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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

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 AUDITOR’S REPORT

INDEPENDENT AUDITOR’S REPORT The Board of Directors and Stockholders PetroEnergy Resources Corporation 7th Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City.

The Board of Directors and Stockholders PetroEnergy Resources Corporation 7th Floor, JMT Building, ADB Avenue, Opinion Ortigas Center, Pasig City.

We have audited the consolidated financial statements of PetroEnergy Resources Corporation and its subsidiaries (the Group), which comprise the consolidated statements of financial position as at December Opinion 31, 2016 and 2015, and the consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for each of the three years Wethe have audited theDecember consolidated of consolidated PetroEnergy financial Resources Corporation and its a in period ended 31, financial 2016, andstatements notes to the statements, including subsidiaries Group),accounting which comprise the consolidated statements of financial position as at summary of (the significant policies.

December 31, 2016 and 2015, and the consolidated statements of comprehensive income, consolidated In our opinion, the accompanying statements statements of changes in equity andconsolidated consolidatedfinancial statements of cash present flows forfairly, each in ofall thematerial three years respects, the consolidated financial position the Group as at December 31, 2016 and 2015, and its a in the period ended December 31, 2016, andof notes to the consolidated financial statements, including consolidated financial performance and its consolidated cash flows for each of the three years in the summary of significant accounting policies. period ended December 31, 2016 in accordance with Philippine Financial Reporting Standards In our opinion, the accompanying consolidated financial statements present fairly, in all material (PFRSs). respects, the consolidated financial position of the Group as at December 31, 2016 and 2015, and its consolidated financial performance and its consolidated cash flows for each of the three years in the Basis for Opinion period ended December 31, 2016 in accordance with Philippine Financial Reporting Standards (PFRSs).

We conducted our audits in accordance with Philippine Standards on Auditing (PSAs). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Basis of forthe Opinion Audit Consolidated Financial Statements section of our report. We are independent of the Group in accordance with the Code of Ethics for Professional Accountants in the Philippines (Code of We conducted audits in accordance with Philippine Standards on Auditing (PSAs).

Our Ethics) togetherour with the ethical requirements that are relevant to our audit of the consolidated responsibilities under those standards are further described in the Auditor’s Responsibilities financial statements in the Philippines, and we have fulfilled our other ethical responsibilitiesfor inthe Audit of the with Consolidated Financial and Statements section of ourWe report.

Wethat arethe independent of thewe accordance these requirements the Code of Ethics. believe audit evidence Groupobtained in accordance with the of Ethics Professional Accountants in the Philippines (Code of have is sufficient andCode appropriate to for provide a basis for our opinion.

Ethics) together with the ethical requirements that are relevant to our audit of the consolidated financial statements Emphasis of Matterin the Philippines, and we have fulfilled our other ethical responsibilities in accordance with these requirements and the Code of Ethics. We believe that the audit evidence we havedraw obtained is sufficient to provide a basis for our opinion.

We attention to Note and 10 ofappropriate the consolidated financial statements, which discusses the suspension of the production activities in the West Linapacan Oilfield. Among the other operations of the Group, Emphasis of Matter the suspension of the production activities in the West Linapacan Oilfield raises uncertainties as to the profitability of the petroleum operations for the said oilfield. The profitability of petroleum operations We draw to Noteis10dependent of the consolidated financial statements, whichquantities discussesthat the would suspension related to attention the said oilfield upon discovery of oil in commercial of the from production activitiesredevelopment in the West Linapacan the other Group, result the successful activitiesOilfield. thereon. Among Our opinion is notoperations qualified of in the respect of the suspension of the production activities in the West Linapacan Oilfield raises uncertainties as to the this matter. profitability of the petroleum operations for the said oilfield. The profitability of petroleum operations related to the said oilfield is dependent upon discovery of oil in commercial quantities that would result from the successful redevelopment activities thereon. Our opinion is not qualified in respect of this matter.

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Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the consolidated financial statements of the current period. These matters were addressed in theAudit context of our audit of the consolidated financial statements as a whole, and in forming our Key Matters opinion thereon, and we do not provide a separate opinion on these matters. For each matter below, Key audit matters are those matters that, in the our matter professional judgment, of most significance in our description of how our audit addressed is provided in thatwere context. our audit of the consolidated financial statements of the current period. These matters were addressed Wethe have fulfilled theaudit responsibilities describedfinancial in the Auditor’s Responsibilities forinthe Audit of in context of our of the consolidated statements as a whole, and forming ourthe Consolidated Financial section of our report, relationFor to these matters. opinion thereon, and we Statements do not provide a separate opinionincluding on these in matters. each matter below, our description ofaudit how our audit the addressed the matter is provided in that context.

Accordingly, our included performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit We have fulfilled the responsibilities described intothe Auditor’s Responsibilities for thethe Audit offor theour procedures, including the procedures performed address the matters below, provide basis Consolidated Financial Statements section of our report, including in relation to these matters. audit opinion on the accompanying consolidated financial statements.

Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risksof ofput material misstatement of the consolidated financial statements. The results of our audit Valuation and call option procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on accompanying financial statements.

The valuation of the PetroGreen Energyconsolidated Corporation’s (a subsidiary of PetroEnergy) derivative liability related to the put and call options on the share purchase agreement entered into with CapAsia ASEAN Valuation of putCooperatief and call option Wind Holdings U.A. over the investee Company, PetroWind Energy, Inc. (PetroWind) is based on certain assumptions and estimates. These include the probability of a liquidity event that will The valuation of PetroGreen Energy terminate the put and call options, theCorporation’s computation (a of subsidiary strike priceofatPetroEnergy) exercise date,derivative the futureliability related to the of putPetroWind, and call options onrisk the adjusted share purchase agreement witharea CapAsia ASEAN performance and the discount rate. Weentered focusedinto on this because of the Wind Holdingsjudgment Cooperatief U.A. over thevaluation. investee Company, Inc. (PetroWind) management’s involved in the The effect PetroWind on the 2016Energy, consolidated net income is of based on certain assumptions and estimates. include the probability a liquidity event the re-measurement of the derivative liability These amounted to $10.76 million. of See Note 19 of the that will terminate the financial put and call options, the computation of strike price at exercise date, the future consolidated statements. performance of PetroWind, and the risk adjusted discount rate. We focused on this area because of the management’s Audit response judgment involved in the valuation. The effect on the 2016 consolidated net income of the of the derivative amounted $10.76 valuation million. See Note We 19 of the We re-measurement assessed the valuation model usedliability by referencing to to common models. reviewed the consolidated financial statements. key inputs used in the valuation such as the probability of an event that will trigger the put or call, contractual cash flows, risk free rate, market beta and unquoted market prices by referencing to market Audit data onresponse valuation date. In addition, we involved our internal specialist in the review of the We assessed model used methodologythe andvaluation the assumptions used.by referencing to common valuation models. We reviewed the key inputs used in the valuation such as the probability of an event that will trigger the put or call, contractual risk free rate, market beta and unquoted market prices by referencing to market Estimation cash of oilflows, reserves data on valuation date. In addition, we involved our internal specialist in the review of the The estimatesand of oil gas reserves require significant judgment and use of assumptions by the methodology theand assumptions used. management including inputs from internal engineers. We focused on this area because these estimates have a material Estimation of oil reservesimpact on the consolidated financial statements, as these are utilized in testing impairment, calculating depreciation, depletion and amortization, and estimating The estimates of oil and gas reserves require significant judgment and use of assumptions by the decommissioning provisions. management including inputs from internal engineers. We focused on this area because these There is anhave inherent uncertainty in estimating reserve statements, quantities because theutilized complex estimates a material impactinvolved on the consolidated financial as theseofare in contractual arrangements detailing the Group’s share ofand reserves in Gabonand andestimating other local service testing impairment, calculating depreciation, depletion amortization, contracts over which the Company has participating interests. This uncertainty also depends on the decommissioning provisions. amount of reliable geologic and engineering data available at the time of the estimate and the There is an inherent uncertainty in estimating reserve becausefinancial of the complex interpretation of these data by theinvolved management.

See Note 10 ofquantities the consolidated statements. contractual arrangements detailing the Group’s share of reserves in Gabon and other local service contracts over which the Company has participating interests. This uncertainty also depends on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data by the management. See Note 10 of the consolidated financial statements.

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Audit response We reviewed the management’s estimation process, including the assumptions used in reference to the assumptions of third party estimates and tested the relevant controls. We performed an analysis of the changes in the current year reserves compared to the prior year and inquired of any changes in the Audit response underlying assumptions used. We evaluated the competence, capabilities and objectivity of the We reviewed the management’s including the assumptions in reference engineers engaged by the Group estimation to performprocess, an independent assessment of its oilused reserves.

We to the assumptions of third party estimates and tested the relevant controls.

We performed an analysis reviewed the specialist’s report and obtained an understanding of the nature, scope and objectivesofofthe changes thebasis current year reservesincluding comparedany to the prior in year inquired of any his workin and of the estimates changes theand reserves during thechanges year. in the underlying assumptions used. We evaluated the competence, capabilities and objectivity of the engineers the Groupobligations to perform an independent assessment of its oil reserves. We Estimationengaged of assetby retirement reviewed the specialist’s report and obtained an understanding of the nature, scope and objectives of his and basis of the estimates including any changes in the reserves obligations during the year.

Thework Group has provisions for close-down, restoration and environmental on its solar power plant in Tarlac, geothermal power plant in Batangas and interest in oil fields in Gabon. The calculation Estimation of assetrequires retirement of these provisions the obligations use of management judgment in estimating future costs given the nature of each site, the operating activities done, and the facilities constructed, among other The Group has provisions for close-down, and environmental obligationsrate on to its discount solar power considerations.

These calculations require restoration the management to assume a reasonable plant in Tarlac, geothermal power plant in Batangas and interest in oil fields in Gabon.

The calculation these future costs to present value at reporting date. of these provisions requires the use of management judgment in estimating future costs given the nature of each site, the activities done,and andenvironmental the facilities constructed, among other basis. The The Group reviews the operating close-down, restoration obligations on an annual considerations.

These calculations require the management to assume a reasonable rate to discount Group uses an external technical specialist to assess its share in abandonment cost in Gabon oil fields, these future costs to present value at reporting date. and an internal technical group to estimate the future restoration costs of its solar and geothermal power plants sites. Because of the judgment and subjectivity involved in the estimation process, we The Group this reviews close-down, restoration and environmental an annual basis. The considered to bethe a key audit matter.

As of December 31, 2016,obligations provisions on related to asset Group usesobligations an externaltotaled technical specialist assess its 18 share in abandonment cost in Gabon oil fields, retirement $1.37 million.to See Note to the consolidated financial statements. and an internal technical group to estimate the future restoration costs of its solar and geothermal power plants sites. Because of the judgment and subjectivity involved in the estimation process, we Audit response considered thisthe tomanagement’s be a key audit process matter. in Ascalculating of December 2016, provisions related to asset We reviewed the31, provisions for asset retirement obligation, retirement obligations totaled $1.37 million.

See Note 18 to the consolidated financial statements. and tested the relevant controls including changes in the said provisions in 2016. We reviewed and discussed with the management relevant documents and tested the amounts of the assumed restoration Audit response by comparing these to the report of the technical specialist. We reviewed the future and rehabilitation We management’s in calculating the provisions for asset retirement cost reviewed estimatesthe used in calculatingprocess the provision.

We assessed the competence, capabilitiesobligation, and and tested the relevant controls including changes in the said provisions in utilized 2016. We reviewed and objectivity of the management’s internal and external technical specialists to produce those discussed with the management relevant documents and tested the amounts of the assumed restoration cost estimates. and rehabilitation by comparing these to the report of the technical specialist. We reviewed the future cost estimates used in calculating the West provision. the competence, capabilities and Valuation of investments in Gabon, AfricaWe andassessed West Linapacan objectivity of the management’s internal and external technical specialists utilized to produce those cost estimates.

The Group has investments in Gabon, West Africa and West Linapacan included in ‘Wells, platforms and other facilities’ account under Property, plant and equipment which are tested for impairment Valuation Gabon, West Africa West Linapacan when thereof areinvestments indicationsin that the carrying valuesand of the investments may exceed recoverable amounts.

The Group has investments in Gabon, West Africa and West Linapacan included in ‘Wells, platforms andaccount other facilities’ account Property, plant andmanagement equipment which are tested for impairment On of the decline in under oil prices in 2016, which considered an impairment when there are indications that the carrying values of the investments may exceed recoverable indicator, the management performed an impairment test and, accordingly, recognized an impairment amounts. loss amounting to $8.83 million. The determination of the recoverable amounts of the assets being tested for impairment requires estimation involving the use of internal assumptions such as future On accountlevels of theand decline in and oil prices in 2016, which management considered an impairment production costs, external assumptions such as oil prices and discount rate. Because of indicator, the management performed anestimation impairmentprocess, test and,weaccordingly, the significant judgment involved in the considered recognized this to be a an keyimpairment audit loss amounting to $8.83 million.

The determination of the recoverable amounts of the assets being matter. See Note 10 of the consolidated financial statements. tested for impairment requires estimation involving the use of internal assumptions such as future production levels and costs, and external assumptions such as oil prices and discount rate. Because of the significant judgment involved in the estimation process, we considered this to be a key audit matter. See Note 10 of the consolidated financial statements.

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Audit response We obtained the management’s assessment of its investments’ recoverability through their discounted cash flow projections. In addition, we tested the assumptions used to compute value-in-use of each investment such as future cash flow projection, commodity prices, discount rates, and exchange rates.

Our Auditprocedures response also include comparing the assumptions used to those provided by third party estimates.

We inspected theassessment service contracts and relevantrecoverability joint operations agreements of each We obtained thealso management’s of its investments’ through their discounted exploration projects to In determine period over which the Group has the value-in-use right to explore in the cash flow projections. addition,that we the tested the assumptions used to compute of each specific areasuch has as notfuture expired and thatprojection, the Group commodity has rights and obligations contracts through investment cash flow prices, discountunder rates,the and exchange rates. participating interests.

We obtained the the latest management disclosures regarding status of their Our procedures also include comparing assumptions used to those provided bythe third party service contracts andinspected assessedthe theservice adequacy to support assessment of management regarding the estimates.

We also contracts and the relevant joint operations agreements of each recoverability of these involved our internal specialist thein the exploration projects to investments. determine thatWe thealso period over which the Group has theteam righttotoreview explore calculation thenot recoverable amounts ofGroup the investments of impairment testing. through specific areaofhas expired and that the has rights for andpurposes obligations under the contracts participating interests. We obtained the latest management disclosures regarding the status of their Other serviceInformation contracts and assessed the adequacy to support the assessment of management regarding the recoverability of these investments. We also involved our internal specialist team to review the Management responsible foramounts the otherofinformation.

Thefor other information comprises the calculation ofisthe recoverable the investments purposes of impairment testing. information included in the SEC Form 20-IS (Definitive Information Statement), SEC Form 17-A and Annual Report for the year ended December 31, 2016, but does not include the consolidated financial Other Information statements and our auditor’s report thereon. The SEC Form 20-IS (Definitive Information Statement), SEC Form 17-A and Annualfor Report for the year endedThe December 31, 2016 are expectedthe to be made Management is responsible the other information. other information comprises available to us after the of this auditor’s information included in date the SEC Form 20-IS report.

(Definitive Information Statement), SEC Form 17-A and Annual Report for the year ended December 31, 2016, but does not include the consolidated financial Our opinionand on our the auditor’s consolidated financial statements not20-IS cover(Definitive the other information we will statements report thereon.

