Issuu

PETROENERGY RESOURCES CORPORATION 7th Floor, JMT Building, ADB Avenue Ortigas Center, Pasig City

637-2917 Telephone Number

31 December 2013 Fiscal Year Ended

Notice of Regular Annual Stockholders’ Meeting

SEC Form 20-IS Information Statement Pursuant to Section 20 of the Securities Regulation Code Form Type

PETROENERGY RESOURCES CORPORATION INFORMATION STATEMENT A. GENERAL INFORMATION 1. Date, Time and Place of Meeting of Security Holders The Regular Annual Meeting of the Stockholders of PetroEnergy Resources Corporation will be held at Rooms 526-528 YIAS, Level 5, Podium 4, RCBC Plaza, Ayala Cor. Gil J. Puyat Avenues, Makati City on Tuesday, July 22, 2014 at 1:30 p.m. th

Mailing Address – 7 Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City The approximate date on which this Information Statement is first to be sent or given to security holders is on June 25, 2014. WE ARE NOT ASKING YOU FOR A PROXY AND YOU ARE REQUESTED NOT TO SEND US A PROXY. 2. Dissenter’s Right of Appraisal There are no corporate matters or actions that will entitle dissenting stockholders to exercise their right of appraisal as provided in the Title X of the Corporation Code. Although the following actions are not among the matters to be taken up during the 2014 Annual Stockholders’ Meeting, the stockholders are herein apprised of their appraisal rights pursuant to Title X of the Philippine Corporation Code. A stockholder shall have the right to dissent and demand payment of fair value of the share in case he voted against the following proposed corporate actions: (a) in case any amendment to the articles of incorporation has the effect of changing or restricting the rights of any stockholders or class of shares, or of authorizing preferences in any respect superior to those outstanding shares of any class, or extending or shortening the term of corporate existence; (b) in case of sale, lease, exchange, transfer, mortgage, pledge or other disposition of all or substantially all of the corporate property and assets; and (c) in case of merger or consolidation. The appraisal right may be exercised by the dissenting stockholder by making a written demand for payment of the fair value of his shares on the company within thirty (30) days after the date on which the vote was taken and within ten (10) days after demanding payment on his shares, he shall submit the certificate of stocks representing his shares to the company for notation thereon that such shares are dissenting shares. If the proposed corporate action is implemented and if there is agreement as to the fair value of the shares, the company shall pay the fair value of the shares to such stockholder upon surrender and transfer of the certificate of stocks. The fair value of the share shall be determined as to the day prior to the date on which the vote was taken, excluding any appreciation or depreciation in anticipation of such corporate actions. Provided, that no payment shall be made to any dissenting stockholder, unless the company has unrestricted retained earnings in its books to cover such payment. If within a period of sixty (60) days from the date of the corporate action was approved, the withdrawing stockholder of the company cannot agree on the fair value of the shares, it shall be determined and appraised by three (3) disinterested persons, one of whom shall be named by the dissenting stockholder, another by the company and third by the two previously chose. The findings of the majority of the appraisers will be final and the award shall be paid by the company within thirty (30) days after the award is made. Upon payment of the agreed or awarded price, the stockholder shall forthwith transfer his share to the company. From the time of demand for payment of the fair value of the stockholder shares, all rights accruing to such shares, including voting and dividend rights shall be suspended. None of the items in the Agenda of the meeting entitles a dissenting stockholder to appraisal right.

3. Interest of Certain Persons in Matters to be Acted Upon The incumbent directors or officers of the Company, since the beginning of the last fiscal year, do not have substantial interest, direct or indirect, by security holdings or otherwise, in any matter to be acted upon. None of the incumbent directors informed in writing that he/she intends to oppose any action to be taken during the annual meeting of the stockholders.

B. CONTROL AND COMPENSATION INFORMATION 4. Voting Securities and Principal Holders Thereof: a) Number of Shares Outstanding as of May 26, 2014: Number of Vote each share is Entitled:

273,824,220 One (1) vote per share

b) All stockholders as of May 26, 2014 are entitled to notice and to vote at the 2014 Annual Stockholders Meeting. c) Of the total outstanding common capital stock, 273,178,792 or 99.76% are owned by Filipino citizens, while 645,428 or 0.24% are owned by Foreigners. d) Manner of Voting Section 7 of Article III of the By-Laws of the Corporation provides that the stockholders may vote at all meetings the number of shares registered in their respective names either in person or by proxy executed in writing. Section 6 of the same Article provides that no proxy shall be recognized unless presented to the Secretary for inspection and registration at least three (3) calendar days before the date of said meeting. The By-Laws of the Corporation does not require notarization of proxies. In the same vein, Section 24 of the Corporation Code of the Philippines and Section 7, Article III of the Corporation’s By-Laws provide that each stockholder may vote in any of the following manner: 1) he/she may vote such number of shares for as many persons as there are Directors to be elected; 2) he/she may cumulate said shares and give one candidate as many votes as the number of Directors to be elected multiplied by his/her shares; 3) he/she may distribute them, on the same principle, among as many candidates as he/she may see fit. In any of these instances, the total number of votes cast by the stockholders should not exceed the number of shares owned by him/her as shown in the books of the Corporation multiplied by the total number of Directors to be elected.

e) Security ownership of certain record and beneficial owners and management. 1) Security ownership of certain record and beneficial owners of more than 5% of Registrant securities as of May 31, 2014: Title of Class Common Common

Name, Address of record Owner and relationships With the Issuer

Name of Beneficial Owner and relationship with the record owner

PCD Nominee Corp. G/F MSE Bldg., 6767 Ayala Ave., Makati City House of Investments, Inc. 3rd Flr., Grepalife Building, 221 Sen. Gil J. Puyat Ave. Makati City

PCD Nominee * (Various stockholders)

Filipino

236,935,391

86.53%

House of Investments, Inc. (Mr. Medel T. Nera, President and Chief Executive Officer)

Filipino

21,805,861

7.96%

(Various stockholders)

Filipino

Common

Others

Citizenship

TOTAL

No. of Shares Held

15,082,968

5.51%

273,824,220

100.00%

Note: Under PCD account, the following companies owned more than 5%: i.

*RCBC Securities – 105,784,038 or 38.63% of the Company’s outstanding capital stock. The current nominee of RCBC Securities, Inc. is Mr. Raul M. Leopando. (Under RCBC Securities, Inc. with 5% of the Registrant securities). a. b. c.

ii.

House of Investments, Inc. – 39,547,183 shares or 14.44% GPL Holdings, Inc. – 41,073,800 shares or 15.00% RCBC Capital, Inc. – 15,570,070 shares or 5.69%

*RCBC Trust and Investment Division – 45,275,895 or 16.53% of the Company’s outstanding capital stock. RCBC Trust and Investments are Trust Accounts between RCBC and Beneficial Owners. The corporate acts of RCBC are carried out by its management through the guidance of its Board of Directors. Ms. Helen Y. Dee is the current Chairman of the Company.

2) Security Ownership of Management (as of May 31, 2014): The following are the number of shares owned and of record by the Directors, the Chief Executive Officer and each of the key officers of the Company and the percentage of shareholdings of each: Title of Class Common Common Common Common Common Common Common Common Common Common Total

Name of Beneficial Owner Name and Position Helen Y. Dee Chairman Milagros V. Reyes President/Director Basil L. Ong Independent Director Cesar A. Buenaventura Independent Director Raul M. Leopando Director Yvonne S. Yuchengco Director/Treasurer Eliseo B. Santiago Director Francisco G. Delfin, Jr. Vice President Samuel V. Torres Corporate Secretary Arlan P. Profeta Asst. Corporate Secretary

Amount and Nature of Beneficial Ownership Direct 10,662 Indirect 1,880,779

Citizenship

Percent of Class

Filipino

0.691%

Indirect

70,695

Filipino

0.026%

Direct Direct Indirect

1 1,300 56,740

Filipino

0.021%

Filipino

110,831

Filipino

0.014%

Direct

Filipino

Direct

55,000

Filipino

0.020%

Filipino

Direct Indirect

2,186,010

0.798%

As of May 31, 2014, the Company’s directors and executive officers owned an aggregate of 2,186,010 shares equivalent to 0.798%.

Voting Trust Holders of 5% or more

The Company is not aware of any voting trust or similar arrangement among persons holding more than 5% of a class of shares. g) Changes in Control There had been no change in the control of the Company since the beginning of last fiscal year. The Company has no existing voting trust or change in control agreements. 5. Directors and Executive Officers: The members of the Board of Directors are elected at the general meeting of stockholders, who shall hold office for a term of one (1) year or until their successors shall have been duly elected and qualified. The Board Committee members and other Officers of the Company, unless removed by the Board of Directors, shall serve as such until their successors are elected or appointed.

a. Directors and Executive Officers The following are the names, ages, positions and periods of service of Directors and Executive Officers: Name Helen Y. Dee Cesar A. Buenaventura Basil L. Ong Milagros V. Reyes Yvonne S. Yuchengco Raul M. Leopando Eliseo B. Santiago Francisco G. Delfin, Jr. Samuel V. Torres Arlan P. Profeta

Age 70 84 62 72 60 63 64 52 49 40

Position Chairman Director / Independent Director / Independent Director / President Director / Treasurer Director Director / Independent Vice President Corporate Secretary Asst. Corporate Secretary

Citizenship Filipino Filipino Filipino Filipino Filipino Filipino Filipino Filipino Filipino Filipino

Period of Service 2001 to present 1998 to present 2011 to present 1998 to present 2004 to present 2010 to present 2013 to present 2008 to present 2006 to present 2008 to present

Business Experiences During the Past five (5) Years: Directors and Nominees: Ms. Helen Y. Dee, 70, Filipino, is presently the Chairman of House of Investments, Inc., Rizal Commercial Banking Corporation, RCBC Forex Brokers Corporation, Financial Brokers Insurance Agency, Inc., Landev Corporation, RCBC Leasing & Finance Corporation, Mapua Information Technology, Inc., Hi-Eisai Pharmaceuticals, Inc., Pan Malayan Realty Corporation, RCBC Savings Bank, La Funeraria Paz-Sucat, Malayan Insurance Company, National Reinsurance Corp of the Philippines, Xamdu Motors, Inc., Seafront Resources Corporation, Manila Memorial Park Cemetery, Inc. and PetroGreen Energy Corporation and Maibarara Geothermal, Inc and PetroWind Energy, Inc. She is the Chairman/President of Hydee Management & Resources, Inc. and Mijo Holdings, Inc. She is also the Chairman and CEO of Tameena Resources, Inc. She is the President of Moira Management, Inc., YGC Corporate Services, Inc. and GPL Holdings, Inc. She is the Vice Chairman of Pan Malayan Management and Investment Corporation and West Spring Development Corporation and Vice President of A.T. Yuchengco, Inc. She is also a Member, Board of Trustees of Mapua Institute of Technology, Inc. a leading engineering school in the Philippines and she also sits in the Board of the following companies, Phil. Long Distance Telephone Company; Great Life Financial Assurance Corp., MICO Equities, Honda Cars Philippines, Inc., Isuzu Philippines, Inc., EEI Corporation, A.Y. Holdings, Inc. Pan Malayan Express, Honda Cars Kalookan, Sun Life Grepa Financial, Inc., Philippine Integrated Advertising Agency, Inc. She is also a Treasurer of Business Harmony Realty, Inc.

Mr. Cesar A. Buenaventura, 84, Filipino, O.B.E., has been holding the following positions: Chairman at Buenaventura, Echauz and Partners (BEP) Financial Services, a financial advisory firm; Vice Chairman of DMCI Holdings, Inc., the holding company of one of the largest construction firm in the Philippines; and the Montecito Properties, Inc., an upscale residential development in Canlubang; Vice Chairman of Atlantic Gulf and Pacific Company of Manila (A G & P), the oldest and one of the largest engineering services, industrial construction and heavy fabrication company in the Philippines; a director of various companies such as: Pilipinas Shell Petroleum Corporation, Phil. American Life Insurance Company, iPeople, inc., Semirara Coal Company and Manila International Airport Authority. He is also a Founding Chairman of Pilipinas Shell Foundation, Inc. Mr. Cesar A. Buenaventura has always possessed the qualifications and none of the disqualifications of an independent director. Mr. Basil L. Ong, 62, Filipino, currently member of the board of several companies such as: Transnational Diversified Group, Inc., Adventure Travel and Tours, Inc. (exclusive Philippine representative of American Express, Inc.), Planet Sports, Inc. (Philippine Licensee and Operator of Athlete’s Foot Stores, Nike Stadium Stores and Kidz Station Stores) and Wordtext Systems, Inc. (WSI) and W.S. Pacific Publications, Inc. Ms. Milagros V. Reyes, 72, Filipino, currently holds the following positions: President and Director of Seafront Resources Corporation; PetroGreen Energy Corporation and PetroWind Energy, Inc.; Director of iPeople, inc. and Maibarara Geothermal, Inc.; Director and Treasurer of Hermosa Ecozone Development Corporation. She previously served as President of Petrofields Corp. (now iPeople, Inc.); Senior Vice President of Basic Consolidated, Inc. (formerly Basic Petroleum and Minerals, Inc.); Vice President and Chief Operating Officer of Mapua Institute of Technology, Inc.; Director and Consultant of PNOC-EC. Ms. Yvonne S. Yuchengco, 60, Filipino, is the Chairperson/President of Y Tower II Office Condominium Corporation; Yuchengco Tower Office Condominium Corporation. She is also the President/Director of Malayan Insurance Company, Inc., Mico Equities, Inc., Philippine Integrated Advertising Agency, Inc and Pacific Fund, Inc. She also holds the position of Chairperson of First Nationwide Assurance Corporation, Malayan Plaza Condominium Association, Inc., RCBC Capital Corporation and XYZ Assets Corporation. Director and Treasurer of Pan Malayan Mgm’t. & Inv’t. Corporation, Honda Cars Kalookan and Mona Lisa Dev. Corporation. Assistant Treasurer, Enrique T. Yuchengco, Inc. Member, Board of Trustees AY Foundation, Inc., Mapua Institute of Technology, Inc, and Yuchengco Museum, Inc. She also sits in the board of several companies such as House of Investment, Inc., HYDee Management and Resource Corp., iPeople, inc., La Funeraria Paz, Inc.-Sucat, Luisita Industrial Park Corp., Malayan College Laguna, Inc., Malayan Colleges, Inc., Malayan High School Science, Inc., Malayan Insurance (H.K.) and (U.K), Malayan International Insurance Corp., Manila Memorial Park, Inc., National Reinsurance Corporation of the Philippines, Pan Malayan Realty Corp., Pan Malayan Express, Pan Pacific Computer, Inc., RCBC Land, Inc., Seafront Resources Corporation, Shayamala Corporation, YGC Corporate Services, GPL Holdings, Inc., AY Holdings, Inc. and Asia-Pac Reinsurance Company Ltd. Mr. Raul M. Leopando, 63, Filipino, is currently the Consultant of RCBC Capital Corporation, Chairman of the Board and Nominee to the Philippine Stock Exchange of RCBC Securities, Inc., President and Director of Investment Houses Association of the Philippines (IHAP), Former President and CEO of RCBC Capital Corporation, Member, Board of Directors of the following, Roxas Holdings, Inc., RCBC Capital Corporation, RCBC Securities, Inc., and Bankard, Inc. Mr. Eliseo B. Santiago, 64, Filipino, is currently the Chairman of the Board of Clark Development Corporation. He is a member of the Board of Trustees of Mapua Institute of Technology, Inc. He sits in Board and is a member of the Executive Committee of Isla Petroleum and Gas Corporation. He is also an Independent Director of Supply Oilfield Services, Inc. Formerly, Chief Executive of the Shell Eastern Caribbean Group of Companies covering Supply & Trading, Sales & Marketing and Chemicals businesses of the Shell Group in 15 island countries, based in Barbados; Managing Director of Pilipinas Shell Petroleum Corporation; Senior Adviser to the Regional Managing Director for Asia Pacific, based in London; Country Chairman of the Shell 8

companies in Thailand and concurrently the Vice President for Retail for the Asean countries and Hongkong, based in Bangkok; Country Chairman of the Shell companies in the Philippines in addition to his regional Retail Sales and Operations for the East, based in Manila; Vice President for Manufacturing, Supply and Distribution for the East Zone and subsequently global Vice President for Manufacturing Joint Ventures, based in Singapore. Executive Officers: MILAGROS V. REYES, 72: Other Business Experience: President/ Director

President and CEO (1998 to present)

Director Director/Treasurer Former Senior Vice President Former Director

Seafront Resources Corporation, PetroGreen Corporation, PetroWind Energy, Inc. iPeople, Inc., Maibarara Geothermal, Inc. Hermosa Ecozone Dev’t. Corporation Basic Petroleum and Minerals Corporation PNOC-EC

FRANCISCO G. DELFIN, JR. 52:

Vice President (2008 to present)

Other Business Experience: President / Director Vice President / Director Former Undersecretary Former Assistant Secretary Former Professor, Public Administration & Governance Geophysics Supervisor

SAMUEL V. TORRES, 49 Other Business Experience: Gen. Counsel/Corporate Secretary Corporate Secretary ARLAN P. PROFETA, 40 Other Business Experience: Corporate Secretary Asst. Corporate Secretary Formerly, Tax Manager

Energy

Maibarara Geothermal, Inc. PetroGreen Energy Corporation, PetroWind Energy, Inc. Department of Energy Department of Energy University of the Philippines, Diliman PNOC-EDC

Corporate Secretary (2006 to present)

Pan Malayan Management Inv’t. Corp. iPeople, Inc.; Seafront Resources Corporation; House of Investments, Inc. Asst. Corporate Secretary (2008 to present)

Maibarara Geothermal, Inc.; PetroGreen Energy Corporation PetroWind Energy, Inc. Seafront Resources Corporation Punongbayan & Araullo

b. Final List of Nominees to the Board of Directors The nominees for the proposed election during the July 22, 2014 Stockholders’ Meeting are all incumbent members. The lists of nominees below were pre-screened and shortlisted by the Nomination Committee. Ms. Shirley S. Cueva nominated the three Independent Directors for the year 2014-2015. Ms. Cueva has no relations with the nominees for Independent Directors. Name

Helen Y. Dee Cesar A. Buenaventura – Independent Director Basil L. Ong – Independent Director Milagros V. Reyes Yvonne S. Yuchengco Raul M. Leopando Eliseo B. Santiago – Independent Director

Age

Citizenship

70 84 62 72 60 63 64

Filipino Filipino Filipino Filipino Filipino Filipino Filipino

The Company adopted SRC Rule 38 (Requirements on Nomination and Election of Independent Directors), and compliance therewith has been made. As defined under the said Rule, an Independent Director is a person who, apart from his fees and shareholdings, is independent of management and free from any business or other relationship which could, or could reasonably be perceived to, materially interfere with his exercise of independent judgment in carrying out his responsibilities as a director. The respective Certificates of Independent Directors are attached hereto as Annex “A”. c. Legal Proceedings The Company is not aware of any legal cases, presently or during the last five (5) years, involving the present members of the Board of Directors or Executive Officers or their property before any court of law or administrative body in the Philippines or elsewhere. Moreover, the Company has no information that the above named persons have been convicted by final judgment of any offense punishable under the laws of the Philippines or of any other country. d. Significant Employees The Corporation has no employee who is not an executive officer that is expected to make a significant contribution to the business. The Corporation values its human resources. It strives to develop and maintain a safe, healthy, challenging, rewarding, participative, and fair working environment for all employees, and intends to utilize their full talents and expertise through effective selection, mentoring and development. The Company likewise seeks to offer career opportunities to qualified employees, regardless of gender, belief, ethnic or regional origin, and physical condition. It expects each employee act as a team player and do his or her share in achieving the Corporation’s set goals. e. Family Relationships Ms. Helen Y. Dee and Ms. Yvonne S. Yuchengco are siblings. f.

Certain Relationships and Related 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 also considered to be related if they are subject to common control or significant influences. Related parties may be individuals or corporate entities.

Transactions with related parties consist mainly of: • •

•

Loans granted to subsidiaries which are interest bearing; unsecured, non-interest bearing advances to subsidiaries, which are currently due and collectible and which will be settled in cash. These advances represent expenses incurred by the Parent Company in behalf of the subsidiaries for the wind and geothermal energy projects management fee and rental, which are recorded under miscellaneous income in the Parent Company statements of income.

Details of related party transactions are as follows: Outstanding

balance

Amount of transactions Receivables (Payables) Terms

Related Party Subsidiaries PetroGreen Resources Corporation

Nature

2013

$Rental income Loan and interest 2,298,682 309,195 Advances $2,607,877 Maibarara Management $151,257 Geothermal, Inc. income – Rental income 12,092 Advances $163,349 PetroWind Energy, Inc. Loans and 3,559,762 interest 57,276 Advances $3,617,037 NRDC Accounts payable $51,126 Investor House ofInternal audit $15,837 Investments, Inc. services

and

2012

2013

2012

Conditions

$11,792 – 24,004 $35,796

$– 2,298,682 308060 $2,606,742

$– – – $–

– – –

$152,725 14,421 21,047 $188,193

$– – 10,024 $10,024

$– – – $–

– – – –

– – $– $55,292

3,559,762 57,276 $3,617,038 ($51,126)

– – $– ($55,292)

– – – Non-interest bearing

$29,978

($5,376)

($10,048)

Non-interest bearing

Below are additional discussions on the nature of the related party transactions: •

•

Loans and interest refers to the $2.3 million loan availed by PetroGreen Energy Corporation (PGEC) on December 12, 2013, payable January 12, 2014, at interest rate of 4.5% per annum, and $3.6 million loan availed by PetroWind Energy Inc. (PWEI) payable February 12, 2014, at interest rate of 5.5%; Management income from Maibarara Geothermal, Inc. (MGI) is based on an annual management fee of $0.15 million (P6.447 million), by virtue of the agreement between MGI and the Parent Company that the latter will be providing management services to MGI in exchange for the annual management fee. Rental income in 2012 refers to sublease agreement between the Parent Company and its subsidiaries, PGEC and MGI, who, together with the Parent Company, occupy a single unit in the JMT building. Allocation of rental charges is pro-rated based on actual area occupied. Advances pertain to the reimbursable expenses incurred by the Parent Company in behalf of its subsidiaries. Advances to PGEC consist of Parent Company’s time-writing charges for accounting, legal, management and other support services rendered to Petrowind during the research stage of the Nabas Wind Power Project (NWPP). PetroEnergy has engaged House of Investments, Inc. (HI) to perform internal audit services to PetroEnergy. HI charges retainer fee of P = 56,000 ($1,261) per month totaling to approximately $15,837 per annum. Also in 2012, PetroEnergy engaged HI to perform process review of its hiring, purchasing and disbursement processes. The engagement fee amounted to P = 600,000 ($14,141). 11

•

Accounts payable to Navy Road Development Corporation (NRDC) pertains to the longoutstanding amount owed by the Parent Company to NRDC as of December 31, 2012.

Please see attached supplementary information and disclosures required on SRC Rule 68 as Amended, Schedule C for transactions with other related parties and Note 23, related party disclosure of the attached Consolidated Audited Financials Compensation of Key Management Personnel of the Parent Company The Parent Company has a profit sharing plan for directors, officers, managers and employees as indicated in its by-laws. The amount, the manner and occasion of distribution is at the discretion of the BOD, provided that profit share shall not exceed 5% of the audited income before income tax and profit share. The remuneration of the Parent Company’s directors and other members of key management are as follows:

Salaries and wages and other short-term benefits Directors’ fees Retirement expense

2013

2012

2011

$364,776 145,442 20,993 $531,211

$405,670 188,015 15,709 $609,394

$345,865 142,697 8,447 $497,009

There are no other transactions with any party aside from the above. g. Disagreement with the Company No Director has resigned from the Board of Directors since the date of the last meeting of shareholders due to disagreement with the Company on any matter relating to its operations, policies and practices. 6. Compensation of Directors and Executive Officers Compensation of Directors and Executive Officers

Summary of Annual Compensation Table Name and Principal Position

Year

Top 5 Highest paid key officers: Milagros V. Reyes President Francisco G. Delfin Vice President Carlota R. Viray Chief Financial Officer Arlan P. Profeta Head, Corporate and Legal Affairs Maria Victoria M. Olivar Geosciences Coordinator Total salaries top 5 highest paid officers 2011 2012 2013 2014est All Directors and Officers as a group 2011 2012 2013 2014est

Salary

190,845 206,084 209,268 218,084 190,845 206,084 209,268 218,084

Bonus

138,623 152,340 119,015 109,042 138,623 152,340 119,015 109,042

Other Annual Compensation

16,397 47,246 36,493 36,635 159,094 235,261 181,936 225,309

Total

345,865 405,670 364,776 363,762 488,562 593,685 510,219 552,436

The Company’s fiscal year ends in the month of December of every year. Estimated compensation of all Directors and officers as for year 2014 is $552,436. There are no other arrangements pursuant to which any director of the company was compensated, or is to be compensated, directly or indirectly.

Section 3 of Article VII of the By-Laws of the Company provides that the Board of Directors, Officers and employees shall share in the profit in the amount of five (5%) percent of the audited income before tax of the Corporation. The Board of Directors receives a per diem of P5,000.00, or its dollar equivalent, per meeting attended. No warrants or options were granted to the Directors and Officers from 2001 to 2014. There are no other arrangements pursuant to which any director of the Company was compensated, or is to be compensated, directly or indirectly, other than those stated in the above table during Company’s last completed fiscal year, and the ensuing year, for any service provided as an executive officer or member of the Board of Directors. There is no director, executive officer, nominee for director, beneficial holder and family member involved in any business transaction of the Company. 7. External Auditors a. Appointment of External Auditors The external auditor of the Corporation is the firm SyCip Gorres Velayo & Co. (SGV & Co.), with address at SGV Building, 6760 Ayala Avenue, Makati City, Philippines. The same auditing firm is being recommended for reappointment at the scheduled annual meeting. The representatives of SGV & Co. have always been present at the shareholders’ meeting held during prior years and shall likewise be present during this year’s stockholders’ meeting to respond to appropriate questions or make statements with reference to matters for which their services were engaged. The Company is in compliance with SRC Rule 68 requiring the rotation of external auditors or engagement partners who have been engaged by the Company for a period of five consecutive years or more. The engagement partner who conducted the audit for 2013 is Mr. Michael C. Sabado has not been involved as engagement partner for more than five (5) years. b. Audit and Other Related Fees Audit and Other Related Fees External audit fees of the Group amounted to $41,151, $110,957 and $40,026, for the years ended December 31, 2013, 2012 and 2011, respectively. Said fees are broken down as follows:

Audit and review of the registrant’s annual financial statements and other services rendered in connection with filing of said financial statements with SEC and BIR. Tax consultation – 2010, 2008 ITR Compliance Review Review of quarterly and annual summary of application of proceeds in stock rights offering Business Process Review Functional and Tax Review (P&A) Filing of income tax return to the Gabonese Government (EY) Total

2013

2012

2011

$21,975

$19,718

$17,053 10,701

5,631

5,772

4,144

6,865 73,082 0

9,401 $41,151

11,292 $110,957

6,500 $40,026

The Audit Committee approved the above fees based on the services rendered and the amount paid from the previous year’s audit fees. c. Changes and Disagreements with Accountants on Accounting and Financial Disclosure. The Company has not changed SGV & Co. as its auditor and has not had any disagreements on any matter relating to accounting principles or practices, financial statement disclosures, or auditing scope or procedure during the last three years or any subsequent interim periods. 13

8. Financial and Other Information The Company’s financial statements for the year ended December 31, 2013 and Management’s Discussion and Analysis or Plan of Operations are contained in the Management Report portion of this Information Statement. 9. Corporate Governance A discussion of the Company’s compliance with its Manual on Corporate Governance is contained in the latter portion of Management’s Discussion and Analysis or Plan of Operation. C. OTHER MATTERS 10. Actions with Respect to Reports a) Approval of the Minutes of the 04 July 2013 Annual Stockholders’ Meeting; The Minutes of 2013 Annual Stockholders’ Meeting reflects the following: 1) Approval of the Management Report and the 2012 Audited Financial Statements of the Company for the year ended December 31, 2012; 2) Confirmation and Ratification of all acts, contracts and investments made and entered into by Management and/or Board of Directors during the period 26 July 2012 to 04 July 2013; 3) Election of Seven (7) members of the Board of Directors for the year 2013-2014; and 4) Appointment of External Auditors. b) Approval of Management Report and the 2013 Audited Financial Statements contained in the 2013 Annual Report; c) Confirmation and Ratification of all acts, contracts and investments made and entered into by Management and/or Board of Directors during the period of 04 July 2013 to 22 July 2014; 1) Constitution of various Committees and Appointment of Chairman and Members: (Organizational Meeting held 04 July 2013), such as: Nomination Committee Chairman - Helen Y. Dee Members - Yvonne S. Yuchengco - Cesar A. Buenaventura (Independent Director) Compensation and Remuneration Committee Chairman - Helen Y. Dee Members - Milagros V. Reyes - Cesar A. Buenaventura (Independent Director) Audit Committee Chairman Members

- Cesar A. Buenaventura (Independent Director) - Basil L. Ong (Independent Director) - Helen Y. Dee

Corporate Governance and Risk Management Committee Chairman - Basil L. Ong (Independent Director) Members - Cesar A. Buenaventura (Independent Director) - Eliseo B. Santiago (Independent Director) 14

2) Approval to act as a Project Sponsor for PetroWind Energy Inc.’s (PWEI) P2.8 Billion Term Loan Facility for the Nabas Wind Power Project. (Special BOD Meeting October 11, 2013); 3) Approval to borrow funds through private placements from individual or institutional lenders in the total amount not exceeding 300 million pesos in order to finance its 40% equity in PWEI. (BOD Meeting November 7, 2013); 4) Approval to Act as PWEI’s Guarantor for the Standby Letter of Credit (SBLC) to be issued by DBP where the Corporation will assume the liabilities referred to in the SBLC only in the event that the Surety Bond issued by Malayan Insurance Co., Inc. (MICO) for PWEI in favor of DBP fails to fully cover the SBLC when drawn. (BOD Meeting November 7, 2013); 5) Approval of the 2013 Audited Financial Statements. (BOD Meeting February 18, 2014); 6) Approval for the renewal of Directors’ and Officers’ Liability Insurance. (BOD Meeting February 18, 2014); 7) Approval for the Amendment to the Third Article of Incorporation to indicate the exact address of the principal office of the Company pursuant to SEC Memorandum Circular No. 6, series of 2014. (BOD Meeting May 6, 2014). d) Election of Seven (7) members of the Board of Directors (including Three (3) Independent Directors) for the year 2014-2015. 11. Matters Not Required to be Submitted a) Proof of the required notice of the meeting. b) Proof of the presence of a quorum. 12. Amendments of Charter, By-Laws and Other Documents Pursuant to SEC Memorandum Circular No. 6, Series of 2014, “Existing corporations and partnerships whose articles of incorporation or articles of partnership indicate only a general address as their principal office address, such that it refers only to a city, town or municipality, or ‘Metro Manila’, are directed to file an amended articles of incorporation or amended articles of partnership in order to specify their complete address, such that, if feasible, it has a street number, street name, barangay, city or municipality, and if applicable, the name of the building, the number of the building, and name or number of the room or unit.” Affected corporations and partnerships are given until December 31, 2014 within which to comply. Failure to comply within deadline will not entail any penalty from the SEC, but the SEC may impose the sanctions of deferment of applications such as amendments, certifications, and clearances and the like. The Company’s Articles of Incorporation states, as follows: THIRD: That the principal office of the Corporation shall be established and located in Metro Manila. The Company is therefore required to amend its Articles of Incorporation, and in compliance with the above directive, the same paragraph in the Articles of Incorporation shall be amended to read as follows: th

THIRD: That the principal office of the Corporation shall be established and located at 7 Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City, Metro Manila.

13. Voting Procedures Section 7 of Article III of the – By-Laws of the Corporation provides that: “At all elections of Directors, each stockholder may vote the shares registered in his name in person or by proxy for as many persons as there are Directors, or he may cumulate said shares and give one candidate as many vote as the number of Directors to be elected multiplied by the number of his shares shall equal, or he may distribute them on the same principle among as many candidates as he shall see fit, provided, however, that the whole number of votes cast by him shall not exceed the number of shares owned by him as shown on the Company’s stock transfer books multiplied by the whole number of Directors to be elected.” With respect to amendments to various provisions of Articles of Incorporation, the approval of the stockholders owning two-thirds (2/3) of the outstanding capital stock is required. Other items that need action of the stockholders require simple majority. The voting procedure for election and approval of corporate actions in which Stockholders’ approval will be required shall be by “viva voce”, unless voting by ballot is decided upon during the meeting. The methods by which votes will be counted, except in cases where voting by ballots is applicable, voting and counting shall be by “viva voce”. If by ballot, counting shall be supervised by external auditors.

MANAGEMENT REPORT Part I – Business and General Information Item 1 – Business Development PetroEnergy Resources Corporation (“PERC”, “PetroEnergy” or the “Company”), formerly Petrotech Consultants, Inc., was organized on September 29, 1994 to provide specialized technical services to its then parent company, Petrofields Corporation, and to companies exploring for oil in the Philippines. In 1997, the Company’s name was formally changed into “PetroEnergy Resources Corporation”, simultaneous with the change in its primary purpose from rendering technical services to oil exploration and development and mining activities. On June 25, 1999, the Department of Energy (DOE) authorized the assumption by the Company of Philippine oil exploration contracts. The Ministry of Energy of Gabon, West Africa had also been duly notified of the transfer to PERC of Petrofields’ Production Sharing Contract covering the Etame discovery block in the Atlantic shelf. On May 23, 2003, the Securities and Exchange Commission (SEC) approved the Company’s application for a decrease in authorized Capital from One Billion (1,000,000,00) common shares at a par value of One Peso (P1.00) per share to Three Hundred Thirty Million (330,000,000) shares at a par value of One Peso (P1.00) per share. On July 28, 2004, the Philippine Stock Exchange, Inc. (PSE) approved the listing by way of introduction of the entire issued capital of the Company. On August 4, 2004, the SEC issued to the Company the certificate of permit to offer securities for sale. This certifies that the shares of the Company have been registered and licensed for listing by way of introduction and by then be sold or offered for sale in the Philippines. On August 11, 2004, the Company’s shares were listed at the PSE. On July 22, 2009, the Board of Directors (BOD) and Stockholders approved the amendment of articles of incorporation of the Company to include the business of generating power from conventional sources such as coal, fossil fuel, natural gas, nuclear and other viable 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 to the Company’s Articles of Incorporation was approved by the SEC on September 23, 2009. On September 14, 2009, the Department of Energy (DOE) awarded the Company two (2) Wind Energy Service Contracts (WESC) covering Sual, Pangasinan and Nabas, Aklan wind areas. These WESCs were awarded pursuant to Republic Act No. 9513, otherwise known as the “Renewable Energy Act of 2008”. The Sual wind area had already been relinquished; while an application for the Declaration of Commerciality had already been submitted to the DOE for the Nabas wind area in September 2012. In October 2009, the DOE bid out ten (10) geothermal contract areas, including the Maibarara Geothermal Field. PERC emerged as the lone qualifying bidder for the Maibarara and was consequently awarded Geothermal Renewable Energy Service Contract No. 2010-02-012 (Maibarara GRESC) on February 1, 2010. Subsidiaries of the Company: 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 or PGEC). PetroGreen shall carry-out the renewable energy projects of PetroEnergy. The SEC approved the incorporation of PetroGreen on March 31, 2010. 17

On May 19, 2010, PetroGreen signed a Joint Venture Agreement (JVA) with Trans-Asia Oil and Energy Development Corporation (Trans-Asia) and PNOC Renewables Corporation (PNOC RC) (collectively the “JV Partners”), whereby the JV Partners agreed to pool their resources together to develop and operate the Maibarara Geothermal Power Project (MGPP) through the formation of a joint venture corporation to be named Maibarara Geothermal, Inc. (MGI). Pursuant to the JVA, PetroGreen holds a 65% interest in MGI, while Trans-Asia and PNOC RC hold 25% and 10% interests, respectively. 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. On January 5, 2011, the DOE approved the transfer of the Maibarara GRESC from PERC to MGI. In January 2013, through a Special Meeting of the Board of Directors, PetroGreen created a subsidiary, PetroWind Energy Inc. (PetroWind or PWEI) 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 PertroWind upon the SEC’s approval of PetroWind’s increase in authorized capital stock on August 23, 2013. Effectively as of December 31, 2013, PetroGreen holds 80% equity share in PetroWind. As of December 31, 2013, MGI and PetroWind are effectively, subsidiaries of PERC through PetroGreen since the Parent Company wholly owns PetroGreen and PetroGreen owns majority of the voting power of MGI and PetroWind. The Parent Company, PetroGreen, MGI are PetroWind are collectively referred to as the Group. MGI started commercial operations on February 8, 2014 and is now generating revenues. PetroWind is still in the pre-commercial operation stage and is still not generating any income. The Company has not been subject to any bankruptcy, receivership or judicial proceedings nor has it’s ever been a party to any merger or consolidation. Item 2 - Business of Issuer Description of Business A.

