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PETROENERGY RESOURCES CORPORATION

02 04 08 28 29 31 39 131 132 FINANCIAL HIGHLIGHTS

TABLE OF CONTENTS

MESSAGE TO OUR SHAREHOLDERS

OPERATIONS REVIEW

STATEMENT OF MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS INDEPENDENT AUDITOR’S REPORT FINANCIAL REPORTs NOTES TO CONSOLIDATED FINANCIAL STATEMENTS BOARD OF DIRECTORS

OFFICERS AND CORPORATE DIRECTORY

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

(In thousand US dollar, except per share, ratio value, and oil price)

CONSOLIDATED 2015

2014

ASSETS

237,131

142,047

LIABILITIES

154,753

83,275

STOCKHOLDER’S EQUITY

82,378

58,772

OIL REVENUE

6,575

11,133

ELECTRICITY SALES

16,968

14,742

OPERATING INCOME

10,508

13,271

INCOME BEFORE INCOME TAX

1,176

15,720

NET INCOME

4,609

9,751

BOOK VALUE PER SHARE

0.162

0.183

EARNINGS PER SHARE

0.008

0.031

CURRENT RATIO

1.02:1

0.45:1

DEBT-TO-EQUITY RATIO

1.88:1

1.42:1

AVERAGE CRUDE OIL PRICE

$48.16

$93.59

OIL PRODUCTION BARRELS (in thousand Barrels)

6,777

5,803

PH’s highest perched wind farm to date at ~300-500 masl

Fuji’s 20 MW Turbine Generator in Maibarara

DESCO Drilling Rig for SC 51

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

The latest addition to our growing portfolio of renewable energy projects is the 50MW Tarlac Solar Power Project (TSPP) located in Central Technopark, Hacienda Luisita, Tarlac City. The TSPP was among the leading projects to have achieved FIT-eligibility for the FIT rate for solar projects of Php8.69/kWh. It is also considered among the biggest in Luzon, possibly the most cost-competitive, and among the fastest to have been constructed in the Southeast Asian Region. For the first year of operation, TSPP is projected to generate 63,574 MWh of electricity translating to about Php 552.46 MM in total revenue. As we ensure the efficient operations of our power facilities, we also gear up for the upcoming expansion of our projects – 12 MW Maibarara-2, 14 MW Nabas-2, and 50 MW Tarlac-2. The additional 76 MW of power generation will not only contribute to the grid stability in Luzon and Visayas but also improve the Company’s consolidated financial performance. We are optimistic that our efforts to expand the range of our investments will translate to value added to shares and dividends payout in the coming year.

xpanding our investment portfolio to include renewables has proven to be a very critical contributor to the success and resilience of our Company. You may recall that in late 2014, we already began seeing the adverse impact of the global oil crisis. We have felt this even more in 2015 as our oil revenues decreased dramatically. Even as we ramped up our crude production, we saw our oil revenue drop from US$ 11.133 MM in 2014 to US$ 6.575 MM in 2015. Thankfully, the revenues from our RE businesses have cushioned the losses in our oil operations. The efficient power plant operations in our RE facilities have contributed to an increase in electricity sales from US$ 14.742 MM in 2014 to US$ 16.968 MM in 2015. We put on stream the 20 MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas in February 2014. Since then, our 65% share in MGPP has been contributing significantly to our consolidated revenues. Our 36 MW Nabas Wind Power Project (NWPP) in Nabas-Malay, Aklan, composed of 18 wind turbines overlooking the island paradise of Boracay, is currently the highest perched wind farm in the country. Building the NWPP was a civil works and logistics challenge, but we managed to complete the project, entitling the NWPP to the second round of Feed-in-Tariff (FIT) for wind projects of P7.40/kWh. The wind farm is expected to generate 96,499 MWh of electricity for 12 months. The Php 4.6 Billion NWPP is considered to be the biggest single investment in Aklan to date.

GREENING POWER GENERATION 2015 ANNUAL REPORT

Greening Power Generation In today’s energy business where there is rapid technological innovation, changing political landscape, and volatile commodity prices, we remain committed to keep our business keenly competitive. More importantly, we are one with the world in heeding the call for more investments in greener, environment-friendly energy technologies. As we continue to strive hard to protect our existing petroleum assets and search for new prospects, we are also hopeful that the renewable energy sector will have more to offer. We shall therefore continue to actively look for other opportunities to generate and deliver more reliable and sustainable power to our stakeholders. We will intensify our efforts to bring value to your investments, increase our social development contribution to our communities, and further strengthen our human capital. We thank you our shareholders for being with us in good and in tough times. We owe our continuing success to you and to the careful planning and meticulous project execution of our Management, and to the commitment and teamwork of our staff. As we continue to venture into greening power generation, we hope that your invaluable trust and support will remain.

Helen Y. Dee

Chairman of the Board

Milagros V. Reyes President

PETROENERGY RESOURCES CORPORATION

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

Expansion of the Etame Field Gabon, West Africa PRODUCTION & DEVELOPMENT

2015 Overall crude production For 2015, the daily oil production from the four (4) oil fields (Etame, Avouma, Ebouri and North Tchibala) ranged from 13,780 - 22,140 barrels of oil per day (BOPD). This translates to a total crude production of 6.78 million barrels of oil (MMBO), ~1 million barrels higher than in 2014. The higher production was contributed by the six (6) new production wells drilled from the Etame Platform and the Southeast Etame/North Tchibala Platform. In addition, the successful work over of two (2) Avouma wells added ~3,000 BOPD. Despite the natural depletion of the field and transient production downtimes, 2015 daily production was still higher compared to 2014’s range of 7,110 - 19,900 BOPD. The consortium managed eleven (11) liftings for the year resulting to net crude export of 6.88 MMBO. Crude oil market prices for the year ranged from US$ 36.11 US$ 68.30 per barrel, with actual crude sales averaging US$ 48.16 per barrel.

GREENING POWER GENERATION 2015 ANNUAL REPORT

In December 2012, the Consortium began the expansion of the Etame Field. The 18-month program which costs US$ 500 MM, consists of the fabrication and installation of two (2) additional platforms and the drilling of 6 to 11 wells from these platforms. One platform was placed over the existing Etame field, which was originally subsea-completed, while the other one was installed in a new oil field South of Etame (Southeast Etame). After 11 months of fabrication, the installation of the two platforms was completed on schedule in September 2014. Subsequently, the Etame Expansion Drilling Campaign commenced in November 2014.

Drilling and Workover Program The Etame Expansion drilling program started with the drilling of three (3) production wells from the new Etame Platform. The Constellation II jack-up rig drilled ET-8H from November to December 2014, ET-10H from December 2014 to February 2015, and ET-12H from February to April 2015. The rig then moved towards the new SEENT Platform to drill three (3) additional wells. The first SEENT well, ETSEM-2H, was drilled from April to June 2015. After which, two (2) more wells were drilled to tap new oil-bearing geologic horizons other than the productive GAMBA Sands. Well ETBNM-1H, whose main objective was the older channel sands, Dentale D09, was drilled from June to September 2015, while well ETBNM-2H, which targeted the Dentale D18/19 sandstone reservoir, was drilled from September to November 2015. These two wells opened up new productive geologic horizons in our Gabon contract area. PETROENERGY RESOURCES CORPORATION

After drilling operations at the SEENT Platform, the Constellation II rig moved to the Avouma Platform in early January 2016 to conduct workover operations on two (2) Avouma wells with defective submersible pumps. As a strategic move to cope with falling oil prices, the consortium decided to conclude the drilling program at this point. The Constellation II rig was demobilized on January 25, 2016.

Crude Sweetening Project One challenge that has come up in the Gabon concession is the emergence of H2S gas in the produced oil of four (4) wells. In July 2012, two wells in Ebouri field manifested H2S 10

GREENING POWER GENERATION 2015 ANNUAL REPORT

in their production, while two (2) wells in Etame field yield H2S in 2014. Since the Ebouri field still contains substantial unrecovered oil, the study of the sweetening process which aims to address the gases from these sour wells, was started in 2012. However, due to the recent decline in oil prices, the project was put on hold. The Gabon oilfield currently has eleven (11) wells producing a total of 21,000 barrels of oil per day. The Gabon consortium has maintained this approximate level of production since the field was put on stream in 2002. A total of 92 million barrels of oil has been extracted to date over the last 13 years, with gross revenue of US$ 6.6 Billion. PETROENERGY RESOURCES CORPORATION

SC 6A - Octon-Malajon Block On May 14, 2015, the DOE approved the exit of Pitkin Petroleum PLC (Pitkin) from the Consortium and the reassignment of Pitkin’s Participating Interest to the remaining JV Partners. The operatorship of the block reverted to The Philodrill Corporation who presented the results of its Geological & Geophysical (G&G) evaluation of the northern portion of SC 6-A block. The study resulted in the identification of new prospects which merit further evaluation. In order to enhance the prospectivity of the identified prospects, Philodrill further proposed the conduct of Broadband Processing of the 2013 3D seismic data followed by a Quantitative Interpretation (QI) workflow. These activities formed part of the 2016 work program, which the DOE approved. PERC’s participating interest in SC 6-A block increased to 16.667% from 5.001%, with the exit of Pitkin Petroleum.

SC 47 - Offshore Mindoro and Panay On February 25, 2015, the SC 47 consortium led by PNOC-Exploration Corporation (PNOC-EC) agreed to relinquish SC 47 block with an option to reapply for the same contract once it is offered again by the DOE. This decision was based on the existing high geologic risk of the current prospects and the lack of interest from investors under the current oil exploration environment. A Letter of Withdrawal of the Joint Venture was sent to DOE on July 28, 2015. To date, the Consortium is still waiting for DOE’s formal approval of the relinquishment of the block. PERC’s participating interest in SC 47 remains at 2.00%, PNOC-EC at 97.00%, and Basic Energy at 1.00%. 12

GREENING POWER GENERATION 2015 ANNUAL REPORT

SC 14 C2 - West Linapacan, Northwest Palawan On February 5, 2015, the DOE granted operator RMA West Linapacan Pte Ltd. (RMA) an additional one-month extension until March 5, 2015 to show proof of financial capability, which RMA failed to provide. This prompted the DOE to terminate on March 12, 2015 RMA’s operatorship of, and membership in, the SC 14-C2 Service Contract. Due to the DOE’s decision and having failed to carry out their commitment, both RMA and Pitkin Petroleum Plc, who originally farmed-in to the block, ended their involvement in the consortium. From April 2015 onwards, the remaining Consortium members, including Nido Petroleum, sought to continue works in the block by conducting technical and commercial audit of works done by RMA during its operatorship. Philodrill re-assumed operatorship of the block and formally requested RMA to hand over all technical, legal, and financial documents in their possession during its operatorship. However, with oil prices continuing to drop throughout the year, the Consortium was in general agreement to postpone any further development in the block. To keep the Service Contract active, Philodrill proposed a 2016 Work Program & Budget (WP&B) for SC 14-C2, which consists of technical and commercial audit of the block alongside continuing efforts to secure the G&G data generated by previous operator RMA. On August 2015, the DOE formally reassigned the Participating Interest of Pitkin to the original Filipino partners (Oriental Petroleum & Minerals Corp., The Philodrill Corp., Forum Energy Philippines Corp., Alcorn Petroleum & Mineral Resources, and PERC) upon termination of the Farm-In Agreement, with PERC’s participating interest in SC 14-C2 back to 4.137%.

SC 51 - East Visayas In 2015, most of the activities done in SC 51 focused on the administrative transition brought about by the impending exit of farminee/operator Otto Energy Investment Ltd. (OEIL), after having failed to convince the DOE to accept the aborted Duhat-2 well as a compliant well. The DOE decided that the properly prepared Duhat-2 well which had a blowout at 201 meters, was a non-compliant well for the Consortium’s obligation due to its failure to reach the target drilling depth, in spite the fact that it had complied with the financial commitment. The remaining partners Trans-Asia Petroleum Corporation (Trans-Asia), Alcorn Petroleum and Minerals Corporation (APMC), and PERC informed DOE of the Consortium’s plan to continue with the Service Contract without OEIL via a revised Work Program for Sub-Phase 5. The Consortium proposed: (1) Conduct of a pre-drilling pore pressure study aimed at identifying overpressure areas in the vicinity of San Isidro prospect; and (2) conduct of high-resolution gravity survey in certain portions of the block to map anomalies which could become new leads and prospects. Since the Service Contract is nearing its maximum 10-year allowable exploration period, interim Operator Trans-Asia sent a letter of request to DOE to invoke a Force Majeure event arising

from the results of drilling Duhat-2. This will give adequate time for the remaining partners to execute the proposed Work Program. To date, the Consortium has not yet received DOE’s reply. PERC’s participating interest in SC 51 will increase to 20.05% from 4.012% upon execution of OEIL’s exit from SC 51, with interim Operator Trans-Asia at 33.35% and APMC at 46.60%.

SC 75 - Offshore Northwest Palawan Activities for SC 75 in 2015 focused on the on-going G&G works for Subphase 1. Results of the marine gravity survey acquired in 2014 were presented to the Consortium on January 12, 2015, while the interpretation of the 2D seismic data was presented on May 22, 2015. On September 9, 2015, the DOE placed SC 75, along with adjacent blocks SC 58 and SC 72 Recto Bank, under Force Majeure due to the geopolitical tensions in the West Philippine Sea. By this time, the Consortium has already fulfilled its Work Program for Subphase 1, consisting of the acquisition, processing and interpretation of 2,200 line-km of 2D seismic data over SC 75, with total cost of US$ 3.13 MM. In the event that the DOE lifts the Force Majeure imposed on SC 75 for exploration works to resume, the Consortium is ready to proceed to Subphase 2 and then conduct a ~1,000 sq.km 3D seismic survey with a minimum DOE approved budget of US$ 3.50 MM. Philex Petroleum is the Operator of SC 75 with 50.00% participating interest, PNOC-EC with 35.00%, and PERC with 15.00%. PETROENERGY PETROENERGYRESOUARCES RESOURCES CORPORATION

PERC’s decision to diversify into renewable energy in 2009 is now bearing fruit for the Company and its shareholders. Power facilities commissioned in 2014 (Maibarara Geothermal Facility) and 2015 (Nabas Wind Farm) are rooted in renewable energy service contracts awarded in 2009-2010. More recently, the grant of a new Solar Service Contract in March 2015 led to the successful commissioning of the Tarlac Solar Power Plant in January 2016. Maibarara Geothermal Inc. (MGI), PetroWind Energy Inc. (PWEI), and PetroSolar Corporation (PSC) are the PERC subsidiaries directly overseeing the operation of the three renewable energy projects with combined capacity of 106 MW.

eading the Company’s renewable energy venture, the 20 MW Maibarara Geothermal Power Plant (Maibarara-1), started commercial operations on February 8, 2014. Located in Sto. Tomas, Batangas, in a region of rapid industrialization and increasing power demand, Maibarara-1 has performed well as a base load power plant in two (2) years of commercial operations. Field operation, though, has not been without challenges. For several days in August and October, the power plant was forced to operate at 50% capacity after the two (2) hot well pumps used to drive the circulating cooling water broke down. MGI engaged the services of Fuji and another third-party contractor, Frontken, to assess and repair the damaged pumps. After completing the repair, the facility resumed normal operations. Despite these technical problems, MGI was able to exceed its 2014 output

GREENING POWER GENERATION 2015 ANNUAL REPORT

by 19%, generating a total of 151,101 MWh for the year 2015. Another notable achievement of MGI was the successful discharge and flow testing of the new production well, MB-15D, which yielded 6MW in capacity. The well’s output, combined with the excess steam from the existing M1 facility, will fuel Maibarara-2 (M2), the 12 MW expansion project which is currently underway. As early as 2nd quarter of 2015, contract negotiations for major equipment, construction, as well as offtake and financing were commenced. The contract for the supply of the 12 MW turbine-generator was awarded to Fuji Electric of Japan in December, 2015. Official approval of debt funding for the M2 project is expected from lender RCBC by early 2016. The 12 MW Maibarara-2 facility is scheduled for commercial operations by 3rd quarter 2017.

ERC’s renewable energy profile was enhanced by the successful commissioning and commercial operation in June 2015 of the 36 MW Nabas Wind Power Project (Nabas-1) in Nabas and Malay towns of Aklan province.

the successful operation and export of power to the Visayas grid from all eighteen (18) WTGs.

The earlier part of 2015 saw PWEI focused on completion of the construction of Nabas-1. On March 24, 2015, PWEI successfully energized and dispatched power from eight (8) Wind Turbine Generators (WTGs) to the Visayas grid, marking the start of the hot commissioning tests of the Nabas wind facility.

On June 16, 2015, the DOE released the Certificate of Endorsement for FIT - eligibility (COE-FIT), confirming the official start of Nabas-1 commercial operation to be June 10, 2015. After conducting its own site validation on June 2425, 2015, the ERC approved PWEI’s Certificate of Compliance (COC-FIT) for Nabas-1 on December 1, 2015. This confirmed the project as eligible to receive FIT payment of PhP 7.40/kWh. The corresponding Renewable Energy Payment Agreement (REPA) with Transco took effect on December 22, 2015.

On April 17, 2015, the DOE issued its “Nomination for FiT Eligibility” for the project. On June 10, 2015, PWEI started

From June 10, 2015 to February 29, 2016, the total energy exported by Nabas-1 to the grid is 69,327 MWh.

PETROENERGY RESOURCES CORPORATION

PERC further diversified its renewable energy

portfolio with its 50 MW Tarlac Solar Power Project (Tarlac-1). PGEC, the holding firm, engaged Syntegra Solar, a German engineering firm, to conduct a pre-feasibility study of the PEZA-registered Central Technopark industrial zone in Tarlac City, Tarlac at the end of 2014. The initial resource assessment yielded positive results that clearly established the area as ideal for solar power development: flat terrain without any obstruction that can cause shadowing, nearby NGCP transmission line for interconnection, existing drainages, concrete roads and water sources which can greatly reduce the construction period. Given those positive findings, PGEC applied and was awarded a Service Contract by the DOE on March 19, 2015. The Tarlac-1 was eventually assigned to PetroSolar

GREENING POWER GENERATION 2015 ANNUAL REPORT

Corporation (PSC) which is 56% owned by PGEC and 44% by EEI Power Corporation. Given the March 15, 2016 deadline set by the DOE for qualification to the 500 MW solar allocation with FIT rate of PhP8.69/kWh, PSC set its sight on completing the solar farm and connection to the grid before this deadline. Following the Service Contract award in March 2015, development started with the application for government permits, such as Environmental Compliance Certificate (ECC) from Department of Environment and Natural Resources (DENR), Certificate of Non-Coverage from National Commission on Indigenous Peoples (NCIP), Philippine Economic Zone Authority (PEZA) construction permits and Local Government Unit endorsements.

Lease Agreements from the lot owners of the transmission line connections were also secured. Contracts for the site clearing (Media Construction), supply of major solar farm equipment (Conergy Inc.), construction of the solar farm (Phesco) and transmission facilities (Philcantech) were finalized by June 2015. As soon as the ECC was released in August 2015 and DOE declared the field’s commerciality, civil works went full blast. By mid-December 2015, the solar farm and transmission facilities were 80% and 100% completed, respectively, prompting the DOE to nominate the Tarlac-1 to be FIT-eligible. The solar farm was completed by mid-January 2016 and was able to export power to the grid

on January 27, 2016. The DOE eventually gave its Certificate of Endorsement (COE) – FIT for Tarlac-1 with Commercial Operations Date of February 10, 2016. ERC is processing the project’s Certificate of Compliance (COC) - FIT. Meanwhile, the ERC issued on April 27, 2016, the Provisional Authority to Operate as a FIT-eligible plant, which will enable PSC to bill TRANSCO for its generation based on the FIT rate of PhP8.69/kWh. On May 10, 2016, the REPA between PSC and TRANSCO took effect.

PETROENERGY RESOURCES CORPORATION

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

Sustaining communities through LIVELIHOOD projects Two years after PERC re-introduced its Corporate Social Responsibility (CSR) campaign - We Power H.E.L.P. (Health, Education, & Livelihood Program) - our commitment and works to uplift our host community have widened and deepened.

Ensuring Access to HEALTH Services Our subsidiary MGI donated a community health center to the residents of Sitio Capuz in Brgy. San Rafael, Sto. Tomas, Batangas. Since the center’s operation in December 2015, it has catered to almost 200 residents who availed of medical consultation in coordination with Sto. Tomas Municipal Health Office and medicines provided by MGI.

Improving the Delivery of EDUCATION PERC’s pioneering Teachers’ Training Program has already benefited 16 public high schools and 480 public school teachers in Palawan, Batangas, and Aklan, since it was launched in 2008. The comprehensive trainings were conducted in cooperation with the Department of Education (DepEd) and PERC’s affiliate Mapua school, the Malayan Colleges Laguna (MCL). The latest installment of the program was concluded in April 2015 with 102 public teachers from Nabas, Aklan completing a three-year competency building aimed at improving classroom management and techniques in teaching English, Science, and Mathematics.

A pilot livelihood program in Nabas, Aklan being implemented by PWEI, has significantly advanced after 2 years since its launch in 2013.

Medical and dental missions are continuing the service to residents from Puting Lupa, Calamba City and Sitio Capuz, San Rafael, Sto. Tomas Batangas. MGI partners with the Daniel Mercado Medical Center of Sto. Tomas for these medical activities. In Tarlac, PERC extended its health assistance by donating an ambulance to the City Government of Tarlac, through PetroSolar Corporation. The donation is aimed at helping the City health officers provide faster emergency medical services to far-flung residents.

at MCL will be completing the program in 4th quarter of 2016 and two (2) Civil Engineer Scholars will graduate in May 2016. In November 2015, PERC also turned-over to the Parents-Teachers Association (PTA) of Tarlac’s Lourdes and Balete Elementary Schools, monetary assistance to partially fund school improvements and students’ expenses of 432 pupils from Grades 4 to 6. The funds are allocated to support the students’ sports activities, solid waste management and environmental projects, as well as necessary improvements of school facilities.