The SECdoes Form Information and Statement), not express any form of assurance conclusion thereon.

SEC Form 17-A and Annual Report for the year ended December 31, 2016 are expected to be made available to us after the date of this auditor’s report.

In connection with our audits of the consolidated financial statements, our responsibility is to read the other information above when itstatements becomes available doing so,information consider whether Our opinion on theidentified consolidated financial does not and, coverinthe other and wethe will other information is materially inconsistent with the consolidated financial statements or our not express any form of assurance conclusion thereon. knowledge obtained in the audits, or otherwise appears to be materially misstated.

In connection with our audits of the consolidated financial statements, our responsibility is to read the Responsibilities Management Charged with Governance Consolidated other informationofidentified above and whenThose it becomes available and, in doingfor so, the consider whether the Financial Statements other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audits, or otherwise appears to be materially misstated.

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with PFRSs, for Charged such internal as management determines is Responsibilities of Management andand Those withcontrol Governance for the Consolidated necessary enable the preparation of consolidated financial statements that are free from material Financial to Statements misstatement, whether due to fraud or error.

Management is responsible for the preparation and fair presentation of the consolidated financial In preparinginthe consolidated statements, is responsible for assessing theis statements accordance withfinancial PFRSs, and for suchmanagement internal control as management determines Group’s ability to continue as a going concern, disclosing, as applicable, matters related to going necessary to enable the preparation of consolidated financial statements that are free from material concern and using the going misstatement, whether due toconcern fraud orbasis error.of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

In preparing the consolidated financial statements, management is responsible for assessing the Those charged governance are responsible for overseeing the Group’s financial reporting process.

Group’s abilitywith to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Group’s financial reporting process.

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ANNUAL REPORT 2016

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Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee an audit conducted accordance PSAs will Financial always detect a material misstatement Auditor’sthat Responsibilities for theinAudit of thewith Consolidated Statements whenobjectives it exists. are Misstatements can arise assurance from fraudabout or error and are material if, individually Our to obtain reasonable whether theconsidered consolidated financial statements or in the aggregate, they could reasonably be expected influence theoreconomic of auditor’s users as a whole are free from material misstatement, whethertodue to fraud error, anddecisions to issue an taken on basis ofour these consolidated financial statements. report thattheincludes opinion.

Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with PSAs will always detect a material misstatement As part an audit in accordance exercise professional judgmentmaterial and maintain when it of exists.

Misstatements canwith arisePSAs, from we fraud or error and are considered if, individually professional skepticism the audit.

We also:to influence the economic decisions of users or in the aggregate, theythroughout could reasonably be expected taken on the basis of these consolidated financial statements. · Identify and assess the risks of material misstatement of the consolidated financial statements, whether to in fraud or error,with design and we perform audit proceduresjudgment responsive to maintain those risks, and As part of andue audit accordance PSAs, exercise professional and obtain audit evidence that is sufficient andWe appropriate to provide a basis for our opinion. The risk professional skepticism throughout the audit. also: of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as and fraud may the involve intentional omissions, misrepresentations, or the · Identify assess riskscollusion, of materialforgery, misstatement of the consolidated financial statements, override of internal control. whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk · of Obtain an understanding internal control relevant to the audit in order to design not detecting a materialofmisstatement resulting from fraud is higher than for oneaudit resulting from procedures thatmay are involve appropriate in the circumstances, but not for the purpose of expressingoranthe error, as fraud collusion, forgery, intentional omissions, misrepresentations, opinion on effectiveness override of the internal control. of the Group’s internal control. · · · ·

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Evaluate appropriateness of accounting theinreasonableness accounting Obtain anthe understanding of internal control policies relevant used to theand audit order to designofaudit estimates and related disclosures made by management. procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control.

Conclude on the appropriateness of management’s use of the going concern basis of accounting and, basedtheonappropriateness the audit evidence obtained, whether material uncertainty exists related to events Evaluate of accounting policies aused and the reasonableness of accounting or conditions maydisclosures cast significant on the Group’s ability to continue as a going concern. estimates and that related madedoubt by management.

If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the disclosures inofthe consolidated use financial or, ifbasis suchof disclosures Conclude on related the appropriateness management’s of thestatements going concern accountingare inadequate, to the modify opinion.

Our conclusions baseduncertainty on the auditexists evidence obtained up and, based on auditour evidence obtained, whether a are material related to events to the date of that our auditor’s However, future events orability conditions may cause the Group to or conditions may cast report. significant doubt on the Group’s to continue as a going concern. cease to continue asaamaterial going concern.

If we conclude that uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are Evaluate thetooverall presentation, and content the consolidated inadequate, modify our opinion.structure Our conclusions areofbased on the audit financial evidence statements, obtained up including whether the consolidated financial statements to the datethe of disclosures, our auditor’sand report.

However, future events or conditions mayrepresent cause thethe Group to underlying transactions and events in a manner that achieves fair presentation. cease to continue as a going concern.

Obtain sufficient appropriate auditstructure evidenceand regarding financial information of the entities or Evaluate the overall presentation, contentthe of the consolidated financial statements, business activities within the to the express an opinion on the consolidated financialthe including the disclosures, andGroup whether consolidated financial statements represent statements. transactions We are responsible for in thea direction, supervision andpresentation. performance of the audit. We underlying and events manner that achieves fair remain solely responsible for our audit opinion.

Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the audit. We remain solely responsible for our audit opinion.

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We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We communicate also provide those with governance with a regarding, statement that we other have complied with relevant with charged those charged with governance among matters, the planned ethical requirements regarding independence, and to communicate with them all relationships and in scope and timing of the audit and significant audit findings, including any significant deficiencies other matters that may reasonably be thought to bear on our independence, and where applicable, internal control that we identify during our audit. related safeguards.

We also provide those charged with governance with a statement that we have complied with relevant From matters communicated with those charged governance, determine those matters ethicalthe requirements regarding independence, and to with communicate withwethem all relationships and that were most significance in the audit of the consolidated financial statements the current period other of matters that may reasonably be thought to bear on our independence, andofwhere applicable, and aresafeguards. therefore the key audit matters. We describe these matters in our auditor’s report unless law or related regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should notwith be communicated in our report because the adverse consequences From the matters communicated those charged with governance, we determine those matters that of doing so would reasonably be expected to outweigh the public interest benefits of such were of most significance in the audit of the consolidated financial statements of the current period communication. and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we The engagement partnershould on thenot audit in this in independent auditor’sthe report is John T. Villa. determine that a matter beresulting communicated our report because adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

SYCIP GORRES VELAYO & CO. The engagement partner on the audit resulting in this independent auditor’s report is John T. Villa.

SYCIP GORRES VELAYO & CO. John T. Villa Partner CPA Certificate No. 94065 SEC Accreditation No. 0783-AR-2 (Group A), 1, 2015, valid until April 30, 2018 JohnMay T. Villa Tax Identification No. 901-617-005 Partner BIR No. 08-001998-76-2015, CPAAccreditation Certificate No. 94065 February 27, 2015, valid until February 26, 2018 SEC Accreditation No. 0783-AR-2 (Group A), PTRMay No. 1, 5908775, January 2017, 2015, valid until3,April 30,Makati 2018 City Tax Identification No. 901-617-005 February 23, 2017 No. 08-001998-76-2015, BIR Accreditation February 27, 2015, valid until February 26, 2018 PTR No. 5908775, January 3, 2017, Makati City February 23, 2017

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ANNUAL REPORT 2016

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31 2015 2016 ASSETS Current Assets Cash and cash equivalents (Notes 6 and 27) Financial assets at fair value through profit or loss (Notes 7 and 27) Receivables (Notes 5, 8 and 27) Prepaid expenses and other current assets (Note 9) Total Current Assets Noncurrent Assets Property, plant and equipment (Notes 5 and 10) 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 21) Other noncurrent assets (Note 14) Total Noncurrent Assets TOTAL ASSETS

$12,914,588

$32,536,605

162,445 7,860,439 6,766,450 27,703,922

156,231 3,591,873 6,413,693 42,698,402

138,870,569 10,134,234 26,843,396 31,417 308,168 10,408,066 186,595,850 $214,299,772

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

$4,619,107 15,982,090 45,532 1,781,640 22,428,369

$18,795,721 16,539,074

99,505,183 1,366,511

99,171,368 1,094,672 10,855,986 1,624,496 114,425 112,860,947 154,752,970

LIABILITIES AND EQUITY Current Liabilities Accounts payable and accrued expenses (Notes 15 and 27) Current portion of loans payable (Notes 16 and 27) Income tax payable (Note 21) Deposits for future stock subscriptions (Note 17) Total Current Liabilities Noncurrent Liabilities Loans payable - net of current portion (Note 16 and 27) Asset retirement obligation (Notes 5 and 18) Derivative liability (Note 19) Deferred tax liabilities (Note 21) Other noncurrent liabilities Total Noncurrent Liabilities Total Liabilities

‒

1,537,586 183,148 102,592,428 125,020,797

‒

6,557,228 41,892,023

(Forward)

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December 31 2015 2016 Equity Attributable to equity holders of the Parent Company Capital stock (Note 20) Additional paid-in capital (Note 20) Retained earnings Appropriated (Note 20) Unappropriated Remeasurements of net accrued retirement liability Cumulative translation adjustment Equity reserve (Note 20) Noncontrolling interests (Note 30) Total Equity TOTAL LIABILITIES AND EQUITY

$9,391,311 35,620,588

$9,391,311 35,620,588

3,149,555 20,672,714 (17,136) (5,399,308) 1,859,173 65,276,897 24,002,078 89,278,975 $214,299,772

3,149,555 18,899,873 (36,227) (2,548,828) 1,859,173 66,335,445 16,042,125 82,377,570 $237,130,540

See accompanying Notes to Consolidated Financial Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

2016 REVENUES Electricity sales (Note 33) Oil revenues COST OF SALES Cost of electricity sales (Note 23) Oil production (Note 22) Depletion (Note 10) GROSS INCOME GENERAL AND ADMINISTRATIVE EXPENSES (Note 24) OTHER INCOME (CHARGES) - net Gain (loss) on derivatives (Note 19) Share in net income (loss) of a joint venture (Note 12) Interest income Net foreign exchange gains (losses) Net gain on fair value changes on financial assets at fair value through profit or loss (Note 7) Gain on disposal of investment (Note 12) Interest expense (Note 16) Impairment loss (Note 10) Accretion expense (Note 18) Miscellaneous income (Note 25) INCOME BEFORE INCOME TAX PROVISION FOR (BENEFIT FROM) INCOME TAX (Note 21)

Years Ended December 31 2015

2014

$28,290,322 5,339,338 33,629,660

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

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

12,199,861 3,704,709 2,795,358 18,699,928

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

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

14,929,732

10,508,420

13,271,421

3,217,253

3,911,082

3,276,903

(734,060) 241,481 112,537 (178,876)

(10,755,464) (242,562) 70,633 (93,661)

16,404 ‒ (9,076,674) (8,831,689) (156,955) 197,087 (5,636,616)

1,392 ‒ (4,934,680)

26,128 21,052,299 (4,524,186)

(140,635) 211,638 (5,421,203)

(50,900) 243,237 5,725,524

6,075,863

1,176,135

15,720,042

(3,432,935)

5,968,772 9,751,270

10,760,704 1,129,923 284,127 40,457

217,631

NET INCOME

5,858,232

4,609,070

OTHER COMPREHENSIVE INCOME (LOSS) Item to be reclassified to profit or loss in subsequent periods Movements in cumulative translation adjustment - net of tax

(3,440,181)

(2,284,665)

316,458

Item not to be reclassified to profit or loss in subsequent periods Remeasurement gains on net accrued retirement liability - net of tax TOTAL OTHER COMPREHENSIVE INCOME (LOSS)

19,091 (3,421,090)

2,179 (2,282,486)

9,157 325,615

TOTAL COMPREHENSIVE INCOME

$2,437,142

$2,326,584

$10,076,885

$0.0076

$0.0310

EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF THE PARENT COMPANY - BASIC AND DILUTED (Note 29)

$0.0043

(Forward)

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2016 NET INCOME ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 30) TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrolling interests (Note 30)

$1,772,841 4,085,391 $5,858,232

($1,058,548) 3,495,690 $2,437,142

Years Ended December 31 2015 $2,680,207 1,928,863 $4,609,070

$937,875 1,388,709 $2,326,584

2014

$8,489,385 1,261,885 $9,751,270

$8,815,000 1,261,885 $10,076,885

See accompanying Notes to Consolidated Financial Statements.

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PETROENERGY RESOURCES CORPORATION

58

$6,321,533 − − − − 3,069,778 − − $9,391,311

Balances at beginning of year Net income Remeasurement loss on net accrued retirement liability Movement in cumulative translation adjustment Total comprehensive income (loss) Issuance of stocks Change in ownership without loss of control (Note 20) Increase in noncontrolling interests - stock issuances Balances at end of year

(Forward)

$9,391,311 – – – – – $9,391,311

Balances at beginning of year Net income Remeasurement gain on net accrued retirement liability Movement in cumulative translation adjustment Total comprehensive income (loss) Increase in noncontrolling interests - stock issuances Balances at end of year

Capital Stock (Note 20)

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

$35,620,588 – – – – – $35,620,588

Additional Paid-in Capital (Note 20)

$3,149,555 − − − − − − − $3,149,555

$3,149,555 – – – – – $3,149,555 19,091 – ($17,136)

($36,227) – 19,091

$16,219,666 2,680,207 − − 2,680,207 − − − $18,899,873

($38,406) − 2,179 − 2,179 − − − ($36,227)

For the Year Ended December 31, 2015

$18,899,873 1,772,841 – – 1,772,841 – $20,672,714

For the Year Ended December 31, 2016

($804,317) − − (1,744,511) (1,744,511) − − − ($2,548,828)

($2,548,828) – – (2,850,480) (2,850,480) – ($5,399,308)

Cumulative Translation Adjustment

$− − − − − − 1,859,173 − $1,859,173

$1,859,173 – – – – – $1,859,173

Equity Reserve (Note 20)

Attributable to Equity Holders of the Parent Company Appropriated Remeasurement Retained Unappropriated of Net Accrued Earnings Retained Retirement (Note 20) Earnings Liability

FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 and 2014

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

$8,679,634 1,928,863 − (540,154) 1,388,709 − 2,810,440 3,163,342 $16,042,125

$16,042,125 4,085,391 – (589,701) 3,495,690 4,464,263 $24,002,078

$58,772,402 4,609,070 2,179 (2,284,665) 2,326,584 13,445,629 4,669,613 3,163,342 $82,377,570

$82,377,570 5,858,232 19,091 (3,440,181) 2,437,142 4,464,263 $89,278,975

Total

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$50,092,768 2,680,207 2,179 (1,744,511) 937,875 13,445,629 1,859,173 − $66,335,445

$66,335,445 1,772,841 19,091 (2,850,480) (1,058,548) – $65,276,897

Total

Noncontrolling Interests (Note 30)

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ANNUAL REPORT 2016

$6,321,533 − − − − − − $6,321,533

See accompanying Notes to Consolidated Financial Statements.

