Valve (MCV) was detected and the valves were shipped to Fuji’s plant in Japan for inspection and repair. The MCVs were shipped back to the site in late December and reinstalled in early January 2014. After the reliability and performance testing, the Maibarara Power Plant went on commercial operations in February 8, 2014.

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FORGING AHEAD | ANNUAL REPORT 2013

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The Well Tracks contain all the geothermal wells

Separator Vessel separates steam from water

Steamline to the PP

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FORGING AHEAD | ANNUAL REPORT 2013

The separated water is returned to the ground through

reinjection wells

Maibarara Geothermal Power Facility Features

TG Building

Switchyard (S/y)

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90m (Diameter)

Nacelle

Hub Rotor Blade

Nabas Wind Power Project Features

Anatomy of a Wind Turbine Generator(WTG)

Tower

90m (H)

Transformer

2,025

Hectares

Total Service Contract Area

69KV

Transmission Line

64 Poles in 6km

50MW PHASE

Generation Capacity 1-18 WTGs 2-7 WTGs

Panay Island 9m wide Substation

3.5KM Access Road

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FORGING AHEAD | ANNUAL REPORT 2013

Distribution Facility

Nabas Wind Power Project Significant progress was achieved in 2013 in proving the viability of the project and in ensuring its early start. Critical milestones covering regulatory approvals, project financing, and wind farm design and construction were successfully hurdled.

Boracay Island

10mins

away from Caticlan/Boracay Port

In May, 2013, the DOE conferred the Confirmation of Commerciality for the 50 MW Nabas wind power project in Nabas, Aklan. In confirming the project commercial, the DOE also effectively converted the Nabas service contract from exploration stage to development phase with a contract life of 25 years, or until 2034. As part of the venture into wind energy production, PERC incorporated a new subsidiary – PetroWind Energy, Inc. (PWEI) – in March, 2013 to handle the Nabas project development, from securing financing through project construction and eventual operations and maintenance. DOE approved the transfer of the Nabas service contract from PetroGreen Energy Corp. (PGEC) to PWEI in July, 2013. Subsequently, two investors acquired equity positions in PWEI. EEI Power, a subsidiary of EEI Corp., acquired a 20% stake in PWEI, while Capital Advisors Partners Asia Pte Ltd. (CapAsia), a Singapore-based investment fund, secured a 40% stake, leaving PGEC with a 40% interest in the Company. On Nov. 4, 2013, DBP granted PWEI a P2.8 Billion loan for the project payable in 15 years; such loan was the first ever extended by DBP for a wind power project. Substantial progress was achieved in the technical design and construction aspects of the project. Even as the DOE’s decision on the confirmation of commerciality was awaited, PWEI initiated the rehabilitation of the existing access road to the wind farm as part of its corporate social responsibility efforts. The rehabilitation was started in May, 2013 with the goal of widening the 5-km long barangay road to accommodate the entry of equipment. Late 2013, PWEI also signed key construction and supply contracts covering the switchyard and transmission line with Cendaur Engineering, civil works on the wind farm including internal roads, turbine foundations, and control room buildings with EEI Corp., and wind turbine supply, installation, maintenance and operation with Gamesa Eolica of Spain. All these have set the stage for an accelerated program to finish the installation of the wind farm by late 2014 to early 2015.

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Corporate Social Responsibility

For 2013, the Company designed its Corporate Social Responsibility (CSR) Program to be a more systematic and integrated scheme, focused on establishing sustainable programs in health, education, and livelihood under the Power to H.E.L.P (Health, Education, Livelihood Program) drive. This is aimed at empowering the residents of our Projects’ host communities particularly those from Sitio Capuz, San Rafael, Sto. Tomas, Batangas through MGI and Brgy. Pawa, Nabas, Aklan through PWEI. The initial step taken to ensure that projects implemented are suited to the communities needs, was to conduct extensive community profiling programs both in Sto. Tomas and Nabas. This enabled the Company to gather baseline information on the communities’ socio-economic profile, family characteristics, educational background, income and expenditures data, as well as their current and perceived livelihood needs. These information were used to craft the general template and framework for PERC’s long-term CSR programs.

On Health

On Education

PERC’s health projects stress the need to ensure that the residents of the host communities have access to medical services and proper nutrition.

The education projects cover three objectives: to engage the community through information, to educate them through formal programs, and to enable them by providing proper education materials and facilities.

The on-going Feeding Program from April to December 2013 in Sto. Tomas, Batangas has benefited a total of 29 out-of-school children and 31 elementary pupils ages 5-11 who were identified to be malnourished. Quarterly assessments of the project indicate that almost 70% of the children beneficiaries have gained normal body mass indices (BMI), after 10 months of feeding. This project will continue until second quarter of 2014 with continuous monitoring to ensure that the beneficiaries and their families will be able to sustain the routine of preparing healthy, more nutritious meals. The medical missions were pursued to help the community gain access to basic medical services. The medical mission in Sto. Tomas was conducted last August 31, 2013 in partnership with a local hospital and the municipal health officials. The activity benefited 260 residents from San Rafael Sto. Tomas, Batangas and Puting Lupa, Calamba City. Similar health and medical missions, including a seminar on herbal remedies, are scheduled for the residents of Brgy. Pawa in Nabas, Aklan in 2014.

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To properly inform our host communities on how the Projects affect them, separate Information and Education Campaigns (IECs) were conducted in Sto. Tomas, Batangas and in Nabas, Aklan. The IECs will continue all throughout the year and will be expanded to include multi-media lectures as well as mobile education or “Lakbay-aral” initiatives. The Company’s banner project for education, the Teachers’ Training Program, was launched in Nabas, Aklan in December 2013 with a 3-year comprehensive training program with a theme: Empowering Teachers as Lifelong Learners. This will cover instructional leadership and competency development in the delivery of lessons for secondary students. The first leg of the program will be conducted by our partners from Malayan Colleges Laguna (MCL) for teachers from four (4) schools - Unidos National High School, Toledo National High School, Solido National High School, and Union National High School.

FORGING AHEAD | ANNUAL REPORT 2013

On Livelihood PERC’s livelihood programs are anchored on sustainability and resilience. To achieve this, a systematic approach is employed consisting of regular community consultations, active participation of community members, and adequate social preparation. The livelihood project in Sto. Tomas, Batangas remains focused on providing direct employment for select residents who have technical and practical qualifications and employable skills. These residents are employed in various posts, from engineering and technical to administrative positions. In parallel, the livelihood program was initiated in Brgy. Pawa, Nabas, Aklan through a site assessment activity of social and agriculture experts to determine other sources of income suited for the community. The drive is directed towards building-up the community’s existing backyard industries such as farming and mat-weaving for their sustenance and basic consumption. In the following years, new livelihood opportunities will be introduced to promote livelihood variety and resiliency. All these livelihood plans are anchored on the vision that Brgy. Pawa can soon be an agro-ecotourism destination in the province of Aklan.

Forging Ahead With these significant achievements in 2013, your Company continues to be steadfast in reaching more milestones in 2014 and the years to come. We forge ahead, taking steady steps through calculated decisions combined with prompt and effective action in our every endeavor. This strategy has brought your Company to where we are now, a consistently profitable publicly listed energy company, and will keep us ready for more investment opportunities in the future.

Helen Y. Dee Chairman

Milagros V. Reyes President

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The Power

Health

Education

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to H . E . L . P

Livelihood P ET ROEN ERG Y RESOU RC ES C OR P O R ATI O N

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Consolidated Financial Statements

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FORGING AHEAD | ANNUAL REPORT 2013

Nabas Wind Power Project Site

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Statement of Management's Responsibility for Financial Statements

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FORGING AHEAD | ANNUAL REPORT 2013

SyCip Gorres Velayo & Co. 6760 Ayala Avenue 1226 Makati City Philippines

Tel: (632) 891 0307 Fax: (632) 819 0872 ey.com/ph

BOA/PRC Reg. No. 0001, December 28, 2012, valid until December 31, 2015 SEC Accreditation No. 0012-FR-3 (Group A), November 15, 2012, valid until November 16, 2015

INDEPENDENT AUDITORS’ REPORT

The Stockholders and the Board of Directors PetroEnergy Resources Corporation We have audited the accompanying consolidated financial statements of PetroEnergy Resources Corporation and Subsidiaries (the Group), which comprise the consolidated statements of financial position as at December 31, 2013 and 2012, 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, 2013, 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.

*SGVFS006399* A member firm of Ernst & Young Global Limited

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-2Opinion 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, 2013 and 2012, and their financial performance and their cash flows for each of the three years in the period ended December 31, 2013 in accordance with Philippine Financial Reporting Standards. Emphasis of Matter Without qualifying our opinion, we draw attention to Note 10 to the consolidated financial statements, which discusses the suspension of the production activities in the West Linapacan Oilfield. Among the other operations of the Group, the suspension of the production activities in the West Linapacan Oilfield raises uncertainties as to the profitability of the petroleum operations for the said oilfield. The profitability of petroleum operations related to the said oilfield is dependent upon the discovery of oil in commercial quantities that would result from the successful redevelopment activities thereon. SYCIP GORRES VELAYO & CO.

Michael C. Sabado C. Sabado Partner CPA Certificate No. 89336 SEC Accreditation No. 0664-AR-1 (Group A), March 11, 2011, valid until March 10, 2014 Tax Identification No. 160-302-865 BIR Accreditation No. 08-001998-73-2012, April 11, 2012, valid until April 10, 2015 PTR No. 4225212, January 2, 2014, Makati City February 18, 2014

*SGVFS006399* A member firm of Ernst & Young Global Limited

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (In U.S. Dollars)

December 31 2012 (As restated Note 3) 2013

January 1 2012 (As restated Note 3)

$2,571,568 914,606

$21,622,222 814,741

$21,904,284 �

138,058 2,606,855 218,217

142,827 1,982,027 414,764

109,018 2,076,016 447,499

16,933,520 23,382,824

4,966,548 29,943,129

7,048,600 31,585,417

75,072,340 11,397,210 266,522 31,417 5,368,328 92,135,817 $115,518,641

51,455,856 6,643,203 140,523 31,417 3,232,354 61,503,353 $91,446,482

21,297,963 5,831,668 82,203 31,417 1,734,225 28,977,476 $60,562,893

Current Liabilities Accounts payable and accrued expenses (Notes 15, 18 and 24) Current portion of loan payable (Notes 16, 18 and 24) Income tax payable (Notes 18 and 20) Total Current Liabilities

$3,944,717 2,238,080 722,479 6,905,276

$5,002,365 െ 75,015 5,077,380

$3,455,507 െ 243,474 3,698,981

Noncurrent Liabilities Loans payable - net of current portion (Notes 9, 16, 18 and 24) Accrued retirement liability (Notes 5, 18 and 19) Asset retirement obligation (Notes 5, 17 and 18) Total Noncurrent Liabilities Total Liabilities

57,214,557 116,175 328,389 57,659,121 64,564,397

38,943,444 57,812 237,668 39,238,924 44,316,304

13,295,139 33,572 474,293 13,803,004 17,501,985

ASSETS Current Assets Cash and cash equivalents (Notes 6 and 24) Short-term investments (Notes 6 and 24) Financial assets at fair value through profit or loss (Notes 7 and 24) Receivables (Notes 5, 8 and 24) Crude oil inventory Prepaid expenses and other current assets (Notes 9 and 16) Total Current Assets Noncurrent Assets Property, plant and equipment (Notes 5, 10 and 16) Deferred oil exploration costs (Notes 5, 11 and 25) Deferred tax assets - net (Notes 5, 20 and 25) Investment properties (Notes 5 and 12) Other noncurrent assets (Notes 14 and 24) Total Noncurrent Assets

LIABILITIES AND EQUITY

(Forward)

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-2-

Equity Attributable to equity holders of the Parent Company Capital stock (Note 18) Additional paid-in capital (Note 18) Retained earnings Appropriated (Note 18) Unappropriated (Note 18) Remeasurements of net accrued retirement liability (Notes 3, 18 and 19) Cumulative translation adjustment (Notes 5 and 18) Noncontrolling interests (Notes 18 and 27) Total Equity

December 31 2012 (As restated Note 3) 2013

January 1 2012 (As restated Note 3)

$6,321,533 25,244,737

3,149,555 7,730,281

2,055,555 6,928,309

2,055,555 5,656,403

(47,563) (1,120,775) 41,277,768 9,676,476 50,954,244 $115,518,641

(5,707) 778,372 41,322,799 5,807,379 47,130,178 $91,446,482

(12,720) (56,227) 39,209,281 3,851,627 43,060,908 $60,562,893

See accompanying Notes to Consolidated Financial Statements.

*SGVFS006399* 30 |

FORGING AHEAD | ANNUAL REPORT 2013

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME

(In U.S. Dollars)

Years Ended December 31 2012 2011 (As restated (As restated Note 3) Note 3) 2013 $13,717,422

$11,990,120

$13,544,412

5,163,930 1,448,670 6,612,600

5,026,209 1,622,262 6,648,471

5,432,149 1,855,082 7,287,231

GROSS INCOME

7,104,822

5,341,649

6,257,181

GENERAL AND ADMINISTRATIVE EXPENSES (Note 22)

3,683,822

3,009,277

2,693,340

202,431

506,150

524,558

7,456 (44,070) (117,524) (189,072) 6,761 (134,018)

24,880 (31,895) െ 384,278 20,220 903,633

(79,588) (62,433) െ 95,112 1,428 479,077

OIL REVENUES COST OF OIL REVENUES Oil production (Note 21) Depletion (Note 10)

OTHER INCOME (CHARGES) Interest income (Note 6) Net gain (loss) on fair value changes on financial assets at fair value through profit or loss (Note 7) Accretion expense (Note 17) Interest expense Net foreign exchange gain (loss) Miscellaneous income INCOME BEFORE INCOME TAX

3,286,982

3,236,005

4,042,918

PROVISION FOR INCOME TAX (Notes 20 and 25)

1,763,572

899,560

1,337,611

NET INCOME (Note 25)

$1,523,410

$2,336,445

$2,705,307

NET INCOME ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 27)

$2,211,220 (687,810)

$2,559,582 (223,137)

$2,925,394 (220,087)

NET INCOME

$1,523,410

$2,336,445

$2,705,307

$0.008

$0.009

$0.010

EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF THE PARENT COMPANY – BASIC AND DILUTED (Note 26) See accompanying Notes to Consolidated Financial Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In U.S. Dollars)

Years Ended December 31 2012 2011 (As restated (As restated Note 3) Note 3) 2013 NET INCOME

$1,523,410

$2,336,445

$2,705,307

OTHER COMPREHENSIVE INCOME (LOSS) Items to be reclassified to profit or loss in subsequent periods Movement in cumulative translation adjustment

(1,899,147)

834,600

(115,390)

(41,856)

7,013

(12,720)

($417,593)

$3,178,058

$2,577,197

$270,217 (687,810) ($417,593)

$3,401,195 (223,137) $3,178,058

$2,797,284 (220,087) $2,577,197

Items not to be reclassified to profit or loss in subsequent periods Remeasurement gains (losses) on net accrued retirement liability - net of tax (Notes 3, 18 and 19) TOTAL COMPREHENSIVE INCOME (LOSS) TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 27)

See accompanying Notes to Consolidated Financial Statements.

*SGVFS006399* 32 |

FORGING AHEAD | ANNUAL REPORT 2013

P ET ROEN ERG Y RESOU RC ES C OR P O R ATI O N

|33

Balances at beginning of year, as previously reported Effect of the adoption of the Revised PAS 19 (Note 3) Balance at beginning of year, as restated Net income (loss) Net income (loss), as previously reported Effect of adoption of the Revised PAS 19 (Note 3) Net income (loss), as restated Other comprehensive income (loss) Effect of adoption of the Revised PAS 19 (Note 3) Movement in cumulative translation adjustment Total comprehensive income (loss) Increase in noncontrolling interests - stock issuances (Note 27) Cash dividends (Note 18) Balances at end of year

Balances at beginning of year Net income (loss) Remeasurement loss on net accrued retirement liability (Note 3) Movement in cumulative translation adjustment Total comprehensive income (loss) Increase in noncontrolling interests - stock issuances (Note 27) Appropriation of retained earnings (Note 18) Cash dividends (Note 18) Balances at end of year

(In U.S. Dollars)

$25,244,737 � 25,244,737 � � � � � – – – $25,244,737

� � � � � � – – $6,321,533

� � � $25,244,737

� � � $6,321,533

$6,321,533 � 6,321,533

� �

� � � 1,094,000 � $3,149,555

� �

$2,055,555 � �

� (1,094,000) (315,248) $7,730,281

� 2,211,220

$6,928,309 2,211,220 �

– – $2,055,555

� � –

� � �

$2,055,555 � 2,055,555

– (1,287,676) $6,928,309

� � 2,559,582

2,557,737 1,845 2,559,582

$5,637,881 18,522 5,656,403

For the Year Ended December 31, 2012

$25,244,737 � �

For the Year Ended December 31, 2013

Additional Paid-in Capital (Note 18)

$6,321,533 � �

Capital Stock (Note 18)

– � ($5,707)

7,013 � 7,013

� � �

$� (12,720) (12,720)

� � � ($47,563)

� (41,856)

($5,707) � (41,856)

� � $778,372

� 834,600 834,600

� � �

($56,228) � (56,228)

� � � ($1,120,775)

(1,899,147) (1,899,147)

$778,372 � �

Attributable to Equity Holders of the Parent Company Remeasurement of Net Accrued Cumulative Appropriated Unappropriated Retirement Translation Retained Retained Liability Adjustment (Notes 3, (Notes 5 Earnings Earnings (Note 18) (Note 18) 18 and 19) and 18)

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

� (1,287,676) $41,322,799

7,013 834,600 3,401,195

2,557,737 1,845 2,559,582

$39,203,478 5,802 39,209,280

� � (315,248) $41,277,768

(1,899,147) 270,217

$41,322,799 2,211,220 (41,856)

Total

2,178,889 (1,287,676) $47,130,178

7,013 834,600 3,178,058

2,334,600 1,845 2,336,445

$43,055,105 5,802 43,060,907

4,556,907 � (315,248) $50,954,244

(1,899,147) (417,593)

$47,130,178 1,523,410 (41,856)

Total

*SGVFS006399*

2,178,889 � $5,807,379

� � (223,137)

(223,137) � (223,137)

$3,851,627 � 3,851,627

4,556,907 � � $9,676,476

� (687,810)

$5,807,379 (687,810) �

Noncontrolling Interests (Notes 18 and 27)

Balances at beginning of year, as previously reported Effect of the adoption of the Revised PAS 19 (Note 3) Balance at beginning of year, as restated Net income (loss) Net income (loss), as previously reported Effect of adoption of the Revised PAS 19 (Note 3) Net income (loss), as restated Other comprehensive income (loss) Effect of adoption of the Revised PAS 19 (Note 3) Movement in cumulative translation adjustment Total comprehensive income (loss), as restated Increase in noncontrolling interests - stock issuances (Note 27) Cash dividends (Note 18) Balances at end of year

-2-

$2,055,555 � 2,055,555

2,926,268 (874) 2,925,394

$3,972,684 19,396 3,992,080

(12,720) � (12,720)

� � �

$� � �

Remeasurements of Net Accrued Retirement Liability (Notes 3, 18 and 19)

� � ($56,227)

� (115,390) (115,390)

� � �

$59,163 � 59,163

Cumulative Translation Adjustment (Notes 5 and 18)

� (1,261,071) $39,209,281

(12,720) (115,390) 2,797,284

2,926,268 (874) 2,925,394

$37,653,672 19,396 37,673,068

Total

2,841,116 � $3,851,627

� � (220,087)

(220,087) � (220,087)

$1,230,598 � 1,230,598

Noncontrolling Interests (Notes 18 and 27)

2,841,116 (1,261,071) $43,060,908

(12,720) (115,391) 2,577,196

2,706,181 (874) 2,705,307

38,884,270 19,396 38,903,666

Total

Attributable to Equity Holders of the Parent Company

$25,244,737 � 25,244,737 � � �

� � 2,925,394

� � ($12,720)

For the Year Ended December 31, 2011

Unappropriated Retained Earnings (Note 18)

$6,321,533 � 6,321,533 � � � � � �

� (1,261,071) $5,656,403

Appropriated Retained Earnings (Note 18)

� � � � � �

� � $2,055,555

Additional Paid-in Capital (Note 18)

� � � � � $25,244,737

Capital Stock (Note 18)

� � $6,321,533

See accompanying Notes to Consolidated Financial Statements.