The Pawa Agri-Ecotourism and Livelihood Development Association (PAELDA) composed of Brgy. Pawa residents in Nabas was formally organized to benefit from these livelihood projects. By end-2015, the group had undergone eight (8) trainings on the following topics: social preparation, team development, setting-up a formal organization, managing a community-based enterprise, and specialized trainings on backyard industries and on craft-making using indigenous materials. PERC also assists its host communities improve their access to basic necessities or enhance

communal welfare. In 2015, MGI funded the installation of 15 solar street lights in Barangay Puting Lupa, Calamba City, Laguna, to help ensure the safety and security of the community. In parallel, PWEI supported electric cooperative AKELCO and local and national agencies in the electrification project for Brgy. Pawa in Nabas, Aklan. As of December 2015, all the 73 distribution line poles have been delivered on site and pole staking have commenced. The electrification project is expected to be completed in March 2016, to light up all 80 households in Brgy. Pawa.

As part of its Student Assistance Program, PERC continues to support 13 scholars from Palawan and Aklan. Among the 11 scholars of Engineering courses, two (2) are now working with foreign companies. Two (2) scholars taking up Diploma in Culinary Arts 22

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

PROMOTING A CULTURE OF SAFETY MGI and PWEI safety teams have once again received the 2015 SHAPES-DOE Safety Awards in December, 2015. Both were awarded with the 2015 Corporate Safety and Health Excellence Award with their respective safety officers receiving the 2015 Outstanding Safety and Health Professional Award. These awards are conferred on companies and professionals who have put in place effectivesafety and health programs, have not incurred lost-time accidents, and no outstanding safety violations.

UNDERTAKING ENVIRONMENTAL PROTECTION PERC, is committed to environment-friendly practices in its operations and activities. In celebration of Environment Month in July 2015, the staff organized and participated in tree planting activities in Batangas, Aklan, and Tarlac. A total of 1,200 seedlings of fruit-bearingand native trees were planted on selected sites identified by MGI, PWEI, and PSC in coordination with the Department of Environment & Natural Resources (DENR). PWEI also conducted a coastal clean-up along the shores of Brgy. Gibon in Nabas and in Boracay Island. 24

GREENING POWER GENERATION 2015 ANNUAL REPORT

In addition to 500 trees being maintained by MGI, 500 fire trees were planted along the boundaries of Makiling Forest Reserve (MFR). The activity is part of MGI’s collaboration with the University of the Philippines Los Banos’ reforestation efforts in Mt. Makiling. PWEI has intensified its site rehabilitation program geared towards the restoration and re-greening of the impacted areas in the Nabas wind farm. Several measures such as benching & compaction, installation of coco fiber and wire mesh and gabions, revegetation, and continuous tree-plating are put in place by PWEI in consultation with a slope stabilization expert, Ground Specialists Inc. (GSI).

BUIlding human capital For more than 25 years, PERC has cultivated a culture of excellence, sense of project ownership, and holistic development among its lean staff. Our human resource is recognized as a core asset, invaluable in the Company’s growth and success. PERC geologists were sent to trainings in advanced basin analysis and petroleum exploration and production in Malaysia and Indonesia in 2014. Two MGI staff also completed the Geothermal Energy Technology Post Graduate Certificate from the University of Auckland in New Zealand in 2014 and 2015.

In April 2015, MGI Managers Pete G. Callos and Paul Elmer C. Morala shared their expertise before the 2015 World Geothermal Congress participants in Melbourne, Australia with the presentation of a paper on the Challenges in the Design and Management of 20-MW Geothermal Field; the Maibarara Experience. And in November 2014, a four-man team composed of PWEI’s engineers, completed the T-1 Certification Program for Wind Turbine Generator Field Technicians, at Gamesa’s Head Office in Spain. PETROENERGY RESOURCES CORPORATION

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PETROENERGY RESOURCES CORPORATION

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 14, 2015, valid until December 31, 2018 SEC Accreditation No. 0012-FR-4 (Group A), November 10, 2015, valid until November 9, 2018

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 its subsidiaries (the Group), which comprise the consolidated statements of financial position as at December 31, 2015 and 2014, 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, 2015, 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.

*SGVFS016036* 28

A member firm of Ernst & Young Global Limited

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(In U.S. Dollars)

-2Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of PetroEnergy Resources Corporation and its subsidiaries as at December 31, 2015 and 2014, and their financial performance and their cash flows for each of the three years in the period ended December 31, 2015 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 the 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 Partner CPA Certificate No. 89336 SEC Accreditation No. 0664-AR-2 (Group A), March 26, 2014, valid until March 25, 2017 Tax Identification No. 160-302-865 BIR Accreditation No. 08-001998-73-2015, February 27, 2015, valid until February 26, 2018 PTR No. 5321688, January 4, 2016, Makati City

December 31 2014 2015 ASSETS Current Assets Cash and cash equivalents (Notes 6 and 29) Short-term investments (Notes 6 and 29) Financial assets at fair value through profit or loss (Notes 7 and 29) Receivables (Notes 5, 8 and 29) Crude oil inventory (Note 2) Prepaid expenses and other current assets (Note 9) Total Current Assets Noncurrent Assets Property, plant and equipment (Notes 5, 10 and 19) Deferred oil exploration costs (Notes 5 and 11) Investment in a joint venture (Notes 2 and 12) Investment properties (Notes 5 and 13) Deferred tax assets - net (Notes 5 and 23) Other noncurrent assets (Note 15) Total Noncurrent Assets

−

$2,818,154 186,513

156,231 3,591,873 96,501 6,317,192 42,698,402

163,052 3,571,608 419,142 2,687,696 9,846,165

140,724,197 15,919,839 27,166,952 31,417 306,910 10,282,823 194,432,138 $237,130,540

79,784,366 19,112,571 27,630,596 31,417 202,036 5,440,355 132,201,341 $142,047,506

$18,795,721 16,539,074

$5,141,956 16,679,150 477

$32,536,605

LIABILITIES AND EQUITY Current Liabilities Accounts payable and accrued expenses (Notes 16, 21 and 29) Current portion of loans payable (Notes 17, 20 and 29) Income tax payable (Note 23) Deposits for future stock subscriptions (Note 18) Total Current Liabilities

February 19, 2016

Noncurrent Liabilities Loans payable - net of current portion (Notes 9, 17, 21 and 29) Asset retirement obligation (Notes 5, 19 and 21) Derivative liability (Notes 20 and 29) Accrued retirement liability (Notes 5, 21 and 22) Deferred tax liabilities (Notes 5 and 23) Other noncurrent liability Total Noncurrent Liabilities Total Liabilities

‒

6,557,228 41,892,023 99,171,368 1,094,672 10,855,986 66,019 1,624,496 48,406 112,860,947 154,752,970

‒

21,821,583 44,969,915 608,542 10,677,196 69,374 5,128,494 ‒

61,453,521 83,275,104

(Forward)

*SGVFS016036* 30

*SGVFS016036*

A member firm of Ernst & Young Global Limited

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME

-2December 31 2014 2015 Equity Attributable to equity holders of the Parent Company Capital stock (Note 21) Additional paid-in capital (Note 21) Retained earnings Appropriated (Note 21) Unappropriated (Note 21) Remeasurements of net accrued retirement liability (Notes 21 and 22) Cumulative translation adjustment (Notes 5 and 21) Equity reserve (Note 21) Noncontrolling interests (Notes 21 and 32) Total Equity

$9,391,311 35,620,588

$6,321,533 25,244,737

3,149,555 18,899,873

3,149,555 16,219,666

(36,227) (2,548,828) 1,859,173 66,335,445 16,042,125 82,377,570 $237,130,540

(38,406) (804,317) − 50,092,768 8,679,634 58,772,402 $142,047,506

See accompanying Notes to Consolidated Financial Statements.

(In U.S. Dollars)

Years Ended December 31 2014 2015 REVENUES Oil revenues Electricity sales (Note 34) COST OF SALES Oil production (Note 24) Depletion (Note 10) Cost of electricity sales (Note 25) GROSS INCOME GENERAL AND ADMINISTRATIVE EXPENSES (Note 26) OTHER INCOME (CHARGES) - net Share in net income (loss) of a joint venture (Note 12) Interest income (Note 6) Net gain on fair value changes on financial assets at fair value through profit or loss (Note 7) Accretion expense (Note 19) Net foreign exchange loss Interest expense (Note 17) Miscellaneous income (Note 27)

GAINS (LOSSSES) ON SALE OF INVESTMENT IN A SUBSIDIARY (Notes 12 and 20): Unrealized gain on remeasurement of investment Gain on sale of investment in a subsidiary Share in deconsolidated retained earnings of a subsidiary Net unrealized loss on derivatives

2013

$6,574,675 16,967,907 23,542,582

$11,132,670 14,741,614 25,874,284

$13,717,422 ‒ 13,717,422

4,239,457 1,681,618 7,113,087 13,034,162

5,132,328 1,405,642 6,064,893 12,602,863

5,163,930 1,448,670 ‒ 6,612,600

10,508,420

13,271,421

7,104,822

3,911,082

3,276,903

3,683,822

241,481 112,537

(242,562) 70,633

1,392 (140,635) (178,876) (4,934,680) 211,638 (4,687,143)

26,128 (50,900) (93,661) (4,524,186) 243,237 (4,571,311)

1,910,195

5,423,207

‒ ‒ ‒ (734,060) (734,060)

17,220,295 2,665,174 1,166,830 (10,755,464) 10,296,835

‒ 202,431 7,456 (44,070) (189,072) (117,524) 6,761 (134,018) 3,286,982

‒ ‒ ‒ ‒ ‒

1,176,135

15,720,042

3,286,982

PROVISION FOR (BENEFIT FROM) INCOME TAX (Note 23)

(3,432,935)

5,968,772

1,763,572

NET INCOME (Note 30)

$4,609,070

$9,751,270

$1,523,410

NET INCOME ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 32)

$2,680,207 1,928,863

$8,489,385 1,261,885

$2,211,220 (687,810)

NET INCOME

$4,609,070

$9,751,270

$1,523,410

$0.008

$0.031

$0.008

INCOME BEFORE INCOME TAX

EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF THE PARENT COMPANY - BASIC AND DILUTED (Note 31) See accompanying Notes to Consolidated Financial Statements.

*SGVFS016036* 32

GREENING POWER GENERATION 2015 ANNUAL REPORT

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

(In U.S. Dollars)

TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 32)

34 GREENING POWER GENERATION 2015 ANNUAL REPORT

316,458 (1,899,147)

2,179 9,157 (41,856)

$2,326,584 $10,076,885 ($417,593)

$937,875 1,388,709 $2,326,584 $8,815,000 1,261,885 $10,076,885 $270,217 (687,810) ($417,593)

See accompanying Notes to Consolidated Financial Statements.

(Forward)

$25,244,737 − − − − − − $25,244,737

− − − − − $6,321,533

− $35,620,588

− $9,391,311

$6,321,533 −

− − − 10,375,851 −

− − − 3,069,778 −

− $3,149,555

− − − −

$3,149,555 −

− $3,149,555

− − − − −

$3,149,555 −

− ($36,227)

2,179 − 2,179 − −

($38,406) −

− $16,219,666

− − 8,489,385 −

$7,730,281 8,489,385

−

− ($38,406)

9,157

($47,563) −

For the Year Ended December 31, 2014

− $18,899,873

− − 2,680,207 − −

$16,219,666 2,680,207

− ($804,317)

− 316,458 316,458 −

($1,120,775) −

− ($2,548,828)

− (1,744,511) (1,744,511) − −

($804,317) −

− $−

− − − −

$− −

− $1,859,173

− − − 1,859,173

$− − −

181,030 $8,679,634

− − 1,261,885 (2,439,757)

$9,676,476 1,261,885

3,163,342 $16,042,125

− (540,154) 1,388,709 − 2,810,440

$8,679,634 1,928,863

181,030 $58,772,402

9,157 316,458 10,076,885 (2,439,757)

$50,954,244 9,751,270

3,163,342 $82,377,570

2,179 (2,284,665) 2,326,584 13,445,629 4,669,613

$58,772,402 4,609,070

Total

*SGVFS016036*

− $50,092,768

9,157 316,458 8,815,000 −

$41,277,768 8,489,385

− $66,335,445

2,179 (1,744,511) 937,875 13,445,629 1,859,173

$50,092,768 2,680,207

Total

Noncontrolling Interests (Note 32)

(In U.S. Dollars)

Balances at beginning of year Net income Remeasurement loss on net accrued retirement liability (Note 22) Movement in cumulative translation adjustment Total comprehensive income (loss) NCI attributed to the deconsolidated subsidiary Increase in noncontrolling interests - stock issuances (Note 32) Balances at end of year

$25,244,737 −

$6,321,533 −

For the Year Ended December 31, 2015

$1,523,410

Balances at beginning of year Net income Remeasurement loss on net accrued retirement liability (Note 22) Movement in cumulative translation adjustment Total comprehensive income (loss) Issuance of stocks Change in ownership without loss of control (Note 21) Increase in noncontrolling interests - stock issuances (Note 32) Balances at end of year

OTHER COMPREHENSIVE INCOME (LOSS)

Appropriated Retained Earnings (Note 21)

TOTAL COMPREHENSIVE INCOME (LOSS) (2,284,665)

$9,751,270

Additional Paid-in Capital (Note 21)

Item to be reclassified to profit or loss in subsequent periods Movements in cumulative translation adjustment Item not to be reclassified to profit or loss in subsequent periods Remeasurement gains (losses) on net accrued retirement liability - net of tax (Note 22) $4,609,070

Capital Stock (Note 21)

NET INCOME 2013

Attributable to Equity Holders of the Parent Company Remeasurement Unappropriated of Net Accrued Cumulative Retained Retirement Translation Earnings Liability Adjustment Equity Reserve (Note 21) (Note 22) (Note 5) (Note 21)

Years Ended December 31 2014 2015

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

*SGVFS016036*

$5,807,379 (687,810) − − (687,810) 4,556,907 − − $9,676,476

$47,130,178 1,523,410 (41,856) (1,899,147) (417,593) 4,556,907 − (315,248) $50,954,244

Total

($5,707) − (41,856) − (41,856) − − − ($47,563) $6,928,309 2,211,220 − − 2,211,220 − (1,094,000) (315,248) $7,730,281 $2,055,555 − − − − − 1,094,000 − $3,149,555 $25,244,737 − − − − − − − $25,244,737 See accompanying Notes to Consolidated Financial Statements.

$6,321,533 − − − − − − − $6,321,533 Balances at beginning of year Net income (loss) Remeasurement loss on net accrued retirement liability (Note 22) Movement in cumulative translation adjustment Total comprehensive income (loss) Increase in noncontrolling interests - stock issuances (Note 32) Appropriation of retained earnings (Note 21) Cash dividends (Note 21) Balances at end of year

For the Year Ended December 31, 2013

(In U.S. Dollars)

Years Ended December 31 2014 2015 CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax Adjustments for: Interest expense Depletion, depreciation and amortization (Notes 10 and 15) Net unrealized loss on derivatives (Notes 20 and 29) Net unrealized foreign exchange loss Accretion expense (Note 19) Net gain on fair value changes on financial assets at fair value through profit or loss (Note 7) Dividend income Interest income (Note 6) Share in net loss (income) of a joint venture (Note 12) Gain on sale of property and equipment (Note 10) Share in deconsolidated retained earnings of a subsidiary (Note 12) Gain on sale of investment in a subsidiary (Note 12) Unrealized gain on remeasurement of investment (Note 12) Operating income before working capital changes Decrease (increase) in: Crude oil inventory Short-term investments Receivables Prepaid expenses and other current assets Increase (decrease) in: Accounts payable and accrued expenses Accrued retirement liability Cash generated from (used in) operations Interest received Income taxes paid Net cash provided by (used in) operating activities

$778,372 − − (1,899,147) (1,899,147) − − − ($1,120,775)

Total

$41,322,799 2,211,220 (41,856) (1,899,147) 270,217 − − (315,248) $41,277,768

Noncontrolling Interests (Note 32) Capital Stock (Note 21)

Additional Paid-in Capital (Note 21)

Attributable to Equity Holders of the Parent Company Remeasurement of Net Accrued Cumulative Unappropriated Appropriated Translation Retained Retirement Retained Adjustment Earnings Liability Earnings (Note 5) (Note 21) (Note 22) (Note 21)

-2-

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of interest in a subsidiary (Note 21) Increase in other noncurrent liabilities Dividends received Decrease (increase) in other noncurrent assets Additional deferred oil exploration costs (Note 11) Acquisitions of property, plant and equipment (Note 10) Additional investment in a joint venture (Note 12) Net cash inflow from deconsolidation of a subsidiary Proceeds from sale of property and equipment Additional capitalized interest (Note 10) Net cash used in investing activities

2013

$1,176,135

$15,720,042

$3,286,982

4,934,680

4,524,186

117,524

4,704,110 734,060 178,876 140,635

4,238,357 10,755,464 93,661 50,900

1,747,985 ‒ 189,072 44,070

(1,392) (1,704) (112,537) (241,481) −

(26,128) (2,059) (70,633) 242,562 (13,192)

(7,456) − (202,431) ‒ −

− −

(1,166,830) (2,665,174)

‒ ‒

− 11,511,382

(17,220,295) 14,460,861

‒ 5,175,746

322,641 186,513 (16,112) (3,694,680)

(200,925) 728,093 (508,217) 2,661,837

196,547 (99,865) (638,492) (12,403,866)

13,782,992 (2,110) 22,090,626 108,384 (40,435) 22,158,575

1,500,287 (33,720) 18,608,216 73,187 (1,501,718) 17,179,685

(1,318,070) (1,432) (9,089,432) 221,020 (1,204,624) (10,073,036)

4,669,613 48,406 1,704 (4,269,732) (5,616,676) (60,378,258) (680,833) − − − (66,225,776)

− − 2,059 1,462,326 (7,715,361) (10,460,030) (5,303,110) 7,871,926 38,480 418,377 (13,685,333)

− − − (2,135,974) (4,754,007) (25,317,818) − − − 3,655,746 (28,552,053)

(Forward)

*SGVFS016036* 36

GREENING POWER GENERATION 2015 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

-2-

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31 2014 2015 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from availment of long-term debt (Note 17) Proceeds from issuance of stocks (Note 21) Proceeds from deposits for future stock subscriptions (Note 18) Additional capital from noncontrolling interest (Note 32) Dividends paid (Note 21) Interest paid Payment of loans Net cash provided by (used in) financing activities

(In U.S. Dollars) 2013

$76,733,682 13,445,629

$2,196,428 −

6,557,228 3,163,342 (535) (5,063,372) (20,000,529) 74,835,445

− 181,030 (2,128) (4,885,084) − (2,509,754)

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

NET EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS

(1,049,793)

(738,012)

(2,100,462)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

29,718,451

246,586

(19,050,654)

2,818,154

2,571,568

21,622,222

$32,536,605

$2,818,154

$2,571,568

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

$20,946,086 −

See accompanying Notes to Consolidated Financial Statements.

1. Corporate Information a.

Organization PetroEnergy Resources Corporation (“PERC”, “PetroEnergy” or the “Company”), formerly Petrotech Consultants, Inc., was organized on September 29, 1994 to provide specialized technical services to its then parent company, Petrofields Corporation, and to companies exploring for oil in the Philippines. In 1997, the Company’s name was formally changed into “PetroEnergy Resources Corporation”, simultaneous with the change in its primary purpose from rendering technical services to oil exploration and development and mining activities. On June 25, 1999, the Department of Energy (DOE) authorized the assumption by the Company of Philippine oil exploration contracts. The Ministry of Energy of Gabon, West Africa had also been duly notified of the transfer to PERC of Petrofields’ Production Sharing Contract covering the Etame discovery block in the Atlantic shelf. On May 23, 2003, the Securities and Exchange Commission (SEC) approved the Company’s application for a decrease in authorized Capital from One Billion (1,000,000,000) common shares at a par value of One Peso (₱1.00) per share to Three Hundred Thirty Million (330,000,000) shares at a par value of One Peso (₱1.00) per share. On July 28, 2004, the Philippine Stock Exchange, Inc. (PSE) approved the Listing by Way of Introduction of the entire issued capital of the Company. On August 4, 2004, the SEC issued to the Company the certificate of permit to offer securities for sale. This certifies that the shares of the Company have been registered and licensed for Listing by Way of Introduction and by then be sold or offered for sale in the Philippines. On August 11, 2004, the Company’s shares were listed at the PSE. On July 22, 2009, the Board of Directors (BOD) and Stockholders approved the amendment of articles of incorporation of the Group to include the business of generating power from conventional sources such as coal, fossil fuel, natural gas, nuclear and other traditional sources of power and from renewable sources such as, but not limited to, biomass, hydro, solar, wind, geothermal, ocean and such other renewable sources of power. The amendment was approved by the Philippine Securities and Exchange Commission (SEC) on September 23, 2009. On February 23, 2010, the BOD Approved a 1:1 Stock Rights Offering (SRO). Under the SRO, the shares were offered at ₱5.00 per share, giving a net proceeds of ₱683.436 million, which was used for the 20MW Phase 1 of the Maibarara power Project (MGPP). The SRO was undertaken during the period June 28, 2010 to July 5, 2010. On December 5, 2014, the BOD approved a 2:1 SRO. The SRO was undertaken during the period May 11 to 15, 2015. The proceeds of the SRO amounted to ₱599.675 million and will be used to partially finance the expansion, construction and development of renewable energy projects, such as the MGPP (Phase 2) and Solar Power Project, as well as the expansion of the Etame Project in Gabon, West Africa.