Oil Exploration

Oil and gas are usually buried several thousand meters underneath the earth. The explorationist, therefore, neither sees nor touches his objective. This lack of physical access, however, is compensated by the employment of state-of-the art technology in remote sensing via seismology, geology, and chemistry. In the actual testing of prospects, computer-guided drills dig rock layers several kilometers below the surface. In offshore exploration and production, robot submarines are used to emplace and control subsea equipment and materials. The intensive application of modern technology is supported by large amounts of capital. Oil exploration companies worldwide had adopted the prudent strategy of pooling together, as consortia, in pursuing their projects in order to distribute risk and minimize financial exposures. The common financial arrangement between host countries and the exploration companies is the sharing in costs and revenues from the sale of the hydrocarbon products. The host country partakes in the costs by allowing the explorationists to recover an agreed percentage of the historical costs before the net proceeds are divided between the government and the consortia. Oil Exploration and Development Projects The principal properties of the Company consist of various oil areas located in the Philippines and in Gabon. Petroleum production is on-going in the Etame (Gabon) concession, while the other petroleum concessions in the Philippines are still in the advances exploration stages or pre-development stages The following is a brief description and update of each are: 18

Foreign Operations Gabon, West Africa Total crude in 2013 reached 6.24 Million barrels (mmbo), with daily oil production ranging from 11,400 – 19,700 barrels of oil per day (bopd) from three oil fields – Etame, Avouma, and Ebouri. The new production well EAVOM-3H was put on-line on April 9, 2013 and is now contributing ~1,600 bopd to the overall daily production from the Avouma platform. Due to the natural depletion of the field, increased gas and water contents in some of the wells, successive drilling activities in the Avouma and Ebouri platforms, and transient production downtimes, the average daily production was reduced to an anticipated ~17,000 bopd compared to 2012’s average of ~18,000-19,000 bopd. Nonetheless, the consortium managed 15 liftings for the year resulting to a net crude export of 6.31 mmbo. Crude oil prices for the year averaged US$107.53 per barrel. Aside from the current production activities in the three fields, the Etame consortium pursued the expansion of the existing Etame field. Two new production platforms were fabricated alongside major facilities upgrades in the existing platforms of Ebouri and Avouma fields. All these efforts are geared towards increased oil production and the extension of economic life of the fields. Etame Expansion Project (EEP) The EEP is an on-going effort led by the block Operator, VAALCO Energy, Inc., to evaluate the possibility of increasing production to 25,000-30,000 bopd. Tapping both internal Consortium technical resources and external third-party Consultants, the EEP comprises four separate but related investigations: • Subsurface simulation study to determine remaining recoverable reserves in low, mid, and high cases; • Drilling and completion review to ascertain drilling costs, duration, and design modifications for future well drilling and completion; • Facilities evaluation of thirteen (13) potential development options that led to the identification of six hybrid development concepts; and duration, risks, and profitability. • In 2011, the EEP team recommended two options to be carried further into the pre-front end engineering design (Pre-FEED) stage. These are the “Etame Production Platform” option and the “Nautipa” option. The former will entail the construction of a full production platform in the central Etame producing field. The other, more preferred, scheme will continue to utilize the current Floating Production Storage and Offloading (FPSO) vessel Petroleo Nautipa throughout the field life combined with a new wellhead platform in Etame. This project, which aims to increase production to at least 25,000 bopd, requires new platforms in the central Etame production field and in the greenfield SouthEast Etame/North Tchibala (SEENT) sector. VAALCO Energy Inc., the joint-venture Operator, contracted the engineering firm McDermott to conduct the Detailed Engineering Studies for the new platforms. In November 2012, the partners approved the rd Final Investment Decision (FID) for this project. Once completed by the 3 quarter of 2014, the new platforms can accommodate more production wells for drilling. On December 27, 2012, the Gabonese Government approved the platform construction for the Etame and SEENT expansion program, covering a 15-18 month construction period. The platform topsides facilities design and fabrication were undertaken in 2013, while the transport and installation of parts will be done in 2014. The Gabonese Government has put on hold the approval of the production drilling until next year, pending the presentation of budget and the number and location of the production wells. By end of 2013, most of the long lead items for the Etame and SEENT expansion program had been purchased, while structural fabrication was on-going in Galveston, USA. Transportation and Installation which have been awarded to EMAS in July 2013 will commence in April 2014. Installation of the platforms is scheduled in June-July 2014.

Brownfield Projects Upgrade The upgrade of both Avouma and Ebouri platforms were carried out in 2012 and are nearing completion. Both platforms were extended to accommodate additional well slots for future drilling. With these additions, the electrical systems of the platforms were likewise upgraded to accommodate additional electrical submersible pumps to be installed. The Avouma Water Knock-Out System was installed and hooked-up during the First Quarter of 2013. The system, which will increase crude output going to the Floating Production Storage and Offloading (FPSO) vessel by enhancing the platform’s capacity to separate water from the oil, was fully operational since August 2013. Ebouri Crude Sweetening Project The Ebouri wells EEBOM-3H and EEBOM-4H, which contribute ~2,000 bopd, have been shut-in since July 2012 due to high hydrogen sulphide (H2S). For safety purposes, these wells have been serviced for temporary abandonment in June 2013, and H2S detection devices were installed in the platform. The consortium then conducted a Crude Sweetening Process Study and is currently in the pre-front end engineering (pre-FEED) phase. Results are expected first quarter of 2014. FPSO Integrity Assessment Related to the “Etame Expansion Project” is the assessment of the existing FPSO vessel, Petroleo Nautipa, as to its suitability in the enhanced production plan. Allied Marine Services and BASS, wellknown marine engineering firms, were contracted to assess the FPSO vessel’s life e xtension while SGS was engaged to undertake a Topsides Integrity Assessment. The collective output of the three contractors is the identification of corrective actions to maintain the vessel’s structural integrity and ensure continuous operation throughout the life of the field. The upgrade and modification of the vessel was carried out in 2013. The DNV Class Renewal 2012 for the Nautipa vessel was approved in full terms in mid-October 2013, with the certification valid until August 2, 2017. Shallow Water Exploration Project (SWEP) Current production in the Gabon concession is limited to known fields lying at the center of the permit area in about 80 meters of water. The goal of SWEP is to identify petroleum prospects for future drilling in the northern and northeastern parts of the concession close to the Gabon shore where water depths are 30 meters or less. The SWEP kicked-off in 2011 with the interpretation of existing 3D seismic data acquired in 1997. Geological analyses were also performed on boreholes within the Etame permit block and from wells in adjoining blocks via data trade with other Operators. The Partners carried out a new 3D seismic data acquisition from late October to mid November 2011 over a 240 square kilometer area. The 3D seismic data acquired in 2011 over the concession’s shallow water region was processed and, along with existing joint-venture seismic data, analyzed and interpreted in 2012. By mid-2012, exploration leads were already mapped; towards the end of the year, some of these leads had been matured into drillable prospects. Given that some of these leads and prospects are situated inside the environmentally sensitive Mayumba marine park, the Consortium is also analyzing options on possible drilling and development of these prospects. In parallel, existing prospects in the deeper portion of the concession area west of the Etame production field, are also being considered for drilling. Schedule and appropriate rig availability may dictate how the Consortium carries out its drilling campaign for both deep and shallow exploratory targets. Two prospects, namely Ovaka and Dimba, in the shallow portion of the Etame Marin consortium were approved by the partners to be drilled. However, Sasol has gone non-consent in the drilling of the Dimba prospect. PetroEnergy picked up its allocable share of Sassol’s participating interest, bringing PetroEnergy’s share to 3.26% (only for the drilling of Dimba prospect). 20

Drilling Campaign for 2012-2014 The Ben Rinnes jack-up rig of KCA Deutag mobilized from Port Gentil Gabon to the Avouma Platform in late December 2012 and started the drilling of EAVOM-3P well on January 21, 2013. Successful tagging of oil-bearing Gamba reservoirs led to the drilling of the horizontal drain EAVOM-3H, which served as the new production well from Avouma. After reaching ~2,900 meters on March 8, 2013, the rig skidded to nearby EAVOM-2H and ETBSM-1H wells on March, 26, 2013 to perform work-over procedures to replace their Electric Submersible Pumps (ESP). The Ben Rinnes rig then moved to the Ebouri Platform on May 20, 2013 and commenced drilling of EEBOM-5P well on May 27, 2013. The 34-day operation yielded negative results. The rig skidded to EEBOM-3H and EEBOM-4H for well service procedures after the temporary abandonment of these wells, the rig was skidded to EEBOM-2H well on July 4, 2013 to replace its two ESP units. Operations in the Ebouri platform were completed on July 22, 2013, after which the rig moved to the location of open-water exploration well EOVKM-1 – the Ovoka Prospect, to test the prospectivity of the deeper sedimentary horizons. This turned out to have poor reservoir quality of sands. The well was plugged and abandoned as a dry hole on August 30, 2013 at TD of 2,770 meters. After the drilling of EOVKM-1, the Ben Rinnes jack-up rig was then handed over to Tullow Oil Plc on September 9, 2013 for a two-well drilling program in Tullow Oil’s Kiasserny block. The rig was mobilized back to the Etame block on December 20, 2013 to drill the Dimba exploration well (EDMBM-1) in the shallower portion of the concession area. Philippine Operations SC 14-C2 - West Linapacan, Northwest Palawan The Parent Company has a working interest in Block “C” of SC 14 situated in offshore Northwest Palawan where oil discoveries were made. On December 15, 1975, pursuant to Section 7 of Presidential Decree No. 87, otherwise known as the “Oil Exploration and Development Act of 1972”, the Joint Venture (JV) partners entered into a service contract with the Philippine Government through the DOE for the exploration, exploitation and development of contract area in offshore Northwest Palawan, Philippines, which was amended from time to time. Production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last sixteen (16) years. The investment in WLO included in “Wells, platforms and other facilities” account under “Property, plant and equipment” in the consolidated statements of financial position amounted to $6.65 million as of December 31, 2013 and 2012. Management assessed that the said investment is fully recoverable as SC 14-C is not yet expired, with the 15-year extension of the SC as approved by the DOE, from December 17, 2010 to December 17, 2025, and the existing redevelopment activities led by Pitkin Petroleum Plc (Pitkin). Pitkin completed during the first quarter of 2008 a farm-in to SC 14-C (WLO) on the following terms: • • •

To earn 58.29% participating interest in consideration of $1.5 million and to pay the cost of a Geological and Geophysical (G & G) Work Program; Option to fund the drilling of one well; and Option to fund the development costs of the oilfield attributable to the participating interest of the Farmors.

As part of the farm-in obligations of Pitkin to maintain the SC in good standing, Pitkin obtained from DOE the 15-year final extension of SC 14-C (WLO), from December 17, 2010 to December 17, 2025 in line with similar extensions granted to other SCs in Palawan, (e.g., SC 6-A Octon and Cadlao). The extension carries the following financial obligation to the DOE: 1) One-time development assistance of $30,000; 2) One-time scholarship fund of $20,000; and 3) Yearly training fund of $20,000 during exploration period and $50,000 during production period. 21

The aforementioned obligations may be treated as operating expenses that are cost-recoverable during production. Earlier plans by Operator Pitkin to drill West Linapacan by 2011 failed to materialize due to unresolved technical questions on the reservoir character of the field. Instead, Pitkin farmed-out half of its 58.29% interest in SC14C2 to RMA (HK) Ltd., a subsidiary of Resource Management Associates Pty Ltd of Australia. The Deed of Assignment for this farm-out filed on April 13, 2011 was subsequently approved by the DOE on July 4, 2011. The farm-out has no effect on the Parent Company’s 1.034% interest and status as free-carried up to the drilling of one well. On April 10, 2012, the DOE officially approved the transfer of the service contract’s Operatorship from Pitkin to RMA (HK) Ltd. This operatorship transfer and the preceding farm-out to RMA (HK) Ltd of Pitkin’s 29.145% interest in the concession would result to the subsequent exploration costs leading to the drilling of one well. This planned drilling, originally targeted by late 2012, had to be rescheduled due to the delay in completion of the reservoir simulation study which is a pre-condition for the JV partners’ approval of the drilling program and budget. To address the risks on the anticipated rig mobilization and drilling posed by the existing 1990 West Linapacan subsea production facilities, the original farmors approved a budget to fund a third-party technical study on the best abandonment method. In the meantime, the programmed environmental impact assessment for the drilling activity had been moved to early 2013, after the completion of the reservoir simulation. Drilling of the West Linapacan well, coded WLA-7, has been set on or before the end of June 2014. 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., which request the DOE approved on May 24, 2013. By the first half of 2013, RMA continued its review work for reserves certification and reservoir simulation, alongside further mapping of the West Linapacan field for additional leads and prospects. In parallel, well trajectory and drilling objective planning were also conducted towards early production and full field development in West Linapacan. RMA sent the final Independent Expert Report 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. PetroEnergy’s participating interest in SC 14-C2 is 1.03425%, but will be carried free in all exploration and development costs up to attainment of first commercial oil in the West Linapacan block. SC 51 - East Visayas On August 5, 2005, a Farm-in Agreement (FIA) was signed by the SC 51 members, including the Parent Company, as Assignors, with Australasian Energy Limited, a corporation existing under the laws of the Isle of Man, and Ottoman Energy Limited, a company organized under the laws of Western Australia as Assignees. The Assignors assigned 80% of their participating interest to the Assignees in SC 51 in consideration for the work obligation including funding, at the Assignees’ sole cost of a seismic survey program. The farminee submitted to the DOE a work program composed of drilling one well and acquisition of seismic data. In 2010, the Operator NorAsian Energy Ltd. (NorAsian) presented its drilling program for an onshore well in San Isidro, Northern Leyte, in lieu of an exploration well that would be drilled in the Offshore Cebu. As part of its fund raising activity, it proposed to amend the FIA to accommodate a new Australian Investor, Swan Oil and Gas Ltd. (Swan). The amendment defines the onshore Leyte area or the North Block, where the two farminees intend to drill an exploration well at their sole cost and consequently be assigned a 40% interest each on the block. Their interests are retained when a second onshore well is drilled. On both cases, the farmors (including the Parent Company) are carried free. The South or the Offshore Area that covers the Argao prospect is also defined. Either of NorAsian or Swan or both can opt to drill the Argao Prospect and earn 80% interest in the whole SC 51 contract area. 22

The farmor partners, Alcorn Gold Resources Corporation (Alcorn), Trans-Asia Oil and Energy Development Corporation (Trans-Asia) and the Parent Company, approved the proposed amendment. A final draft of the Amended FIA is being prepared by NorAsian for signature of all the parties. As a DOE commitment for the Consortium’s Sub-Phase 3 (SP3) work program, the on-shore vertical exploratory well Duhat-1 was spudded in San Isidro, Northwest Leyte on April 20, 2011 to test the hydrocarbon potential of service contract’s northern block. After it was sidetracked, the well (Duhat-1A) reached a total depth of 321m but had to be abandoned on May 25, 2011 after persistent mechanical drilling problems. Although the well failed short of reaching its 1,000m programmed total depth, the Operator/Farminee NorAsian obtained DOE approval to consider Duhat-1A as satisfying the Consortium’s SP3 work commitment. However, this well will not be considered as an “earning” well by the farmors Alcorn, Trans-Asia, and the Parent Company. NorAsian’s application on February 3, 2011 with the DOE for the approval of Swan’s farm-in for 40% participating interest in SC 51 was approved by the DOE on July 1, 2011. On August 31, 2011, the DOE also approved the consortium’s entry into Sub-Phase 4 (August 1, 2011 to July 31, 2012) with a revised work commitment of acquiring and interpreting 100 line-km of 2D seismic data in northwest Leyte at a budget of $3.0 million. In November 2011, NorAsian completed the scouting survey for this planned 2D seismic study. It subsequently engaged BGP SE Asia to conduct the 2D seismic survey at a slightly expanded budget of $4.3 million. In December 2011, the SC 51 partners reached an internal agreement to revise the farm-in terms to: 1) divide the SC 51 contract area into a northern (northwest Leyte) and southern (offshore Cebu) blocks; 2) the assignment of NorAsian’s putative 40% interest in the south block to Swan thus relinquishing all of NorAsian’s interest in offshore Cebu; 3) the drilling of a second on-shore well in northwest Leyte to complete NorAsian’s farm-in; and 4) a deadline of April 30, 2012 for Swan to commit to the drilling of the offshore Argao prospect in Cebu, or forfeit all its interests and rights in SC 51. Meanwhile in the South Block, the SC 51 Filipino consortium issued a reminder to SWAN Oil & Gas to exercise its financial capability to drill the Argao-1 deepwater well in Cebu by the end of March 2012, with the consequence of being in default with the Consortium. SWAN disputed its default status, but later announced entering into an amicable agreement with the Filipino partners upon exiting SC 51 on September 20, 2012. On January 25, 2012, the DOE approved the Subphase 4 Work Program & Budget (WP&B) of SC 51. The WP&B for SP 4 includes the acquisition, processing and interpretation of 100km of 2D seismic over the Duhat prospect in the North Block, at a total budget of $4.35 million. The operator of the block, Otto Energy, contracted Beijing-based BGP Asia to conduct the 2D seismic survey. Mobilization of the seismic crew started in February 2012. Actual data shooting and acquisition for the 102 line-km 2D seismic survey over the Duhat prospect was conducted from August to October 2012, at a cost of US$ 3.38MM. Following the completion of the 2D seismic program, the Consortium elected on December 12, 2012 to enter SP 5 with a one well drilling commitment. This made way for commencement of Otto’s well design planning and activities to secure a suitable rig to drill the Duhat-2 well in mid-2013. On January 28, 2013, the DOE approved the SC 51 North block consortium’s election to enter Subphase 5, which includes drilling of the Duhat-2 well in NW Leyte. After acquiring all the necessary permits from the LGUs and appropriate site preparations in San Isidro, Leyte, Duhat-2 was spudded by Operator Otto Energy Investments Ltd. on July 24, 2013. Upon reaching a depth of 201m on July 26, 2013, salt water flow occurred. Otto decided to plug and abandon the well to prevent adverse environmental impact to the local community. Similar to the previous Duhat-1 well, the Farmors, Alcorn (now Cosco Capital), TransAsia, and PetroEnergy did not credit Duhat-2 as an “earning well”. The DOE for its part declared Duhat-2 failed to satisfy the work commitment for subphase 5. Otto Energy appealed to the DOE and was given a 6-month extension to conduct further geologic assessment of Duhat-2 for the remainder of Subphase 5.

SC 6-A - Octon-Malajon Block In March 2007, Vitol GPC Investments S.A. (VGI) negotiated a farm-in to the SC 6-A in offshore Palawan. Under the agreement, Vitol will conduct a study on the prospectivity of the block over a one-year period until March 2008, after which it will decide whether to continue or complete the farm-in process. GPC Investments SA (formerly Vitol GPC Investments SA) gave notice in November 2010 of its decision not to exercise its option on the farm in interest in SC 6-A. This followed the failure of the Galoc Consortium to commit to the second development phase of the Galoc Field. Thereafter, Philodrill reassumed the Operatorship of the Octon Block. In December 2011, to maintain the validity of the SC, the Octon Joint Venture submitted to the DOE a $546,000 work program. It consisted of the reprocessing of 400 sq. km. of the 1997 3D seismic data. Reprocessing would enhance the quality of the seismic information, which would enable the mapping of potential structural drilling targets in the northern portion of the contract area. Following the departure of Vitol GPC from the SC 6A Consortium in late 2010, Pitkin Petroleum Plc (Pitkin), a UK-registered company, signed in July 2011 a farm-in agreement with the consortium members for a 70% participating interest in the block. As farminee, Pitkin will spend, at its own cost, about $5.0 million to acquire, process, and interpret 500 sq. km. of 3D seismic data in Octon. Should it elect to exercise its options, Pitkin may drill up to two production wells at no cost to the farming-out consortium members. On December 6, 2011, the DOE approved the Deed of Assignment transferring the Operatorship and 70% of the service contract interest to Pitkin. Consequently, the Parent Company’s interest in the block was reduced from 16.67% to 5.001% but the Parent Company will be carried free in all subsequent exploration costs up to the drilling of two Octon wells. After the DOE approval of Pitkin’s farm-in and Operatorship of SC-6A on December 6, 2011, Pitkin commenced preparation for Phase 1 activities, consisting of the acquisition, processing and interpretation of ~500km of 3D seismic data. This new 3D seismic program will help further refine the drilling potential of the prospects and leads in the area. In mid-March 2012, Pitkin sent out tenders to ten (10) seismic firms to carry out the 3D seismic survey with the intention of commencing the survey by mid-February, 2013. After the conduct of Information, Education and Communication (IEC) activities and upon securing the necessary endorsements from the Palawan local government units (Palawan Council for Sustainable Development and the Sangguniang Panlalawigan of Palawan) in February to June 2013, Operator Pitkin secured DOE approval for the conduct of the 3D seismic survey for Phase 1. On July 30, 2013, the consortium granted Pitkin request for a one year extension fee. The seismic vessel M/V Voyager Explorer commenced the acquisition of 508 sq.km of 3D seismic data on October 5, 2013 and 48.5 line-km of 2D seismic data tying the Bantac-1 well in SC 57 and the Malajon-1 well in SC 6A. The survey was completed on November 6, 2013. In consideration of the amounts of time needed for seismic interpretation, the consortium agreed with Pitkin to seek DOE approval to extend Phase 1 of the work program for four months, from August 31, 2014 to December 31, 2014. To date, the DOE reply is still forth coming. SC 47 - Offshore Mindoro and Panay The DOE approved on January 12, 2011 a one-year extension of the Consortium’s Sub-Phase 2 (SP2) work program deadline to July 10, 2011. This would enable the Operator, PNOC Exploration Corporation (PNOC-EC), to finish the evaluation of 2D seismic data acquired by the Partners in 2010. PNOC-EC’s evaluation identified at least six potential leads, most of which were in deep water. To further de-risk these leads and enable the Partners to attract potential farminees, PNOC-EC requested the DOE on June 21, 2011 for a further one-year extension of SP2 to carry out a 500-km 2D seismic survey and a source-to-reservoir migration study. PNOC-EC repeated the extension request in August 2011 but no official DOE response had been received till the end of 2011. In the meantime, PNOC-EC is completing 24

the reservoir study, preparing the program for the additional 500 km 2D seismic survey, and discussing farm-in opportunities with potential investors. PNOC-EC, requested for a one-year extension of the contract’s Subphase 2 to July 10, 2012 to conduct detailed source rock-to-reservoir rock migration studies and acquisition of 500km 2D seismic data. These proposed studies were intended to further de-risk the area and attract potential farminees who have been stymied by the discouraging results of the last deep oil well drilled in 2007 by Malaysia’s Petronas. As of end-2012, the application for Subphase 2 extension was still pending approval by the DOE. While awaiting DOE approval, the SC 47 Consortium has been actively seeking potential farminees to carry out the drilling of one (1) exploratory well, as programmed for the subsequent Subphase 3. The consortium has a pending request from the DOE for an extension of SubPhase 2. This request was made by PNOC-EC, in 2012. During the year, farm-out efforts have been carried out by the operator. The farmout terms include seismic processing and drilling of one well. As of end of the year, the farmout process has not been settled. PetroEnergy’s participating interest in SC 47 remains at 2.00% , PNOC-EC at 97%, and Basic Energy at 1%. SC 75 – Offshore Northwest Palawan The joint study and bid group consisting of Philex Petroleum Corporation, PNOC-EC and PetroEnergy was notified by the DOE that the group had won the bidding for Area 4 of the Philippine Energy Contracting Round 4 (PECR 4) last February 14, 2013. The block is located in deepwater areas offshore Northwest Palawan. After finalization of contract terms, the consortium formally signed Service Contract 75 on December 19, 2013. Secretary Petilla then signed on behalf of DOE on December 27, 2013. Under the newly-executed Service Contract, the first Sub-phase will consist of Geological & Geophysical (G&G) studies of the Northwest Palawan Basin and the conduct of a 2,200 line-km 2D seismic survey over SC 75 for the duration of 24 months at an estimated cost of US$ 3.50 MM. Philex Petroleum is the Operator of SC 75 with 50% participating interest, PNOC-EC with 35%, and PetroEnergy with 15%. Summary of Petroleum Properties: Contract No.

Contract Expiry 2014

Participating Location Interest % 2.525% Gabon Offshore

Production Sharing Contract (PSC) 93 - Gabon Service Contracts (SC) - Philippines SC 6A - Octon Malajon Block 2024 5.001% Northwest Palawan SC 14C2 - West Linapacan 2025 1.034% Northwest Palawan SC 47 - Offshore Mindoro pending 2.000% Offshore Mindoro SC 51 - East Visayas 2014 4.012% East Visayan Sea SC 75- NW Palawan 2039 15.000% East Visayan Sea The Company derives its revenues from its Gabon Operations. All contractual obligations with the Gabonese Government are complied with. The Philippine contracts are in exploration stage and some contracts are being farmed out to reduce risk inherent to the business.

Renewable Energy

Maibarara Geothermal Power Project The geothermal project is the 20 MW Maibarara project in Sto. Tomas, Batangas.

2011 Activities The Maibarara Geothermal Power Project (MGPP) accomplished a number of milestones in 2011. In pursuit of further development of the Maibarara Geothermal Field towards commerciality, three wells, namely Mai-6D, Mai-9D and Mai-11D in Pad A, were rehabilitated through work-over operations from January to February 2011. Upon completing work-over operations for the three wells on February 2011, flow tests and discharge testing were conducted in Mai-6D and Mai-9D from March to May 2011 to validate previous output estimates of these wells. In-house resource assessment of the Maibarara Geothermal Field on June 2011 and subsequent Third-Party review by a New Zealand consulting firm in August 2011 confirmed that the proven field resource is capable of generating 20MW of electricity for commercial production for a period of 25 years plant life. The National Grid Corporation of the Philippines (NGCP) approved and released the Grid Impact Study for MGPP in March 2011. The Connection and Transmission Agreements with NGCP were signed in August 2011, ensuring power transmission from the Maibarara field. Power Purchase Agreements (PPA) were finalized on September 2011, ensuring the competitive sale of the produced electricity from Maibarara. The Engineering, Procurement and Construction (EPC) contract for power plant was signed with EEI Corp. last September 2011 along with an operations and maintenance agreement with Fuji Electric. The P2.40-billion project loan facility with lenders RCBC and BPI was signed on 26 September 2011. These funds will be used for the construction of the steamfield pipeline system, the power plant, and related transmission connection. 2012 Activities The 2012 highlights of the Maibarara Geothermal Power Project (MGPP) are as follows: • • • • • •

•

Drilling of MB 12-D, the third production well; Drilling of MB-14RD, which will be used as reinjection for power plant condensates; Work-over of Mai-9D; On-going Fluid Collection and Reinjection System (FCRS) and Power Plant construction; Engaging Meralco Industrial and Engineering Services Corporation (MIESCOR) as contractor for the Engineering Procurement and Construction (EPC) on the transmission lines; Signing of the Interconnection Agreement (ICA) with Manila Electric Company (MERALCO) for the physical interconnection facilities of MGI’s 20 MW power plant to MERALCO’s distribution system; Execution of a Memorandum of Agreement (MOA) between MGI, MERALCO and TRANSASIA.

In 2012, MGI mobilized its team and subcontractors with four concrete goals for 2012: 1) complete the steam production and reinjection well capacities, 2) expedite the construction of the steamfield and power plant facilities, 3) secure the right-of-way and initiate the erection of the transmission line, and 4) fortify our relationship with the host community. The completion of the steam requirement for the 20 MW plant was successfully achieved when MGI drilled its first production well, MB-12D, in July -August 2012 to a total depth of over 2,000 m. After a month of heat-up, MB-12D was successfully flowed for 2 months yielding chemically benign, low-gas, and high-enthalpy fluid with a power output of as much as 12MW. Along with existing wells Mai-6D and Mai9D which were worked-over in 2011, MB-12D completed the steam supply requirement for our 20MW plant. Similarly, the drilling of new condensate injection well MB-14RD to a depth of 1,900 m in October, 2012 with resulting good permeability satisfied the well requirement for condensate fluid reinjection. Along with the 2011 work-over of well Mai-11D to be used for hot brine injection, MGI has the necessary wells for the 20 MW facility’s reinjection load. The construction of the steamfield’s piping system went full blast and neared 53% completion by end 2012. While the engineering design and procurement of the steamfield piping materials were directly handled by MGI, several reputable firms were tapped to undertake different engineering components of 26

the steamfield facility. The steamfield construction works for electrical and insulation will be started in 2013. Parallel power plant engineering, procurement, and construction activities by EEI Corporation reached over 50% completion by end 2012. Foundation works and some vertical structures were already done for many elements of the power plant facility such as the turbine-generator building, workshop building, raw water tanks, condenser, hotwell pump pit, and cooling tower. At the same time, Fuji Electric Co. Ltd of Japan, the project’s supplier of major power plant equipment, reported 72% completion of its task in November, 2012. Fuji Electric assured MGI that it will be able to ship the plant equipment to site within the first quarter of 2013. Major challenges, however, delayed start-up of the transmission line (T/L) installation. To address the hurdles, MGI opted for a shorter, 6 km-long, 115 kV line to connect to Meralco’s existing 115 kV substation at the First Philippine Industrial Plant (FPIP) complex in Calamba. This necessitated signing a new interconnection agreement with Meralco and amending the separate transmission agreement between MGI and NGCP. These new contractual relationships effectively mean that MGI’s power output will have to pass through Meralco’s distribution line if it is to be sold by our aggregator Trans-Asia to parties other than Meralco. MGI finally signed the tri-partite agreement with Meralco and Trans-Asia, the interconnection agreement with Meralco, and the T/L EPC contract with Miescor all on December, 2012. Construction activities for the 115 kV T/L will start in early 2013. If all the major construction activities are achieved on schedule, the project should be ready for initial commissioning tests by the end of 2013 and st for commercial operations by 1 quarter of 2014. 2013 Activities The year 2013 was a productive year for the MGPP. Construction of the Steamfield, Power Plant, Switchyard and Transmission Line facilities were in full-swing. By year-end, these facilities successfully underwent commissioning and testing. In preparation for the pre-commissioning phase, steam flushing of the steamfield surface facilities was conducted on May 17, 2013. The purpose of the flushing is to clean the pipes of debris from manufacturing and installation. This activity was followed by pressurization on June 20, 2013. The production well Mai-6D was fully opened to allow the flow of two-phase fluid through the pipeline and to the separator vessel. This enabled the system to attain the desired operating pressure. The steam was temporarily diverted to the blow-off and rock muffler until such time that the power plant was ready to accept the steam for commissioning and testing. MGI also undertook a successful work-over of reinjection well, Mai-11D, from September 8-18, 2013. The objective of the work-over is to mechanically drill-out the scales that have developed inside the wellbore after being used as an injector of cooled brine. Well Mai9D was temporarily converted from production to reinjection well to address the reinjection requirements of the field. An important milestone was achieved when the target plate testing was successfully carried out last August 9, 2013. The target plate test is a standard procedure conducted to check the quality and purity of the steam prior to admission by the turbine-generator. The two plate tests passed the inspection of the Japanese engineers from Fuji Electric Co. (Japan). After its completion in August 2013, the MGPP’s 115kV Transmission Line system was successfully connected to the existing Meralco line on September 10, 2013. Meanwhile, on October 7, 2013, the Energy Regulatory Commission (ERC) granted MGI the Certificate of Compliance (COC) allowing MGI to own and operate the MGPP. These two major milestones: transmission line energization and COC grant, gave way to the commissioning and testing activities in the power plant. Finally, on November 2, 2013, the valve connecting the steamline and the power plant was opened, and initial steam admission took place. The steam admission was followed by grid synchronization wherein MGPP supplied an initial load of 1MW to the Luzon Grid. During succeeding tests, an issue with the turbine’s Main Control Valve (MCV) was detected. The valve was shipped to Fuji’s plant in Japan for inspection and repair. The MCV was shipped back to the site in 27

late December 2013 and was reinstalled in early January 2014. Upon completion of the reliability and performance testing, the Maibarara Power Plant went on commercial operations on February 8, 2014. Wind Energy On September 14, 2009, PERC was awarded by the DOE with two (2) WESCs (the Wind Energy Projects) covering the areas of Sual, Pangasinan and Nabas, Aklan. These service contracts were awarded pursuant to Republic Act (RA) No. 9513, otherwise known as the “Renewable Energy Act of 2008”. During the two-year pre-development stage of the contracts, PERC should conduct technical feasibility studies in the contract areas in order to confirm the wind power potential in the two (2) areas. The expected total expenditures for each contract amount to about $420,000. As part of the technical study, PERC committed to install a 60m wind mast to measure the wind data characteristics and other relevant parameters. The data from the technical feasibility study will determine whether the wind resource is viable for commercial development and operations. As stated, PERC created PGEC to carry out its renewable energy projects, which includes the wind energy projects. On November 30, 2009, PERC purchased a 60m wind mast from NRG Systems. Power Dimension, Inc. (PDI) was hired to erect the mast at the site. Tower lifting began on February 17, 2010 and the mast was fully raised on February 18, 2010. In September 2010, the Company’s Senior Wind Specialist (consultant), the contracted Danish engineering consultant, recommended the installation of a second mast in Nabas, Aklan to increase confidence in the wind data. Installation of the second mast was completed on the first week of January 2011. Following one year of wind data recording in Nabas (Aklan) and Sual (Pangasinan) wind service contract areas in February 2011, initial micrositing and annual energy production analyses were prepared by the consultant. The consultant reported in May 2011 that the Sual site has only a fair to modest wind resource potential and unlikely to be commercially viable. This result prompted PGEC to relinquish the Sual wind service contract. The DOE formally approved the relinquishment on October 28, 2011. In contrast to Sual, the consultant reported in July 2011 that the Nabas project site can sustain a 50 MW wind farm. This encouraging result led PERC to start obtaining the first set of development permits and conducting initial engineering studies. SMEC Philippines (SMEC) was engaged in September 2011 to undertake the environmental baseline survey of Nabas needed to obtain the project’s ECC. In November 2011, PERC applied with the National Commission on Indigenous Peoples (NCIP) for a Certificate of Non-Overlap (CNO) attesting that the project site does not overlap with any existing indigenous peoples’ ancestral domain claims. PERC also filed with the National Grid Corporation of the Philippines (NGCP) for the conduct of the grid impact study (GIS) which will determine the feasibility of interconnecting the Nabas wind project to the Visayas Grid. A detailed topographic survey of the likely development areas of the project, including an inventory of existing private and public lots was likewise undertaken. On November 8, 2011, the DOE approved the Deed of Assignment and Assumption transferring the WESC from the Company to PGEC. The DOE also granted the one-year extension of the predevelopment phase from September 13, 2011 to September 13, 2012. On December 26, 2011, PGEC obtained the CNO from the NCIP which certified that the project area is free of any ancestral domain claims from indigenous communities. Research costs relating to the Wind Energy power project amounted to $165,079, $147,813, and $114,476 as of December 31, 2012, 2011 and 2010 respectively. These are included as “research costs” under “General and administrative expenses” in the consolidated statement of income. 28