*SGVFS006399*

FORGING AHEAD | ANNUAL REPORT 2013

34 |

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

(In U.S. Dollars)

Years Ended December 31 2012 2011 (As restated (As restated – Note 3) – Note 3) 2013 CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax Adjustments for: Net unrealized foreign exchange loss (gain) Depletion, depreciation and amortization (Note 10) Decrease in accrued retirement liability Accretion expense (Note 17) Interest income Net loss (gain) on fair value changes on financial assets at fair value through profit or loss (Note 7) Gain on sale of property, plant and equipment Interest expense Operating income before working capital changes Decrease (increase) in: Short-term investments Receivables Crude oil inventory Prepaid expenses and other current assets Increase in accounts payable and accrued expenses Cash generated from (used in) operations Interest received Income taxes paid Net cash provided by (used in) operating activities CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of property, plant and equipment (Notes 10 and 28) Proceeds from disposals of: Property, plant and equipment (Note 10) Intangible asset Financial assets at fair value through profit or loss Increase in capitalized interest Increase in Other noncurrent assets Increase in deferred oil exploration costs (Note 11) Increase in deferred geothermal costs Net cash used in investing activities

$3,286,982

$3,236,005

$4,042,918

189,072 1,747,985 (1,432) 44,070 (202,431)

(384,278) 1,863,392 31,567 31,895 (506,150)

(95,112) 2,003,389 (106) 62,433 (524,558)

(7,456) – 117,524 5,174,314

(24,880) (17,892) – 4,229,659

79,588 – – 5,568,552

(99,865) (638,492) 196,547 (12,403,866) (1,318,070) (9,089,432) 221,020 (1,204,624) (10,073,036)

(814,741) 77,537 32,735 1,850,010 1,104,893 6,480,093 482,433 (1,131,830) 5,830,696

� 502,844 (247,087) (486,341) 2,701,284 8,039,252 684,443 (1,369,614) 7,354,081

(25,317,818)

(32,353,911)

(8,775,750)

� � � 3,655,746 (2,135,974) (4,754,007) � (28,552,053)

81,997 � – 2,157,885 (1,263,600) (811,535) – (32,189,164)

– � 1,363,640 10,039 (6,862,760) (996,291) – (15,261,122)

(Forward)

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-2Years Ended December 31 2012 2011 (As restated (As restated – Note 3) – Note 3) 2013 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt (Note 16) Additional capital from noncontrolling interest (Note 27) Dividends paid (Note 18) Interest paid Net cash provided by financing activities EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

$20,946,086

$25,648,305

4,556,907 (339,949) (3,488,147) 21,674,897

2,178,890 (1,252,489) (1,708,953) 24,865,753

(2,100,462)

$1,210,653

(19,050,654)

(282,062)

$12,111,820 2,841,116 (1,243,767) – 13,709,169

$17,672 5,819,800

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

21,622,222

21,904,284

16,084,484

CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 6)

$2,571,568

$21,622,222

$21,904,284

See accompanying Notes to Consolidated Financial Statements.

*SGVFS006399* 36 |

FORGING AHEAD | ANNUAL REPORT 2013

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In U.S. Dollars)

Corporate Information a.

Organization PetroEnergy Resources Corporation (PetroEnergy or 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 1, 2010, the Parent Company signed Geothermal Renewable Energy Service Contract (GRESC) No. 2010-02-012 covering the Maibarara Geothermal Field (“the Field”) in Laguna and Batangas, following a Philippine Energy Contracting Round for Geothermal held by the Department of Energy (DOE) in November, 2009, where the Parent Company emerged as the lone qualified bidder. The Field had been previously explored and relevant resource data identify certain portions thereof as having potential stored heat capacity that can produce electricity in commercial quantities. In order to insulate PetroEnergy’s core oil business from its renewable energy ventures, PetroEnergy, with the approval of the Board on February 23, 2010, created a wholly-owned subsidiary called PetroGreen Energy Corporation (PetroGreen). PetroGreen shall carry-out the renewable energy projects of PetroEnergy. 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. On January 5, 2011, the DOE approved the transfer of the Maibarara GRESC from PetroEnergy to MGI. In January 2013, through a Special Meeting of the Board of Directors, PetroGreen created a subsidiary, PetroWind Energy, Inc. (PetroWind) that will undertake the Nabas Wind Power Project (NWPP). PetroWind was incorporated on March 6, 2013 wherein PetroGreen initially held 100% interest. On July 15, 2013, EEI Power Corporation (EEIPC) subscribed to a 20%

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|37

-2equity share in PetroWind. EEIPC formally became a stockholder of PertroWind upon the SEC’s approval of PetroWind’s increase in authorized capital stock on August 23, 2013. Effectively as of December 31, 2013, PetroGreen holds 80% equity share in PetroWind. MGI and PetroWind are effectively, subsidiaries of the Parent Company through PetroGreen, since the Parent Company wholly owns PetroGreen and PetroGreen owns majority of the voting power of MGI and PetroWind. The Parent Company, PetroGreen, MGI and PetroWind 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 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. See Notes 10 and 11 for updates on the Group’s petroleum operations. Wind Energy The wind energy project is the 36-megawatt (MW) NWPP in Nabas, Aklan, where PWEI is now developing the area. The activities in 2013 concentrated on the application from the DOE for Declaration of Commerciality and selection of contractors for the various project components, such as wind turbine generators (WTG) supply, installation and operation and maintenance, civil works and transmission line and switchyard construction. Financing for project through bank loan was also worked on during the year. See Note 33 for more updates on Wind Energy Service Contract. Geothermal Energy The geothermal project is the 20-MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas where MGI’s construction of the steamfield, power plant, switchyard and transmission line facilities is in full-swing. These facilities were successfully undergoing commissioning and testing in the last quarter of 2013. See Note 10 for more updates on the Group’s geothermal energy operations.

The accompanying consolidated financial statements were approved and authorized for issue by the BOD on February 18, 2014. 2.

Basis of Preparation The accompanying consolidated financial statements have been prepared under the historical cost convention method, except for financial assets carried at fair value through profit or loss (FVPL) and the Parent Company’s crude oil inventory that have been measured at fair value. Figures are presented in United States (US) Dollar ($), the Parent Company’s functional currency. All amounts are rounded to the nearest dollar unless otherwise indicated.

*SGVFS006399* 38 |

FORGING AHEAD | ANNUAL REPORT 2013

-3The consolidated financial statements provide comparative information in respect of the previous period. In addition, the Group presents an additional statement of financial position at the beginning of the earliest period presented when there is a retrospective application of an accounting policy, a retrospective restatement, or a reclassification of items in consolidated financial statements. An additional statement of financial position as at January 1, 2012 is presented in these consolidated financial statements due to retrospective application of Philippine Accounting Standards (PAS) 19 Revised, Employee Benefits. Statement of Compliance The accompanying consolidated financial statements have been prepared in compliance with Philippine Financial Reporting Standards (PFRS). Basis of Consolidation The consolidated financial statements comprise the financial statements of the Group as at December 31, 2013 and 2012. The financial statements of the subsidiaries are prepared for the same reporting year as the Parent Company, using consistent accounting policies. Below are the Parent Company’s subsidiaries with its respective percentage ownership as of December 31, 2013, 2012, and 2011:

PGEC MGI PWEI Navy Road Development Corporation (NRDC)

Percentage of Ownership 2012 2013 100% 100% 65% 65% � 80% 100%

100%

2011 100% 65% � 100%

Subsidiaries are consolidated when control is transferred to the Group and cease to be consolidated when control is transferred out of the Group. Control is achieved when the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Specifically, the Group controls a subsidiary if and only if the Group has: a) Power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee) b) Exposure, or rights, to variable returns from its involvement with the investee, and c) The ability to use its power over the investee to affect its returns When the Group has less than a majority of the voting or similar rights of an investee, the Group considers all relevant facts and circumstances in assessing whether it has power over an investee, including: a) The contractual arrangement with the other vote holders of the investee b) Rights arising from other contractual arrangements c) The Group’s voting rights and potential voting rights The Group re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control.

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-4The consolidated financial statements are prepared using uniform accounting policies for like transactions and other events in similar circumstances. All intercompany balances and transactions, intercompany profits and expenses and gains and losses are eliminated during consolidation. All intercompany balances, transactions, income and expenses and profit and losses are eliminated in full. Noncontrolling interests are presented separately from the Parent Company’s equity. The portion of profit or loss and net assets in subsidiaries not wholly-owned are presented separately in the consolidated statement of income, consolidated statement of comprehensive income and consolidated statement of changes in equity, and within equity in the consolidated statement of financial position. Losses within a subsidiary are attributed to the noncontrolling interests 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: x

Derecognizes the assets (including goodwill) and liabilities of the subsidiary, the carrying amount of any noncontrolling interest and the cumulative translation differences, recorded in equity.

Recognizes the fair value of the consideration received, the fair value of any investment retained and any surplus or deficit in the consolidated statement of income.

Reclassifies the Parent Company’s share of components previously recognized in OCI to the consolidated statement of income or retained earnings, as appropriate.

3. Changes in Accounting Policies The Group applied Revised PAS 19 for the first time and requires restatement of previous financial statements. Several other amendments apply for the first time in 2013, however, they do not impact the annual financial statements of the Group. x

PAS 19, Employee Benefits (Revised) On 1 January 2013, the Group adopted the Revised PAS 19. For defined benefit plans, the Revised PAS 19 requires all actuarial gains and losses to be recognized in OCI and unvested past service costs previously recognized over the average vesting period to be recognized immediately in profit or loss when incurred. Prior to adoption of the Revised PAS 19, the Group recognized actuarial gains and losses as income or expense when the net cumulative unrecognized gains and losses for each individual plan at the end of the previous period exceeded 10% of the higher of the defined benefit obligation and the fair value of the plan assets and recognized unvested past service costs as an expense on a straight-line basis over the average vesting period until the benefits become vested. Upon adoption of the revised PAS 19, the Group changed its accounting policy to recognize all actuarial gains and losses in OCI and all past service costs in profit or loss in the period they occur.

*SGVFS006399* 40 |

FORGING AHEAD | ANNUAL REPORT 2013

-5The Revised PAS 19 replaced the interest cost and expected return on plan assets with the concept of net interest on defined benefit liability or asset which is calculated by multiplying the net balance sheet defined benefit liability or asset by the discount rate used to measure the employee benefit obligation, each as at the beginning of the annual period. The Revised PAS 19 also amended the definition of short-term employee benefits and requires employee benefits to be classified as short-term based on expected timing of settlement rather than the employee’s entitlement to the benefits. In addition, the Revised PAS 19 modifies the timing of recognition for termination benefits. The modification requires the termination benefits to be recognized at the earlier of when the offer cannot be withdrawn or when the related restructuring costs are recognized. Changes to definition of short-term employee benefits and timing of recognition for termination benefits do not have any impact to the Group’s financial position and financial performance. The changes in accounting policies have been applied retrospectively. The effects of adoption on the consolidated financial statements are as follows:

Consolidated statement of financial position Increase (decrease) in: Pension liability Deferred tax asset Remeasurements of net accrued retirement liability Retained earnings

As at December 31 2013 2012

$75,672 22,702 (47,563) (5,407)

As at January 1 2012 2011

($20,943) (6,283)

($8,289) (2,487)

(5,707) 20,367

(12,720) 18,522

($27,709) (8,313) – 19,396

For the years ended December 31 2013 2012 Consolidated statement of income Increase (decrease) in: Pension expense Income before income tax Provision for income tax Net income Consolidated statement of comprehensive income Increase (decrease) in: Net income Remeasurement gains on net accrued retirement liability Total comprehensive income

2011

$36,820 (36,820) (11,046) ($25,774)

($2,636) 2,636 791 $1,845

$1,249 (1,249) (375) ($874)

($25,774)

$1,845

($874)

(41,856) ($67,630)

7,013 $8,858

(12,720) ($13,594)

The adoption did not have any impact on the consolidated statements of cash flows.

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-6The nature and the impact of the new standards and amendments are described below: x

PFRS 7, Financial instruments: Disclosures - Offsetting Financial Assets and Financial Liabilities (Amendments) These amendments require an entity to disclose information about rights of set-off and related arrangements (such as collateral agreements). The new disclosures are required for all recognized financial instruments that are set off in accordance with PAS 32. These disclosures also apply to recognized financial instruments that are subject to an enforceable master netting arrangement or ‘similar agreement’, irrespective of whether they are set-off in accordance with PAS 32. The amendments require entities to disclose, in a tabular format, unless another format is more appropriate, the following minimum quantitative information. This is presented separately for financial assets and financial liabilities recognized at the end of the reporting period: a) The gross amounts of those recognized financial assets and recognized financial liabilities; b) The amounts that are set off in accordance with the criteria in PAS 32 when determining the net amounts presented in the statement of financial position; c) The net amounts presented in the statement of financial position; d) The amounts subject to an enforceable master netting arrangement or similar agreement that are not otherwise included in (b) above, including: i. Amounts related to recognized financial instruments that do not meet some or all of the offsetting criteria in PAS 32; and ii. Amounts related to financial collateral (including cash collateral); and e) The net amount after deducting the amounts in (d) from the amounts in (c) above. The amendments have no impact on the consolidated financial position or performance of the Group.

PFRS 10, Consolidated Financial Statements The Group adopted PFRS 10 in the current year. PFRS 10 replaced the portion of PAS 27, Consolidated and Separate Financial Statements, that addressed the accounting for consolidated financial statements. It also included the issues raised in SIC 12, Consolidation Special Purpose Entities. PFRS 10 established a single control model that applied to all entities including special purpose entities. The changes introduced by PFRS 10 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. A reassessment of control was performed by the Parent Company on all its interest in other entities and has determined that there are no additional entities that are controlled or where control is lost.

PFRS 11, Joint Arrangements PFRS 11 replaced PAS 31, Interests in Joint Ventures, and SIC 13, Jointly Controlled Entities - Non-Monetary Contributions by Venturers. PFRS 11 removed the option to account for jointly controlled entities using proportionate consolidation. Instead, jointly controlled entities that meet the definition of a joint venture must be accounted for using the equity method. The standard has no impact on the consolidated financial statements of the Group.

PFRS 12, Disclosure of Interests in Other Entities PFRS 12 sets out the requirements for disclosures relating to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. The requirements in PFRS 12 are more comprehensive than the previously existing disclosure requirements for

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-7subsidiaries (for example, where a subsidiary is controlled with less than a majority of voting rights). The new disclosure requirements are provided in Note 27. x

PFRS 13, Fair Value Measurement PFRS 13 establishes a single source of guidance under PFRSs 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. PFRS 13 defines fair value as an exit price. PFRS 13 also requires additional disclosures. As a result of the guidance in PFRS 13, the Group re-assessed its policies for measuring fair values, in particular, its valuation inputs such as non-performance risk for fair value measurement of liabilities. The Group has assessed that the application of PFRS 13 has not materially impacted the fair value measurements of the Group. Additional disclosures, where required, are provided in the individual notes relating to the assets and liabilities whose fair values were determined. Fair value hierarchy is provided in Note 24.

PAS 1, Presentation of Financial Statements - Presentation of Items of Other Comprehensive Income or OCI (Amendments) The amendments to PAS 1 introduced a grouping of items presented in OCI. Items that will be reclassified (or “recycled”) to profit or loss at a future point in time (for example, upon derecognition or settlement) will be presented separately from items that will never be recycled. The amendments have no impact on the Group’s financial position or performance.

PAS 27, Separate Financial Statements (as revised in 2011) As a consequence of the issuance of the new PFRS 10 and PFRS 12, what remains of PAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in the separate financial statements. The adoption of the amended PAS 27 did not have a significant impact on the separate financial statements of the entities in the Group.

PAS 28, Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the issuance of the new PFRS 11and 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 standard has no impact on the consolidated financial statements of the Group.

Philippine Interpretation Financial Reporting Interpretations Committee (IFRIC) 20, Stripping Costs in the Production Phase of a Surface Mine This interpretation applies to waste removal (stripping) costs incurred in surface mining activity, during the production phase of the mine. The interpretation addresses the accounting for the benefit from the stripping activity. This new interpretation is not relevant to the Group.

PFRS 1, First-time Adoption of Philippine Financial Reporting Standards - Government Loans (Amendments) The amendments to PFRS 1 require first-time adopters to apply the requirements of PAS 20, Accounting for Government Grants and Disclosure of Government Assistance, prospectively to government loans existing at the date of transition to PFRS. However, entities may choose to apply the requirements of PAS 39, Financial Instruments: Recognition and Measurement, and PAS 20 to government loans retrospectively if the information needed to do so had been obtained at the time of initially accounting for those loans. These amendments are not relevant to the Group.

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-8Standards and Interpretations Issued But Not Yet Effective The Group has not applied the following PFRS, PAS and Philippine Interpretations which are not yet effective as of December 31, 2013. This list consists of standards and interpretations issued, which the Group reasonably expects to be applicable at a future date. The Group intends to adopt those standards when they become effective. x

PAS 36, Impairment of Assets - Recoverable Amount Disclosures for Non-Financial Assets (Amendments) These amendments remove the unintended consequences of PFRS 13 on the disclosures required under PAS 36. In addition, these amendments require disclosure of the recoverable amounts for the assets or cash-generating units for which impairment loss has been recognized or reversed during the period. These amendments are effective retrospectively for annual periods beginning on or after January 1, 2014 with earlier application permitted, provided PFRS 13 is also applied. The amendments have no impact on the Group’s financial position or performance.