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

Capital Stock (Note 20)

$25,244,737 − − − − − − $25,244,737

Additional Paid-in Capital (Note 20)

$3,149,555 − − − − − − $3,149,555

$7,730,281 8,489,385 − − 8,489,385 − − $16,219,666

($47,563) − 9,157 − 9,157 − − ($38,406)

For the Year Ended December 31, 2014

Appropriated Remeasurement Retained Unappropriated of Net Accrued Retirement Earnings Retained (Note 20) Liability Earnings

($1,120,775) − − 316,458 316,458 − − ($804,317)

Cumulative Translation Adjustment

$− − − − − − − $−

Equity Reserve (Note 20)

Attributable to Equity Holders of the Parent Company

$9,676,476 1,261,885 − − 1,261,885 (2,439,757) 181,030 $8,679,634

$50,954,244 9,751,270 9,157 316,458 10,076,885 (2,439,757) 181,030 $58,772,402

Total

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$41,277,768 8,489,385 9,157 316,458 8,815,000 − − $50,092,768

Total

Noncontrolling Interests (Note 30)

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31 2015 2014 2016 CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax Adjustments for: Interest expense (Note 16) Impairment loss on Gabon asset (Note 10) Depletion, depreciation and amortization (Notes 10 and 14) Accretion expense (Note 18) Write-off of deferred exploration costs (Notes 11 and 24) Gain on disposal of investment (Note 12) Loss (gain) on derivatives (Note 19) Share in net loss (income) of a joint venture (Note 12) Interest income Net unrealized foreign exchange loss (gain) Net gain on fair value changes on financial assets at fair value through profit or loss (Note 7) Gain on sale of equipment (Note 25) Dividend income (Note 7) Operating income before working capital changes Decrease (increase) in: Receivables Prepaid expenses and other current assets Increase (decrease) in: Accounts payable and accrued expenses Cash generated from operations Interest received Income taxes paid Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment Dividends received Decrease in short-term investments Acquisitions of property, plant and equipment (Note 10) Additional deferred oil exploration costs (Note 11) Decrease (increase) in other noncurrent assets Additional investment in a joint venture (Note 12) Net cash inflow from deconsolidation of a subsidiary (Note 12) Net cash used in investing activities

$6,075,863

$1,176,135

$15,720,042

9,076,674 8,831,689

4,934,680 −

4,524,186 −

8,374,260 156,955

4,704,110 140,635

4,238,357 50,900

32,980 − (10,760,704) (1,129,923) (284,127) (40,457)

− − 734,060 (241,481) (112,537) 178,876

− (21,052,299) 10,755,464 242,562 (70,633) 93,661

(16,404) (7,354) (2,131) 20,307,321

(1,392) − (1,704) 11,511,382

(26,128) (13,192) (2,059) 14,460,861

(4,310,186) (352,757)

(16,112) (3,372,039)

(508,217) 2,460,912

(12,897,954) 2,746,424 325,747 (170,110) 2,902,061

13,302,349 21,425,580 108,384 (40,435) 21,493,529

1,466,567 17,880,123 73,187 (1,501,718) 16,451,592

120,553 2,131 − (14,064,208) (1,239,641) (760,862) −

− 1,704 186,513 (59,899,725) (5,616,676) (4,269,732) (680,833)

38,480 2,059 728,093 (10,041,653) (7,715,361) 1,462,326 (5,303,110)

− (15,942,027)

− (70,278,749)

7,871,926 (12,957,240)

(Forward)

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60

2016 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from availment of long-term debt (Note 16) Increase in other noncurrent liabilities Proceeds from sale of interest in a subsidiary to noncontrolling interests (Note 20) Proceeds from issuance of stocks (Note 20) Proceeds from deposits for future stock subscriptions (Note 17) Additional capital from noncontrolling interest (Note 30) Payment of loans (Note 16) Interest paid Dividends paid (Note 20) Net cash provided by (used in) financing activities NET EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 6)

Years Ended December 31 2015 2014

$55,711,987 83,091

$76,733,682 48,406

$2,196,428 −

− −

4,669,613 13,445,629

− −

− − (55,773,732) (9,877,644) (176) (9,856,474)

6,557,228 3,163,342 (20,000,529) (5,063,372) (535) 79,553,464

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

3,274,423

(1,049,793)

(738,012)

(19,622,017)

29,718,451

246,586

32,536,605

2,818,154

2,571,568

$12,914,588

$32,536,605

$2,818,154

See accompanying Grouping Notes to Consolidated Financial Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Information a. Organization PetroEnergy Resources Corporation (“PERC”, “PetroEnergy” or the “Group”), formerly Petrotech Consultants, Inc., was organized on September 29, 1994 to provide specialized technical services to its parent company, Petrofields Corporation, and to companies exploring for oil in the Philippines.

The registered office and principal place of business of the Parent Company is 7/F JMT Building, ADB Avenue, Ortigas Center, Pasig City.

In 1997, the Group’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 Group 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 Group’s application for a decrease in authorized Capital from One Billion (1,000,000,000) common shares at a par value of One Peso (P =1.00) per share to Three Hundred Thirty Million (330,000,000) shares at a par value of One Peso (P =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 Group.

On August 4, 2004, the SEC issued to the Group the certificate of permit to offer securities for sale. This certifies that the shares of the Group 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 Group’s shares were listed at the PSE. On July 22, 2009, the Board of Directors (BOD) approved the amendment of the articles of incorporation of PERC 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 P =5.00 per share, giving a net proceeds of = P683.436 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 = P599.675 million and will be used to partially finance the expansion, construction and development of renewable energy

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62

projects, such as the MGPP (Phase 2) and Solar Power Project, as well as the expansion of the Etame Project in Gabon, West Africa.

On June 03, 2015, SEC approved the Group’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 Board on February 23, 2010, created a wholly owned subsidiary called PetroGreen Energy Corporation (PetroGreen). PetroGreen shall carry-out the renewable energy projects of PetroEnergy. The SEC approved the incorporation of PetroGreen on March 31, 2010.

On May 19, 2010, PetroGreen signed a Joint Venture Agreement (JVA) with Trans-Asia Oil and Energy Development Corporation (“Trans-Asia”), now PHINMA Energy Corporation 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 Wind 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 (SHA) that will govern their relationship as shareholders and state their respective rights and obligations in relation to PetroWind. Further, the SHA contains provisions regarding voting requirements for relevant activities that require a higher degree of approval than that under existing corporate laws. PetroGreen, CapAsia and EEIPC agree that their equity ownership ratios in PetroWind are at 40%, 40% and 20%, respectively.

Although the SPA and the SHA 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

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to CapAsia and all the conditions precedent have been satisfactorily completed. As such, PetroGreen lost its control over PetroWind while CapAsia was given full voting and economic rights as a 40% shareholder. The transaction made PetroWind a joint venture between PetroGreen, CapAsia and EEIPC by virtue of the SHA 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. On June 09, 2015, EEIPC acquired 10% of PetroEnergy’s share in PetroGreen, leaving PetroEnergy with 90% share in PetroGreen.

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 with target completion of January 2016.

As of December 31, 2016, 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.

Geothermal Energy The geothermal projects are the 20-MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas and its 12MW expansion that is expected to be completed by the fourth quarter of 2017.

Wind Energy The wind energy project is the 36-megawatt (MW) NWPP in Nabas, Aklan, where PetroWind has a wind farm.

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Solar Energy The Solar power project is the 50MW Tarlac Solar Power Plant (TSPP) in Tarlac City, Tarlac. c.

Approval of Consolidated Financial Statements The accompanying consolidated financial statements were approved and authorized for issue by the BOD on February 23, 2017.

2. Basis of Preparation The accompanying consolidated financial statements have been prepared under the historical cost convention method, except for financial assets carried at fair value through profit or loss (FVPL) and derivative liability that have been measured at net realizable 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, 2016 and 2015. 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, 2016, 2015 and 2014:

PetroGreen Percentage share of PetroGreen in its subsidiaries: MGI PetroSolar Navy Road Development Corporation (NRDC)

Percentage of Ownership 2015 2014 2016 1 1 90% 90% 100% 65% 56% 100%

65% 56% 100%

65% – 100%

1

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 years ended December 31, 2016 and 2015.

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.

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Subsidiaries are consolidated when control is transferred to the Group and cease to be consolidated when control is transferred out of the Group. 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.

The consolidated financial statements are prepared using uniform accounting policies for like transactions and other events in similar circumstances. All interGroup balances and transactions, interGroup profits and expenses and gains and losses are eliminated during consolidation. All interGroup 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 comprehensive 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 comprehensive income.

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

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

3. Changes in Accounting Policies The accounting policies adopted are consistent with those of the previous calendar year, except that the Group has adopted the following new accounting pronouncements starting January 1, 2016. Adoption of these pronouncements did not have any significant impact on the Group’s financial position or performance unless otherwise indicated. · · · · · · · ·

Amendments to PFRS 10, PFRS 12 and PAS 28, Investment Entities: Applying the Consolidation Exception Amendments to PFRS 11, Accounting for Acquisitions of Interests in Joint Operations PFRS 14, Regulatory Deferral Accounts Amendments to PAS 1, Disclosure Initiative Amendments to PAS 16 and PAS 38, Clarification of Acceptable Methods of Depreciation and Amortization Amendments to PAS 16 and PAS 41, Agriculture: Bearer Plants Amendments to PAS 27, Equity Method in Separate Financial Statements Annual Improvements to PFRSs 2012 - 2014 Cycle • Amendment to PFRS 5, Changes in Methods of Disposal • Amendment to PFRS 7, Servicing Contracts • Amendment to PFRS 7, Applicability of the Amendments to PFRS 7 to Condensed Interim Financial Statements • Amendment to PAS 19, Discount Rate: Regional Market Issue • Amendment to PAS 34, Disclosure of Information ‘Elsewhere in the Interim Financial Report’

New Accounting Standards, Interpretations and Amendments Effective Subsequent to December 31, 2016 The Group will adopt the standards and interpretations enumerated below when these become effective. Except as otherwise indicated, the Group does not expect the adoption of these new, revised and amended standards and new Philippine Interpretation to have a significant impact on its financial statements.

Effective in 2017: Amendment to PFRS 12, Clarification of the Scope of the Standard (Part of Annual Improvements to PFRSs 2014 - 2016 Cycle) The amendments clarify that the disclosure requirements in PFRS 12, other than those relating to summarized financial information, apply to an entity’s interest in a subsidiary, a joint venture or an associate (or a portion of its interest in a joint venture or an associate) that is classified (or included in a disposal group that is classified) as held for sale.

The amendments do not have any impact on the Group’s financial position and results of operation. The Group will include the required disclosures in its 2017 consolidated financial statements.

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Amendments to PAS 7, Statement of Cash Flows, Disclosure Initiative The amendments to PAS 7 require an entity to provide disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes (such as foreign exchange gains or losses).

On initial application of the amendments, entities are not required to provide comparative information for preceding periods. Early application of the amendments is permitted.

Application of amendments will result in additional disclosures in the 2017 consolidated financial statements of the Group.

Amendments to PAS 12, Income Taxes, Recognition of Deferred Tax Assets for Unrealized Losses The amendments clarify that an entity needs to consider whether tax law restricts the sources of taxable profits against which it may make deductions on the reversal of that deductible temporary difference. Furthermore, the amendments provide guidance on how an entity should determine future taxable profits and explain the circumstances in which taxable profit may include the recovery of some assets for more than their carrying amount.

Entities are required to apply the amendments retrospectively. However, on initial application of the amendments, the change in the opening equity of the earliest comparative period may be recognized in opening retained earnings (or in another component of equity, as appropriate), without allocating the change between opening retained earnings and other components of equity.

Entities applying this relief must disclose that fact. Early application of the amendments is permitted.

These amendments are not expected to have any impact on the Group.

Effective in 2018: Amendments to PFRS 2, Share-based Payment, Classification and Measurement of Sharebased Payment Transactions The amendments to PFRS 2 address three main areas: the effects of vesting conditions on the measurement of a cash-settled share-based payment transaction; the classification of a share-based payment transaction with net settlement features for withholding tax obligations; and the accounting where a modification to the terms and conditions of a share-based payment transaction changes its classification from cash settled to equity settled.

On adoption, entities are required to apply the amendments without restating prior periods, but retrospective application is permitted if elected for all three amendments and if other criteria are met. Early application of the amendments is permitted.

The Group is assessing the potential effect of the amendments on its consolidated financial statements.

PFRS 15, Revenue from Contracts with Customers PFRS 15 establishes a new five-step model that will apply to revenue arising from contracts with customers. Under PFRS 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 PFRS 15 provide a more structured approach to measuring and recognizing revenue.

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The new revenue standard is applicable to all entities and will supersede all current revenue recognition requirements under PFRSs. Either a full or modified retrospective application is required for annual periods beginning on or after January 1, 2018.

The Group is currently assessing the impact of PFRS 15 and plans to adopt the new standard on the required effective date PFRS 9, Financial Instruments 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 providing comparative information is not compulsory. For hedge accounting, the requirements are generally applied prospectively, with some limited exceptions.

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 adoption will also have an effect on the Group’s application of hedge accounting and on the amount of its credit losses.

Amendments to PAS 28, Measuring an Associate or Joint Venture at Fair Value (Part of Annual Improvements to PFRSs 2014 - 2016 Cycle) The amendments clarify that an entity that is a venture capital organization, or other qualifying entity, may elect, at initial recognition on an investment-by-investment basis, to measure its investments in associates and joint ventures at fair value through profit or loss. They also clarify that if an entity that is not itself an investment entity has an interest in an associate or joint venture that is an investment entity, the entity may, when applying the equity method, elect to retain the fair value measurement applied by that investment entity associate or joint venture to the investment entity associate’s or joint venture’s interests in subsidiaries. This election is made separately for each investment entity associate or joint venture, at the later of the date on which (a) the investment entity associate or joint venture is initially recognized; (b) the associate or joint venture becomes an investment entity; and (c) the investment entity associate or joint venture first becomes a parent. The amendments should be applied retrospectively, with earlier application permitted.

The Group is assessing the potential effect of the amendments on its consolidated financial statements.

Amendments to PAS 40, Investment Property, Transfers of Investment Property The amendments clarify when an entity should transfer property, including property under construction or development into, or out of investment property. The amendments state that a change in use occurs when the property meets, or ceases to meet, the definition of investment property and there is evidence of the change in use. A mere change in management’s intentions for the use of a property does not provide evidence of a change in use. The amendments should be applied prospectively to changes in use that occur on or after the beginning of the annual reporting period in which the entity first applies the amendments. Retrospective application is only permitted if this is possible without the use of hindsight.

The Group is assessing the potential effect of the amendments on its consolidated financial statements.

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Philippine Interpretation IFRIC-22, Foreign Currency Transactions and Advance Consideration The interpretation clarifies that in determining the spot exchange rate to use on initial recognition of the related asset, expense or income (or part of it) on the derecognition of a non-monetary asset or non-monetary liability relating to advance consideration, the date of the transaction is the date on which an entity initially recognizes the nonmonetary asset or non-monetary liability arising from the advance consideration. If there are multiple payments or receipts in advance, then the entity must determine a date of the transactions for each payment or receipt of advance consideration. The interpretation may be applied on a fully retrospective basis. Entities may apply the interpretation prospectively to all assets, expenses and income in its scope that are initially recognized on or after the beginning of the reporting period in which the entity first applies the interpretation or the beginning of a prior reporting period presented as comparative information in the financial statements of the reporting period in which the entity first applies the interpretation.

The Group is assessing the potential effect of the interpretation on its consolidated financial statements.