*SGVFS016036* 38

GREENING POWER GENERATION 2015 ANNUAL REPORT

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

On June 03, 2015, SEC approved the Company’s application for an increase in Authorized Capital from Three Hundred Thirty Million (330,000,000) shares at par value of One Peso (P =1.00) to Seven Hundred Million (700,000,000) shares at par value of One Peso. In order to insulate PetroEnergy’s core oil business from its renewable energy ventures, PetroEnergy, with the approval of the BOD 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% equity share in PetroWind. EEIPC formally became a stockholder of PetroWind upon the SEC’s approval of PetroWind’s increase in authorized capital stock on August 23, 2013. Effectively as of December 31, 2013, PetroGreen held 80% equity share in PetroWind. On November 21, 2013, PetroGreen and CapAsia Asean Holdings Cooperatief U.A. (CapAsia) entered into a Share Purchase Agreement (SPA) which sets out the parties’ mutual agreement as to the sale of 2,375,000 shares in PetroWind held by PetroGreen, which is equivalent to 40% of the total issued and outstanding shares of PetroWind. The purchase price for the sale of shares, as set out in Section 3 of the SPA, shall be $5,337,079 upfront payment and a premium of $2,600,000 which will be paid on a staggered basis. Simultaneously on November 21, 2013, PetroGreen, CapAsia and EEIPC entered into a Shareholders’ Agreement (SA). The SA will govern their relationship as the shareholders of PetroWind as well as containing their respective rights and obligations in relation to PetroWind. Further, the SA contains provisions regarding voting requirements for relevant activities that require unanimous consent of all the parties. PetroGreen, CapAsia and EEIPC agree that their equity ownership ratio in PetroWind are at 40%, 40% and 20%, respectively. Although the SPA and the SA were executed on November 21, 2013, these did not result to PetroGreen’s loss of control over PetroWind in 2013. The loss of control did not happen until February 14, 2014, the Closing Date. On February 14, 2014, the Closing Date, the payment has been received from sale of the shares as executed in the Deed of Assignment covering the transfer of shares from PetroGreen to CapAsia and all the conditions precedent have been satisfactory completed. As such, PetroGreen lost its control over PetroWind while CapAsia was given full voting and economic

*SGVFS016036* 40

GREENING POWER GENERATION 2015 ANNUAL REPORT

rights as a 40% shareholder. The transaction made PetroWind a joint venture between PetroGreen (40%), CapAsia (40%) and EEIPC (20%) by virtue of the SA signed between the three parties governing the manner of managing PetroWind. As of December 31, 2014, MGI is effectively a subsidiary of PetroEnergy through PetroGreen, which is wholly owned by PetroEnergy. PetroGreen owned majority of the voting power of MGI. PetroEnergy, PetroGreen and MGI are collectively referred to as the Group. On June 9, 2015, EEIPC acquired 10% of PetroEnergy’s share in PetroGreen, leaving PetroEnergy with 90% share in PetroGreen (Note 21). On March 19, 2015, PetroGreen was awarded by the DOE with the Solar Energy Service Contract (SESC) No. 2015-03-115 giving it the right and obligation to explore, develop and utilize the solar energy resource within the service contract area located in Tarlac City. By virtue of the Tarlac SESC, PetroGreen commenced the pre-development activities for the 50 MW Tarlac Solar Power Project (TSPP) to be constructed within a 55 hectare property in Cenral technopark, San Miguel, Tarlac City. On June 17, 2015, PetroSolar Corporation (“PetroSolar”) was incorporated. PetroGreen has 56% shareholdings in PetroSolar, while EEIPC owns the remaining 44%. On June 19, 2015, by virtue of the Deed of Assignment and Assumption, PetroGreen transferred its interest in the SESC to PetroSolar. The assignment was approved by the DOE on September 15, 2015. The DOE confirmed the commerciality of the TSPP on September 24, 2015. Construction of the TSPP commenced by the third quarter of 2015 which was completed in January 2016. As of December 31, 2015, MGI and PetroSolar are effectively indirect subsidiaries of PetroEnergy through PetroGreen which is 90% owned by PetroEnergy. PetroGreen owned majority of the voting power of MGI and PetroSolar. PetroEnergy, PetroGreen, MGI and PetroSolar are collectively referred to as the Group. b. Nature of Operations The Group’s four (4) main energy businesses are petroleum, wind, geothermal and solar. 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. Geothermal Energy The geothermal project is the 20-MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas. See Note 10 for updates on the Group’s geothermal energy operations. Wind Energy The wind energy project is the 36-megawatt (MW) NWPP in Nabas, Aklan, where PetroWind has a wind farm. See Notes 10 and 36 for updates on the Group’s wind energy operation.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

Solar Energy The Solar power project is the 50MW Tarlac Solar Power Plant (TSPP) in Tarlac City, Tarlac. See Note 10 for updates on the Group’s solar energy operations. The accompanying consolidated financial statements were approved and authorized for issue by the BOD on February 19, 2016. 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), derivative liability and 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. 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, 2015 and 2014. The financial statements of the subsidiaries are prepared for the same reporting year as the Group, using consistent accounting policies. Below are the Group’s subsidiaries with its respective percentage ownership as of December 31, 2015, 2014 and 2013:

PetroGreen Percentage share of PetroGreen to its subsidiaries MGI PetroSolar PetroWind Navy Road Development Corporation (NRDC)

Percentage of Ownership 2014 2013 2015 100% 100% 90%1 65% 56% 40% 100%

65% – 40%2 100%

65% – 80% 100%

As a result of the sale of 10% stake in PGEC, consolidated PERC’s ultimate share in MGI and PetroSolar’s retained earnings and income is reduced by 10% as of and for the year ended December 31, 2015.

As a result of the loss of control on February 14, 2014, PetroWind became a joint venture between PetroGreen, CapAsia and EEIPC. PetroGreen has control over PetroSolar, since PetroGreen is largely involved in the key decisions concerning the financial and operating policies, activities and provision of technological support and technical know-how to PetroSolar. 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

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GREENING POWER GENERATION 2015 ANNUAL REPORT

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. On February 14, 2014, the Group disposed its investment in PetroWind and its interest of 80% was reduced to 40% where it lost its control over PetroWind. As of and for the year ended December 31, 2014, PetroWind has been deconsolidated. The 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 loss of control, is accounted for as an equity transaction, as transactions with the owners in their capacity as owners. For purchases from non-controlling interests, the difference between any consideration paid and the relevant share acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recorded in equity. If the Group loses control over a subsidiary, it: · · ·

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’s share of components previously recognized in OCI to the

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

consolidated statement of income or retained earnings, as appropriate.

This policy is in accordance with PFRS 10, Consolidated Financial Statements.

•

3. Changes in Accounting Policies The Group adopted the following new and amended PFRS, Philippine Accounting Standards (PAS) and Philippine Interpretations that became effective beginning January 1, 2015 in the accompanying consolidated financial statements. Except as otherwise indicated, the adoption of the new and amended PFRS, PAS and Philippine Interpretations did not have any effect on the consolidated financial statements of the Group. ·

PAS 19, Employee Benefits - Defined Benefit Plans: Employee Contributions PAS 19 requires an entity to consider contributions from employees or third parties when accounting for defined benefit plans. Where the contributions are linked to service, they should be attributed to periods of service as a negative benefit. These amendments clarify that, if the amount of the contributions is independent of the number of years of service, an entity is permitted to recognize such contributions as a reduction in the service cost in the period in which the service is rendered, instead of allocating the contributions to the periods of service. The amendments had no impact on the Group’s consolidated financial position or performance.

Annual Improvements to PFRSs (2010-2012 cycle) The Annual Improvements to PFRSs (2010-2012 cycle) became effective for annual periods beginning on or after January 1, 2015 and did not have a material impact on the Group. ·

PFRS 2, Share-based Payment - Definition of Vesting Condition This improvement is applied prospectively and clarifies various issues relating to the definitions of performance and service conditions which are vesting conditions, including: • • • • •

A performance condition must contain a service condition A performance target must be met while the counterparty is rendering service A performance target may relate to the operations or activities of an entity, or to those of another entity in the same group A performance condition may be a market or non-market condition If the counterparty, regardless of the reason, ceases to provide service during the vesting period, the service condition is not satisfied.

•

PFRS 3, Business Combinations - Accounting for Contingent Consideration in a Business Combination The amendment is applied prospectively for business combinations for which the acquisition date is on or after July 1, 2014. It clarifies that a 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, Financial Instruments: Recognition and Measurement (or PFRS 9, Financial Instruments, if early adopted). The Group shall consider this amendment for future business combinations.

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GREENING POWER GENERATION 2015 ANNUAL REPORT

An entity must disclose the judgments made by management in applying the aggregation criteria in the standard, including a brief description of operating segments that have been aggregated and the economic characteristics (e.g., sales and gross margins) used to assess whether the segments are ‘similar’. The reconciliation of segment assets to total assets is only required to be disclosed if the reconciliation is reported to the chief operating decision maker, similar to the required disclosure for segment liabilities.

The amendments affect disclosures only and had no impact on the Group’s consolidated financial position or performance. ·

PAS 16, Property, Plant and Equipment - Revaluation Method - Proportionate Restatement of Accumulated Depreciation The amendment is applied retrospectively and clarifies in PAS 16 and PAS 38 that the asset may be revalued by reference to the observable data on either the gross or the net carrying amount. In addition, the accumulated depreciation or amortization is the difference between the gross and carrying amounts of the asset. The amendment had no impact on the Group’s consolidated financial position or performance.

PAS 24, Related Party Disclosures - Key Management Personnel The amendment is applied retrospectively and clarifies that a management entity, which is an entity that provides key management personnel services, is a related party subject to the related party disclosures. In addition, an entity that uses a management entity is required to disclose the expenses incurred for management services. The amendments affect disclosures only and had no impact on the Group’s consolidated financial position or performance.

Annual Improvements to PFRSs (2011-2013 cycle) The Annual Improvements to PFRSs (2010-2012 cycle) became effective for annual periods beginning on or after January 1, 2015 and did not have a material impact on the Group. ·

PFRS 3, Business Combinations - Scope Exceptions for Joint Arrangements The amendment is applied prospectively and clarifies the following regarding the scope exceptions within PFRS 3: • Joint arrangements, not just joint ventures, are outside the scope of PFRS 3. • This scope exception applies only to the accounting in the financial statements of the joint arrangement itself.

This amendment does not apply to the Group as it has no share-based payments. ·

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 are applied retrospectively and clarify that:

The amendment had no impact on the Group’s consolidated financial position or performance. ·

PFRS 13, Fair Value Measurement - Portfolio Exception The amendment is applied prospectively and clarifies that the portfolio exception in PFRS 13 can be applied not only to financial assets and financial liabilities, but also to other contracts within the scope of PAS 39. The amendment had no significant impact on the Group’s consolidated financial position or performance.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

PAS 40, Investment Property The amendment is applied prospectively and clarifies that PFRS 3, and not the description of ancillary services in PAS 40, is used to determine if the transaction is the purchase of an asset or business combination. The description of ancillary services in PAS 40 only differentiates between investment property and owner-occupied property (i.e., property, plant and equipment). The amendment had no significant impact on the Group’s consolidated financial position or performance.

apply this method from the date of transition to PFRS. These amendments are not expected to have any impact to the Group. ·

Standards Issued but not yet Effective The standards and interpretations that are issued, but not yet effective, up to date of issuance of the Group’s consolidated financial statements are disclosed below. The Group intends to adopt these standards, if applicable, when they become effective. Deferred Effectivity Philippine Interpretation IFRIC 15, Agreements for the Construction of Real Estate This interpretation covers accounting for revenue and associated expenses by entities that undertake the construction of real estate directly or through subcontractors. The interpretation requires that revenue on construction of real estate be recognized only upon completion, except when such contract qualifies as construction contract to be accounted for under PAS 11 or involves rendering of services, in which case, revenue is recognized based on stage of completion. Contracts involving provision of services with the construction materials and where the risks and reward of ownership are transferred to the buyer on a continuous basis will also be accounted for based on stage of completion. The SEC and the Financial Reporting Standards Council have deferred the effectivity of this interpretation until the final Revenue standard is issued by the International Accounting Standards Board (IASB) 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.

The amendments apply to both the acquisition of the initial interest in a joint operation and the acquisition of any additional interests in the same joint operation and are prospectively effective for annual periods beginning on or after January 1, 2016, with early adoption permitted. These amendments are not expected to have any impact to the Group. ·

· · ·

PFRS 10, Consolidated Financial Statements and PAS 28, Investments in Associates and Joint Ventures - Sale or Contribution of Assets between an Investor and its Associate or Joint Venture These amendments address an acknowledged inconsistency between the requirements in PFRS 10 and those in PAS 28 (2011) in dealing with the sale or contribution of assets between an investor and its associate or joint venture. The amendments require that a full gain or loss is recognized when a transaction involves a business (whether it is housed in a subsidiary or not). A partial gain or loss is recognized when a transaction involves assets that do not constitute a business, even if these assets are housed in a subsidiary. These amendments are effective from annual periods beginning on or after January 1, 2016. The amendment will have no significant impact on the Group’s consolidated financial position or performance. PAS 27, Separate Financial Statements - Equity Method in Separate Financial Statements (Amendments) The amendments will allow entities to use the equity method to account for investments in subsidiaries, joint ventures and associates in their separate financial statements. Entities already applying PFRS and electing to change to the equity method in its separate financial statements will have to apply that change retrospectively. For first-time adopters of PFRS electing to use the equity method in its separate financial statements, they will be required to

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PAS 1, Presentation of Financial Statements - Disclosure Initiative (Amendments) The amendments are intended to assist entities in applying judgment when meeting the presentation and disclosure requirements in PFRS. They clarify the following: ·

Effective January 1, 2016 ·

PFRS 11, Joint Arrangements - Accounting for Acquisitions of Interests in Joint Operations (Amendments) The amendments to PFRS 11 require that a joint operator accounting for the acquisition of an interest in a joint operation, in which the activity of the joint operation constitutes a business must apply the relevant PFRS 3 principles for business combinations accounting. The amendments also clarify that a previously held interest in a joint operation is not remeasured on the acquisition of an additional interest in the same joint operation while joint control is retained. In addition, a scope exclusion has been added to PFRS 11 to specify that the amendments do not apply when the parties sharing joint control, including the reporting entity, are under common control of the same ultimate controlling party.

That entities shall not reduce the understandability of their financial statements by either obscuring material information with immaterial information; or aggregating material items that have different natures or functions. That specific line items in the statement of income and Other Comprehensive Income (OCI) and the statement of financial position may be disaggregated. That entities have flexibility as to the order in which they present the notes to financial statements. That the share of OCI of associates and joint ventures accounted for using the equity method must be presented in aggregate as a single line item, and classified between those items that will or will not be subsequently reclassified to profit or loss.

Early application is permitted and entities do not need to disclose that fact as the amendments are considered to be clarifications that do not affect an entity’s accounting policies or accounting estimates. The Group is currently assessing the impact of these amendments on its consolidated financial statements. ·

PFRS 14, Regulatory Deferral Accounts PFRS 14 is an optional standard that allows an entity, whose activities are subject to rateregulation, to continue applying most of its existing accounting policies for regulatory deferral account balances upon its first-time adoption of PFRS. Entities that adopt PFRS 14 must present the regulatory deferral accounts as separate line items on the statement of consolidated financial position and present movements in these account balances as separate line items in the statement of profit or loss and other comprehensive income. The standard requires disclosures on the nature of, and risks associated with, the entity’s rate-regulation and the effects of that rate-regulation on its financial statements. PFRS 14 is effective for annual periods beginning on or after January 1, 2016. Since the Group is an existing PFRS preparer, this standard would not apply.

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PAS 16, Property, Plant and Equipment, and PAS 38, Intangible Assets - Clarification of Acceptable Methods of Depreciation and Amortization (Amendments) The amendments clarify the principle in PAS 16 and PAS 38 that revenue reflects a pattern of economic benefits that are generated from operating a business (of which the asset is part) rather than the economic benefits that are consumed through use of the asset. As a result, a revenue-based method cannot be used to depreciate property, plant and equipment and may only be used in very limited circumstances to amortize intangible assets. The amendments are effective prospectively for annual periods beginning on or after January 1, 2016, with early adoption permitted. The amendment will have no significant impact on the Group’s consolidated financial position or performance. PAS 16, Property, Plant and Equipment, and PAS 41, Agriculture - Bearer Plants (Amendments) The amendments change the accounting requirements for biological assets that meet the definition of bearer plants. Under the amendments, biological assets that meet the definition of bearer plants will no longer be within the scope of PAS 41. Instead, PAS 16 will apply. After initial recognition, bearer plants will be measured under PAS 16 at accumulated cost (before maturity) and using either the cost model or revaluation model (after maturity). The amendments also require that produce that grows on bearer plants will remain in the scope of PAS 41 measured at fair value less costs to sell. For government grants related to bearer plants, PAS 20, Accounting for Government Grants and Disclosure of Government Assistance, will apply. The amendments are retrospectively effective for annual periods beginning on or after January 1, 2016, with early adoption permitted. The amendment will have no significant impact on the Group’s consolidated financial position or performance.

PFRS 7 - Applicability of the Amendments to PFRS 7 to Condensed Interim Financial Statements This amendment is applied retrospectively and clarifies that the disclosures on offsetting of financial assets and financial liabilities are not required in the condensed interim financial report unless they provide a significant update to the information reported in the most recent annual report. The amendment will have no significant impact on the Group’s consolidated financial position or performance.

PAS 19, Employee Benefits - regional market issue regarding discount rate This amendment is applied prospectively and clarifies that market depth of high quality corporate bonds is assessed based on the currency in which the obligation is denominated, rather than the country where the obligation is located. When there is no deep market for high quality corporate bonds in that currency, government bond rates must be used. The amendment will have no significant impact on the Group’s consolidated financial position or performance.

Effective January 1, 2018 ·

Annual Improvements to PFRSs (2012-2014 cycle) The Annual Improvements to PFRSs (2012-2014 cycle) are effective for annual periods beginning on or after January 1, 2016 and are not expected to have a material impact on the Group. ·

PFRS 5, Non-current Assets Held for Sale and Discontinued Operations - Changes in Methods of Disposal The amendment is applied prospectively and clarifies that changing from a disposal through sale to a disposal through distribution to owners and vice-versa should not be considered to be a new plan of disposal, rather it is a continuation of the original plan. There is, therefore, no interruption of the application of the requirements in PFRS 5. The amendment also clarifies that changing the disposal method does not change the date of classification. The amendment will have no significant impact on the Group’s consolidated financial position or performance. PFRS 7, Financial Instruments: Disclosures - Servicing Contracts PFRS 7 requires an entity to provide disclosures for any continuing involvement in a transferred asset that is derecognized in its entirety. The amendment clarifies that a servicing contract that includes a fee can constitute continuing involvement in a financial asset. An entity must assess the nature of the fee and arrangement against the guidance in PFRS 7 in order to assess whether the disclosures are required. The amendment is to be applied such that the assessment of which servicing contracts constitute continuing involvement will need to be done retrospectively. However, comparative disclosures are not required to be provided for any period beginning before the annual period in which the entity first applies the amendments. The amendment will have no significant impact on the Group’s consolidated financial position or performance.

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GREENING POWER GENERATION 2015 ANNUAL REPORT

PFRS 9, Financial Instruments In July 2014, the final version of PFRS 9, Financial Instruments, was issued. PFRS 9 reflects all phases of the financial instruments project and replaces PAS 39, Financial Instruments: Recognition and Measurement, and all previous versions of PFRS 9. The standard introduces new requirements for classification and measurement, impairment, and hedge accounting. PFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early application permitted. Retrospective application is required, but comparative information is not compulsory. Early application of previous versions of PFRS 9 is permitted if the date of initial application is before February 1, 2015. The adoption of PFRS 9 will have an effect on the classification and measurement of the Group’s financial assets and impairment methodology for financial assets, but will have no impact on the classification and measurement of the Group’s financial liabilities.

The following new standard issued by the IASB has not yet been adopted by the FRSC ·

IFRS 15, Revenue from Contracts with Customers IFRS 15 was issued in May 2014 and establishes a new five-step model that will apply to revenue arising from contracts with customers. Under IFRS 15 revenue is recognized at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer. The principles in IFRS 15 provide a more structured approach to measuring and recognizing revenue. The new revenue standard is applicable to all entities and will supersede all current revenue recognition requirements under IFRS. Either a full or modified retrospective application is required for annual periods beginning on or after January 1, 2018 with early adoption permitted. The Group is currently assessing the impact of IFRS 15 and plans to adopt the new standard on the required effective date once adopted locally.

IFRS 16, Leases On January 13, 2016, the IASB issued its new standard, IFRS 16, Leases, which replaces IAS 17, the current leases standard, and the related Interpretations.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

Under the new standard, lessees will no longer classify their leases as either operating or finance leases in accordance with IAS 17. Rather, lessees will apply the single-asset model. Under this model, lessees will recognize the assets and related liabilities for most leases on their balance sheets, and subsequently, will depreciate the lease assets and recognize interest on the lease liabilities in their profit or loss. Leases with a term of 12 months or less or for which the underlying asset is of low value are exempted from these requirements. The accounting by lessors is substantially unchanged as the new standard carries forward the principles of lessor accounting under IAS 17. Lessors, however, will be required to disclose more information in their financial statements, particularly on the risk exposure to residual value. The new standard is effective for annual periods beginning on or after January 1, 2019. Entities may early adopt IFRS 16 but only if they have also adopted IFRS 15. When adopting IFRS 16, an entity is permitted to use either a full retrospective or a modified retrospective approach, with options to use certain transition reliefs. The Group is currently assessing the impact of IFRS 16 and plans to adopt the new standard on the required effective date once adopted locally. 4. 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 revenue can be reliably measured regardless of when the payment is being made. Revenue is measured at the fair value of the considerations received or receivable, taking into account contractually defined terms of payment and excluding taxes or duty. 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 since it is the primary obligor in all the revenue arrangements , has pricing latitude and is also exposed to inventory and credit risks. The specific recognition criteria described below must also be met before revenue is recognized. Oil Revenue Revenue from oil wells is recognized as income at the time of production. Revenue is measured at the fair value of the consideration received. Electricity Sales Sale of electricity using geothermal energy is consummated whenever the electricity generated by the Group is transmitted through the transmission line designated by the buyer, for a consideration. Rent Income Rent income is accounted on a straight-line basis over the lease term. Interest Income Interest income is recognized as the interest accrues taking into account the effective yield on the asset. Gain on Sale of Investment in a Subsidiary The gain on sale of investment in a subsidiary is recognized when it meets the derecognition principle and any gain or loss on disposal is recognized in the consolidated statement of income.

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Miscellaneous Income Miscellaneous income includes time writing charges, 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. Short-term Investments Short-term investments are short-term placements with maturities of more than three months but less than one year from the date of acquisition. These earn interest at the respective short-term investment rates. 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. 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:

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

· ·

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: · · ·

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 re-assessing 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.

· · ·

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 (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 “Other income”. The derivative is carried as asset when the fair value is positive and as liability when the fair value is negative. As of December 31, 2015 and 2014, the Group has a free-standing derivative arising from call and put options under the shareholders’ agreement (Note 20). The Group recognized a derivative liability amounting to $10.86 million and $10.68 million as of December 31, 2015 and 2014, respectively. The net unrealized loss on derivatives recognized in the consolidated statement of income amounted to $0.73 million and $10.76 million for the years ended December 31, 2015 and 2014, respectively (Note 20).