Investment Entities (Amendments to PFRS 10, PFRS 12 and PAS 27) These amendments are effective for annual periods beginning on or after January 1, 2014. They provide an exception to the consolidation requirement for entities that meet the definition of an investment entity under PFRS 10. The exception to consolidation requires investment entities to account for subsidiaries at FVPL. The Group does not expect that this amendment would have material financial impact in the future financial statements.

Philippine Interpretation IFRIC 21, Levies IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. For a levy that is triggered upon reaching a minimum threshold, the interpretation clarifies that no liability should be anticipated before the specified minimum threshold is reached. IFRIC 21 is effective for annual periods beginning on or after January 1, 2014. The Group does not expect that IFRIC 21 will have material financial impact in future financial statements.

PAS 39, Financial Instruments: Recognition and Measurement - Novation of Derivatives and Continuation of Hedge Accounting (Amendments) These amendments provide relief from discontinuing hedge accounting when novation of a derivative designated as a hedging instrument meets certain criteria. These amendments are effective for annual periods beginning on or after January 1, 2014. The Group has not novated its derivatives during the current period. However, these amendments would be considered for future novations.

PAS 32, Financial Instruments: Presentation - Offsetting Financial Assets and Financial Liabilities (Amendments) The amendments 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. The amendments affect presentation only and have no impact on the Group’s financial position or performance. The amendments to PAS 32 are to be retrospectively applied for annual periods beginning on or after January 1, 2014. This amendment does not have a significant impact to the Group’s financial position or performance.

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-9x

PAS 19, Employee Benefits - Defined Benefit Plans: Employee Contributions (Amendments) The amendments apply to contributions from employees or third parties to defined benefit plans. Contributions that are set out in the formal terms of the plan shall be accounted for as reductions to current service costs if they are linked to service or as part of the remeasurements of the net defined benefit asset or liability if they are not linked to service. Contributions that are discretionary shall be accounted for as reductions of current service cost upon payment of these contributions to the plans. The amendments to PAS 19 are to be retrospectively applied for annual periods beginning on or after July 1, 2014. This amendment does not have a significant impact to the Group’s financial position or performance.

Annual Improvements to PFRSs (2010-2012 cycle) The Annual Improvements to PFRSs (2010-2012 cycle) contain non-urgent but necessary amendments to PFRSs. The Group adopted these amendments for the current year. x

PFRS 2, Share-based Payment - Definition of Vesting Condition The amendment revised the definitions of vesting condition and market condition and added the definitions of performance condition and service condition to clarify various issues. This amendment shall be prospectively applied to share-based payment transactions for which the grant date is on or after July 1, 2014. This amendment does not have a significant impact to the Group’s financial position or performance.

PFRS 3, Business Combinations - Accounting for Contingent Consideration in a Business Combination The amendment clarifies that a contingent consideration that meets the definition of a financial instrument should be classified as a financial liability or as equity in accordance with PAS 32. Contingent consideration that is not classified as equity is subsequently measured at fair value through profit or loss whether or not it falls within the scope of PAS 39. The amendment shall be prospectively applied to business combinations for which the acquisition date is on or after July 1, 2014. The Group shall consider this amendment for future business combinations.

PFRS 8, Operating Segments - Aggregation of Operating Segments and Reconciliation of the Total of the Reportable Segments’ Assets to the Entity’s Assets The amendments require entities to disclose the judgment made by management in aggregating two or more operating segments. This disclosure should include a brief description of the operating segments that have been aggregated in this way and the economic indicators that have been assessed in determining that the aggregated operating segments share similar economic characteristics. The amendments also clarify that an entity shall provide reconciliations of the total of the reportable segments’ assets to the entity’s assets if such amounts are regularly provided to the chief operating decision maker. These amendments are effective for annual periods beginning on or after July 1, 2014 and are applied retrospectively. The amendments have no impact on the Group’s financial position or performance.

PFRS 13, Fair Value Measurement - Short-term Receivables and Payables The amendment clarifies that short-term receivables and payables with no stated interest rates can be held at invoice amounts when the effect of discounting is immaterial.

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- 10 x

PAS 16, Property, Plant and Equipment - Revaluation Method - Proportionate Restatement of Accumulated Depreciation The amendment clarifies that, upon revaluation of an item of property, plant and equipment, the carrying amount of the asset shall be adjusted to the revalued amount, and the asset shall be treated in one of the following ways: a) The gross carrying amount is adjusted in a manner that is consistent with the revaluation of the carrying amount of the asset. The accumulated depreciation at the date of revaluation is adjusted to equal the difference between the gross carrying amount and the carrying amount of the asset after taking into account any accumulated impairment losses. b) The accumulated depreciation is eliminated against the gross carrying amount of the asset. The amendment is effective for annual periods beginning on or after July 1, 2014. The amendment shall apply to all revaluations recognized in annual periods beginning on or after the date of initial application of this amendment and in the immediately preceding annual period. The amendment has no impact on the Group’s financial position or performance.

PAS 24, Related Party Disclosures - Key Management Personnel The amendments clarify that an entity is a related party of the reporting entity if the said entity, or any member of a group for which it is a part of, provides key management personnel services to the reporting entity or to the parent company of the reporting entity. The amendments also clarify that a reporting entity that obtains management personnel services from another entity (also referred to as management entity) is not required to disclose the compensation paid or payable by the management entity to its employees or directors. The reporting entity is required to disclose the amounts incurred for the key management personnel services provided by a separate management entity. The amendments are effective for annual periods beginning on or after July 1, 2014 and are applied retrospectively. The amendments have no impact on the Group’s financial position or performance.

PAS 38, Intangible Assets - Revaluation Method - Proportionate Restatement of Accumulated Amortization The amendments clarify that, upon revaluation of an intangible asset, the carrying amount of the asset shall be adjusted to the revalued amount, and the asset shall be treated in one of the following ways: a) The gross carrying amount is adjusted in a manner that is consistent with the revaluation of the carrying amount of the asset. The accumulated amortization at the date of revaluation is adjusted to equal the difference between the gross carrying amount and the carrying amount of the asset after taking into account any accumulated impairment losses. b) The accumulated amortization is eliminated against the gross carrying amount of the asset. The amendments also clarify that the amount of the adjustment of the accumulated amortization should form part of the increase or decrease in the carrying amount accounted for in accordance with the standard. The amendments are effective for annual periods beginning on or after July 1, 2014. The amendments shall apply to all revaluations recognized in annual periods beginning on or after the date of initial application of this amendment and in the immediately preceding annual period. The amendments have no impact on the Group’s financial position or performance.

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- 11 Annual Improvements to PFRSs (2011-2013 cycle) The Annual Improvements to PFRSs (2011-2013 cycle) contain non-urgent but necessary amendments to PFRSs. The Group adopted these amendments for the current year. x

PFRS 1, First-time Adoption of Philippine Financial Reporting Standards - Meaning of ‘Effective PFRSs’ The amendment clarifies that an entity may choose to apply either a current standard or a new standard that is not yet mandatory, but that permits early application, provided either standard is applied consistently throughout the periods presented in the entity’s first PFRS financial statements. This amendment is not applicable to the Group as it is not a first-time adopter of PFRS.

PFRS 3, Business Combinations - Scope Exceptions for Joint Arrangements The amendment clarifies that PFRS 3 does not apply to the accounting for the formation of a joint arrangement in the financial statements of the joint arrangement itself. The amendment is effective for annual periods beginning on or after July 1, 2014 and is applied prospectively. This amendment does not have a significant impact to the Group’s financial position or performance.

PFRS 13, Fair Value Measurement - Portfolio Exception The amendment clarifies that the portfolio exception in PFRS 13 can be applied to financial assets, financial liabilities and other contracts. The amendment is effective for annual periods beginning on or after July 1, 2014 and is applied prospectively. The amendment has no significant impact on the Group’s financial position or performance.

PAS 40, Investment Property The amendment clarifies the interrelationship between PFRS 3 and PAS 40 when classifying property as investment property or owner-occupied property. The amendment stated that judgment is needed when determining whether the acquisition of investment property is the acquisition of an asset or a group of assets or a business combination within the scope of PFRS 3. This judgment is based on the guidance of PFRS 3. This amendment is effective for annual periods beginning on or after July 1, 2014 and is applied prospectively. The amendment has no significant impact on the Group’s financial position or performance.

PFRS 9, Financial Instruments PFRS 9, as issued, reflects the first and third phases of the project to replace PAS 39 and applies to the classification and measurement of financial assets and liabilities and hedge accounting, respectively. Work on the second phase, which relate to impairment of financial instruments, and the limited amendments to the classification and measurement model is still ongoing, with a view to replace PAS 39 in its entirety. PFRS 9 requires all financial assets to be measured at fair value at initial recognition. A debt financial asset may, if the fair value option (FVO) is not invoked, be subsequently measured at amortized cost if it is held within a business model that has the objective to hold the assets to collect the contractual cash flows and its contractual terms give rise, on specified dates, to cash flows that are solely payments of principal and interest on the principal outstanding. All other debt instruments are subsequently measured at fair value through profit or loss. All equity financial assets are measured at fair value either through OCI or profit or loss. Equity financial assets held for trading must be measured at fair value through profit or loss. For liabilities designated as at FVPL using the fair value option, the amount of change in the fair value of a liability that is attributable to changes in credit risk must be presented in OCI. The remainder of the change in fair value is presented in profit or loss, unless presentation of the fair value change relating

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- 12 to the entity’s own credit risk in OCI would create or enlarge an accounting mismatch in profit or loss. All other PAS 39 classification and measurement requirements for financial liabilities have been carried forward to PFRS 9, including the embedded derivative bifurcation rules and the criteria for using the FVO. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Group’s financial assets, but will potentially have no impact on the classification and measurement of financial liabilities. On hedge accounting, PFRS 9 replaces the rules-based hedge accounting model of PAS 39 with a more principles-based approach. Changes include replacing the rules-based hedge effectiveness test with an objectives-based test that focuses on the economic relationship between the hedged item and the hedging instrument, and the effect of credit risk on that economic relationship; allowing risk components to be designated as the hedged item, not only for financial items, but also for non-financial items, provided that the risk component is separately identifiable and reliably measurable; and allowing the time value of an option, the forward element of a forward contract and any foreign currency basis spread to be excluded from the designation of a financial instrument as the hedging instrument and accounted for as costs of hedging. PFRS 9 also requires more extensive disclosures for hedge accounting. PFRS 9 currently has no mandatory effective date. PFRS 9 may be applied before the completion of the limited amendments to the classification and measurement model and impairment methodology. The Group will not adopt the standard before the completion of the limited amendments and the second phase of the project. In compliance with SEC Memorandum Circular No. 3, series of 2012, the Group has conducted a study on the impact of an early adoption of PFRS 9. After careful consideration of the results on the impact evaluation, the Group has decided not to early adopt PFRS 9 for its 2013 annual financial reporting. Therefore, these consolidated financial statements do not reflect the impact of the said standard. x

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 SEC and the Financial Reporting Standards Council have deferred the effectivity of this interpretation until the final Revenue standard is issued by the 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. Adoption of the interpretation when it becomes effective will not have any impact on the financial statements of the Group.

Summary of Significant Accounting Policies Revenue Recognition 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 oil wells are recognized as income at the time of production.

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- 13 Interest Income Interest income is recognized as the interest accrues taking into account the effective yield on the asset. Miscellaneous Income Miscellaneous income includes dividend income and gain on sale of transportation equipment. Revenue is recognized when the Group’s right to receive the payment is established. 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 (3) months or less from the dates of acquisition and that are subject to an insignificant risk of change in value. Financial Instruments Date of recognition The Group recognizes a financial asset or a financial liability in the consolidated statement of financial position when it becomes a party to the contractual provisions of the instrument. Purchases or sales of financial assets that require delivery of assets within the time frame established by regulation or convention in the marketplace are recognized on the settlement date. Initial Recognition and Measurement Financial assets within the scope of PAS 39 are classified as either financial assets at FVPL, loans and receivables, held to maturity (HTM) investments or available-for-sale (AFS) financial assets, as appropriate. Financial liabilities are classified as either financial liabilities at FVPL or other financial liabilities. The classification depends on the purpose for which the investments are acquired and the Group determines the classification of the financial instruments at initial recognition and, where allowed and appropriate, re-evaluates this designation at each financial year-end. All financial assets are initially recognized at fair value plus, in the case of financial assets not at FVPL, directly attributable transaction costs. All financial liabilities are initially recognized at fair value, less, in the case of financial liabilities not at FVPL, directly attributable transaction costs. The Group’s financial assets include financial assets at FVPL and loans and receivables and its financial liabilities are of the nature of other financial liabilities. Subsequent Measurement The subsequent measurement bases for financial assets depend on the classification. Financial assets that are classified as loans and receivables are measured at amortized cost using the effective interest rate (EIR) method. Amortized cost is calculated by taking into account any discount, premium and transaction costs on acquisition, over the period to maturity. Amortization of discounts, premiums and transaction costs are taken directly to the consolidated statement of income.

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- 14 Determination of Fair Value Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either: x x

In the principal market for the asset or liability, or In the absence of a principal market, in the most advantageous market for the asset or liability

The principal or the most advantageous market must be accessible to by the Group. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorized within the fair value hierarchy, described as follows, based on the lowest level input that is significant to the fair value measurement as a whole: x x x

Level 1 - Quoted (unadjusted) market prices in active markets for identical assets or liabilities Level 2 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable Level 3 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable

For assets and liabilities that are recognized in the financial statements on a recurring basis, the Group determines whether transfers have occurred between Levels in the hierarchy by reassessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. Day 1 Difference 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 difference) in the consolidated statement of income unless it qualifies for recognition as some other type of asset or liability. In cases where variables used is made of data which is not observable, the difference between the transaction price and model value is only recognized in the consolidated statement of income when the inputs become observable or when the instrument is derecognized. For each transaction, the Group determines the appropriate method of recognizing the Day 1 difference amount. Loans and Receivables Loans and receivables are financial assets with fixed or determinable payments and fixed maturities that are not quoted in an active market. They are not entered into with the intention of immediate or short-term resale and are not designated as AFS financial assets or financial assets at FVPL.

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- 15 After initial measurement, loans and receivables are subsequently measured at amortized cost using the EIR method, less allowance for impairment. Amortized cost is calculated by taking into account any discount or premium on acquisition and fees that are an integral part of the EIR. Classified under this category are the Group’s cash and cash equivalents, short-term investments, receivables, and restricted cash (see Notes 6, 8, 14, and 24). Financial Assets and Financial Liabilities at FVPL Financial assets and financial liabilities at FVPL include financial assets and financial liabilities held for trading purposes, derivative instruments, or those designated by management upon initial recognition as at FVPL, subject to any of the following criteria: x x x

the designation eliminates or significantly reduces the inconsistent treatment that would otherwise arise from measuring the assets or liabilities or recognizing gains or losses on them on a different basis; or the assets and liabilities are part of a group of financial assets, financial liabilities or both which are managed and their performance are evaluated on a fair value basis, in accordance with a documented risk management or investment strategy; or the financial instrument contains an embedded derivative, unless the embedded derivative does not significantly modify the cash flows or it is clear, with little or no analysis, that it would not be separately recorded.

Financial assets and financial liabilities at FVPL are recorded in the consolidated statement of financial position at fair value. Changes in fair value are reflected in the consolidated statement of income. Interest earned or incurred is recorded in interest income or expense, respectively. Dividend income is recognized according to the terms of the contract, or when the right of the payment has been established. Classified as financial assets at FVPL are the Group’s marketable equity securities held for trading purposes and investment in golf club shares (see Note 7). Derivative Financial Instruments Derivative financial instruments (including bifurcated embedded derivatives), if any, are initially recognized at fair value on the date at which the derivative contract is entered into and is subsequently remeasured at fair value. Any gains or losses arising from changes in fair value of the derivative (except those accounted for as accounting hedges) is taken directly to the consolidated statement of income under “Miscellaneous income”. The derivative is carried as asset when the fair value is positive and as liability when the fair value is negative. The Group has no derivative financial instruments as at December 31, 2013 and 2012. Embedded Derivatives An embedded derivative is separated from the host financial or non-financial contract and accounted for as a derivative if all of the following conditions are met: x x x

the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristic of the host contract; a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and the hybrid or combined instrument is not recognized at FVPL.

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- 16 The Group assesses whether embedded derivatives are required to be separated from host contracts when the Group first becomes a party to the contract. Reassessment only occurs if there is a change in the terms of the contract that significantly modifies the cash flows that would otherwise be required. Embedded derivatives that are bifurcated from the host contracts are accounted for as financial assets or liabilities at FVPL. Changes in fair values are included in the consolidated statement of income. As of December 31, 2013 and 2012, the Group has no embedded derivatives requiring bifurcation. AFS Financial Assets AFS financial assets are those which are designated as such and are purchased and held indefinitely, and may be sold in response to liquidity requirements or changes in market conditions. AFS financial assets include equity securities. After initial measurement, AFS financial assets are measured at fair value. The unrealized gains and losses arising from the fair valuation of AFS financial assets are excluded from reported earnings and are reported in the consolidated statement of financial position and consolidated statement of changes in equity. When the security is disposed of, the cumulative gain or loss previously recognized in the consolidated statement of changes in equity is recognized in the consolidated statement of income. Where the Group holds more than one investment in the same security, these are deemed to be disposed of on a first-in first-out basis. Dividends earned in AFS financial assets are recognized in the consolidated statement of income when right to receive payment has been established. The losses arising from impairment of such investments are recognized in the consolidated statement of income. As of December 31, 2013 and 2012, the Group has no AFS financial assets. HTM investments HTM investments are quoted nonderivative financial assets with fixed or determinable payments and fixed maturities for which management has the positive intention and ability to hold to maturity. Where the Group sells other than an insignificant amount of HTM investments, the entire category would be tainted and reclassified as AFS financial assets. After initial measurement, these investments are measured at amortized cost using the effective interest method, less impairment in value. Amortized cost is calculated by taking into account any discount or premium on acquisition and fees that are integral parts of the EIR. The amortization is included in interest income in the consolidated statement of income. Gains and losses are recognized in the consolidated statement of income under “Other income” when the HTM investments are derecognized and impaired, as well as through the amortization process. As of December 31, 2013 and 2012, the Group has no HTM investments. Other Financial Liabilities All financial liabilities are initially recognized at the fair value of the consideration received less directly attributable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the EIR method. Gains and losses are recognized in the consolidated statement of income when the liabilities are derecognized or impaired, as well as through the amortization process.