Effective in 2019: PFRS 16, Leases Under the new standard, lessees will no longer classify their leases as either operating or finance leases in accordance with PAS 17, Leases. 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 PAS 17. Lessors, however, will be required to disclose more information in their financial statements, particularly on the risk exposure to residual value.

Entities may early adopt PFRS 16 but only if they have also adopted PFRS 15. When adopting PFRS 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 adopting PFRS 16.

Deferred Effectivity: Amendments to PFRS 10 and PAS 28, Sale or Contribution of Assets between an Investor and its Associate or Joint Venture The amendments address the conflict between PFRS 10 and PAS 28 in dealing with the loss of control of a subsidiary that is sold or contributed to an associate or joint venture. The amendments clarify that a full gain or loss is recognized when a transfer to an associate or joint venture involves a business as defined in PFRS 3, Business Combinations. Any gain or loss resulting from the sale or contribution of assets that does not constitute a business, however, is recognized only to the extent of unrelated investors’ interests in the associate or joint venture.

On January 13, 2016, the Financial Reporting Standards Council postponed the original effective date of January 1, 2016 of the said amendments until the International Accounting Standards Board has completed its broader review of the research project on equity accounting that may result in the simplification of accounting for such transactions and of other aspects of accounting for associates and joint ventures.

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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 renewable energy is consummated whenever the electricity generated by the Group is transmitted through the transmission line designated by the buyer, for a consideration.

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

Miscellaneous Income Miscellaneous income includes time writing charges, dividend income, rental income and gain on sale of transportation equipment. Revenue is recognized when the Group’s right to receive the payment is established.

Cash and Cash Equivalents Cash includes cash on hand and in banks. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash with original maturities of three (3) months or less from the dates of acquisition and that are subject to an insignificant risk of change in value.

Financial Instruments Date of recognition The Group recognizes a financial asset or a financial liability in the consolidated statement of financial position when it becomes a party to the contractual provisions of the instrument.

Purchases or sales of financial assets that require delivery of assets within the time frame established by regulation or convention in the marketplace are recognized on the settlement date.

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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 comprehensive 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: · 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

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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 comprehensive 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 comprehensive income when the inputs become observable or when the instrument is derecognized. For each transaction, the Group determines the appropriate method of recognizing the Day 1 difference amount.

Loans and Receivables Loans and receivables are financial assets with fixed or determinable payments and fixed maturities that are not quoted in an active market. They are not entered into with the intention of immediate or short-term resale and are not designated as AFS financial assets or financial assets at FVPL. 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, receivables and restricted cash.

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: · · ·

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 comprehensive 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

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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 comprehensive 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.

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 comprehensive income when the liabilities are derecognized or impaired, as well as through the amortization process.

Classified under this category are the Group’s accounts payable and accrued expenses and loans payable.

Impairment of Financial Assets The Group assesses at each reporting date whether a financial or group of financial assets is impaired.

A financial asset or a group of financial assets is deemed to be impaired if, and only if, there is objective evidence of impairment as a result of one or more events that has occurred after the initial recognition of the asset (an incurred ‘loss event’) and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the borrower or a group of borrowers is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganization and where observable data indicate that there is measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

Loans and Receivables The Group first assesses whether objective evidence of impairment exists individually for financial assets that are individually significant or collectively for financial assets that are not individually significant. If there is an objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset’s original EIR (i.e., the EIR computed at initial recognition).

If it is determined that no objective evidence of impairment exists for an individually assessed financial asset loan or receivable, whether significant or not, the asset is included in a group of financial assets with similar credit risk characteristics and that group of financial assets is collectively assessed for impairment. Assets that are individually assessed for impairment and for which an impairment loss is or continues to be recognized are not included in a collective assessment of impairment.

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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 comprehensive 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 comprehensive 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 comprehensive income, is transferred from the consolidated statement of changes in equity to statement of comprehensive income. Impairment reversals in respect of equity instruments classified as AFS financial assets are not recognized in the consolidated statement of comprehensive income. Reversals of impairment losses on debt instruments are reversed through the consolidated statement of comprehensive 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 comprehensive 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 comprehensive income.

Offsetting Financial Instruments Financial assets and financial liabilities are offset and the net amount reported in the consolidated statement of financial position if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the asset and

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settle the liability simultaneously.

Prepaid Expenses and Other Current Assets 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 comprehensive 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.

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

Number of Years 25 4 15 5 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 comprehensive 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 Development Costs – Geothermal included in Other Noncurrent Assets All costs incurred in the geological and geophysical activities such as costs of topographical, geological and geophysical studies, rights of access to properties to conduct those studies, salaries and other expenses of geologists, geophysical crews, or others conducting those studies are charged to profit or loss in the year such costs are incurred.

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

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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.

Deferred Development Costs - Solar Power Project included in Other Noncurrent Assets 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 of the solar farm.

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.

The amortization expense on intangible assets with finite lives is recognized in the statement of comprehensive 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.

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.

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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 comprehensive 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 · share of the revenue from the sale of the output by the joint operation · expenses, including its share of any expenses incurred jointly The Group accounts for the assets it controls and the liabilities it incurs, the expenses it incurs and the share of income that it earns from the sale of crude oil by the joint operations.

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 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

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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, deferred 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 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 comprehensive income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase.

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

Retained earnings represent accumulated earnings of the entities within the Group less dividends declared and with consideration of any changes in accounting policies and errors applied retroactively. The retained earnings of the 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.

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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 Group); 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 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 21).

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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 comprehensive income. Past service costs are recognized when plan amendment or curtailment occurs. These amounts are calculated periodically by independent qualified actuaries.

Net interest on the net defined benefit liability or asset is the change during the period in the net defined benefit liability or asset that arises from the passage of time which is determined by applying the discount rate based on government bonds to the net defined benefit liability or asset.

Net interest on the net defined benefit liability or asset is recognized as expense or income in the consolidated statement of comprehensive 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 comprehensive 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

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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.

For the renewable energy, 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.

For the oil operation, the Group depreciates ARO assets based on unit of production method.

The Group amortizes ARO liability using the effective interest method and recognizes accretion expense over the service contract term.

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.

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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 comprehensive 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.

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 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.

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 comprehensive 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 comprehensive 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.

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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 comprehensive 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 comprehensive income.

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

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

Operating Segment The Group’s operating businesses are organized and managed separately according to the nature of the products and services provided, with each segment representing a strategic business unit that offers different products and services and serves different markets. Financial information on business segments is presented in Note 28 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 financial statements, if any. Post year-end events that are not adjusting events are disclosed in the notes to 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.

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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, 2016 and 2015, the Group’s cumulative translation adjustment amounted to $5.40 million and $2.55 million, respectively.

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

Facts and circumstances that would require an impairment assessment as set forth in PFRS 6, Exploration for and Evaluation of Mineral Resources, are as follows: · · · ·

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.

In 2016, the DOE approved the withdrawal of the SC 47 (Offshore Mindoro and Panay) after the consortium agreed to relinquish the SC 47 block. 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. Consequently, the Group wroteoff the deferred exploration costs pertaining to this service contract amounting to $32,980 (see Note 11).

As of December 31, 2016 and 2015, the carrying value of deferred oil exploration costs amounted to $10.13 million and $15.92 million, respectively (Note 11).

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Classification of Joint Arrangements Judgment is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. Judgment is required to classify a joint arrangement.

Classifying the arrangement requires the Group to assess their rights and obligations arising from the arrangement. Specifically, the Group considers: · The structure of the joint arrangement - whether it is structured through a separate vehicle · When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from: · The legal form of the separate vehicle · The terms of the contractual arrangement · Other facts and circumstances, considered on a case by case basis This assessment often requires significant judgment. A different conclusion about both joint control and whether the arrangement is a joint operation or a joint venture, may materially impact the accounting.

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.

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.

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.

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.

As of December 31, 2016 and 2015, the carrying value of receivables amounted to $7.86 million and $3.59 million, respectively. Accumulated impairment losses amounted to $0.05 million and $0.06 million as of December 31, 2016 and 2015 (Note 8). No impairment losses were recognized in 2016, 2015 and 2014.

Valuation for Derivatives The Group carries certain derivative financial instruments at fair value, which requires use of accounting estimates and judgments. Fair value determinations for derivatives are based generally on current forward exchange rates for contracts with similar maturity profiles. If prices are not readily determinable or if liquidating the positions is reasonably expected to affect market prices,

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fair value is based on either internal valuation models or management’s estimate of amounts that could be realized under current market conditions, assuming an orderly liquidation over a reasonable period of time.

As of December 31, 2016 and 2015, the Group has a derivative liability amounting to nil and $10.86 million, respectively (see Note 19). Gain on derivative amounting to $10.76 million and loss on derivative amounting to $0.73 million were recognized in the statement of comprehensive income in 2016 and 2015, respectively.

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.

As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. Such changes may impact the Group’s reported financial position and results, which include: · The carrying value of exploration and evaluation asset; and property, plant and equipment; · Provisions for decommissioning may change - where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities; and · The recognition and carrying value of deferred tax assets may change due to changes in the judgments regarding the existence of such assets and in estimates of the likely recovery of such assets.

Estimating Proved Oil Reserves Proved oil reserves are estimates of the amounts of oil that can be economically and legally extracted from the Group’s oil properties. The Group estimates its commercial reserves based on the technical assumptions and is calculated 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.

The Group assesses its estimate of proved reserves on an annual basis. All proved reserve estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. Estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted.

For the period ended December 31, 2016 there has been no significant change in estimated recoverable reserves for the Gabon assets. The same estimated remaining recoverable reserve was used to compute the depletion rate used.

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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, 2016 and 2015, the Group’s depreciable property, plant and equipment amounted to $130.77 million and $80.71 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.

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, 2016 and 2015.

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) of the United States of America. Based on oil prices existing at December 31, 2016, the prices have not gone below the breakeven level for the Company in so far as its WLO investment is concerned. Thus, no impairment was recognized for 2016 and 2015.

On December 31, 2016, the Company recorded an impairment loss amounting to $8.83 million pertaining to the assets in Gabon, Africa used for oil production. The Group believes that the low oil prices in the global market is an indicator that the assets might be impaired and thus prompted the Company to perform impairment testing (see Note 10).

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

Property and equipment Intangible assets Investment properties

2016 $138,870,569 3,017,049 31,417 $141,919,035

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

Estimating Asset Retirement Obligations The Group has various legal obligation to decommission or dismantle its assets related to the oil production, geothermal energy project and solar power project at the end of each respective service contract. 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. The Group recognizes the present value of the obligation to dismantle and capitalizes the present value of this cost as part of the balance of the related property, plant and equipment, which are being depreciated and amortized on a straight-line basis over the useful life of the related assets (for the renewable energy) and based on unit of production (for the oil operations).

The related balances of the Group’s asset retirement obligation follow: PetroEnergy - Oil production MGI - Geothermal energy project PetroSolar - Solar power project

2016 $981,283 244,035 141,193 $1,366,511

2015 $851,304 243,368 – $1,094,672

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

As of December 31, 2016 and 2015, the Group did not recognize deferred tax assets on certain NOLCO and MCIT as the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized (see Note 21).

6. Cash and Cash Equivalents Cash on hand Cash in banks Cash equivalents

2016 $4,745 4,523,451 8,386,392 $12,914,588

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

Cash in banks earn interest at the prevailing bank deposit rates. Cash equivalents 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.

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The Group has no short-term investments with periods of more than three months but less than one year as of December 31, 2016 and December 31, 2015.

Interest income earned on cash in banks and short-term investments amounted to $0.15 million, $0.11 million and $0.07 million in 2016, 2015 and 2014, respectively.

7. Financial Assets at Fair Value Through Profit or Loss Marketable equity securities Investment in golf club shares

2016 $146,958 15,487 $162,445

2015 $144,118 12,113 $156,231

Net gain on fair value changes on financial assets at FVPL included in the consolidated statements of comprehensive income amounted to $16,404, $1,392 and $26,128 in 2016, 2015 and 2014, respectively. Dividend income received from equity securities amounted to $2,131, $1,704 and $2,059 in 2016, 2015 and 2014, respectively (Note 25).

8. Receivables Accounts receivable from: Feed-in-Tariff (FiT) revenue from TransCo Electricity sales to PHINMA Consortium operator Electricity sales to WESM Affiliate (Note 26) Others Interest receivable Less allowance for impairment losses

2016

2015

$5,343,506 1,575,173 980,694 7,428 1,854 3,697 2,037 7,914,389 53,950 $7,860,439

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

The Group’s receivables are mainly due from FiT sales to National Transmission Corporation (TransCo), sale of electricity to PHINMA Energy Corporation and consortium operator. These are due within one year. The carrying values as of December 31, 2016 and 2015 approximate their fair values (Note 27).

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 26.

The table below shows the disclosure of reconciliation of allowance for impairment losses on receivables from a consortium operator: Balance at beginning of year Effect of foreign currency translation Balance at end of year

2016 $57,000 (3,050) $53,950

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

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

2016 $2,472,521 2,351,879 862,314 210,811 868,925 $6,766,450

2015 $3,815,197 1,508,774 658,518 145,515 285,689 $6,413,693

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) of MGI and PetroSolar, respectively. The restricted cash is used to pay for the forthcoming debt service scheduled in April and October of every year until the loan is fully paid off. This also includes unused portion of the Stock Rights proceeds, which was held under escrow account.

Advances to contractors 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 “Prepaid expenses and other current assets”. There were no downpayments to contractors that are related parties as of December 31, 2016 and 2015, respectively.

Prepaid expenses include prepaid insurance and prepaid rent.

Prepaid taxes pertains creditable withholding taxes and prior year’s income tax credit.

Others pertain to supplies, crude oil inventory and undrawn deferred financing costs.