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.

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:

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 (Notes 6, 8, 9, 15, and 29).

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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:

GREENING POWER GENERATION 2015 ANNUAL REPORT

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.

The Group assesses whether embedded derivatives are required to be separated from host

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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 Group’s consolidated statement of income. As of December 31, 2015 and 2014, 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.

Classification of Financial Instruments between Debt and Equity A financial instrument is classified as debt, if it provides for a contractual obligation to: · · ·

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

If the Group does not have an unconditional right to avoid delivering cash or another financial asset to settle its contractual obligation, the obligation meets the definition of a financial liability.

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.

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.

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 the right to receive payment has been established. The losses arising from impairment of such investments are recognized in the consolidated statement of income.

The Group has no financial instruments that contain both liability and equity elements.

As of December 31, 2015 and 2014, 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, 2015 and 2014, 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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Classified under this category are the Group’s accounts payable and accrued expenses and loans payable (Notes 16, 17 and 29).

GREENING POWER GENERATION 2015 ANNUAL REPORT

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

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

assessment of impairment. 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 consolidated 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 the consolidated 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 consolidated 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: · ·

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.

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 the 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. 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. Power plant, fuel collection and reinjection system (FCRS) and production wells in the geothermal plant 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. Land improvements consist of betterments, site preparation and site improvements that ready land for its intended use. These include excavation, non-infrastructure utility installation, driveways, sidewalks, parking lots, and fences. Land improvements are depreciated over 5 years.

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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*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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

Number of Years 25 15 5 - 10 5 4 3 2-3

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

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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: · · ·

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. 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 and depreciated accordingly. As of December 31, 2015 and 2014, deferred geothermal costs amounting $0.71 million and $0.02 million, respectively, were recognized under “Other noncurrent assets” in the consolidated statement of financial position (Note 15). Deferred Costs - Solar Power Project These are costs incurred in the development of the Solar Project. This include costs incurred for the construction of the asset and other directly attributable expenses during the construction o the solar farm. As of December 31, 2015, deferred costs for the Solar Power Project amounting $0.46 million, were recognized under “Other noncurrent assets” in the consolidated statement of financial position (Note 15). Intangible Assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired is their fair value as at the date of acquisition. Following initial recognition, intangible assets are carried at cost less accumulated amortization and accumulated impairment losses, if any. Intangible assets with finite lives are amortized over their useful economic lives and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization period and the amortization method for an intangible asset with a finite useful life are reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset is accounted for by changing the amortization period or method, as appropriate, and are treated as changes in accounting estimates.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

The amortization expense on intangible assets with finite lives is recognized in the statement of income in the expense category consistent with the function of the intangible assets.

· ·

Amortization is computed using the straight-line method over the estimated useful lives (EUL) of one (1) to two (2) years.

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.

Intangible assets with indefinite useful lives are not amortized, but are tested for impairment annually, either individually or at the CGU level. The assessment of indefinite life is reviewed annually to determine whether the indefinite life continues to be supportable. If not, the change in useful life from indefinite to finite is made on a prospective basis. Gains or losses arising from derecognition of an intangible asset are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in the statement of profit or loss when the asset is derecognized.

Investment in a Joint Venture A joint venture (JV) is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Investment in a JV is accounted for under the equity method of accounting.

As of December 31, 2015 and 2014, intangible assets amounting $3.28 million and $0.05 million, respectively, were recognized under “Other noncurrent assets” in the consolidated statement of financial position (Note 15). 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 statement 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: · assets, including its share of any assets held jointly · liabilities, including its share of any liabilities incurred jointly · revenue from the sale of its share of the output arising from the joint operation

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GREENING POWER GENERATION 2015 ANNUAL REPORT

share of the revenue from the sale of the output by the joint operation expenses, including its share of any expenses incurred jointly

As discussed in Note 2, the Group lost its control over PetroWind. Prior to becoming a joint venture in 2014, PetroWind was accounted for as a subsidiary in previous years. In accordance with PFRS, the Group measures and recognizes any retained investment at its fair value when there is loss of control over a subsidiary. Any difference between the carrying amount of the subsidiary upon loss of control and the fair value of the retained investment and proceeds from disposal is recognized in profit or loss as unrealized gain on remeasurement of investment (Note 12). 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 and geothermal costs, and intangible assets) may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group estimates the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cash-generating unit’s fair value less costs to sell and its value in use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or group of assets. Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Group makes an estimate of recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization 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.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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 Group and its subsidiaries are available for dividends only upon approval and declaration of each of their respective BOD. Equity Reserve Equity reserve is made up of equity transactions other than equity contributions such as gain or loss resulting from increase or decrease of ownership without loss of control. Deposits for Future Stock Subscriptions Deposits for future stock subscriptions is recorded based on the redeemable amounts received and is presented under liabilities unless the following items were met for classification as part of equity: a.

The unissued authorized capital stock of the entity is insufficient to cover the amount of shares indicated in the contract; b. There is BOD approval on the proposed increase in authorized capital stock (for which a deposit was received by the Company); c. There is stockholders’ approval of said proposed increase; and d. The application for the approval of the proposed increase has been filed with the Securities and Exchange Commission (SEC). Deposits represent subscription payments received from prospective investors for the Group’s common shares which are yet to be issued upon approval by the SEC of the application for increase in the authorized capital stock. This will be reclassified to ‘Capital stock’ upon issuance of the subscribed shares. Income Taxes Current Tax Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted at the reporting date. Deferred Tax Deferred tax is provided using the balance sheet liability method on all temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except to the extent that the deferred tax liabilities arise from the: a) initial recognition of goodwill; or b) the initial

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recognition of an asset or liability in a transaction which is not: i) a business combination; and ii) at the time of the transaction, affects neither accounting profit nor taxable profit or loss. Deferred tax assets are recognized for all deductible temporary differences with certain exceptions, and carryforward benefits of unused tax credits from excess minimum corporate income tax (MCIT) over RCIT and unused net operating loss carryover (NOLCO), to the extent that it is probable that sufficient taxable income will be available against which the deductible temporary differences and carryforward benefits of unused tax credits from excess MCIT and unused NOLCO can be utilized. Deferred tax assets, however, are not recognized when it arises from the: a) initial recognition of an asset or liability in a transaction that is not a business combination; and b) at the time of transaction, affects neither the accounting income nor taxable profit or loss. The carrying amounts of deferred tax assets are 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 tax assets to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date, and are recognized to the extent that it has become probable that future taxable income will allow the deferred tax assets to be recovered. The Group does not recognize deferred tax assets and deferred tax liabilities that will reverse during the income tax holiday (Note 24). Deferred tax assets and liabilities are measured at the tax rates that are applicable to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted as of the reporting date. Deferred tax relating to items recognized outside profit or loss is recognized outside profit or loss. Deferred tax items are recognized in correlation to the underlying transaction either in profit or loss or other comprehensive income. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. 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: · Service cost · Net interest on the net defined benefit liability or asset · 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

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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. 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 produce and sell crude oil inventory, including transportation, storage and loading, among others. Costs of electricity sales pertain to direct costs in generating electricity power which includes operating and maintenance costs (O&M) for power plant and fluid collection and reinjection system (FCRS), depreciation and other costs directly attributed to producing electricity. General and administrative expenses constitute costs of administering the business. Costs and expenses are recognized as incurred. Asset Retirement Obligation (ARO) Provision for asset retirement obligation is recognized when the recognition criteria for a provision are met. The Group recognizes the present value of these costs as ARO assets (included under “Property, plant and equipment”) and ARO liability. The Group depreciates ARO assets on a straight-line basis over the estimated useful life (EUL) of the related asset or the service contract term, whichever is shorter, or written off as a results of impairment of the related asset. The Group amortizes ARO liability using the effective interest method and recognizes accretion expense over the service contract term.

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The Group regularly assesses the provision for ARO and adjusts the related liability. 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.

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; b. there is a change in the determination of whether fulfillment is dependent on a specified asset; or c. 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. 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: · · · · ·

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

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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, plant and equipment are amortized using the straight-line method over the estimated useful lives of the assets. Interest expense on loans and borrowings is recognized using the EIR method over the term of the loans and borrowings. 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 Group’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 statement 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 Group’s immediate subsidiary, PetroGreen and its subsidiaries, namely MGI and PetroSolar, is the 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 statement 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.

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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 30 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 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 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 and MGI is the Philippine Peso. As of December 31, 2015 and 2014, the Group’s cumulative translation adjustment amounted to $2.55 million and $0.84 million, respectively.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

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. The Group determines impairment of projects based on management’s decision not to pursue any further commercial development of its exploration projects. Facts and circumstances that would require an impairment assessment as set forth in PFRS 6, Exploration for and Evaluation of Mineral Resources, are as follows: · · · ·

The period for which the Group has the right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed; Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; Exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

As of December 31, 2015 and 2014, the carrying value of deferred oil exploration costs amounted to $15.92 million and $19.11 million, respectively (Note 11). No impairment loss for deferred oil exploration costs was recognized in 2015, 2014 and 2013. Classification of Joint Arrangements The Group’s investment in a joint venture (Note 12) is structured in a separate incorporated entity. The Group and the parties to the agreement only have the right to the net assets of the joint venture through the terms of the contractual arrangement. Accordingly, the joint arrangement is classified as a joint venture.

Fair Values of Financial Assets and Financial Liabilities The Group carries certain financial assets, liabilities and free-standing derivatives 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, liabilities and free-standing derivatives would affect directly the consolidated statement of income (Note 7). Where the fair values of certain financial assets, liabilities and free-standing derivatives 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. 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 engaged at its own cost the New Zealand firm Sinclair Knight Merz (SKM) in 2011 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.

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 economic feasibility is confirmed, usually when a product development project has reached a defined milestone according to an established project management model. If the requirements for capitalization of development costs are not met, such costs are expensed.

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.

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.

MGI commenced producing power commercially last February 8, 2014. To date, the current production wells are capable of producing 33.1 MW. These production wells including the complement reinjection wells are concentrated on the proven resource area.

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.

An updated reserves estimation using the stored-heat calculation was made as a result of the 2014 drilling campaign. Using Monte Carlo simulation to estimate the reserves, the proven resource area has an 80% probability of delivering between 18.1 MW to 50.9 MW over a 25-year operating period. This Monte Carlo simulation also showed that the expected mean reserve for the proven resource area is 30.4 MW for 25 years. Currently the existing production wells on this proven resource area can produce around 33.1 MW, more than enough to meet the steam requirement of the existing 20 MW power plant plus the at least 12 MW expansion power plant.

No impairment losses were recognized in 2015, 2014 and 2013.

Also, there is a likely geothermal potential south of the proven area where two old wells were drilled and encountered high fluid temperatures (T ~ 300°C). MGI identified the southern block as

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As of December 31, 2015 and 2014, the carrying value of receivables amounted to $3.59 million and $3.57 million, respectively. Accumulated impairment losses amounted to $0.06 million as of December 31, 2015 and 2014 (Note 8).

GREENING POWER GENERATION 2015 ANNUAL REPORT

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a probable reserve area. SKM in 2011 suggested that the southern block can be classified as Indicated Resource based on the Australian Code as high temperatures have been intersected by the two wells. SKM estimated that the stored heat in the Southern Block has a resource potential equivalent to 12 MW for a project life of 25 years. 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. 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, plant and equipment would increase the recorded depletion, depreciation and amortization expense and decrease noncurrent assets. As of December 31, 2015 and 2014, the Group’s property, plant and equipment amounted to $140.72 million and $79.78 million, respectively (Note 10). Estimating Impairment of Nonfinancial Assets The Group assesses impairment on its nonfinancial assets (e.g., property, plant and equipment, investment properties and intangible assets) whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 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.

The related balances of the Group’s nonfinancial assets follow (Notes 10, 13 and 15): Property and equipment Intangible assets Investment properties

2015 $140,724,197 3,283,286 31,417 $144,038,900

2014 $79,784,366 54,392 31,417 $79,870,175

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 22 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, 2015 and 2014 amounted to $0.66 million and $0.69 million, respectively. 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, 2015 and 2014, asset retirement obligation amounted to $0.85 million and $0.38 million, respectively (Note 19). Asset Retirement Obligation - Geothermal Energy Project In determining the amount of provisions for restoration costs, assumptions and estimates are required in relation to the expected costs to restore sites and infrastructure when such obligation exists. As of December 31, 2015 and 2014, asset retirement obligation amounted to $0.24 million and $0.23 million, respectively (Note 19). The estimate represents costs of plugging and abandonment of the geothermal wells.

As discussed in Note 10, production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last seventeen (17) 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 $6.66 million as of December 31, 2015 and 2014. Management assessed that the said investment is fully recoverable as SC 14-C has 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 in the view of the existing redevelopment activities led by Pitkin Petroleum Ltd. (Pitkin). Thus, no impairment was recognized in 2015 and 2014.

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.

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PETROENERGY RESOURCES CORPORATION

As of December 31, 2015 and 2014, the Group did not recognize deferred tax assets on NOLCO amounting to $0.25 million and $0.58 million, respectively, and MCIT amounting $0.04 million and $0.01 million, respectively. 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 (Note 23). 6. Cash and Cash Equivalents and Short-term Investments Cash on hand Cash in banks Short-term investments

2015 $4,376 14,710,421 17,821,808 $32,536,605

2014 $3,323 1,175,051 1,639,780 $2,818,154

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 2014, the Group invested $0.19 million to short-term investments with periods more than three months but less than one year. These investments were presented separately as short-term investments (Note 29). Interest income earned on cash in banks and short-term investments amounted to $0.11 million, $0.07 million and $0.20 million in 2015, 2014 and 2013, respectively.

The Group’s receivables are mainly due from consortium operator and from the sale of electricity to Trans-Asia. These are due within one year. The carrying values as of December 31, 2015 and 2014 approximate their fair values (Note 29). The receivable from affiliate represents advances made by the Group to PetroWind. This is unsecured and noninterest bearing and collectible within one year. For the terms and conditions on related party transactions, refer to Note 28. The table below shows the disclosure of reconciliation of allowance for impairment losses for receivables from a consortium operator:

Marketable equity securities Investment in golf club shares

2014 $150,306 12,746 $163,052

Net gain on fair value changes on financial assets at FVPL included in the consolidated statements of income amounted to $1,392, $26,128 and $7,456 in 2015, 2014 and 2013, respectively. 8. Receivables Accounts receivable from: Consortium operator Electricity sales to Trans-Asia Affiliate (Note 28) Others Interest receivable Less allowance for impairment losses

2015

2014

$1,032,511 1,726,101 879,782 3,752 6,727 3,648,873 57,000 $3,591,873

$1,772,766 1,815,322 − 40,929 2,574 3,631,591 59,983 $3,571,608

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GREENING POWER GENERATION 2015 ANNUAL REPORT

2014 $60,422 (439) $59,983

9. Prepaid Expenses and Other Current Assets Restricted cash Downpayments to contractors Prepaid expenses Prepaid taxes Others

7. Financial Assets at Fair Value Through Profit or Loss 2015 $144,118 12,113 $156,231

2015 $59,983 (2,983) $57,000

Balance at beginning of year Effect of foreign currency translation Balances at end of year

2015 $3,815,197 1,508,774 658,518 145,515 189,188 $6,317,192

2014 $1,989,468 319,790 291,307 65,184 21,947 $2,687,696

Restricted cash mainly pertains to the amount of fund that the group is required to comply with the Debt Service Payment Account (DSPA) and Debt Service Reserve Account (DSRA) MGI and PetroSolar, respectively. This also includes unused portion of the Stock Rights proceeds, which was held under escrow account. Downpayments pertain to advances made to various contractors for the construction of power plants such as the MGPP and Solar Power Project (Note 10). The downpayments will be applied against future billings in the course of construction. The current portions are estimated to be applied against progress billings within one year from reporting date and are classified under “Advances, prepaid expenses and other current assets”. Downpayments to contractors that are related parties amounted to nil and $119,845 as of December 31, 2015 and 2014, respectively (Note 28). Prepaid expenses include prepaid insurance and professional fees. Prepaid taxes pertains creditable withholding taxes and overpayment of income tax in 2014 and 2015. Others pertain to supplies and advances.

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74 GREENING POWER GENERATION 2015 ANNUAL REPORT PETROENERGY RESOURCES CORPORATION

Cost Balance at beginning of year Additions Disposals Set up of ARO (Note 19) Capitalized development cost (Note 38) Reclassification/adjustments Effect of deconsolidation of a subsidiary (Note 12) Effect of foreign currency translation Balance at end of year Accumulated depletion and depreciation Balance at beginning of year Depletion and depreciation (Notes 26) Disposals Reclassification/adjustments Effect of deconsolidation of a subsidiary (Note 12) Effect of foreign currency translation Balance at end of year Net book values

Cost Balance at beginning of year Additions Change in estimate of ARO (Note 19) Transfers from deferred exploration costs (Note 11) Reclassification/adjustments Effect of foreign currency translation Balance at end of year Accumulated depletion and depreciation Balance at beginning of year Depletion and depreciation (Notes 26) Depreciation capitalized Reclassification/adjustments Effect of foreign currency translation Balance at end of year Net book values − (39,241) (1,002,778) 19,884,969 607,264 688,818 ‒ − (53,055) 1,243,027 $18,641,942

FCRS and production wells geothermal $16,256,900 4,285,045 ‒ 229,253 754,386 (719,086) − (639,528) 20,166,970 ‒ 605,214 ‒ 2,050 −

$48,248,324 109,758 ‒ − (331,318) (2,399,088) 45,627,676 1,768,095 1,838,890 ‒ ‒ (148,940) 3,458,045 $42,169,631

Power plant $‒ − ‒ ‒ − 48,248,324 − − 48,248,324 ‒ 1,774,868 ‒ (6,773)

− 607,264 $19,559,706

$20,166,970 760,018 ‒

Power plant

− − 1,768,095 $46,480,229

FCRS and production wells geothermal

10. Property, Plant and Equipment

85,592 ‒ ‒ (6,812) 158,649 $1,523,083

79,869

− 292,397 (70,207) 1,681,732

$1,411,932 47,610 ‒

Land and land improvements

− − 14,723,628 $8,502,460

1,405,642 ‒ 46,874

13,271,112

− − 23,226,088

$22,976,527 137,405 − − − 112,156

− 15,537 79,869 $1,332,063

53,588 ‒ 5,441

5,303

(176,250) 56,126 1,411,932

$1,059,384 320,441 ‒ ‒ − 152,231

Wells, platforms and other Land and land facilities improvements

1,681,618 ‒ ‒ ‒ 16,405,246 $17,350,381

14,723,628

8,809,408 − ‒ 33,755,627

$23,226,088 1,362,361 357,770

Wells, platforms and other facilities

(34,355) 757,257 $16,659

73,351 ‒ − −

718,261

− (137,740) 773,916

(2,911) (1,259) 301,391 $385,821

122,529 (33,657) 3,984

212,705

(29,064) (16,120) 687,212

$716,342 63,394 (47,049) ‒ − (291)

Transportation equipment

2014 Office condominium units and improvements $910,661 995 ‒ ‒ − ‒

121,843 3,915 934 (8,580) 419,503 $308,160

301,391

− (2,136) (19,150) 727,663

$687,212 61,737 ‒

30,723 ‒ 2,372 ‒ 790,352 $6,104

757,257

− 22,540 ‒ 796,456

$773,916 ‒ ‒

2015 Office condominium units and Transportation improvements equipment

(1,308) (36,645) 522,448 $660,399

216,246 − (100,234)

444,389

(12,909) (54,320) 1,182,847

$961,201 420,279 (1,262) ‒ − (130,142)

Office furniture and other equipment

247,075 1,559 (6,345) (23,739) 740,998 $708,813

522,448

− (11,011) (38,416) 1,449,811

$1,182,847 316,391 ‒

Office furniture and other equipment

4,694,559 5,474 (3,039) (241,126) 23,215,820 $140,724,197

18,759,952

8,809,408 (478,533) (3,671,204) 163,940,017

$98,544,318 60,378,258 357,770

Total

(4,219) (56,722) 18,759,952 $79,784,366

4,251,438 (33,657) (48,658)

14,651,770

(419,180) (596,092) 98,544,318

$89,724,110 10,460,030 (48,311) 229,253 754,386 (1,559,878)

Total

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− − − $2,847,029

− ‒ ‒

‒

(200,957) 195,490 2,847,029

$46,843,095 5,232,471 ‒ ‒ − (49,223,070)

Construction in progress

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‒ ‒ ‒ ‒ ‒ $60,016,083

‒

− (409,764) (141,565) 60,016,083

$2,847,029 57,720,383 ‒

Construction in progress

The power plant, FCRS and production wells pertains to assets of MGI. The MGI’s geothermal power plant was completed in 2013.

19, 2015, through the target Lower Gamba reservoir unit. ET-12H was put on line on April 12,2015 at a stable rate of 2,500 BOPD from the Etame Platform.

The Construction in progress pertains to the construction of Maibarara Phase-2 and TSPP of MGI and PetroSolar.

After completing operations for the ET-12H in the Etame Platform, the Constellation II rig mobilized towards the SEENT Platform on April 12, 2015 and spudded the ETSEM-2H development well on April 20, 2015. The well was drilled to a depth of 3,967m when the well experienced a downhole drillpipe failure that resulted in the loss of the bottomhole assembly. Three unsuccessful attempts to recover the parted drillpipe prompted operator VAALCO to conduct cement plug and abandonment procedure of the 12-1/4” hole section. To allow time to assess the cause of the failure and to plan for a sidetrack of the ETSEM-2H, VAALCO skidded the rig to the slot designated for the ETBNM-1H (North Tchibala) well and proceeded with tophole drilling operations. The ETBNM-1H (North Tchibala) well was spudded on May 22, 2015 and reached a depth of 1,010m.