In 2012, PGEC moved to further advance the project towards eventual commerciality. The key activities centered on securing critical government permits, completing technical feasibility studies, and initiating request for engineering, procurement, and construction bids for the wind farm. In June 2012, the critical ECC for the 50 MW Nabas wind power project was released by the DENR Region 6 Office. This gave PGEC clearance to proceed to site development, from road rehabilitation, access road construction, wind turbine installation, transmission line erection, and operation and maintenance of the facility subject to compliance to standard environmental regulations. Another government approval sought was DOE’s Declaration of Commerciality for the project which was applied on September 10, 2012. As part of this application process, the DOE’s Renewable Energy Management Bureau (REMB) conducted a site visit on November 27-19, 2012 to meet with local municipal and barangay officials and DENR staff who assured the DOE team of the strong support for the project. With more than two years of wind data, the consultant completed its technical feasibility study in August 2012, concluding the viability of the site to generate 50MW of wind power with a high capacity factor. At the same time, NGCP completed its own system impact study that stressed that the four wind turbine models from different suppliers are all compliant with NGCP standards; further, NGCP recommended the location and type of transmission connection for Nabas. Using these two major technical studies, PGEC completed in August its own conceptual engineering design of the project, recommending a phased development with an initial phase of about 36 MW capacity and a second 14 MW phase. Given the positive results of various technical studies, PGEC moved to obtain costing and commitment from several likely construction partners for various project components. It started by signing a Heads of Agreement (HOA) with EEI Corporation for the balance of plant construction contract. All the foregoing activities were prompted not only by the positive results of the various technical feasibility studies but also the Energy Regulatory Commission’s (ERC) decision to grant a feed-in-tariff rate of P8.53/kWh to qualified wind farm developers. In May 2013, after several months of review, the DOE conferred the Confirmation of Commerciality for the 50 MW Nabas wind power project in Nabas, Aklan. In confirming the project commercial, the DOE also effectively converted the Nabas service contract from exploration stage to development phase with a contract life of 25 years, or until 2034. The confirmation of commerciality on Nabas brought to four (4) the number of Philippine wind projects officially endorsed for feed-in-tariff (FiT) pre-qualification and competition. As part of the venture into wind energy production, PERC incorporated a new subsidiary – PetroWind Energy, Inc. (PWEI) – on March 6, 2013 to handle the Nabas project development, from securing financing through project construction and eventual operations and maintenance. DOE approved the transfer of the Nabas service contract from PetroGreen Energy Corp. (PGEC) to PWEI in July 2013. Subsequently, on July 15, 2013 EEIPC, a subsidiary of EEI Corporation, subscribed to a 20% stake in PWEI ( EEIPC formally became a stockholder of PertroWind upon the SEC’s approval of PetroWind’s increase in authorized capital stock on August 23, 2013), leaving PGEC with a 80% interest in the Company as of December 31, 2013. On November 4, 2013, DBP granted to PWEI a P2.8 Billion loan for the project payable in 15 years; such loan was the first ever extended by DBP for a wind power project attesting to its confidence on our Company to turn Nabas into reality. Substantial progress was likewise achieved in the technical design and construction aspects of the project. Even as PetroWind awaited DOE’s decision on our confirmation of commerciality, PWEI initiated the rehabilitation of the existing access road to the wind farm as part of corporate social responsibility efforts. The rehabilitation was started in May 2013 with the goal of making the 5-km long barangay road accessible only by motorcycles into a road wide enough to accommodate the entry of the initial wave of heavy equipment. While road rehabilitation efforts were starting, PWEI also signed in late 2013 key 29

construction or supply contracts covering the switchyard and transmission line with Cendaur Engineering, civil works on the wind farm including internal roads, turbine foundations, and control room buildings with EEI Corp., and wind turbine supply, installation, and maintenance and operation with Gamesa Eolica of Spain. All these have set the stage for an expedited program to finish the installation of the wind turbines by late 2014 to early 2015. Summary of Renewable Energy Service Contract: Contract No. Wind Energy Service Contract No. 2009-09-002 Geothermal RE Service Contract No. 2010-02-012

Contract Expiry

Location

2034 Nabas -Buruanga-Malay, Aklan 2035 Maibarara,Batangas/Laguna

Products The Group has crude oil from Etame (Gabon) concession as its product and the same contributes about 98.45 % to total revenues. As of December 31, 2013 Philippine oil projects and renewable energy projects are still in the development and exploration stages and are not generating any income for the Group. For the renewable energy projects, the Maibarara Geothermal Power Project commenced commercial operation on February 8, 2014. This will contribute revenues from sale of electricity for the Group in 2014 onwards. For Nabas Wind Power Project, it is still in the development phase and will generate revenues once it starts its commercial operations. Distribution Method In 2013, crude oil sales from Etame (Gabon) were made through a Crude Oil Sale and Purchase Agreement with Mercuria Trading NV (“Mercuria”). Under the Agreement, Mercuria shall purchase all of the oil produced by the Consortium within the Etame Permit within the year 2013 as at a sales price based on the monthly average during the time of lifting with reference to Dated Brent as published by Platts’ Crude Oil Marketwire an internationally recognized publication on oil process. Physical transfer of the oil was effected at the offshore production site from the Floating Production Storage and Offloading Vessel (FPSO) to the buyer’s oil tanker. Competition In the upstream (oil) local industry and energy industry, companies form a consortium or joint venture to explore certain areas due to high cost of exploration and development. Competition arises when two or more parties bid for a single block offered by the government and have to come up with the best program for exploration. Sources and Availability of Raw Materials and Names of Principal Suppliers The Company is not into manufacturing and has no need for raw materials for its business. Dependence on a single customer or few customers The 100% of the production of crude oil Etame (Gabon) is sold to a single customer on an annual basis. For the year 2013, the Consortium, composed of Sojitz Etame Ltd.; Addax Petroleum Etame, Inc.; Sasol Petroleum West Africa Limited; Tullow Oil Gabon SA and VAALCO Gabon (Etame), Inc., signed an annual crude oil sale and purchase agreement with Mercuria. Sales price is based on the monthly average during the time of lifting with reference to Dated Brent as published by Platts’ Crude Oil Marketwire, an internationally recognized publication on oil prices. Physical transfer of the oil is effected at the offshore production site from the Floating Production Storage and Offloading (FPSO) vessel, to the buyer’s tanker. Failure to negotiate and sign a new sales contract may create an adverse impact on the Company’s profitability. However, sale of crude may be done on a month to month basis with other buyers to ensure a cash flow for operational expenses.

Transaction with and/or Dependence on Related Parties The Consortium operating Etame Oilfield, through the Operator, signed a short term contract for the sale of the crude oil produced in Gabon. Please see “Item 12” for additional discussion on Related Party transactions. Summary of principal terms and expiration dates of all patents, trademarks, copy rights, licenses, franchises, concessions and royalty agreements Aside from the Petroleum Properties and Renewable Energy Service Contracts discussed earlier, there are no other patents, trademarks, copyrights, licenses, franchises, concessions, and royalty agreements entered into by the Group as of December 31, 2013 and 2012. Need for Government approvals of Principal Products Oil industry in the Philippines is regulated by the policies and rules and regulations provided by government agencies like the Departments of Energy, Finance and Environment and Natural Resources. Moreover, generation and sale of electricity need prior approval from the Energy Regulatory Commission. Effect of existing or probable governmental regulations and Costs and Effects of Compliance with Environmental Laws The Company shares in the cost of studies pertaining to compliance to environmental laws in the local oil industry. For the Renewable Energy Project, the Company conducted extensive studies to determine the environmental impact and possible mitigating actions to reduce, if not, eliminate potential threats to the environment connected with the conduct of geothermal operations. Active coordination and consultation with local government units and other stakeholders are also being carefully observed. For the MGPP, the Company conducted extensive studies to determine the environmental impact and possible mitigating actions to reduce, if not, eliminate potential threats to the environment connected with the conduct of geothermal operations. Active coordination and consultation with local government units and other stakeholders are also being carefully observed. The ECC was released on August 10, 2010 to the Parent Company by the DENR. On December 29, 2010, the DENR approved the change in the proponent’s name for the Parent Company to MGI. The ECC for the 50 MW Nabas wind power project was released by the DENR Region 6 Office in June 2012. This gave PGEC clearance to proceed to site development, from road rehabilitation, access road construction, wind turbine installation, transmission line erection, and operation and maintenance of the facility subject to compliance to standard environmental regulations. Tree planting activities were conducted in the Maibarara and the Nabas Wind areas. These were conducted in compliance with the requirements under the ECC and were undertaken in cooperation with the local government units of the areas and with DENR. Amount spent on research and development activities and its percentage to revenues A. Oil Exploration and development

Year 2013 2012 2011

$ $ $

Amount 4,754,007 811,535 1,319,646

% to Oil Revenue 34.66% 6.77% 9.74%

Development costs for the oil projects are mainly from the development of Etame Expansion Project (Gabon) discussed above. B. Renewable Energy Research and Development The Group spent approximately $47.167 million and $9.3 million from inception (research phase) to December 31, 2013 in the research and development of the Maibarara Geothermal Power Project and the Nabas Wind Power Project, respectively. Revenues from these projects will be 31

produced once they reach commercial operation. As of December 31, 2013, the MGPP is in its commercial testing stage, while the NWPP is in its development phase. Total Number of Employees and Number of Full-Time Employees As of December 31, 2013, there were 116 regular employees of the Group. The Group may hire employees in the next twelve (12) months due to increased volume of business, specifically for its renewable energy business. Below is the break-down of regular employees of PERC and its subsidiaries PetroEnergy PetroGreen Maibarara PetroWind Total Employees

20 16 71 9 116

Risk Factors Political, Economic and Legal Risks in the Philippines and Gabon The Philippines has, from time to time, experienced military instability, mass demonstrations, and similar occurrences, which have led to political instability. The country has also experienced periods of slow growth, high inflation and significant depreciation of the Peso. The regional economic crisis which started in 1997 negatively affected the Philippine economy resulting in the depreciation of the Peso, higher interest rates, increased unemployment, greater volatility and lower value of the stock market, lower credit rating of the country and the reduction of the country’s foreign currency reserves. There has also been growing concerns about the unrestrained judicial intervention in major infrastructure project of the government. There is no assurance that the political environment in the Philippines will be stable and that current or future governments will adopt economic policies conducive to sustained economic growth. The State of Gabon is said to be politically stable by African standards, despite having its internal problems. Presiding over Gabon is Ali-Ben Bongo, the son of the continent's second longest-serving head of state, President Omar Bongo. He was elected president of Gabon after the death of Pres. Bongo. Its political stability and ample natural resources have helped make Gabon a wealthy nation compared to the rest of Sub-Saharan Africa. It must be noted however that Gabon's wealth is not distributed equitably, and almost half of the population lives below the poverty line. The oil industry is the key to Gabon’s economy although the government is trying to distance itself from oil dependence and focus on non-oil businesses such as forestry products due to concerns over the life of the oil reserves. The general political situation in and the state of the economy of the Philippines and Gabon may influence the growth and profitability of the Company. Any future political or economic instability in these countries may have a negative effect on the financial results of the Company. The prospects of the Company are dependent on the continuing validity and existence of the various service contracts and exploration and production sharing contracts with the governments of the Philippines and Gabon. Although the Company is in compliance with the requirements of Philippine and Gabon laws, and is unaware of any reason that would result in such termination and cancellation, there can be no assurance that the contracts will not be terminated or cancelled, or that the same will be renewed as and when they fall due. The cancellation, termination and/or modification of any such contracts may have a material adverse effect on the prospects of the Company. Neither can there be any assurance that the properties of the Company will not be confiscated, expropriated, seized or nationalized.

Technical Risk The petroleum exploration industry is a high risk, capital intensive and highly speculative industry. By virtue of the high degree of risk associated with the petroleum exploration business, PetroEnergy participates in the use of high technology equipment and expertise to mitigate the risk involved. Operational Risk Almost all of the Company’s revenues are sourced from equity share in the Etame crude oil production in Gabon Offshore. The production of crude oil may involve many risks such as breakdown of equipment, unexpected levels of output or efficiency, natural disasters, and the need to comply with further directions of the relevant government authority. Moreover, like most oil discovery areas, there are concerns over how long these reserves will last. Any of the foregoing circumstances could significantly reduce revenues or increase the cost of operating the drilling area. Likewise, 100% of the production of crude oil is sold to a single customer on an annual basis. For the year 2013, the Consortium, composed of Sojitz Etame Ltd.; Addax Petroleum Etame, Inc.; Sasol Petroleum West Africa Limited; Tullow Oil Gabon SA and VAALCO Gabon (Etame), Inc., signed an annual crude oil sale and purchase agreement with Mercuria. Sales price is based on the monthly average during the time of lifting with reference to Dated Brent as published by Platts’ Crude Oil Marketwire, an internationally recognized publication on oil prices. Physical transfer of the oil is effected at the offshore production site from the Floating Production Storage and Offloading (FPSO) vessel, to the buyer’s tanker. As stated earlier in the “Risk Factors”, the loss of production from the Gabon oilfield could adversely affect the Company’s revenues and income. Failure to negotiate and sign a new sales contract may create an adverse impact on the Company’s profitability. However, sale of crude may be done on a month to month basis with other buyers to ensure a cash flow for operational expenses. Risk of Venturing into Renewable Energy Projects The Maibarara Geothermal Field is currently being developed and is projected to generate its own income by beginning of 2014. There is a risk, however, that the existing wells which have been worked-over and the eventual steam production may not be able to produce the expected output. This may entail additional costs in putting the project on stream and may pull down the expected economics of the project. Should the MGPP and/or NWPP push through as planned, the following risks may still be present and may have significant effect in the Company’s business, financial condition, and results of operations: •

breakdown or failure of power generation equipment, steam supply equipment, transmission lines, pipelines or other necessary equipment or processes, leading to unplanned outages and other operational issues;

•

flaws in the design of equipment or in the construction of an electric generation or steam supply plant;

•

problems with the quality and quantity of geothermal and wind resources;

•

material changes in law or in governmental permit requirements;

•

operator error;

•

performance below expected levels of output or efficiency;

•

labor disputes, work stoppages, and other industrial actions by employees affecting the projects directly;

•

pollution or environmental contamination affecting the operation of the plants;

•

planned and unplanned power outages due to maintenance, expansion and refurbishment;

•

the inability to obtain required governmental permits and approvals;

•

opposition from local communities and special interest groups;

•

social unrest and terrorism; 33

•

engineering and environmental problems;

•

construction and operational delays, or unanticipated cost overruns; and

•

force majeure and other catastrophic events such as fires, explosions, earthquakes, floods and acts of terrorism and war that could result in forced outages, personal injury, loss of life, severe damage or destruction of a plants and suspension of operations.

The Company cannot assure that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the expected revenues from any of its power or steam generating assets, or significantly increase the costs of operating any such assets. Foreign Currency Risk The revenues of PetroEnergy are predominantly denominated in U.S. Dollars. However, the obligation and expenses of the local areas which do not contribute revenues to the Company are denominated in Philippine Peso. In addition, a substantial portion of the PERC’s future capital expenditures in Gabon are denominated in currencies other than the Peso. During the last decade, the Philippine economy has from time to time experienced instances of devaluation of the Peso and limited availability of foreign exchange. Recurrence of these conditions may adversely affect the financial condition and results of operations of the Company. The Company does not normally hedge its foreign currency exposures as it believes that it has sufficient revenues in U.S. Dollar and/or Philippine Peso, as the case may be, to answer for corresponding obligations. Equity Partnership Risk The Company has been participating in various oil exploration and development activities in Gabon and the Philippines with other parties. The Company is currently engaged in a production sharing contract with an equity share of 2.525% covering the Etame discovery block in the Atlantic shelf. Such equity partnership requires the sharing in costs and revenues from the sale of the Etame crude oil. The Company is also engaged in equity partnership with Trans-Asia and PNOC-RC for the MGPP and in equity partnership with EEI-PC for the NWPP as of December 31, 2013. Said partnership requires sharing in costs and revenues for the sale of electricity. This situation may involve special risks associated with the possibility that the equity partner (i) may have economic or business interests or goals that are inconsistent with those of the Company; (ii) take actions contrary to the interests of the Company; (iii) be unable or unwilling to fulfill its obligations under the production sharing contract or sales contract; or (iv) experience financial difficulties. These conflicts may adversely affect the Company’s operations. To date, the Company has not experienced any significant problems with respect to its equity partners. Financial Risk Management Objectives and Policies The Group’s principal financial instruments include cash and cash equivalents, trading and investment securities (financial assets at FVPL) and receivables. The main purpose of these financial instruments is to fund the Company’s working capital requirements. The Group manages and maintains its own portfolio of financial instruments in order to fund its own operations and capital expenditures. Inherent in using these financial instruments are the following risks on liquidity, market and credit. Financial Risks The main financial risks arising from the Group’s financial instruments are liquidity risk, market risk and credit risk. a.

term and long-term funding requirements, the Group intends to use internally generated funds as well as to obtain loan from financial institutions. The 20 MW MGPP is expected to start commercial operations beginning 2014. Proceeds from sale of electricity will then be used to settle the Group’s loans payable. b.

Market Risk Market risk is the risk of loss on future earnings, on fair values or on future cash flows that may result from changes in market prices. The value of a financial instrument may change as a result of changes in equity prices, foreign currency exchanges rates, interest rates and other market changes. Equity Price Risk The Group closely monitors the prices of its securities on a daily basis, as well as macroeconomic and entity-specific factors which could directly or indirectly affect the prices of these instruments. In case of an expected decline in its portfolio of equity securities, the Group readily disposes or trades the securities for replacement with more viable and less risky investments. Such investment securities are subject to price risk due to changes in market values of instruments arising either from factors specific to individual instruments or their issuers, or factors affecting all instruments traded in the market. There is no other impact on the Group’s equity other than those already affecting net income. Foreign Exchange Risk Exposure to currency risk arises from 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. There is no other impact on the Group’s equity other than those already affecting net income. Interest Rate Risk The Group’s exposure to market risk for changes in interest rates relates primarily to the Group’s short-term investments amounting to $.91 million and $21.42 million for December 31, 2013 and 2012, respectively. Interest rate of loans payable is fixed for the first five (5) years and will be repriced thereafter. There is no other impact on the Group’s equity other than those already affecting net income.

Credit Risk There are significant concentrations of credit risk within the Group since most of its financial assets are from consortium operator, although credit risk is immaterial. The 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. With respect to credit risk arising from the other financial assets of the Group, which compose of financial assets at FVPL, cash in bank and short-term investments, the Group’s exposure to credit risk relates to default of the counter party, with a maximum exposure equal to the carrying amounts of these instruments. As of December 31, 2013 and 2012, the Group has no past due receivables that are not impaired.

Past due and impaired receivable pertains to a long-outstanding receivable from a consortium member which is fully provided with allowance. Capital Management The primary objective of the Group’s capital management is to ensure that it maintains a strong credit rating and healthy capital ratios in order to support its business and maximize shareholders’ value. The Group manages its capital structure and makes adjustments to it, in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may increase its debt from creditors, adjust the dividend payment to shareholders or issue new shares. As of December 31, 2013, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity. Based on the Group’s assessment, the capital management objectives were met in 2013, 2012 and 2011. There were no changes made in the objectives, policies or processes for the years ended December 31, 2013 and 2012, respectively. Properties Aside from the Service Contracts entered into by the Group (refer to business of issuer), below are the major properties owned or leased by the Group: PetroEnergy owns a 714 square meter office unit located at 7th Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City. The title of the Company over the property is clean, and is free from any lien and/or encumbrance. In April 2012, Maibarara entered into a 25-year Land Lease Agreement (LLA) for its steamfeild and access road with Power Sector Assets and Liabilities Management Corp. (PSALM) and paid upfront fees for the entire term. Also, As of December 31, 2013 Maibarara has a $0.760 million worth of purchased lot to be used as MGPP plant site, access road and transmission line. MGI has pledged portion of its land and property plant and equipment amounting as collateral in connection with the loan (please refer to attached Consolidated AFS Note 16, Loans Payable). As of December 31, 2013, PetroWind initially purchased $0.154 million worth (10,500sqm) of lots in Nabas for the development of the NWPP. Aside from the development of the NWPP, wherein PetroWind will acquire additional lots for the construction of the Wind Farm, the Group does not intend to acquire additional properties in the next twelve (12) months. Please refer to Consolidated AFS Note 10, Property, Plant and Equipment of the Group. Item 3 - Legal Proceedings MGI is undergoing a vat refund process as of December 31, 2013. MGI has accumulated Input VAT as of December 31, 2013 amounting to P = 104.8 million or $2.36 million, of which P = 15.79 million or $0.355 million covering the four (4) quarters of 2011 were already filed with the BIR Regional District Office for administrative claim on VAT refund. Moreover, the first two (2) quarters of these claims amounting to P = 13.23 million or $ 0.298 million were already elevated and filed with the Court of Tax Appeals. Aside from the discussion above, The Group is neither a party to, nor is involved in, any litigation that affects or will affect its interests. It has neither any knowledge of any litigation, present or contemplated, against the Company. 36

There are no other pending legal proceedings to which the Group is a party of or which any of its property is subject to. Item 4 - Submission of Matters to a Vote of Security Holders There were no matters that were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report.

PART II - OPERATIONAL AND FINANCIAL INFORMATION Item 5 - Market for Registrant’s Common Equity and Related Stockholder Matters a) Market Price of and Dividends on Registrant’s Common Equity and Related Stockholder Matters 1. Market Information Stock Market Price and Dividend on Registrant’s Common Equity (last 2 years) 1st Q uarte r P a rtic u la rs

Par value High Low Volume

2nd Q uarte r

2013

2012

2013

2012

Php1.00 Php7.24 Php6.10

P hp1.00 P hp7.05 P hp5.25

P hp1.00 P hp7.20 P hp5.95

P hp1.00 P hp6.60 P hp5.62

5.631MM

5.10MM

3.86MM

1.17MM

3rd Q u arte r 2013 Php1.00 Php7.00 Php5.98 .593MM

2012 Php1.00 Php6.30 Php5.88 5.55MM

4th Q u arte r 2013

2012

Php1.00 Php6.13 Php4.02

Php1.00 Php6.30 Php5.80

2.00MM

5.03MM

1st Q u arte r 2014

25-Jun-14

Php1.00 Php5.63 Php5.41 2.894MM

Php1.00 Php7.11 Php6.69 1.238MM

2. Holders As of May 31, 2014, the Company has 2,012 stockholders. Hereunder is the list of the top 20 Stockholders:

STOCKHOLDERS 1. PCD Nominee Corporation (Filipino) 2. House of Investments, Inc. 3 Hydee Management & Resources Corp. 4. Ipeople, Inc. 5. PCD Nominee Corporation (Non-Filipino) 6. Baguyo, Dennis G. 7. Yan, Lucio 8. Ong Pac, Sally C. 9. R.P. Land Development Corp. 10. Tan, Juanita Uy 11. David Go Securities Corporation 12. Ley, Fely 13. Chen Hua Bi 14. Pan Malayan Management & Investment Corp. 15. Mendoza, Alberto &/or Jeanie C. 16. Yu, John Peter C. &/or Yu, Juan G. 17. Phil. Asia Equity Sec., Inc. U-055 18. Orientrade Securities, Inc. 19. Roque, Gonzalo Jr. and/or Roque, Eric 20. Uy-Tioco, George Sub-Total Others Total

SHARES 236,290,672 21,805,861 1,880,779 1,240,651 644,719 498,888 355,468 327,030 309,078 300,781 277,949 266,600 266,599 266,592 251,492 180,000 159,959 121,500 106,640 106,640 265,657,898 8,166,322 273,824,220

PERCENTAGE 86.29% 7.96% 0.69% 0.45% 0.24% 0.18% 0.13% 0.12% 0.11% 0.11% 0.10% 0.10% 0.10% 0.10% 0.09% 0.07% 0.06% 0.04% 0.04% 0.04% 97.02% 2.98% 100.00%

3. Minimum Public Ownership The Company is compliant with the required Minimum Public Ownership of at least 10% of the total issued and outstanding capital stock, as mandated by Section 3, Article XVIII of the Continuing Listing Requirements of the Listing and Disclosure Rules. As of March 31, 2014, the Company’s public float was 64.20%.

4. Dividends In accordance with the Corporation Code of the Philippines, the Company intends to declare dividends (either in cash or stock or both) in the future. The shareholders of the Company are entitled to receive a proportionate share in cash dividends that may be declared by the Board of Directors out of surplus profits derived from the Company’s operations. The same right exists with respect to a stock dividend, the declaration of which is subject to the approval of stockholders representing at least two-thirds (2/3) of the outstanding shares entitled to vote. The amount will depend on the Company’s profits and its capital expenditure and investment requirements at the relevant time.

Dividend declaration in two (2) most recent years Date of Declaration April 26, 2012 April 26, 2012 July 04, 2013

Dividends per Share Cash Stock 10% 10% 5%

Record Date May 18, 2012 September 21, 2012 July 25, 2013

Payment Date June 14, 2012 October 17, 2012 August 20, 2013

5. Recent Sale of Unregistered Securities There was no sale of unregistered securities for the past three years. b) Description of Registrant`s Securities 1. Common Stock The details of the Company’s capital stock are as follows:

No. of shares

Amount

Authorized - 330 million shares at $0.0245 par value Issued and outstanding

273,824,220

$6,321,533

2. Debt Securities - Not Applicable 3. Stock Options - Not Applicable 4. Securities Subject to Redemption call – Not Applicable 5. Warrants – Not Applicable 6. Market Information for Securities Other than Common Equity – Not Applicable 7. Other Securities – Not Applicable

Item 6 - Management’s Discussion and Analysis or Plan of Operation 1. Management’s Discussion and Analysis (Amounts are in U.S. Dollar) a. Consolidated Financial Position (As of December 31, 2013 and 2012) As of December 31 (Audited) 2013 ASSETS Cash and cash equivalents Short-term investments

2012

% Change

% in Total Assets

$2,571,568 914,606

$21,622,222 814,741

-88.11% 12.26%

2.23% 0.79%

138,058 2,606,855

142,827 1,982,027

-3.34%

0.12%

31.52%

2.26%

218,217

414,764

-47.39%

0.19%

Advances, prepaid expenses and other current assets Property and equipment-net

16,933,520 75,072,340

4,966,548 51,455,856

240.95%

14.66%

45.90%

64.99%

Deferred oil exploration cost

11,397,210

6,643,203

71.56%

9.87%

31,417

0.00%

0.03%

266,522

140,523

89.66%

0.23%

5,368,328

3,232,354

66.08%

4.65%

$115,518,641

$91,446,482

26.32%

100.00%

3,709,321

4,742,267

-21.78%

3.21%

235,396

260,098

-9.50%

0.20%

863.11%

0.63%

Financial assets at fair value through profit and loss (FVPL) Receivables Crude oil inventory

Investment properties-net Deferred tax assets-net Advances and other noncurrent assets TOTAl ASSETS LIABILITIES AND EQUITY Accounts payable and accrued expenses Dividends payable Short-term loans payable Income tax payable Loans payable

2,238,080

722,479

75,015

57,214,557

38,943,444

46.92%

49.53%

Accrued retirement liability

116,175

57,812

100.95%

0.10%

Asset retirement obligation

328,389

237,668

38.17%

0.28%

$64,564,397

$44,316,304

45.69%

55.89%

41,277,768

$41,322,799

-0.11%

35.73%

66.62%

8.38%

TOTAL LIABILITIES EQUITY Attributable to equity holders of the Parent Company Non-controlling interest TOTAL EQUITY TOTAL LIABILITIES AND EQUITY

9,676,476

5,807,379

$50,954,244

$47,130,178

8.11%

44.11%

$115,518,641

$91,446,482

26.32%

100.00%

Total assets amounted to US$115.515 million and US$91.446 million as of December 31, 2013 and December 31, 2012, respectively. Cash and cash equivalents consist of cash on hand, cash in banks and money market placements with original maturities of not more than three months. The 88.11% net decrease from US$21.622 million as of December 31, 2012 to US$2.572 million as of December 31, 2013 is mainly due to payments made for progress billings for the construction of the MGPP; development expenses for the Etame Expansion Project in Gabon; and development of the NWPP.

Short-term investments consist of maney market placements with maturities of more than three months but less than one year. The 12.26% increase accounts for additional investments. Financial assets at FVPL amounted to US$0.138 million and US$0.143 million as of December 31, 2013 and December 31, 2012, respectively. The 3.34% net decline is mainly due to slight decline in market prices of investments in stocks traded in the PSE. Receivables, arising mainly from proceeds from lifting/sales and advance payments for Gabon projects increased by 31.52% from US$1.982 million as of December 31, 2012 to US$2.607 million in December 31, 2013. Increase was due to higher outstanding receivable from sales for December 31, 2013. Crude oil inventory declined by 47.39% due to lower number of barrels left unsold (100%) from 234,537 barrels as of December 31, 2012 to 96,643 bbls as of December 31, 2013. Advances, prepaid expenses and other current assets refer to advances to contractors, advances to employees, deferred financing costs, VAT credit charges, prepaid insurance, supplies inventory, refundable deposits, and other prepayments. This account amounted to US$16.93 million and US$4.97 million as of December 31, 2013 and 2012, respectively. The 240.95% increase is mainly due to downpayments made for the supply and construction of wind farm of the NWPP. . Property, plant and equipment (PPE) is up by 45.90% from US$51.456 as of December 31, 2012 to US$75.072 million as of December 31, 2013 in line with the construction of MGPP and Fluid Collection and Reinjection System (FCRS) and costs of completed wells in Gabon. Deferred oil exploration cost amounted to US$11.397 million and US$6.643 million as of December 31, 2013 and 2012, respectively. The 45.90% increase is due to continuous expansion and other development activities in Gabon, West Africa. Investment properties remained unchanged as of December 31, 2013. Deferred tax assets (DTA) occurs due to timing differences in recognizing temporary deductible expenses and temporary taxable revenues such as accrued profit share, accretion expenses, accrued retirement liability, provision for probable losses and change in crude oil inventory. Due to the discussed changes apparently, the Company has a US$0.267 million and US$0.141 million DTA as of December 31, 2013 and December 31, 2012, respectively. Intangible asset for 2013 represents the initial payment for the acquisition of new Accounting software. Advances and other non-current assets consists of the non-current portion of advance rent, advances to contractors, restricted cash, deferred financing costs and MGI’s claim for input tax credit. The 66.08% net addition in 2013 is due to the following activities: • Upfront finance costs for the P2.8B loan application for the Wind Energy Project; and • Claim for input tax credit relative to the vat- zero rated activities of MGPP. Accounts payable and accrued expenses amounted to US$ 3.709 million and US$4.742 million as of December 31, 2013 and 2012, respectively. Settlement of payable to suppliers and contractor and other accruals caused the -21.78% change in this account. Dividends payable amounted to US$0.235 million and US$0.260 million as of December 31, 2013 and 2012, respectively. Balances mainly pertain to unclaimed dividends. Income tax payable mainly refers to the Parent Company’s outstanding income tax payable as of December 31, 2013 and 2012. Higher outstanding income tax payable accounts for higher taxable income in 2013 compared to 2012 taxable income. Short-term loans payable pertains to loan availed in December 12, 2013 with 33 days maturity.