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- 17 Classified under this category are the Group’s accounts payable and accrued expenses and loans payable (see Notes 15, 16 and 24). Classification of Financial Instruments between Debt and Equity A financial instrument is classified as debt, if it provides for a contractual obligation to: x x x

deliver cash or another financial asset to another entity; or exchange financial assets or financial liabilities with another entity under conditions that are potentially unfavorable to the Group; or satisfy the obligation other than by the exchange of a fixed amount of cash or another financial asset for a fixed number of own equity shares.

If the Group does not have an unconditional right to avoid delivering cash or another financial asset to settle its contractual obligation, the obligation meets the definition of a financial liability. The components of issued financial instruments that contain both liability and equity elements are accounted for separately, with the equity component being assigned the residual amount, after deducting from the instrument as a whole the amount separately determined as the fair value of the liability component on the date of issue. The Group has no financial instruments that contain both liability and equity elements. Impairment of Financial Assets The Group assesses at each reporting date whether a financial or group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if, and only if, there is objective evidence of impairment as a result of one or more events that has occurred after the initial recognition of the asset (an incurred ‘loss event’) and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the borrower or a group of borrowers is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganization and where observable data indicate that there is measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults. 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 there is an objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset’s original EIR (i.e., the EIR computed at initial recognition). If it is determined that no objective evidence of impairment exists for an individually assessed financial asset loan or receivable, whether significant or not, the asset is included in a group of financial assets with similar credit risk characteristics and that group of financial assets is collectively assessed for impairment. Assets that are individually assessed for impairment and for which an impairment loss is or continues to be recognized are not included in a collective assessment of impairment.

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- 18 The carrying amount of the asset is reduced through the use of an allowance for impairment loss account. The amount of the loss shall be recognized in the consolidated statement of income. If, in a subsequent period, the amount of the impairment loss decreases, and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed. Any subsequent reversal of an impairment loss is recognized in the consolidated statement of income, to the extent that the carrying value of the asset does not exceed what would have been the amortized cost at the reversal date had there been no impairment recognized. AFS Financial Assets If an AFS financial asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization) and its current fair value, less any impairment loss previously recognized in statement of income, is transferred from the consolidated statement of changes in equity to statement of income. Impairment reversals in respect of equity instruments classified as AFS financial assets are not recognized in the consolidated statement of income. Reversals of impairment losses on debt instruments are reversed through statement of income, if the increase in fair value of the instrument can be objectively related to an event occurring after the impairment loss was recognized in statement of income. The amount of reversal is limited to the amount that brings the carrying value of the debt instrument to what it could have been had there been no impairment in the first place. Derecognition of Financial Assets and Liabilities A financial asset (or where applicable, a part of a group of financial assets) is derecognized when: x x

the rights to receive cash flows from the assets have expired; or the Group has transferred substantially all the risks and rewards of the asset, or has assumed an obligation to pay them in full without material delay to a third-party under a “pass-through” arrangement and neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

Where the Group has transferred the rights to receive cash flows from an asset or has entered into a pass-through arrangement and has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the asset is recognized to the extent of the Group’s continuing involvement in the asset. 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 Financial liabilities are derecognized when the obligation under the liability is discharged, cancelled or has expired. Where an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognized in the consolidated statement of income. Offsetting Financial Instruments Financial assets and financial liabilities are offset and the net amount reported in the consolidated statement of financial position if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the asset and settle the liability simultaneously.

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- 19 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 are stated at cost less accumulated depletion, depreciation and amortization and 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 statement of 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. 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. 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 Land improvements Transportation equipment Office improvements Office furniture and other equipment

Number of Years 15 5 4 3 2-3

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- 20 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 statement 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 statement 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 statement of financial position. These costs include the following: x x x

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 recycling or waste disposal.

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- 21 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 Properties Investment properties consist 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 properties comprises of purchase price and any directly attributable costs of bringing the asset to its working condition. Expenditures incurred after the investment properties 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 properties beyond its originally assessed standard of performance, the expenditures are capitalized as an additional cost of investment properties. 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 investment properties are recognized in the consolidated statements of income in the year of retirement or disposal. Transfers are made to investment properties 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 properties 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 Operations A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. The Group recognized in relation to its interest in a joint operation its: x assets, including its share of any assets held jointly x liabilities, including its share of any liabilities incurred jointly x revenue from the sale of its share of the output arising from the joint operation x share of the revenue from the sale of the output by the joint operation x expenses, including its share of any expenses incurred jointly 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 operations. 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 properties, and deferred oil exploration 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.

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- 22 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 statement of income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase. Equity The Group records common stock 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 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 BOD. Income Taxes Current Income Tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted at the reporting date. Deferred Income Tax Deferred income tax is provided using the balance sheet liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

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- 23 Deferred income tax liabilities are recognized for all taxable temporary differences, with certain exceptions. Deferred income tax assets are recognized for all deductible temporary differences with certain exceptions, and carry forward benefits of unused tax credits from excess minimum corporate income tax (MCIT) over regular corporate income tax (RCIT) and unused net operating loss carryover (NOLCO), to the extent that it is probable that taxable income will be available against which the deductible temporary differences and carry forward benefits of unused tax credits from excess MCIT and unused 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 income will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are earned at each reporting date and are recognized to the extent that it has become probable that future taxable income will allow all as part of the deferred income tax and to be recovered. The Group does not recognize deferred income tax assets and deferred income tax liabilities that will reverse during the income tax holiday. Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to set off current income tax assets against current income tax liabilities and the deferred income taxes relate to the same taxable entity and the same taxation authority. Pension Cost The net defined benefit liability or asset is the aggregate of the present value of the defined benefit obligation at the end of the reporting period reduced by the fair value of plan assets (if any), adjusted for any effect of limiting a net defined benefit asset to the asset ceiling. The asset ceiling is the present value of any economic benefits available in the form of refunds from the plan or reductions in future contributions to the plan. The cost of providing benefits under the defined benefit plans is actuarially determined using the projected unit credit method. Defined benefit costs comprise the following: x Service cost x Net interest on the net defined benefit liability or asset x Remeasurements of net defined benefit liability or asset Service costs which include current service costs, past service costs and gains or losses on nonroutine settlements are recognized as expense in the consolidated statement of income. Past service costs are recognized when plan amendment or curtailment occurs. These amounts are calculated periodically by independent qualified actuaries. Net interest on the net defined benefit liability or asset is the change during the period in the net defined benefit liability or asset that arises from the passage of time which is determined by applying the discount rate based on government bonds to the net defined benefit liability or asset. Net interest on the net defined benefit liability or asset is recognized as expense or income in the consolidated statement of income. Remeasurements comprising actuarial gains and losses, return on plan assets and any change in the effect of the asset ceiling (excluding net interest on defined benefit liability) are recognized immediately in OCI in the period in which they arise. Remeasurements are not reclassified to consolidated statement of income in subsequent periods.

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- 24 Plan assets are assets that are held by a long-term employee benefit fund or qualifying insurance policies. Plan assets are not available to the creditors of the Group nor can they be paid directly to the Group. Fair value of plan assets is based on market price information. When no market price is available, the fair value of plan assets is estimated by discounting expected future cash flows using a discount rate that reflects both the risk associated with the plan assets and the maturity or expected disposal date of those assets (or, if they have no maturity, the expected period until the settlement of the related obligations). If the fair value of the plan assets is higher than the present value of the defined benefit obligation, the measurement of the resulting defined benefit asset is limited to the present value of economic benefits available in the form of refunds from the plan or reductions in future contributions to the plan. The Group’s right to be reimbursed of some or all of the expenditure required to settle a defined benefit obligation is recognized as a separate asset at fair value when and only when reimbursement is virtually certain. Costs and Expenses Oil production operating expenses are costs incurred to sell crude oil inventory, 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 is 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. Leases The determination of whether an arrangement is, or contains a lease, is based on the substance of the arrangement at inception date, and requires an assessment of whether the fulfillment of the arrangement is dependent on the use of a specific asset or assets, and the arrangement conveys a right to use the asset. A reassessment is made after inception of the lease only if one (1) of the following applies: a. b. c. d.

there is a change in contractual terms, other than a renewal or extension of the arrangement; a renewal option is exercised or an extension granted, unless that term of the renewal or extension was initially included in the lease term; there is a change in the determination of whether fulfillment is dependent on a specified asset; or there is a substantial change to the asset.

Where a reassessment is made, lease accounting shall commence or cease from the date when the change in circumstances gave rise to the reassessment for any of the scenarios above, and at the date of renewal or extension period for the second scenario. Group as a Lessee Leases where the lessor retains substantially all the risks and benefits of ownership of the asset are classified as operating leases. Operating lease payments are recognized as an expense in the consolidated statement of income on a straight-line basis over the lease term. Minimum lease payments are recognized on a straight-line basis while the variable rent is recognized as an expense based on the terms of the leased contract.

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- 25 Group as Lessor Leases where the Group retains substantially all the risk and benefits of ownership of the assets are classified as operating leases. Lease payments received are recognized as income in the consolidated statement of income on a straight-line basis over the lease term. Contingent rents are recognized as revenue in the period in which they are earned. Indirect costs incurred in negotiating an operating lease are added to the carrying value of the leased asset and recognized over the lease term on the same basis as the lease 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: x x x x x

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.

Borrowing Costs Interest and other related financing charges on borrowed funds used to finance the acquisition and construction of a qualifying asset (included under property, plant and equipment) are capitalized to the appropriate asset accounts. Capitalization of borrowing costs commences when the expenditures and borrowing costs are being incurred during the construction and related activities necessary to prepare the asset for its intended use are in progress. It is suspended during extended periods in which active development is interrupted and ceases when substantially all the activities necessary to prepare the asset for its intended use are complete. The capitalization is based on the weighted average borrowing cost. The borrowing costs capitalized as part of property and equipment are amortized using the straight-line method over the estimated useful lives of the assets. If after capitalization of the borrowing costs, the carrying amount of the asset exceeds its recoverable amount, an impairment loss is recorded in the consolidated statement of income. Interest expense on loans and borrowings is recognized using the EIR method over the term of the loans and borrowings. Provisions Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects a provision to be reimbursed, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as an interest expense. Provisions are reviewed at each reporting date and adjusted to reflect the current best estimate.

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- 26 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. Foreign Currency-denominated Transactions and 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 statement 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, PetroGreen, and PetroGreen’s subsidiaries, MGI and Petro Wind, 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 exchange differences arising on the translation are taken directly to “Cumulative translation adjustment” account in the equity section of the consolidated statement 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 statement of income. Earnings Per Share (EPS) 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. Operating Segment The Group’s operating businesses are organized and managed separately according to the nature of the products and services provided, with each segment representing a strategic business unit that offers different products and services and serves different markets. Financial information on business segments is presented in Note 25 to the consolidated financial statements. Provisions Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market

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- 27 assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as an interest expense. Provisions are reviewed at each reporting date and adjusted to reflect the current best estimate. 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. 5. Significant Accounting Judgments, Estimates and Assumptions The preparation of the consolidated financial statements in compliance with PFRS requires the Group to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, income and expenses and disclosure of contingent assets and contingent liabilities. Future events may occur which will cause the assumptions used in arriving at the estimates to change. The effects of any change in judgments, estimates and assumptions are reflected in the consolidated financial statements, as they become reasonably determinable. Judgments, estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. 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 PetroGreen, MGI and PetroWind is Philippine Peso. As of December 31, 2013 and 2012, the Group’s cumulative translation adjustment amounted to $1.12 million and ($0.78 million), respectively. 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. 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: x x

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;

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- 28 x x

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, 2013 and 2012, the carrying value of deferred oil exploration costs amounted to $11.40 million and $6.64 million, respectively (see Note 11). Based on the above mentioned criteria, the Group did not recognize any impairment of deferred oil exploration costs in 2013, 2012 and 2011. 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. Determination of Fair Values of Financial Assets and Liabilities The fair value determination 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 (see Note 24 for the fair value of financial assets and liabilities). Estimating 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 2013, 2012 and 2011. As of December 31, 2013 and 2012, the carrying value of receivables amounted to $2.61 million and $1.98 million, respectively. Accumulated impairment losses amounted to $0.06 million and $0.07 million as of December 31, 2013 and 2012, respectively (see Note 8). Fair Values of Financial Assets and Financial Liabilities The Group carries certain financial assets and liabilities at fair value, which requires extensive use of accounting estimates and judgment. While significant components of fair value measurement were determined using verifiable objective evidence (i.e., foreign exchange rates, interest rates), the amount of changes in fair value would differ if the Group utilized different valuation methodologies. Any changes in fair value of these financial assets and liabilities would affect directly the consolidated statement of income (see Note 7). Where the fair values of certain financial assets and financial liabilities recorded in the consolidated statement of financial position cannot be derived from active markets, they are determined using valuation techniques using generally accepted market valuation models. The inputs to these models are taken from observable markets where possible, but where this is not feasible, estimates are used in establishing fair values.

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- 29 Capitalization of Development Costs Development costs are capitalized in accordance with the accounting policy discussed in Note 4. Initial capitalization of costs is based on management’s judgment that technological and economical feasibility is confirmed, usually when a product development project has reached a defined milestone according to an established project management model. If accounting policy on capitalization of development costs are not met, such costs are expensed. 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 44 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 MGI SKM Indicated SKM MGI

MW Generation Capacity for 25 Years Probability P90 Probability P50 Probability P10 12 28

28 44

51 66

10 -

16 -

26 -

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 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.

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- 30 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, 2013 and 2012, the Group’s property, plant and equipment amounted to $75.07 million and $51.46 million, respectively (see Note 10). Estimating Impairment of Nonfinancial Assets The Group assesses impairment on its nonfinancial assets (e.g., property, plant and equipment and investment properties) 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 and investment properties, 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 properties, the Group is required to make estimates and assumptions that can materially affect the consolidated financial statements. As discussed in Note 10, production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last sixteen (16) 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 $6.65 million as of December 31, 2013 and 2012. 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 in 2013, 2012 and 2011. As of December 31, 2013 and 2012, the carrying value of property, plant and equipment amounted to $75.07 million and $51.46 million, respectively (see Note 10); and the carrying value of investment properties amounted to $0.03 million (see Note 12). Retirement Obligation The determination of obligation and cost of pension is dependent on the selection of certain assumptions used in calculating such amounts. Those assumptions, which are described in Note 19 to the consolidated financial statements, include, among others, discount rates and salary increase rates. Actual results that differ from the Group’s assumptions are accumulated and amortized over future periods and therefore, generally affect the recognized expense and recorded obligation in such future periods. While the Group believes that the assumptions are reasonable and appropriate, significant differences in the actual experience or significant changes in the assumptions may materially affect the pension obligations. The accrued retirement liability as of December 31, 2013 and 2012 amounted to $0.12 million and $0.06 million, respectively.

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- 31 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 statement of financial position is increased by the accretion expense charged to operations using EIR method over the estimated remaining term of the obligation. As of December 31, 2013 and 2012, asset retirement obligation amounted to $0.33 million and $0.24 million, respectively (see Note 17). 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 to dismantle, remove or restore sites and infrastructure when such obligation exists. As of December 31, 2013 and 2012, 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, 2013 and 2012, deferred tax assets amounted to $0.27 million and $0.14 million, respectively. However, the Group did not recognize deferred tax assets on NOLCO amounting to $5.16 million and $2.64 million as of December 31, 2013 and 2012, respectively, 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 20). 6.

Cash and Cash Equivalents Cash on hand and in banks Short-term investments

2013 $2,229,744 341,824 $2,571,568

2012 $1,020,234 20,601,988 $21,622,222

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. In 2013 and 2012, the Group invested $0.91 million and $0.81 million, respectively, to short-term investments with periods more than three months but less than one year. These investments were presented separately as short-term investments (see Note 36). Interest income earned on cash in banks and short-term investments amounted to $0.20 million, $0.51 million and $0.52 million in 2013, 2012 and 2011, respectively.

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- 32 7.

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

2013 $124,317 13,741 $138,058

2012 $125,531 17,296 $142,827

Net gain (loss) on fair value changes on financial assets at FVPL included in the consolidated statements of income amounted to $7,456, $24,880 and ($79,588) in 2013, 2012 and 2011, respectively. 8.

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

2013

2012

$2,622,051 40,098 5,128 2,667,277 60,422 $2,606,855

$2,021,687 1,969 23,717 2,047,373 65,346 $1,982,027

The Group’s receivables are mainly due from consortium operator and are due within one year. Carrying values as of year-end approximate their fair values (see Note 24). The table below shows the disclosure of reconciliation of allowance for impairment losses for receivables from a consortium operator: Balances at beginning of year Effect of foreign currency translation Balances at end of year 9.

2013 $65,346 (4,924) $60,422

2012 $61,187 4,159 $65,346

Prepaid Expenses and Other Current Assets Downpayments to contractors Downpayments to contractors - related parties (Note 23) Deferred financing costs - undrawn portion (Note 16) Prepaid expenses Others

2013 $10,161,027

2012 $551,527

4,526,038

3,266,268

1,450,062 624,699 171,694 $16,933,520

542,498 575,655 30,600 $4,966,548

Downpayments to contractors pertain to the downpayment to various contractors for the construction of power plant in the MGPP and NWPP (see Note 10). This will be applied against future billings in the course of construction. The current portion are estimated to be applied

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- 33 against progress billings within one year from reporting date are classified under “Advances, prepaid expenses and other current assets”. Prepaid expenses include prepaid insurance and professional fees. Deferred financing cost (DFC) undrawn portion represents the portion of the incidental costs incurred in obtaining the loan pertaining to the undrawn amount of the total loan. “Others” pertain to software licenses, advances to employees, supplies and deposits.

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10. Property, Plant and Equipment

Cost Balance at beginning of year Additions (Note 16) Disposals Change in ARO estimate (Notes 17 and 29) Balance at end of year Accumulated depletion and depreciation Balance at beginning of year Depletion and depreciation (Note 22) Disposals Balance at end of year Net book value

$816,610 94,051 � � 910,661

$605,867 110,475 � � 716,342

$687,949 277,816 (4,564) � 961,201

2013 Office Condominium Office Units and Transportation Furniture and Improvements Equipment Other Equipment

$26,555,923 20,287,172 � � 46,843,095

Construction in Progress

$64,364,205 25,317,818 (4,564) 46,651 89,724,110

Total

- 34 -

$12,751,733 3,505,167 � � 16,256,900

Wells, Platforms FCRS and and Other Production Wells Facilities Geothermal $22,027,382 902,494 � 46,651 22,976,527

Land and Land Improvements $918,741 140,643 � � 1,059,384

12,908,349 1,747,985 (4,564) 14,651,770 $75,072,340

Total

� � � � $46,843,095

Construction in Progress

$32,389,129 32,331,984 (88,388) (268,520) 64,364,205

304,194 144,759 (4,564) 444,389 $516,812

Office Furniture and Other Equipment

$3,440,337 23,115,586 � � 26,555,923

11,091,166 1,873,855 (56,672) 12,908,349 $51,455,856

103,487 109,218 � 212,705 $503,637 2012 Office Condominium Units and Transportation Improvements Equipment

$362,986 335,126 (10,163) � 687,949

� � – � $26,555,923

631,352 86,909 � 718,261 $192,400

$228,758 455,334 (78,225) � 605,867

199,415 114,942 (10,163) 304,194 $383,755

� � � � $16,256,900

$724,473 92,137 � � 816,610

98,232 51,764 (46,509) 103,487 $502,380

11,869,316 1,401,796 � 13,271,112 $9,705,415

$5,223,832 7,527,901 � � 12,751,733

546,465 84,887 – 631,352 $185,258

� 5,303 � 5,303 $1,054,081

$21,541,071 754,831 – (268,520) 22,027,382

� � – – $12,751,733

Wells, Platforms FCRS and and Other Production Wells Facilities Geothermal

$867,672 51,069 � � 918,741

10,247,054 1,622,262 – 11,869,316 $10,158,066

Land and Land Improvements

� � – � $918,741

Depletion of wells, platforms and other facilities is part of oil production under cost of sales in the consolidated statements of income.