Depletion of wells, platforms and other facilities is part of oil production under cost of sales in the consolidated statement of income. Depletion and depreciation expense charged to profit or loss follows: Cost of electricity sales (Note 25) Depletion General and administrative expenses (Note 26)

2015 $2,735,992 1,681,618 276,949 $4,694,559

2014 $2,531,557 1,405,642 314,239 $4,251,438

Foreign Operations Gabon, West Africa Update on Production Total crude production in 2015 reached 6.78 million barrels of oil (MMBO), with daily oil production ranging from 13,780 – 22,140 barrels of oil per day (BOPD) from four oil fields (Etame, Avouma, Ebouri and North Tchibala). Six (6) wells were drilled in 2015 as part of the Etame Expansion Project, contributing to a general increase in overall production. Update on Development Etame Expansion Project (EEP) The EEP, which commenced in 2010, aims to increase crude oil production to ~25,000 - 30,000 BOPD and maximize the life of the Etame Marin field by 1) optimizing the available recoverable oil reserves in the existing production fields by installing two (2) offshore production platforms and the subsequent drilling from these platforms, and 2) exploring for new petroleum prospects which can add to crude production. After the Gabon government approved the platform construction for the Etame and Southeast Etame/North Tchibala (SEENT) expansion program on December 27, 2012, the platform topsides facilities design and fabrication were undertaken in 2013, while the transport and installation of parts were done in 2014. After an 18-month construction period, the Etame and SEENT Platforms arrived in Gabon and were installed in place in September 2014, in time for the drilling of three (3) Etame production wells and another three (3) SEENT wells. The drilling program for the Etame Expansion Program commenced in October 2014 using a different rig – Constellation II, with the first sanctioned well, ET-8H, being drilled from the newly-installed Etame Platform in November 2014. The well was shut-in in December 2014 due to detection of H2S. The well was flow-tested in March 25, 2015, but was shut-in again due to high concentration of H2S. The second production well under the Etame expansion, ET-10H, reached a total depth of 3,144 meters on January 16, 2015 through the target Gamba reservoir section. The well commenced production on February 6, 2015, contributing 3,000 BOPD from the Etame Platform. The third sanctioned well, ET-12H, was drilled to a depth of 3,452m on March

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After conclusion of tophole drilling operations at ETBNM-1H, the Constellation II rig skidded back to the ETSEM-2H on June 02, 2015 to conduct sidetrack operations. The remaining hole section of the sidetracked well, ETSEM-2H ST1, was drilled to a total depth of 4,271m. The wellbore intersected a total of 190m of hydrocarbon-bearing Gamba Sand in the production hole section. Well ETBNM-1H, whose main objective was the older channel sands, Dentale D09, was completed in September 2015, while well ETBNM-2H, which targeted the Dentale D18/19 sandstone reservoir, was drilled from September to November 2015. After drilling operations at the SEENT Platform, the Constellation II rig moved to the Avouma Platform in early January 2016 to conduct workover operations on two (2) Avouma wells with defective submersible pumps. As a strategic move to cope with falling oil prices, the consortium decided to conclude the drilling program at this point. The Constellation II rig was demobilized on January 25, 2016. Despite the natural depletion of the field, increased gas and water contents in some of the wells, successive drilling activities in the Etame and SEENT platforms, and transient production downtimes, the daily production still increased to 13,780 – 22,140 BOPD compared to 2014’s range of 7,110 - 19,900 BOPD. Nonetheless, the Consortium managed eleven (11) liftings for the year 2015, resulting in a net crude export of 6.88 MMBO. Crude oil market prices for the year 2015 ranged from US$36.11 - US$68.30 per barrel. Shallow Water Exploration Project (SWEP) In an effort to maximize the remaining recoverable oil reserves within the Etame Marin concession, the Etame consortium kicked off a Shallow Water Exploration Program in 2011 to identify petroleum prospects for future drilling in the shallower parts of the block. Using the available 3D seismic data acquired in 1997 and 2011, the Consortium was able to map out drillable prospects in these shallower areas, and by 2013, the consortium committed to drill two shallow water prospects, namely Ovoka and Dimba. The Ovoka prospect was drilled in August 2013, while Dimba was drilled in February 2014. Both wells had oil shows, but were deemed non-commercial. Crude Sweetening Project One challenge that has cropped up in the Etame Marin concession is the emergence of H2S gas in the produced oil. Two wells in Ebouri field and two wells in Etame field manifested H2S in their hydrocarbon output. The sweetening project was started in 2011 to determine the best ways to

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

treat these sour oils, but due to the recent decline in oil price, the project was put on hold. This scheme, however, is still being studied and will only take off once it becomes economical to be implemented. Brownfield Projects Upgrade In 2013, a Water Knock-Out System was installed in the Avouma Platform to optimize the extracted crude going to the Floating Production Storage and Offloading (FPSO) vessel. FPSO Integrity Assessment In order to further maximize the long-term usability of the existing FPSO, the Petroleo Nautipa, a Topsides Integrity Assessment was jointly carried out in 2013 by Allied Marine Services and BASS to identify corrective actions to maintain the vessel’s structural integrity and ensure continuous operation throughout the life of the field. 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. Philippine Operations SC 14-C2 - West Linapacan, Northwest Palawan In 2008, Pitkin Petroleum Plc farmed-in to the block with the work commitment of 1) a G&G program, 2) drilling one (1) well, which would lead to eventual field development. In 2010, the DOE granted the final 15-year extension of the SC 14C acreage from December 17, 2010 until December 17, 2025, in line with similar extensions granted to other SCs in Palawan. However, questions regarding the character of the reservoir hampered Pitkin’s plan to push ahead with the drilling campaign, which led to its decision to farm-out half of its 58.29% interest to RMA (HK) Ltd. in 2011, which the DOE formally approved in April 2012. But RMA itself had to re-schedule the drilling due to delays in completing their reservoir simulation study, which is a prerequisite for the JV Partners’ approval of the drilling program. On January 3, 2013, Operator RMA (HK) Ltd. applied with 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. (RMA West), 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 West 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 a Proved + Probable (2P) reserves estimate of 16.5 MMBO. This is based on a two-multilateral well development program scheduled in 2014-15. In March 2014, RMA shared with partners the final report of Gaffney, Cline and Associates (GCA) on the certification of the reserves of the West Linapacan A structure. According to the report, the West Linapacan A structure has Proved (1P) reserves of 11.6 Million barrels, with Proved + Probable (2P) reserves of 18.2 Million barrels, and Proved + Probable + Possible (3P) reserves of 22.8 Million barrels. Further, GCA indicated that all three cases assume reserved from a three-well development which was agreed upon by the Consortium during the Technical and Operating Committee Meetings (TCM/OCM) held at RMA offices in Melbourne, Australia on March 5-6, 2014.

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On February 5, 2015, the DOE granted incumbent operator RMA West an additional one-month extension until March 5, 2015 to show proof of financial capability, which RMA West failed to provide. This prompted the DOE to terminate the Farm-in Agreement (FIA) between Pitkin and the Filipino partners on March 12, 2015. This also effectively terminates the Pitkin-RMA FIA, also stripping RMA West of its involvement in the block. From April to May 2015, the remaining Consortium members sought DOE’s formal approval of the reversion of participating interests in SC 14C2 following the exit of Pitkin and RMA West. While such approval was sought, newly appointed Operator Philodrill presented its proposed 2015 Work Program and Budget for the block - consisting of technical and commercial audit of RMA West’s completed works throughout its Operatorship, totaling US$59,950 over five (5) months. Following Philodrill’s re-assumption of Operatorship of the West Linapacan block, they made a formal request to former operator RMA West on June 1, 2015 to cooperate with Philodrill in the hand-over of all technical, legal and financial documents in RMA West’s possession during its operatorship. With oil prices continuing to drop throughout the end of 2015, the Consortium was in general agreement to postpone any further development in the block. However, the consortium agreed to continue to keep the SC active by submitting a Work Program for 2016. This will entail an abandonment study with a minimum financial commitment. On December 18, 2015, Philodrill submitted to the JV Partners their proposed 2016 Work Program & Budget (WP&B) for SC 14C2, which consists of the conduct of an ROV (remotely operated vehicle) downhole survey of the old West Linapacan wells in preparation for abandonment procedures. The technical and commercial audit of the block will continue in 2016, alongside continuing efforts to secure the G&G data generated by previous operator RMA West. The total budget for the abovementioned activities is US$628,890. PetroEnergy share is US$27,150. After the termination of the FIA with Pitkin, PERC’s participating interest in SC 14C2 is back to 4.137% from 1.03725%. Geothermal Energy Geothermal Renewable Energy Service Contract (GRESC) No. 2010-02-012 PetroEnergy signed the Service Contract for the Maibarara Geothermal Power Project on February 1, 2010. After which, PERC conducted pre-development activities in 2010 until 2011. Also, PetroEnergy formed a Joint Venture company, Maibarara Geothermal Inc. (MGI), with TransAsia and PNOCRC. During the latter part of 2011, the DOE confirmed the commerciality of the 20-MW Maibarara Geothermal Power Project, which allowed MGI to proceed to the project’s development stage, involving 1) the drilling of two (2) wells to complete the steam production and reinjection well capacities, and 2) the construction of the steamfield and power plant facilities. The completion of the steam requirement for the 20 MW Maibarara Geothermal Power Plant (MGPP) was successfully achieved when MGI drilled its first production well, MB-12D, in JulyAugust 2012 to a total depth of over 2,000 m. 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 wells Mai-6D, Mai-9D and Mai-11D, MGI has the necessary wells for the 20 MW facility.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

MGPP’s 115kV Transmission Line system was successfully connected to the existing MERALCO line on September 10, 2013. Upon completion of the reliability and performance testing, the MGPP went on commercial operations on February 8, 2014. MGI drilled two new wells in 2014 to confirm the expansion of the Maibarara resource. Well MB15RD was successfully completed on October 6, 2014, while well MB-16D was drilled and completed on November 16, 2014. Due to very good flow test results, MB-15RD was later decided to be the production well for the expansion, and well MB-16D as the reinjection well.

The DOE subsequently approved the assignment of the Tarlac Solar Service Contract to PSC on September 22, 2015. It also issued the Affirmation of Declaration of Commerciality for the TSPP on September 24, 2015, concluding the project’s Pre-Development Stage and commencing with the project’s Development Stage. Between September and November 2016, PEZA issued several permits for TSPP construction, allowing development inside LIPCO to go full-blast.

With the stable performance of the reservoir, MGI decided to pursue an expansion of the Maibarara Project (M2). There is at least 5 MW excess steam supply from the 20 MW wells, and with the ~6 MW capacity of MB-15RD, an expansion to 12 MW was decided and approved in 2015. The preparations for the expansion took off in 2015 with initial discussions with potential suppliers and contractors. Discussions with potential offtakers were also conducted during the year.

Media Construction mobilized for the site clearing in early July and by November, was able to complete much of the internal roads and foundation works for the solar farm and the control building. Conergy’s piling contractor Conecon initiated the piling works for the solar panel substructure in late September and completed it by mid-November. Phesco Inc, the onshore construction contractor, commenced with the installation of solar modules on October 13, 2015 and completed it on January 11, 2016.

From January 1 to December 31, 2015, the total energy exported to the grid was 151,103.67 MWh. This was sold to MGI’s Offtaker, Trans-Asia. Tarlac Solar Power Project

Philcantech commenced the erection of the 69-kV T/L poles on October 3, 2015 and was able to complete the whole 5.9 km transmission line by the third week of December 2015. Philcantech was able to complete the switchyard by the third week of December. This followed from NGCP’s approval of the System Impact Study and Facility Study by PSC.

The Service Contract for PetroGreen newest renewable energy project, the 50 MW Tarlac Solar Power Project (TSPP), was signed with the DOE on March 19, 2015. The solar project is situated in the central plains of Luzon consisting of flat terrain with high irradiation values making it highly favourable for photovoltaic (PV) solar power development.

In the meantime, PetroSolar executed an Omnibus Loan and Security Agreement (OLSA) with joint lenders Development Bank of the Philippines (DBP) and Philippine National Bank (PNB) on November 12, 2015, covering a loan amount of P2.6 billion. The OLSA was registered with the Registry of Deeds on November 13, 2015.

PetroGreen awarded the major solar equipment supply contract for the TSPP to German firm Conergy on June 19, 2015. Conergy, through their local Onshore Contractor, Phesco Inc., commited to commence the solar farm construction activities by August 2015, with expected completion of the 50-MW solar farm by January 11, 2016. PetroGreen awarded the Civil and Structural Works for the Tarlac site to Media Construction and Development Corporation on June 19, 2015. Philcantech Enterprises (an electrical firm based in Tarlac City) undertook the supply, delivery and installation of the 5.9-kilometer 69-kV transmission line linking the Tarlac solar farm to the NGCP grid.

By mid-December 2015, the solar farm and transmission facilities were 80% and 100% completed, respectively, prompting the DOE to nominate the TSPP to be FIT-eligible. The solar farm was completed by mid-January 2016 and was able to export power to the grid on January 27, 2016. The DOE eventually gave its Certificate of Endorsement (COE) – FIT for TSPP with Commercial Operations Date of February 10, 2016. ERC is processing the project’s Certificated of Compliance (COC) – FIT which will enable TSPP to bill TRANSCO for its generation based on the FIT rate of = P8.69/kWh.

On June 17, 2015, PetroGreen and affiliate company EEI Power Corp. (EEIPC), incorporated a joint venture project company, PetroSolar Corporation (PSC), to undertake the development of the TSPP. On June 22, 2015 PGEC and solar farm lot owners Luisita Industrial Park Corporation (LIPCO) executed a Lease Agreement for the 55-hectar solar farm development. This was later assigned to PSC on September 15, 2015. As the LIPCO property is within the Central Technopark, which is under the jusrisdiction of the Philippine Economic Zone (PEZA), PSC was able to register as an Economic Zone Untilities Enterprise on July 28, 2015, entitling it to the incentives available to PEZA locators, and enabling the waiver of LGU endorsements (the Tarlac City’s favorable endorsement was nevertheless sought and was secured on September 3, 2015) and for the TSPP to benefit from an expedited issuance of the Environmental Compliance Certificate (ECC). On August 4, 2015, the DENR-EMB Region III issued PSC with the ECC, an essential permit needed for ground works to commence on the solar park site. Also, on August 27, 2015, the National Commission on Indigenous Peoples – Region III (NCIP) issued the Certificate of Non-

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Overlap (CNO) to PSC, stating that no ancestral domains or indigenous peoples exist within the project site.

GREENING POWER GENERATION 2015 ANNUAL REPORT

On March 7, 2016, the DOE issued the Certificate of Endorsement for Feed-in Tariff Eligibility (COE-FIT) of the TSPP, confirming that the project is qualified under the FIT system subject to compliance with the requirements of the Energy Regulatory Commission (ERC), and validating that February 10, 2016 is the start of the project’s commercial operation. Borrowing Cost In 2015 and 2014, the Group capitalized specific borrowing costs relating to finance charges incurred in the construction of the power plant. Capitalized specific borrowing costs amounted to $0.02 million and $0.42 million in 2015 and 2014, respectively. The rate used to determine the amount of specific borrowing costs eligible for capitalization is 6.89%, which is the effective interest rate of loans. Collateral to Secure Borrowings 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.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

MGI has pledged a portion of its land and property, plant and equipment amounting to $4.5 million as collateral in connection with the loan. Pledged assets are as follows: · ·

Real estate (land to be used as power plant site, under “Property, plant and equipment”) $3.25 million; and Chattel (under “Property, plant and equipment”) - $1.5 million.

PSC pledged all of its property and equipment as collateral in connection with its loan. 11. Deferred Oil Exploration Costs Balance at beginning of year Additions Transfers to wells and platforms (Note 10) Balance at end of year

2015 $19,112,571 5,616,676 (8,809,408) $15,919,839

2014 $11,397,210 7,715,361 − $19,112,571

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. Additions pertain to development costs incurred for Etame expansion. 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, SC 51 members (Alcorn Gold Resources, Trans-Asia Oil, and PERC) signed a farm-in agreement with NorAsian Energy Ltd. (later changed name to Otto Energy Investment Ltd, OEIL). 80% participating interest in SC 51 will be earned by NorAsian upon successful acquisition of 3D seismic data and drilling of 2 exploratory wells. For Subphase 2 commitment, the 3D seismic data over Argao was acquired in June 2007. Through its own G&G evaluation, Operator OEIL decided to focus on the northern block (NW Leyte) and to relinquish all its interest in the southern block (Offshore Cebu). In April 2011, as a commitment for Subphase 3 (SP3), the onshore exploratory well Duhat-1 was spudded in San Isidro, Northwest Leyte. After it was sidetracked, the well (Duhat-1A) reached a total depth of 321m but had to be abandoned on May 25, 2011 due to persistent mechanical drilling problems. Although the well failed short of reaching its 1,000m programmed total depth, the Operator/Farminee OEIL 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.

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In an effort to further delineate the Duhat prospect and to avoid the same outcome as that of Duhat-1, the Consortium proposed the acquisition, processing and interpretation of 100km of 2D seismic over the Duhat prospect. On January 25, 2012, the DOE approved the said Work Program as Subphase 4 commitment, with a total budget of $4.35 million. OEIL contracted Beijing-based BGP Asia to conduct the 2D seismic survey. Actual data shooting and acquisition for the 102 line-km 2D seismic survey over the Duhat prospect was conducted from August to October 2012, at a cost of US$ 3.38MM. Following the completion of the 2D seismic program, the Consortium elected on December 12, 2012 to enter Subphase 5 (SP5) with a one well drilling commitment. On January 28, 2013, the DOE approved the SC 51 North block consortium’s election to enter SP5. After acquiring all the necessary permits from the LGUs and appropriate site preparations in San Isidro, Leyte, Duhat-2 was spudded by Operator OEIL on July 24, 2013. Upon reaching a depth of 201m on July 26, 2013, salt water flow occurred. OEIL 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), Trans-Asia, and PetroEnergy did not credit Duhat-2 as an “earning well”. The DOE for its part declared Duhat-2 as non-compliant well. OEIL appealed to the DOE and was given a 6-month extension to conduct post-well analysis of Duhat-2 for the remainder of SP5. The post-well analysis of Duhat-2 commenced on February 20, 2014, and the results were presented during the OCM on April 28, 2014. OEIL concluded that it is not safe to drill anywhere on the Duhat prospect. OEIL also expressed its intention to withdraw from the SC 51 and to resign from Operatorship. The following day, a formal letter of withdrawal and resignation was submitted by OEIL to the SC 51 JV partners (Trans-Asia, Cosco and PetroEnergy) and to the DOE. On June 10, 2014, OEIL submitted a legal document to the DOE to appeal the status of Duhat-2. The legal document aimed to point out to DOE that the operator has drilled the well to standards and that the high pressure saltwater blow-out constituted a fortuitous event which rendered impossible the fulfilment of the objective of the well. In 2015, most of the activities for SC 51 focused on the administrative transition brought about by OEIL’s exit. DOE recognized that Duhat-2 well was non-compliant due to its failure to reach the objective drilling depth. The remaining partners (TAO, Cosco and PERC) met with DOE and informed them of the Consortium’s plan to continue with the SC, with the proposed Work Program: (1) Conduct pore pressure study using the drilling results of Duhat-1 and 2 and existing seismic data to establish that drilling in the area is not feasible; and (2) conduct detailed gravity survey within previously identified structures SE of the North Block. The Partners also requested for an extension of the Service Contract. To date, the Consortium is awaiting DOE’s letter of approval for the proposed Work Program and Service Contract extension. PetroEnergy’s Participating Interest in SC 51 increased to 20.05% from 4.012% upon OEIL’s resignation and exit from SC 51, with new Operator Trans-Asia Petroleum Corporation at 33.35% and CosCo Capital at 46.60%.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

SC 6-A - Octon-Malajon Block In July 2011, Pitkin Petroleum Plc entered a farm-in agreement to acquire 70% participating interest in SC 6A block. Furthermore, Pitkin was assigned as the new Operator of SC 6A in December 2011. As its farm-in obligation, Pitkin, acquired, processed and interpreted 508 sq. km. of 3D seismic data for Phase 1. The seismic acquisition was completed in November 2013. After which, Pitkin began processing and interpreting the seismic data in 2014. On August 27, 2014, Pitkin sent a letter to inform the Filipino JV partners of its intent to withdraw from the consortium after completing Phase 1 (i.e. interpretation of 3D seismic data) at the end of December 2014 without payment of penalty. Pitkin will turn over all data, reports and analysis generated during Phase 1 and will submit to DOE all records related to Phase 1 work program for cost recovery. The partners approved Pitkin’s withdrawal upon fulfilment of all the above conditions. During the SC 6A Technical and Operating Committee Meetings (TCM/OCM) on November 24, 2014, the partners approved the proposed 2015 Work Program and Budget (WP&B), composed mainly of Geological and Geophysical studies, with a total budget amount of US$ 178,170. Former SC 6A operator The Philodrill Corporation was also unanimously elected to re-assume the operatorship from Pitkin. The Philodrill Corporation presented the results of their ongoing Geological & Geophysical (G&G) evaluation of the northern portion of SC6A block. Towards the middle of the 2015, Philodrill proposed the conduct of Broadband Processing for the 2013 3D seismic data, to be followed by a Quantitative Interpretation (QI) workflow, in order to enhance the prospectivity of the identified prospects. The Partners unanimously approved these activities as part of the 2016 Work Program & Budget. The DOE approved the 2016 SC6A Work Program and Budget (WP&B) amounting to US$ 759,990.50. PetroEnergy’s Participating Interest in SC 6A block increased to 16.667% from 5.001%, with the exit of Pitkin Petroleum on May 14, 2015. SC 47 - Offshore Mindoro and Panay In 2012, the consortium requested from the DOE an extension of SubPhase 2. During the year, farm-out efforts have been carried out by the operator. The farmout terms include seismic processing and drilling of one well. In January 2014, the DOE approved a three-year extension to the 7-year Exploration Phase of SC 47, to which PNOC-EC submitted a Work Program for SubPhase 2, including the reprocessing and interpretation of 2D lines and prospect maturation which may lead to drilling of the Macadamia prospect. However, on February 25, 2015, the SC 47 consortium agreed to relinquish the SC 47 block, with an option to reapply for the same contract once it is offered again by the DOE. This decision was based on the existing high geological risk of the current prospect and lead inventory, lack of interest from farminees, and given the DOE requirement of drilling one well for SubPhase 3. A Letter of Withdrawal of the Joint Venture was sent to DOE on July 28, 2015. To date, the Consortium is still waiting for DOE’s formal approval of the relinquishment of the block.