Loans payable pertains to the following loans availed by the group: • US$50.46 million loan facility availed by MGI from RCBC and BPI to finance the construction of 20 MW MGPP; and • US$8.005 million loan availed by PERC from various lenders to finance equity infusion to PetroWind. The increase in this account mainly pertains to the additional loan draw-down for the MGPP project and loan avialment for the Etame Expansion project. Accrued retirement liability amounted to US$0.116 million and US$0.058 million as of December 31, 2013 and 2012, respectively. The 47.51% increase is due to additional funding requirement of the retirement fund. Asset Retirement Obligation amounted to US$0.328 million and US$0.277 million as of December 31, 2013 and 2012, respectively. The 38.17% increase in this account is mainly due to the accretion of present value of the estimated asset retirement fund. The estimate was provided by a third party expert, as engaged by the consortium operator of the oilfields in Gabon, West Africa. Equity attributable to equity holders of the Parent Company amounted to US$41.277 or book value per share of US$0.1506 and US$41.323 million or book value per share of US$0.151 as of December 31, 2013 and December 31, 2012, respectively. Non-controlling interest pertains to the 25% share of Trans-Asia Oil and Energy Development Corporation (Trans-Asia) as well as 10% share of Philippine National Oil Corporation – Renewable Corporation (PNOC-RC) in Maibarara Geothermal, Inc (MGI); and the 20% share of EEI Power Corporation (EEI-PC) in PetroWind Energy Inc.

b. Consolidated Results of Operation (As of December 31, 2013, 2012 and 2011 ) Years Ended December 31 (Audited) 2013 OIL REVENUES

2012

2011

% % in Total Change Revenues 2011 vs. 2011

$13,717,422

$11,990,120

$13,544,412

14.41%

100.99%

5,163,930

5,026,209

5,432,149

2.74%

38.02%

COST OF SALES & SERVICES Oil production operating expenses Depletion

GROSS INCOME GENERAL AND ADMINISTRATIVE EXPENSES

1,448,670

1,622,262

1,855,082

-10.70%

10.66%

6,612,600

6,648,471

7,287,231

-0.54%

48.68%

7,104,822

5,341,649

6,257,181

33.01%

52.31%

3,683,822 10,296,422

3,009,277 9,657,748

2,693,340 9,980,571

22.42%

27.12%

6.61%

75.80%

OTHER INCOME (CHARGES) Interest income Net unrealized foreign exchange gain

202,431 (189,072)

506,150 384,278

524,558 95,112

-60.01% -149.2%

1.49% -1.39%

Net unrealized gain (loss) on fair value changes on financial assets at FVPL Interest expense Accretion expense

7,456 (117,524) (44,070)

24,880 (31,895)

(79,588) (62,433)

-70.03% 0.00%

0.05% 0.00%

38.17%

-0.32%

20,220

1,428

-66.56%

0.05%

(134,018)

903,633

479,077

-114.8%

-0.99%

3,286,982 1,763,572

3,236,005 899,560

4,042,918 1,337,611

1.58%

24.20%

96.05%

12.98%

1,523,410

2,336,445

2,705,307

-34.80%

11.22%

Equity holders of the Parent Company

2,211,220

2,559,582

2,821,548

-13.61%

16.28%

Minority interest

(687,810)

(223,137)

(220,087)

$1,523,410

$2,336,445

$2,601,461

208.25% -34.80%

-5.06% 11.22%

0.008

0.009

0.011

Miscellaneous income (charges) TO TAL O THER INC O ME (C HARGES) NET INC O ME BEFO RE INC O ME TAX PRO VISIO N FO R INC O ME TAX

NET INC O ME

6,761

NET INCOME ATTRIBUTABLE TO:

NET INCOME Basic/Diluted Earnings Per Share (EPS)

Note: Differences in amounts are due to rounding off. The Company generated consolidated net income attributable to equity holders of the Parent Company amounting to US$2.211 million or US$0.008 and US$2.560 million or US$0.009 EPS for the year December 31, 2013 and December 31, 2012, respectively. Parent Company’s stand-alone statement of income recorded a net income of $3.832 million and $3.376 million as of December 31, 2013 and December 31, 2012, respectively. The crude oil revenue is up by 14.41% from US$11.990 million to US$13.717 million as of December 31, 2012 and 2013, respectively. The increase is due to higher average cost recovery rate. This is despite the 11% decline in total production barrels and 4% decrease in average crude oil price per barrel. Below is the comparative data as of December 31, 2013 and 2012. 43

Total production (barrels) Average crude oil price Cost recovery rate

As of December 31, 2013 6.244 million $107.53 2.035%

As of December 31, 2012 7.045 million $112.11 1.566%

Oil Production operating expenses increased by 2.74% due to scheduled work-over of wells, EEBOM2H and EAVOM 2H. Our share for these work-overs is $ 270,371. The 10.71% decline in Depletion is due to lower depletion rate of $9.19/bbls as of December 31, 2013 compared to $9.12/bbls as of December 31, 2012. This is mainly due to lower production barrels and lower net book value of PPE- wells subject depletion. General and administrative expenses increased by 22.42% primarily due to the expenses incurred for the geothermal and wind projects. Other income (charges)-net amounted to US$(0.134) million and US$0.904 million for the year ended December 31, 2013 and 2012, respectively. The 114.8% negative change is due to the following net effects: • 60.01% lower interest income due to decline in the average money market placements (MMP) balances attributed to completion of MGPP, development of NWPP and Etame Expansion Project. • 149.20% turn around on net realized forex changes from US$0.384million net realized forex gain in December 31, 2012 to US$(0.189) million net realized forex loss in December 31, 2013. Changes in forex can be related to the following rate changes: o Peso weakened from $1:P41.05 in Dec. 2012 to $1:P44.395 in December 2013 o Peso strengthened from $1:P43.84 in Dec. 2011 to $1:P41.050 in December 2012 • 70.03% decline in net unrealized gain on fair value changes at FVPL due to lower market value of investments in stocks for December 2013 (reckoned from December 31, 2012 market prices) compared to the volatile market value average movements as of December 2012 ( reckoned from December 2011 market prices). • $0.117 million interest expense from loans • 38.17% increase in accretion expense because of the increase in present value of Asset Retirement Obligation; and • 66.56% decrease in miscellaneous income; in 2012 there was a gain from the disposal of the Parent company’s transportation equipment, none in 2013. Provision for income tax amounted to US$1.764 million and US$0.900 million for the year ended December 31, 2013 and 2012, respectively. The 96.05% decrease is due higher taxable income as of December 31, 2013 compared to 2012. Non-controlling interest pertains to the 25% share of Trans-Asia as well as 10% share of PNOC-RC in Maibarara Geothermal, Inc (MGI) and the 20% share of EEI Corporation in PetroWind Energy Inc. c. Consolidated Financial Position (As of December 31, 2012 and 2011) Total assets amounted to US$91.446 million and US$60.565 million as of December 31, 2012 and December 31, 2011, respectively. Cash and cash equivalents consists of cash on hand, cash in bank and money market placements with original maturities of not more than three months. The 1.29% decline is mainly due to investments in short-term investments with period of more than three months but less than one year. These investments were presented under advances, prepaid expenses and other current assets.

Financial assets at FVPL amounted to US$0.143 million and US$0.109 million as of December 31, 2012 and December 31, 2011, respectively. The 31.01% net increase is mainly due to appreciation of market prices of investments in stocks traded in the PSE. Receivables, arising mainly from proceeds from lifting/sales and advance payments for Gabon projects decreased by 4.53% from US$2.076 million as of December 31, 2011 to US$1.982 million in December 31, 2012. Decline was due to lower outstanding receivable from sales for December 31, 2012 in relation to lower number of barrels lifted. Crude oil inventory amounted to US$0.415 million and US$0.447 million at the end of December 31, 2012 and 2011, respectively. The 7.32% decline is due to lower number of barrels left unsold from 260,566 barrels as of December 31, 2011 to 234,537 barrels as of December 31, 2012. Advances, prepaid expenses and other current assets consists of advances to contractor, deferred financing costs, VAT credit charges, prepaid insurance, supplies inventory, refundable deposits, and other prepayments. This account amounted to US$4.966 and US$7.501 million as of December 31, 2012 and 2011, respectively. The 33.79% drop in this account is mainly due to down-payment recoupment of advances to contactor on the engineering, procurement and construction (EPC) contract with EEI Corporation on the construction of power plant in the Maibarara Geothermal Power Project (MGPP). This will be applied against future billings in the course of construction. The current portion of $3.82 million and $5.99 million as of December 31, 2012 and 2011, respectively, which are estimated to be applied against progress billings within one year from reporting date are classified under “Advances, prepaid expenses and other current assets”. Property, plant and equipment amounted to US$51.456 million and US$21.298 million as of December 31, 2012 and 2011, respectively. The 141.60% net increase is mainly due to continuous construction of the Maibarara Geothermal Power Plant. Deferred oil exploration cost amounted to US$6.643 million and US$5.832 million as of December 31, 2012 and 2011, respectively. The 13.92% increase is accounted for the continuous development of the Etame, Ebouri and Avouma fields. Investment properties remained unchanged as of December 31, 2012. Deferred tax is the net effect of timing differences in recognizing temporary deductible expenses and temporary taxable revenues such as asset retirement obligation (ARO), accrued profit share and retirement liability, provision for probable losses, changes in crude oil revenues and unrealized forex. The company has net deferred tax asset amounting to US$0.141 million and US$0.079 million as of December 31, 2012 and 2011, respectively. The 90.54% positive change is accounted as increase in DTA from ARO and decline in the reconciled crude oil inventory. Advances and other non-current assets consists of the non-current portion of advance rent, advances to contractors, restricted cash and deferred financing costs. The 96.44% net addition in 2012 is due to advance rental payment paid in the lease agreement. On April 23, 2012, the Company entered into a Land Lease Agreement (LLA or the Agreement) with the National Power Corporation (NPC) and the Power Sector Assets and Liabilities Management Corporation (PSALM) over the MGPP’s steam-field lot in Sto. Tomas, Batangas. Under the LLA, the Company will lease the steam-field lot for a period of 25 years, extendable for another 25 years upon mutual agreement of the parties. Accounts payable and accrued expenses amounted to US$ 4.742 million and US$3.231 million as of December 31, 2012 and 2011, respectively. Increase in payable to suppliers and contractor; accrual of interest on loan; and other accruals caused the 46.79% change in this account. Dividends payable amounted to US$0.260 million and US$0.225 million as of December 31, 2012 and 2011, respectively. Balances as of December 31, 2012 and 2011 pertain to unclaimed dividends. The 15.64% increase in this account is mainly attributable to the declaration of dividends as follows: 45

Date of Declaration April 26, 2012 April 26, 2012

Cash dividends per Record Date Share 10% May 18, 2012 10% September 21, 2012

Payment Date June 14, 2012 October 17, 2012

Income tax payable refers to the Parent Company’s outstanding income tax payable as of December 31, 2012 and 2011. Lower outstanding payable of 69.19% accounts for lower taxable income in 2012 compared to 2011 taxable income. Loans payable pertains to the US$54.7 million loan facility availed by MGI from RCBC and BPI to finance the construction of 20 MW MGPP. As of December 31, 2012 and 2011, MGI has outstanding drawdowns of $39.95 million and $13.69 million, respectively. The 192.91% increase in this account is due to the additional drawdowns made in 2012. Accrued retirement liability amounted to US$0.058 million and US$0.034 million as of December 31, 2012 and 2011, respectively. The 70.59% increase is due to outstanding retirement payable for funding in 2012. This was subsequently paid on January 2013. Asset Retirement Obligation amounted to US$0.238 million US$0.474 million as of December 31, 2012 and 2011, respectively. The 49.89% reduction during the year resulted from the change in estimated abandonment costs from $1.54 million in 2011 to $0.87 million in 2012 (the Group’s share to the total accrued retirement obligation of the consortium). The estimate was provided by a third party expert, as engaged by the consortium operator of the oilfields in Gabon, West Africa. Equity attributable to equity holders of the Parent Company amounted to US$41.322 million or book value per share of US$0.151 and US$39.203 million or book value per share of US$0.143 as of December 31, 2012 and December 31, 2011, respectively. Non-controlling interest pertains to the 25% share of Trans-Asia Oil and Energy Development Corporation (Trans-Asia) as well as 10% share of Philippine National Oil Corporation – Renewable Corporation (PNOC-RC) in Maibarara Geothermal, Inc (MGI). d. Results of Operations (For the years ended December 31, 2012 and 2011) The Company generated net income attributable to equity holders of the Parent Company amounting to US$2.560 million or US$0.009 EPS and US$2.925 million or US$0.011 EPS for the year December 31, 2012 and December 31, 2011, respectively. The Company generated total oil revenues of US$11.990 and US$13.544 million for December 31, 2012 and 2011, respectively. The 11.48% drop is due to lower number of from 8,064,359 as of December 31, 2011 to 7,045,073 barrels as of December 31, temporary shut-down of two producing wells which manifested high H2S (colorless, flammable gas).

the years ended barrels produced 2012 caused by very poisonous,

Oil Production operating expenses decreased by 7.47% from US$5.432 million in 2011 to US$5.026 million due to lower royalty payments to the Gabon government. Royalty rate changed from 15% to 13% effective July 2011. Depletion amounted to US$1.622 million and US$1.855 million for the year ended December 31, 2012 and 2011, respectively. The 12.55% decline is due to lower crude oil production. General and administrative expenses increased by 14.63% primarily due to the expenses incurred for the geothermal and wind projects.

Other income (charges) amounted to US$0.904 million and US$0.479 million for the year ended December 31, 2012 and 2011, respectively. The 88.62% positive change is due to the following net effects: • 304.03% increase in net realized gain on forex changes from US$0.095 million in 2011 to US$0.384million in 2012. Reinstatement and strengthening of peso thereof from US$1:P43.84 to closing rate US$1:P41.05 of the peso investments of the group caused the positive change. For 2011, there was a slight movement in this account; • 131.26% positive change in market values of investments in stocks traded in the PSE. In 2011, the group incurred US$0.080 million negative change in market prices in contrary to the 2012 bullish market where in the group incurred US$0.024 million unrealized gain in changes in market prices of these investments; • 1,315% increase in miscellaneous income from the disposal of the Parent company’s transportation equipment, none in 2011; • 48.91% decline in accretion expense because of the change in abandonment cost estimate as discussed above in the asset retirement obligation; and • 3.51% slight decline in the interest income due to lower average money market placements reinvested with in the year. Provision for income tax amounted to US$0.900 million and US$1.338 million for the year ended December 31, 2012 and 2011, respectively. The 32.83% decrease is due lower taxable income as of December 31, 2012. Non-controlling interest pertains to the 25% share of Trans-Asia as well as 10% share of PNOC-RC in Maibarara Geothermal, Inc (MGI). Key Performance Indicators: The following liquidity and profitability ratios indicate acceptable levels of financial condition and performance of the company: 2013 Current ratio Debt-to-equity ratio Asset-to-equity ratio Operating profit margin Asset turnover

3.39:1 1.27:1 2.27:1 51.79% 11.87%

2012

2011

5.90:1 0.941:1 1.941:1 44.55% 14.10%

8.54:1 0.41:1 1.41:1 46.20% 23.15%

Formula Total Current Assets/Total Current Liabilities Liabilities/Total Stockholders’ Equity Total Assets/ Total Stockholders' Equity Operating profit/Revenue Total Revenue/Total Assets

There is a decline in the group’s current ratio as of December 31, 2013 compared to 2012 due to increase of current liabilities from short-term loans and decline in cash equivalents relative to the Etame Expansion Project, construction of the MGPP and development of NWPP. Although there was a decline, the group still has a relatively high current ratio as an indication of the group’s liquidity and ability to pay current obligations as they become due. There is an increase in the group’s debt-to-equity ratio as of December 31, 2013 as compared to 2012 due to MGI’s the additional loan drawdown to finance the construction of MGPP and additional loan made by PetroEnergy to finance its Etame Expansion project. The asset-to-equity ratio indicates the group’s leverage. This increased because of the on-going Etame Expansion, construction of MGPP and development of the NWPP. There is an increase in the operating profit margin as of December 31, 2013 compared to 2012, mainly because of higher cost recovery rate from crude oil revenues. This indicates the yardstick of the group’s operating efficiency.

Decline in the asset turnover is caused by on-going Etame Expansion and construction/expenditure for the MGPP which the group expects its commerciality beginning 2014. 2. Plan of Operations for the next 12 months A. Oil Exploration Gabon, West Africa Aside from maintaining the daily production of the three oilfields (Ebouri, Etame, Avouma), the expansion and upgrade of the Ebouri and Avouma platforms will be continued and completed by this year. Exploration drilling for the shallow water prospects will continue in 2014, with the drilling of the EDMBM-1 (Dimba) exploratory well, followed by workover operations in the EAVOM-2H well and the re-drilling of the ETBSM-1H well. Alongside the operations and the drilling activities, the construction of the two new production platforms in the Etame and Southeast Etame/North Tchibala (SEENT) sector will be pursued and is planned to be commissioned by mid-2014. During the second half of 2014, the development drilling program for the Etame and SEENT platforms will commence, with three Etame and two SEENT wells scheduled to be drilled from said platforms. The Ebouri Crude Sweetening Project will proceed to the Front-end Engineering Design (FEED) phase, which will determine the optimal method to utilize these H2S-laden wells. Buffer operations are scheduled to be conducted in the event of early arrival of rig for the Etame/SEENT drilling program. These buffer operations consist of exploration drilling of other shallow water prospects, appraisal well drilling in the Etame, South Tchibala and Ebouri fields, and unscheduled workovers in existing wells. The partnership will still decide which operations best fit for a buffer activity. Philippine Service Contracts SC 6A - Octon As part of the Phase 1 work commitments to the DOE, Operator Pitkin Petroleum Plc will continue with the processing and interpretation of newly-acquired 500 sq.km 3D seismic data over the Malajon, Barselisa and East Barselisa prospects. In parallel, Pitkin will conduct petrophysical analysis of selected Octon wells and a biostratigraphic/source rock analysis of Malajon-1 well samples. Phase 1 runs from February 1, 2012 until August 31, 2014, pending DOE approval of a four-month extension sought by Pitkin until December 31, 2014. SC 14C2 – West Linapacan Under Phase 2 of the current Work Program approved by the DOE, Operator RMA West Linapacan Pte Ltd. will continue with the preparations for the field development of the West Linapacan field, including the drilling of the West Linapacan A-7 well in December 2014. Other planned activities in 2014 include 1) completion of front-end engineering design (FEED) works leading to Final Investment Decision (FID); 2) FPSO acquisition and facilities upgrade for field suitability for production from West Linapacan; 3) subsea equipment upgrade and mooring installation, among others. In addition, abandonment procedures will be conducted for the old subsea equipment and wellhead assemblies from the old West Linapacan wells. SC 47 – Offshore Mindoro Pending approval from DOE, the consortium will elect to enter Subphase 3 of SC 47 and propose a program to de-risk and mature the Macadamia prospect which will be drilled subsequently. SC 51 – East Visayan Basin In 2014, Operator Otto Energy Investments Ltd. will conduct post-well geological analysis of Duhat-2 well samples as part of their Subphase 5 extension works, which will end on July 31, 2014.

Upon election to enter Subphase 6, the SC 51 consortium will commit to drill one (1) exploratory well in the South Block of SC 51, covering the Argao prospect in offshore Cebu-Bohol. In parallel, farmout efforts are continuing between the SC 51 South Block consortium and potential farminees that will finance the drilling of the Argao prospect. SC 75 – Offshore Nothwest Palawan Under Subphase 1 of the newly-executed Service Contract 75, Operator Philex Petroleum will conduct a 2,237 line-km 2D seismic acquisition survey over SC 75 to further assess the block’s prospectivity. The SC 75 consortium will also conduct Geological & Geophysical (G&G) studies in the block during the remainder of 2014. B. Renewable Energy Nabas Wind Power Project For the next 12 months, construction will be in full swing to develop the Nabas Wind Farm in order to avail of the Feed-in-Tariff allocation. Maibarara Geothermal Power Project The Maibarara Geothermal Power Plant will continue to supply electricity to the grid, with TransAsia as offtaker. Material Commitments The Parent Company is expected to have additional expenditures in oil exploration and development in Gabon, West Africa (about $6.7 million for year 2014 for Etame Expansion Project). The Company’s revenue from the Etame field in Gabon, West Africa will finance said expenditures. With the continuing rise in the price of crude, and dollar/peso exchange rate and continuous oil production in Gabon, the Company is expected to earn more revenues. PGEC is committed to pay its 40% equity share in the development of the Nabas Wind Power Project Discussion of Indicators of the Company’s Level of Performance Productivity Program The Company’s main source of revenue is from the share in Etame, Gabon West Africa. The operator of said project, VAALCO Gabon (Etame), Inc., and the members of the Consortium have defined some wells to be drilled to increase production. VAALCO has the necessary skills to manage the resources and complete the work on time and within budget. Receivable Management Most of the Company’s receivables reported in the Balance Sheet are mainly the receivables from sale of crude oil (Etame, West Africa). These are being recorded once sale of crude is made. Payment will be received 30 days after the sale. For the eleven (11) years since oil production inception, there was no event that the buyer failed to remit the proceeds of the sale. However, the Company is willing to look for another buyer should there be some problem that may happen in the future. Liquidity Management Management of liquidity requires a flow and stock perspective. Constraint such as political environment, taxation, foreign exchange, interest rates and other environmental factors can impose significant restrictions on firms in management of their financial liquidity. The Company considers the above factors and pays special attention to its cash flow management. The Company identifies all its cash requirements for a certain period and invests unrestricted funds to money market placements to maximize interest earnings. 49

Inventory Management The only inventory is the crude oil produced in Gabon. The buyer lifts certain volume and pays the same in 30 days. The operator sees to it that crude oil inventory does not reach 800,000 barrels at any one time to avoid overflow and to generate revenues to cover production costs. Cost Reduction Efforts In order to reduce costs, the Group employs a total of one hundred sixteen (116) employees with multitask assignments. The Company’s general and administrative expense is equivalent to 23.36% of the total revenue. Rate of Return of Each Stockholder The Company has no existing dividend policy. However, the Company intends to declare dividends in the future in accordance with the Corporation Code of the Philippines. Please see Part II, Item 5, 3. Dividends, Page 25 for the Dividend declared for two (2) most recent years. Item 7 - Financial Statements The 2013 Consolidated Audited Financial Statements (AFS) of the Company are incorporated herein by reference. The schedules listed in the accompanying index to Supplementary Schedules are filed as part of this Form 17-A. Item 8 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosures Information on Independent Auditor The Company’s independent auditor is the accounting firm, Sycip Gorres Velayo and Company (SGV &Co.). Pursuant to the Memorandum Circular No. 8 series of 2003 (Rotation of External Auditors), SRC rules mandate the compulsory rotation of audit partner after 5 years. Because the engagement of Partner Cyril Jasmin B. Valencia for the period 2008-2012 has ended, the Company engaged a new Partner Michael C. Sabado for the year 2013. Disagreements with Accountants on Accounting and Financial Disclosures As of December 31, 2013, there are no disagreements with Accountants on Accounting and Financial Disclosure. Corporate Governance The Board of Directors including its officers attended Corporate Governance seminars in compliance with the requirements of the Securities and Exchange Commission. In addition, the total corporate organization received copies of the Manual of Corporate Governance duly approved by the Board of Directors. The Company’s platform of corporate governance is anchored on its Revised Manual on Corporate Governance (Manual). The Manual has been updated to reflect the requirements stated in the Revised Code of Corporate Governance (SEC Memorandum Circular No. 6, Series of 2009). The Manual institutionalizes the principles of good corporate governance in the entire organization. It also lays down the Company’s compliance system and identifies the responsibilities of the Board and management in relation to good corporate governance. The Company believes that compliance with the principles of good corporate governance begins with the Board of Directors. It is the board’s duty and responsibility to foster the long-term success of the company and secure its sustained competitiveness in a manner consistent with its fiduciary responsibilities, which must be exercised in the best interests of the Company, and in proper cases, its shareholders. The corporation’s Board of Directors is composed of individuals of proven competence, integrity, and probity. These individuals determine the Company’s purposes, vision and mission, and strategies to carry out its objectives, ensure compliance with all relevant laws, regulations and codes of best business 50

practices, adopt a system of internal checks and balances, and install a process of selection to ensure a mix of competent directors and officers. Three (3) Independent Directors (namely, Mr. Basil L. Ong, Mr. Cesar A. Buenaventura and Mr. Eliseo B. Santiago) sit on the Board. The Company adopts the definition of Independence in the Securities Regulation Code, and considers as an independent director as one who, except for his director’s fees and shareholdings, is independent of management and free from any business or other relationship which, or could reasonably be perceived to, materially interfere with his exercise of independent judgment in carrying out his responsibilities as a director in the Company. The Board is supported in its corporate governance functions by four (4) committees: the Compensation and Remuneration Committee, the Nomination Committee, the Audit Committee, and the Corporate Governance and Risk Management Committee. The Compensation and Remuneration Committee is tasked to establish a formal and transparent procedure for developing a policy on executive remuneration and for fixing the remuneration packages of corporate officers and directors, and provide oversight over remuneration of senior management and other key personnel ensuring that compensation is consistent with the Company’s culture, strategy, and control environment. The Nomination Committee evaluates all candidates nominated to the Board in accordance with the Manual. The Audit Committee reviews and approves the Company’s financial reports, performs oversight financial management functions, and evaluates and approves internal and external audit plans. The Corporate Governance and Risk Management Committee ensures observance and compliance with good corporate governance practices and shall be responsible for the development and oversight of the Corporation’s risk management program. Below are the Committees and their corresponding members: Nomination Committee Chairman Members

Ms. Helen Y. Dee Ms. Yvonne S. Yuchengco Mr. Cesar A. Buenaventura - Independent Director

Compensation and Remuneration Committee Chairperson Ms. Helen Y. Dee Members Ms. Milagros V. Reyes Mr. Cesar A. Buenaventura - Independent Director Audit Committee Chairman Mr. Cesar A. Buenaventura - Independent Director Members Mr. Basil L. Ong – Independent Director Ms. Helen Y. Dee Corporate Governance and Risk Management Committee Chairman Mr. Basil L. Ong – Independent Director Members Mr. Cesar A. Buenaventura - Independent Director Mr. Eliseo B. Santiago – Independent Director As part of corporate measures to ensure compliance with the principles and policies embodied in the Manual, the Board of Directors designated Atty. Samuel V. Torres, as the Company’s Compliance Officer (concurrent Corporate Secretary). Atty. Torres is responsible for, among matters, determining and measuring compliance with the Manual; appearing before the Philippine SEC upon summons on matters relating to the Manual; identifying, monitoring, and controlling compliance with corporate governance matters; and recommending to the Board of Directors the review of the Manual. Atty. Torres works closely with the Board of Directors, top management, and board committees to evaluate and monitor compliance with the Manual. Specifically, he determines the level of compliance and accordingly recommends the adoption of measures to improve such compliance. Likewise, the various board committees perform oversight duties and functions to ensure proper compliance with the Manual and other corporate policies. The Company also submits governance reports required by the Philippine SEC and the PSE to determine compliance with their rules and regulations, the Manual, and the Code of Corporate Governance.

In line with the Company’s aspirations for growth and development, the Company continues to work towards enhancing its adherence to the principles and best practices of good corporate governance. There was no deviation from the Company’s Revised Manual of Corporate Governance as submitted to the Securities and Exchange Commission. The Company has no plan to improve its Revised Manual, provided no new instructions or rules are issued by the Securities and Exchange Commission.

Petr)gnergr/

7/F JMT Building, AOB A\renue, Ortigas Center

Pasig City 1600, Mefo Manila, Philippines 637-2917 Fax: (632) 63.14066 E-mail: petro_energy@petroenetgy.com.ph

Tel: (632)

PETROENERGY RESOURCES CORPORATION

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

February 18,2O14

Securities and Exchange Commission SEC Building, Edsacreenhills Mandaluyong, Metro Manila

The management of PetroEnergy Resources Corporation is responsible for the preparation and fair presentation of the consolidated financial statements for the years ended Decembet 31, 2013 & 2012 including the additional components attached therein, rn accordance with the prescribed financial reporting framework indicated therein. This responsrbility includes designing and implementing internal controls relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or enor, selecting and applying appropriate accounting policies, and making accounting estimates that are reasonable in the circumstances.

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

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

Helen Y/Dee Chairman of the Boar

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SUBSCRIBED AND SWORN to me before this Affiants exhibited to me their Residence Certificate Numbers indicated below each name.

TAX IDENTIFICATIONNO,

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101-562-982 100-732-775 100-732-809

Helen Y. Dee Milagros V Reyes Carlota R. Viray

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Sycip Gorres Velayo & Co. 6760 Ayala Avenue 't 226 Makati City

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

Philippines

BOA/PRC Reg. No.0001, December 28, 2012.valid unti, December 31. 2015 SEC Accredilation No. 0012-FR-3 (croup A), Novembe. 15.2012, vatid ustit November t6.2Ois

II{DEPEIYDENT AUDITORS' REPORT

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

We have audited the accompanying consolidated financial statements of PetroEnerry Resources Corporation and Subsidiaries (the Group), which comprise the consolidated statements of financial position as at December31,2013 and 2012, and the consolidated statements of income, statements of comprehensive income, statements of changes in equity and statements of cash flows for each of the three years in the period ended December 3I,2013, and a summary of significant accounting policies and other explanatory information.

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

uditors' Respons ibility

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

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financiai sta-tements, whether due to fraud or effor. In making those risk assessments, the auditor considers intemal control relevant to the entity's preparation and fair presentation ofthe consolidated financial statements in order to- design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal contol. An audit also inctudes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

A mgmber lirm of

Ensr & Young ctobet Umited

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Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of PetroEnergr Resources Corporation and Subsidiaries as at December 31,2Q13 and 2012, and their financial performance and their cash flows for each ofthe three years in the period ended December 31,2013 in accordance with Philippine Financial Reporting Standards.

Emphasis of Matter Without qualiffing our opinion, we draw attention to Note l0 to the consolidated financial statements, which discusses the suspension of the production activities in the West Linapacan Oilfield. Among the other operations of the Group, the suspension of the production activities in the West Linapacan Oilfield raises uncertainties as to the profitability of the peholeum operations for the said oilfield. The

profitability of petroleum operations related to the said oilfield is dependent upon the discovery of oil in commercial quantities that would result from the successful redevelopment activities thereon.

SYCIP GORRES VELAYO & CO.

-m/M'u0g#6 \

Michael C. Sabado Partner

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

Februarv 18.2014

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PETROENERGY RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF FINANCIAL

IARIES

(In U.S. Dollars)

(A/restated Note

2013

ASSETS

Current Assets Cash and cash equivalents (Notes 6 and 24) Short-term investments (Notes 6 and 24) Financial assets at fair value through profit or loss

$2,571,568

$2t,622,222

(Notes 7 utd24)

138,058

142,827

109,018

2,606,855

1982p27

2,076,016

218,217

414,764

441 4q9

16,933,520

4,966,548

23,382,824 29,943,129

7,048,600 31,585,417

75,072,340

,455,856 6,643,203 140,523

2t,297,963

3r,4r7

31,4t7

Receivables (Notes 5, 8 and 24) Crude oil inventory Prepaid expenses and other current assets

(Notes 9 and 16) Total

CurrentAssets

921,904,284

8t4,741

914,606

Noncurrent Assets Property, plant and equipment (Notes 5, 10 and l6) Defened oil exploration costs (Notes 5, l1 and 25) Deferred tax assets - net CNotes 5,20 and 25) Investment properties (l.lotes 5 and 12) Other noncurrent assets fNotes l4 and 24 Total Noncurrent Assets

11,397210 266,522 31,411

3.232.354

5,83 1,668

82,203 1.734

92,135,911 61,503,353

29,977 ,476

s3,944,717

$5,002,36s

$3,455,507

75,0 i 5

243,474 3,698,981

LIABILITIES AND EQUITY Current Liabilities Accounts payable and accrued expenses (Notes 15, 18

and24) Current portion of loan payable (Notes 16, 1 8 and 24) Total Current

2,238,080

722,479

Liabilities

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

6,905,276 5,077,380 18

57,214,557

38,943,444

57,812

116,l75

33,5'.72

328,389

237,668

474,293 r 3.803.004

4,564,397

44,316,304

17,501 ,985

57 6

13,295,139

(Forward)

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2012 (As restated

2012 (As restated -

Equity Attributable to equity holders of the Parent Company Capital stock (Note 18) Additional paid-in capital (Note 18)

$6,321,533 25,244,737

$6,321,533

2s,244,737

25,244,737

Retained eamings

Appropriated (Note l8) Unappropriated (Note I 8) Remeasurements of net accrued retirement liabiliw (Notes 3, l8 and 19) Cumulative translation ad 5 and 18 Noncontro

interests CNotes 18 and

See accompanying Notes

3,149,555

2,055,555

7,730,,291

6,928,309

5,656,403

(47,563)

(s,707)

(12,720)

1.120.775)

4L,277,768 9.676.476

4t,322,799 5.807.379

39,209,281

47.130,r78

43.060

3.851

to Consolidated Financial Slatements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLil)ATED STATEMENTS OF INCOME (In U.S. Dollars)

Years Ended December 31 2012 2011 (As restated - (As restated -

oIL

REVENUES

COST OF OIL REVENUES Oil production (Note 2l) letion

Note l0

$13,717,422 $11,990,120 5,163,930

$13,544,412

5,432,149 1.855.082

GROSS INCOME

GENERAL AND ADMINISTRATIYE EXPENSES fNote 22

3.009.277

oTrrER INCOME (CHARGES) Interest income (Note 6) Net gain (loss) on fair value changes on financial assets at fair value through profit or loss (Note 7)

202,43L

Accretion expense (Note 17) Interest expense Net foreign exchange gain (loss)

(7e,s88)

(t89,072)

384,278

INCOMN, BEFORE INCOME TAX

3,296,992

PROVISION F'OR INCOME TAX

1.7

l,89s)

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

s2,211,220 687.810 10

62,433) o< I l, 1.428

3,236,005 899.560

NET INCOME (Note 25

See accompanying Notes to

24,880 (3

76L

EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF' TIIE PARENT COMPANY - BASIC AND DILUTED CNote

524,558

7,456 (44,070) (117,524)

Miscellaneous income

NET INCOME

s06,l s0

4,042,9r9 l ,337.61

336.445

70s.307

$2,s59,s82

s2,925,394

220

445

705

$0.009

$0.010

Cowolidated Financial Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In U.S. Dollars)

Years Ended December

2012 2011 (As restated - (As restated -

NET INCOME

$1,523,410

s2,336,445

(1,899,147)

834,600

s2,705,307

oTHER COMPREHENSTVE TNCOME (LOSS) Items to be reclassified to profit or loss in subsequent periods Movement in cumulative translation adjustment

(r 1s,390)

Items not to be reclassified to profit or loss in subsequent periods Remeasurement gains (losses) on net accrued retirement - net oftax (Notes 3. 18 and 19

12.720

TOTALCOMPREHENSWLT,Sq3)

$3,178,058

52,5'77,197

$3,401,195 223.13 $3. r 78.058

$2,797,284 220 77.r97

TOTAL COMPRDHENSM TNCOME (LOSS) ATTRIBUTABLE TO: Equity holders of the Parent Company Noncontrollins interests

$270,217 687.810

t7 See accompanying Notes to Consolidated

Financial Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLDATED STATEMENTS OF'CHANGES IN EQUITY

(In U.S. Dollars)

Attributable to Equity Holders ofthe PrrentCompany Additional

Appropriated

Uoapprop.i.acd

ReEessnremenl of Net Accrued RetiremcDt

Paid-irl

R€t ined

R.taimd

Liebility

Capit!l

Adjuslment

Earnings

(Notes 3,

(Notcs 5

Cumul.tive Translatiotr

Nonconhollitrg Interests (Not€s

Total

lE and

and

For tbe Yerr Ended Dccember3l. 2013

4t rDcome

Remeasurement loss on net accrucd retirement liabilitv (Note 3) in oumulative comprehensive income (loss) Lrcrease itr nooconholling irltercsts - stook issu&ces (Note 27) Appropriarion ofreaiaed camings (Notc l8)

2,21t,220

(687,8r0) (4r,Es6)

(41,8s6)

r,094,000

(1,899,r4?)

l's23,410 (41,8s6)

(6E7,6r0)

(417,s93)

4,55690?

4,556,907

(1,094,000) s41.277.168

For the Year Ended December 31, 2012

BalaNes at beginning ofyear, as previously reported Effect of th6 of the Revised PAS 19 of vear. as Net iocome (loss) Net iDcome (loss), as previously leported Net incoma (loss), ar r€steted Oaher compreheDsiv. income (loss) Effeot ofadoptio! ofthe Revised PAS 19 (Note 3)

Incr€ase in oonconholling inler€sts - stock issuancas (Not! 27)

Cash

Brlauces

$2,055,555

$5,637,88r I

$3,851,627

(223,137) 2.s59,582

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2559,s82 1,013

7,013

$q,ooo s3i,i6o 834,600

3,401,195

(223,137)

2,336J4s 7,013

s:i;60 3,178,058

2,r78,889

€nd

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Attributable to Ruity HoldeB ofthe Parent Compaty Remeasurehents

ofNet Accrued Additional

Appropriated UnapFopriated

Paid-in Capital

Retained

Retircm€nl

Retaircd

Liability

Cumulative Translation AdJustment

Eamings

(Notes 3, l8 and

{Notes 5 aad I

For tbe Year End€d December 31. 201

rcported

restated

and

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3) Molcdrcntinclmuladvctranslarionadiustmcnt-----.tr<ronr,ir<.ro^\/,,cr^ri Total oonp.ch.asiw incomc (loss), as restar€d Incrcasc in noocootolling interests - stock issuanc€s (Note 27) Cash divideods

2,926268 nzar t,rZ*Sa

02,120)

(ZZO,O87,

2,926,268 zorrr 2,925,394 (12,720)

2,Z06,tEl

'"."'