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- 35 Foreign Operations Gabon, West Africa Total crude in 2013 reached 6.24 million barrels (mmbo), with daily oil production ranging from 11,400 - 19,700 barrels of oil per day (bopd) from three oil fields - Etame, Avouma, and Ebouri. The new production well EAVOM-3H was put on-line on April 9, 2013 and is now contributing ~1,600 bopd to the overall daily production from the Avouma platform. Due to the natural depletion of the field, increased gas and water contents in some of the wells, successive drilling activities in the Avouma and Ebouri platforms, and transient production downtimes, the average daily production was reduced to an anticipated ~17,000 bopd compared to 2012’s average of ~18,000 - 19,000 bopd. Nonetheless, the consortium managed 15 liftings for the year resulting to a net crude export of 6.31 mmbo. Crude oil prices for the year averaged US$107.53 per barrel. Aside from the current production activities in the three fields, the Etame consortium pursued the expansion of the existing Etame field. Two new production platforms were fabricated alongside major facilities upgrades in the existing platforms of Ebouri and Avouma fields. All these efforts are geared towards increased oil production and the extension of economic life of the fields. 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 bopd. Tapping both internal Consortium technical resources and external third-party Consultants, the EEP comprises four separate but related investigations: x x x x

Subsurface simulation study to determine remaining recoverable reserves in low, mid, and high cases; Drilling and completion review to ascertain drilling costs, duration, and design modifications for future well drilling and completion; Facilities evaluation of thirteen (13) potential development options that led to the identification of six hybrid development concepts; and 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.

This project, which aims to increase production to at least 25,000 bopd, requires new platforms in the central Etame production field and in the greenfield SouthEast Etame/North Tchibala (SEENT) sector. VAALCO Energy Inc., the joint-venture Operator, contracted the engineering firm McDermott to conduct the Detailed Engineering Studies for the new platforms. In November 2012, the partners approved the Final Investment Decision (FID) for this project. Once completed by the 3rd quarter of 2014, the new platforms can accommodate more production wells for drilling. On December 27, 2012, the Gabon government has approved the platform construction for the Etame and SEENT expansion program, covering a 15-18 month construction period. The platform topsides facilities design and fabrication were undertaken in 2013, while the transport and installation of parts will be done in 2014. The Gabonese Government has put on hold the approval

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- 36 of the production drilling until next year, pending the presentation of budget and the number and location of the production wells. By end of 2013, most of the long lead items for the Etame and SEENT expansion program had been purchased, while structural fabrication was on-going in Galveston, USA. Transportation and Installation which have been awarded to EMAS in July 2013 will commence in April 2014. Installation of the platforms is scheduled in June-July 2014. Brownfield Projects Upgrade The upgrade of both Avouma and Ebouri platforms were carried out in 2012 and are nearing completion. Both platforms were extended to accommodate additional well slots for future drilling. With these additions, the electrical systems of the platforms were likewise upgraded to accommodate additional electrical submersible pumps to be installed. The Avouma Water Knock-Out System was installed and hooked-up during the First Quarter of 2013. The system, which will increase crude output going to the Floating Production Storage and Offloading (FPSO) vessel by enhancing the platform’s capacity to separate water from the oil, was fully operational since August 2013. Ebouri Crude Sweetening Project The Ebouri wells EEBOM-3H and EEBOM-4H, which contribute ~2,000 bopd, have been shut-in since July 2012 due to high hydrogen sulphide (H2S). For safety purposes, these wells have been serviced for temporary abandonment in June 2013, and H2S detection devices were installed in the platform. The consortium then conducted a Crude Sweetening Process Study and is currently in the pre-front end engineering (pre-FEED) phase. Results are expected first quarter of 2014. FPSO Integrity Assessment Related to the “Etame Expansion Project” is the assessment of the existing FPSO vessel, Petroleo Nautipa, as to its suitability in the enhanced production plan. Allied Marine Services and BASS, well-known marine engineering firms, were contracted to assess the FPSO vessel’s life extension while SGS was engaged to undertake a Topsides Integrity Assessment. The collective output of the three contractors is the identification of corrective actions to maintain the vessel’s structural integrity and ensure continuous operation throughout the life of the field. The upgrade and modification of the vessel was carried out in 2013. The DNV Class Renewal 2012 for the Nautipa vessel was approved in full terms in mid-October 2013, with the certification valid until August 2, 2017. 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.

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- 37 The 3D seismic data acquired in 2011 over the concession’s shallow water region was processed and, along with existing joint-venture seismic data, analyzed and interpreted in 2012. By mid2012, exploration leads were already mapped; towards the end of the year, some of these leads had been matured into drillable prospects. Given that some of these leads and prospects are situated inside the environmentally sensitive Mayumba marine park, the Consortium is also analyzing options on possible drilling and development of these prospects. In parallel, existing prospects in the deeper portion of the concession area west of the Etame production field, are also being considered for drilling. Schedule and appropriate rig availability may dictate how the Consortium carries out its drilling campaign for both deep and shallow exploratory targets. Two prospects, namely Ovaka and Dimba, in the shallow portion of the Etame Marin consortium were approved by the partners to be drilled. However, Sasol has gone non-consent in the drilling of the Dimba prospect. PetroEnergy picked up its allocable share of Sassol’s participating interest, bringing PetroEnergy’s share to 3.26% (only for the drilling of Dimba prospect). Drilling Campaign for 2012-2014 The Ben Rinnes jack-up rig of KCA Deutag mobilized from Port Gentil Gabon to the Avouma Platform in late December 2012 and started the drilling of EAVOM-3P well on January 21, 2013. Successful tagging of oil-bearing Gamba reservoirs led to the drilling of the horizontal drain EAVOM-3H, which served as the new production well from Avouma. After reaching ~2,900 meters on March 8, 2013, the rig skidded to nearby EAVOM-2H and ETBSM-1H wells on March, 26, 2013 to perform work-over procedures to replace their Electric Submersible Pumps (ESP). The Ben Rinnes rig then moved to the Ebouri Platform on May 20, 2013 and commenced drilling of EEBOM-5P well on May 27, 2013. The 34-day operation yielded negative results. The rig skidded to EEBOM-3H and EEBOM-4H for well service procedures after the temporary abandonment of these wells, the rig was skidded to EEBOM-2H well on July 4, 2013 to replace its two ESP units. Operations in the Ebouri platform were completed on July 22, 2013, after which the rig moved to the location of open-water exploration well EOVKM-1 – the Ovoka Prospect, to test the prospectivity of the deeper sedimentary horizons. This turned out to have poor reservoir quality of sands. The well was plugged and abandoned as a dry hole on August 30, 2013 at TD of 2,770 meters. After the drilling of EOVKM-1, the Ben Rinnes jack-up rig was then handed over to Tullow Oil Plc on September 9, 2013 for a two-well drilling program in Tullow Oil’s Kiasserny block. The rig was mobilized back to the Etame block on December 20, 2013 to drill the Dimba exploration well (EDMBM-1) in the shallower portion of the concession area. 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 Presidential Decree No. 87, otherwise known as the “Oil Exploration and Development Act of 1972”, the Joint Venture (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.

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- 38 Production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last sixteen (16) 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 $6.65 million as of December 31, 2013 and 2012. 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 17, 2010 to December 17, 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: x x x

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 17, 2010 to December 17, 2025 in line with 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. 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. On April 10, 2012, the DOE officially approved the transfer of the service contract’s Operatorship from Pitkin to RMA (HK) Ltd. This operatorship transfer and the preceding farm-out to RMA (HK) Ltd of Pitkin’s 29.145% interest in the concession would result to the subsequent exploration costs leading to the drilling of one well. This planned drilling, originally targeted by late 2012, had to be rescheduled due to the delay in completion of the reservoir simulation study which is a pre-condition for the JV partners’ approval of the drilling program and budget. To address the risks on the anticipated rig mobilization and drilling posed by the existing 1990 West Linapacan subsea production facilities, the original farmors approved a budget to fund a third-party technical study on the best abandonment method. In the meantime, the programmed environmental impact assessment for the drilling activity had been moved to early 2013, after the completion of the reservoir simulation. Drilling of the West Linapacan well, coded WLA-7, has been set on or before the end of June 2014.

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trajectory and drilling objective planning were also conducted towards early production and full field development in West Linapacan. RMA sent the final Independent Expert Report of the West Linapacan “A” Reserves (Gaffney Cline & Associates) on September 5, 2013. The WLA field has Proved (1P) oil reserves of 9.6 MMBO and3,a2013, Proved + Probable (2P) reserves estimate of for 16.5 MMBO. This is based on a twoOn January Operator RMA (HK) Ltd. applied with the DOE a transfer of operatorship multilateral wellRMA development scheduled in 2014-15. of SC 14C2 from (HK) Ltd toprogram its newly formed Singapore-based subsidiary RMA West

Linapacan Pte Ltd., which request the DOE approved on May 24, 2013. By the first half of 2013, RMA continuedparticipating its review workinterest for reserves certification simulation, alongside PetroEnergy’s in SC 14-C2 and is atreservoir 1.03425%, but will be carried free in all further mapping of the West Linapacan field for additional leads and prospects. In parallel, exploration and development costs up to attainment of first commercial oil inwell the West Linapacan trajectory and drilling objective planning were also conducted towards early production and full block. field development in West Linapacan.

Geothermal Energy RMA sent the final Independent Expert Report of the West Linapacan “A” Reserves (Gaffney

Cline & Associates) on September 5, 2013. The WLA field has Proved (1P) oil reserves of 9.6 MMBO and aRenewable Proved + Probable (2P) reservesContract estimate of(GRESC) 16.5 MMBO. This is based on a twomultilateral Geothermal Energy Service No. 2010-02-012 well development program scheduled in 2014-15. 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 PetroEnergy’s participating interest in SC 14-C2 is at 1.03425%, but will be carried free in all Energy Contracting Roundcosts for Geothermal held by commercial the DOE in 2009, where the Parent exploration and development up to attainment of first oilNovember in the West Linapacan Company emerged as the winning bidder. The Field had been previously explored and relevant block. resource data identified certain portions thereof as having potential stored heat capacity that can Geothermal Energy in commercial quantities. produce electricity Geothermal Renewable Energy Service Contract (GRESC) No. 2010-02-012 Under this service contract, the Parent Company committed to perform the following during the On February 1, 2010, the Parent Company signed GRESC No. 2010-02-012 covering the first contract year of the stage: (i) Localareas, Government Units (LGU) and Maibarara Geothermal Fieldpre-development (“the field”) in Laguna and Batangas following a Philippine stakeholders coordination; (ii) geologic and geophysical studies and resource assessment; (iii) land Energy Contracting Round for Geothermal held by the DOE in November 2009, where the Parent rights survey and lease; (iv) obtain DENR andhad other establish logistics station; (vi) Company emerged as the winning bidder. The Field beenpermits; previously(v) explored and relevant resource data identified portions thereof as having stored heat capacitypreparations. that can land and water supplycertain preparations; and (vii) well potential work-over and drilling The produce electricity in commercial quantities. expected minimum expenditures for the first contract year amounted to $560,000. For the second contract year, the Parent Company committed to perform (i) work-over of existing Under this service contract, the Parent Company committed to perform the following during the wells; (ii) flow-testing and bore output measurements; (iii) engineering and design of steam/brine first contract year of the pre-development stage: (i) Local Government Units (LGU) and lines; (iv) grid impact study; and (v) site preparation construction fluid collection stakeholders coordination; (ii) geologic andstart geophysical studies and and resource assessment;of (iii)the land and disposal plant.andThe expected minimum rights survey system and lease;and (iv) power obtain DENR other permits; (v) establish expenditures logistics station; is (vi)about $17.8 million. land and water supply preparations; and (vii) well work-over and drilling preparations. The minimum expenditures the first contract yearof amounted to $560,000. Onexpected January 5, 2011, the DOE for approved the Deed Assignment and Assumption transferring the For the second contract year, the Parent Company committed to perform (i) work-over of existing GRESC from the Parent Company to MGI. wells; (ii) flow-testing 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. On January 5, 2011, the DOE approved the Deed of Assignment and Assumption transferring the GRESC from the Parent Company to MGI.

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- 40 In 2011, the Group reclassified the following costs from deferred geothermal costs to FCRS and production wells - geothermal: LGU and stakeholder coordination Geologic and geophysical studies and resource assessment Land rights survey and lease Obtainment of DENR and other permits Establishment of logistics station Land and water supply preparations Preparation for well work-over and drilling Work-over of existing wells Drilling of new wells Flow-testing and bore output measurements Engineering and design of steam/brine lines Financing, grid impact study and power purchase contract Construction fluid collection

$8,151 166,337 127,662 110,055 19,605 630,067 217,246 2,051,582 1,080,823 394,263 126,946 18,935 272,160 $5,223,832

In 2012, all costs that are directly related to the MGPP amounting to $23.12 million have been capitalized as construction in progress under property, plant and equipment. The activities during the development phase are as follows: x 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 Sto. Tomas, 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 MGPP and enlist their support. During the second quarter of 2011, several CSR activities were conducted in and around the project area. These 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. x

Geologic and 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, Sincliar.Knight.Merz (SKM), to conduct a technical due diligence review (third-party review) over the MGPP, 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

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- 41 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 MGPP. x

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 Compliance Certificate (ECC) from the Department of Environment and Natural Resources (DENR) and other necessary permits. The Parent Company 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 the Parent Company by the DENR. On December 29, 2010, the DENR approved the change in the proponent’s name for the Parent Company to MGI 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 thirdparty contractors and organic personnel. A safe, spacious and secure logistics station to address this operational need for the MGPP was established in Sto. Tomas, Batangas. In March 2010, a lease contract was signed with a lessor 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 mid-December 2010 in time for the mobilization of the drilling rig.

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- 42 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. x

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 such as steel casings for relining the wells, drill bits, master valves, and related supplies. It continued with the pull-out 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 the 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 workedover. 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 for 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 $0.4 million for the mobilization and demobilization of the rig.

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- 43 In 2012, MB-12D, the third production well, and MB-14D, which will be used as reinjection for power plant condensates, were drilled. The work-over of well Mai-9D was also carried out for safety reasons. x

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 took place in early 2011 include: (1) the design and fabrication of portable twin-shock silencer; (2) the design and fabrication of webre separator to 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 15MW.

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 (CADD) 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, 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 Certified Emission Reductions 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. 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. In 2012, since MGI mobilized its team and subcontractors with four concrete goals for 2012: 1) complete the steam production and reinjection well capacities, 2) expedite the construction of the steamfield and power plant facilities, 3) secure the right-of-way and initiate the erection of the transmission line, and 4) fortify relationship with the host community.

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- 44 The completion of the steam requirement for the 20 MW plant was successfully achieved when MGI drilled its first production well, MB-12D, in July -August, 2012 to a total depth of over 2,000 m. After a month of heat-up, MB-12D was successfully flowed for two months yielding chemically benign, low-gas, and high-enthalpy fluid with a power output of as much as 12 MW. Along with existing wells Mai-6D and Mai-9D which were worked-over in 2011, MB-12D completed the steam supply requirement for the 20MW plant. Similarly, the drilling of new condensate injection well MB-14RD to a depth of 1,900 m in October 2012 with resulting good permeability satisfied the well requirement for condensate fluid reinjection. Along with the 2011 work-over of well Mai-11D to be used for hot brine injection, MGI has the necessary wells for the 20 MW facility’s reinjection load. The year 2013 was a productive year for the MGPP. Construction of the Steamfield, Power Plant, Switchyard and Transmission Line facilities were in full-swing. By year-end, these facilities successfully underwent commissioning and testing. In preparation for the pre-commissioning phase, steam flushing of the steamfield surface facilities was conducted on May 17, 2013. The purpose of the flushing is to clean the pipes of debris from manufacturing and installation. This activity was followed by pressurization on June 20, 2013. The production well Mai-6D was fully opened to allow the flow of two-phase fluid through the pipeline and to the separator vessel. This enabled the system to attain the desired operating pressure. The steam was temporarily diverted to the blow-off and rock muffler until such time that the power plant was ready to accept the steam for commissioning and testing. MGI also undertook a successful work-over of reinjection well, Mai-11D, from September 8-18, 2013. The objective of the work-over is to mechanically drill-out the scales that have developed inside the wellbore after being used as an injector of cooled brine. Well Mai9D was temporarily converted from production to reinjection well to address the reinjection requirements of the field. An important milestone was achieved when the target plate testing was successfully carried out last August 9, 2013. The target plate test is a standard procedure conducted to check the quality and purity of the steam prior to admission by the turbine-generator. The two plate tests passed the inspection of the Japanese engineers from Fuji Electric Co. (Japan). After its completion in August 2013, the MGPP’s 115kV Transmission Line system was successfully connected to the existing Meralco line on September 10, 2013. Meanwhile, on October 7, 2013, the Energy Regulatory Commission (ERC) granted MGI the Certificate of Compliance (COC) allowing MGI to own and operate the MGPP. These two major milestones: transmission line energization and COC grant, gave way to the commissioning and testing activities in the power plant. Finally, on November 2, 2013, the valve connecting the steamline and the power plant was opened, and initial steam admission took place. The steam admission was followed by grid synchronization wherein MGPP supplied an initial load of 1MW to the Luzon Grid. During succeeding tests, an issue with the turbine’s Main Control Valve (MCV) was detected. The valve was shipped to Fuji’s plant in Japan for inspection and repair. The MCV was shipped back to the site in late December 2013 and was reinstalled in early January 2014. Upon completion the reliability and performance testing, the Maibarara Power Plant went on commercial operations on February 8, 2014.