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As of December 31, 2015, PERC’s participating interest in SC 47 remains at 2.00%, PNOC-EC at 97.00%, and Basic Energy at 1.00%. However, in a letter from the DOE dated January 16, 2016, the DOE no longer recognized SC 47 as among the service contracts in which PetroEnergy is a member. 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 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. 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 million. Following the execution of Service Contract 75 on December 27, 2013, the SC 75 consortium (Philex Petroleum, PNOC-EC, PetroEnergy) held a kick-off meeting on January 16, 2014 to discuss the way forward. Operator Philex Petroleum presented the forward plan to conduct a 2D seismic survey over SC 75 as part of Subphase 1. The M/V Voyager Explorer vessel of Seabird Exploration commenced the SC 75 2D seismic survey on March 31, 2014. After 16 days of line acquisition, the vessel completed the 2,237 linekm survey on April 17, 2014. Throughout the second half of 2014, CGG Mumbai was commissioned for the processing of the newly-acquired 2D seismic data. ARKeX Ltd. completed the processing of the supplementary gravity and magnetics data on June 20, 2014, with copies of the newly-completed gravity and magnetics data sent to the consortium by end-June 2014. The decision of the Joint Venture for the way forward, either to acquire more seismic data or get new partners to drill, will depend on the results of the interpretation of the lines to be conducted in 2015. In August 2014, the SC 75 consortium approved the application of the broadband processing to the entire 2014 2D seismic data set to enhance the quality of data. Additional cost for broadband processing amounted to US$44,140. Activities for SC 75 in 2015 focused on the on-going Geological & Geophysical (G&G) works for Subphase 1. Results of the marine gravity survey acquired in 2014 were presented to the Partners on January 12, 2015; while the interpretation of the 2D seismic data were presented on May 22, 2015. On September 9, 2015, the DOE placed SC 75, along with adjacent blocks SC 58 and SC 72 Recto Bank, under Force Majeure due to the geopolitical tensions in the West Philippine Sea. By this time, the consortium has already fulfilled its Work Program for Subphase 1, consisting of the acquisition, processing and interpretation of 2,200 line-km of 2D seismic data over SC 75. On December 4, 2015, the DOE approved the Revised SC 75 Work Program & Budget (WP&B) for 2016, which consists of a ~1,000 sq.km 3D seismic survey with a budget of US$3.50 MM. Due to the enforcement of Force Majeure by the DOE which started at the end of Subphase 1 on December 27, 2015, no exploration work will be done in the block within the West Philippine Sea’s disputed waters until the Force Majeure is lifted.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

Philex Petroleum is the Operator of SC 75 with 50% participating interest, PNOC-EC with 35%, and PetroEnergy with 15%.

As a result of the loss of control, PetroWind was deconsolidated in the 2014 consolidated financial statements.

As of December 31, 2015, 2014 and 2013, the corresponding percentages of the Group’s participation in the various SC areas are as follows:

a) The Group derecognized the assets, liabilities, the carrying amount of the noncontrolling interest and cumulative translation differences recorded in equity as of February 14, 2014. Details 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

2015 2.525% 4.137% 16.667% 20.05% 2.000% 15.000%

2014 2.525% 1.034% 5.001% 4.012% 2.000% 15.000%

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

12. Investment in a Joint Venture The investment in a joint venture represents PetroGreen’s 40% interest in PetroWind. The joint venture is accounted for as a joint venture (Note 1). PetroWind was incorporated in the Philippines on March 6, 2013 as a wholly owned subsidiary of PetroGreen, primarily to carry on the general business of generating, transmitting and/or distributing power derived from renewable energy sources. On July 15, 2013, EEIPC subscribed to a 20% equity share in PetroWind. As discussed in Note 1, on November 21, 2013, PetroGreen and CapAsia entered into a Share Purchase Agreement (SPA) as to the sale of PetroGreen’s 40% equity share in PetroWind. As of December 31, 2013, PetroGreen still holds 80% equity share in PetroWind and accounted as a subsidiary in the 2013 consolidated financial statements. On February 14, 2014, PetroGreen received the payment from sale of the shares, and the Deed of Assignment, covering the transfer of shares from PetroGreen to CapAsia, was executed upon satisfactory completion of all the conditions precedent under the SPA. PetroGreen lost its control in PetroWind after the consummation of the SPA. Accordingly, PetroWind ceased as a subsidiary of PetroGreen (Note 2). Thereafter, PetroWind became a joint venture between PetroGreen, CapAsia and EEIPC by virtue of the SA signed between the three parties governing the manner of managing PetroWind (Notes 2 and 4).

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Cash and cash equivalents Receivables Advances Prepaid expenses and other current assets Property and equipment Other noncurrent assets Accounts and other payables Due to related parties Loans payable Noncontrolling interest Cumulative translation adjustment

$12,891,213 370 17,412,582 2,853,821 1,160,191 9,611 (120,090) (239,242) (22,143,288) (2,358,585) (46,353) $9,420,230

b) The Group recognized the fair value of the consideration received, the fair value of any investment retained and any surplus or deficit in the 2014 consolidated statement of income. Details are as follows: Fair value of the considerations received on the sale of 40% interest Fair value of 40% retained noncontrolling interest Carrying amount of 20% noncontrolling interest upon loss of control Carrying amount of PetroWind’s net assets upon loss of control Excess of fair value and proceeds over carrying amount Realized gain on sale of 40% retained interest Unrealized gain on remeasurement of 40% retained interest Share in deconsolidated retained earnings of a subsidiary Excess of fair value and proceeds over carrying amount

$8,014,928 22,570,048 2,383,169 32,968,145 (11,915,846) $21,052,299 $2,665,174 17,220,295 1,166,830 $21,052,299

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

The computation of remeasurement gain follows:

13. Investment Properties

Remeasured fair value of 40% retained noncontrolling interest upon loss of control Carrying amount of retained interest on investment in a joint venture Unrealized gain on remeasurement of 40% retained interest on investment

$22,570,048 5,349,753 $17,220,295

The realized gain on the sale follows: Proceeds from sale Carrying amount of the disposed 40% interest Realized gain on sale

$8,014,928 5,349,754 $2,665,174

The movements in the carrying value of the Group’s investment in joint venture in PetroWind in 2015 and 2014 follows: Balance at beginning of year Additional investment during the year Share in net income (loss) of a joint venture Translation adjustment Balance at end of year

2015 $27,630,596 680,833 241,481 (1,385,958) $27,166,952

2014 $22,570,048 5,303,110 (242,562) − $27,630,596

Selected financial information of PetroWind as of December 31, 2015 and 2014 follows: Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity

2015 $10,139,351 90,876,669 (20,344,934) (58,660,986) $22,010,100

2014 $8,007,859 67,192,375 (8,656,827) (43,995,826) $22,547,581

Summary of statement of income of PetroWind for the year ended December 31, 2015 and for the period February 15 to December 31, 2014 follows:

Revenue Cost and expenses Income (loss) before tax Tax expense Net income (loss) Group’s share of the net income (loss)

2015 $6,899,580 6,295,877 603,703 − $603,703 $241,481

2014 (Nine Months) $41,815 (648,219) (606,404) − ($606,404) ($242,562)

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GREENING POWER GENERATION 2015 ANNUAL REPORT

As of December 31, 2015 and 2014, this account consists of land and parking lot space (located in Tektite) with total carrying value of $31,417. The fair value of the investment properties of the Group amounted to $40,278 as of December 31, 2015 and 2014. 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, 2015 and 2014, 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 2015, 2014 and 2013. 14. Investment in Navy Road Development Corporation (NRDC) As of December 31, 2015 and 2014, this account consists of: Acquisition cost Advances

$260,388 54,032 314,420 314,420 $–

Less accumulated impairment loss

Investment in NRDC represents investment in subsidiary due to the Group’s 100% holdings in NRDC’s capital stock. Below is NRDC’s financial position as of December 31, 2015 and 2014: Current assets Noncurrent assets Allowance for impairment Total Assets/Net Assets

$− 366,193 (366,193) $–

As of December 31, 2015 and 2014, NRDC has not commenced commercial operations and has not incurred any expenses in 2015, 2014 and 2013. Management intends to liquidate NRDC and has provided full impairment loss on this investment.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

15. Other Noncurrent Assets 2015 $3,283,286 3,110,688 2,037,881 1,142,094 490,544 218,330 $10,282,823

Intangible assets Input VAT Prepaid rent - noncurrent portion Deferred development costs Restricted cash Others

2014 $54,392 2,814,295 2,275,917 24,043 259,318 12,390 $5,440,355

Intangible assets As of December 31, 2015, bulk of this account pertains to the acquired easement of right of way by PetroSolar amounting to $3.23 million. This also includes software used for the geological modeling of MGI field. Details follow:

Cost Balances at beginning of year Additions Effect of foreign currency translation Balances at end of year Accumulated Amortization Balances at beginning of year Amortization Effect of foreign currency translation Balances at end of year Net Book Values

Land Rights

2015 Software

Total

2014 Software

$− 3,232,673

$240,066 7,788

$240,066 3,240,461

$168,981 71,566

− 3,232,673 − − − − $3,232,673

(6,965) 240,889

(6,965) 3,473,562

(481) 240,066

185,673 9,551

113,640 72,716

(4,948) 190,276 $50,613

(4,948) 190,276 $3,283,286

(682) 185,674 $54,392

Land rights refers to grant of easement of right of way entered by PetroSolar to construct, operate, maintain, repair, replace and remove poles, wire, cables, apparatus, and equipment and such other apparatus and structures needed for the transmission line. Amortization expense charged to profit or loss follows: General and administrative expenses (Note 26) Cost of electricity sales (Note 25)

2015 $6,124 3,427 $9,551

2014 $12,306 58,396 $72,716

Input VAT The input VAT refers to the Group’s cumulative input VAT carryovers which will be utilized in future periods. Majority of the input VAT pertains to MGI. MGI is undergoing a VAT refund process covering the years 2011, 2012 and 2013 with a total amount of $2.26 million or P =106.53 million. These claims have now been elevated to the Court of tax Appeals of the Philippines.

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GREENING POWER GENERATION 2015 ANNUAL REPORT

Prepaid rent - noncurrent portion On April 23, 2012, MGI 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, MGI 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. Deferred development costs Deferred development costs pertain to the costs incurred for the 10MW Phase 2 project of MGI amounting $0.71 million and $0.02 million in 2015 and 2014, respectively, and development cost for the 50 MW Tarlac Solar Power Project amounting to $0.46 million in 2015. Restricted cash Restricted cash pertains to the Group’s share in the escrow fund to secure payment and discharge of the Group’s obligations and liabilities under the Floating Production Storage and Offloading (FPSO) contract. The amount for the share in escrow of the Groups’ obligation for the FPSO was deducted from the Group’s share on lifting proceeds during the first lifting made by Etame in November 2002 and will be paid back to the Group at the end of the contract which is in 2020. As of December 31, 2015 and December 31, 2014, the Group contributed its share in the abandonment of the Etame Marine Permit to the escrow fund amounting to $0.29 million and $0.20 million, respectively. Others This consists of prepaid expenses and security deposit. 16. Accounts Payable and Accrued Expenses Accounts payable Accrued interest payable Accrued expenses Withholding taxes payable Dividends payable Payables to related parties (Note 28) Others

2015 $16,462,406 1,240,442 461,540 351,555 221,151 − 58,627 $18,795,721

2014 $2,744,363 1,017,177 521,112 94,834 233,269 471,128 60,073 $5,141,956

Accounts payable consists of payable to suppliers and contractors that are currently involved in the development and construction of energy projects. Accrued interest payable pertains to accrual of interest on loans.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

Accrued expenses are as follows: Sick/vacation leaves Professional fees Utilities Government share (Note 25) Professional fees - related parties (Note 28) Others

2014 $153,945 69,080 92,959 161,164 3,757 40,207 $521,112

2015 $217,297 82,527 90,849 19,953 3,570 47,344 $461,540

Dividends payable pertain to unclaimed checks as of December 31, 2015 and 2014. 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, 2015 and 2014. For terms and condition on related party transactions, see Note 28. 17. Short-term and Long-term Loans Payable The Group’s loans payable pertains to loans availed by the Group. 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 Total Unarmortized deferred financing cost

2015 $16,646,026 106,952 16,539,074 101,205,990 2,034,622 99,171,368 $115,710,442 $2,141,574

2014 $16,734,730 55,580 16,679,150 46,000,511 1,030,596 44,969,915 $61,649,065 $1,086,176

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 annual 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. This loan was settled on July 19, 2015. On November 21, 2013, PetroEnergy entered into additional loan amounting to $4.5 million (P =200 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 two (2) years. This loan was settled on November 21, 2015.

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GREENING POWER GENERATION 2015 ANNUAL REPORT

On April 27, 2015, PetroEnergy entered into an Omnibus Credit Line Agreement with the Development bank of the Philippines which provides a credit facility in the principal amount not exceeding $9.3 million (P =420 million) with annual interest rate for the first period of 5.1509%, subject to re-pricing every quarter. On May 12, 2015, $1.3 million (P =60 million) was granted as first drawdown and on October 15, 2015, additional $1.91 million (P =90 million) was drawn from the credit facility. On July 20, 2015, PetroEnergy entered into an additional loan amounting to $2.5 million loan with various lenders with an interest rate of 3.9647% per annum. The loan is payable in two (2) years with maturity on July 19, 2017. On November 21, 2015, PetroEnergy entered into a $3.27 million (₱154 million) loan agreement 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 3 months in the last day of each threemonth period. The tenor of the loan is two (2) years, maturity is on November 21, 2017. PetroGreen’s short-term and long-term loans payable PetroGreen availed of a one-year unsecured credit line facility amounting to $2.64 million (P =124.5 million) on December 19, 2014 with various lenders at 5% annual interest payable every quarter. On December 19, 2015, $1.1 million (P =49 million) of the total facility was granted, and the remaining balance was released in January 2015. All of these loans were settled as of December 31, 2015. In November 2015, PetroGreen entered into a 5-year credit line facility with Chinabank in the amount of $10.62 million (P =500 million) with an anual interest rate of 5.24% subject to repricing and payable every October and April. As of December 31, 2015, $8.5 million (P =400 million) out of the total loan facility were granted. MGI’s long-term loans payable On September 26, 2011, MGI together with PNOC Renewables Corporation and Trans-Asia entered into a P =2.4 billion (or $54 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, 2015 and 2014 MGI has outstanding drawdowns of $43.7 million (or P =2.06 billion) and $54 million (or P =2.4 billion), respectively. 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 semi-annual principal payment will start in April 2015. Thus, the corresponding amount on the first two semi-annual payment is duly classified as current portion of the long term loan. 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, arranger’s fee and other costs directly attributable in obtaining the loan. As of December 31, 2015 and 2014, the portion pertaining to the drawn amount of the loan amounting to $2.14 million and $1.09 million is presented as deduction from the loans payable account and is amortized over the life of the loan using the effective interest rate method. Amortization of deferred costs will be

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

capitalized until all activities necessary to prepare the power plant for its intended use are substantially complete. Details of the Groups’ unamortized deferred financing costs 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

2015 $1,086,176

2014 $1,261,013

1,521,444 2,607,620 466,446 $2,141,174

171,697 1,432,710 346,534 $1,086,176

The amortization is recognized under “Interest expense” in the consolidated statements of income. Below are the accumulated borrowing costs of the Group as of December 31, 2015 and 2014: Interest on loans payable Balance at beginning of year Interest incurred during the year Balance at end of year Deferred financing cost Balance at beginning of year Amortization during the year Balance at end of year

2015

2014

$10,347,856 4,934,680 15,282,536

$5,823,670 4,524,186 10,347,856

648,712 487,511 1,136,223 $16,418,759

302,178 346,534 648,712 $10,996,568

The loan covenants covering the outstanding debt of MGI include, among others, maintenance of certain level of debt-to-equity and debt-service coverage ratios. As of December 31, 2015 and 2014, MGI is in compliance with the said loan covenants. PetroSolar’s loans payable Omnibus Loan and Security Agreement with PNB and DBP On November 12, 2015, the Company, together with PGEC and EEIPC, as third party mortgagors and pledgors, entered into a = P2.6 billion (or $55.25 million) Omnibus Loan and Security Agreement (OLSA) with PNB and DBP specifically to partially finance the design, development, procurement, construction, operation and maintenance of its Tarlac solar power project. As of December 31, 2015, the Company has outstanding drawdowns of P =2.49 billion (or $52.91 million). Total drawdowns during the year Less unamortized deferred financing cost Total Less current portion Noncurrent portion

$52,911,177 1,385,703 51,525,474 2,405,054 $49,120,420

PSC shall fully pay the Loan for the pro-rata account of each lender within twelve (12) years from and after the date of the initial drawdown immediately following the Loan Signing date, the payments to be made in every twenty-two (22) semi-annual principal installments commencing on the date the first anniversary of the initial drawdown ( the "Principal Amortization Date"), inclusive, for the avoidance of doubt, of a grace period of twelve (12) months from the initial

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GREENING POWER GENERATION 2015 ANNUAL REPORT

drawdown Date. Thus the corresponding amount on the first semi-annual payment is duly classified as current portion of the long-term loan. Deferred financing costs are incidental costs incurred in obtaining the loan, which include documentary stamp tax, transfer tax, chattel mortgage, real estate mortgage, professional fees, arranger’s fee and other out-of-pocket expenses. As of December 31, 2015, the portion pertaining to the drawn amount of the loan amounted to =66.06 million (or $1.40 million) are presented as deduction to the loans payable account and will P be amortized over the life of the loan using effective interest method. Amortization of deferred costs will be capitalized until all activities necessary to prepare the power plant for its intended use are substantially complete. Details of unamortized deferred financing costs follows: Deferred financing costs on loan drawn during the year Less amortization during the year Balance at end of year

$1,403,771 18,068 $1,385,703

Capitalized borrowing cost relating to finance charges incurred in the construction of the power plant amounted to $0.34 million (P =16.20) million in 2015. PSC pledged all of its property and equipment as collateral in connection with the loan. 18. Deposits for Future Stock Subscriptions Deposits for future stock subscriptions pertains to total consideration received from the noncontrolling interests in excess of the authorized capital of the entities within the Group, with the purpose of applying the same as payment for future issuance of shares. Details follow:

PetroGreen EEIPC MGI Trans-Asia PNOC-RC PetroSolar EEIPC

No. of shares

Subscription amount

25,583,147

$543,628

450,000 180,000

956,226 382,490

2,200,000 28,413,147

4,674,884 $6,557,228

As of December 31, 2015, the increase in authorized capital was not yet approved by the Philippine SEC, thus, the deposits were not classified as equity, in accordance with Philippine SEC Financial Reporting Bulletin No. 006 issued in January 2013.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

19. 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 and Geothermal field located in Sto. Tomas Batangas. Movements in this account follow: Balance at beginning of year Accretion expense Addition (Note 10) Translation adjustment Balance at end of year

2015 $608,542 140,635 357,770 (12,275) $1,094,672

2014 $328,389 50,900 229,253 − $608,542

The provision for the oilfields in Etame maintained the original discount rate at 15.50% for both years. PetroEnergy MGI

2015 $851,304 243,368 $1,094,672

2014 $379,289 229,253 $608,542

In 2015, the movement is attributable to change in estimate which resulted to adjustment of carrying amount of the obligation. 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 an increase in the book value of “Wells, platforms and other facilities” account under “Property, plant and equipment” in the consolidated statements of financial position (Note 10). The addition in 2014 pertains to provision for the present value of the future estimated costs of legal and constructive obligations to restore the Sto. Tomas geothermal site upon termination of the service contract. The provisions for the abandonment costs for Etame are expected to be settled in 2020, while for Avouma and Ebouri in 2022. 20. Derivative Liability On November 21, 2013, PetroGreen and CapAsia Asean Holdings Cooperatief U.A. (CapAsia) entered into a Share Purchase Agreement (SPA) which sets out the parties’ mutual agreement as to the sale of 2,375,000 shares in PetroWind held by PetroGreen, which is equivalent to 40% of the total issued and outstanding shares of PetroWind. Simultaneously on November 21, 2013, PetroGreen, EEIPC and CapAsia entered into a Shareholders’ Agreement (SA). The SA will govern their relationship as the shareholders of PetroWind as well as containing their respective rights and obligations in relation to PetroWind. Further, the SA contains provisions regarding voting requirements for relevant activities that require unanimous consent of all the parties.

*SGVFS016036* 96

GREENING POWER GENERATION 2015 ANNUAL REPORT

CapAsia was given full voting and economic rights as a 40% shareholder. On February 14, 2014, the Closing Date, PetroGreen lost its control on PetroWind as a result of its sale of the half of its 80% interest in PetroWind. The SA further provides call and put options. CapAsia Investor’s Put Option In the absence of a Liquidity Event by the sixth anniversary of the Closing Date, CapAsia Investor may at any point thereafter, by written notice (the “Put Notice”), requires PetroGreen or its designee to purchase all of its shares in PetroWind at a value that shall ensure CapAsia Investor an IRR of fifteen percent (15%) for its investment. PetroGreen’s Call Option In the absence of a Liquidity Event by the seventh anniversary of the Closing Date, PetroGreen may at any point thereafter, by written notice (the “Call Notice”), call upon CapAsia Investor to sell all of its common shares in PetroWind to PetroGreen or its designee at a value that shall ensure CapAsia Investor an IRR of twenty percent (20%) for its investment. Payoff Structure Upon exit of CapAsia Investor through a Liquidity Event, CapAsia Investor shall share the profit of the Investment with PetroGreen following the schedule below: (a) After CapAsia Investor has received an IRR of twenty percent (20%) on its Investment, PetroGreen shall receive twenty five percent (25%) of the profits from the Investment over an IRR of twenty percent (20%) and up to an IRR to CapAsia Investor of twenty five percent (25%). (b) After CapAsia Investor has received an IRR of twenty-five percent (25%) on its Investment, PetroGreen shall receive fifty percent (50%) of the profits from the Investment over an IRR of twenty-five percent (25%) and up to an IRR to CapAsia Investor of thirty percent (30%). (c) After CapAsia Investor has received an equity IRR of thirty percent (30%) on its Investment, PetroGreen shall receive seventy-five percent (75%) of the profits from the Investment over an IRR of thirty percent (30%). Movements in this account follow: Balance at beginning of year Unrealized loss on derivatives during the year Translation adjustment Balance at end of year

2015 $10,677,196 734,060 (555,270) $10,855,986

2014 $− 10,755,464 (78,268) $10,677,196

21. 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 Company to own and hold any mining, petroleum or renewable energy contract area. As of December 31, 2015, the total issued and subscribed capital stock of the Group is 99.76% Filipino and 0.24% non-Filipino as compared to December 31, 2014 wherein the total issued and subscribed capital stock of the Group is 99.68% Filipino and 0.32% non-Filipino.