Aro,o87) _

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2,E4t,t16

2,84t,1l6

<t2,:2l)

Br|aDc€'tendofvear$6'32l,533s25,244,737$2,055,555ss,ese,lbr'sst'eur$43,o6o.9o8

See

Interests

(Notes

of ycar, as prcviously

Net iaoome (loss), as previously Effect ofadoption ofthe Revised PAS 19 (Note Net iroome (loss), as Other com preheosivc income (loss) Effect ofsdoprion ofthe Rcvised PAS 19 (Note

Noncontrolling

071

accompanying Notes to Consolidzted Financi.al Statements.

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF' CASH FLOWS Qn U.S. Dollars)

Years Ended December

2012

2011 (As restated

(As restated

CASH F'LOWS FROM OPERATING ACTTVITIES

Income before income tax Adjustments for: Net unrealized foreign exchange loss (gain) Depletion, depreciation and amortization (Note Decrease in accrued retirement liability Accretion expense (Note 17) Interest

$3,286,9g2 $3,236,005

10)

income

Net loss (gain) on fair value changes on financial assets at fair value through profit ot loss (Note 7) Gain on sale of property, plant and equipment Interest

lgg,07z (3g4,278) (g5,ll2) l,j4j,ggs 1,963,392 2,003,3g9' (l,4SZ) 31,567 (106) 44,070 31,g95 62',433' eLZ,4Sl) (506,150) (524,558)

Receivables Crude oil inventory

(17

29,s88

.g92\

1fi.524

changes

assets

(24,880)

e,4s6) _

expense

Operating income before working capital Decrease (increase) in: Short-term investments

$4,O4L,glg

'l743W (99,g65) 635,492j 196,547

(514,741)

77,53:. SO2,B44 32,735 (247,0g7) (12,403,g66) 1,g50,010 i+sa,l+i

Prepaid expenses and other current Increase in accounts payable and accrue4 expenses (1,31g,070) 1,104.g93 Cash generated from (used in) operations (9,089,432) 6,480,093 Interest received 221,020 482,433 lncome taxes Net cash used in activities 696

8,039,252 684,443

CASH FLOWS FROM IITVESTING ACTTVITIES Acquisitions of property, plant and equipment (Notes l0 and 28) Proceeds from disposals of: Property, plant and equipment (Note

(25,317,818)

(32,353,911)

l0)

Intangible asset Financial assets at fair value through profit or loss Increase in capitalized interest Increase in Other noncurrent assets Increase in deferred oil exploration costs (Note l1) Increase in deferred costs Net cash used in activities

(8,775,750)

81,997

3,655,7;

r,3$,6;

Q,135,974)

2,1s7,885 (1,263,600)

(6,862,760)

(4,754,007)

(81 1,535)

(996,29r)

189.164

10,039

15.261.122

(Forward)

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-2Years Ended December 3l 2012 2011 (As restated (As restated - Note 3 - Note 3

CASH FLOWS FROM FINANCING ACTryITIES Proceeds from long-term debt (Note 16) Additional capital from noncontrolling interest CNote 27) Dividends paid (Note l8) Interest paid Net cash orovided

s20,946,086

$25,648,305

2,178,890

4,556,907

(339,949)

(r,252,489)

$12,111,820

2,841,116 (1,243,767)

1.708.9s3

activities

EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH AND CASH UryALENTS NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

24.865.7s3

13.709.r69

1.210.6s3

$17.672

(19,050,654)

(282,062)

5,819,800

CASH AND CASH EQUryALENTS AT BEGINNING OF YEAR

cAsII AND CASH EQUMLENTS AT END OF YEAR fNote See accompanying Notes to Consolidated

Finoncial Statements-

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars)

Corporate Information

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

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

On February 1, 2010, the Parent Company signed Geothermal Renewable Enerry Service Contract (GRESC) No. 2010-02-012 covering the Maibarara Geothermal Field ("the Field") in Laguna and Batangas, following a Philippine Energy Contracting Round for Geothermal held by the Deparunent of Energy (DOE) in November, 2009, where the Parent Company emerged as the lone qualified bidder. The Field had been previously explored and relevant resource data identiff certain portions thereof as having potential stored heat capacity that can produce electricity in commercial quantities. In order to insulate PetroEnergy's oore oil business from its renewable enerry venfures, PetroEnergr, with the approval of the Board on February 23,2010, created a wholly-owned subsidiary called PetroGreen Enerry Corporation (PetroGreen). PetroGreen shall carry-out the renewable energy projects ofPetroEnergy. The SEC approved the incorporation of PetroGreen on March

3 I , 201 0.

On May 19,2010, PetroGreen signed a Joint Venture Agreement (JVA) with Trans-Asia Oil and Enerry Development Corpomtion (Trans-Asia) and PNOC Renewables Corporation (PNOC-RC) (collectively the JV Partners), whereby the fV Partners agreed to pool their resources together and enter into ajoint 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 MGL while Tran-Asia and PNOC-RChold2S% and l0%, 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 ofthe Board ofDirectors, PetroGreen created a subsidiary, PetroWind Enerry, Inc. (PetroWind) that will undertake the Nabas Wind Power Project (NWPP). PetroWind was incorporated on March 6,2013 wherein PetroGreen initially held 100% interest. On July 15, 2013, EEI Power Corporation (EEIPC) subscribed to a 20%

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-zequity share in PetroWind. EEIPC formally became a stockholder of PenroWind upon the SEC's approval of PetroWind's increase in authorized capital stock on August 23,2013. Effectively as of December 31,2013, PetroGreen holds 80% equity share in PetroWind.

MGI and PetroWind are eflectively, subsidiaries of the Parent Company through PetroGreen, since the Parent Company wholly owns PetroGreen and PetroGreen owns majority of the voting power of MGI and PetroWind. The Parent Company, PetroGreen, MGI and PetroWind are collectively referred to as the Group.

Nature of Ooerations The Group's three (3) main energy businesses are petroleum, wind and geothermal energy. Petroleum Petroleum production is on-going in the Etame (Gabon) concession, while the other petroleum concessions in the Philippines (Northwest Palawan, Offshore Mindoro, Eastern Visayas) are still in the advanced exploration stages or pre-development stages. See Notes l0 and l1 for updates on the Group's petroleum operations. Wind Energt The wind energy project is the 36-megawatt (MW) NWPP in Nabas, Aklan, where PWEI is now developing the area. The activities in 2013 concentrated on the application from the DOE for Declaration of Commerciality and selection of contractors for the various project components, such as wind turbine generators (WTG) supply, installation and operation and maintenance, civil works and transmission line and switchyard construction. Financing for project through bank loan was also worked on during the year. See Note 33

for more updates on Wind Energy Service Contract.

Geothermal Energt

The geothermal project is the 20-MW Maibarara Geothermal Power Project (MGPP) in Sto. Tomas, Batangas where MGI's construction of the steamfield, power plant, switchyard and transmission line facilities is in full-swing. These facilities were successfully undergoing commissioning and testing in the last quarter of 2013. See

Note l0 for more updates on the Group's geothermal enerry operations.

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

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

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The consolidated financial statements provide comparative infomation in respect of the previous period. In addition, the Group presents an additional statement of financial position at the beginning ofthe earliest period presented when there is a retrospective application ofan accounting policy, a retrospective restatement, or a reclassification of items in consolidated financial statements. An additional statement of financial position as at January i, 2012 is presented in these consolidated financial statements due to retrospective application of Philippine Accounting Standards (PAS) 19 Revised, Employee Benefits. Statement of Compliance The accompanying consolidated frnancial statements have been prepared in compliance with Philippine Financial Reporting Standards (PFRS). Basis of Consolidation The consolidated financial statements comprise the financial statements of the Group as at December 31,2013 and20l2. The financial statements ofthe subsidiaries are prepared for the same reporting year as the Parent Company, using consistent accounting policies.

Below are the Parent Company's subsidiaries with its respective percentage ownership as December 31, 2013,

2012,and20ll:

PGEC

Percentage of Ownership 2013 20t2 l00o/o r00%

MGI

650/o

PWEI Navy Road Development Corporation (NRDC)

80o/o

1000h

65%

2011 100% 6s%

l00Vo

100%

Subsidiaries are consolidated when control is transfened to the Group and cease to be consolidated when control is transferred out ofthe Group. Control is achieved when the Group is exposed, or has rights, to variable retums from its involvement with the investee and has the ability to affect those returns through its power over the investee. Specifically, the Group conhols a subsidiary if and only if the Group has:

a) b)

Power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee) Exposure, or rights, to variable returns from its involvement with the investee. and The ability to use its power over the investee to affect its retums

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) b)

The contractual arrangement with the other vote holders of the investee Rights arising from other contractual arrangements The Group's voting rights and potential voting rights

The Group re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control.

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

Noncontrolling interests are presented separately from the Parent Company's equity. The portion ofprofit or loss and net assets in subsidiaries not wholly-owned are presented separately in the consolidated statement of income, consolidated statement of comprehensive income and consolidated statement of changes in equity, and within equity in the consolidated statement of financial position, Losses within a subsidiary are attributed to the noncontrolling interests even ifthat results in a deficit balance.

A change in the ownership interest of a subsidiary, without a loss of control, is accounted for equity transaction. If the Group loses control over a subsidiary, it:

r . o 3.

as an

Derecoglizes the assets (including goodwill) and liabilities of the subsidiary, the carrying amount ofany noncontrolling interest and the cumulative hanslation differences, recorded in equrty. Recognizes the fair value ofthe consideration received, the fair value ofany investment retained and any surplus or deficit in the consolidated state'ment of income. Reclassifies the Parent Company's share of components previously recognized in OCI to the consolidated statement of incorne or retained eamings, as appropriate.

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

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

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-)The Revised PAS 19 replaced the interest cost and expected retum on plan assets with the concept of net interest on defined benefit liability or asset which is calculated by multiplying the net balance sheet defined benefit liability or asset by the discount rate used to measure tlie employee benefit obligation, each as at the beginning of the annual period. The Revised PAS 19 also amended the definition of short-term employee benefits and requires employee benefits to be classified as short-term based on expected timing of settlement rather than the employee's entitlement to the benefits. In addition, the Revised PAS 19 modifies the

timing of recognition for termination benefits. The modification requires the termination benefits to be recognized at the earlier of when the offer cannot be withdrawn or when the related restrucfuring costs are recognized. changes to definition of short-term employee benefits and timing of recognition for termination benefits do not have any impact to the Group's financial position and financial performance. The changes in accounting policies have been applied retrospectively. The effects ofadoption on the consolidated financial statements are as follows: As at December 31 2013 Consolidated statement of financial position Increase (decrease) in: Pension liability

Deferred tax asset

$7s,672 11 1rr1

Remeasurements ofnet accrued retirement liabilitv Retained earnings

(47,s63) (s,407)

($20,943)

($8,289)

(s27,709)

(6,283)

(2,487)

(8,313)

(s,707)

(12,720)

20,367

t8,522

For the years ended December 2013 2012

19,396 I

20t1

Consolidated statement of income Increase (decrease) in: Pension expense Income before income tax Provision for income tax

Net income Consolidated statement of comprehensive income Increase (decrease) in: Net income

($2s,774) $1,8{!

($874)

($25,774)

($874)

(41,856) ($67,630)

7,0t3 $8,8s8

Remeasurement gains on net accrued

retirement liability Total comprehensive income

(1,24e)

2,636 791

1,845

(12.720\ ($13.594)

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

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

PFRS 7, Financial instruments: Disclosures - Offsetting Financial Assets and Financial Liabil ities (Amendments) These amendments require an entity to disclose information about rights of set-off and related arrangements (such as collateral agreements). The new disclosures are required for all recognized financial instruments that are set off in accordance with pAS 32. These disclosures also apply to recognized financial instruments that are subject to an enforceable master netting arrangement or 'similar agreement', irrespective of whether they are set-off in accordance with PAS 32. The amendments require entities to disclose, in a tabular format, unless another format is more appropriate, the following minimum quantitative information.

This is presented separately for financial assets and financial liabilities recognized at the end of the reporting period: a) The gross amounts ofthose recognized financial assets and recognized financial liabilities; b) The amounts that are set off in accordance with the criteria in PAS 32 when determinine the net amounts presented in the statement of financial position; c) The net amounts presented in the statement of financial position; d) The amounts subject to an enforceable master netting arrangement or similar agreement that are not otherwise included in (b) above, including: Amounts related to recognized financial instruments that do not meet some or all of the offsetting criteria in PAS 32; and Amounts related to financial collateral (including cash collateral); and e) The net amount after deducting the amounts in (d) from the amounts in (c) above.

ii.

The amendments have no impact on the consolidated financial position or performance of the

Group.

PFRS 10, Consolidated Financial Statements The Group adopted PFRS l0 in the current year. PFRS l0 replaced the portion ofPAS 27, consolidated and separate Financial statements, that addressed the accounting for consolidated financial statements. It also included the issues raised in SIC 12, Cowolidation Special Purpose Entities. PFRS 10 established a single control model that applied to all entities including special purpose entities. The changes introduced by pFRS l0 require management to exercise significant judgment to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in PAS 27. A reassessment of control was performed by the Parent Company on all its interest in other entities and has determined that there are no additional entities that are controlled or where conhol is lost. PFRS I PFRS I

l, Joint Anangements I replaced PAS 31, Interests in Joint

Ventures, and SIC 13, Jointly Controlled Entities Non'Monetary Contributions by l/enturers. PFRS 1l removed the option to account for jointly controlled entities using proportionate consolidation. Instead, jointly controlled entities that meet the definition of a joint venture must be accounted for using the equity method. The standard has no impact on the consolidated financial statements of the Group. -

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

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

PFRS 13, Fair Value Measurement PFRS 13 establishes a single source ofguidance under PFRSs for all fair value measurements. PFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under PFRS. PFRS 13 defines fair value as an exit price. PFRS l3 also requires additional disclosures. As a result of the guidance in PFRS 13, the Group re-assessed its policies for measuring fair values, in particular, its valuation inputs such as non-performance risk for fair value measurement of liabilities. The Group has assessed that the application of PFRS 13 has not materially impacted the fair value measurements of the Group. Additional disclosures, where required, are provided in the individual notes relating to the assets and liabilities whose fair values were determined. Fair value hierarchy is provided in Note 24,

PAS l, Presentation of Financial Stalements - Presentation of Items of Other Comprehensive Income or OCI (Amendments) The amendments to PAS I introduced a grouping of items presented in OCI. Items that will be reclassified (or 'orecycled") to profit or loss at a future point in time (for example, upon derecognition or settlement) will be prosented separately from items that will never be recycled. The amendments have no impact on the Group's financial position or performance. PAS 27, Separate Financial Statements (as revised in 201l) As a consequence of the issuance of the new PFRS 10 and PFRS 12, what remains of pAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in the separate financial statements. The adoption ofthe amended PAS 27 did not have a significant impact on the separate financial statements of the entities in the Group. PAS 28, Investments in Associates and Joint Ventures (as revised in 2011) AsaconsequenceoftheissuanceofthenewPFRS llandPFRS 12,PAS23hasbeenrenamed PAS 28, Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The standard has no impact on the consolidated financial statements of the Group, Philippine Interpretation Financial Reporting lnterpretations Committee (IFRIC) 20, Stripping Costs in the Production Phase of a Surface Mine This interpretation applies to waste removal (stripping) costs incurred in surface mining activity, during the production phase ofthe mine, The interpretation addresses the accounting for the benefit from tho stripping activity. This new interpretation is not relevant to the Group. PFRS 1, First-time Adoption of Philippine Financial Reporting standards - Government Zoazs (Amendments) The amendments to PFRS 1 require first-time adopters to apply the requirements of pAS 20, Accounting for Government Grants and Dbclosure of Government Assistance, prospectively to govemment loans existing at the date of transition to PFRS. However, entities may choose to apply the requirements of PAS 39, Financial Instruments: Recognition and Measuremew, and PAS 20 to government loans retrospectively ifthe information needed to do so had been obtained at the time of initially accounting for those loans. These amendments are not relevant to the Grouo.

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

PAS 36, Impairment of Assets - Recoverable Amount Disclosures (Amendments)

for Non-Financial

Assets

These amendments remove the unintended consequences of PFRS 13 on the disclosures required under PAS 36. In addition, these amendments require disclosure ofthe recoverable amounts for the assets or cash-generating units for which impairment loss has been recogrized or reversed during the period. These amendments are effective retrospectively for annual periods beginning on or after January l, 2014 with earlier application permitted, provided PFRS 13 is also applied. The amendments have no impact on the Group's financial position or performance.

Investment Entities (Amendments to PFRS 10, PFRS 12 and pAS 27) These amendments are efflective for annual periods beginning on or after Janu uy 1,2014. They provide an exception to the consolidation requirement for entities that meet the deftnition of an investment entity under PFRS I0. The exception to consolidation requires investment entities to account for subsidiaries at FVPL. The Group does not expect that this amendment would have material financial impact in the future financial statements.

Philippine Interpretation IFP.IC 21, Levies IFRIC 2l clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by tle relevant legislation, occurs. For a levy that is triggered upon reaching a minimum threshold, the interpretation clarifies that no liability should be anticipated before the specified minimum threshold is reached. IFRIC 2l is effective for annual periods beginning on or after Janmry 1,2014. The Group does not expect that IFRIC 21 will have material financial impact in future financial statoments. PAS 39, Financial Instruments: Recognition and Measurement - Novation of Derivatives and Continuation of Hedge Accozzlrng (Amendments) These amendments provide relief from discontinuing hedge accounting when novation of a derivative designated as a hedging instument meets certain criteria. These amendments are effective for annual periods beginning on or after January l, 2014. The Group has not novated its derivatives during the current period. However, these amendments would be considered for future novations. PAS 32, Financial Instruments: Presentation - Offsetting Financial Assets and Financial Liabilities (Amendments) The amendments clariff the meaning of 'ocurrently has a legally enforceable right to set-off' and also clarify the application of the PAS 32 offsetting criteria to settlement systems (such as central clearing house systems) which apply gross settlement mechanisms that are not simultaneous. The amendments affect presentation only and have no impact on ttre Group's financial position or performance. The amendments to PAS 32 are to be retrospectively applied for annual periods beginning on or after January 1,2014. This amendment does not have a significant impact to the Group's financial position or performance.

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

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

PFRS 2, Share-based Payrnent - Definition of Yesting Condition The amendment revised the definitions ofvesting condition and market condition and added the definitions of performance condition and service condition to clari$ various issues. This amendment shall be prospectively applied to share-based payment transactions for which the grant date is on or after July 1,2014. This amendment does not have a sisnificant impact to the Group's financial position or performance. PFRS 3, Business Combinatiow - Accounting

for Contingent Consideration in a Business Combination The amendment clarifies that a contingent consideration that meets the definition of a financial instrument should be classified as a financial liability or as equity in accordance with PAS 32' Contingent consideration that is not classified as equity is subsequently measured at fair value through profrt or loss whether or not it falls within the scope of pAS 39. The amendment shall be prospectively applied to business combinations for which the acquisition date is on or after July l, 2014. The Group shall consider this amendment for future 6usiness combinations. PFRS 8, Operating Segments - Aggregation of Operating Segments and Reconciliation of the Total of the Reportable Segments'Assets to the Entity's Assets The amendments require entities to disclose the judgment made by management in aggregating two or more operating segments. This disclosure should include a brief description ofthe operating segments that have been aggregated in this way and the economic indicators that have been assessed in determining that the aggregated operating segrnents share similar economic characteristics. The amendments also clarif, that an entity shall provide reconciliations of the total of the reportable segments' assets to the entity's assets if such amounts are regularly provided to the chief operating decision maker. These amendments are effective for annual periods beginning on or after July 1,2014 and are applied retrospectively. The amendments have no impact on the Group's financial position or performance. PFRS 13, Fair Value Measurement - Short-term Receivables and payables The amendment clarifies that short-term receivables and payables with no stated interest rates can be held at invoice amounts when the effect of discountine is immaterial.

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-10PAS 16, Property, Plant and Equipment - Revaluation Method - Proportionate Restatement of Accumulated D eprec iation The amendment clarifies that, upon revaluation of an item of property, plant and equipment, the catrying amount of the asset shall be adjusted to the revalued amount, and the asset shall be treated in one of the following ways: a) The gross carrying amount is adjusted in a manner that is consistent with the revaluation of the carrying amount of the asset. The accumulated depreciation at the date of revaluation is adjusted to equal the difference between the gross carrying amount and the carrying amount of the asset after taking into account any accumulated impairment losses. b) The accumulated depreciation is eliminated against the gross carrying amount of the asset. The amendment is effective for annual periods beginning on or after July l, 2014. The amendment shall apply to all revaluations recognized in annual periods beginning on or after the date of initial application of this amendment and in the immediately preceding annual period. The amendment has no impact on the Group's financial position or performance.

PAS 24, Related Party Disclosures - Key Management Personnel The amendments clarifu that an entity is a related party of the reporting entity if the said entity, or any member of a group for which it is a paft of, provides key management personnel services to the reporting entity or to the parent company of the reporting entity. The amendments also clari$r that a reporting entity that obtains management personnel services from another entity (also referred to as management entify) is not required to disclose the compensation paid or payable by the management entity to its employees or directors. The reporting entity is required to disclose the amounts incurred for the key management personnel services provided by a separate management entity. The amendments are effective for annual periods beginning on or after July l, 2014 and are applied retrospectively. The amendments have no impact on the Group's financial position or performance. PAS 38, Intangible Assets - Revaluation Method - Proportionate Restatement of Accumulated Amortization The amendments clari! that, upon revaluation of an intangible asset, the carrying amount of the asset shall be adjusted to the revalued amount, and the asset shall be treated in one ofthe

following ways: a) The gross carrying amount is adjusted in a manner that is consisGnt with the revaluation of the carrying amount of the asset, The accumulated amortization at the date of revaluation is adjusted to equal the difference between the gross carrying amount and the carrying amount of the asset after taking into account any accumulated impairment losses. b) The accumulated amortization is eliminated against the gross carrying amount of the asset. The amendments also clarifr that the amount of the adjustment of the accumulated

amortization should form part ofthe increase or decrease in the carrying amount accounted for

in accordance with the standard. The amendments are effective for annual periods begiruring on or after July l, 2014. The amendments shall apply to all revaluations recognized in annual periods beginning on or after the date of initial application of this amendment and inthe immediately preceding annual period. The amendments have no impact on the Group's financial position or performance.

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Annual Improvements to PFRSs (201 1-2013 cycle) The Annual Improvements to PFRSs (2011-2013 cycle) contain non-urgent but necessary amendments to PFRSs. The Group adopted these amendments for the cunent year.

1, First4ime Adoption of Philippine Financial Repolting Standards - Meaning of 'Effective PFRSs' The amendment clarifies that an entity may choose to apply either a current standard or a new standard that is not yet mandatory, but that permits early application, provided either standard is applied consistently throughout the periods presented in the entity's first PFRS financial statements. This amendment is not applicable to the Group as it is not a first-time adopter of

PFRS

PFRS,

PFRS 3, Business Combinations - Scope Exceptions for Joint Atangements The amendment clarifies that PFRS 3 does not apply to the accounting for the formation of a joint arrangement in the financial statements of the joint axrangement itself. The amendment is effective for annual periods beginning on or after July 1,2014 and is applied prospectively. This amendment does not have a significant impact to the Group's financial position or performance. PFRS 13, Fair Value Measurement - Portfolio Exception The amendment clarifies that the portfolio exception in PFRS l3 can be applied to financial assets, financial liabilities and other contracts. The amendment is effective for annual periods beginning on or after July 1, 2014 and is applied prospectively. The amendment has no significant impact on the Group's financial position or performance.

PAS 40, Investment Propertlt The amendment clarifies the interrelationship between PFRS 3 and PAS 40 when classiffing property as investment properly or owner-occupied property. The amendment stated that judgment is needed when determining whether the acquisition of investment properfy is the acquisition ofan asset or a group ofassets or a business combination within the scope of PFRS 3. This judgment is based on the guidance of PFRS 3. This amendment is effective for annual periods beginning on or after July 1 ,2014 and is applied prospectively. The amendment has no significant impact on the Group's financial position or performance, PFRS 9, Financial Instruments PFRS 9, as issued, reflects the first and third phases ofthe project to replace PAS 39 and applies to the classification and measurement offinancial assets and liabilities and hedge accounting, respectively. Work on the second phase, which relate to impairment of financial instruments, and the limited amendments to the classification and measurement model is still ongoing, with a view to replace PAS 39 in its entirety. PFRS 9 requires all financial assets to be measured at fair value at initial recognition. A debt financial asset may, ifthe fair value option (FVO) is not invoked, be subsequently measured at amortized cost if it is held within a business model that has the objective to hold the assets to collect the contractual cash flows and its conhactual terms give rise, on specified datos, to cash flows that are solely payments of principal and interest on the principal outstanding. All other debt instruments are subsequently measured at fair value through profit or loss. All equity financial assets are measured at fair value either through OCI or profit or loss. Equity financial assets held for trading must be measured at fair value through profit or loss. For liabilities designated as at FVPL using the fair value option, the amount of change in the fair value of a liability that is attributable to changes in credit risk must be presented in OCI. The remainder ofthe change in fair value is presented in profit or loss, unless presentation ofthe fair value change relating

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-12to the entity's own credit risk in OCI would create or enlarge an accounting mismatch in profit or loss. All other PAS 39 classification and measurement requirements for financial liabilities have been carried forward to PFRS 9, including the embedded derivative bifurcation rules and the criteria for using the FVO. The adoption of the first phase of PFRS 9 will have an effect on the classification and measurement of the Group's financial assets, but will potentially have no impact on the classification and measurement of financial liabilities.

On hedge accounting, PFRS 9 replaces the rules-based hedge accounting model ofpAS 39 with a more principles-based approach. Changes include replacing the rules-based hedge effectiveness test with an objectives-based test that focuses on the economic relationship between the hedged item and the hedging instrument, and the effect of credit risk on that economic relationship; allowing risk components to be designated as the hedged item, not only for financial items, but also for non-financial items, provided that the risk component is separately identifiable and reliably measurable; and allowing the time value of an option, the forward element of a forward conhact and any foreign currency basis spread to be excluded from the designation ofa financial instrument as the hedging instrument and accounted for as costs ofhedging. PFRS 9 also requires more extensive disclosures for hedge accounting. PFRS 9 currently has no mandatory effective date. PFRS 9 may be applied before the completion of the limited amendments to the classification and measurement model and impairment methodology. The Group will not adopt the standard before the completion of the limited amendments and the second phase of the project.

In compliance with SEC Memorandum Circular No. 3, series of 2012, the Group has eonducted a study on the impact of an early adoption of PFRS 9. After careful consideration ofthe results on the impact evaluation, the Group has decided not to early adopt PFRS 9 for its 2013 annual financial reporting. Therefore, these consolidated financial statements do not reflect the impact of the said standard.

Philippine lnterpretation IFRIC 15, Agreements for the Conshuction of Real Estate This interpretation covers accounting for revenue and associated expenses by entities that undertake the construction of real estate directly or through subcontractors. The SEC and the Financial Reporting Standards Council have deferred the effectivity of this interpretation until the final Revenue standard is issued by the Intemational Accounting Standards Board and an evaluation ofthe requirements ofthe final Revenue standard against the practices ofthe Philippine real estate industry is completed. Adoption of the interpretation when it becomes effective will not have any impact on the financial statements of the Group.

Summary of Significant Accounting Policies Revenue Recognition Revenue is recognized to the extent that it is probable that the economic benefits will flow to the Group and the income can be reliably measured, The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent, The Group has concluded that it is acting as principal in all of its revenue arrangements. The following specific recogrition criteria must also be met before revenue is recognized:

Oil Revenues Revenues from

oil wells

are recognized as income at the time of production.

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Interest Income

lnterest income is recogrized as the interest accrues taking into account the effective yield on the asset.

Miscellaneous Income Miscellaneous income includes dividend income and gain on sale of transportation equipment. Revenue is recognized when the Group's right to receive the payment is established. Cash and Cash Equivalents Cash includes cash on hand and in banks. Cash equivalents aro short-term, highly liquid invesftnents that are readily convertible to known amounts of cash with original maturities of three (3) months or less from the dates ofacquisition and that are subject to an insignificant risk change in value.

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

Initial Recognition and Measurement Financial assets within the scope of PAS 39 are classified as either financial assets at FVPL, loans and receivables, held to maturity (IITM) 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 investrnents 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 tlre 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. Sub s e quent Me as ure me

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 ofdiscounts, premiums and transaction costs are taken directly to the consolidated statement of income.

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-14Determination 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:

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ln 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:

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

For assets and liabilities that are recognized in the financial statements on a recurring basis, the Group determines whether transfers have occurred between Levels in the hierarchy by reassessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period.

Day I 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 insfument 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 I difference) in the consolidated statement of income unless it qualifies for recognition as some other type of asset or liability. Ln oases where variables used is made of data which is not observable, the difference between the transaction price and model value is only recognized in the consolidated statement of income when the inputs become observable or when the instrument is derecognized. For each transaction, the Group determines the appropriate method of recognizing the Day I diflerence amount.

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

FVPL.

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

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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 ofa group of finanoial 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 strategyl or the financial instrument contains an embedded derivative, unless the embedded derivative does not significantly modiS 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 income. Interest earned or incurred is recorded in interest income or expense, respectively.

Dividend income is recognized according to the terms of the contract, or when the right of the payment has been established. Classified as finanoial assets at FVPL are the Group's marketable equity securities held for trading purposes and investment in golf club shares (see Note 7). Derivative Financial Instruments Derivative financial instruments (including bifurcated embedded derivatives), if any, are initially recognized at fair value on the date at which the derivative contract is entered into and is subsequently remeasured at fair value. Any gains or losses arising from changes in fair value of the derivative (except those accounted for as accounting hedges) is taken directly to the consolidated statement of income under "Miscellaneous income". The derivative is carried as asset when the fair value is positive and as liability when the fair value is negative. The Group has no derivative financial instruments as at December

, 2013 and 2012.

Embedded Derivatives An embedded derivative is separated from the host financial or non-financial contract and accounted for as a derivative if all of the following conditions are met:

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

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The Group assesses whether embedded derivatives are required to be separated from host contracts when the Group first becomes a party to the contract. Reassessment only occurs ifthere is a change in the terms of the conhact that significantly modifres the cash flows that would otherwise be required. Embedded derivatives that are bifurcated from the host contracts are accounted for as financial assets or liabilities at FVPL. Changes in fair values are included in the consolidated statement income.

As of December 31,2013 and 2012, the Group has no embedded derivatives requiring bifurcation. AFS Financial Assets AFS financial assets are those which are designated as such and are purchased and held indefinitely, and may be sold in response to liquidity requirements or changes in market conditions. AFS financial assets include equity securities.

After initial measurement, AFS financial assets are measured at fair value. The unrealized gains and losses arising from the fair valuation ofAFS financial assets are excluded from reported eamings and are reported in the consolidated staternent of financial position and consolidated statement of changes in equity, When the security is disposed of, the cumulative gain or loss previously recognized in the consolidated statement ofchanges in equity is recognized in the consolidated statement of income. Where the Group holds more than one investrnent in the same security, these are deemed to be disposed of on a first-in first-out basis. Dividends eamed in AFS financial assets are recognized in the consolidated statement of income when right to receive payment has been established. The losses arising from impairment of such investments are recognized in the consolidated statement of income.

As of December

3 1, 20 I

3 and 2072, the Group has no AFS financial assets.

HTM investments HTM investments are quoted nonderivative financial assets with fixed or determinable payments and fixed maturities for which management has the positive intention and ability to hold to maturity. Where the Group sells other than an insignificant amount of HTM investrnents, the entire category would be tainted and reclassified as AFS financial assets. After initial measurement, these investments are measured at amortized cost using the effective interest method, less impairment in value. Amortized cost is calculated by taking into account any discount or premium on acquisition and fees that are integral parts ofthe EIR. The amortization is included in interest income in the consolidated statement of income. Gains and losses are recognized in the consolidated statement of income under "Other income" when t}1e HTM investments are derecognized and impaired, as well as through the amortization process.

As of December 31, 2013 and20l2, the Group has no HTM investments. Other Financial Liabilities

All financial liabilities

are initially recognized at the fair value of the consideration received less directly athibutable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the EIR method. Gains and losses are recognized in the consolidated statement of income when the liabilities are derecognized or impaired, as well as through the amortization process.

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Classified under this category are the Group's accounts payable and accrued expenses and loans payable (see Notes 15, 76 and 24). Classification of Financial Instruments between Debt and Equity A financial instrument is classified as debt, if it provides for a contractual obligation to:

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

Ifthe Group does not have an unconditional right to avoid delivering asset to settle its contractual obligation, the obligation meets the

cash or another financial definition ofa financial liability.

The components of issued financial instruments that contain both liability and equity elements are accounted for separately, with the equity component being assigned the residual amount, after deducting from the instrument as a whole the amount separately determined as the fair value of the liability component on the date of issue.

The Group has no financial instruments that contain both liability and equity elements. Impairment of Financial Assets The Group assesses at each reporting date whether a financial or group offinancial assets is impaired. asset or a goup 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 ofthe asset (an incuned 'loss event') and that loss event (or events) has an impact on the estimated fufure 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

A financial

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

If it is determined

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

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- 18 The carrying amount of the asset is reduced through the use of an allowance for impairment loss account. The amount ofthe loss shall be recognized in the consolidated statement of income. If, in a subsequent period, the amount ofthe impairment loss decreases, and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed. Any subsequent reversal of an impairment loss is recognized in the consolidated statement of income, to the extent that the carrying value of the asset does not exceed what would have been the amortized cost at the reversal date had there been no impairment recognized. AFS Financial Assets

an AFS financial asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization) and its current fair value, less any impairment loss previously recognized in statement of income, is transferred from the consolidated statement of changes in equity to statement of income. Impairment reversals in respect of equity instruments classified as AFS financial assets are not recognized in the consolidated statement of income. Reversals of impairment losses on debt instruments are reversed through statement of income, the increase in fair value ofthe instrument can be objectively related to an event occurring after the impairment loss was recognized in statement of income, The amount of reversal is limited to the amount that brings the carrying value of the debt instrument to what it could have been had there been no impairment in the first place.

Derecosnition of Financial Assets and Liabilities asset (or where applicable, a part ofa group of financial assets) is derecognized when:

A financial

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the rights to receive cash flows from the assets have expired; or the Group has tansferred substantially all the risks and rewards ofthe 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 ofthe asset, but has hansferred control ofthe 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 ofthe asse! the asset is recognized to the extent ofthe

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. Whore an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognized in the consolidated statement of income. Offsettins Financial Instruments Financial assets and financial liabitities are offset and the net amount reported in the consolidated statement offinancial position if, and only if, there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis. or to realize the asset and settle the liability simultaneously.

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_19Crude Oil Inventory Crude oil inventory is stated at fair market value.

Advances, Prepaid Expenses and Other Current Assets Advances, prepaid expenses and other current assets pertain to resources controlled by the Group as a result of past events and from which future economic benefits are expected to flow to the Group. Prope4v. Plant and Eqlripment 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 athibutable costs of bringing the assets to its working condition and location for its intended use and abandonment costs.