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- 45 Borrowing Cost In 2013 and 2012, 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 $3.64 million and $1.68 million in 2013 and 2012, respectively. 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. 11. Deferred Oil Exploration Costs Balance at beginning of year Internal development Balance at end of year

2013 $6,643,203 4,754,007 $11,397,210

2012 $5,831,668 811,535 $6,643,203

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 internal development costs pertain to the Etame expansion costs and costs incurred for other service contracts during the year. 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. 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

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- 46 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 (Trans-Asia) 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. 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 1,000m programmed total depth, the Operator/Farminee NorAsian 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 $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. 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. Meanwhile in the South Block, the SC 51 Filipino consortium issued a reminder to SWAN Oil & Gas to exercise its financial capability to drill the Argao-1 deepwater well in Cebu by the end of March 2012, with the consequence of being in default with the Consortium. SWAN disputed its default status, but later announced entering into an amicable agreement with the Filipino partners upon exiting SC 51 on September 20, 2012. On January 25, 2012, the DOE approved the Subphase 4 Work Program & Budget (WP&B) of SC 51. The WP&B for SP 4 includes the acquisition, processing and interpretation of 100km of 2D seismic over the Duhat prospect in the North Block, at a total budget of $4.35 million. The operator of the block, Otto Energy, contracted Beijing-based BGP Asia to conduct the 2D seismic survey. Mobilization of the seismic crew started in February 2012. Actual data shooting and acquisition for the 102 line-km 2D seismic survey over the Duhat prospect was conducted from August to October 2012, at a cost of US$ 3.38MM. Following the completion of the 2D seismic program, the Consortium elected on December 12, 2012 to enter SP 5 with a one well drilling commitment. This made way for commencement of Otto’s well design planning and activities to secure a suitable rig to drill the Duhat-2 well in mid-2013.

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- 47 On January 28, 2013, the DOE approved the SC 51 North block consortium’s election to enter Subphase 5, which includes drilling of the Duhat-2 well in NW Leyte. After acquiring all the necessary permits from the LGUs and appropriate site preparations in San Isidro, Leyte, Duhat-2 was spudded by Operator Otto Energy Investments Ltd. on July 24, 2013. Upon reaching a depth of 201m on July 26, 2013, salt water flow occurred. Otto decided to plug and abandon the well to prevent adverse environmental impact to the local community. Similar to the previous Duhat-1 well, the Farmors, Alcorn (now Cosco Capital), TransAsia, and PetroEnergy did not credit Duhat-2 as an “earning well”. The DOE for its part declared Duhat-2 failed to satisfy the work commitment for subphase 5. Otto Energy appealed to the DOE and was given a 6-month extension to conduct further geologic assessment of Duhat-2 for the remainder of Subphase 5. 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. In December 2011, to maintain the validity of the SC, the Octon Joint Venture submitted to the DOE a $546,000 work program. 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 SC 6A Consortium in late 2010, Pitkin Petroleum Plc (Pitkin), a UK-registered 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 $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. After the DOE approval of Pitkin’s farm-in and Operatorship of SC-6A on December 6, 2011, Pitkin commenced preparation for Phase 1 activities, consisting of the acquisition, processing and interpretation of ~500km of 3D seismic data. This new 3D seismic program will help further refine the drilling potential of the prospects and leads in the area. In mid-March 2012, Pitkin sent out tenders to ten (10) seismic firms to carry out the 3D seismic survey with the intention of commencing the survey by mid-February, 2013.

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- 48 After the conduct of Information, Education and Communication (IEC) activities and upon securing the necessary endorsements from the Palawan local government units (Palawan Council for Sustainable Development and the Sangguniang Panlalawigan of Palawan) in February to June 2013, Operator Pitkin secured DOE approval for the conduct of the 3D seismic survey for Phase 1. On July 30, 2013, the consortium granted Pitkin request for a one year extension fee. The seismic vessel M/V Voyager Explorer commenced the acquisition of 508 sq.km of 3D seismic data on October 5, 2013 and 48.5 line-km of 2D seismic data tying the Bantac-1 well in SC 57 and the Malajon-1 well in SC 6A. The survey was completed on November 6, 2013. In consideration of the amounts of time needed for seismic interpretation, the consortium agreed with Pitkin to seek DOE approval to extend Phase 1 of the work program for four months, from August 31, 2014 to December 31, 2014. To date, the DOE reply is still forth coming. SC 47 - Offshore Mindoro and Panay The DOE approved on 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. PNOC-EC requested for a one-year extension of the contract’s Subphase 2 to July 10, 2012 to conduct detailed source rock-to-reservoir rock migration studies and acquisition of 500km 2D seismic data. These proposed studies were intended to further de-risk the area and attract potential farminees who have been stymied by the discouraging results of the last deep oil well drilled in 2007 by Malaysia’s Petronas. As of end-2012, the application for Subphase 2 extension was still pending approval by the DOE. While awaiting DOE approval, the SC 47 Consortium has been actively seeking potential farminees to carry out the drilling of one (1) exploratory well, as programmed for the subsequent Subphase 3. The consortium has a pending request from the DOE for an extension of SubPhase 2. This request was made by PNOC-EC, in 2012. During the year, farm-out efforts have been carried out by the operator. The farmout terms include seismic processing and drilling of one well. As of end of the year, the farmout process has not been settled. PetroEnergy’s participating interest in SC 47 remains at 2.00% , PNOC-EC at 97%, and Basic Energy at 1%. SC 75 – Offshore Northwest Palawan The joint study and bid group consisting of Philex Petroleum Corporation, PNOC-EC and PetroEnergy was notified by the DOE that the group had won the bidding for Area 4 of the Philippine Energy Contracting Round 4 (PECR 4) last February 14, 2013. The block is located in deepwater areas offshore Northwest Palawan.

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- 49 After finalization of contract terms, the consortium formally signed Service Contract 75 on December 19, 2013. Secretary Petilla then signed on behalf of DOE on December 27, 2013. Under the newly-executed Service Contract, the first Sub-phase will consist of Geological & Geophysical (G&G) studies of the Northwest Palawan Basin and the conduct of a 2,200 line-km 2D seismic survey over SC 75 for the duration of 24 months at an estimated cost of US$ 3.50 MM. Philex Petroleum is the Operator of SC 75 with 50% participating interest, PNOC-EC with 35%, and PetroEnergy with 15%. As of December 31, 2013, 2012 and 2011, the corresponding percentages of the Group’s participation in the various SC areas are as follows: Gabonese Oil Concessions West Linapacan - SC 14 C2 Octon Malajon Block - SC 6-A East Visayas - SC 51 Offshore Mindoro - SC 47 NW Palawan -SC 75

2013 2.525% 1.034% 5.001% 4.012% 2.000% 15.000%

2012 2.525% 1.034% 5.001% 4.012% 2.000% -

2011 2.525% 4.137% 5.001% 4.012% 2.000% -

12. Investment Properties As of December 31, 2013 and 2012, this account consists of land with total carrying value of $31,417. The fair value of the investment properties of the Group amounted to $47,683 as of December 31, 2013 and 2012. The Group did not obtain the services of an appraiser and determined the fair values of the Group’s investment properties on the basis of recent sales of similar properties in the same areas as the investment properties and taking into account the economic conditions prevailing at the time the valuations were made. As of December 31, 2013 and 2012, the fair value of the investment properties is classified under the Level 2 category. Except for insignificant amounts of real property taxes on the investment properties, no other expenses were incurred, and no income was earned in relation to the investment properties in 2013, 2012 and 2011. 13. Investment in Navy Road Development Corporation (NRDC) As of December 31, 2013 and 2012, this account consists of: Acquisition cost Advances Less accumulated impairment loss

$260,388 54,032 314,420 314,420 $–

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

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- 50 Below is NRDC’s financial position as of December 31, 2013 and 2012: Financial Position Current assets Noncurrent assets Allowance for impairment Total Assets Current liabilities Noncurrent liabilities Total Liabilities Net Assets

$� 366,193 (366,193) – � � – $–

As of December 31, 2013 and 2012, NRDC has not commenced commercial operations and has not incurred any expenses in 2013, 2012 and 2011. Management intends to liquidate NRDC and has provided for full impairment losses on this investment. 14. Other Noncurrent Assets Input VAT Prepaid rent - noncurrent portion Deferred cost – wind Restricted cash Others

2013 $2,628,670 2,177,765 452,229 63,125 46,539 $5,368,328

2012 $709,412 2,457,440 – 63,125 2,377 $3,232,354

Input VAT refers to the Groups cumulative input vat carry overs which will be utilized in future periods. MGI is undergoing a vat refund process as of December 31, 2013. MGI has accumulated Input VAT as of December 31, 2013 amounting to = P104.8 million or $2.36 million, of which P =15.79 million or $0.355 million covering the four (4) quarters of 2011 were already filed with the BIR Regional District Office for administrative claim on VAT refund. Moreover, the first two (2) quarters of these claims amounting to P =13.23 million or $ 0.298 million were already elevated and filed with the Court of Tax Appeals. On April 23, 2012, the Company entered into a Land Lease Agreement (LLA or the Agreement) with the National Power Corporation (NPC) and the Power Sector Assets and Liabilities Management Corporation (PSALM) over the MGPP’s steamfield lot in Sto. Tomas, Batangas. Under the LLA, the Company will lease the steamfield lot for a period of 25 years, extendable for another 25 years upon mutual agreement of the parties. Prepaid rent-noncurrent portion pertains to the advance rental payment paid for the lease agreement. The current portion due in one year is shown as part of “Prepaid expenses and other current assets” in the consolidated statements of financial position. Restricted cash pertains to the Parent Company’s share in the escrow fund to secure payment and discharge of the 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 at the end of the contract which is in 2020.

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- 51 15. Accounts Payable and Accrued Expenses Accounts payable Payables to related parties (Note 23) Accrued interest payable Accrued expenses Dividends payable Withholding taxes payable Others

2013 $1,020,771 861,771 968,885 565,145 235,397 175,051 117,697 $3,944,717

2012 $241,547 2,984,663 683,762 471,287 260,098 125,261 235,747 $5,002,365

Accounts payable consist of payable to suppliers and contractors. Accrued expenses are as follows: Profit share Professional fees Professional fees - related parties Sick/Vacation leaves Insurance Trust fees Others

2012 $224,884 71,417 10,048 67,739 61,429 35,770 � $471,287

2013 $294,528 21,691 5,376 143,644 � � 99,906 $565,145

Accrued interest payable pertains to accrual for interest on loans (see Note 16). Dividends payable pertain to unclaimed checks as of December 31, 2013 and 2012. Other payables mainly pertain to accrued security services, utilities and condominium dues. The Group’s accounts payable and accrued expenses are due within one year. Carrying values approximate their fair values as of December 31, 2013 and 2012. 16. Short-term and Long-term Loans Payable The Group’s loans payable pertains to loans availed by the Parent Company and MGI. Below are the details of the loans entered: Short-term loans payable Less unamortized deferred financing cost Long-term -loans payable Less unamortized deferred financing cost Loans payable

2013 $2,252,503 14,423 2,238,080 58,461,144 1,246,587 57,214,557 $59,452,637

2012 $– – – 39,951,279 1,007,835 38,943,444 $38,943,444

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- 52 PetroEnergy’s short-term and long-term loans payable PetroEnergy entered into unsecured loan agreements with various lenders specifically to finance equity infusion to PetroWind. On July 19, 2013, PetroEnergy entered into a $3.5 million loan agreement with various lenders with interest rate for the first interest period (i.e. six months from issue date) of 3.898%, subject to re-pricing every six months based on a benchmark rate plus a pre-agreed spread. The tenor of the loan is 2 years, maturity July 19, 2015. On November 21, 2013, Petroenergy entered into additional loan amounting to P =200 million ($4.5 million) with various lenders with an interest rate of 5.45% per annum. Interest rate on the note shall be calculated on a 30/360 day count basis and will be paid every 3 months in arrears in the last day of each three-month period. The tenor of the loan is 2 years, maturity November 21, 2015. These loans are reflected under the long-term loans payable account. On December 12, 2013, PetroEnergy entered into a = P100 million or $2.2 million loan with various lenders with an interest rate of 4.5% per annum. The loan is payable within 33 days, maturity January 14, 2014. This loan is reflected under “short-term loans payable account”. MGI’s long-term loans payable On September 26, 2011, MGI together with PNOC Renewables Corporation and Trans-Asia entered into a = P2.24 billion or $50.5 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, 2013 and 2012, MGI has outstanding drawdowns of $50.46 million and $39.95 million, respectively. 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) semiannual 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 as part of noncurrent liabilities. 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 includes 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, 2013 and 2012, the portion pertaining to the drawn amount of the loan amounting to $1.18 million and $1.01 million is presented as deduction from the loans payable account and is amortized over the life of the loan using the EIR method. Amortization of

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- 53 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 are as follows: Balance at beginning of year Deferred financing costs on loan drawn during the year Less amortization during the year Balance at end of year

2013 $1,007,835

2012 $393,792

396,018 1,403,853 142,840 $1,261,013

766,141 $1,159,933 152,098 $1,007,835

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, 2013 and 2012, $1.45 million and $0.54 million, respectively are presented as current asset under “Prepaid expenses and other current assets” account (see Note 9). MGI has pledged a portion of its land and property, plant and equipment amounting to $3.86 million as collateral in connection with the loan. Pledged assets are as follows: x x

Real estate (land to be used as power plant site, under “Property, plant and equipment”) $3.19 million; and Chattel (under “Property, plant and equipment”) - $0.67 million.

Below are the accumulated capitalized borrowing costs as of December 31, 2013 and 2012: Interest on loans payable Balance at the beginning of year Interest incurred during the year Balance at end of year Deferred financing cost Balance at the beginning of year Amortization during the year Balance at end of year

2013

2012

$2,167,924 3,655,746 5,823,670

$10,039 2,157,885 2,167,924

159,338 142,840 302,178 $6,125,848

7,240 152,098 159,338 $2,327,262

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, 2013 and 2012, MGI is in compliance with the said loan covenants.

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- 54 17. Asset Retirement Obligation The Group has recognized its share in the abandonment costs associated with the Etame, Avouma and Ebouri oilfields located in Gabon, West Africa. Movements in this account follow: Balance at beginning of year Change in estimate (Note 10) Accretion expense Balance at end of year

2013 $237,668 46,651 44,070 $328,389

2012 $474,293 (268,520) 31,895 $237,668

The provision for the oilfields in Etame maintained the original discount rate at 15% for both years. Reduction during the year resulted from the change in estimated abandonment costs from $0.87 million in 2012 to $0.78 million in 2013 (the Group’s share to the total accrued retirement obligation of the consortium). The estimate was provided by a third party expert, as engaged by the consortium operator of the oilfields in Gabon, West Africa. This also resulted to a decrease in the book value of “Wells, platforms and other facilities” account under “Property, plant and equipment” in the consolidated statements of financial position (see Note 10). The provisions for the abandonment costs for Etame are expected to be settled in 2020, while for Avouma and Ebouri in 2022. 18. 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, 2013, the total issued and subscribed capital stock of the Parent Company is 99.79% Filipino and 0.21% nonFilipino, as compared to 99.75% Filipino and 0.25% non-Filipino as of December 31, 2012 and 99.87% Filipino and 0.13% non-Filipino as of December 31, 2011. As of December 31, 2013 and 2012, capital stock consists of 330,000,000 authorized and 273,824,220 issued and outstanding common shares with par value of = P1 ($0.0244) per share. Total capital stock and additional paid-in capital amounted to $6.32 million and $25.24 million, respectively, as of December 31, 2013, 2012 and 2011.

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FORGING AHEAD | ANNUAL REPORT 2013

- 55 Capital Stock The Parent Company’s track records of capital stock are as follows:

Listing by way of introduction August 11, 2004 Add (deduct): 25% stock dividend 30% stock dividend 1:1 stock rights offering December 31, 2010 Deduct: Movement December 31, 2011 Deduct: Movement December 31, 2012 Deduct Movement December 31, 2013

Number of shares registered

Issue/offer price

Date of SEC approval

84,253,606

= P3/share

August 4, 2004

21,063,402 31,595,102 136,912,110 273,824,220 � 273,824,220 � 273,824,220 � 273,824,220

P =1/share P =1/share = P5/share

September 6, 2005 September 8, 2006 May 26, 2010

Number of holders as of year - end

2,149 (26) 2,123 (10) 2,113 (41) 2,072

Dividends The BOD approved the declaration of cash dividends as follows: July 4, 2013, 5% or $.001 per share cash dividends to all stockholders of record as of July 25, 2013 amounting to $315,248 The dividends were paid on August 20, 2013. April 26, 2012, 10% or $0.002 per share cash dividends to all stockholders of record as of September 21, 2012 amounting to $643,838. The dividends were paid on October 17, 2012. April 26, 2012, 10% or $0.002 per share cash dividends to all stockholders of record as of May 18, 2012 amounting to $643,838. The dividends were paid on June 14, 2012. May 17, 2011, 10% or $0.002 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 $0.002 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

2013

2012

2011

$315,248

$–

–

643,838

–

643,838

–

631,951

– $315,248

– $1,287,676

629,120 $1,261,071

The Parent Company’s retained earnings available for dividend declaration as of December 31, 2013, 2012 and 2011 amounted to $11.10 million, $8.68 million and $6.73 million, respectively.

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- 56 Appropriated Retained Earnings

On January 15, 2008, the BOD approved the appropriation of $0.49 million for the development of the Ebouri oil field in Gabon, in addition to the $0.56 million originally appropriated amount. Participation in the development of the Ebouri field by the Parent Company has been approved by the BOD on the same date. On July 24, 2008, the BOD approved additional appropriation of retained earnings amounting to $1.0 million for the development of the Ebouri oil field in Gabon, West Africa.