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Cost Balances at beginning of year Additions Change in ARO estimate (Note 18) Transfers from deferred exploration costs (Note 11) Transfers from development cost (Note 14) Reclassification/adjustments Disposal Balances at end of year Accumulated depletion and depreciation Balances at beginning of year Depletion and depreciation Disposals Reclassification/Adjustments Balances at end of year Cumulative translation adjustments Impairment of Gabon assets Net book values

FCRS and production wells geothermal $19,884,969 212,788 ‒ ‒ ‒ 2,377,624 ‒ 22,475,381 1,243,027 797,318 ‒ ‒ 2,040,345 (961,363) ‒ $19,473,673

Power plants $45,627,676 4,470,907 135,301 ‒ 435,710 54,409,086 ‒ 105,078,680 3,458,045 4,076,815 ‒ ‒ 7,534,860 (2,072,119) ‒ $95,471,701

10. Property, Plant and Equipment

16,405,246 2,795,358 ‒ ‒ 19,200,604 ‒ (8,831,689) $13,173,808

‒ ‒ ‒ 41,206,101

6,992,266

$33,755,627 464,680 (6,472)

Wells, platforms and other facilities

158,649 108,242 (53,826) ‒ 213,065 (76,601) ‒ $1,478,795

‒ ‒ (53,826) 1,768,461

‒

$1,681,732 140,555 ‒

Land and land improvements

790,352 10,372 ‒ (7,590) 793,134 ‒ ‒ $4,049

‒ ‒ ‒ 797,183

‒

$796,456 727 ‒

419,503 124,393 (30,152) ‒ 513,744 (10,297) ‒ $482,652

‒ ‒ (66,727) 1,006,693

‒

$727,663 345,757 ‒

2016 Office condominium units and Transportation improvements equipment

740,998 338,477 ‒ 7,590 1,087,065 (21,653) ‒ $684,621

‒ ‒ ‒ 1,793,339

‒

$1,449,811 343,528 ‒

Office furniture and other equipment

23,215,820 8,250,975 (83,978) ‒ 31,382,817 (6,355,402) (8,831,689) $138,870,569

435,710 ‒ (120,553) 185,440,477

6,992,266

$163,940,017 14,064,208 128,829

Total

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‒ ‒ ‒ ‒ ‒ (3,213,369) ‒ $8,101,270

‒ (56,786,710) ‒ 11,314,639

‒

$60,016,083 8,085,266 ‒

Construction in progress

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Net book values

Cost Balance at beginning of year Additions Change in ARO estimate (Note 18) Transfers from deferred exploration costs (Note 11) Reclassification/adjustments Balance at end of year Accumulated depletion and depreciation Balance at beginning of year Depletion and depreciation Balance at end of year Cumulative translation adjustment 607,264 688,818 1,296,082 (949,723)

1,768,095 1,838,890 3,606,985 (2,250,148) $18,641,942

− 439,292 20,887,747

− (331,318) 48,026,764

$42,169,631

$20,166,970 281,485 ‒

$48,248,324 109,758 ‒

Power plants

FCRS and production wells geothermal

$17,350,381

14,723,628 1,681,618 16,405,246 −

8,809,408 − 33,755,627

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

Wells, platforms and other facilities

$1,523,083

79,869 85,592 165,461 (63,395)

− 292,397 1,751,939

$1,411,932 47,610 ‒

Land and land improvements

$6,104

759,629 30,723 790,352 −

− 22,540 796,456

$773,916 ‒ ‒

2015 Office condominium units and improvements

$308,160

306,240 121,843 428,083 (10,570)

− (2,136) 746,813

$687,212 61,737 ‒

Transportation equipment

$708,813

517,662 247,075 764,737 (14,677)

− (11,011) 1,488,227

$1,182,847 316,391 ‒

Office furniture and other equipment

$140,724,197

18,762,387 4,694,559 23,456,946 (3,430,078)

8,809,408 − 167,611,221

$98,544,318 59,899,725 357,770

Total

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‒ ‒ ‒ (141,565)

− (409,764) 60,157,648

$2,847,029 57,720,383 ‒

Construction in progress

Power Plant includes MGI’s geothermal power plant which were completed in 2013 and PetroSolar’s photovoltaic plant which were completed in February 2016.

The Construction in progress pertains to the construction of Maibarara Phase-2.

Change in ARO estimate and transfers from deferred exploration costs and development cost are considered as noncash investing activities.

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

Depletion and depreciation expense charged to profit or loss follows: Cost of electricity sales (Note 23) Depletion General and administrative expenses (Note 24)

2016 $5,231,844 2,795,358 223,773 $8,250,975

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

Foreign Operations Gabon, West Africa Update on Production Total crude production in 2016 reached 6.15 million barrels of oil (MMBO), with daily oil production ranging from 11,740 - 22,910 barrels of oil per day (BOPD) from four oil fields (Etame, Avouma, Ebouri and North Tchibala). Two (2) Avouma wells were worked-over in 2016, stabilizing overall production.

The Group recognized impairment loss on the assets located in Gabon, Africa which are used in oil production. The Group believes that the low crude oil prices in the market is an indicator that the assets might be impaired and thus prompted the Group to perform impairment testing of the assets.

In assessing whether impairment is required, the carrying value of the asset or CGU is compared with its recoverable amount. The recoverable amount is the higher of the asset’s/CGU’s fair value less costs to sell and value in use. Given the nature of the Group’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers or similar transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment loss is value in use. The Group generally estimates value in use using a discounted cash flow model.

The future cash flows were discounted to their present values using a pre-tax discount rate of 11.01% The Group recognized an impairment loss amounting to $8.83 million. The carrying amount of Gabon asset before the impairment is $15.35 million. As of December 31, 2016, the carrying amount of Gabon asset after the impairment amounts to $6.52 million.

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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 September 2014, in time for the drilling of three (3) Etame production wells and another three (3) SEENT wells.

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, mechanical failures and transient production downtimes, the daily production ranged from 11,740 – 22,910 BOPD compared to 2015’s range of 13,780 – 22,140 BOPD. Nonetheless, the Consortium managed twelve (12) liftings for the year 2016, resulting in a net crude export of 6.02 MMBO. Crude oil market prices for the year 2016 ranged from $27.80 - $56.80 per barrel.

Avouma Hydraulic Workovers To maintain stable overall production of the Etame field, workover operations were conducted on two (2) Avouma wells (ETBSM-2H and EAVOM-2H) to replace their defective submersible pumps. These workovers aimed to bring back ~4,200 BOPD to the overall production of the field.

The workover operations on the ETBSM-2H well, which started on November 19, 2016, were concluded on December 06, 2016 with completed Dominator-type ESPs. The well was handed over to Production, and initially produced ~1,500 bbls on December 07, 2016. The Hydraulic Workover Unit (HWU) skidded to EAVOM-2H on December 07, 2016, and its workover was completed on December 20, 2016. The well was put on-line on December 21, 2016 at a stable rate of ~3,300 BOPD. Field Life Extension and Integrated Field Development Plan Gabon recently passed a new Hydrocarbon Law which introduces new fiscal terms for all upstream operators which include increased government share and royalties, decreased cost recovery, and the imposition of 35% income tax on profit oil. In the light of these changes, the Etame consortium has been conducting a comprehensive economic modeling and valuation of the Etame Marin reserves, which will be subject to the provisions of the new Gabonese Production Sharing Contract (PSC) system.

The new fiscal regime will take effect once the first of the exploitation licenses (Etame) expires in July 2021 (Avouma will expire in 2025, while Ebouri will expire in 2026). After July 2021, the consortium will apply for a new PSC merging the three (3) fields, which will already be based on the new fiscal regime.

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The current economic models are based on drilling of three (3) wells in the Etame license before July 2021, with further drilling programs from 2021-2024. The consortium is currently examining the most optimal drilling program to ensure maximum recoverable oil while ensuring positive returns for the consortium members.

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 come up in the Gabon concession is the emergence of H2S gas in the produced oil of four (4) wells. In July 2012, two (2) wells in the Ebouri field manifested H2S in their production, while two (2) wells in Etame field yielded 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.

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 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.

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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.

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.

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 Linapacan. The total budget for the abovementioned activities is US$628,890. PetroEnergy share is US$27,150.

In early 2016, Philodrill sought approval from the JV Partners for the conduct of a downhole survey of the old West Linapacan wells using an ROV (remotely operated vehicle), in preparation for eventual field abandonment. The JV partners instead opted to reclassify this work as contingent of the on-going technical and commercial audit of RMA and other contractual obligations to the DOE. Throughout 2016, Philodrill has been conducting its G&G studies on the block to further strengthen the West Linapacan block to be revived for production. Towards the end of 2016, the consortium discussed Philodrill’s proposed WP&B for 2017 to be submitted to the DOE. Note that in 2014, previous operator RMA engaged contractor DownUnder Geosolutions (DUG) to reprocess a 3D seismic dataset over the West Linapacan block as part of their farm-in works, but was not able to settle the remaining balances. After RMA’s subsequent exit from the block in 2015, DUG kept hold of the processed 3D dataset.

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As part of the 2017 SC 14C2 WP&B with a total budget of $472,924, the remaining Consortium members allocated a Firm budget of $174,659 to pay RMA’s outstanding balance of acquiring this dataset from DUG. A Contingent program of $298,265 for possible Quantitative Interpretation (QI) works using the DUG 3D dataset is aimed to update/modify the JV’s well design / development plans or to formulate entirely new plans for the block.

PERC and the other Partners approved the said WP&B on December 20, 2016. Philodrill has submitted this WP&B to the DOE on December 21, 2016 and was approved on January 25, 2017.

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, PERC formed a Joint Venture Group, MGI, with Trans-Asia and PNOC-RC. 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 July to August 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 had the necessary wells for the 20 MW facility.

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 MB-15RD 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 MB-16D as the reinjection well.

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.

The MGPP had its first scheduled Preventive Maintenance Shutdown (PMS) from March 07–28, 2016 - the first major PMS since the plant’s commercial operations in February 2014. Major components on the Steamfield and Power Plant were refurbished. The MGI team completed all shutdown activities as programmed. The power plant was synchronized to the grid on March 29,

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2016 at 5:16 AM and resumed normal full load 20MW gross output by 7:15 AM, about 12 hours ahead of the original schedule.

MGI drilled the new Maibarara-2 (M2) reinjection well, MB-17RD, to a total depth of 1,900 meters on July 08, 2016 using DESCO Rig 30. Drilling and completion test results indicated that the well requires a pump in order to be utilized for brine injection. Currently, MB-17RD is being injected with power plant condensates in attempt to enhance its capacity, similar to what was done on MB-14RD during its early operations.

On the Steamfield and Reservoir side, well MB-15D - intended as production well for the 12-MW Maibarara-2 expansion project - is on continuous discharge testing since October 20, 2016. The well will be shut in mid-January 2017 when it is expected that Maibarara-2 construction activities in the same Pad will go into full drive. Flow measurements indicate that the well has an output of 14.0 MWe as of December 29, 2016.

The combined reinjection load for Maibarara-1 and Maibarara-2 totals to 74 kg/s and the combined capacity of wells MB-14RD and MB-17RD (78 kg/s) is enough to accept all of the reinjection load. Well MB-16RD will be used as a standby reinjection well when needed.

From January 01 to December 31, 2016, the total energy exported to the grid was 153,067.70 MWh. This was sold to MGI’s Offtaker, PHINMA Energy Corporation.

Tarlac Solar Power Project Solar Energy Service Contract (SESC) No. 2015-03-115) The Service Contract for PGEC 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.

PGEC 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. PGEC 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.

On June 17, 2015, PGEC and affiliate Group EEI Power Corp. (EEIPC), incorporated a joint venture project Group, 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 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 Utilities 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

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National Commission on Indigenous Peoples – Region III (NCIP) issued the Certificate of NonOverlap (CNO) to PSC, stating that no ancestral domains or indigenous peoples exist within the project site.

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.

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.

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. 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 P =2.6 billion. The OLSA was registered with the Registry of Deeds on November 13, 2015.

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.

On March 07, 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.

On April 06, 2016, PetroSolar executed its Renewable Energy Payment Agreement (REPA) with the National Transmission Corporation (TransCo), assuring the project’s revenues from the FiT payment of P =8.69/kWh from 2016 to 2036. The REPA took effect on May 10, 2016.

The Energy Regulatory Commission (ERC) approved on July 12, 2016 the Certificate of Compliance as a Feed-in-Tariff eligible power plant (COC-FIT) for the TSPP, which qualifies the plant to receive the FiT payments of P =8.69/kWh for 20 years.

PetroSolar completed the local Variable Renewable Energy (VRE) tests with NGCP for the TSPP last December 01 - 02, 2016 to ensure the compliance of the on-site electrical settings to Philippine Grid Code standards. Remote VRE tests were conducted with NGCP on December 27 - 28, 2016 to ensure effectiveness of the plant’s response to NGCP-controlled parameters. To address data polarity issues encountered during the remote VRE tests, NGCP will resume final data integration during the 2nd week of January, 2017. After passing these tests, NGCP will issue PetroSolar with the Final Approval to Connect certification.

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PetroSolar executed its Co-Location Agreement with NGCP on December 27, 2016. This agreement allows PetroSolar to use NGCP’s 40-m Right-of-Way (ROW) over the 230-kV Concepcion-San Manuel line for the construction and utilization of PetroSolar’s 69-kV Switching Station, connecting the TSPP to the NGCP grid.

From February 10 to December 31, 2016, the total energy exported to the grid is 67,393 MWh, with revenue of = P558.7 MM based on the FiT price of = P8.69 / kWh. Borrowing Cost In 2016 and 2015, the Group capitalized specific borrowing costs relating to finance charges incurred in the construction of the power plant. Capitalized specific borrowing costs amounted to $0.71 million and $0.02 million in 2016 and 2015, respectively. The rate used to determine the amount of specific borrowing costs eligible for capitalization was 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. In connection with the loans, MGI has pledged a portion of its land and property, plant and equipment amounting to $4.5 million as collateral. 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 also pledged all of its property and equipment amounting to $56.34 million (P =2.80 billion) and $57.54 million (P =2.71 billion) as collateral in connection with its loan in 2016 and 2015, respectively.

11. Deferred Oil Exploration Costs Balance at beginning of year Additions Write-off (Note 24) Transfers to wells and platforms (Note 10) Balance at end of year

2016 $15,919,839 1,239,641 (32,980) (6,992,266) $10,134,234

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

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.

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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 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 $178,170. Former SC 6A operator The Philodrill Corporation was also unanimously elected to reassume 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 $759,990.50.

Throughout 2016, Philodrill conducted Geological and Geophysical (G&G) works for the Octon block, as part of the DOE-approved Work Program for 2016. These include 1) broadband reprocessing of the 2013 3D seismic dataset, which Philodrill received from DownUnder Geosolutions (DUG) last September 05, 2016, 2) on-going seismic interpretation works on the newly processed data, and 3) on-going Quantitative Interpretation (QI) works on the Octon datasets.

On December 02, 2016, the SC 6A consortium discussed Philodrill’s proposed WP&B for 2017 to be submitted to the DOE. The 2017 SC 6A WP&B has a total budget of $454,767, with a Firm program of $416,014 for the conduct of data processing of the 2013 3D seismic data and Quantitative Interpretation works over that processed dataset, and a Contingent program of $38,753.70 for preliminary well design studies for prospect(s) that can be matured to drillable status.

PERC and the other Partners approved the said WP&B on December 20, 2016. Philodrill has submitted this WP&B to the DOE on December 21, 2016 and was approved on January 25, 2017.

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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. 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. The DOE formally approved the JV’s relinquishment of SC 47 on March 10, 2016, with the official termination date reckoned at the end of the 7-year Exploration Period on January 10, 2012. As a result, the Parent Company has written off the deferred oil exploration cost related to this amounting to $32,980 in 2016.

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).

Otto Energy drilled two wells but both were unsuccessful. Filipino farmors (Cosco Capital, TransAsia and PERC) did not credit the wells as earning wells. Similarly, DOE did not credit the wells as compliant to the SC commitment, but gave Otto 6 months to conduct post-well analysis.

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.

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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.

On February 15, 2016, a meeting was held among the SC 51 JV Partners to discuss the current situation of the Service Contract after former Operator Otto Energy officially expressed its intention to leave the block. Trans-Asia informed the partners that the DOE is amenable to give clearance to Otto once the remaining partners assume all the rights and obligations under SC 51.

In lieu of drilling a well, the partners would proposed a revised Work Program which will help determine if there are still other drillable prospects aside from the Duhat structure.

On April 11, 2016, the DOE requested the Filipino consortium members (Trans-Asia, Alcorn and PERC) to furnish documentary requirements to formalize the transfer of outgoing Operator Otto Energy’s 80% Participating Interests and their exit from the block. Assuming Operator Trans-Asia formally submitted the consortium’s documents to the DOE on May 18, 2016, with the DOE approving the submission on June 09, 2016.