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

As of December 31, 2014, the Parent Company’s capital stock consists of 330,000,000 authorized and 273,824,220 issued and outstanding common shares with par value of P =1 ($0.0224) per share. Total capital stock and additional paid-in capital amounted to $6.32 million and $25.24 million, respectively. On June 3, 2015, Securities and Exchange Commission approved the increase in authorized capital from 330,000,000 shares to 700,000,000 shares at = P1 par value per share. Out of the entire increase in the authorized capital stock, 136,912,110 common shares have been subscribed through the SRO on May 11 to 15, 2015. The subscription of 136,912,110 common shares amounted to $13.44 million, out of which additional paid-in capital amounted to $10.38 million. As of December 31, 2015, the Parent Company’s capital stock consists of 700,000,000 authorized and 410,736,330 issued and outstanding common shares with par value of P =1 ($0.0214) per share. Total capital stock and additional paid-in capital amounted to $9.391 million and $35.62 million, respectively. Capital Stock Balances at beginning of year Stock rights offering Balances at end of year

Number of shares 2014 2013 2015 273,824,220 273,824,220 273,824,220 − − 136,912,110 410,736,330 273,824,220 273,824,220

Additional paid-in capital

2015 $6,321,533 3,069,779 $9,391,312

Amount 2014 2013 $6,321,533 $6,321,533 − − $6,321,533 $6,321,533

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

273,824,220 136,912,110 410,736,330

P =4.38/share

May 11, 2016

Number of holders as of year-end

2,149 (26) 2,123 (10) 2,113 (41) 2,072 (29) 2,043 (15) 2,028

*SGVFS016036* 98

GREENING POWER GENERATION 2015 ANNUAL REPORT

2015

2014

2013

$−

$315,248

Unappropriated Retained Earnings Under the Tax Code of the Philippines, publicly listed companies are allowed to accumulate retained earnings in excess of capital stock and are exempt from improperly accumulated earnings tax. Nonetheless, retained earnings available for dividend declaration, after reconciling items, for the years ended December 31, 2015, 2014 and 2013 amounted to $13.09 million, $13.03 million and $11.10 million, respectively, which is below the paid-up capital of $45.01 million in 2015, $25.25 million in 2014 and 2013. The paid-up capital includes capital stock and additional paid-in capital. The accumulated earnings of a joint venture not declared as dividends are not available for dividend declaration of the Parent Company, unless these are declared. For the year ended December 31, 2015, the joint venture has accumulated losses amounting $11,081.

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.

The Group’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 Deduct: Movement December 31, 2014 Add (Deduct): 2:1 stock rights offering December 31, 2015

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.

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 Group has been approved by the BOD on the same date.

2014 2013 2015 $25,244,737 $25,244,737 $25,244,737 − − 10,375,851 $35,620,588 $25,244,737 $25,244,737

Balances at beginning of year Stock rights offering Balances at end of year

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

On February 19, 2013, the BOD approved additional appropriated retained earnings amounting to $1.09 million to cover for the Group’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, 2015 and 2014 amounted to $3.15 million. Further expansion of the said oilfield is on-going. There are no appropriations in 2015 and 2014. Equity Reserve As discussed in Note 1, on June 9, 2015, PetroEnergy sold its 10% interest in PetroGreen to EEIPC, bringing its ownership in PetroGreen from 100% to 90%. The transaction was accounted as an equity transaction since there was no change in control. The effect of change in the ownership interest in PetroGreen on the equity attributable to owners of PetroEnergy during the year is summarized as follows: Consideration received from non-controlling interest Carrying amount of non-controlling interest sold, net of related cost Excess of consideration received recognized in equity

$4,669,613 2,810,440 $1,859,173

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

At PetroEnergy’s separate financial statements, the gain from sale recognized in the statement of income amounted to $2.12 million in 2015. 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, 2015 and 2014, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity. As of December 31, 2015 and 2014, the Group’s sources of capital are as follows: 2015 $115,710,442 9,391,311 35,620,588 22,049,428 1,859,173 $184,630,942

Loans payable Capital stock Additional paid-in capital Retained earnings Equity reserve

2014 $61,649,065 6,321,533 25,244,737 19,369,221 − $112,584,556

The table below demonstrates the debt-to-equity ratio of the Group as of December 31, 2015, 2014 and 2013: Total debt Loans payable Accounts payable and accrued expenses Income tax payable Deposit for future stock subscription Asset retirement obligation Accrued retirement liability Derivative liability Deferred tax liabilities Other noncurrent liability Total equity Debt-to-equity ratio

2015

2014

2013

$115,710,442

$61,649,065

$59,452,637

18,795,721 −

5,141,956 477

3,944,717 772,479

6,557,228 1,094,672 66,019 10,855,986 1,624,496 48,406 $154,752,970 $82,377,570 1.88:1

− 608,542 69,374 10,677,196 5,128,494 − $83,275,104 $58,772,402 1.42:1

− 328,389 116,175 − − − $64,614,397 $50,954,244 1.27:1

22. 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 latest retirement valuation was issued on January 8, 2016. The Group’s fund is in the form of a trust being maintained by a trustee bank, Rizal Commercial Banking Corporation (RCBC). The fund has no investments in the Group’s equity as of December 31, 2015 and 2014. 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, 2015 and 2014 are as follows: 2015 $333,877 (267,858) $66,019

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

2014 $297,575 (228,201) $69,374

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 Demographic assumptions Experience adjustments Remeasurement losses/gains Contribution Foreign currency translation adjustments Balances at end of year

Present value of accrued retirement liability $297,575 47,776 13,776 61,552

2015 Fair value of plan assets $228,201 − 10,564 10,564

(12,493) 1,803 1,990 (8,700) −

(5,586) − − (5,586) 45,913

(16,550) $333,877

(11,234) $267,858

Accrued retirement liability $69,374 47,776 3,212 50,988 (6,907) 1,803 1,990 (3,114) (45,913) (5,316) $66,019

Based on the Group’s assessment, the capital management objectives were met in 2015, 2014 and 2013.

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GREENING POWER GENERATION 2015 ANNUAL REPORT

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

101

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

Present value of accrued retirement liability $254,766 51,168 11,414 62,582

2014 Fair value of plan assets $138,591 − 6,209 6,209

(6,635) (10,977) (17,612) −

(4,531) − (4,531) 89,594

(2,161) $297,575

(1,662) $228,201

Accrued retirement liability $116,175 51,168 5,205 56,373 (2,104) (10,977) (13,081) (89,594) (499) $69,374

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

2015 $46,434 114,216 107,477 (269) $267,858

2014 $99,697 127,359 1,502 (357) $228,201

Discount rate Salary rate

Shown below is the maturity analysis of the undiscounted benefit payments as of December 31, 2015 and 2014: 2015 $28,465 125,027 242,370 124,986 2,669,611 1,832,359

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

2014 $33,633 104,997 269,903 127,539 502,350 1,869,782

The Group expects to contribute to the fund the amount of $50,322 in 2016.

2015

2014

6.67% 6.67%

4.71% 5.10%

4.48% 4.71%

Current Deferred

*SGVFS016036*

2015 $39,958 (3,472,893) ($3,432,935)

2014 $749,464 5,219,308 $5,968,772

2013 $1,852,088 (88,516) $1,763,572

The components of the Group’s net deferred tax assets (liabilities) are as follows: PetroEnergy Deferred tax assets on: Asset retirement obligation Unrealized foreign exchange loss Accrued retirement liability Provision for probable losses Accrued profit share Deferred tax liability on oil revenue Deferred tax assets - net

GREENING POWER GENERATION 2015 ANNUAL REPORT

Effect on defined benefits obligation ($14,399) 15,779 30,789 (26,185)

The provision for (benefit from) income tax consists of:

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

102

Increase (decrease) +0.5% -0.5% +1.0% -1.0%

23. Income Tax

The actual return on plan assets amounted to $4,978 and $1,678 for the years ended December 31, 2015 and 2014, respectively.

Rate of increase in salaries Beginning Ending Discount rate Beginning Ending

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, 2015, assuming all other assumptions were held constant:

2015 $238,731 48,719 32,034 19,026 7,327 345,837 (38,927) $306,910

2014 $205,005 17,182 37,235 19,026 53,055 331,503 (129,467) $202,036

*SGVFS016036* PETROENERGY RESOURCES CORPORATION

103

PetroGreen Deferred tax liabilities on unrealized gain on remeasurement of investment in PetroWind

2015

2014

$1,624,496

$5,128,494

As of December 31, 2015 and 2014, the Group did not recognize deferred tax assets on NOLCO amounting $0.25 million and $0.58 million, respectively, and MCIT amounting to $0.04 million and $0.01 million, respectively. 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 NOLCO are as follows: PetroEnergy Year Incurred 2015

In PHP =61,855,966 P

In USD $1,153,640

Used/Expired $−

Balance Available Until $‒ 2018

PetroGreen Year Incurred 2012 2014 2015

In PHP =19,753,890 P 31,239,999 15,875,290 =66,869,179 P

In USD $481,215 703,690 348,921 $1,533,826

Used/Expired $481,215 ‒ − $481,215

Balance Available Until 2015 $− 2017 703,690 348,921 2018 $1,052,611

In PHP =53,920,047 P

In USD $1,214,552

Used/Expired $‒

Balance Available Until $1,214,552 2016

MGI Year Incurred 2013

Details of the MCIT are as follows: PetroEnergy Year Incurred 2015

In PHP =1,338,437 P

In USD $28,441

Used/Expired $−

Balance Available Until $28,441 2018

In PHP P40,520 = 485,853 =526,373 P

In USD $913 10,678 $11,591

Used/Expired $‒ − $−

Balance Available Until $913 2017 10,678 2018 $11,591

PetroGreen Year Incurred 2014 2015

(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. For PSC, on July 28, 2015, the PSC registered with PEZA as an Economic Zone Utilities Enterprise to establish, operate and maintain its 50MW Solar Facility project at the Central Technopark and the sale of electricity in accordance with the representations, commitments and proposals set forth in its application. PSC shall pay the special tax rate of 5% on its gross income earned from sources within the PEZA economic zone in lieu of paying all national and local income taxes. Gross income earned refers to gross sales derived from any business activity, net of returns, discounts and allowances, less cost of sales, cost of production and allowable expenses as defined by PEZA. Income generated from sources outside of the PEZA economic zone shall be subject to regular corporate income taxes. All other income outside the RE and PEZA regulations are subject to the RCIT rate of 30%. 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: Nondeductible expenses Unrealized gain on FVPL Income subjected to final tax Unrealized foreign exchange gain Movement in unrecognized deferred tax assets Capital gains subjected to final tax Loss from entities subjected to lower rate Others Effective income tax rate

2015 30.00%

2014 30.00%

2013 30.00%

18.88 (0.03) (1.93)

20.58 (0.05) (0.12)

2.86 (0.06) (0.61)

4.33

(0.19)

(1.62)

11.50

(0.69)

8.27

(50.80)

(5.09)

−

(104.56) (199.27) (291.88%)

(6.92) 0.45 37.97%

10.27 4.54 53.65%

Others includes the effect of the change on the tax rate on investment in shares remeasured at fair value (Note 12).

For MGI, 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

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26. General and Administrative Expenses

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

2015

2014

2013

$3,127,198 908,893 6,048 197,318 $4,239,457

$3,862,795 960,032 6,071 303,430 $5,132,328

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

2015 $2,739,419 1,341,440 1,289,795 1,000,404 249,639 222,706 167,620 69,750 32,314 $7,113,087

2014 $2,589,953 1,341,581 681,633 765,002 337,956 109,196 154,756 55,211 29,605 $6,064,893

25. Cost of Electricity Sales Depreciation and amortization (Notes 10 and 15) Purchased services and utilities Rental, insurance and taxes Personnel costs Materials and supplies Repairs and maintenance Business and related expenses Government share Royalty fees

Based on Energy Regulation 1-94, all power producer shall set aside one-centavo per kilowatthour (₱0.01/kwh) of the total electricity sales of the energy-generating facility which shall be applied to Generation Facilities and/or energy resource development projects located in all barangays, municipalities, cities, provinces and regions. MGI recognized royalty fee amounting $32,314 and $55,211 in 2015 and 2014, respectively. Under the GRESC No. 2010-02-012, the RE Developer shall pay the government share equivalent to one and a half percent (1.5%) from the sale of geothermal steam produced and such other income incidental to and arising from generation, transmission and sale of electric power generated from geothermal energy within the Contract Area less costs and expenses incurred thereon. MGI recognized government share amounting to $69,750 and $29,605 in 2015 and 2014, respectively. Electricity sales only started in 2014 (Note 10).

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Salaries, wages and benefits (Notes 19 and 22) Taxes and licenses Stock transfer fees Professional and other fees Depreciation and amortization (Notes 10 and 15) Research costs Rent expense Transportation and travel Insurance Entertainment, amusement and recreation (EAR) Utilities Communication Training and seminar Condominium dues Repairs and maintenance Donation and contribution Security and janitorial services Gasoline, oil and lubricants Business meetings Other services Fringe benefit tax Office supplies Dues and subscriptions Advertisement Environmental and social expenses Others

2015

2014

2013

$1,163,940 758,666 393,332 298,991

$1,168,545 497,329 10,155 274,439

$1,405,082 405,265 12,448 210,624

283,073 137,289 127,090 125,620 90,437

326,545 22,305 118,600 139,492 99,326

299,315 156,933 128,192 149,677 90,373

63,316 44,646 43,583 40,024 39,695 33,339 31,951 31,855 31,649 30,857 25,616 16,371 29,673 9,164 8,784

48,139 52,291 45,986 32,975 38,523 23,889 56,839 55,073 43,207 43,839 13,729 17,099 35,243 5,900 16,151

72,648 67,173 58,071 12,419 41,466 45,247 83,960 161,582 70,320 38,306 6,226 18,012 58,635 8,646 15,776

− 52,121 $3,911,082

11,695 79,589 $3,276,903

22,797 44,629 $3,683,822

Others pertain to miscellaneous expenses such as development assistance, notarization, bank charges, fringe benefit taxes 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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1.12% interest. These loans have been fully paid as of December 31, 2015 and 2014.

27. Miscellaneous Income 2014 $208,679 19,307 2,059 13,192 − $243,237

2015 $189,532 17,269 1,704 − 3,133 $211,638

Management income (Note 28) Rental income Dividend income Gain (loss) on sale of equipment Others

2013 $− − 5,128 − 1,633 $6,761

d. PetroWind availed of a $3.5 million loan from PetroEnergy on December 13, 2013 payable on February 13, 2014 at an annual interest rate of 5.5%. There is no outstanding balance of loan as of December 31, 2014. In March 2015, PWEI availed of a = P20 million (or $0.42 million) loan from PGEC at 5.6% annual interest payable in June 2016. On May 4, 2015, PWEI availed of an additional loan from PERC amounting = P 20 million (or $0.42 million) payable in May 2016 at annual interest rate of 6.104%.

Management income refers to administrative fees billed by PetroEnergy to PetroWind. For the terms and condition of related party transactions, see Note 28. 28. 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 Affiliate EEI Corporation EPC - Advances EPC - Accounts payable HI Loans payable Interest expense Internal audit services Joint Venture PetroWind Due from PetroWind Interest income Management income Advances

Transactions for the Years Ended December 31 2014 2015

Outstanding Balance Receivables (Payables) 2014 2015

$− − −

$48,355 – 48,355

$– – –

700,000 3,267

600,000 1,321

− −

14,770 718,037

15,027 616,348

(3,570) (3,570)

849,979 29,803 189,532

− 23,205 208,679

849,979 29,803 −

5,390 1,074,704 $1,792,741

163,176 395,060 $1,059,763

− 879,782 $876,212

$119,845 (471,128) (351,283) – − (3,757) (3,757) – − − – – ($355,040)

Terms and Conditions Note a Note a Note b Note b Note c

Note d Note d Note e Note f

On September 2, 2011, Maibarara engaged EEI Corporation for the Engineering, Procurement and Construction of the MGPP. Contact price is approximately $37 million (₱1.6 billion). Total payment made amounted to $35.9 million (₱1.5 billion). As of December 31, 2015 and 2014, the contract is 100% complete. These are non-interest bearing and payable in 30 days.

b. PetroEnergy availed of a $0.60 million loan from House of Investments, Inc. (HI) on October 1, 2014, payable on December 22, 2014 at an annual interest rate of 0.98%. On July 19, 2015, PERC availed of a $0.70 million loan from HI, payable on December 9, 2015 at

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PetroEnergy has engaged HI to perform internal audit services on PetroEnergy. HI charges retainer fee of = P56,000 ($1,189) per month totaling to P =0.67 million or $14,770 per annum.

Management income refers to timewriting charges, management fees for accounting, legal, management and other support services rendered by PetroEnergy and PetroGreen to PetroWind.

Advances are minimal reimbursement of costs and expenses.

Terms and conditions of transactions with related parties Outstanding balances at year-end are unsecured, interest-free and settlement occurs in cash. There have been no guarantees provided or received for any related party receivables or payables. The Group has not recognized any impairment on amounts due from affiliated companies for the years ended December 31, 2015 and 2014. This assessment is undertaken each financial year through a review of the financial position of the related party and the market in which the related party operates. Compensation of Key Management Personnel The Group has a profit-sharing plan for directors, officers, managers and employees as indicated in its by-laws. The amount, the manner and occasion of distribution is at the discretion of the BOD, provided that profit share shall not exceed 5% of the audited income before income tax and profit share. The remuneration of the Group’s directors and other members of key management are as follows: Salaries and wages and other short-term benefits (Note 26) Directors’ fees (Note 26) Retirement expense (Notes 22 and 26)

2015

2014

2013

$320,586 90,578

$389,256 192,307

$364,776 145,442

29,071 $440,235

32,141 $613,704

20,993 $531,211

29. 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.

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Categories and Fair Values of Financial Instruments As of December 31, 2015 and 2014, the carrying amounts of the Group’s financial assets and financial liabilities approximate their fair values except for loans payable. The fair value of the loans payable as of December 31, 2015 and 2014 amounted to $126.59 million and $61.65 million compared to its carrying value of $115.71 million and $61.65 million, respectively.

The following tables show financial instruments recognized at fair value as of December 31, 2015 and 2014. The fair value is based on the source of valuation as outlined below:

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

Cash and cash equivalents and Receivables

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

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).

Equity securities

Fair values are based on published quoted prices.

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

Debt securities and Golf club shares

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

Investment properties Derivative liability

Investment properties

Fair values are based on the recent sales of similar properties in the same area.

Accounts payable and accrued expenses

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

Loans payable

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 2015 and 2014 for the 5 year tenor loans is derived using the projected T-Bond coupon rate of 4.519% and 3.002%, respectively, plus 3.202% credit spread for the first five years and 4.303% for the second five years. The fair value of the 22 year tenor loan is derived using the projected T-Bond coupon rate of 4.640% plus 2.250 credit spread. For the two loans with 2-year tenor, 2015 and 2014 fair value is derived using the treasury rate of 3.892% plus a credit spreads of 0.073% and 1.648%, respectively.

Derivative liability

Fair value is estimated using a modified binomial options pricing model which consists of two parts: the price tree and the backwards induction tree.

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

Level 1

Level 2

2015 Level 3

Fair Value

$144,118 12,113 $156,231 − −

$− − − 40,278 −

$− − − − 10,855,986

$144,118 12,113 156,231 40,278 10,855,986

Level 1

Level 2

2014 Level 3

Fair Value

$150,306 12,746 163,052 − −

$− − − 40,278 −

$− − − − 10,677,196

$150,306 12,746 163,052 40,278 10,677,196

In 2015 and 2014, there were no transfers of financial instruments among all levels. Derivative Financial Instruments The combined fair value of the options is estimated using a modified binomial options pricing model which consists of two parts: the price tree and the backwards induction tree. Under a riskneutral assumption, the price tree is used to predict the potential upward and downward movements of the company value as of valuation date. The backwards induction tree is used to compute the value of the options given the predicted values in the price tree. The backwards induction tree is modified to incorporate several assumptions that are based on management's judgment and expectations. These assumptions are as follows: (a) (b) (c) (d)

The projected offer price is the book value of PetroWind at 5th year (2020). PetroWind share price volatility is assumed at 30%. There will be no dividend declaration for the 6-year projection. 40% probability of liquidity event

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Description of significant unobservable inputs to valuation The significant unobservable inputs used in the fair value measurement categorized within Level 3 of the fair value hierarchy together with a quantitative sensitivity analysis as at December 31, 2015 and 2014 are as shown below:

Derivative liability

Valuation technique Modified binomial model

Significant unobservable inputs Probability of liquidity event until 2020

Projected spot price

Volatility

Base assumption 40%

Sensitivity of the input to fair value If the probability is increased by 5%, the derivative liability will decline by 8.5%; if the probability is decreased by 5%, the derivative liability will be up by 8.5%

The spot price is based on the projected discounted cash flow (DCF) of PetroWind

If the spot price is increased by 5%, the derivative liability will decline by 3.8%; if the spot price is decreased by 5%, the derivative liability will be up by 5.2%

30%

If volatility is increased by 10%, the derivative liability will increase by 1.4%; if the volatility is decreased by 10%, the derivative liability will decrease by 1.6%

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. 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 shortterm and long-term funding requirements, the Group intends to use internally generated funds as well as to obtain loan from financial institutions.