Expenditures incurred after the fixed assets have been put into operation, such as repairs and maintenance, are normally charged to statement of income in the period in which the costs are incurred. ln 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 ofan item of propefty, 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 Operatiotts, and the date the asset is derecognized.

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

Wells, platforms and other facilities are depleted using the units-of-production method computed based on estimates of proved reseryes. The depletion base includes the exploration and development cost of the producing oilfields. FCRS and production wells - geothermal are depreciated using the straight line method over the useful lives of the assets. The useful life ofthese assets shall be determined once in the condition necessary for these assets to be capable ofoperating in the manner intended by management.

Other proper(y, plant and equipment are depreciated and amortized using the straight-line method over the estimated useful lives ofthe assets as follows: Number of Years

Ofhce condominium units Land improvements Transportation equipment Office improvements Office furniture and other equipment

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_20

Wells in progress peftain to those development costs relating to the Service Contract (SC) where and are subsequently reclassified to'oWells, 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.

oil in commercial quantities are discovered

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 pattem of economic benefits from items of properly, plant and equipment.

Construction in progress represents property, plant and equipment under construction and is stated at cost. This includes the cost of construotion 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. Defened 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 "Properly, 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 offin the year the area is permanently abandoned. SCs are considered permanently abandoned ifthe SCs have expired and/or there are no definite plans for further exploration and/or development.

Deferred Geothermal Costs costs incurred in the geological and geophysical activities such as costs oftopographical, 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.

All

Ifthe results of initial geological and geophysical ac,tivities reveal the presence of geothermal resource that will require further exploration and drilling, subsequent exploration and drilling oosts are accumulated and deferred under the "Deferred geothermal costs" aooount in the

consolidated statement of financial position. These costs include the following:

. . .

Costs associated with the construction of temporary facilities; Costs ofdrilling 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. Iftests conducted on the drilled exptoratory wells reveal that these wells cannot produce proved reserves, the capitalized costs are charged to expense except when management decides to use the unproductive wells for recycling or waste disposal.

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-21Once 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.

lnvestment 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 ofthe investment properties comprises ofpurchase 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 ofan 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 investrnent 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 investrnent properties are recognized in the consolidated statements of income in the year of retirement or disposal, Transfers are made to inveshnent properties when, and only when, there is a change in use, evidenced by the end of owner-occupation, commencement ofan operating lease to another party or by the end of construction or development. Transfers are made from investrnent 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: ass€ts: including its share ofany assets heldjointly liabilities, including its share of any liabilities incurred jointly revenue from the sale of its share ofthe output arising from thejoint operation share ofthe revenue from the sale ofthe output by thejoint operation expenses, including its share of any expenses incurred jointly

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The Group accounts for the assets it controls and the liabilities it incurs, the expenses it incurs and the share of income that it eams from the sale of crude oil by the joint operations.

Impairment of Nonfinancial Assets The Group assesses at each reporting date whether there is an indication that an asset (e.g', property, plant and equipment, investment properties, and deferred oil exploration costs) may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group estimates the asset's recoverable amount. An asset's recoverable amount is the higher ofan 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 ofthose from other assets or group of zrssets.

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Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators.

An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Group makes an estimate of recoverable amount. A previously recognized impairment loss is reversed only ifthere has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the consolidated statement of income unless the asset is carried at revalued amount, in which case the reversal is treated as a revaluation increase.

Equit-v The Group records common stock at par value and additional paid-in capital in excess ofthe total contributions received over the aggregate par values ofthe equity shares. When the Group issues more than one class ofstock, a separate account is maintained for each class of stock and the number of shares issued. Incremental costs incurred directly attributable to the issuance ofnew 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 athibutable 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 ofany changes in accounting policies and errors applied rehoactively, The retained earnings of the Parent Company and its subsidiaries are available for dividends only upon approval and declaration ofeach of their respective BOD.

Insome Taxes Cunent Income Tm Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted at the reporting date. Deferred Income Tac Deferred income tax is provided using the balance sheet liability method on temporary diflerences at the reporting date between the tax bases of assets and liabilities and &eir carrying amounts for financial reporting purposes,

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-23 Deferred income tax liabilities are recognized for all taxable temporary differences, with certain exceptions. Deferred income tax assets are recognized for all deductible temporary differences with certain exceptions, and carry forward benefits of unused tax credits from excess minimum corporate income tax (MCIT) over regular corporate income tax (RCIT) and unused net operating loss carryover (NOLCO), to the extent that it is probable that taxable income will be available against which the deductible temporary differences and carry forward benefits ofunused tax credits from excess MCIT and unused NOLCO can be utilized.

The carrying amount of defened income tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that suffrcient taxable income will be available to allow all or part ofthe deferred income tax asset to be utilized. Unrecognized deferred income tax assets are eamed at each reporting date and are recognized to the extent that it has become probable that future taxable income will allow all as part of the deferred income tax and to be recovered. The Group does not recognize deferred income tax assets and defened income tax liabilities that will reverse during the income tax holiday.

Deferred income tax assets and defened income tax liabilities are offset if a legally enforceable right exists to set off current income tax assets against current income tax liabiiities and the defened income taxes relate to the same taxable entity and the same taxation authoritv. Pension Cost The net defined benefit liability or asset is the aggregate ofthe present value ofthe defined benefit obligation at the end ofthe reporting period reduced by the fair value ofplan assets (ifany), adjusted for any effect of limiting a net defined benefit asset to the asset ceiling. The assef ceiling is the present value of any economic benefits available in the form of refunds fom 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:

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Service cost

Net interest on the net defined benefit liability or asset Remeasurements of net defined benefit liability or asset

Service costs which include current service costs, past service costs and gains or losses on nonroutine settlements are recognized as expense in the consolidated statement of income. Past 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 deiermined by applying the discount rate based on government bonds to the net defined benefit liability oi asset. Net interest on the net defined benefit liability or asset is recognized as expense or income in the consolidated statement of income.

Remeasurements comprising acfuarial gains and losse$, refum on plan assets and any change in the effect ofthe asset ceiling (excluding net interest on defined benefit liability) are recognized immediately in OCI in the period in which they arise. Remeasurements are not reclassified to consolidated statement of income in subsequent periods.

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Plan assets are assets that a"re held by a long-term employee benefit fund or qualifuing 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 ofthose assets (or, ifthey have no maturity, the expected period until the settlement ofthe related obligations). If the fair value ofthe plan assets is higher than the present value ofthe defined benefit obligation, the measurement ofthe resulting defined benefit asset is limited to the present value of economic benefits available in the form of refunds from the plan or reductions in future contributions to the plan. The Group's right to be reimbursed of some or all of the expenditure required to settle a defined benefit obligation is recognized as a separate asset at fair value when and only when reimbursement is virtually certain. Costs and Expenses

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

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

The determination of whether an arrangement is, or contains a lease, is based on the substance of the arrangement at inception date, and requires an assessment of whether the fulfillment of the arrangement is dependent on the use ofa specific asset or assets, and the arrangement conveys a right to use the asset, A reassessment is made after inception ofthe lease only if one (l) ofthe

following applies:

a. b.

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

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 ofthe scenarios above, and at the date of renewal or extension period for the second scenario.

Group as a Lessee Leases where the lessor retains substantially all the risks and benefits of ownership ofthe asset are classified as operating leases. Operating lease payments are recognized as an expense in the consolidated statement of income on a straightJine 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 tlre terms

ofthe leased contract.

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-25 -

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

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

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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 ofresources to complete the asset; and the ability to measure reliably the expenditure during development.

Borrowinq Costs Interest and other related financing charges on borrowed funds used to finance the acquisition and construction ofa quali8ring 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 a.re 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 bonowing cost.

The bonowing costs capitalized as part of propert5z and equipment are amortized using the straight-line method over the estimated useful lives of the assets.

If after capitalization of the borrowing

costs, the carrying amount of the asset exceeds its recoverable amount, an impairment loss is recorded in the consolidated statement of income. Interest expense on loans and borrowings is recognized using the EIR method over the term ofthe loans and borrowings.

Provisions Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. where the Group expects a provision to be reimbursed, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. If the effect of the time value of money is material, provisions are determined by discounting the expected fufure cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as an interest expense. Provisions are reviewed at each reporting date and adjusted to reflect the current best estimate.

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-26 Contingencies

Contingent liabilities are not recognized in the consolidated financial statements. They are disclosed unless the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognized in the consolidated financial statements but disclosed when an inflow of economic benefit is probable.

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

All

differences are taken to the consolidated statement of income with the exception of differences on foreign currency borrowings that provide, if any, a hedge against a net investment in a foreign entity. These are taken directly to equity until disposal of the net investment, at which time thJy are recognized in the consolidated statements of income. Non-monetary items that are measured in terms ofhistorical 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 foreigr currency are translated using the exchange rates at tre date when the fair value was determined. The functional currency of the Parent company's immediate subsidiary, petroGreen, and PetroGreen's subsidiaries, MGI and Petro wind, is Philippine Peso. As at reporting date, the assets and liabilities ofthese subsidiaries are translated into the presentation currency ofthe Group (the US Dollars) at the exchange rate at the reporting date and the consolidated statements of income accounts are translated at weighted average exchange rates for the year. The exchange differences arising on the translation are taken directly to "Cumulative translation adjustment" account in the equity section ofthe consolidated statement of financial position. Upon disposal of a subsidiary, the defened cumulative translation adjustment amount recognized in equity relating to that particular subsidiary is recognized in the consolidated statement of income. Earnings Per Share GPS) Basic earnings per share are computed on the basis ofthe weighted average number ofshares outstanding during the year after giving retroactive effect for any stock dividends declared in the curront year.

Diluted earnings per share are computed on the basis ofthe weighted average number of shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion ofall 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 seryes different markets. Financial information on business segments is presented in Note 25 to the consolidated financial statements. Provisions Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market

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

statements when material.

Significant Accounting Judgments, Estimates and Assumptions The preparation of the consolidated financial statements in compliance with PFRS requires the Group to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, income and expenses and disclosure of contingent assets and contingent liabilities. Future events may occur which will cause the assumptions used in arriving at the estimates to change. The effects of any change in judgments, estimates and assumptions are reflected in the consolidated financial statements, as they become reasonably determinable. Judgments, estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Judsments 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 cunency 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 cunency of PetroGreen, MGI and PehoWind is Philippine Peso. As of December 31, 2013 and 2012, the Group's cumulative translation adjustment amounted to $1.12 million and ($0.29 million), respectively. Impairment of Deferred Oil Exploration Costs The Group assesses impairment on deferred oil exploration costs when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount, Until the Group has sufficient data to determine technical feasibility and commercial viability, defened 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:

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The period for which the Group has the right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed; Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned;

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_28

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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 entify has decided to discontinue such activities in the specific area; and Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

As of December 31,2013 and,2012, the carrying value of deferred oil exploration costs amounted to $11.40 million and $6.64 million, respectively (see Note 1 1). Based on the above mentioned criteria, the Group did not recognize any impairment of deferred oil exploration costs in 2013, 2012 and20ll. Estimates and Assumptions The key assumptions conceming the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

Determination of Fair Values of Financial Assets and Liabilities The fair value determination for financial assets and liabilities are based generally on listed market prices or broker or dealer price quotations. If prices are not readily determinable or if liquidating the positions is reasonably expected to affect market prices, fair value is based on either intemal valuation models or management's estimate of amounts that could be realized under current market conditions, assuming an orderly liquidation over a reasonable period of time (see Note 24 for the fair value offinancial assets and liabilities). Estimating Impairment of Receivables The Group reviews its receivables to assess impairment at least on an annual basis. In determining whether an impairment loss should be recorded in the consolidated statements of income, the Group makes judgments as to whether there is any observable data indicating that there is a measurable decrease in the estimated future cash flows from its receivables. This evidence normally includes direct information about the financial oondition and historical payments of the borrower,

No impairment losses were recognized in 2013, 20lZ andZ0ll. As of December 31,2013 and2012, the carrying value of receivables amounted to $2.61 million and $1.98 million, respectively. Accumulated impairment losses amounted to $0.06 million and $0.07 million as of December 31, 2013 arird2012, respectively (see Note g).

Fair

Values of Financial Assets and Financial Liabilities The Group carries certain financial assets and liabilities at fair value, which requires extensive use of accounting estimates and j udgment. While significant components of fair vilue measurement were determined using verifiable objective evidence (i.e., foreign exchange rates, interest rates), the amount of changes in fair value woutd differ if the Group utilized diffirent valuation methodologies. Any changes in fair value of these financial assets and liabilities would affect directly the consolidated statement of income (see Note 7).

Where the fair values of certain financial assets and financial liabilities recorded in the consolidated statement offinancial position cannot be derived from active markets, they are determined using valuation techniques using generally accepted market valuation models. The inputs to these models are taken from observable markets where possible, but where this is not feasible, estimates are used in establishins fair values.

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_29 -

C apital ization of Dev elopment C osts Development costs are capitalized in accordance with the accounting policy discussed in Note 4. lnitial capitalization of costs is based on management's judgment that technological and economical feasibility is confirmed, usually when a product development project has reached a dehned milestone according to an established project management model. If accounting policy on capitalization ofdevelopment costs are not met, such costs are expensed.

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

MGI's simulation indicated a mean (P50) proven reserves of 27.8 MW for 25 years. In contrast, SKM calculated the P50 reseryes at 44 MW. AtgO% probability (P90), the.eierves calculated Z_t_!tW and 12 MW by SKM and MGI, respectively. SKM concluded that the approach taken ry by MGI is conservalive as it limits reservoir thickness to depths where a maximum tirickness of 280'C will be encountered although the measured temperature reached as high as 324oC, There is reasonable confidence that the 20 MW (gross) plant development is feasible-as the P90 level appears also conservative as with MGI's approach, In addition, SKM identified indicated reserves, translating to l0 MW-26 MW in the area south of and outside the cunent area of development. Since this area is not being tapped at the moment for the 20_ MW project, MGI preferred not to estimate such reserves at the momint; however, this provides additional confidence for future project capacity expansion. The results ofthe reserves calculation are given below.

MW Generation MGI SKM Indicated SKM MGI

for 25 Years

28 44

5l 66

Estimating Proved Group Oil Resemes The Group assesses its estimate ofproved reserves on an annual basis based on the report from an independent par(y hired by the consortium operator to estimate the oil reserves. The independent party estimates the reserves of oil in accordance with accepted volumetric methods, specihcally the probabilistic method of estimation. Probabilistic method uses known geological, engineering and economic data to generate a range of estimates and their associated probabilities. Estimating Useful Lives of Property, Plant and Equipment The Group reviews on an annual basis the estimated useful lives of property, plant and equipment based on expected asset utilization as anchored on business plans and stratigiis that also consider expected future technological developments and market behavior.

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-30It is possible that future results of operations could be materially affected by changes in these estimates brought about by changes in the factors mentioned. A reduction in the estimated useful lives of property and equipment would increase the recorded depreciation and amortization expense and decrease noncurrent assets.

AsofDecember3l,2013 and2}l2,theGroup'spropefy,plantandequipmentamountedto $75.07 million and $5 I .46 million, respectively (see Note l0). Estimating Impairment of Nonfinancial Assets The Group assesses impairment on its nonfinancial assets (e.g., property, plant and equipment and investment properties) whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Among others, the factors that the Group considers important which could trigger an impairment review on its nonfinancial assets include the

following: For property, plant and equipment and investment properties, an impairment loss is recognized whenever the carrying amount of an asset exceeds its recoverable amount. The recoverable amount is the higher of an asset's net selling price and value in use. The net selling price is the amount obtainable from the sale of an asset in an arm's length transaction while value in use is the present value of estimated future cash flows expected to arise from the continuing use ofan asset and from its disposal at the end of its useful life.

In determining the present value of estimated firture cash flows expected to be generated from the continued use of property, plant and equipment and investment properties, the Group is required to make estimates and assumptions that can materially affect the consolidated financial statements. As discussed in Note 10, production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last sixteen (16) years. The investment in WLO included in "Wells, Platforms and Other Facilities" account under property, plant and equipment in the consolidated statements of financial position amounted to $6.65 million as of December 31, 2013 and,20l2. Management assessed that the said investment is fully reooverable as SC l4-C is not yet expired, with the I 5-year extension of the SC as approved by the Deparfinent of Energy (DOE), from December 18, 2010 to December 18,2025 and the existing redevelopment activities Ied by Pitkin Petroleum Ltd. (Pitkin). Thus, no impairment was recognized in 2013, 2012 and2}ll.

As of December 3 I , 2013 and 2012, the carrying value of property, plant and equipment amounted to $75.07 million and $51.46 million, respectively (see Note l0); and the carrying value of investment properties amounted to $0.03 million (see Note l2). Retirement Obligation The determination of obligation and cost ofpension is dependent on the selection of certain assumptions used in calculating such amounts. Those assumptions, which are described in Note 19 to the consolidated financial statements, include, among others, discount rates and salary increase rates. Actual results that differ from the Group's assumptions are accumulated and amortized over future periods and therefore, generally aflect the recognized expense and recorded obligation in such future periods. While the Group believes that the assumptions are reasonable and appropriate, significant differences in the actual experience or significant changes in the assumptions may materially affect the pension obligations. The accrued retirement liability as of December 37,2013 and20l2 amounted to $0.12 million and $0.06 million, respectively.

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

recognition. The amount of asset retirement obligation in the consolidated statement of financial position is increased by the accretion expense charged to operations using EIR method over the estimated remaining term of the obligation.

As of December 31,2013 and2012, asset retirement obligation amounted to $0.33 million and $0.24 million, respectively (see Note l7).

- Wind Energt mtd Geothermal Energt Projects In determining the amount of provisions for dismantling, removal and restoration costs, assumptions and estimates are required in relation to the expected costs to dismantle, remove or restore sites and infrastructure when such obligation exists. As of December 3l,2}l3 and 2QL2, the Group made an assessment that such obligation does not exist yet in the current stage of operations ofthe wind energy and geothermal energr projects.

Asset Retirement Obligation

Defewed Tm Assets The Group reviews the carrying amounts of defened 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 ofthe deferred tax assets to be utilized. As of Decemb er 31,2013 and 2012, deferred tax assets amounted to $0.27 million and $0.l4 million, respectively. However, the Group did not recognize deferred tax assets on NOLCO amountingto $5.16 million and52.64 million as of December3l,2013 and2}T2,respectively, because the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized (see Note 20).

Cash and Cash Equivalents

Cash on hand and in banks

Short-term investments

2013 s2,229,744 341

2012 $1,020,234 20.601.988 $21,6

Cash in banks earn interest at the prevailing bank deposit rates. Short-term deposits are made for varying periods of up to three months depending on the immediate cash requirements of the Group, and earn interest at the prevailing short-term deposit rates. In 2013 and2012, the Group invested $0.91 million and $0.81 million, respectively, to short-term investrnents with periods more than three months but less than one year. These investments were presented separately as short-term investments (see Note 36).

lnterest income earned on cash in banks and short-term investments amounted to $0.20 million. $0.51 million and $0.52 million in 2013,2012 and 2011, respectively.

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-32-

Financial Assets at F\aPL

20t2

20L3 Marketab le equity securities

lnvestment in golf club shares

s124,317

13.741

12s,53

tt $142.827

Net gain (loss) on fair value changes on financial assets at FVPL included in the consolidated statements of income amounted to s7,456, $24,880 and ($79,5gg) in 2013, 2012 and 2011, respectively.

Receivables

Accounts receivable from: Consortium operator Others Interest receivable

20t3

2012

$2,622,051 40,099

$2,021,687 1,969

2,667277

2,047,373

23.7t7

Less allowance for

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

Balances at beginning ofyear Effect of foreisn currencv translation Balances at end of

2013

20t2

$65,346 4 $60

$61,187

4.159 5.346

Prepaid Expenses and Other Current Assets

Downpayments to contractors Downpayments to contractors - related parties (Note 23) Deferred furancing costs - undrawn portion

(Note 16) Prepaid expenses Others

2012

2013 $10,161,027

$55 1,527

4,526,039

3,266,268

1,450,062 624,699

542,499

L7L

575,65s 30.600

Downpayments to contractors pertain to the downpayment to various contractors for the construction of power plant in the MGPP and NWPP (see Note l0). This will be applied against future billings in the course of construction. The current portion are estimated to bl-applied

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-33against progress billings within one year from reporting date are classified under "Advances, prepaid expenses and other current assets". Prepaid expenses include prepaid insurance and professional fees.

Deferred financing cost (DFC) undrawn portion represents the portion ofthe incidental costs incurred in obtaining the loan pertaining to the undrawn amount of the total loan.

"others" pertain to software licenses, advances to employees, supplies and deposits.

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-34 -

10. Properfy, Plant and Equipment

Wells. Platforms

Land and

Land

FCRS and and Oth€r Production Wells

Facilities

Condominium Utrits and

Transportation

Geothermal

Cost Balance at beginning of year

$918,741

Additions (Not€ 16)

140s43

$22,027

382

$r2,751,733

$816,6r0

$605,867

902,494

350s,167

94,051

rr0A7s

Disposals in ARO estimate

Furniture Other

and

Construction in

$6E7,949

$64;64,20s

$26,55s,923

2t3r1$r8

20287,172

277

816 (4564)

(4564)

Accumuleted dcpletiotr and Balance ar beginning ofyear Depletion and depreciation (Note 22)

Ntt book

value

Balance at beginning ofyear

Land

s867,672 51,069

Additions (Note 16)

at end

149{8J4e

lu:159

1,747,985

Wells, Platforms FCRS and and Other Production Wells Facilities Gmthermal $21,541,07r 754,831

{{o1

61?

{<rr(

9rsJ4t

8,,1T*,rrTdofye.

22)

'054 ' 1,622262

, -

(1r

ezra

rGifiai'

Ao<

Tmnsportation

Fumiture and other Equi

Construction in

s5,223,837

s724,473

8228,758

7,527,90r

92,t37

$362,986 335,126 (10,163)

$3,440,337 23,115,586

10247

rrr

Condominium Units and

e7<

nrt

arn

Office

45{ l1d

(78,22s)

value

304,194

r09,2r8

l7 and

Accumulal€d depletion and depreciation Balanc€ at beginning ofyear Depretion and depreciation (Nore

Net book

103,487

1,40r,796

$1,031,081 stJ05.415 $16156.900 stq2-4oo

land and

Disposals in ARO estimate

rt,869Jl6

$32,389,129 32,331,984 (88,388)

51.733

546'465 84,887

.., ,_

98'232 sr,1&

l99'415 tr4,g42

11,091,166 1,873,8ss

_ (+e,sogl (ro,rssi ------

(s6,672)

_------Jt$E:+q-

$383,755 s26,555,g23

$51y'55,856

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

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Foreign Onerations Gabon, West Africa Total crude in 2013 reached 6.24 million banels (mmbo), with daily oil production ranging from 11,400 - 19,700 banels of oil per day (bopd) from three oil fields - Etame, Avouma, and Ebouri. The new production well EAVOM-3H was put on-line on April 9,2013 and is now contributing -1,600 bopd to the overall daily production from the Avouma platform. Due to the natural depletion of the field, increased gas and water contents in some of the wells, successive drilling activities in the Avouma and Ebouri platforms, and transient production -bopd downtimes, the average daily production was reduced to an anticipated compared to -17,000 2012's avetage of-l8,000 - 19,000 bopd. Nonetheless, the consortium managed tS tiftings for the year resulting to a net crude export of 6,3 I mmbo. crude oil prices for thelear au".ugJd US$107.53 per barrel.

Aside from the current production activities in the three fields, the Etame consortium pursued the expansion of the existing Etame field. Two new production platforms were fabricated alongside major facilities upgrades in the existing platforms of Ebouri and Avouma fields. All these efforts are geared towards increased oil production and the extension of economic life ofthe fields. Etame Expansion Project (EEP) The EEP is an on-going effort led by the block operator, vAALco Energy, Inc., to evaluate the possibility of increasing production to 25,000 - 30,000 bopd. Tapping boih lntemal Consortium technical resources and external third-party Consultants, the EEP comprises four separate but related investigations :

r o r r

Subsurface simulation study to determine remaining recoverable reserves in low, mid, and high cases; Drilling and completion review to ascertain drilling costs, duration, and design modifications for future well drilling and completion; Facilities evaluation ofthirteen (13) potential development options that led to the identification of six hybrid development concepts; and duration, risks, and profitability. In 2011, the EEP team recommended two options to be carried further into the pre-front end engineering design (Pre-FEED) stage. These are the "Etame Production plitform" option and the "Nautipa" option. The former will entail the construction of a full production platform in the cenhal Etame producing field. The other, more preferred, scheme will continue to utilize the current Floating Production Storage and OmoaOing (FPSO) vessel Petroleo Nautipa throughout the field life combined *ith a n"* wellhead platform in Etame.

This project, which aims to increase production to at least 25,000 bopd, requires new platforms in the central Etame production field and in the greenfield SouthEast ELmeA{orth Tchibala (SEENT) sector. VAALCO Energy krc., the joint-venture Operator, contracted the engineering firm McDermott to conduct the Detailed Engineering Studies for the new platforms. In November tl: partners ap^p^roved the Final Investment Decision (FID) for this project. Once completed 301?' by the 3'' quarter of 2014, the new platforms can accommodate more produition wells for drilling. On December 27,2012, the Gabon government has approved the platform construction for the

Etan19 an_d SEENT expansiotr-program, covering a 15-l 8 month c-onstruction period. The platform topsides. facilities design and fabrication were undertaken in 2013, while the transport and-

installation of parts

will

be done in 2014. The Gabonese Govemment has put on hold the approval

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-36 ofthe production drilling until next year, pending the presentation of budget and the number and location of the production wells. By end of 2013, most of the long lead items for the Etame and IEENT expansion program had been purchased, while structural fabrication was on-going in Galveston, USA. Transportation and Installation which have been awarded to EMAS in Julv 2013 will commence in April 2014. Installation of the platforms is scheduled in June-July 2014. B r ownfi e ld P roj

e ct s Up gr ade The upgrade ofboth Avouma and Ebouri platforms were carried out in 20i2 and are nearing completion. Both plafforms were extended to accommodate additional well slots for future drilling. With these additions, the electrical systems of the platforms were likewise upgraded to accommodate additional electrical submersible pumps to be installed.

The Avouma Water Knock-Out System was installed and hooked-up during the First Quarter of 2013. The system, which will increase crude output going to the Floating Pioduction Siorage and Offloading (FPSO) vessel by enhancing the platform's capacity to reparut. water from the oil, was fi.rlly operational since August 2013.

Ebouri Crude Sweetening Project The Ebouri wells EEBOM-3H and EEBOM-4H, which contribute -2,000 bopd, have been shut-in since JuJy 2012 due to high hydrogen sulphide (H2S). For safety purposes, thise wells have been serviced for temporary abandonment in June 2013, and H2S deteition devices were installed in the platform' The consortium then conducted a Crude Sweetening Process Study and is currently in the pre-front end engineering (pre-FEED) phase. Results are -xpected first quarter of20l4. FPSO Integrity Assessment lgUtea to the "Etame Expansion Project" is the assessment ofthe existing FPSO vessel, petroleo Nautipa, as to its suitabilify in the enhanced production plan. Allied Marine Services and BASS, well-known marine engineering firms, were contracted to assess the FPSO vessel's life extension while SGS was engaged to undertake a Topsides Integrity Assessment. The collective output of the three conhactors is the identification of corrective actions to maintain the vessel's structural integrity and ensure continuous operation throughout the life ofthe field. The upgrade and modification of the vessel was carried out in2013.The DNV Class Renewal 2012 for the Nautipa vessel was approved in full terms in mid-October 2013, with the certification

valid until August 2,2017.

Shallow Water Exploration Project (SWE?) Current production in the Gabon concession is limited to known fields lying at the center of the permit area in about 80 meters of water. The goal of SWEP is to identiff pitrol"u- prospects for future drilling in the northem and northeastern parts of the concession to the Gabon shore "lose where water depths are 30 meters or less. The SWEP kicked-off in 201 1 with the interpretation of existing 3D seismic data acquired in 1997. Geological analyses were also performed on boreholes within the Etame permit block and from wells in adjoining blocks via data trade with other Operators. The Partners carried out a new 3D seismic data acquisition from late October to mid November 20Il over a240 square kilometer area.

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The 3D seismic data acquired in 201

1 over the concession's shallow water region was processed and, along with existing joint-venture seismic data, analyzed and interpreted in20l2. By mid2012, exploration leads were already mapped; towards the end ofthe year, some ofthesi leads had been matured into drillable prospects. Given that some of these leads and prospects are situated inside tJre environmentally sensitive Mayumba marine park, the Consortium is also analyzing options on possible drilling and development of these prospects.

In parallel, existing prospects in the deeper portion of the concession area west ofthe Etame production field, are also being considered for drilling. Schedule and appropriate rig availability may dictate how the Consortium carries out its drilling campaign for both deep and shallow exploratory targets. Two prospects, namely Ovaka and Dimba, in the shallow portion of the Etame Marin consortium lere approved by the partners to be drilled. However, Sasol has gone non-consent in the drilling of.the Dimba prospect. PetroEnergy picked up its allocable share of Sassol's participating interit, bringing PetroEnergy's share to 3.26% (only for the drilling of Dimba prospect).

Drill ing C ampaign for 2 0 I 2 -2 0 I 4 The Ben Rinnes jack-up rig of KCA Deutag mobilized from Port Gentil Gabon to the Avouma Platform in late December 2012 and started the dritling of EAVOM-3P well on January 2I, ZOl3. luccessful tagging ofoil-bearing Gamba reservoirs led to the drilling of the horizontal drain EAVOM-3H, which served as the new production well from Avouma. After reaching -2,900 meters on March 8, 2013, the rig skidded to nearby EAVOM-2H and ETBSM-IH wells on \ayn,26,2013 to perform work-over procedures to replace their Electric Submersible pumps

(ESP).

T!9 Ben Rinnes rig then moved to the Ebouri Platform on May 20,2013 and commenced drilling of EEBOM-5P well on May 27, 2013. The 34-day operation yielded negative results. The rig skidded to EEBOM-3H and EEBOM-4H for well service procedures after the temporary abandonment of these wells, the rig was skidded to EEBOM-2H well on July 4, 2til3 to replace its fwo ESP units. Operations in the Ebouri platform were completed on July Zi,i1l3,after which the rig moved to the location- of open-water exploration weli EOVKM-l the Ovoka prospect, to test_the prospectivity ofthe deeper sedimentary horizons. This turned out to have poor resirvoir quality ofsands. The well was plugged and abandoned as a dry hole on August 30,2013 at TD of 2,770 meters.

After the drilling of EOVKM-I, the Ben Rinnes jack-up rig was then handed over to Tullow Oil Plc on September 9,2073 for a two-well drilling program in Tullow Oil's Kiassemy block. The rig was mobilized back to the Etame block on December 20,2013 to drill the Dimba eiploration welf (EDMBM- I ) in the shallower portion of the concession area,

Philipnine Operations SC I4-C2

- llest Linapacan, Northwest palawan

The Parent Company has a working interest in Block "C" of SC Palawan where oil discoveries were made.

l4 situated in offshore Northwest

On December 15., 1975, pursuant to Section 7 of Presidential Decree No. 87, otherwise known as the "Oil Exploration and Development Act of l972",the Joint Venture (W) partners entered into a service contract with the Philippine Govemment through the DOE for the exploration, exploitation and development of contract area in offshore Northwest Palawan, Philippines, which was amended

from time to time.

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-38Production activities in the West Linapacan Oilfield (WLO) remained on suspension mode for the last sixteen (16) years. The investment in WLO included in "Wells, platformi and other facilities" account urtder "Propert5r, plant and equipment" in the consolidated statements of financial position amounted to $6.65 million as of December 31,2013 and2012. Management assessed that the said investment is fully recoverable as SC 14-C is not yet expired, with the 15-year extension of the SC as approved by the DoE, from December 17 , 2010 to December 17 ,2025, and the existing redevelopment activities led by Pitkin petroleum plc (pitkin).

Pitkin completed during the first quarter of 2008 a farm-in to SC 14-C (WLO) on the following

terms:

r . '

To eam 5 8 .29Yo participating interest in consideration of $ L 5 million and to pay the cost of a Geological and Geophysical (G & G) Work program; Option to fund the drilling of one well; and Option to fund the development costs of the oilfield athibutable to the participating interest of

the Farmors.

As part_of the farm-in obligations of Pitkin to maintain the SC in good standing, pitkin obtained from DoE the lS-year final extension of sc l4-c (wlo), from Secember filiototo December 17,2025 in line with similar extensions granted to other scs in palawan, (e.g., sc 6-4 octon and cadlao). The extension carries the following financial obligation to the DoE:

1) One-time development assistance of $30,000; 2) One-time scholarship fund of 920,000; and 3) Yearlytrainingfundof$20,000duringexplorationperiodandg50,000duringproduction period. The aforementioned obligations may be treated as operating expenses that are cost-recoverable

during production.

Earlier plans by Operator Pitkin to drill West Linapacan by 2011 failed to materialize due to ofthe field. Instead, Pitkin farmed-out half of its 58.29% interest inscl4c2 to RMA (HK) Ltd., a subsidiary of Resource Management Associates Pty Ltd of Australia. The Deed of Assignment for this farm-out filed on April 13, 2011 was subsequently approved by the DOE on July 4, 201 1 The farm-out has no effect on the parent company's 1 .034% interest and status as free-carried up to the drilling of one well. unreso,lved technical questions on the reseryoir character

April L0' 2012, the DoE officially approved the transfer of the service contract's Operatorship from Pitkin to RMA (HK) Ltd. This operatorship transfer and the preceding farm-out to RMA (HK) Ltd of Pitkin's29.145Yo interest in the concession would reJult to the subsequent exploration On

costs leading to the drilling of one well.

This planned drilling, originally targeted by l^tez}lz,had to be rescheduled due to the delay in completion ofthe reservoir simulation study which is a pre-condition for the JV partners' approval of t]le drilling program and budget. To address the risks on the anticipated rig mtbilization and drilling posed by the existing 1990 West Linapacan subsea production facilities, the original farmors approved a budget to fund a third-party technical study on the best abandonment method. In the meanlime, the programmed environmental impact assessment for the drilling activity had been moved to early 2013, after the completion of the reservoir simulation. Drilline of the West Linapacan well, coded WLA-7, has been set on or before the end of June 2014.

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-39On lnuary 3,2013, Op".49t RMA (HK) Ltd. applied with the DOE for a transfer of operatorship of sc 14c2 from RMA (tIK) Ltd ro its newly formed Singapore-based subsidiary RMA west Linapacan Pte Ltd., which request the DoE approved on May 24,2013. By the frrst 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 tlajgctoty and drilling objective planning were also conducted towardl early production and full field development in West Linapacan.

RMA sent the final lndependent Expert Report of the west Linapacan ,?" Reseryes (Gaffirey cline & Associates) on september 5,2013. The wLA field has Froved (lp) oil reserves of 9.6 MMBO and a Proved + Probable (2P) reserves estimate of 16.5 MMBO. tttlr is based on a twomultilateral well development program scheduled in 2014-15. PetroEnergli's participating interest in SC l4-C2 is at 1.03425Yo, but will be carried free in all exploration and development costs up to attainment of first commercial oil in the West Linapacan block. Geothermal Energy Geothermal Renewable Energt Semice Contract (GRESC) No. 2010-02-012 on February 7,2010, the Parent company signed GRESC No. 2010-02-012 covering the Maibarara Geothermal Field ("the freld") in Laguna and Batangas areas, following a ltritippine Energy Contracting Round for Geothermal held by the DOE in November 2009. where thi parent Company emerged as the winning bidder. The Field had been previously explored and relevant resource data identified certain portions thereof as having potential stored heat capacity that can produce electricity in commercial quantities.