From July to October 2016, the DOE has maintained communication with Otto over unsettled Training Fund payments during their Operatorship over the block, totaling $124,763.00. It was resolved that the Filipino consortium members may execute a Letter of Undertaking to settle Otto’s remaining Training Fund balance of $124,763.00, only when the DOE has exhausted its legal measures against Otto’s refusal to pay such balance. Upon execution of such undertaking, the consortium can undertake the Subphase 5 Work Program for the remaining two (2) years of the Service Contract until 2019 – which includes a Pore Pressure study and a Gravity survey over SC 51.

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 Alcorn Petroleum & Minerals Corporation at 46.60%.

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

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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 $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, 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 $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.

To date, the block is still under Force Majeure, putting exploration activities on-hold.

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

As of December 31, 2016, 2015 and 2014, the corresponding percentages of the Group’s participation in the various Petroleum SC areas are as follows: Gabonese Oil Concessions West Linapacan - SC 14C2 Octon Malajon Block - SC 6A East Visayas - SC 51 Offshore Mindoro - SC 47 NW Palawan -SC 75

2016 2.525% 4.137% 16.667% 20.050% – 15.000%

2015 2.525% 4.137% 16.667% 20.050% 2.000% 15.000%

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

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12. Investment in a Joint Venture The investment in a joint venture represents PetroGreen’s 40% interest in PetroWind (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).

The Group recognized unrealized gain on remeasurement of investment amounting to $17.22 million, gain on sale of investment amounting to $2.67 million and share in deconsolidated retained earnings amounting to $1.17 million. Total gain on disposal of investment amounted to $21.05 million. The Group’s net proceeds as a result of the disposal of investment amounted to $7.87 million.

The movements in the carrying value of the Group’s investment in joint venture in PetroWind in 2016 and 2015 follows: Balance at beginning of year Additional investment during the year Share in net income of a joint venture Translation adjustment Balance at end of year

2016 $27,166,952 – 1,129,923 (1,453,479) $26,843,396

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

Selected financial information of PetroWind as of December 31, 2016 and 2015 follows: Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity

2016 $20,974,460 81,399,683 (20,098,892) (55,022,479) $27,252,772

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

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Summary of statement of comprehensive income of PetroWind for the year ended December 31, 2016 and 2015 follows: Revenue Cost and expenses Income before tax Tax benefit Net income Group’s share of the net income

2016 $16,447,112 (13,631,166) 2,815,946 8,862 $2,824,808 $1,129,923

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

13. Investment Properties As of December 31, 2016 and 2015, 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, 2016 and 2015. 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, 2016 and 2015, 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 2016, 2015 and 2014.

14. Other Noncurrent Assets Intangible assets Input VAT Prepaid rent - noncurrent portion Deferred development costs Restricted cash Others

2016 $3,017,049 3,011,676 1,958,412 1,553,351 703,086 164,492 $10,408,066

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

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Intangible assets As of December 31, 2016, bulk of this account pertains to the acquired easement of right of way

by PetroSolar amounting to $3.06 million net of amortization. This also includes software used for the geological modeling of MGI field. Details follow:

Cost Balances at beginning of year Additions Balances at end of year Accumulated amortization Balances at beginning of year Amortization Balances at end of year Cumulative translation adjustment Net book values

Cost Balances at beginning of year Additions Balances at end of year Accumulated amortization Balances at beginning of year Amortization Balances at end of year Cumulative translation adjustment Net book values

Land Rights

2016 Software

Total

$3,232,673 2,214 3,234,887

$240,889 23,945 264,834

$3,473,562 26,159 3,499,721

– 117,576 117,576 (167,640) $2,949,671

190,276 5,709 195,985 (1,471) $67,378

190,276 123,285 313,561 (169,111) $3,017,049

Land Rights

2015 Software

Total

$− 3,232,673 3,232,673

$240,066 7,788 247,854

$240,066 3,240,461 3,480,527

− − − − $3,232,673

185,673 9,551 195,224 (2,017) $50,613

185,673 9,551 195,224 (2,017) $3,283,286

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 (see Note 35).

Amortization expense charged to profit or loss follows: General and administrative expenses (Note 24) Cost of electricity sales (Note 23)

2016 $5,709 117,576 $123,285

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

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 $2.25 million or P =112.03 million. These claims have now been elevated to the Court of tax Appeals of the Philippines.

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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 $1.44 million and $0.71 million in 2016 and 2015, respectively. Development cost also includes costs incurred for the 50 MW Tarlac Solar Power Project amounting to $0.46 million as of December 31, 2015. On February 2016, development costs amounting to $0.44 million were capitalized to property, plant and equipment upon PetroSolar’s start of commercial operation.

Remaining balance of deferred development cost of PetroSolar as of December 31, 2016 pertains to costs incurred for the Phase 2 expansion project amounting to $0.11 million.

Restricted cash Restricted cash pertains to the Parent Company’s share in the escrow fund for the abandonment of the Gabon assets. This also includes escrow 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 Parent Company’s obligation for the FPSO was deducted from the 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, 2016 and December 31, 2015, the Parent Company contributed its additional share in the abandonment of the Etame Marine Permit to the escrow fund amounting to $0.21 million and $0.23 million, respectively.

Others This consists of prepaid expenses and security deposit.

15. Accounts Payable and Accrued Expenses Accounts payable Accrued interest payable Accrued expenses Withholding taxes and VAT payable Dividends payable Others

2016 $2,422,775 1,036,687 611,175 283,895 209,152 55,423 $4,619,107

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

Accounts payable consists of payable to suppliers and contractors that are currently involved in the development, construction and operations of energy projects.

Accrued interest payable pertains to accrual of interest on loans.

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Accrued expenses are as follows: Sick/vacation leaves Professional fees Utilities Government share Due to HI(Note 26) Others

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

2016 $228,117 155,420 134,423 38,140 8,166 46,909 $611,175

Dividends payable pertain to unclaimed checks as of December 31, 2016 and 2015.

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, 2016 and 2015.

16. 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: Current loans payable Short-term loans payable Current portion of long-term loans payable Unamortized deferred financing cost Non-current loans payable Loans payable Unamortized deferred financing cost

2016 $3,419,147 12,575,697 (12,754) $15,982,090

2015 $3,187,420 13,458,606 (106,952) $16,539,074

2016 $101,165,618 (1,660,435) $99,505,183

2015 $101,205,990 (2,034,622) $99,171,368

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 $3.50 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 $4.50 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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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 $9.30 million (P =420 million). On May 12, 2015, PetroEnergy availed the first drawdown amounting to $1.30 million (P =60 million) with an interest rate of 5.15% per annum subject to repricing every quarter payable. The loan is payable within one year which matured and paid on May 6, 2016.

On July 20, 2015, PetroEnergy entered into an additional loan amounting to $2.50 million loan with various lenders with an interest rate of 3.9647% per annum subject to repricing every quarter.

The loan is payable in two (2) years with maturity on July 19, 2017.

On October 15, 2015, additional $1.91 million (P =90 million) was drawn from the DBP’s credit facility with an interest rate of 5.00% per annum payable within one year which matured and paid on October 7, 2016.

On November 23, 2015, PetroEnergy entered into additional loan amounting to P =154 million ($3.30 million) with various lenders with an interest rate of 5.25% per annum. Interest rate on the note shall be calculated on a 30/360 day count basis and will be paid every 3 months in arrears in the last day of each three-month period. The tenor of the loan is 2 years and the maturity is on November 23, 2017.

On October 14, 2016, additional $3.42 million (P =170 million) was drawn from the DBP’s credit facility with an interest rate of 4.50% per annum subject to repricing every quarter payable within one year with maturity on October 9, 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 realeased 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 annual interest rate of 5.24% subject to repricing payable every May and November. As of December 31, 2015, $8.50 million (P =400 million) out of the total facility were granted. On November 2016, PetroGreen availed additional $0.60 million (P =30 million) loan with the same interest and principal maturity date as the first drawdown. The principal is payable semi-annually starting November 2017 after a 2-year grace period from the original drawdown. Principal due within one year amounting to $.09 million (P =4.3 million) were duly classified as current portion of the long term loan.

MGI’s long-term loans payable On September 26, 2011, MGI together with PNOC Renewables Corporation and Trans-Asia entered into a = P2.4 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.

In 2016, the MGI pre-terminated its loan and paid the entire remaining outstanding principal resulting to recognition of finance cost on extinguishment of loan amounting to P =58.40 million.

Outstanding drawdowns pertaining to this loan facility as of December 31, 2016 and 2015 amounts to $2,011 (or = P100 thousand) and $43.7 million (or = P2.06 billion), respectively.

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On June 2, 2016 and October 10, 2016, MGI, together with PNOC RC and PHINMA Energy Corporation, entered into a P =1.40 billion and = P2.10 billion Project Loan Facility Agreement with RCBC specifically to partially finance the design, development, procurement and construction of its 12MW geothermal power plant expansion project, and to consolidate the outstanding term loans under 2011 Omnibus Agreement and incidental costs in connection with the consolidation, and to finance the working capital requirements and other general corporate purposes of the borrower, respectively.

The new M1 Loan amounting to = P2,10 billion has a term of ten (10) years from the Drawdown Date of October 10, 2016. Interest is payable semi-annually and principal is payable in twenty (20) semi-annual payments starting April 12, 2017.

Interest rate is fixed for the first five (5) years from Drawdown Date, based on the sum of the prevailing 5-Year Fixed Benchmark Rate on the Pricing date and the margin of 1.75% (the “Initial Interest Rate”). On the Repricing Date, the interest for the remaining five (5)-year term of the Loan will be the higher of (i) the sum of then prevailing 5-Year Fixed Benchmark Rate plus the margin of 1.75%, or (ii) the Initial Interest Rate.

The M2 Expansion Loan amounting to P =1,40 billion has a term of twelve (12) years including thirty-six (36) months grace period from Initial Drawdown Date of June 2, 2016. Interest is payable semi-annually, and principal is payable in eighteen (18) semi-annual payments within twelve (12) years from and after the Initial Drawdown Date.

Interest rate is fixed for the first seven (7) years from the Initial Drawdown Date based on the sum of the prevailing 7-Year Fixed Benchmark Rate on the Pricing Date and the applicable margin of (1) 1.25% per annum prior to Commercial Operations Date, or (ii) 1.75% per annum from and after the Commercial Operations Date (the “Initial Interest Rate”). For subsequent Drawdowns, interest rate will be the three (3) –day simple average interpolated rate based on the remaining tenor and computed using the straight-line method. On the Repricing Date, the interest for the remaining five (5)-year term of the Loan will be the higher of (i) the sum of the then prevailing 5Year Fixed Benchmark Rate plus the applicable margin, or (ii) the weighted average interest rate during the first seven (7) years of the Loan.

As of December 31, 2016 and 2015, the MGI has outstanding drawdowns of $51.69 million (P =2.57 billion) and $43.71 million (P =2.06 billion), respectively.

The loan covenants covering the outstanding debt of MGI include, among others, maintenance of debt-to-equity and debt-service coverage ratios. As of December 31, 2016 and 2015, MGI is in compliance with the said loan covenants.

PetroSolar’s long-term loans payable On November 12, 2015, the PetroSolar, 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, 2016 and 2015, the PetroSolar drawdown a total of = P2.49 billion (or $52.91 million).

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

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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 drawdown Date. Thus the corresponding amount on the first semi-annual payment is duly classified as current portion of the long-term loan.

PSC pledged all of its property and equipment as collateral in connection with the loan.

Deferred financing costs 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, 2016 and 2015, the portion pertaining to the drawn amount of the loan amounting to $1.67 million and $2.14 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 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

2016 $2,141,574

2015 $1,086,176

596,815 2,738,389 1,065,200 $1,673,189

1,521,444 2,607,620 466,046 $2,141,574

Interest expense related to these loans amounted to $9.08 million, $4.93 million and $4.52 million in 2016, 2015 and 2014, respectively.

Total proceeds from availment from long-term debt amounted to $55.71 million, $76.73 million and $2.20 million in 2016, 2015 and 2014, respectively.

Total payments for loans amounted to $55.77 million and $20.00 million in 2016 and 2015, respectively.

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17. Deposits for Future Stock Subscriptions Deposits for future stock subscriptions pertain 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 PetroEnergy EEIPC MGI PetroGreen Trans-Asia PNOC-RC PetroSolar EEIPC PetroGreen

December 31, 2016 Subscription No. of shares amount

December 31, 2015 Subscription No. of shares amount

23,024,832 2,558,315

$463,090 51,454

23,024,832 2,558,315

$489,265 54,363

409,500 157,500 63,000

823,612 316,774 126,710

409,500 157,500 63,000

870,165 334,679 133,872

– – 26,213,147

– – $1,781,640

1,232,000 968,000 28,413,147

2,617,935 2,056,949 $6,557,228

On July 12, 2016, SEC approved PetroSolar’s application for increase in authorized capital stock.

After completion of all the requirements, the group reclassified deposits for future stock subscription from liability account to equity account under non-controlling interest.

As of December 31, 2016, the increase in authorized capital of PetroGreen and MGI was not yet approved by the Philippine SEC, thus, the balance of deposits was not classified as equity, in accordance with Philippine SEC Financial Reporting Bulletin No. 006 issued in January 2013.

18. 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, Geothermal field located in Sto. Tomas Batangas, and photovoltaic (PV) solar power facility in Tarlac.

Movements in this account follow: Balance at beginning of year Accretion expense Additions or change in estimates (Note 10) Translation adjustment Balance at end of year

2016 $1,094,672 156,955 128,829 (13,945) $1,366,511

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

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Discount rate of 4.63% and 15.50% were used in estimating the provision for the oilfields in Etame for 2016 and 2015, respectively.

PetroEnergy MGI PetroSolar

2016 $981,283 244,035 141,193 $1,366,511

2015 $851,304 243,368 – $1,094,672

In 2016 and 2015, the change in estimate resulted from the adjustment of carrying amount of the obligation and discount rate used. The estimate was provided by a third party expert, as engaged by the consortium operator of the oilfields in Gabon, West Africa. This also resulted to a decrease in the book value in 2016 and increase in the book value in 2015, of “Wells, platforms and other facilities” account under “Property, plant and equipment” in the Group’s consolidated statements of financial position (Note 10).

The addition in 2016 pertains to provision for the present value of the future estimated costs of legal and constructive obligations to restore the site upon dismantling and removing the operating facilities of the Tarlac solar power plant.

19. Derivative Liability On November 21, 2013, PetroGreen and CapAsia ASEAN Wind 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.

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 interest of 80% on PetroWind.

The SA further provides for 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.

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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, PGEC 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 equity IRR of thirty percent (30%) on its Investment, PGEC shall receive seventy-five percent (75%) of the profits from the Investment over an IRR of thirty percent (30%).

Liquidity Event shall mean any of the following: (a) A sale of all of PetroWind’s capital stock to a third party; (b) Transfer of shares by the Company to a proposed transferee which gives rise to the tag along rights of CapAsia investor; (c) An initial public offering of the shares of PetroWind on the Philippine Stock Exchange (PSE); or (d) Any other process or transaction of a similar nature as the above listing that enables CapAsia investor to divest of its share in PetroWind.

In 2016, CapAsia’s mother company, CAIFIII PTE Ltd. (CAIF III) negotiated for a proposed sale to a third party of its 99.99% membership interest in CapAsia which owns 40% interest in PetroWind. In relation to this, it was agreed that the SA entered previously by PetroGreen, EEIPC and CapAsia shall cease to have effect. Moreover on a Letter Agreement entered into by the parties, they acknowledged and confirmed that CapAsia Investor’s Put Option and PetroGreen’s Call Option shall cease to have any effect on the date of the closing of the sale which happened in the first quarter of 2017.