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The tables below summarize the maturity profile of the Group’s financial assets and financial liabilities as of December 31, 2015 and 2014 based on contractual payments:

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Short-term investments Accounts receivable: Consortium operator Electricity sales to Trans-Asia Receivable from affiliate 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 Electricity sales to Trans-Asia 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)

On demand

Less than 6 months

2015 6 months to 12 months

More than 12 months

Total

$156,231

$−

$156,231

14,714,797 −

17,821,808 −

− −

32,536,605 −

975,511

−

975,511

1,726,101 − 3,752 6,727 − $17,583,119

− − − − 3,815,197 $21,637,005

− 879,782 − − − $879,782

− − − 490,544 $490,544

1,726,101 879,782 3,752 6,727 4,305,741 $40,590,450

$16,462,406 − − 221,151

$16,539,074 − 461,540 1,240,442 −

$− − − − −

$99,171,368 − − − −

$115,710,442 16,462,406 461,540 1,240,442 221,151

48,231 10,396 $16,742,184 $840,935

− − $18,241,056 $3,395,949

− − $− $879,782

− − $99,171,368 ($98,680,824)

48,231 10,396 $134,154,608 ($93,564,158)

On demand

Less than 6 months

2014 6 months to 12 months

More than 12 months

Total

$163,052

$−

$163,052

1,178,374 −

1,639,780 −

− 186,513

− −

2,818,154 186,513

1,712,783

−

1,712,783

1,815,322 40,929 2,574 − $4,913,034

− − − 1,989,468 $3,629,248

− − − − $186,513

− − − 259,318 $259,318

1,815,322 40,929 2,574 2,248,786 $8,988,113

$− 3,215,491 − − 233,269

$16,679,150 − 521,112 1,017,177 −

$− − − − −

$44,969,915 − − − −

$61,649,065 3,215,491 521,112 1,017,177 233,269

50,754 104,153 3,603,667 $1,309,367

− − 18,217,438 ($14,588,190)

− − 44,969,915 ($44,710,597)

50,754 104,153 66,791,021 ($57,802,908)

− − − $186,513

The bulk of the loans payable will be settled from the proceeds from electricity sales.

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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.

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.

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.

Increase/decrease in Php rate +1.08% -1.08%

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

2015 Impact on income before tax % Increase Decrease 7.87% $11,685 ($11,685) 9.42% 1,201 (1,201) $12,886 ($12,886) 2014 Impact on income before tax % Increase Decrease 4.39% $6,649 ($6,649) 5.00% 687 (687) $7,336 ($7,336)

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.

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Increase/decrease in Php rate +0.27% -0.27%

2015

2014

Impact on income before tax $97,218 (97,218) Impact on income before tax $11,576 (11,576)

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 loans payable and derivative liability. 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. Loans payable Increase/decrease in interest rate (in basis points) +46 -46 Increase/decrease in interest rate (in basis points) +25 -25

2015

2014

Impact on income before tax ($1,700,722) 1,700,722 Impact on income before tax ($439,974) 439,974

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Derivative liability Increase/decrease in interest rate (in basis points) +5 -5 Increase/decrease in interest rate (in basis points) +5 -5

2015

2014

The Group determines the credit quality by class for loan-related consolidated statements of financial position lines based on the following: Impact on income before tax $21,792 (21,747)

Cash in banks and short-term investments - based on the nature of the counterparties and the reputation of the financial institution.

Impact on income before tax $288,982 (165,671)

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, 2015 and 2014:

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.

There is no other impact on the Group’s equity other than those already affecting income before income 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, 2015 and 2014: Financial assets at FVPL: Marketable equity securities Golf club shares Loans and receivables: Short-term investments Cash in bank Accounts receivable: Consortium operator Electricity sales to Trans-Asia Receivable from affiliate Others Interest receivable Restricted cash

2015

2014

$144,118 12,113

$150,306 12,746

17,821,808 14,710,421

1,826,293 1,175,051

1,032,511 1,726,101 879,782 3,752 6,727 4,305,741 $40,643,074

1,772,766 1,815,322 − 40,929 2,574 2,248,785 $9,044,772

Cash in banks Short-term investments Accounts receivable: Consortium operator Electricity sales to Trans-Asia Receivable from affiliate Others Interest receivable Restricted cash

Cash in banks Short-term investments Accounts receivable: Consortium operator Electricity sales to Trans-Asia Others Interest receivable Restricted cash

2015 Neither past due nor impaired Past due High grade Standard grade and impaired $14,710,421 $− $− 17,821,808 − −

Total $14,710,421 17,821,808

975,511

−

57,000

1,032,511

1,726,101

−

1,726,101

879,782 3,752 6,727 4,305,741 $40,429,843

− − − − $−

− − − − $57,000

879,782 3,752 6,727 4,305,741 $40,486,843

2014 Neither past due nor impaired Past due High grade Standard grade and impaired $1,175,051 $‒ $‒ 1,826,293 ‒ ‒

Total $1,175,051 1,826,293

1,712,783

‒

59,983

1,772,766

1,815,322 40,929 2,574 2,248,785 $8,821,737

‒ ‒ ‒ ‒ $‒

‒ ‒ ‒ ‒ $59,983

1,815,322 40,929 2,574 2,248,785 $8,881,720

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.

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The tables below show the aging analysis of the Group’s receivables as of December 31, 2015 and 2014.

Accounts receivable Consortium operator Trans-Asia Receivable from affiliate Others Interest receivable

Accounts receivable Consortium operator Trans-Asia Others Interest receivable

1 to 90 days

2015 Over 90 days

Total

$975,511 1,726,101 879,782 3,752 6,727 $3,591,873

$57,000 − − − − $57,000

$1,032,511 1,726,101 879,782 3,752 6,727 $3,648,873

1 to 90 days

2014 Over 90 days

$1,712,783 1,815,322 40,929 2,574 $3,571,608

$59,983 ‒ ‒ ‒ $59,983

Total $1,772,766 1,815,322` 40,929 2,574 $3,631,591

As of December 31, 2015 and 2014, 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. 30. Segment Information For management purposes, the Group is organized into business units based on their products and has five reportable segments as follows: · · ·

· ·

The oil production segment is engaged in the oil and mineral exploration, development and production. The geothermal energy segment develops and operates geothermal steamfields and power plants. The wind energy segment carries out the general business of generating, transmitting, and/or distributing power derived from wind energy sources. Starting 2015, this was not presented as operating segment as this became a joint venture in 2014. The Group take up its share in net earnings of PetroWind and presents it the consolidated statements of income under “Share in net income (loss) of a joint venture”. The solar energy segment carries out solar energy operations of the Group. Other activities pertain to research and investment activities.

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 (loss) Other Information: Segment assets except deferred tax assets Deferred tax assets - net Segment liabilities except deferred tax liabilities Deferred tax liabilities - net 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

Segment revenue Net income (loss) Other comprehensive income Other Information: Segment assets except deferred tax assets Deferred tax assets - net Segment liabilities except deferred tax liabilities Deferred tax liabilities - net 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

2015

Oil Production $6,574,675 227,167 2,179

Geothermal Energy $16,967,907 4,563,174 −

Solar Energy $− (402,956) −

Other Activities $− 2,268,310 −

$72,774,800 $306,910

$77,849,572 $−

$88,192,978 $−

$59,760,285 $−

($61,754,005) $236,823,630 $− $306,910

$11,108,496

$49,804,941

$28,625,871

($18,020,555) $153,128,474

$−

$81,609,721 $−

Elimination Consolidated $− $23,542,582 (2,046,625) 4,609,070 (2,284,665) (2,282,486)

$1,624,496

$−

$1,216,275 (9,918,071) 14,452,693 ($83,941) $1,390,775 ($15,919,839)

$5,789,670 (2,616,351) (3,222,425) $837 $1,443,891 $−

$16,167,879 (61,348,620) 69,123,049 $− $57,541,841 $−

($17,643,116)

($5,506,847)

($5,292)

Oil Production $11,132,670 1,996,773 9,157

Geothermal Energy $14,741,614 3,652,747 −

Wind Energy $− 690,448 −

$57,294,111 $202,036

$82,439,438 $−

$75,200,233 $−

$44,467,614 ($117,555,926) $− $−

$141,845,470 $202,036

$9,197,909

$57,569,946

$50,304,710

$6,279,628 ($45,205,583)

$78,146,610

$−

$4,068,580 $4,830,691 (2,338,194) (10,277,017) (2,264,582) 5,699,642 $795,556 $6,215 $199,408 $10,259,924 $19,112,571 $− $1,584,211

$2,647,015

($17,763,070) (31,214,932) 52,728,324 $− $20,947,065 $− $64,147

($4,296,558) $3,281,309 (13,077,844) 73,275,553 17,765,496 (100,628,567) ($3,349,831) $− $22,252 ($20,501) $− $−

$1,624,496

($56,720)

($3,844)

$22,158,575 (13,685,333) (2,509,754) ($3,432,935) $60,378,258 ($15,919,839) ($23,215,820)

2014

Other Activities $− 3,268,292 −

$5,128,494

Elimination $− 143,010 316,458

$−

$207,580 $25,835,904 1,384,439 28,760,371 (1,056,045) (57,617,097) $5,167,001 $− $9,482 ($20,955,849) $− $− $13,949

($70,965)

Consolidated $25,874,284 9,751,270 325,615

$5,128,494 $17,179,685 (13,685,333) (2,509,758) $5,968,772 $10,460,030 $19,112,571 $4,238,357

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

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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

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

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

Geothermal Energy $− (1,167,006) −

As of December 31, 2015, 2014 and 2013, the accumulated balances of and net loss attributable to noncontrolling interests are as follows:

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 $− $24,125,435 $−

($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 $25,317,818 $11,397,210

$1,633,213

$107,721

$7,051

$−

$1,747,985

Accumulated balances of noncontrolling interests: MGI PetroGreen PetroSolar PetroWind Net income (loss) attributable to noncontrolling interests: MGI PetroGreen PetroSolar PetroWind

Intercompany investments, revenues and expenses are eliminated during consolidation.

The computation of the Group’s earnings per share follows:

MGI

2015

2014

2013

$2,680,207 353,589,617 $0.00758

$8,489,385 273,824,220 $0.0310

$2,211,220 273,824,220 $0.00808

32. Noncontrolling Interests As of December 31, 2015, noncontrolling interest (NCI) pertains to the 10% shareholdings of EEIPC in PetroGreen, 35% shareholdings of Trans-Asia and PNOC in MGI and 44% shareholdings of EEI-PC in PetroSolar. As of December 31, 2014, NCI pertains to the 35% shareholdings of Trans-Asia and PNOC in MGI, while the noncontrolling interest in 2013 represents the 35% shareholdings of Trans-Asia and PNOC in MGI and 20% shareholdings of EEI-PC in PetroWind. MGI, PetroSolar and PetroWind are entities incorporated and are operating in the Philippines.

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2014

2013

$9,861,430 3,312,057 2,868,638 − $16,042,125

$8,679,634 − − − $8,679,634

$7,220,144 − − 2,456,332 $9,676,476

$1,597,111 509,053 (177,301) − $1,928,863

$1,278,461 − − (16,576) $1,261,885

($408,452) − − (279,358) ($687,810)

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.

31. Basic/Diluted Earnings Per Share

Net income attributable to equity holders of the Parent Company Weighted average number of shares Basic/diluted earnings per share

2015

Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statements of Income Revenue Expenses Net income (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

2015

2014

2013

=310,497,164 P 3,353,103,714 (652,960,361) (1,690,860,174) =1,319,780,343 P

=284,031,752 P 3,402,659,916 (553,221,209) (2,021,306,765) =1,112,163,694 P

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

P774,451,131 = (566,834,479) =207,616,652 P

P656,050,779 = (493,888,651) =162,162,128 P

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

P272,167,164 = (122,830,735) (151,647,313) (470,909)

P216,041,290 = (459,588,189) 254,888,000 (6,404)

(P =242,869,564) (967,320,634) 813,000,000 (849,289)

P =11,334,697

(P =398,039,487)

(P =2,781,793)

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PetroGreen

The 2015 financial information for PetroGreen follows: Statement of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statement of Income Revenue Expenses Benefit from income tax Net loss Statement of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Net increase in cash

=255,095,418 P 2,557,223,582 (439,610,963) (983,971,265) =1,388,736,772 P P24,405,703 = (73,613,085) 152,411,641 =103,204,259 P (P =202,196,030) (615,443,351) 836,044,260 =18,404,879 P

PetroSolar - Incorporated in 2015 The 2015 financial information for PetroSolar follows: Statement of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statement of Income Revenue Expenses Net loss Statement of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Net increase in cash

=1,261,266,540 P 2,889,095,008 (1,526,668,503) (2,313,884,988) =309,808,057 P P5,589,830 = (23,923,650) (P =18,333,820)

33. 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. =760,860,375 P (2,887,066,059) 3,252,930,689 =1,126,725,005 P

iv.

There were no dividends paid to noncontrolling interests. The increase in noncontrolling interests from stock issuances follows: · As of December 31, 2015 PetroSolar issued 3,300,000 common shares with P =100 par value. The issuances increased the noncontrolling interest by = P163.68 million, PetroGreen also issued 55,250,000 shares which increased the noncontrolling interest by = P5.53 million. · As of December 31, 2014, MGI issued 748,880 common shares with 100 par value. Such

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stock issuances increased the noncontrolling interests by = P26.21 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.

v. vi.

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

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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, 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. vii.

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. 34. 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.

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A more competitive power industry will in turn result in lower power rates and a more efficient delivery of electricity supply to end-users. Specifically, the EPIRA has the following objectives: · · · · ·

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

35. Commitments MGI 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 .

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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. 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. However, MGI has not closed a CER purchase agreement with Enel and the MOA which is valid for one year from the date of its signing, thus expired in 2014. 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 started on February 8, 2014 and pursuant to the ESA, all of MGI’s net capacity at delivery point in accordance with the electricity delivery procedures were sold to Trans-Asia through the electricity fees at the price agreed upon and subject to an adjustment starting on the second contract year, for charges on foreign exchange and inflation. Revenue from sale of electricity under the ESA amounted to $16.96 million or P =772.01 million in 2015. PSC Operating lease commitments – lessee On June 22, 2015, the Company (as assignee of PGEC) entered into a 25 year operating lease agreement with Luisita Industrial Park Corporation. The lease is renewable by mutual agreement of both parties generally under the same terms and conditions with escalation clause of 3% every 2 years. 36. Wind Energy Service Contract (WESC) On November 4, 2013, Development Bank of the Philippines (DBP) granted to PetroWind a P =2.8 billion loan for the project payable in 15 years. Following this, PetroWind 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 Corporation, and wind turbine supply, installation, and maintenance and operation with Gamesa Eolica of S.L. Unipersonal Spain. Construction of the Phase 1 of the wind farm (36 MW) started in December 2013 with EEI commencing with the project access road at entry point from the Provincial highway. The access roads were completed by 2nd quarter of 2014, while the internal roads for the first eight WTG (Wind Turbine Generator) towers were completed by 3rd quarter of the year. On December 19, 2014, PetroWind also obtained two (2) key approvals from Energy Regulatory Commission (ERC). ERC approved PetroWind’s application for a two-month testing and sales of generated power of the first eight (8) WTGs. PetroWind also received the approval to develop, own, and

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operate a dedicated point-to-point transmission facility connecting the Nabas Wind Farm to the NGCP’s Nabas-Caticlan 69 kV overhead transmission line. The first half of 2015 was devoted to completion of the construction of the wind farm in Nabas, Aklan. On March 24, 2015 PWEI successfully energized and dispatched power from eight (8) WTGs (WTG’s 1-8) to the Visayas grid. On April 17, 2015, the Department of Energy (DOE) issued its “Nomination for FIT Eligibility” of Nabas-1. The DOE also released on April 30, 2015, its Certificate of Endorsement of Nabas-1 which is one of the requirements for the ERC to process PWEI’s Certificate of Compliance (COC) for the power facility and for FIT eligibility. By June 2015, all eighteen (18) WTG’s become operational. On June 16, 2015, the Department of Energy (DOE) released the Certificate of Endorsement (COE) for FIT Eligibility endorsing the official start of commercial operation to be June 10, 2015. The Energy Regulatory Commission (ERC) also completed the site visit for DOE’s COE-FIT validation on June 24-25, 2015. On August 17, 2015, the ERC approved PWEI’s Certificate of Compliance (COC) for Phase 1. This confirms the commercial operation date of the wind farm to be June 10, 2015. On September 3, 2015, PWEI received the Philippine Electricity Market Corporation’s (PEMC) acknowledgement of PWEI’s participation in the Wholesale Electricity Spot Market (WESM). Upon reliably operating all eighteen (18) WTGs and accomplishing consolidation of approved punchlists and other prerequisite documentations, PWEI accepted the Wind Farm Turnover Certificate from Gamesa on December 12, 2015. From June 10 to December 31, 2015, the total energy exported to the grid is 42,285.41 MWh for the Project’s Phase 1, with revenue of PhP312.9 MM based on the FiT price of P =7.40 / kWh as stated in the COC-FiT issued by ERC on December 1, 2015. 37. Contracts and Agreements MGI 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 MGI on instances wherein the power plant encounters technical problems requiring Fuji’s assistance. 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. This was renewed in 2015.

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.

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On July 7, 2014, MGI, Trans-Asia and MERALCO signed a Memorandum of Agreement which effectively waived the payment for the wheeling charges amounting to $96,154 (₱4.30 million) per month. c.

d. Coordination Agreement On June 30, 2015, PetroGreen signed a Coordination Agreement with Phesco, Inc. and Conergy Asia & ME Pte Ltd. The Coordination Agreement provides that Phesco and Conergy are jointly and severally liable to PetroSolar for all the contractual payment obligations under the agreements for both the onshore and offshore work scopes, provided that PetroSolar should first exhaust all options to recover damages from the defaulting party before approaching the party that is not at fault. This contract was likewise assigned to PetroSolar on July 9, 2015.

MGI and FUJI signed on December 21, 2015 the contract for the manufacture and supply of the 12MW turbine, generator and other main equipment for the Maibarara 2 (M2) expansion project. The payment of the 10% down payment amounting to $1,055,600.00 was made on December 22, 2015. Under the contract, FUJI will manufacture the equipment within 15 months and deliver to MGI at CFR Manila on February 20, 2017. Installation of the equipment shall be supervised by Fuji including the commissioning of the M2 power plant to the grid.

The Company signed a Contract Agreement with Media Construction & Development Corporation on July 10, 2015 for the site development and civil works for the TSPP. The works shall be completed within five (5) months from the issuance of the Notice to Proceed and Construction Schedule. Total contract price is = P52.9 million.

PSC The following contracts have been entered into for the construction and development of the 50MW Tarlac Solar Power Project (TSPP): a.

Framework Agreement for the Owner’s Engineer Services

On June 25, 2015, PetroGreen entered into the Framework Agreement for Owner’s Engineer Services for the TSPP with Syntegra Solar International AG (Syntegra). Under this agreement, Syntegra shall provide engineering services covering the four project phases, from concept development, PV System Engineering, PV Power Plant Development and PV Power Plant Project Execution. Total contract price amounted to $1,500,000.

The agreement requires the posting of a payment bond as security for the obligation to pay the 90% balance of the Offshore Contract Price. On July 9, 2015, PetroGreen assigned this Offshore Supply Contract to PetroSolar. Following this assignment, PetroSolar obtained the required bond from Malayan Insurance Company, Inc. c.

Onshore Construction Contract On June 30, 2015, PetroGreen entered into an Onshore Construction Contract with Phesco, Inc. wherein Phesco shall install the imported solar power plant equipment, perform the electrical and mechanical works, procure local plant materials, and perform commissioning services. Total contract price amounted to P =247,950,000. The contract was assigned to PetroSolar on July 9, 2015.

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Design, Supply, Delivery, Installation, Test,/ Commission of Substation and Switching Station Equipment and Telecommunication Equipment including Civil Works & Construction of a 4 KM Dedicated 69KV Transmission Line for the 50MW Tarlac Solar Power Project Contract Agreement On July 9, 2015, PetroSolar Corporation entered into a Contract Agreement with Philcantech Enterprises wherein the works shall consist in the design, supply, delivery, erection, installation, test and commissioning of the substation and switching station equipment and telecommunication equipment including civil works and construction of a 4km dedicated 69kV Transmission Line for the 50MW Tarlac Solar Power Project. Total contract price amounted to = P163,000,000.

b. Offshore Supply Contract On June 30, 2015, PetroGreen entered into an Offshore Supply Contract with Conergy Asia & ME PTE LTD (Conergy) for the supply of all imported solar power plant equipment which is required for the construction of the TSPP. Total contract price amounted to $46,735,500 exclusive of Value Added Tax (VAT).

Civil Works for the 50MW Tarlac Solar Power Project Contract Agreement

Contract of Easement of Right-of-Way (RCBC) i. Rizal Commercial Banking Corporation On November 23, 2015, PetroSolar entered into a Contract of Easement of Right-of-Way with the Rizal Commercial Banking Corporation (RCBC). Under the agreement, for a period of twenty-five (25) years, RCBC shall allow PetroSolar to construct and maintain a 69kV transmission line along the edges of RCBC’s property within the Central Technopark Hacienda Luisita, Tarlac City. PetroSolar paid RCBC the amount of P =57,429,000 for the easement. ii. Tarlac Development Corporation On December 22, 2015, PetroSolar likewise entered into a 25-year Contract of Easement of Right-of-Way with Tarlac Development Corporation (TDC) covering TDC’s lots in Tarlac City for PetroSolar’s 69kV transmission line. The total consideration amounted to P =94,700,610.

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38. Reclassification of Accounts In 2014, capitalized development cost amounting P =33.74 million or $0.75 million for Maibarara Phase-1 was shown under “Intangible assets”. The 2014 capitalized development cost was reclassified to “Property, plant and equipment” (Note 10) to conform with the 2015 presentation of accounts. In 2014, overpayment of income taxes amounted to $0.65 million and was shown as part of “Other noncurrent assets”. The 2014 overpayment of income taxes was reclassified to “Other current assets” under “Prepaid taxes” (Note 9) to conform with the 2015 presentation of accounts. Management believes that the new presentation is more appropriate.

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On-going groundworks for 12 MW expansion of Maibarara Facility

CORPORATE DIRECTORY AUDITOR SGV & Co. 6760 Ayala Ave., Makati City BANKER Rizal Commercial Banking Corporation G/F Ortigas Malayan Plaza cor Opal Road ADB Avenue, Ortigas Business Center, Pasig City TRANSFER AGENT Rizal Commercial Banking Corporation G/F Grepalife Buidling, Gil J. Puyat Ave. Makati City Telephone Nos.: (632) 892-4156 / 892-1416 132

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CORPORATE OFFICE PetroEnergy Resources Corporation 7th Floor, JMT Corporate Building, ADB Avenue., Ortigas Business Center, Pasig City T: (632) 637-2917 / 637-5799 / 637-4032 / 637-4362 F: (632) 634-6066 / 633-8584 Email: petro_energy@petroenergy.com.ph Website: http://www.petroenergy.com.ph

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