Under this service contract, the Parent Company committed to perform the following during the first contract year of the pre-development stage: (i) Local Government units (LGU) and stakeholders coordination; (ii) geologic and geophysical studies and resource assesiment; (iii) land rights survey and lease; (iv) obtain DENR and other permits; (v) establish logistics stationj (vi) land and water supply preparations; and (vii) well work-over and drilling pre-parations. The expected minimum expenditures for the first contract year amounted to $ieo,ooo. Forthe sec,ond contract year, the Parent Company committed to perform (i) work-over of existing wells; (ii) flow-testing and bore oulput measurements; (iii) engineering and design of steam/brinJ lines; (iv) grid impact study; and (v) start site preparation and construction ofthJ fluid collection and disposal system and power plant. The expected minimum expenditures is about $17.8 million. On January 5,2011, the DOE approved the Deed of Assignment and Assumption hansferring the GRESC from the Parent Company to MGI.

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

$8,l5l r66,337 127,662 1

10,055 19,605

630,067 217,246

2,051,592 l,080,823 394,263 126,946 19,935

272.160

ln 2012' all costs that are directly related to the MGPP amounting to $23 .12 million have been capitalized as construction in progress under property, plant and iquipment. The activities during the development phase are as follows: LGU and stakeholder coordination

This activity involves coordination with the LGUs in Barangay puting Lupa in calamba, Lagula a1d Barangays san Rafael and san Antonio in sto. iomas, nitangas, which has political jurisdiction over the service oontract area. It also involves coordi-nating with the stakeholders such as UP Los Bafios in terms of maintaining the Mt. Makiling Forest Reserve area' among others. This activity is important so as to inform LGUs and thJaffected stakeholders about the MGpp and enlist their suppott. During the second quarter of201l, several CSR activities were conducted in and around the project area. These include: l) donation of an ambulance to Brgy. san Rafael on April 25, 2011 2) donation of six flashlights to Brry. santiago on May ti,zott and 3) conduct of Medical Mission: Operation Circumcision to San Rafael r"rid"trtr on May Zl,ZOtt. payment for crop damages brought about by the discharge activities were given to affected owners on

June 2011.

MGI also: (1) conducted two worlahops with the community residents to determine the best livelihood projects that.MGI can support; and (2) donated Infocus Multimedia projector and its accessories to sto, Tomas philippine Nationai police on November 9, 201 L

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

MGI engaged the services of an independent New Zealandfirm, Sincliar.Knight.Merz (SKM), to conduct a technical due diligence review (third-party review) over the MGFp, primarily focused on reseryes estimates. SKM mentioned that MGI's own resource assessment is sound and well suppo*ed by data; however, SKM's independent reseryes estimates yielded higher

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_41

generation capacities compared to that of 25 years for the area.

MGI. SKM confirmed

a 28

MW resource sood for

On November I I , 201 I , based on the report of SKM (among other factors), the DOE confirmed the commerciality of the MGPP.

Land rights survey and lease This activity involves determining the total land area needed for the entire project and determining which part of the land area are govemment and private prop"rty. For those land area that are still private property, MGI will either buy those parcels-of iand or secure a lease agreement with the land owners. MGI engaged New R&E Surveying & Engineering Services to do a detailed inventory of the status of public and private lots within the likely development area' This was followed by a new topographic survey that produced an updatedtopograp6l. map ofthe area including the location of existing houses and infrastructures lroaOs, Uiiages, etc.).

Obtainment of DENR and other permits This involves obtaining the Environmental compliance certificate (ECC) from the Department of Environment and Nafural Resources (DENR) and other necessary permits. The Parent-Company engaged SMEC Philippines to conduct the necessary environmental impact study for the project and ensure the release ofthe ECC. on August 10,2010, the ECC was released to the Parent company by the DENR. on December 2-9, 2010, the DENR approved the change in the proponent's name for the parent Company to MGI As part of the ECC condition, DENR and MGI will forge a memorandum of agreement (MoA) goveming a multi-partite monitoring team (MMT). Several discussion-s were held with the DENR Los Bafros-office throughout the year regarding this MMT-MOA culminating in the agreements reached last December 2,2010. In zOi l, thJteam was formed and the MOA was finalized' The MOA includes provision for an environmental guarantee fund in the form of insurance, environmental guarantee cash fund and environmental monitoring fund. The MoA will be executed upon completion of signature of all the members of the tiam. tabl ishment of logistics station Producing geothermal steam for power generation requires the delivery, maintenance and safekeeping of many supplies and equipment, not to mention the servites of numerous thirdparty contractors and organic personnel. A safe, spacious and secure logistics station to address this operational need for the MGpp was established in sto. Tomas, Batangas. Es

In March 2010, a lease contract was signed with a lessor for his property to serve as logistics station' This has served as the main site delivery point for many drilling-related consumables such as drill pipes, casings, chemicals, etc. Land and water supply preparations This activity involves preparing the land mea and securing enough water supply for the work over and drilling activities. After the ECC was granted, civil works for the conitruction of deep cellar in Pad A commenced in early september 2010 with the engagement of Media consftuction. This new deep cellar will maximize the use of the existinf space in pad A by providing slots for future wells, allow pipelines to be trenched inside thJceilar, and minimize disturbance in future drilling and civil works operations. while the cellar was being constructed, repair and relining of the drilling sump was also started; both of these were completed in mid-December 2010 in time for the mobilization of the drilling rig.

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-+zsimultaneously, the water source for the drilling and future operations of the field was identified and rehabilitated and alvenius pipes were installed to convey water from the well. The necessary pump from the well was secured, a generator set rented, and water lines connected by late December 2010. Preparation for well work-over and drilling The preparation for well work-over and drilling began with the advanced order for longJead drilling items such as steel casings for relining the wells, drill bits, master valves, and related supplies. It continued with the pull-out and reconditioning of wellhead assemblies in wells Mai-6D, Mai-9D and Mai-l1D to ensure their safety and integrity for actual operations. The qrep,arations were completed with the fabrication and installation of necessarycellar supports for the drilling rig. Work-over of existing wells Although the actual work-over of the three (3) existing wells commenced only in January 2011, there were tasks done in 2010 to support the 201 I operations. Among these tasks was the engagement of a drilling consultant beginning in July 2010 to oversee the preparations ofthe work-over drilling program. Other key contracts signed during this stage were those for the drilling rig, milling tools, cementing services, drilling fluids, mud servic--es, pressure-temperature-spinner logging services, and downhole video and caliper tools. On site, the work-over preparations centered on lowering the wellhead of the three (3) existing wglls by cutting down their conductor pipes and casing head flanges. Mobilization to Maibarara of the drilling rig started on December 20, 2010 and was finishe.d bv December 31, 2010.

ln 201 1, three (3) existing wells, Mai-6D, Mai-9D, and Mai-l lD, were successfully workedover. The first two (2) wells are intended as production wells and the third as a re-iniection well. Mai-6D showed very good indications that it will be a good producer because ofvery good temperature and permeability, as shown in the Heat-up Results. Mai-l lD's completion test showed a very nice kick in temperature, indicating a fast thermal recovery, but with a lower permeability compared to Mai-6D. The important part operationally, however, is its measured capacity to aocept fluid, which is about 60 kg/s. when the plant is operated, the required reinjection capacity would be about 58 kgis. Reinjection is needed in order to contain any potential environmental hazard the brine may carry, and that it will also recharge the reservoir, thereby extending its productive life. As a rule of thumb in geothermal operations, there should be one (1) reinjection well for every two (2) production wells. Mai-9D is less hot than Mai-6D but also showed good permeability.

Drilling of new wells In preparation for the planned drilling of two (2) new wells to complete the 20 MW, casing head flanges and expansion spools were already fabricated as early as October 2010. Other Iong-lead items such as casings, drill bits, valves, etc. were also purchased in advance. In 2011, the negotiation for rig contract with DESCo was done. The rig,s performance as well as capability was evaluated thoroughly and recommendations to DESCO were forwarded in terms of rig rental and additional auxiliary equipment during drilling. MGI paid $0.4 million for the mobilization and demobilization of the rie.

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-+J [n2012, MB-12D, the third production well, and MB-I4D, which will be used as reinjection for power plant condensates, were drilled. The work-over of well Mai-9D was also carried out for safety reasons.

Flowlesting and bore oulput measurements A well testing supervisor was engaged in early 2010 to identif, and, ifnecessary design all the well testing requirements for the project. Apart from the inventory of the state of the various wellheads and cellars conducted in mid-2010, the preparations foithis activitywhich took place in euly 201I include: (1) the design and fabrication ofportable trvin-shock silencer; (2) the desigr and fabrication of webre separator to be used during high-pressure collection of geothermal fluids, and (3) the installation of the discharge set-up, fittings and lines. On March 5, 201 I , wells Mai-6D and Mai-9D were successfully discharged. Based on the results of the discharge testing, the potential output of the welliis lsMw.

Engineering design of steam/brine lines The technical complement for the Engineering Design Group (EDG) was formed in the latter part of 2010' Two (2) civil works consultant and a Computer-Aidei Desigrr and Drafting (CADD) operator were hired to work on the engineeringaspects of the ste-amfield and p,o-wer plant.

FDG completed in December 2010 the conceptual development plan, the initial heat and mass balance, and the piping and instrumentation diagram of thl project. Visits to the power plant site and meetings with potential Engineering, Procurement and Construction (Epb) contiactor were also conducted during the second half of 201 0.

Financing, grid impact study and power purchase contract A project-term consultant was engaged to prepare the documents needed for a Grid Impact Study(GIS) application with the National Grid Corporation of the Philippines (NGCp), which was filed on June 20,2010. In 201l, MGI receivedthe final GIS for the project.

In 201 0' MGI also went into negotiation with Endesa Carbono, the carbon trading arm of the major Spanish electric utility firm Endes4 for the sale ofthe carbon credits to be-generated by the project' After months of discussion, MGI agreed in December 2010 on the final draft and terms of the carbon credit contracts in which the Company will sell 100% of the carbon credits to be generated by the project to Endesa Carbono, ana tft" latter guarantees to buy these credits beginning in2013 to at least 2020. The Certified Emission RedJctions Purchase Agreement was signed in January 2011.

Inrelation to the agreement with Endes4 MGI engaged the services of AENOR to perform validation of MGPP, in accordance with certain provisions of the Kyoto protocol. Upon confirmation of commerciality during the latter part of 2011, deferred geothermal costs incurred prior to 2011 amounting to $1.28 million andincurred in 101I amointing to $3.94 million are reclassified to property, plant and equipment under FCRS and production wells -

Geothermal.

1n2012, since MGI mobilized its team and subcontractors with four concrete goals for 2012: l) complete the steam production and reinjection well capacities, 2) expedite thJconstruction ofthe steamfield and power plant facilities, 3) secure the right-of-way and initiate the erection of the transmission line, and 4) fortiff relationship with the host community.

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The completion of the steam requirement for the 20 MW plant was successfully achieved when MGI drilledits first production well, MB-l2D, in July -August, 2012to a total depth of over 2,000 m. After a month of heat-up, MB-l2D was successfully flowed for two months yielding chemically benign, low-gas, and high-enthalpy fluid with a power output of as much as 12 Mw. Along with existing wells Mai-6D and Mai-9D which were worked-over in 2011, MB-l2D completed the steam supply requirement for the 20MW plant. similarly, the driliing of new condensate injection well MB-l4RD to a depth of 1,900 m in October )OtZwitnrezulting good permeability satisfied the well requirement for condensate fluid reinjection. Along wittr ttrJZOt t work-over of well Mai-l I D to be used for hot brine injection, MGI Las the necesJary wells for the 20 MW facility's reinjection load. The year 2013 was a productive year for the MGPP. Construction of the Steamfield, power plant, Switchyard and Transmission Line facilities were in full-swing. By year-end, these facilities successfully underwent commissioning and testing.

In preparation for the pre-eommissioning phase, steam flushing of the steamfield surface facilities was conducted on May 17 ,2013. The purpose ofthe flushing is to clean the pipes of debris from manufacturing and installation. This activity was followed by pressurization on Jun" 20,2013.The production well Mai-6D was fully opened to allow the now bf trvo-ptrase fluid through the pipeline and to the separator vessel. This enabled the system to attain the desired op"ruting pressure' The steam was temporarily diverted to the blow-off and rock muffler until such time that the power plant was ready to accept the steam for commissioning and testing.

MGI also undertook a successful work-over of reinjection well, Mai-l1D, from September g-1g, 2013. The objective oftle work-over is to mechanically drill-out the scales that have developed inside the wellbore after being u,sed as an injector of cooled brine. Well MaigD was temporarily converted from production to reinjection well to address the reinjection requirements of the field. An important milestone was achieved when the target plate testing was successfully carried out last August 9, 2013 ' The target plate test is a standard procedure conducted to check the quality and purity of the steam prior to admission by the turbine-generator. The two plate tests passed the inspection ofthe Japanese engineers from Fuji Electric Co. 1fapan1.

After its completion in August 2013, the MGpp's I l5kv rransmission Line system was

successfully connected to the existing Meralco line on september 10, 2013. Meanwhile, on october 7,2013, the Enerry Regulatory commission (nric) granted MGI the certificate of Compliance (COC) allowing MGI to own and operate the rUCpp. These two major milestones: transmission line energization and coc grant, gave way to the commissioning and testing activities in the power plant. Finally, on November 2,2:a].3., the valve the steamline and the power plant was opened, and initial steam admission took place. "o*."dng The stelm admission was followed by grid synchronization wherein MGPP supplied an initial load of 1MW to the Luzon

Grid.

During_ succeeding tests, an issue with the turbine's Main Control Valve (MCV) was detected. The valve was shipped to Fuji's p-l1nt in Japan for inspection and repair. in" frA'cv was shipped back to the site in late December 2013 and was reinstalled in early J'anuary 2014. upon completion the reliability and performance testing, the Maibararapower ilant went on commercial operations on February 8,201,4.

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-45Borrowing Cost In 2013 and 2012, MGI capitalized borrowing costs relating to finance charges incurred in the construction of the power plant. The construction is expected to be completid in 2013 . Capitalized borrowing costs amounted to $3.64 million and $1.68 million in 2013 andZ0lZ, respectively. The rate used to determine the amount of bonowing costs eligible for capitalization is 7 .97Yo, which is the effective interest rate of loans. Land In 2011, MGI acquired parcels of land from Science Park of the Philippines, Inc. and philtown Properties, lnc. amounting to $0.6 million and $0.2 million, respectiveiy, to be used as power plant site in the Maibarara Project Area in Sto. Tomas, Batangas.

I 1. Deferred Oil Exploration Costs

Balance at beginning of year

Internal Balance at end

2013 $6,643"203 4.7

2012 $5,831,668 811.535 $6,643.203

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

However, if the contractors fail to comply with their work obligations, they shall pay to the govemment 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 govem their rights and obligations under these contracts. The internal development costs pertain to the Etame expansion costs and costs incurred for other service contracts during the year. The full recovery of these deferred costs is dependent upon the discovery of oil in commercial quantities from any of the petroleum concessions and the success of future development thereof.

5I - East Visayas on August 5,2005, a Farm-in Agreement (FIA) was signed by the SC 5l members, including the Parent Company, as Assignors, with Aushalasian Energy Limited, a corporation existing undir the laws of the Isle of Man, and ottoman Energy Limited, a company organizedunder the laws of Westem Australia as Assignees. The Assignors assigned tO% oitheir participating interest to the Assignees in SC 5l in consideration for the work obligation including funding, at the Assignees' sole cost of a seismic survey program. The farminee submitted to th; DoE a-work prograir composed of drilling one well and acquisition of seismic data. SC

In 2010, the operator NorAsian Energy Ltd. (NorAsian) presented its drilling program for an onshore well in San Isidro, Northern Leyte, in lieu of an ixploration well thai would be drilled in the offshore cebu. As part of its fund raising activity, it proposed to amend the FIA to accommodate a new Australian lnvestor, Swan Oil and Gas Ltd. (Swan). The amendment defines the onshore Leyte area orthe North Block, where the two farminees intend to drill an exploration

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-46_ well at their sole cost and consequently be assigned a 400lo interest each on the block. Their interests are retained when a second onshore well is drilled. On both cases, the farmors (including the Parent Company) are carried free. The South or the Offshore Area that covers the Argao prospect is also defined. Either of NorAsian or Swan or both can opt to drill the Argao Prospect and eam 80% interest in the whole SC 5l contract area. The farmor partners, Alcorn Gold Resowces Corporation (Alcorn), Trans-Asia Oil and Energy Development corporation (Trans-Asia) and the parent company, approved the proposed amendment. A final draft of the Amended FIA is being preparid 6y NorAsian for signature of all the parties.

As a DoE commitment for the consortium's sub-phase 3 (Sp3) work program, the on-shore vertical exploratory well Duhat-l was spudded in San Isidro, Northwest Gyte on April 20, 201I to test the hydrocarbon potential of service contract's northern block. Aftei it was sldetracked, the well (Duhat-lA) reached a total depth of321m but had to be abandoned on May 25,2011 after persistent mechanical drilling problems. Although the well failed short of reaching its 1,000m programmed total depth, the Operator/Farminee NorAsian obtained DOE approvaf to consider Duhat-1A as satisffing the Consortium's SP3 work commitment. Howevei,'this well will not be considered as an "eaming" well by the farmors - Alcom, Trans-Asi4 and the parent company.

NorAsian's application on February 3, 201 1 with the DoE for the approval of swan,s farm-in for !0% participating interest in SC 5 I was approved by the DoE on ruty l, 201 L on August 3 1, 2011, theDoE also approved the.consortium's entry into sub-phase 4 (eugust l, 201ito July 31, 2012) with a revised work commitment of acquiring and interpreting 100 line-km of 2D seismic data in northwest Leyte at a budget of $3.0 million. In November 2011, NorAsian completed the scouting survey for this planned 2D seismic study. It subsequently engaged BGp sE Asia to conduct the 2D seismic survey at a slightly expanded budget of $4.3 -ittion. In December 201l, the SC 51 partners reached an intemal agreement to revise the farm-in terms to: l) divide the SC 5l contract area into a northem (northwest Leyte) and southem (offshore Cebu) blocks; 2) the assignment of NorAsian's putative 40% interest in the south block to Swan thus relinquishing all of NorAsian's interest in offshore Cebu; 3) the drilting of a second on-shore wellinnorthwestLeytetocompleteNorAsian'sfarm-in; and,4)adeadtineofApril30,2012for Swan to commit to the drilling of the offshore Argao prospect in Cebu, or forfeii all its interests and rights in SC 51 .

Meanwhile in the South Block, the SC 5l Filipino consortium issued a reminder to SWAN Oil & Gas to exercise its financial capabilify to drill the Argao-1 deepwater well in Cebu by the end of March20l2, with the consequence of being in default with the Consortium. SWAN disputed its default status, but later announced entering into an amicable agreement with the Filipini partners upon exiting SC 51 on September20,2012.

on January 25,2012, the DoE approved the subphase 4 work program & Budget (wp&B) of SC 51 . The WP&B for SP 4 includes the acquisition, processing und int"rp..tutlon of l00km of 2D seismic over &e Duhat prospect in the North Block, at a total budget oi $q.:s million. The operator of the block, otto Energy, contracted Beijing-based BGp Asia to conduct the 2D seismic survey' Mobilization of the seismic crew started in February 2012, Actualdata shooting and acquisition for the 102 line-km 2D seismic survey over the Duhat prospect was conducted

from August to october 2012, ata cost of US$ 3.391\4I\4. Following thi completion of the 2D seismic program, the Consortium elected on December 12, 2012tienter SPi with a one well drilling commitment. This made way for commencement of otto,s well design planning and activities to secure a suitable rig to drill the Duhat-2 well in mid-2013.

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-47 On January 28,2013, the DOE approved the SC 5l North block consortium's election to enter Subphase 5, which includes drilling of the Duhat-2 well in NW Leyte. After acquiring all the necessary permits from the LGUs and appropriate site preparations in San tsiAro, feyte, Duhat-2 was spudded by operator otto Energy Investments Ltd. on July 24,2013. Upon reaciing a depth of201m on July 26,2013, salt water flow occurred. Otto decid'ed to plug and abandon the well to prevent adverse environmental impact to the local community.

similar to the previous Duhat- 1 well, the Farmors, Alcorn (now cosco capital), TransAsi4 and PetroEnergy did not credit Duhat-2 as an "earning well". The DOE for its part declared Duhat-2 failed to satisfi the work commitment for subphase 5. Otto Energ, appealid to the DOE and was given a 6-month extension to conduct further geologi. ussest*er.=i of Duhar2 for the remainder of Subphase 5.

SC 6-A - Octon-Malajon Block ln March 2007, Vitol GPC Investments S,A. (VGI) negotiated a farm-in to the SC 6-4 in offshore Palawan. Under the agreement, Vitol will conduct u.tudy on the prospectivity of the block over a one-year period until March 2008, after which it will decide whetlier to continue or complete the

farm-in process.

GPC Investments SA (formerly Vitol GPC Investments SA) gave notice in November 201 0 of its decision not to exercise its option on the farm in interest in Sa 6-,4. This followed the failure of the Galoc Consortium to commit to the second development phase of the Galoc Field. Thereafter, Philodrill re-assumed the Operatorship of the Octon Block.

In December 2011, to maintain the validity of the SC, the Octon Joint Venture submitted to the DoE a $546,000 work program. It consisted of the reprocessing of 400 sq. km. of the lggT 3D seismic data' Reprocessing would enhance the qualiry of the sei-smic infoimation, which would enable the mapping of potential structural drilling targets in the northem portion of the contract axea,

Follorving the departure of Vitot GPC from the SC 64, Consortium in late 2010, pitkin petroleum Plc (Pitkin), a uK-registered company, signed in July 20l l a farm-in ugr""."ni with the consortium members fot a70Yo participating interesi in the block. As iarminee, pitkin will spend, at its own cost, about $5.0 million to acquirJ, process, and interpret 500 sq. km. of 3D seismic data in Octon. Should it elect to exercise its options, Pitkin may drili up to two production wells at no cost to the farming-out consortium members. On December 6,2011, the DOE approved the Deed of Assignment transferring the Operatorship Pitkin. Consequently, the parent C6mpany's interesi in the block was reduced from l6.67Yo to 5.001% but the Parent io*puny will be carried free in all subsequent exploration costs up to the drilling of two Octon wells. and70%o of the service contract interestto

Aaer the DoE approval of Pitkin's farm-in and operatorship of sc-6A on December 6,2011, Pitkin commenced preparation for Phase I activitils, consisting of the acquisition, processing and interpretation of -500km of 3D seismic data. This new 3D seismic program will help further refine the drilling potential of the prospects and leads in the area. In mid-March 2012, Pitkin sent out tenders to i.n ltoy seismic firmsio aaf,ry out the 3D seismic survey with the intention of commencing the survey by mid-February, 2013.

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After the conduct of Information, Education and Communication (IEC) activities and upon securing the necessary endorsements from the Palawan local government units (Palawan Council for SusJainable Development and the Sangguniang Panlalawigan of Palawan) in February to June 2013, Operator Pitkin secured DOE approval for the conduct ofthe 3D seismic survey for Phase 1. on July 30,2013, the consorlium granted Pitkin request for a one year extension fee. The seismic vessel M/V Voyager Explorer commenced the acquisition of 508 sq.km of 3D seismic data on October 5, 2013 and 48.5 line-km of 2D seismic data tying the Bantac-l well in SC 57 and the Malajon-l well in SC 6A. The survey was completed on Novernber 6,2013.

ln consideration of the amounts of time needed for seismic interpretation, the consortium agreed with Pitkin to seek DOE approval to extend Phase I of the workprogram for four months, from August 31,2014 to December 31,2014. To date, the DoE reply is still forth coming. SC 47 - Offshore Mindoro and Panay The DOE approved on January 12,201I a one-year extension ofthe Consortium's Sub-phase 2 (sP2) work program deadline to July 10, 2011. This would enable the operator, pNoc Exploration Corporation (PNOC-EC), to finish the evaluation of 2D seismic data acquired by the Partners in 2010. PNOC-EC's evaluation identified at least six potential leads, most of which were in deep water. To further de-risk these leads and enable the Partners to attract potential farminees, PNOC-EC requested the DOE on June 21,2011for a further one-year extension of Sp2 to carry out a 500-km 2D seismic survey and a source-to-reservoir migration study. pNOC-EC repeated the extension request in August 201 I but no official DOE response had been received till the end of 2011. In the meantime, PNoc-EC is completing the reservoir study, preparing the program for the additional 500 km 2D seismic survey, and discussing farm-in opportunities with potential investors.

PNOC-EC requested for a one-year extension ofthe contract's Subphase 2 to July 10,2012 to conduct detailed source rock-to-reseryoir rock migration sfudies and acquisition of 500km 2D seismic data. These proposed studies were intended to further de-risk thi area and athact potential farminees who have been stymied by the discouraging results of the last deep oil well driied in 2007 by Malaysia's Petronas.

of end-2012, the application for Subphase 2 extension was still pending approval by the DOE, while awaiting DoE approval, the sc 47 consortium has been actively ri"ting poteniial farminees to carry out the drilling of one (l) exploratory well, as programmed ioi the subsequent As.

Subphase 3.

The consortium has a pending request from the DOE for an extension of SubPhase 2. This request was made by PNOC-EC, in2012. During the year, farm-out efforts have been carried out by the operator. The farmout terms include seismic processing and drilling of one well. As of end Lf the year,.the farmout process has not been settled. PetroEnerry's participating interest in SC 47 remains at2.00Yo, PNOC-EC at97o/o, and Basic nnergy t%.

SC 75 - Offshore Northwest Palawan The joint study and bid group consisting of philex petroleum corporation, pNoc-EC and f911oEnerg,, was notified by the DoE that the group had won the uiaolng for Area 4 of the Philippine Energy Contracting Round 4 (PECR 4) last February 14,2013. Th-e block is located in deepwater areas offshore Northwest palawan.

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_49After finalization of contract terms, the consortium formally signed Service Contract 75

December 19,2013. Secretary Petilla then signed on behalf of DOE on December 27, 2013. Under the newly-executed Service Contract, the first Sub-phase will consist of Geological & Geophysical (G&G) studies of the Northwest Palawan Basin and the conduct of a 2,200 line-km 2D seismic survey over SC 75 for the duration of 24 months at an estimated cost of US$ 3.50 MM.

Philex Petroleum is the Operator of SC ?5 with 50% participating interest, PNOC-EC with 35%, and PetroEnergy with l5%. As ofDecember 31,2013,2012 and 2011, the corresponding percentages ofthe Group's participation in the various SC areas are as follows: 2013 Gabonese Oil Concessions West Linapacan - SC 14 C2 Octon Malajon Block - SC 6-^4 East Visayas - SC 5l

Offshore Mindoro - SC 47 NW Palawan -SC 75

2.525o/o

2012 2.525%

2.525o/o

201r

1.0340

r.034%

4.l37Yo

5.001%

4.012o/o

4.012%

2.000vo 15.000%

2.000o/o

5.00lyo 4.012% 2.000%

12. Investment Properties

As of Decembet 3l ,2013 and 2012, this account consists of land with total carrying value of $31,417.

The fair value of the investment prop€rties of the Group amounted to $47,6g3 as of December 31, 2013 and 2012. The Group did not obtain the services ofan appraiser and determined the fair values ofthe Group's investment properties on the basis oi recent sales of similar properties in the same areas as tlre investment properties and taking into account the economic conditions prevailing at the time the valuations were made.

AsofDecember3l,2013 and20l2,thefairvalueoftheinvestnentpropertiesisclassifiedunder the Level 2 category.

Except for insignificant amounts ofreal property taxes on the investment properties, no other expenses were incurred, and no income was eamed in relation to the investment properties in 2013,2012 and 2011.

13. Investment in Navy Road Development Corporation (NRDCj As of December 31,2013 and20lZ, this account consists of:

Acquisition cost

$260,3 88

Advances

54.032

in NRDC represents investment in subsidiary due to the Group,s 100% holdings in stock.

-T]Tlnent NRDC's capital

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-50Befow is NRDC's financial position as of December 31, 2013 and2012

Financial Position Cument assets

Noncurrent assets

366,193

Allowance for Total Assets Current liabilities Noncurrent liabilities Total Liabilities Net Assets

66-t93

As of Decembet 31,2013 and 2012, NRDC has not commenced commercial oDerations and has not incurred any expenses 1n2013,2012 and 2011. Management intends to liquidate NRDC and has provided for fult impairment losses on this investment. 14. Other Noncurrent Assets

Input VAT Prepaid rent - noncurrent portion Deferred cost - wind

2013 $2,628,670 2,177,765

2012 $709,4r2 2,457,440

452,229

63.125

63,125

Input VAT refers to the Groups cumulative input vat carry overs which will be utilized in future periods' MGI is undergoing a vat refund process as of December 31,2013. MGI has accumulated Input VAT as of December 31,2013 amounting to Fl04.g million or $2.36 million, of which FI5.79 million or $0.355 million covering the four (4) quarters of 2011 were already filed with the BIR Regional District Office for administrative claim on VAT refund. Moreover, the first two (2) quarters of these claims amounting to F13.23 million or $ 0.298 million were already elevated and filed with the Court of Tax Appeals.

on April 23, 2012, the company entered into a Land Lease Agreement (LLA or the Agreement) with the National Power Corporation (NPC) and the Power Sector Assets and Liabilities Management corporation (PSALM) over the MGpp's steamfield lot in sto. Tomas, Batangas. Under the LLA, the Company will lease the steamfield lot for a period of 25 years, extendable for another 25 years upon mutual agr-eement ofthe parties. Prepaid ient-noncurrent portion pertains to the advance rental payment paid for the lease agreement. The current portion dui in oni year is shown as part of"Prepaid expenses and other current assets" in the consolidated statements of

financial position.

Restricted cash pertains to the Parent Company's share in the escrow fund to secure payment and discharge ofthe Parent Company's obligations and liabilities under the Floatine production Slorage and Offloading (FPSO) contract. The amount was deducted from the P-arent Company's share on lifting proceeds during the first lifting made by Etame in November 2002 and wili be paid back to the Parent company at the end of the contract which is in2020.

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5. Accounts Payable and Accrued Expenses

Accounts payable Payables to related parties (Note 23) Accrued interest payable Accrued expenses Dividends payable

2013

2012

sl,020,77r

$241,s47 2,984,663 683,762 471,287 260,098 125,261 235.747 $5,002,365

861,771 968,885 565,145 235,397 175,051

Withholding taxes payable Others

s3,944,717 Accounts payable consist of payable to suppliers and contractors. Accrued expenses are as follows:

$294,528

2012 s224,884

2l,69l

71,417

5,376 143,644

67,739

2013

Profit share Professional fees Professional fees - related parties

SicWacation leaves

10,048

Insurance

6t,429

Trust fees

35,770

Others

Accrued interest payable pertains to accrual for interest on loans (see Note 16). Dividends payable pertain to unclaimed checks as of December 31, 2013 and 2012. Other payables mainly pertain to accrued security services, utilities and condominium dues. The Group's accounts payable and accrued expenses are due within one year. Carrying values approximate their fair values as of December 3 l. 2013 and 2012.

16. Short-term and Long-term Loans Payable The Group's loans payable pertains to loans availed by the Parent Company and MGL Below are the details ofthe loans entered: 2013

Short-term loans payable Less unamortized deferred

Less unamortized defered financing

$2252,503

cost

l?46'.5g7

20t2 $-

1.007.g35

$s9

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-52PetroEnergy's short-term and lone-term loans paliable PehoEnergy entered into unsecured loan agreements with various lenders specifically to finance equity infusion to PetroWind. On July 19,2013, PetroEnergy entered into a $3.5 million loan agreement with various lenders with interest rate for the first interest period (i.e. six months from issue date) of 3.898%, subject to re-pricing every six months based on a benchmark rate plus a pre-agreed spread. The tenor ofthe Ioan is 2 years, maturity July i 9, 201 5. On November 2I,2013, Petroenergy entered into additional loan amountins to F200 million ($4.5 million) with various lenders with an interest rate of 5.45% p.r un ruri. 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, mafurity November 21,

20t5.

These loans are reflected under the long-term loans payable account. On December 12,2013, PeffoEnerry entered into a Pl00 million or $2.2 million loan with various lenders with an interest rate of 4.5Yo per annum. The loan is payable within 33 days, maturity January 14,2014. This loan is reflected under "short-term loani payable account,,.

MGI's long-term loans payable

on september 26,2011, MGI together with pNoc Renewables corporation and rrans-Asia entered into a?2'24 billion or $50.5 million Omnibus Loan and Security Agreement with RCBC and BPI specifically to partially finance the design, development, procuremint, construction, operation and maintenance of its geothermal power plant project. As of Deoember 31,2013 and2011,MGI has outstanding drawdowns of $50.46 million and $39.95 million, respectively. The remaining balance wilibe subsequently drawn based on a certain drawdown schedule. The loan is payable semi-annually within ten (10) years from and after the date of initial drawdown immediately following the signing date, payments to be made in fourteen (14) semiannual principal installment commencing on the end of 6th semester from the date of the initial drawdown, inclusive of a grace period of thirty-six (36) months. The amount of loans payable is presented as part of noncurrent liabilities.

of interest applicable to the loan is fixed for the first five (5) years from the initial Jhe ryte drawdown date based on the sum of the prevailing fixed benchmark rate on the pricing date and {e nlarqil of 25% per annum (the "Initial Interest Rate"). After five years from the date of the first initial drawdown, the interest for the remaining 5 years tenor shali be repriced based on the higher ofi (i) the sum of the thenprevailing fixed benchmark rate plus the margin of 2.25o/o per annum, or (ii) the Initial Interest Rate. Deferred financing costs are incidental costs incurred in obtaining tho loan which includos documentary stamp tax, hansfer tax, chattel mortgage, real ostate mortgage, professional fees, arrangers fee and other out-of-pocket expenses. Total defened frnancing costs amounted to

$l.6million' AsofDecember3l,20T3and20l2,theportionpertaininftothedrawnamountof the loan amounting to $1.18 million and $1,01 million is presented as dJduction fiom the loans payable account and is amortized over ttre life ofthe loan using the EIR method. Amortization

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-53deferred financing cost will be capitalized until all necessary activities to prepare the power plant for its intended use are substantially complete.

Details of unamortized deferred financing costs are as follows:

Balance at beginning of year Deferred financing costs on loan drawn during the

2013

2012

$1,007,935

s393,792

766.t4r 1,403,853 Less amortization Balance at end of

1,159,933 152.098 $ r.007.83 5 $

The portion pertaining to the undrawn amount of the loan is presented as an asset in the consolidated statements of financial position. As of Decembi r 31 2013 and 2012, L45 million , $ and $0.54 million, respectively are presented as current asset under "Prepaid expenses and other current assets" account (see Note 9).