As the parties acknowledged and confirmed that the call and put option shall cease upon signing of the new SA, PetroGreen derecognized the derivative liability as at December 31, 2016.

Gain on derivative write-off amounting to $10.76 million in 2016 and loss on derivative amounting to $0.73 million and $10.76 million were recognized for the years ended December 31, 2015 and 2014, respectively.

20. Equity Under the existing laws of the Republic of the Philippines, at least 60% of PERC’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, 2016, the total issued and subscribed capital stock of the Parent Company is 99.64% Filipino and 0.36% non-Filipino as compared to December 31, 2015 wherein the total issued and subscribed capital stock of the

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Group is 99.76% Filipino and 0.24% non-Filipino.

As of December 31, 2014 , 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, 2016 and 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 ($0.0201) per share. Total capital stock and additional paid-in capital amounted to $9.39 million and $35.62 million, respectively.

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

Number of shares 2015 2016

2016

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

$9,391,311 − $9,391,311

410,736,330 − 410,736,330

Additional Paid-in Capital

2016 $35,620,588 − $35,620,588

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

Amount

2015

$6,321,533 3,069,778 $9,391,311

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

The Group’s track record of capital stock 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 Deduct: Movement December 31, 2016

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

P =4.38/share

June 3, 2015

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

Number of holders as of year-end

2,149 (26) 2,123 (10) 2,113 (41) 2,072 (29) 2,043 (15) 2,028 (1) 2,027

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Dividends There were no declaration of cash dividends for the years 2016 and 2015.

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.

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

On February 19, 2013, the BOD approved additional appropriated retained earnings amounting to $1.09 million to cover for the 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, 2016 and 2015 amounted to $3.15 million. Further expansion of the said oilfield is on-going.

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

At PetroEnergy’s separate financial statements, the gain from sale recognized in the statement of comprehensive 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, 2016 and 2015, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity.

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As of December 31, 2016 and 2015, the Group’s sources of capital are as follows: 2016 $115,487,273 9,391,311 35,620,588 23,822,269 1,859,173 $186,180,614

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

2015 $115,710,442 9,391,311 35,620,588 22,049,428 1,859,173 $184,630,942

The table below demonstrates the debt-to-equity ratio of the Group as of December 31, 2016 and 2015: Total debt Loans payable Accounts payable and accrued expenses Income tax payable Deposit for future stock subscription Asset retirement obligation Derivative liability Deferred tax liabilities Other noncurrent liability Total equity Debt-to-equity ratio

2016

2015

$115,487,273 4,619,107 45,532 1,781,640 1,366,511 − 1,537,586 183,148 $125,020,797 $89,278,975 1.40:1

$115,710,442 18,795,721 − 6,557,228 1,094,672 10,855,986 1,624,496 114,425 $154,752,970 $82,377,570 1.88:1

Based on the Group’s assessment, the capital management objectives were met in 2016, 2015 and 2014.

21. Income Tax The provision for (benefit from) income tax consists of: Current Deferred

2016 $223,102 (5,471) $217,631

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

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

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The components of the Group’s net deferred tax liabilities are as follows: Deferred tax assets (liabilities) recognized in net income: Accrued rent payable Asset retirement obligation Unrealized foreign exchange loss Accrued retirement liability Provision for probable losses Accrued profit share Oil production revenue Asset retirement cost Unrealized gain on re-measurement of investment Deferred tax asset recognized in equity: Asset retirement obligation Deferred tax liabilities - net

2016

2015

$6,575 301,445 49,528 8,151 − − (58,363) (6,512) (1,537,586) (1,236,762)

$− 238,731 48,719 16,508 19,026 7,327 (38,927) − (1,624,496) (1,333,112)

7,344 ($1,229,418)

15,526 ($1,317,586)

The above deferred tax assets and liabilities are presented in the consolidated statement of financial position as follows: Deferred income tax assets - net Deferred income tax liabilities - net Net deferred income tax liabilities

2016 $308,168 (1,537,586) ($1,229,418)

2015 $306,910 (1,624,496) ($1,317,586)

As of December 31, 2016 and 2015, the Group did not recognize deferred tax assets on NOLCO and MCIT as the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized.

Details of the NOLCO and MCIT follow: NOLCO Year Incurred In USD In PHP 2016 $3,663,817 P =173,945,963 2015 1,693,904 77,731,256 2014 655,270 31,110,074 $6,012,991 P =282,787,293

MCIT In USD In PHP $4,782 P =227,010 38,675 1,824,314 853 40,520 $44,310 P =2,091,844

Expiry Year 2019 2018 2018

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 (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

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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 Income from entities subjected to lower rate Others Effective income tax rate

2015 30.00%

2014 30.00%

2.99 (0.09) (0.88)

18.88 (0.03) (1.93)

20.58 (0.05) (0.12)

–

4.33

(0.19)

–

11.50

(0.69)

–

(50.80)

(5.09)

(104.56) (199.27) (291.88%)

(6.92) 0.45 37.97%

2016 30.00%

(28.32) (0.12) 3.58%

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

2016

2015

2014

$2,640,829 933,251 6,902 123,727 $3,704,709

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

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

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23. Cost of Electricity Sales Depreciation and amortization (Notes 10 and 14) Rental, insurance and taxes Purchased services and utilities Personnel costs Repairs and maintenance Materials and supplies Business and related expenses Government share Royalty fees

2016

2015

5,349,420 2,671,709 1,853,830 1,097,030 485,932 369,405 234,303 92,463 45,769 $12,199,861

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

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

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. The Group recognized royalty fees amounting $45,769, $32,314 and 29,605 in 2016, 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 $50,990, $69,750 and $55,211 in 2016, 2015 and 2014, respectively. PetroSolar also recognized government share amounting to $41,473 in 2016.

Electricity sales of PetroSolar started only in 2016 (see Note 10).

24. General and Administrative Expenses Salaries, wages and benefits (Notes 18 and 22) Professional and other fees Depreciation and amortization (Notes 10 and 14) Taxes and licenses Transportation and travel Rent expense Entertainment, amusement and recreation (EAR) Insurance Communication Donation and contribution

2016

2015

2014

$1,192,112 407,826

$1,163,940 298,991

$1,168,545 274,439

229,482 166,708 148,614 125,551

283,073 758,666 125,620 127,090

326,545 497,329 139,492 118,600

74,293 71,014 49,980 43,332

63,316 90,437 43,583 31,951

48,139 99,326 45,986 56,839

(Forward)

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Utilities Other services Condominium dues Repairs and maintenance Research costs Office supplies Business meetings Write-off of deferred exploration costs (Note 11) Gasoline, oil and lubricants Environmental and social expenses Training and seminar Advertisement Security and janitorial services Fringe benefit tax Stock transfer fees Dues and subscriptions Others

2016 $41,727 40,696 37,950 33,697 33,648 33,449 33,401

2015 $44,646 25,616 39,695 33,339 137,289 29,673 30,857

2014 $52,291 13,729 38,523 23,889 22,305 35,243 43,839

32,980 31,677

− 31,649

− 43,207

31,123 31,044 30,687 27,031 23,120 10,341 6,497 229,273 $3,217,253

− 40,024 8,784 31,855 16,371 393,332 9,164 52,121 $3,911,082

11,695 32,975 16,151 55,073 17,099 10,155 5,900 79,589 $3,276,903

“Others” pertain to miscellaneous expenses such as development assistance, notarization, bank charges, fringe benefit taxes and reproduction expenses.

25. Miscellaneous Income Management income (Note 26) Rental income Gain on sale of equipment Dividend income Others

2016 $169,376 18,054 7,354 2,131 172 $197,087

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

2014 $208,679 19,307 13,192 2,059 − $243,237

Management income refers to administrative fees billed by PetroEnergy and PetroGreen to PetroWind. For the terms and condition of related party transactions, see Note 26.

26. 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.

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Significant transactions with related parties are as follows:

Related Party/Nature Stockholder 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 2015 2016 $− − (20,052) ($20,052) $828,293 49,657 169,376 90,159 $1,137,485

$700,000 3,267 14,770 $718,037 $849,979 29,803 189,532 5,390 $1,074,704

Outstanding Balance Receivables (Payables) 2015 2016 $− − (8,166) ($8,166) $− − − 1,854 $1,854

$− − (3,570) ($3,570) $849,979 29,803 − − $879,782

Terms and Conditions Note a Note a Note b

Note c Note c Note d Note e

a. On July 19, 2015, PERC availed of a $0.70 million loan from House of Investments, Inc (HI), payable on December 9, 2015 at 1.12% interest. These loans have been fully paid as of December 31, 2016 and 2015. b. PetroEnergy has engaged HI to perform internal audit services on PetroEnergy. HI charges retainer fee of = P56,000 ($1,180) per month. Also, on March 22, 2016, PetroEnergy engaged HI for IT General Controls and System Implementation Review. c. On March 2015, PWEI availed of a P =20 million (or $0.42 million) loan from PGEC at 5.6% annual interest payable in June 2016. This was rolled-over and paid on December 29, 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%. This was rolled over and paid on December 29, 2016. d. Management income refers to timewriting charges, management fees for accounting, legal, management and other support services rendered by PetroEnergy and PetroGreen to PetroWind. e. 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, 2016 and 2015. 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.

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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 24) Directors’ fees (Note 24) Retirement expense

2016

2015

2014

$320,822 6,561 27,261 $354,644

$320,586 90,578 29,071 $440,235

$389,256 192,307 32,141 $613,704

27. Financial Instruments The Group’s principal financial instruments include cash and cash equivalents, short term investments, trading and investment securities (financial assets at FVPL), receivables, restricted cash, loans payable, accounts payable, accrued expenses and dividends payable. The main purpose of these financial instruments is to fund the Group’s working capital requirements.

Categories and Fair Values of Financial Instruments As of December 31, 2016 and 2015, 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, 2016 and 2015 amounted to $120.39 million and $120.71 million compared to their carrying value of $115.49 million and $115.71 million, respectively.

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

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

Equity securities

Fair values are based on published quoted prices.

Golf club shares

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

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 2016 and 2015 for the 5 year tenor loans is derived using the projected T-Bond coupon rate of 3.868% and 4.519%, 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, 2016 and 2015 fair value is derived using the treasury rate of 5.964% and 3.892% plus a credit

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spreads of nil and 0.073%, 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.

The following tables show financial instruments recognized at fair value as of December 31, 2016 and 2015. The fair value is based on the source of valuation as outlined below: · · ·

quoted prices in active markets for identical assets or liabilities (Level 1); those involving inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly (Level 2); and those with inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).

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

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

Level 1

Level 2

2016 Level 3

Fair Value

$146,958 15,487 162,445

$− − −

$− − −

$146,958 15,487 162,445

Level 1

Level 2

2015 Level 3

Fair Value

$144,118 12,113 156,231 −

$− − − −

$− − − 10,855,986

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

In 2016 and 2015, 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) The projected offer price is the book value of PetroWind at 5th year (2020). (b) PetroWind share price volatility is assumed at 10%. (c) There will be no dividend declaration for the 7-year projection. (d) 99% 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, 2016 and 2015 are as shown below:

Derivative liability

Valuation technique Modified binomial model

Significant unobservable inputs Probability of liquidity event until 2020

Base assumption 2016: 99% 2015: 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%

Projected spot price

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%

Volatility

2016: 10% 2015: 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, 2016 and 2015 based on contractual payments:

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Accounts receivable Interest receivable Restricted cash Financial Liabilities Loans payable** Accounts payable and accrued expenses* Net financial assets (liabilities)

On demand

Less than 6 months

2016 6 months to 12 months

More than 12 months

Total

$162,445

$−

$−

$−

$162,445

4,528,196 7,804,452 2,037 − $12,497,130

8,386,392 − − 2,472,521 $10,858,913

− − − − $−

− 53,950 − 703,086 $757,036

12,914,588 7,858,402 2,037 3,175,607 $24,113,079

$−

$25,988,539

$−

$130,684,937

$156,673,476

2,971,245 $2,971,245

1,363,967 $27,352,506

− $−

− $130,684,937

4,335,212 $161,008,688

$9,525,885

($16,493,593)

$−

($129,927,901)

($136,895,609)

*Excluding statutory payables **Includes future interest payments

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Accounts receivable Interest receivable Restricted cash Financial Liabilities Loans payable Accounts payable and accrued expenses* 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 2,705,364 6,727 − $17,583,119

17,821,808 − − 3,815,197 $21,637,005

− 879,782 − − $879,782

− 57,000 490,544 $547,544

32,536,605 3,642,146 6,727 4,305,741 $40,647,450

$-

$18,563,941

$−

$112,454,137

$131,018,078

16,742,184 $16,742,184

1,701,982 $20,265,923

− $−

− $112,454,137

18,444,166 $149,462,244

$840,935

$1,371,082

$879,782

($111,906,593)

($108,814,794)

*Excluding statutory payables

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

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

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

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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

Increase/ decrease in market price +2.01% -2.01% +2.01% -2.01%

2016 2015 Impact on income before tax $11,685 $2,954 (11,685) (2,954) 1,201 311 (1,201) (311)

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

Foreign Exchange Risk Exposure to currency risk arises from general and administrative expenses, assets and liabilities in currencies other than the Group’s functional currency which is very minimal since the Group’s oil revenues and costs and expenses are denominated in US Dollar.

Currency risk is monitored and analyzed systematically and is managed by the Group.

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

The following table sets forth the foreign currency-denominated financial instruments of the Group as of December 31, 2016 and 2015:

Financial assets Cash and cash equivalents Financial assets at FVPL Receivables Restricted Cash Financial liabilities Loans payable Accounts payable and accrued expenses Net exposure

2016

2015

Dollar Equivalent

Philippine Peso

P =642,113,315 $12,914,588 8,076,765 162,445 342,060,921 6,879,745 122,933,744 2,472,521 1,115,184,745 22,429,299

=1,531,172,631 P 7,352,231 120,443,576 179,543,171 1,838,511,609

$32,536,605 156,231 2,559,362 3,815,197 39,067,395

5,742,027,214 115,487,273

5,445,333,401

115,710,442

Philippine Peso

Dollar Equivalent

884,526,630 18,795,721 229,662,000 4,619,107 6,329,860,031 134,506,163 5,971,689,214 120,106,380 =4,491,348,422) ($95,438,768) (P =4,856,504,469) ($97,677,081) (P

As of December 31, 2016, 2015, the exchange rates used for conversion are P =49.72 and P =47.06 per $1, respectively.

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The following table demonstrates the sensitivity to a reasonably possible change in US dollar exchange rates. With all other variables held constant, the effect on the Group’s income before is as follows: Effect on income before income tax 2015 2016 ($4,771,938) ($4,883,854) 4,771,938 4,883,854

Increase/(decrease) in foreign currency +5% -5%

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) +136% -136% Increase/decrease in interest rate (in basis points) +46 -46

2016

2015

Impact on income before tax ($1,280,411) $1,280,411 Impact on income before tax ($1,700,722) 1,700,722

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

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

The tables below show 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, 2016 and 2015:

Cash and cash equivalents* Accounts receivable Interest receivable Restricted cash

2016 Neither past due nor impaired Past due High grade Standard grade and impaired $12,909,843 7,804,452 2,037 3,175,607 $23,891,939

$− − − − $−

Total

$− 53,950 − − $53,950

$12,909,843 7,858,402 2,037 3,175,607 $23,945,889

2015 Neither past due nor impaired Past due High grade Standard grade and impaired

Total

*excluding cash on hand

Cash and cash equivalents* Accounts receivable Interest receivable Restricted cash

$32,532,229 3,528,146 6,727 4,305,741 $40,372,843

$− − − $−

$− 57,000 − − $57,000

$32,532,229 3,585,146 6,727 4,305,741 $40,429,843

*excluding cash on hand

28. 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.