On February 19, 2013, the BOD approved additional appropriated retained earnings amounting to $1.09 million to cover for the Parent Company’s share in the cost of the committed wells in the Etame oilfield in Gabon, West Africa. Total appropriations for the development of the oilfields in Gabon, West Africa as of December 31, 2013 and 2012 amounted to $3.15 million and $2.06 million, respectively. Further expansion of the said oilfield is on-going and is set to be completed in 2015. There are no appropriations of retained earnings made in 2012 and 2011. 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, 2013, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity. As of December 31, 2013 and 2012, the Group’s sources of capital are as follows: 2013 $59,452,637 25,244,737 10,879,836 6,321,533 $101,898,743

Loans payable Additional paid-in capital Retained earnings Capital stock

2012 $38,943,444 25,244,737 8,983,864 6,321,533 $79,493,578

The table below demonstrates the debt-to-equity ratio of the Group as of December 31, 2013, 2012 and 2011: Total debt Loans payable Accounts payable and accrued expenses Income tax payable Asset retirement obligation Accrued retirement liability

2013

2012

2011

$59,452,637

$38,943,444

$13,295,139

3,944,717 772,479 328,389 116,175 $64,564,397

5,002,365 75,015 237,668 57,812 $44,316,304

3,455,507 243,474 474,293 33,572 $17,501,985

(Forward)

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FORGING AHEAD | ANNUAL REPORT 2013

- 57 -

Total debt Total equity Capital stock Additional paid-in capital Retained earnings Appropriated Unappropriated Remeasurements of net accrued retirement liability Cumulative translation adjustment Noncontrolling interest Debt-to-equity ratio

2013

2012

2011

$6,321,533 25,244,737

3,149,555 7,730,281

2,055,555 6,928,309

2,055,555 5,656,403

(47,563) (1,120,775) 9,676,476 $50,954,244 1.27:1

(5,707) 778,372 5,807,379 $47,130,178 0.94:1

(12,720) (56,227) 3,851,627 $43,060,908 0.41:1

Based on the Group’s assessment, the capital management objectives were met in 2013, 2012 and 2011. 19. Retirement Plan The Group has a funded 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 Group’s fund is in the form of a trust being maintained by a trustee bank, Rizal Commercial Banking Corporation (RCBC). In 2013, 2012 and 2011, there were no transactions that took place between the fund and the Group. The fund has no investments in the Group’s equity as of December 31, 2013 and 2012. Under the existing regulatory framework, Republic Act 7641, The Retirement Pay Law, requires a provision for retirement pay to qualified private sector employees in the absence of any retirement plan in the entity, provided however that the employee’s retirement benefits under any collective bargaining and other agreements shall not be less than those provided under the law. The law does not require minimum funding of the plan. The Group updates the actuarial valuation every year by hiring the services of a third party professionally qualified actuary. The accrued retirement liability recognized in the consolidated statements of financial position as of December 31, 2013 and 2012 and January 1, 2012 are as follows:

Present value of accrued retirement liability Fair value of plan assets Accrued retirement liability

2013

2012 (As restated)

2011 (As restated)

$254,766 138,591 $116,175

$164,092 106,280 $57,812

$125,108 91,536 $33,572

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- 58 The movements in the accrued retirement liability recognized in the consolidated statements of financial position are as follows:

Balances at beginning of year Current service cost Net interest Retirement expense Actuarial changes arising from: Financial assumptions Experience Foreign currency translation adjustments Remeasurement losses (gains) Contribution Balances at end of year

Present value of accrued retirement liability $164,092 33,873 8,366 42,239 73,235 (7,645) (17,155) 48,435 – $254,766

2013 Fair value of plan assets $106,280 – 5,419 5,419 (1,474) – (9,886) (11,360) 38,252 $138,591

Accrued retirement liability $57,812 33,873 2,947 36,820 74,709 (7,645) (17,155) 59,795 (38,252) $116,175

2012 (As restated - Note 3) Present value Accrued of accrued retirement retirement Fair value of liability liability plan assets $125,108 $91,536 $33,572 32,247 – 32,247 7,493 5,481 2,012 39,740 5,481 34,259 4,150 (14,267) 9,361 (756) $164,092

2,802 – 6,461 9,263 $106,280

1,348 (14,267) 2,900 (10,019) $57,812

2011 (As restated - Note 3) Present value of accrued Accrued retirement Fair value of retirement liability plan assets liability $81,267 $65,758 $15,509 21,090 – 21,090 5,634 4,560 1,074 26,724 4,560 22,164 31,567 (13,914) (536) 17,117 – $125,108

(739) – (315) (1,054) 22,272 $91,536

32,306 (13,914) (221) 18,171 (22,272) $33,572

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FORGING AHEAD | ANNUAL REPORT 2013

- 59 The components of net plan assets are as follows: Cash and cash equivalents Investments in quoted government securities Interest receivable Trust fee payable

2013 $45,995

2012 $40,975

2011 $55,092

92,334 742 (480) $138,591

65,051 789 (535) $106,280

36,301 285 (142) $91,536

The principal actuarial assumptions used in determining pension benefit obligation for the Group’s plan are as follows: Rate of increase in salaries Beginning Ending Discount rate Beginning Ending

2013

2012

4.00% 6.67%

4.20% 4.00%

5.27% 4.48%

5.77% 5.27%

The sensitivity analysis below has been determined based on reasonably possible changes of each significant assumption on the accrued retirement liability as of December 31, 2013, assuming if all other assumptions were held constant:

Discount rate

Increase (decrease) +0.50% -0.50%

Effect on accrued retirement liability ($13,312) 14,868

Shown below is the maturity analysis of the undiscounted benefit payments as of December 31, 2013 and 2012: Less than one year More than one year to five years More than five years to 10 years More than 10 years to 15 years More than 15 years to 20 years More than 20 years

2013 $25,785 90,391 289,981 137,026 539,719 2,300,125

2012 $25,834 89,221 257,172 32,559 104,800 1,437,154

The Group expects to contribute to the fund the amount of $20,225 in 2014.

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- 60 20. Income Tax The provision for income tax consists of: 2013 $1,852,088 (88,516) $1,763,572

Current - RCIT Deferred

2012 $963,372 (63,812) $899,560

2011 $1,191,787 145,824 $1,337,611

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

2013

Deferred tax assets on: Asset retirement obligation Accrued profit share Accrued retirement liability Provision for probable losses Deferred tax liabilities on: Production revenue Unrealized foreign exchange gain

2012 (As restated - Note 3)

$193,831 92,743 37,320 19,026 342,920

$166,357 60,743 13,628 17,092 257,820

68,714 7,684 76,398 $266,522

113,344 3,953 117,297 $140,523

As of December 31, 2013 and 2012, the Group did not recognize deferred tax assets on NOLCO amounting to $5.16 million and $2.64 million, respectively, 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 Year Incurred

2012 2011

Expiration 2015 2014

NOLCO In USD In PHP =19,753,890 P $481,215 14,999,967 342,153 =34,753,857 P $823,368

2013 2012 2011

Expiration 2016 2015 2014

NOLCO In USD In PHP =53,920,047 P $1,214,552 41,354,900 1,007,428 32,373,964 738,457 =127,648,911 $2,960,437 P

MGI Year Incurred

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FORGING AHEAD | ANNUAL REPORT 2013

- 61 PWEI Year Incurred

2013

Expiration 2016

NOLCO In USD In PHP = P 61,007,482 $1,374,197

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 RCIT rate of 30%, while PetroGreen and MGI are subject to a corporate tax of 10%. The reconciliation of the statutory tax rate to the effective income tax rate shown in the consolidated statements of income follows:

Statutory tax rate Add (deduct) reconciling items: Loss from entities subjected to lower rate Movement in unrecognized deferred tax assets Unrealized loss (gain) on FVPL Interest income subjected to final tax Nondeductible exenses Unrealized foreign exchange gain Others Effective income tax rate

2013 30.00%

2012 (As restated Note 3) 30.00%

2011 (As restated Note 3) 30.00%

10.27

3.47

5.68

8.27 (0.06)

1.98 0.25

2.84 0.26

(0.61) 2.86 (1.62) 4.54 53.65%

(2.14) 1.44 (5.38) (1.82) 27.80%

(4.09) (0.12) – (1.49) 33.08%

2013

2012

2011

$4,022,289 915,566 4,596 221,479 $5,163,930

$4,130,614 830,725 5,028 59,842 $5,026,209

$4,788,555 563,622 2,805 77,167 $5,432,149

21. Oil Production Production, transportation and related expenses Storage and loading expenses Supplies and facilities Others

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- 62 22. General and Administrative Expenses

Salaries, wages and benefits (Notes 19 and 23) Taxes and licenses Depreciation (Note 10) Professional and other fees Security and janitorial services Research costs (Note 31) Transportation and travel Rent expense Insurance Donation and contribution Entertainment, amusement and recreation (EAR) Gasoline, oil and lubricants Utilities Office supplies Communication Repairs and maintenance Condominium dues Business meetings Environmental and social expenses Advertisement Stock transfer fees Training and seminar Dues and subscriptions Listing fees Others

2013

2012 (As restated Note 3)

2011 (As restated Note 3)

$1,405,082 405,265 299,315 210,624 161,582 156,933 149,677 128,192 90,373 83,960

$1,110,358 189,628 251,593 302,534 140,546 181,487 156,872 52,108 72,198 48,484

$1,000,459 119,993 146,107 243,084 157,576 147,813 142,680 43,467 55,912 143,272

72,648 70,320 67,173 58,635 58,071 45,247 41,466 38,306 22,797 15,776 12,448 12,419 8,646 � 68,867 $3,683,822

53,290 57,579 46,482 35,552 41,252 22,768 27,349 38,678 6,545 16,160 14,164 47,388 9,911 – 86,351 $3,009,277

57,545 47,101 46,491 32,323 34,465 24,139 24,386 32,226 41,079 7,653 11,884 58,627 4,388 12,909 57,761 $2,693,340

Listing fees in 2011 pertain to the restructuring expenses incurred in relation to the SRO. Others pertain to miscellaneous expenses such as development assistance, notarization and reproduction expenses. 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.

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FORGING AHEAD | ANNUAL REPORT 2013

- 63 23. 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. Significant transactions with related parties are as follows:

Related Party/Nature Investor EPC - Advances Internal audit services Affiliate Civil works EPC - Accounts payable

Amount 2013

2012

Outstanding Balance Receivables (Payables) 2013 2012

Terms and Conditions

$81,450

$1,362,091

15,837

29,978

(5,376)

(10,048)

Note A.

$4,438,338 12,403,445

$– 14,820,787

$4,438,338 (861,771)

$– (2,984,663)

Note B. Note C.

3,664,267 $3,655,891

281,605 ($271,557)

$87,700

$3,266,268

PetroEnergy has engaged House of Investments, Inc. (HI) to perform internal audit services to PetroEnergy. HI charges retainer fee of = P56,000 ($1,261) per month totaling to approximately $15,837 per annum. Also in 2012, PetroEnergy engaged HI to perform process review of its hiring, purchasing and disbursement processes. The engagement fee amounted to P =600,000 ($14,141).

PetroWind has engaged EEI Corporation for the civil works on the construction of wind farm including internal roads, turbine foundations and control room buildings. The Contract is approximately $14.79 million (P =656.8 million). As of December 31, 2013, PetroWind paid down-payment amounting to $4.4 million (P =197 million).

On September 2, 2011, Maibarara engaged EEI Corporation for the Engineering, Procurement and Construction of the MGPP. Contact price is approximately $37 million (P =1.6 billion). Total payment made amounted to $35.9 million (P =1.5 billion). As of December 31, 2013 the contract is 96.43% complete.

24. Financial Instruments The Group’s principal financial instruments include cash and cash equivalents, short term investments, trading and investment securities (financial assets at FVPL), receivables, restricted cash, loans payable, accounts payable, accrued expenses and dividends payable. 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, 2013 and 2012, 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

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- 64 loans payable as of December 31, 2013 and 2012 amounted to $60.74 million and $41.15 million compared to its carrying value of $59.45 million and $38.94 million, respectively. The methods and assumptions used by the Group in estimating the fair value of financial instruments are: Cash and cash equivalents and Receivables Equity securities Debt securities and Golf club shares Accounts payable and accrued expenses Loans Payable

Due to the short-term nature of the instruments, carrying amounts approximate fair values as of the reporting date. Fair values are based on published quoted prices. Fair values are based on quoted market prices as at reporting date. Due to the short-term nature of the instruments, carrying amounts approximate fair values as at reporting date. Fair values 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 2013 and 2012 for the 5 year tenor loans is derived using the projected T-Bond coupon rate of 3.002% and 4.125%, respectively, plus 2.5% credit spread for the first five years and 2.25% for the second five years. For the two loans with 2-year tenor, 2013 fair value is derived using the treasury rate of 2.125% plus a credit spreads of 1.648% and 3.450%, respectively.

The following tables show financial instruments recognized at fair value as of December 31, 2013 and 2012. The fair value is based on the source of valuation as outlined below: x x x

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).

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

Level 1

Level 2

2013 Level 3

Fair Value

$124,317 13,741 $138,058

$� � $�

$124,317 13,741 $138,058

Level 1

Level 2

2012 Level 3

Fair Value

$125,531 17,296 $142,827

$� � $�

$125,531 17,296 $142,827

In 2013 and 2012, there were no transfers of financial instruments among all levels.

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FORGING AHEAD | ANNUAL REPORT 2013

- 65 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 and financial liabilities as of December 31, 2013 and 2012 based on contractual undiscounted payments:

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Short-term investments Accounts receivable: Consortium operator Others Interest receivable Restricted cash Financial Liabilities Loans payable Accounts payable Accrued expenses Accrued interest payable Dividends payable Others: Due to NRDC Others Net financial assets (liabilities)

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Short-term investments Accounts receivable: Consortium operator Others Interest receivable Restricted cash

On demand

Less than 6 months

2013 6 months to 12 months

More than 12 months

Total

$138,058

$�

$138,058

2,229,744 �

341,824 �

� 914,606

� �

2,571,568 914,606

2,561,629 40,098 5,128 � $4,974,657

� � � � $341,824

� � � � $914,606

� � � 63,125 $63,125

2,561,629 40,098 5,128 63,125 $6,294,212

$� 1,698,877 1,623,292 � 235,397

$2,238,080 � � 94,403 �

$� � � � �

$57,214,557 � � � �

$59,452,637 1,698,877 1,623,292 94,403 235,397

� � 57,214,557 ($57,151,432)

51,126 66,571 63,222,303 ($56,928,091)

51,126 66,571 3,675,263 $1,299,394

� � 2,332,483 ($1,990,659)

� � � $914,606

On demand

Less than 6 months

2012 6 months to 12 months

More than 12 months

Total

$142,827

$–

$142,827

1,020,234 –

20,601,988 –

– 814,741

– –

21,622,222 814,741

1,956,341 1,969 23,717 – $3,145,088

– – – – $20,601,988

– – – – $814,741

– – – 63,125 $63,125

1,956,341 1,969 23,717 63,125 $24,624,942

(Forward)

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- 66 -

Financial Liabilities Loans payable Accounts payable Accrued expenses Accrued interest payable Dividends payable Others: Due to NRDC Others

Net financial assets (liabilities)

On demand $– 3,226,210 471,287

Less than 6 months $– –

2012 6 months to 12 months

More than 12 months

Total

–

$38,943,444 – – – –

$38,943,444 3,226,210 471,287 683,762 260,098

– – $38,943,444

55,292 180,455 $43,820,548

($38,880,319)

($19,195,606)

$– – –

260,098

683,762 –

55,292 180,455 $4,193,342

– – 683,762

– – $–

$19,918,226

$814,741

($1,048,254)

As stated on Note 1, the 20 MW MGPP is expected to start commercial operations by late 2013. Proceeds from sale of electricity will then be used to settle the Group’s loans payable. b.

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. The analysis below is performed for reasonably possible movements in the PSE index (PSEi) 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). The Group used the daily average of movements in PSEi price indices, plus adjusted betas for equity securities.

Equity securities Golf club shares

2013 Impact on income before tax % Increase Decrease 16% $20,650 ($20,650) 20% 23,535 (23,535) $44,185 ($44,185) 2012 Impact on income before tax % Increase 17% $20,161 19% 3,464 $23,625

Decrease ($20,161) (3,464) ($23,625)

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- 67 There is no other impact on the Group’s equity other than those already affecting income before tax. Foreign Exchange Risk Exposure to currency risk arises from general and administrative expenses, assets and liabilities 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). The Group used the year-average forecast from the Business Monitor International in the analysis. 2013 Increase/decrease in Php rate

Impact on income before tax $256,430 ($256,430)

+0.89% -0.89% 2012

Increase/decrease in Php rate

Impact on income before tax $81,617 ($81,617)

+2.56% -2.56%

There is no other impact on the Group’s equity other than those already affecting income before tax. Interest Rate Risk The Group’s exposure to market risk for changes in interest rates relates primarily to the Group’s short-term investments amounting to $1.26 million and $21.42 million for December 31, 2013 and 2012, respectively (see Notes 6 and 9). Interest rate of loans payable is fixed for the first five (5) years and will be repriced thereafter. 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. The Group used the forecasted one-year Treasury Bill rate in performing the analysis below. 2013

Increase/decrease in interest rate (in basis points) +148 -148

Impact on income before tax ($1,949,299) 1,949,299

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- 68 2012

Increase/decrease in interest rate (in basis points) +51 -51

Impact on income before tax $109,606 (109,606)

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

Credit Risk There are significant concentrations of credit risk within the Group since most of its financial assets are with consortium operator, although credit risk is immaterial. The gross maximum exposure of the Group’s credit risk is equal to the carrying amounts of the financial assets. The table below shows the summary of maximum credit risk exposure on financial instruments as of December 31, 2013 and 2012: Financial assets at FVPL: Marketable equity securities Golf club shares Loans and receivables: Short-term investments Cash in bank Accounts receivable: Consortium operator - net Others Interest receivable Restricted cash

2013

2012

$124,317 13,741

$125,531 17,296

914,606 2,566,635

21,416,729 1,016,093

2,622,051 40,098 5,128 63,125 $6,349,701

2,021,687 1,969 23,717 63,125 $24,686,147

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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- 69 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, 2013 and 2012:

Cash in banks Short-term investments Accounts receivable: Consortium operator Others Interest receivable Restricted cash

2013 Neither past due nor impaired Past due High grade Standard grade and impaired $2,566,635 � � 914,606 � � 2,561,629 40,098 5,128 63,125 $6,151,221

� � � � $�

Total $2,566,635 914,606

60,422 � � � $60,422

2,622,051 40,098 5,128 63,125 $6,211,643

2012 Neither past due nor impaired Past due High grade Standard grade and impaired $1,016,093 $– $– 21,416,729 – –

Total $1,016,093 21,416,729

1,956,341 1,969 23,717 63,125 $24,477,974

– – – – $–

65,346 – – – $65,346

2,021,687 1,969 23,717 63,125 $24,543,320

The tables below show the aging analysis of the Group’s receivables as of December 31, 2013 and 2012. 1 to 90 days Accounts receivable Consortium operator Others Interest receivable

$2,561,629 40,098 5,128 $2,606,855

1 to 90 days Accounts receivable Consortium operator Others Interest receivable

$1,956,341 – 23,717 $1,980,058

2013 Over 90 days

Total

$60,422 � � $60,422

$2,622,051 40,098 5,128 $2,667,277

2012 Over 90 days

Total

$65,346 1,969 – $67,315

$2,021,687 1,969 23,717 $2,047,373

As of December 31, 2013 and 2012, 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.

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- 70 25. Segment Information For management purposes, the Group is organized into business units based on their products and has three reportable segments as follows: x x x

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. 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.