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

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

Segment revenue Net income (loss) Other comprehensive income (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

Oil Geothermal Production Energy $5,339,338 $16,526,183 (11,740,775) 2,967,696 19,091 –

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

Solar Energy $11,764,139 3,511,919 –

Other Activities $241,247 10,001,755 –

Elimination Consolidated ($241,247) $33,629,660 1,117,637 5,858,232 – 19,091

$60,627,169 $301,045

$87,607,326 $–

$68,662,752 $7,123

$52,870,028 $–

($55,467,503) $214,299,772 $ $308,168

$10,676,684

$58,229,273

$48,991,668

$13,850,803

($8,265,217) $123,483,211

$–

$–

$–

$1,537,586

($927,205) (1,579,650) 231,551 $10,270 $718,079 $10,134,234 $2,892,911

Oil Production Segment revenue $6,574,675 Net income (loss) 227,167 Other comprehensive income (loss) 2,179 Other Information: Segment assets except deferred tax assets $72,774,800 Deferred tax assets - net $306,910 Segment liabilities except deferred tax liabilities $11,108,496 Deferred tax liabilities - net

2016

$− $1,216,275 (9,918,071) 14,452,693 ($83,941) $1,390,775 ($15,919,839) ($17,643,116)

$6,722,522 ($14,879,847) (11,623,304) (3,467,871) 9,551,514 (2,239,012) $– ($7,695) $9,856,968 $3,524,822 $– $– $3,046,230

$2,835,721 (7,342) (2,963,053) $– $8,363 $–

$2,422,612 2015

$– $5,321,428 15,122,261 (4,349,273) $7,695 ($44,023) $–

$12,807

($300)

Other Activities $− 2,268,310 −

Elimination $− (2,046,625) (2,284,665)

$1,537,586 ($927,381) (1,555,906) 231,727 $10,270 $14,064,209 $10,134,234 $8,374,260

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

Solar Energy $− (402,956) −

$77,849,572 $−

$88,192,978 $−

$59,760,285 $−

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

$49,804,941

$81,609,721 $−

$28,625,871

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

$−

$5,789,670 $16,167,879 (2,616,351) (61,348,620) (3,222,425) 69,123,049 $837 $− $1,443,891 $57,541,841 $− $− ($5,506,847)

($5,292)

$1,624,496

$−

($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) $− $− ($56,720)

($3,844)

Consolidated $23,542,582 4,609,070 (2,282,486)

$1,624,496 $22,158,575 (13,685,333) (2,509,754) ($3,432,935) $60,378,258 ($15,919,839) ($23,215,820)

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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

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 $−

$9,197,909

$57,569,946

$50,304,710

$−

$−

$−

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

$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

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

$2,647,015

$64,147

2014

Other Activities $− 3,268,292 −

Elimination $− 143,010 316,458

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

$44,467,614 ($117,555,926) $141,845,470 $− $− $202,036 $6,279,628 ($45,205,583) $5,128,494

$−

$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

$78,146,610 $5,128,494 $17,179,685 (13,685,333) (2,509,758) $5,968,772 $10,460,030 $19,112,571

($70,965)

$4,238,357

InterGroup investments, revenues and expenses are eliminated during consolidation.

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

2016

2015

2014

$1,772,841 410,736,330 $0.0043

$2,680,207 353,589,617 $0.0076

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

Earnings per share are calculated using the net income attributable to equity holders of the Parent Company divided by the weighted average number of shares. On June 3, 2015, Securities and Exchange Commission approved the increase in the authorized capital from 330,000,000 shares to 700,000,000 shares at P =1 par value per share. Out of the entire increase in the authorized capital stock, 136,912,110 common shares have been subscribed through the Stock Rights Offering on May 11 to 15, 2015 (see Note 20).

30. Noncontrolling Interests As of December 31, 2016 and 2015, noncontrolling interests (NCI) pertain to the 10% shareholdings of EEI-PC in PetroGreen, 35% shareholdings of Trans-Asia and PNOC in MGI and 44% shareholdings of EEI-PC in PetroSolar.

MGI, PetroSolar and PetroWind are entities incorporated and operating in the Philippines.

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As of December 31, 2016 and 2015, the accumulated balances of and net loss attributable to noncontrolling interests are as follows: Accumulated balances of noncontrolling interests: MGI PetroGreen PetroSolar Net income (loss) attributable to noncontrolling interests: MGI PetroGreen PetroSolar PetroWind

2016

2015

$10,475,492 8,713,076 4,813,510 $24,002,078

$9,861,430 3,312,057 2,868,638 $16,042,125 $1,597,111 509,053 (177,301) − $1,928,863

$1,038,694 – 1,545,244 1,501,453 $4,085,391

The summarized financial information of these subsidiaries is provided below in Philippine Peso which is the subsidiaries’ functional currency. This information is based on amounts before intercompany eliminations.

MGI The 2016 and 2015 financial information for MGI follows: Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statements of Comprehensive Income Revenue Expenses Net income 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

2016

2015

P =596,805,411 3,759,030,839 (457,812,138) (2,437,347,335) P =1,460,676,777

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

P =789,826,937 (648,930,503) P =140,896,434

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

P =334,243,815 (577,910,655) 474,901,268 (138,919)

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

P =231,095,509

(P =2,781,793)

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PetroGreen The 2016 financial information for PetroGreen follows: 2016

Statement of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statement of Comprehensive Income Revenue Gain (loss) on derivatives Expenses Net income (loss) Statement of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Net increase (decrease) in cash

2015

P =71,717,198 1,792,493,015 (265,631,092) (423,030,852) P =1,175,548,269

=255,095,418 P 1,792,735,994 (439,610,963) (907,522,506) 700,697,943

P =11,453,609 510,882,721 (47,486,004) P =474,850,326

P24,405,703 = (33,398,502) (40,700,460) (P =49,693,259)

P =140,992,036 (365,062) (147,323,000) (P =6,696,026)

(P =205,556,245) (615,443,351) 839,404,475 =18,404,879 P

PetroSolar The 2016 financial information for PetroSolar follows: Statement of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statement of comprehensive income Revenue Expenses Net income (loss) Statement of Cash Flows Net cash used in: Operating activities Investing activities Financing activities Effect of foreign exchange rate Net increase (decrease) in cash

2016

2015

P1,261,266,540 P =455,156,856 = 2,889,095,008 2,959,109,374 (1,526,668,503) (327,740,291) (2,108,125,427) (2,313,884,988) =309,808,057 P P =978,400,512 P =563,595,157 (396,860,425) = 166,734,732 P

=5,589,830 P (23,923,650) (P =18,333,820)

=760,860,375 P (P =739,825,998) (172,422,540) (2,887,066,059) (111,323,695) 3,252,930,689 − (2,301,012) P1,126,725,005 (P =1,025,873,245) =

There were no dividends paid to noncontrolling interests.

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The increase in noncontrolling interests from stock issuances follows: · As of December 31, 2016, PetroSolar converted its deposit for future stock subscription into capital stock which increased the noncontrolling interest by $4.49 million. · As of December 31, 2015, PetroSolar issued 3,300,000 common shares with $2.04 par value.

The issuances increased the noncontrolling interest by $3.05 million, PetroGreen also issued 55,250,000 shares which increased the noncontrolling interest by = P0.11 million. · As of December 31, 2014, MGI issued 748,880 common shares with 100 par value. Such stock issuances increased the noncontrolling interests by $0.18 million.

The increase in noncontrolling interest from stock issuances does not result to the dilution of the Parent Company’s effective interest in the subsidiaries.

31. Renewable Energy Act of 2008 On January 30, 2009, Republic Act No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energy Resources and for Other Purposes, otherwise known as the “Renewable Energy Act of 2008” (the “Act”), became effective. The Act aims to (a) accelerate the exploration and development of renewable energy resources such as, but not limited to, biomass, solar, wind, hydro, geothermal and ocean energy sources, including hybrid systems, to achieve energy self-reliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels and thereby minimize the country’s exposure to price fluctuations in the international markets, the effects of which spiral down to almost all sectors of the economy; (b) increase the utilization of renewable energy by institutionalizing the development of national and local capabilities in the use of renewable energy systems, and promoting its efficient and cost-effective commercial application by providing fiscal and non-fiscal incentives; (c) encourage the development and utilization of renewable energy resources as tools to effectively prevent or reduce harmful emissions and thereby balance the goals of economic growth and development with the protection of health and environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws.

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

iii.

iv.

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

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shall be carried over as deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss; v. Corporate Tax Rate - After seven (7) years of ITH, all RE developers shall pay a corporate tax of ten percent (10%) on its net taxable income as defined in the National Internal Revenue Code of 1997, as amended by Republic Act No. 9337; vi. Accelerated Depreciation - If, and only if, an RE project fails to receive an ITH before full operation, it may apply for accelerated depreciation in its tax books and be taxed based on such; vii. Zero Percent VAT Rate - The sale of fuel or power generated from renewable sources of energy, the purchase of local goods, properties and services needed for the development, construction and installation of the plant facilities, as well as the whole process of exploration and development of RE sources up to its conversion into power shall be subject to zero percent (0%) VAT; viii. Cash Incentive of RE Developers for Missionary Electrification - An RE developer, established after the effectivity of the Act, shall be entitled to a cash generation-based incentive per kilowatt-hour rate generated, equivalent to fifty percent (50%) of the universal charge for power needed to service missionary areas where it operates the same; ix. Tax Exemption of Carbon Credits - All proceeds from the sale of carbon emission credits shall be exempt from any and all taxes; and x. Tax Credit on Domestic Capital Equipment and Services - A tax credit equivalent to one hundred percent (100%) of the value of the VAT and custom duties that would have been paid on the RE machinery, equipment, materials and parts had these items been imported shall be given to an RE operating contract holder who purchases machinery, equipment, materials, and parts from a domestic manufacturer for purposes set forth in the Act. RE developers and local manufacturers, fabricators and suppliers of locally-produced RE equipment shall register with the DOE, through the Renewable Energy Management Bureau (REMB). Upon registration, a certification shall be issued to each RE developer and local manufacturer, fabricator and supplier of locally-produced renewable energy equipment to serve as the basis of their entitlement to the incentives provided for in the Act. All certifications required to qualify RE developers to avail of the incentives provided for under the Act shall be issued by the DOE through the REMB. 32. 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

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called for the privatization of NPC. The restructuring of the electricity industry calls for the separation of the different components of the power sector, namely: generation, transmission, distribution, and supply. On the other hand, the privatization of the NPC involves the sale of the state-owned power firm’s generation and transmission assets (e.g. power plants and transmission facilities) to private investors. These two reforms are aimed at encouraging greater competition and attracting more private-sector investments in the power industry.

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

Specifically, the EPIRA has the following objectives: · · · · ·

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

33. 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.

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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 then issue the CERs equal to the verified GHG emission reductions.

The slowdown in world market conditions for carbon credits severely affected Endesa, necessitating its closure and eventual liquidation. For this reason, effective June 28, 2013, MGI and Endesa decided to mutually terminate the ERPA. On July 31, 2013, MGI entered into a memorandum of agreement (MOA) with Enel Trade S.P.A (Enel), a Group 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.

MGI has not undergone the validation process, because of the poor market condition for carbon credits, and MGI would only do so once the same rebounds. b. Electricity Supply Agreement In 2011, MGI entered into an Electricity Supply Agreement (M1 ESA) with Trans-Asia Oil and Energy Development Corporation (Trans-Asia) in which the latter offered to purchase all of the 20 MW facility’s net output.

The commercial operation started on February 8, 2014 and pursuant to the M1 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 M1 ESA amounted to $16.53 million or P =784.61 million and $16.96 million or P =772.01 million in 2016 and 2015, respectively.

In May 2016, MGI entered into another Electricity Supply Agreement (M2 ESA) with TransAsia, this time covering the net output of the 12 MW expansion. The terms and conditions of the M2 ESA are similar to that of the M1 ESA. PSC Operating lease commitments - lessee On June 22, 2015, the Group (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.

34. Wind Energy Service Contract (WESC) Wind Energy Service Contract (WESC) No. 2009-09-002 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

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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 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.

To assist during the initial stage of the O&M, PWEI has engaged a consultant, Modern Energy Management (MEM), to do site audit/assessment, conduct windfarm management training for PWEI technical personnel, and evaluate Gamesa’s monthly reports for the first year of the O&M. The site audit and training was conducted by MEM last May 10 - 17, 2016.

The Preventive Maintenance Services (PMS) of the Windfarm Electrical Facilities (i.e., Substation and Switching Station, including Switchgears) were successfully conducted on May 21 - 22, 2016.

For the Operations and Maintenance (O&M) of the wind turbines, Gamesa had completed its 12-Month (12M) Maintenance on July 05, 2016, its 3-Month (3M) Maintenance activities on August 12, 2016, and will start with the 18-month preventive maintenance on October 03, 2016.

The program for the 18-month maintenance works is for one (1) WTG per day for 8 hours over an 18-day period.

Maintenance works for the Balance of Plant (BOP), including electrical feeder cables, substation, etc., were done by Gamesa’s subcontractor - Airnergy and Renewables Inc. - from August 08 – 12, 2016, initial test results of which passed Gamesa‘s evaluation.

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Slope protection works have been implemented throughout 2016, even during the typhoon season in August 2016, to which contractor GSI was able to assess the integrity of the completed works, and determine areas for further works.

The NWPP was shut-down during the onslaught of Typhoon “Marce” on November 25, 2016 due to grid failures along the 138-kV Nabas-Panit-an line and the 69-kV Nabas-Caticlan line. On-site, the said typhoon caused minor soil erosion, minor damage on the access road canal and obstructed cross drains (especially those leading to WTGs 9, 14 and 16), but the rest of the site remained under normal operating conditions. Site clearing operations along the drainage canals and road resurfacing works were conducted from November 26-29, 2016.

As for the Variable Renewable Energy (VRE) Tests with NGCP, PWEI is still awaiting issuance of the Final Authority to Connect from NGCP’s Revenue and Regulatory Affairs Group (RRAG) office in Manila, which is expected to be issued in February 2017.

From January 01 to December 31, 2016, the total energy exported to the grid is 103,495.76 MWh for the Project’s Phase 1, with revenue of PhP 769.9 MM based on the FiT price of = P7.40 per kWh. 35. 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 and extended until October 2016.

On October 19, 2016, MGI and Fuji executed the Technical Services Agreement duly replacing the RMS-TAS. Under the new agreement, Fuji shall dispatch one Technical Field Advisor once every six months to conduct a regular field inspection of the plant’s operation and regulary answer MGI’s queries through phone calls or email correspondences. Should the situation call for it, Fuji could dispatch its personnel within 48 hours in order to address urgent technical issues. 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,

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Sto. Tomas, Batangas will be connected to MERALCO’s existing 115 kV line in Calamba, Laguna.

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.

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.

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.

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).

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 Group, 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.

d. Coordination Agreement On June 30, 2015, PetroGreen signed a Coordination Agreement with Phesco, Inc. and

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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. e.

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

f.

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.

g. 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 (see Note 14)

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 (see Note 14).

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