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

Oil Production $13,717,422 3,832,460 (41,856)

Geothermal Energy $� (1,167,006) �

2013 Wind Energy $� (1,396,789) �

Elimination $� (132,248) (1,899,147)

Consolidated $13,717,422 1,136,417 (1,941,003)

$58,202,613 $266,754 $12,176,835

$71,745,079 $� $52,033,105

$17,168,310 $� $5,168,537

($31,863,883) ($232) ($4,814,080)

$115,252,119 $266,522 $64,564,397

$5,802,532 (24,521,348) 9,844,324 $1,763,572 $677,142 $11,397,210

($3,491,720) (23,767,886) 18,312,873 $� $26,819,947 $�

($17,177,016) (1,160,036) 18,402,682 $� $515,241 $�

$4,793,168 20,897,217 (24,884,982) $� $� $�

($10,073,036) (28,552,053) 21,674,897 $1,763,572 $28,012,330 $11,397,210

$1,633,213

Oil Production $11,990,120 3,375,880 7,103 $43,725,937 $140,523 $1,049,515 $4,659,270 (6,852,702) (1,252,489) $899,560 $713,250 $6,643,203 $1,804,576

$107,721

Geothermal Energy $– (589,948) � $60,509,231 $– $43,166,651 $1,337,954 (28,525,023) 29,370,893 $– $30,694,556 $– $35,236

$7,051 2012 Wind Energy $– (449,228) – $12,957,722 $– $100,138 ($371,833) (4,125,793) 4,470,614 $– $655,658 $– $25,284

$�

$1,747,985

Elimination $– (259) $834,510

Consolidated $11,990,120 2,336,445 841,613

($25,886,931) $– $–

$91,305,959 $140,523 $44,316,304

$205,305 7,314,354 (7,723,265) $– $– $– $–

$5,830,696 (32,189,164) 24,865,753 $899,560 $32,063,464 $6,643,203 $1,865,096

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

Oil Production $13,544,412 3,669,299 (12,720) $42,082,175 $79,716 $1,440,164 $6,232,222 (6,045,824) (1,243,767) $1,337,611 $1,501,183 $5,831,668 $1,959,994

Geothermal Energy $– (628,428) –

2011 Wind Energy $– (335,564) –

Elimination $– – (115,391)

Consolidated $13,544,412 2,705,307 (128,111)

$26,965,599 $– $16,047,184

$8,390,174 $– $19,281

($16,957,258) $2,487 ($4,643)

$60,480,690 $82,203 $17,501,986

$1,606,518 (15,072,853) 20,016,948 $– $9,531,841 $– $21,366

($503,680) (5,174,163) 6,052,318 $– $161,763 $– $22,029

$19,021 11,031,718 (11,116,330) $– $– $– $–

$7,354,081 (15,261,122) 13,709,169 1,337,611 $11,194,787 $5,831,668 $2,003,389

Intercompany investments, revenues and expenses are eliminated during consolidation. 26. Basic/Diluted Earnings Per Share The computation of the Group’s earnings per share follows: Net income attributable to equity holders of the Parent Company Weighted average number of shares Basic/diluted earnings per share

2013

2012

2011

$2,211,220 273,824,220 $0.008

$2,559,582 273,824,220 $0.009

$2,821,548 273,824,220 $0.010

27. Noncontrolling Interests Noncontrolling interests represent the 35% shareholdings of Trans-Asia and PNOC in MGI and 20% shareholdings of EEI-PC in PetroWind. MGI and PetroWind are entities incorporated and are operating in the Philippines. As of December 31, 2013, 2012 and 2011, the accumulated balances of and net loss attributable to noncontrolling interests are as follows: Accumulated balances of noncontrolling interests: MGI PWEI Net loss attributable to noncontrolling interests: MGI PWEI

2013

2012

2011

$7,220,144 2,456,332 $9,676,476

$5,807,379 – $5,807,379

$3,851,627 – $3,851,627

$408,452 279,358 $687,810

$223,137 – $223,137

$220,087 – $220,087

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- 72 The summarized financial information of these subsidiaries is provided below in Philippine Peso which is the subsidiaries’ functional currency. This information is based on amounts before intercompany eliminations. MGI Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statements of Income Revenue Expenses Net loss Statements of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Effect of foreign exchange rate Net increase (decrease) in cash and cash equivalents

2013

2012

2011

P =117,642,802 3,067,480,467 (122,513,042) (2,187,496,661) P =875,113,566

=680,221,340 P 1,803,687,842 (173,362,669) (1,598,628,371) =711,918,142 P

=692,298,275 P 487,327,555 (120,649,615) (582,858,897) =476,117,318 P

P =4,482,998 (54,287,574) P =49,804,576

P10,763,172 = (35,675,709) =24,912,537 P

=5,161,507 P (32,781,722) =27,620,215 P

(P =242,869,564) (967,320,634) 813,000,000

(P =55,707,650) (1,155,376,139) 1,300,713,361

=70,018,432 P (661,233,989) 877,543,012

(849,289)

(359,929)

(351,927)

(P =398,039,487)

PWEI* Statements of Financial Position Current assets Noncurrent assets Current liabilities Equity Statements of Income Revenue Expenses Net loss Statements of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Net increase in cash * PWEI was incorporated on March 6, 2013

P =89,269,643

P =285,975,528 2013 =711,008,607 P 51,178,534 (229,457,180) =532,729,961 P =75,035 P (61,095,074) =61,020,039 P (P =762,573,620) (51,499,798) 816,987,064 =2,913,646 P

There were no dividends paid to noncontrolling interests.

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- 73 The increase in noncontrolling interests from stock issuances follows: x

As of December 31, 2011, MGI issued 3,240,625 common shares with = P100 par value and collected subscription receivable amounting to = P24.23 million, which increased the noncontrolling interests by P =121.90 million.

As of December 31, 2012, MGI issued 1,740,015 common shares with = P100 par value and collected subscription receivable amounting to = P86.71 million, which increased the noncontrolling interests by P =91.25 million.

As of December 31, 2013, MGI and PetroWind issued 2,130,000 and 5,937,500 common shares, respectively with = P100 par value. Such stock issuances increased the noncontrolling interests by = P806.75 million.

28. Notes to the Consolidated Statements of Cash Flows

In 2013, the noncash investing activity of the Group pertains to the additions to Property, plant and equipment, which is due to the increase in ARO estimate amounting to $0.47 million. In 2012, the noncash investing activity of the Group pertains to the reduction in Property, plant and equipment, which is due to the decrease in ARO estimate amounting to $0.27 million. In 2011, noncash investing activities pertain to the following items: x x x

Transfer from Deferred oil exploration costs to Wells, platforms and other facilities amounting to $1.18 million. Transfer from Deferred geothermal costs to FCRS and production wells - Geothermal amounting to $1.28 million. Increase in Wells, platforms and other facilities due to change in ARO estimate amounting to $9,067.

29. Events After the Reporting Period PetroGreen On February 14, 2014 CapAsia Asean Wind Holdings Cooperatief U.A (CapAsia) purchased 50% of PetroGreen’s 80% investment in PetroWind. MGI The MGPP started the commercial operation on February 8, 2014. This 20-MW Maibarara geothermal project situated in Sto. Tomas, Batangas, is the newest geothermal power facility in the country and the first under President Benigno S. Aquino’s administration. PetroWind On November 4, 2013, the = P2.4 billion Omnibus Loan and Security Agreement between Petrowind and Development Bank of the Philippines was signed. The first drawdown materialized on January 10, 2014 amounting to = P991 million.

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- 74 As of February 14, 2014 equity holders of PetroWind are: 40%, PetroGreen; 40% CapAsia (beneficial owner) and 20% EEIPC. 30. 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 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. ii.

iii.

iv.

v. vi. vii.

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; 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; 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; 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; 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; 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; 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,

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- 75 construction and installation of the plant facilities, as well as the whole process of exploration and development of RE sources 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. 31. 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.

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- 76 Specifically, the EPIRA has the following objectives: x x x x x

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.

32. 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 has undergone 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 which was prepared by Endesa presents information on the essential technical and organizational aspects of the project activity and is a key input in the validation, 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. The Secretariat of the United Nations framework convention on climate change (UNFCCC) has confirmed that the MGPP has been registered effective December 26, 2012. 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 . The slowdown in world market conditions for carbon credits severely affected Endesa, necessitating its closure and eventual liquidation. For this reason, effective June 28, 2013, MGI and Endesa decided to mutually terminate the ERPA.

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- 77 On July 31, 2013, MGI entered into a memorandum of agreement (MOA) with Enel Trade S.P.A (Enel), a company registered and domiciled in Rome, Italy, with the intention of establishing an arrangement for the discussion, negotiation, and cooperation of a mutually beneficial CER purchase agreement. To date, MGI has not yet closed a CER purchase agreement with Enel. The MOA is valid for one year from the date of its signing. b. Electricity Supply Agreement In 2011, MGI entered into an Electricity Supply 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, in 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 changes in foreign exchange and inflation. 33. Wind Energy Service Contract (WESC) On September 14, 2009, the PetroEnergy 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, PetroEnergy 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, PetroEnergy 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, PetroEnergy created PetroGreen to carry out its renewable energy projects, which includes the wind energy projects. On November 30, 2009, PetroEnergy purchased a 60m wind mast from NRG Systems. Power Dimension, Inc. (PDI) was hired to erect the mast at the site. Tower lifting began on February 17, 2010 and the mast was fully raised on February 18, 2010. In September 2010, the Company’s Senior Wind Specialist (consultant), the contracted Danish engineering consultant, recommended the installation of a second mast in Nabas, Aklan to increase confidence in the wind data. Installation of the second mast was completed on the first week of January 2011. Following one year of wind data recording in Nabas (Aklan) and Sual (Pangasinan) wind service contract areas in February 2011, initial micrositing and annual energy production analyses were prepared by the consultant. The consultant 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.

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- 78 In contrast to Sual, the consultant reported in July 2011 that the Nabas project site can sustain a 50 MW wind farm. This encouraging result led PetroEnergy 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 ECC. In November 2011, PetroEnergy 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. PetroEnergy 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 Company to PGEC. The DOE also granted the one-year extension of the predevelopment phase from September 13, 2011 to September 13, 2012. On December 26, 2011, PetroGreen obtained the CNO from the NCIP which certified that the project area is free of any ancestral domain claims from indigenous communities. Research costs relating to the Wind Energy power project amounted to $165,079, $147,813, and $114,476 as of December 31, 2012, 2011 and 2010 respectively. These are included as “research costs” under “General and administrative expenses” in the consolidated statement of income. In 2012, PetroGreen moved to further advance the project towards eventual commerciality. The key activities centered on securing critical government permits, completing technical feasibility studies, and initiating request for engineering, procurement, and construction bids for the wind farm. On June 2012, the critical ECC for the 50 MW Nabas wind power project was released by the DENR Region 6 Office in June 2012. This gave PetroGreen clearance to proceed to site development, from road rehabilitation, access road construction, wind turbine installation, transmission line erection, and operation and maintenance of the facility subject to compliance to standard environmental regulations. Another government approval sought was DOE’s Declaration of Commerciality for the project which was applied on September 10, 2012. As part of this application process, the DOE’s Renewable Energy Management Bureau (REMB) conducted a site visit on November 27-19, 2012 to meet with local municipal and barangay officials and DENR staff who assured the DOE team of the strong support for the project. With more than two years of wind data, the consultant completed its technical feasibility study in August 2012, concluding the viability of the site to generate 50MW of wind power with a high capacity factor. At the same time, NGCP completed its own system impact study that stressed that the four wind turbine models from different suppliers are all compliant with NGCP standards; further, NGCP recommended the location and type of transmission connection for Nabas. Using these two major technical studies, PetroGreen completed in August its own conceptual engineering design of the project, recommending a phased development with an initial phase of about 36 MW capacity and a second 14 MW phase. Given the positive results of various technical studies, PetroGreen moved to obtain costing and commitment from several likely construction partners for various project components. It started

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- 79 by signing a Heads of Agreement (HOA) with EEI Corporation for the balance of plant construction contract. All the foregoing activities were prompted not only by the positive results of the various technical feasibility studies but also the Energy Regulatory Commission’s (ERC) decision to grant a feedin-tariff rate of P8.53/kWh to qualified wind farm developers. In May 2013, after several months of review, the DOE conferred the Confirmation of Commerciality for the 50 MW NWPP in Nabas, Aklan. In confirming the project commercial, the DOE also effectively converted the Nabas service contract from exploration stage to development phase with a contract life of 25 years, or until 2034. The confirmation of commerciality on Nabas brought to four (4) the number of Philippine wind projects officially endorsed for feed-in-tariff (FiT) pre-qualification and competition. As part of the venture into wind energy production, PetroEnergy incorporated a new subsidiary – PetroWind - on March 6, 2013 to handle the Nabas project development, from securing financing through project construction and eventual operations and maintenance. DOE approved the transfer of the Nabas service contract from PetroGreen to PetroWind in July 2013. Subsequently, on July 15, 2013 EEIPC, a subsidiary of EEI Corporation, subscribed a 20% stake in PetroWind ( EEIPC formally became a stockholder of PertroWind upon the SEC’s approval of PetroWind’s increase in authorized capital stock on August 23, 2013), leaving PetroGreen with an 80% interest in PetroWind as of December 31, 2013. On November 4, 2013, Development Bank of the Philippines (DBP) granted to PetroWind a = P2.8 Billion loan for the project payable in 15 years; such loan was the first ever extended by DBP for a wind power project attesting to its confidence to PetroWind to turn NWPP into reality. Substantial progress was likewise achieved in the technical design and construction aspects of the project. Even as PetroWind awaited DOE’s decision on our confirmation of commerciality, PetroWind initiated the rehabilitation of the existing access road to the wind farm as part of corporate social responsibility efforts. The rehabilitation was started in May, 2013 with the goal of making the 5-km long barangay road accessible only by motorcycles into a road wide enough to accommodate the entry of the initial wave of heavy equipment. While road rehabilitation efforts were starting, PetroWind also signed in late 2013 key construction or supply contracts covering the switchyard and transmission line with Cendaur Engineering, civil works on the wind farm including internal roads, turbine foundations, and control room buildings with EEI Corporation, and wind turbine supply, installation, and maintenance and operation with Gamesa Eolica of S.L. Unipersonal Spain. All these have set the stage for an expedited program to finish the installation of the wind turbines by late 2014 to early 2015. 34. MGI Contracts and Agreements a.

Remote Monitoring System and Technical Advisory Services Agreement On August 19, 2011, MGI entered into an agreement with Fuji Electric Co. Ltd. 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.

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- 80 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. b.

Interconnection Agreement MGI signed an Interconnection Agreement (ICA) with MERALCO for the physical interconnection of the generation and connection facilities of MGI’s 20 MW power plant to MERALCO’s distribution system. The power facility being constructed in Brgy. San Rafael, Sto. Tomas, Batangas will be connected to MERALCO’s existing 115 kV line in Calamba, Laguna. MGI and MERALCO, along with Trans-Asia Oil and Energy Development Corporation (TRANS-ASIA), also signed on December 6, 2012 a Memorandum of Agreement (MOA). The MOA defined the respective rights and obligations among the Parties: MGI as a Generation Facility to be interconnected with MERALCO’s distribution system under the ICA, and TRANS-ASIA as the sole off-taker of MGI’s electricity output under the Electricity Sales Agreement (ESA), which shall sell said output through MERALCO’s distribution system.

Transmission Line, Operation, Service and Maintenance Agreement On March 26, 2013, MGI entered into an agreement with Nikkon Builders International, Inc. wherein the latter will conduct the operation, service and maintenance of MGI’s switchyard and 4.8 kilometers transmission line within the period of five (5) years. The agreement includes an annual inspection services fee amounting to $4,214 on the first year for both switchyard and transmission line and “on call” services based on pre-agreed rates for manpower and equipment utilization.

35. PetroWind Contracts and Agreements a.

Wind Turbine Generators Supply, Services and Maintenance Agreements On August 30, 2013, PetroWind entered into a Supply Agreement with Gamesa Eolica S.L. Unipersonal for the supply and purchase of wind turbine generators (WTG). The price of the equipment amounted to $36,028,966 and the price to transport the equipment amounted to $2,233,405 that adds up to a total of $38,262,371. The Services Agreement with Gamesa Eolica S.L. Unipersonal Philippines Branch was entered by PetroWind also on August 30, 2013 which covers inland transportation, installation, start up, commissioning and testing of the equipment and the execution of certain electrical works and associated civil works. The contract price for the Services is $12,835,816.94. The Maintenance Agreement with Gamesa Eolica S.L. Unipersonal Philippines Branch which is for a term of 5 years covers the full scope operation and maintenance services of certain wind turbine generators and related equipment. The annual price is $65,800 per WTG plus inspection and repair fee of $2,500 per WTG per year and $9,800 per year for the weather/wind production forecasting.

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- 81 b.

Civil Works Contract Agreement On August 1, 2013, PetroWind signed a Contract Agreement with EEI Corporation for the civil works to include construction of 18 units WTG foundations, roadways and temporary landing pad intended for the 36MW Nabas Wind Power Project (NWPP). The contractor shall complete the works within 11 calendar months from the commencement of works. The contract price amounted to $14,794,459 (P =656,800,000).

Transmission Line and Switchyard Contract Agreement PWEI signed a Contract Agreement with Cendaur Engineering on July 5, 2013 for the design selection, supply, delivery, erection, installation, and testing of the 36 MW NWPP 69kV Switchyard. Total contract price is $1,252,750 (for foreign component, excluding duties and taxes) plus $861,662 (P =38,253,500) (for local component), exclusive of local Value Added Tax. Likewise, a Contract Agreement with the same contractor was entered into on August 5, 2014 for the 69kV transmission line in the amount of $696,291 (P =30,911,854).

36. Reclassification of Accounts Previously, the short-term investments account was shown under advances, prepaid expenses and other current assets account. In 2013, the short-term investment account was presented separately in the consolidated statement of financial position. Accordingly, the December 31, 2012 presentation was revised to conform with the December 31, 2013 presentation. Similarly, the input VAT account was shown previously under advances, prepaid expenses and other current assets account. In 2013, the input VAT was presented under advances and other noncurrent assets account. Accordingly, the December 31, 2012 and January 1, 2012 presentation was revised to conform with the December 31, 2013 presentation. Management believes that the new presentation is more appropriate.

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Board of Directors

Helen Y. Dee Chairman of the Board Yvonne S. Yuchengco Director and Treasurer

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Milagros V. Reyes Director and President

Eliseo B. Santiago Director

Cesar A. Buenaventura Director

Raul M. Leopando Director

Basil L. Ong Director

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Corporate Directory

OFFICERS

President: Milagros V. Reyes Vice President: Francisco G. Delfin, Jr. Treasurer: Yvonne S. Yuchengco Corporate Secretary: Atty. Samuel V. Torres

CORPORATE DIRECTORY AUDITOR SGV & Co. 6760 Ayala Ave., Makati City

BANKER

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 Gil J. Puyat Avenue, Makati City Telephone Nos.: (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:http://www.petroenergy.com.ph

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Layout and Design by: Sakura Donna A. Suzuki

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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 | 647-4362 Fax: (632) 634-6066 | 633-8584 Email Address: petro_energy@petroenergy.com.ph Website: http://www.petroenergy.com.ph