MGItas pledged

a portion of its land and property, plant and equipment amounting to $3.86 million as collateral in connection with the loan. pledged asiets are as follows:

r e

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

Below are the accumulated capitalized borrowing costs as of December

3l,2ol3

and 2012:

2012

2013

lnterest on loans payable Balance at the beginning of year lnterest incurred durine t}le Balance at end

Defened financing cost Balance at the beginning ofyear Amortization durins the Balance at end

s2,167,924

746

10,039

157.88s 167.924

7,240 152.098

1s9.338

The loan covenants covering the outstanding debt of MGI include, among others, maintenance of certain level of debt-to-equity and debt-service ratios. As of December 3-1, 2013'and 2012, MGI is in compliance with the said loan covenants.

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-5417. Asset Retirement Obligation The Group has recognized its share in the abandonment costs associated with the Etame, Avouma and Ebouri oilfields located in Gabon, West Africa.

Movements in this account follow:

Balance at beginning ofyear Change in estimate (Note l0)

exp:ns=e fc:cretion

Balance at end

2013 $237,668

46,651

44,070

20t2 $474,293

(268,s20) 31,g95

$237,668

The provision for the oilfields in Etame maintained the original discount rate at l5% for both

years.

Reduction during the year resulted from the change in estimated abandonment costs from $0'87 million in 2012 to $0.78 million in 2013 (the Group's share to the total accrued retirement obligation of the consortium). The estimate was provided by a third party expert, as engaged by the consonium operator of the oilfields in Gabon, West Africa. This'also t"sult"d to a dlcrease in the book value of "wells, platforms and other facilities" account under ,.property, plant and equipment" in the consolidated statements of financial position (see Note l0J. The provisions for the abandonment costs for Etame are expected to be settled in 2020, while for Avouma and Ebouri in2022.

18. Equity Under the existing laws of the Republic of the Philippines, at least 60Yo of the parent Company's issued capital stock should be owned by citizens ofth€ Philippines for the Group to own and hold any mining, petroleum or renewable energy contract area. As of December 3l, zol3,the total and subscribed capital stock of the Parent Company is 99.79% Filipino and 0.21% non1s;yed Filipino, as compared to 99.75% Filipino and0.25yo non-Filipino as of December 31,2012 and 99.87% Filipino and 0.13% non-Filipino as of December 31,201l

As ofDecember 31,2013 and2012, capital stock consists of330,000,000 authorized and 273,824,220 issued and outstanding common shares with par value of Fl (90.0244) per share. Total capital stock and additional paid-in capital amounted to $6.32 million and$25.24 million. respectively, as of Decembe r 3 l, 201 3, 2012 and 20 | l.

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

Number of

introduction August I l,

2004

Add (deduct): 25% stock dividend 30%o stock dividend I :l stock December 31, 2010 r.ug!ru!l. Deduct: Mov€ment rvruvsllrcllr December 3 l, 201 I

Date

84,253,606

p3/share

21,063,402 31,595,102

F I /share

136.9t2.1t0

F1/share P5/share

Number of holders

ofSEC

August 4, 2004

September 6, 2005 September 8, 2006 2010

273,824,220

2,t49 liA\

', l)7

273,824,220

Deduct: Movement December 3 l, 2012 Deduct Movement

273.824

ll3

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

July 4, 2013, 5% or 9.001 per share cash dividends to all stockholders of record as of July 25, 2013 amounting to $315,248 The dividends were naid on August 20, 2013. April26,2012, l0% or $0.002 per share cash dividends to all stockholders of record as of Septe mber 2l , 2012 amounting to S643,838. The dividends were paid on October 17,2012. April26,2012, l0% or $0.002 per share cash dividends to all stockholders of record as of May 18,2012 amounting to $643,838. The dividends were paid on June 14, 2012. May 17,2011,10% or $0.002 per share cash dividends to all stockholders of record as of September 20, 201 I amounting to $631,951. The dividends were paid on October 14, 201l. May 17,2011,10% or $0.002 per share cash dividends to all stockholders of record as of June 16, 201 I amounting to $629,120. The dividends were oaid

20t3

2012

2011

$315,248

643,838

643,83

63 1,951

The Parent company's retained eamings available for dividend declaration as of December 31,2013,2012 and 201 I amounted to $1 l.l0 million, $8.68 million and $6.73 million-

respectively.

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-56Appropriated Retained Eamings 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 ofthe Ebouri field by the Parent Company has been approved by the BOD on the same date.

On July 24, 2008, the BOD approved additional appropriation ofretained earnings amounting to $ I .0 million for the development of the Ebouri oil field in Gabon, West Africa.

On February 19,2013, the BOD approved additional appropriated retained eamings amounting to $1.09 million to cover for the Parent Company's share in the cost of the committed wells in the Etame oilfield in Gabon, West Africa.

Total appropriations for the development of the oilfields in Gabon, West Africa as

December3l,2013and20l2amountedto$3.l5millionand$2.06million,respectively. Further expansion of the said oilfield is on-going and is set to be completed in 2015. There are no appropriations of retained earnings made in 2012 and 20ll . Capital Management The primary objective of the Group's capital management is to ensure that it maintains a strong credit rating and healthy capital ratios in order to support its business and maximize shareholders' value. The Group manages its capital structure and makes adjustments to it, in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may increase its debt from creditors, adjust the dividend payment to shareholders or issue new shares.

As of December 31, 2013, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity. As of December 31,2013 and20I2,the Group's sources of capital are as follows:

20t2

2g13 Loans payable

s59,452,637

538,943,444

$101,898,743

6.121.533 $79,493,578

25244,737 25,244,737 10,879,836 8,983,864

Additional paid-in capital Retained eamines stock

The table below demonstrates the debt-to-equity ratio of the Group as of December 31,2013, 2012 and2011: 2013

20ll

2012

Total debt Loans payable Accounts payable and accrued expenses lncome tax payable Asset retirement obligation

Accrued retirement liabilitv

$59,452,637

3,944,717 772,479 328,389 116,175

s64,564,397

$38,943,444

$13,295,139

5,002,365

3,455,507 243,474

75,015 237,668

57,812

$44,31 6,304

474,293 33,572 $17,501,985

(Forward)

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-57 -

2012

2013

Total debt Total equity Capital stock Additional paid-in capital

$6,321,533 25,244,737

Retained eamings

Appropriated Unappropriated

2011

$6,321,533 25,244,737

3,149,555

<<<

2,055,55 5

7,730,281

6,928,309

5,656,403

n<{

Remeasurements of net accrued retirement

liability

(s,707)

(47,563)

(12,720)

Cumulative translation adjustment

Noncontrolline interest

(1,120,775) 9,676,476 $s0

778,372 5.807.379 $47.130.178

(s6,227) 3.85t.627 $43.060.908

Based on the Group's assessment, the capital management objectives were met in 2013, 20lZ and

20tr.

19. Retirement Plan The Group has a funded defined benefit retirement plan (the Plan) for all of its employees. The Plan provides for normal and early retirement, as well as, death and disability benefits. The Group's fund is in the form of a trust being maintained by a trustee bank, Rizal Commercial Banking Corporation (RCBC). In 20i 3, 2012 and 201 1, there were no transactions that took place between the fund and the Group, The fund has no investments in the Group's equity as of December 3 1, 2013 and 2012.

Under the existing regulatory framework, Republic Act764l, The Retirement Pay Law, requires a provision for retirement pay to qualified private sector employees in the absence of any retiiement plan in the entity, provided however that the employee's retirement benefits under any collective bargaining and other agreements shall not be less than those provided under the law. The law does not require minimum funding of the plan. The Group updates the actuarial valuation every year by hiring the services of a third party professionally qualified actuary. The accrued retirement liability recognized in the consolidated statements of financial position as 3 l, 20 13 and 2012 and January l. Z0l2 are as follows :

of December

2013

2012

(As

restated)

2011

(As restated)

Present value of accrued retirement

liability Fair value of plan assets Accrued retirement liabi

s254.766

$116.17s

164,092 106.280 $57.812

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$r 2s,108

9l-536

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-58The movements in the accrued retirement liability recognized in the consolidated statements

financial position are as follows: 2013

Present value

of accrued retirement

Fair value of lan assets

Balances at

Accrued retirement liab

Current service cost Net interest

$57.812 33,873

33,873 19

Belireqrqnt_expense_. _ Actuarial changes arising from: Financial assumptions

73,235

Experience

(7,64s) translation ad

(r,474)

74,709

(7,64s)

Remeasurement losses

2012 (As restated - Note 3) Present value

of accrued retirement

Fair value

lan assets Balances at Cunent service cost Net interest

125. r08

$9r.536

32,247

Accrued retirement liabi $33.572 32,247

7.493

0t2

5.481

Retirement

Actuarial changes arising from: Financial assumptions Experience translation adiustments

4,150

2,802

(14,267)

1,348

(14,267)

6.46r

9.361

Remeasurment losses Balances at end of

2011 (As restated - Note 3) Present value

of accrued retirement

Fair value

Accrued retirement

lan assets Balances at Current service cost Net interest

Retir"tTrqnte*pense.

Actuarial changes arising from: Financial assumptions Experience Foreign currency translation

t.267

$65.7s8

21,090 5.634

4.560

21,090

(73e)

31,567 (13,914)

1.0'74

32,306 (13,914)

Remeasurement losses

Contribution Earellgg at Jng qJear

$15

1,054

$125,108

)) _ 71)_ __ $91,536

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18.171

(22272\ 533572

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-59The components of net plan assets are as follows:

Cash and cash equivalents

Investments in quoted govemment securities tnterest receivable

Trust fee

20r3

2012

20tl

$45,995

$40,97 s

$ss,092

65,0s

36,301

92,334

789

742 480

285 142

The principal actuarial assumptions used in determining pension benefit obligation for the Group's plan are as follows: 2013

2012

4.000A 6.67Vo

4.20% 4.00%

5.27Yo 4.48Vo

5.27%

Rate of increase in salaries

Beginning Ending Discount rate Beginning Ending

5.77o/o

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

Effect on accrued

retirement

Increase decrease

Discount rate

+0.50% -0.50%

Shown below is the maturity analysis of the undiscounted benefit payments as December 31, 2013 and 2012:

Less than one year More than one year to five years More than five years to I 0 years

More than l0 years to 15 years More than 15 years to 20 years More than 20 vears

2013 $25,785 90,391 289,981

137,026

($13,312) 14,868

of 20t2 $2s,834 89,221

11) 32,s59

1<'.7

539,7t9

104,800

2,300,125

1,437,t54

The Group expects to contribute to the fund the amount of $20,225 in2014.

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-6020. Income Tax The provision for income tax consists of:

20t2

2013 $1,852,088

Cunent - RCIT

Defened

G8,516)

201

$963,372

s899.560

$1.337.61I

(63,812)

1,191,787 145,824

The components ofthe Group's net deferred tax assets are as follows:

20t2

Asset retirement obligation

Accrued profit share Accrued retirement liability Provision for losses

$193,831

$166,3s7

92,743 37,320

60,743

17.092

t3,628 257.820

Deferred tax liabilities on: Production revenue Unrealized foreisn ex

68,714

113,344

3.953

1t7

76.398

40,523

As of December 3 I , 201 3 and 2012, the Group did not recognize deferred tax assets on NOLCO amounting to $5.16 million and $2.64 million, respectively, because the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized Details of the NOLCO are as follows: PGEC

Year Incurred

tion 2015

20t4

NOLCO In USD $481.215 342.153

InPHP

F19.753.890 14.999.967

NOLCO Year Incurred 2013

20t6

2012

2015

2011

2014

In USD $1214,552 1,007,429

In PHP ?53,920,047 41,354,900

32.373.964 Pt27.648.911

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-61PWEI

Year

Incurred

Expiration

2016

NOLCO

In sr.s1

USD

4,197

In pl{p

F61.007.482

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) b)

The NOLCO had not been previoirsly offset as a deduction from gross income; and The loss should be a result from the operations and not from the availment of incentives provided for in the RE Act.

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

30.00%

10.27

3.47

5.68

8.27

(0.06)

1.98 0,25

2.84 0.26

(0.61)

(2.r4)

2.86

1.44 (5.3 8)

(4.0e) (0.12)

2013 Statutory tax rate Add (deduct) reconciling items: Loss from entities subjected to

lower rate Movement in unrecognized defened tax assets Unrealized loss (gain) on FVPL Interest income subjected to final tax Nondeductible exenses Unrealized foreign exchange gain Others

Effective income tax rate

2012 2011 - (As restated 3) Note 3)

(As restated Note 30.00%

(r.62) 4.54

t,82

t.49

53.65Vo

27.80%

33.08%

2013

20t2

20tr

s4,022,289 915,566

$4,130,614 830,725

$4,788,5s5 563,622

4,596 221,479

5,028

59.842

2,805 77.t67

21. Oil Production

Production, transpoftation and related expenses

Storage and loading expenses Supplies and facilities Others

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-62 22. General and Administrative Expenses 2012 (As restated Note 3

20t1 (As resrared -

Salaries, wages and benefits

(Notes 19 and 23) Taxes and licenses

Depreciation (Note 10) Professional and other fees Security and janitorial services Research costs (Note 3 i)

Transportation and travel Rent expense Insurance Donation and contribution Entertainment, amusement and recreation

$1,405,082 405,265 299,315

$i,110,3s8

1,000,459

189,628

r 19,993

25t,593

146,107

210,624

302,534

243,084

161,582 156,933 149,677

140,546 l8 1,487 156,872 52,108

157,576

128,192

t47,8t3 142,680 43,467

90,373 83,960

72,t98

72,648 70,320

53,290

<1 <A<

<7 <70

46,482

Repairs and maintenance

61,173 58,635 58,071 45,247

47,101 46,491

Condominium dues

41,466

Business meetings

38,306 22,797

6,545

32,226 41,079

ts,776 12,448

16,160 14,164

I 1,884

12,4lg

47,388

58,62',1

8,646

9,91

(EAR) Gasoline, oil and lubricants

Utilities Office supplies Communication

Environmental and social expenses Advertisement Stock transfer fees Training and seminar Dues and subscriptions

55,912 r43,272

48,484

z,JzJ 34,465 24,139 24,386 )

)\)

22,768 27,349 8,678

7,6s3

4,388

Listing fees Others

t2,909 86.351

s7.761

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

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

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-6323. 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 ifone party has the ability, directly or indirictly, tJ 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 mav be individuals or corporate entities.

Significant transactions with related parties are as follows:

Amount Related

Outstanding Balance Receivables (payables)

Investor EPC - Advances Internal audit services

$81,450

$l,362,09 r

15,837

29,978

$87,700

(5,376)

$3,266,268 (10,048)

Afliliate Civil works EPC - Accounts

$4,438,33

12,403,44s

$14,820,787

$4,43 8,338

(861,77t) 3.664.267 655.89

(2,e84,663) 28 I I

PetroEnergy has engaged House of Investments, Inc. (HI) to perform intemal audit services to f9lr9!1erw, HI charges rgtainer fee of P56,000 ($1,261) per month totaling to approximately $15,837 per anrum. Also in 2012, PetroEnergy engaged HI to perform pro"ir. review of its hiring, purchasing and disbursement processes. The engagement fee amounted to F600,000 ($ r 4,141), b.

PetroWind has engaged EEI Corporation for the civil works on the construction of wind farm including intemal roads, turbine foundations and control room buildings. The Contract is approimately $14.79 million (F656.s million). As of December 31,2013, petrowind paid down-payment amounting to $4.4 million (Fl92 million).

on september 2,201r, Maibarara

engaged EEI corporation for the Engineering, procurement and construction of the MGPP. contact price is approximately $37 million (pl.6 billion). Total payment made amounted to $35.9 million (FI.5 billion). As of December 31. 2013 the contract is 96.43% complete.

24. Financial Instruments The Group's principal financial instruments include cash and cash equivalents, short term investments, trading and investment securities (financial assets at FVPL), receivables, restricted cash, loans payable, accounts payable, accrued expenses and dividends payable. The main purpose of these financial instuments is to fund the Group's working capital requirements. Categories and Fair Values of Financial lnstruments As of December31,2013 and20l2,the carrying amounts of the Group's financial assets and financial liabilities approximate their fair values except for loans payable. The fair value of the

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-64The 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 ofthe instruments, carrying amounts approximate fair values as of the

reporting date. Fair values are based on published quoted prices. Fair values are based on quoted market prices as at reporting date. Due to the short-term nature of the instruments, canying amounts approximate fair values as at reporting date. Fair values are based on the discounted value of expected future cash flows using the applicable interest rate for similar type of instruments. The fair value for 2013 and 2012 for the 5 year tenor loans is derived using the projected T-Bond coupon rate of 3.002% and 4.125yo, respectively, plus2.5% credit spread for the first five years and 2.25Vo for the second five years. For the two loans with 2-year tenor, 2013 fair value is derived using the treasury late of 2.l25yo plus a credit

Equity securities Debt securities and Golf club shares Accounts payable and accrued expenses

Loans Payable

spreads

I .64 8Vo arrd

.450o/o, respectively.

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

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quoted prices in active markets for identical assets or liabilities (Level l); those involving inputs other than quoted prices included in Level I that are observable for the asset or liabilify, 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). 2013

Level2

Level 3

Fair Value

$124,317 13.741

$124Jr7

Level I

Level2

2012 Level 3

Fair Value

$125,531

Level Financial assets at FVPL Marketable equity securities Investment in golfclub shares

Financial assets at FVPL Marketable equity securities [nvestment in golfclub shares

$ 125,53

13.741

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

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-65 Financial Risk Manaeement Objectives and Policies The Group manages and maintains its own portfolio of financial instruments in order to fund its own operations and capital expenditures. lnherent 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 short-term and long-term funding requirements, the Group intends to use intemally generated funds as well as to obtain loan from financial institutions. The tables below summarize the maturity profile of the Group's financial assets and financial Iiabilities as of December3l,2013 and2}l2based on conhactual undiscounted payments:

On demand

than morths

Less 6

6 months to

Morc than

12 months

l2 months

Total

$r38,058

Financial Assets Financial assets at FVPL Loans and receivables: Cash and cash equivalents Short-tem investments Accounts receivable: Consortium 0peralor Others Interest receivable

Resticted

cash

$138,0s8

2,229,7U

341,824

2,s7r56r 914,606

2,56t,629 40,098 5,128 $4,974,6s7

: $34r.824

N€t financial assers

(liabiliries)

2,561,629 40,098

5,12E

63.125

63.125 s6.294.212

$57,214,s57

s59,452,637 r,698,877

$914.606

Finrncirl Liabilities Loans payable Accounts payable Aocrued expenses Accru€d interest payable Dividends payable Oth€rs: Due to NRDC Others

914,606

$2,238,080

r,698,877 t,623,292

r,623292 94,403

94,403 235,391

235,397 51,126

51,126

$r,299J94 ($1.990,659) $914.606

($5?.151.432t ($56.928.0911

20t2 6 months to l2 months

More than

On demand

Less fian 6 months

l2 months

Total

$t42,827

t,020,234

20,601,988

Finsncial Assets Financial assels at FVPL Loans and receivables: Cash and cash €quivalents Short-term investments Accounts rec€ivable: Consortium operator Others Interest receivabl€ Restrict€d cash

1,956,341 1,969 23,7 t7

814,741

1,956,34r

I o(o 23,',|t7 63.r25

(Forwrrd)

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-66-

More than l2 months

On demand

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

NRDC

3,226,2t0

s38,943,444

3,226,210 47t,28.1

471,287 683,'762

260,098

538.94t,444

683,',762

260,098

55,292

,q,

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

market changes.

Equiw 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 po*f;olio of equity securities, ihe Group readily disposes or trades the securities for replacement with moie viable and less risky investments. Such investment securities are subject to price risk due to changes in market values of instruments arising either from factors specific to individual instruments or their issuers, or factors affecting all instruments traded in the market, The analysis below is performed for reasonably possible movements in the PSE index (pSEi) with all other variables held constan! showing the impact on income before tax (due to changes in fair value of equity securities and golfshares 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.

20t3

Equitysecurities Golf club

Impact on incomg before tax fncrease Decrease

rc"7, @

20o/o

Z3,S3S

e3,S3Si

20t2 Equity securities Golf club shares

l7%

Increase $20,161

19%

3.464

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Decrease

($20,161) 3.464

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-67 There is no other impact on the Group's equity other than those already affecting income before tax.

Foreign Exchanse 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 ofthe Group's foreign exchange risk, with all other variables held constant, showing the impact on income before tax (due to changes in fair value of currency sensitive to financial assets and liabilities). The Group used the year-average forecast from the Business Monitor International in the analysis. 2013

lmpact on income before tax

Increase/decrease in +0.89Vo -0.890A

$256,430 ($256,430)

2012 Impact on income before tax

lncrease/decrease in

+2.56% -2.56%

$81,617

($81,617)

There is no other impact on the Group's equity other than those already affecting income before tax. Interest Rate Risk The Group's exposure to market risk for changes in interest rates relates primarily to the Group's short-term investments amounting to $1.26 million and $21.42 million for

December3l,2013and2}lZ,respectively(seeNotes6andg). Interestrateofloanspayable 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-yeax Treasury Bill rate in performing the analysis below, 2013

Iucrease/decrease

in interest rate (in basis points) +148 -148

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

l,g4g,2gg

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-682012 Increase/decrease in interest rate (in basis points) +51 -51

Impact on income before tax $

109,606

(10e,606)

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

Credit Risk There are significant concentrations of credit risk within the Group since most of its financial assets are with consortium operator, although credit risk is immaterial. The gross maximum exposure of the Group's credit risk is equal to the carrying amounts of the financial assets. The table below shows the summary of maximum credit risk exposure on financial instruments as of December 31.2013 and20l2:

Financial assets at FVPL: Marketable equity securities Golf club shares Loans and receivables: Short-term investments Cash in bank Accounts receivable: Consortium operator - net Others

lnterest receivable

20t3

2012

$124,3t7 13,741

$125,531 17,296

914,606 2,566,635

21,4r6,729

2,622,051 40,098

2,021,687 1,969 z.J,t I I 63.125 $24,686,147

5,128

Restricted cash

$6,349,701

1,016,093

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

The Group determines the credit quality by class for loan-related consolidated statements financial position lines based on the following:

Cash in banks and short-term investmenls - based on the nature of the counterparties and the reputation of the financial institution. Receivables - based on the payment behavior ofthe counterparty. High grade pertains to receivables from consortium operator and interest receivable from short-term investments and standard grade pertains to other receivables. Both are neither past due nor impaired.

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_69_

The tables below shows the credit quality by class of asset for loan-related consolidated statements offinancial position lines, based on the Group's credit rating system as of December 3 l, 2013 and 2012: 20r3 Past due

Standard Cash in banks

Short-term investments Accounts receivable: Consortium operator

and im

Total

$2,566,635 914,606

2,561,629

Others Interest receivable Restricted cash

60,422

2,622,051

40,099 5,128

40,098 5,129

125

63.125

rst.22l

l1 2012

Neither past due nor impaired

Past due

Standard Cash in banks Short-term investments

Accounts receivable: Consortium operator Others Interest receivable

Restricted cash

Total

1,016,093 21,416,729

r,956,34r

6s,346

l,016,093

2t,416,729 2,021,687

1,969

23,7t7 63.t25

23,717

63.r25

The tables below show the aging analysis ofthe Group's receivables as of December 31, 2013 and 2012. 2013 Accounts receivable Consortium opemtor Others Interest receivable

$2,561,629 40,098 128

s2,622,051

s60,422

40,098 5,128

2012 Accounts receivable Consortium operator

1,9s6,341

Others

1,969

r,969

lnterest receivable

As of December impaired.

$2,02t,687

$65,346

23;n7

23,7t'l

, 201 3 wtd 2012, the Group has no past due receivables that are not

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

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-7025. Segment Information For management purposes, the Group is organized into business units based on their products and has three reporlable segments as follows:

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The oil segment is engaged in the oil and mineral exploration, development and production. The wind energy segment carries out the general business of generating, transmitting, and/or distributing power derived from wind energy sources. The geothermal energy segment will develop and operate geothermal steamfields and power plants.

No operating segments have been aggregated to form the above reportable operating segments. Management monitors the operating results of its business units separately for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on operating profit or loss and is measured consistently with operating profit or loss in the consolidated financial statements. 20t3

Geothermal

Wind

Oil Production Segmcnt revenue Net income (lo$) Oth€r comprehensive

Elimination

income

3,832,460 (r,167,006) (1,396,789) (t32,248)

1,136,417

(41"856)

Other Information: Segment ass€ts except dcferred

assets

Deferrcd tax a$ets -

S.gr.or

tar

net

li"biljti".

$58J02,6t3 $71.74s,029 $17,168,J10

5266:154 $$tilZe,grS $Si,0tj,iOs@

($31,863,88J)

S-

A?l.?)

5,252,

3266522

Cash flows from (used in):

Operating sctivities Investing activities

$s,802,532

($3,49 r ,720)

(24,s21J48)

(23,767,886)

($r7,r77,016) (1,r60,036)

$4,793,168 20,897,217

($10,073,036)

(285s2,0s3) 2

Geothermal

Oil Produotion Segment revenue Net income (loss) Other comorehensive income Segment assets except defered tax assets

tfi

assets - net

Elimination

I 1,990,120

(589,948)

3,375,880

(449228)

(zse)

7.103

.510

Consolidated I I,990,120 2,336,445

E4l.6l3

?t{ ol7 140

$1.049.515 Cash flows from (used in): Operating activities Investing activities

activities Provision for income tax

s4,659,270 (6,8s2,702) I

1,337954

($37r,833)

Q8,525,023)

(4,t25,793)

4.470.614

$205,305 7,314,354

$5,830,696

(32,189,!64)

723

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-11. -

Geodrennal

Illrmination

Oil Productron

sll5lrtl)

Segment revenIe Nei incornc (loss)

Consolidated

t3.5{4,412

(628,128)

3,669,299

2.',745

)01

lzil.lI

I15.391 Other lnformation deien ed tar rssets Deferred

la\

175

ass€ts - net

lirbrlilies

i.440

Cash ilows fron Grsed in): Operating aclivities hrvestjng activities

l'inancina islivities

161

s 16.017.184

56,212,222

$1,606,518

(6,045.82,1)

(r s,072,85r)

s r.337.61

187

t.24t.76

Provision lbr income lax

s60180 690

114

5?S.7r6

t9.281

17,-\01 .986

($503,680) (s,174,163)

$ 19,021

$7, t 54,08

lt.tl

(15.26r,122)

11,0t1.718

13.709.169

1.3,17.61I

s1.50r.181

i 1.19.t.78i

j.831.668

5.81I

Intercompany investmenls, revenues and expcnses are eliminated during consolidation.

26. Basic/Dilutcd Earnings Per Share The computation ofthc Group's earnings per share follows: 2013

Nct income attributablc to equity holders of the Parent Company Weighted average nltnber ofshares Basic/diluted share

qt tl I t tfl 273,824,220 $0.008

201

$2,559.582

273,824,220

$2,821.548

213,824.220

!i0.009

s0.010

27, Noncontrolling Inter.ests

Noncontrolling interests represent the 35% shareholdings of rrans-Asia and pNoc in MGI and 20% shareholdings of EEI-PC in PetroWind. MGI and PetroWind are entities incorporated and are operating in the Philippines. As ofDecenrber 31, 2013, 2012 and 201 1, thc accumulated balances ofand net loss attributable to noncontrolling interests arc as follows:

Accrrmulated balances of noncontrolling interests MGI

Net loss attributablc to noncontrolling interests MGI PWEI

2013

20t2

20tI

0,1{{

$5,807,3 79

s3,851,627

s9.676.476

$5,807,3 79

$3,85 1,627

s 7,2 2

$408,452 279

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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 20L3 Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities

*117,642,802

2012

20rl

P680,221,340

F692,298,275 487,327,555 (120,649,61,s) s82.85

3,067,480,467 1,803,687,842 (122,513,042) (t73,362,669) 2,197

P875 13

P71t.918.142

P476.117.318

Statements of Income Revenue

Net loss Statements of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financing activities Effect of foreign exchange rate

*4,482..999 54 P49

P10,763,172 3s.675.709 ?24.912.537

F5,161,507 32.781.722

?27.620.215

(P242,869,564) (Fs5,707,650) (967,s20,634)

(r,r's,376,139)

p70,018,432 (661,233,989)

813,000,000 1,300,713,361 877,543,0t2 849

59.929

351

Net increase (decrease) in

PWEI* 2013 Statements of Financial Position Current assets Noncurrent assets

Cunent liabilities

F71 I ,008,607

51,178,534

229.457.r80 P532.729.96r

Statements of Income Revenue

F75,035

61.095.074

Net loss Statements of Cash Flows Net cash provided by (used in): Operating activities Investing activities Financins activities Net increase in cash

F61.020.039

("762,573,620) (st,499,798) 816.987.064 13.646

+ PII/EI vas incorporated on March 6, 2013

There were no dividends paid to noncontrolling interests.

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The increase in noncontrolling interests from stock issuances follows:

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As of December 3 1, 201 l, MGI issued 3,240,625 common shares with Fl00 par varue and collected subscription receivable amounting to P24.23 million, which increased the noncontrolling interests by F121.90 million. As of December3r,20l2, MGI issued r,740,u5 common shares with pl00 parvarue and collected subscription receivable amounting to F86,71 million, which increased the noncontrolling interests by P91 .25 million. As of December 31,2013, MGI and PetroWind issued 2,130,000 and 5,937,500 common shares, respectively with Pl00 par value. Such stock issuances increased the noncontrollins interests by F806.75 million.

28. Notes to the Consolidated Staternents of Cash Flows In2013, the noncash investing activity ofthe Group pertains to the additions to Property, plant and equipment, which is due to the increase in ARo estimate amounting to $0.47 million.

ln 2012, t}le noncash investing activity ofthe Group pertains to the reduction in Property, plant and equipment, which is due to the decrease in ARo estimate amounting to $0.27 million. In 201I, noncash investing activities pertain to the following items:

r r r

Transfer from Deferred oil exploration costs to Wells, platforms and other facilities amounting to $1.18 million. Transfer from Deferred geothermal costs to FCRS and production wells - Geothermal amounting to $1.28 million, Increase in Wells, platforms and other facilities due to change in ARO estimate amounting to s9.067.

29. Events After the Reporting Period PetroGreen On_February 14,2014 CapAsiaAsean Wind Holdings Cooperatief U.A (CapAsia) purchased 50% of PetroGreen's 80% investment in PetroWind.

MGI The MGPP started the commercial operation on February 8,2014, This 20-MW Maibarara geothermal project situated in Sto. Tomas, Batangas, is the newest geothermal power facility in the country and the first under President Benigno S. Aquino's administration.

PetroWind on November 4, 2013, the P2.4 bitlion omnibus Loan and security Agreement between Petrowind and Development Bank of the Philippines was signed, The first drawdown materialized on January 10, 2014 amounting to F99l million.

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As of February 14,2014 equity holders of PetroWind are: 40%o,petroGreen; 40% CapAsia (beneficial owner) and 20% EEIPC.

30. Renewable Energy Act of 2008 On January 30,2009, Republic Act No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energt 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 ofthe 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 fiscai and non-fiscal incentives; (c) encourage the development and utilization of renewable enerry 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 ofthe RE component, for both power and nqn-power applications, as duly certified by the DOE, in consultation with the Board of Investments (BOI), shall be entitled to the following incentives, among others:

i. ii. iii.

iv. v' vi.

Income Tax Holiday (ITH) - Forthe 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 ofa certification ofan RE developer, the importation of machinery and equipment, and materials and parts thereof, including control and communication equipment, shall not be subject to tariffduties; Special Realty Tax Rates on Equipment and Machinery - Any law to the contrary notwithstanding, realty and other taxes on civil works, equipment, machinery, and other improvements of a registered RE developer actually and exclusively used for RE facilities shall not exceed one and a half percent (1.5%) of their original cost less accumulated normal depreciation or net book value; NOLCO - the NOLCO of the RE developer during the first three (3) years from the start of commercial operation which had not been previously offset as deduction from gross income shall be carried over as deduction from gross income for the next seven (7) coniecutive taxable years immediately following the year of such loss; Corporate Tax Rate - Afler seven (7) years ofITH, 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 1,997, as amended by Republic Act No. 9332; Accelerated Depreciation - Il and only if, an RE project fails to receive an ITH before full operation, it may apply for accelerated depreciation in irc 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 developmen!

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viii.

ix' x.

conshuction and installation of the plant facilities, as well as the whole process of exploration and development ofRE sources up to its conversion into power shalt be subject to zero percent (0%) VAT; cash Incentive of RE Developers for Missionary Elechification - An RE developer, established after the effectivity ofthe Act, shall be entitled to a cash generation-based incentive per kilowatt-hour rate generated, equivalent to fifty percent (50%) ofthe universal charge for power needed to service missionary areas where it operates the same; Tax Exemption of Carbon Credits - All proceeds from the sale bf carbon emission credits shall be exempt from any and all taxes; and Tax Credit on Domestic Capital Equipment and Services - A tax credit equivalent to one hundred percent (100%) ofthe value ofthe 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 manufacfurer for purposes set forth in the Act.

RE developers and local manufacturers, fabricators and suppliers of locally-produced RE, 9!{p1ent shall register with the DoE, through the Renewable Enerry 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. alitertifications required to qualiff RE developers to avail of the incentives provided for under the Act shall be issued by the DOE through the REMB.

31. Electric Power Industry Reform Act (EPIRA) After emerging from the crippling power crisis that occurred in the early 1990s, the Philippine Government embarked on an industry privatization and restructuring program envisioned io ensure the adequate supply of electricity to energize its developing econolny. This restructuring scheme is embodied in RA No. 9136, the EPIRA. Approved on June g, 2001, rhe EpIRA seeki to ensure qualify, reliable, secure and afflordable elechic 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 Govemment 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 ofthe 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 powir industry and called for the privatization of NPC. The restructuring of the electricity industry calls for the separation of the different components of the power sector, namely: generation, transmission, distribution, and supply. On the other hand, the privatization of ttre 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 athacting more private-sector investrnents in the power industry

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

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-76Specifically, 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 elechicilv 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 behaviois; and Accelerate and ensure the total electrification of the country.

t . e r

32. Commitments

Certified Emission Reductions purchase Agreement Ort January 31, 201l, 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'i generated by the Maibarara Geothermal Power Project (the "Projecf') in favor of Endesa from ttre start;f its commercial operations in October 2013 until 2020. This will provide MGI with a secondary revenue stream apad from electricity sales. It should be noted thal under the RE Act oi2oos, ull proceeds from the sale ofcarbon 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 Desigr Document (pDD), validation conducted bya Designated operational rntity (,obe" or..Vdidutor'), applicaiion with the Designated National Authority (Deparhnent oi dnvironment and Natural Resources for the Philippines), and-registration or acceptance ofthe Project as a CDM project Activity by the cDM Executive Board ("8B"). The pDD which was prepared by Endesa presenrs information on the essential technical and organizational aspects of the iroject aciivity and is a key input in the validation, registration and verification of tire Project. MdI contracted the Spanish Association for Standardization and Certification as the Validator to C'AENbR) perfgrm an independent evaluation ofthe project activity against the riquirements ofthe CDM on the basis of the PDD. The Secretariat of the United Nati,ons framework convention on climate change (uNFCcc) has confirmed that the MGpp has been registered effective December 26,2012.

commercial operations, MGI shall collect and archive all relevant data necessary for calculating green house gas (GHG) emission reductions, which will then be subjected to periodic independent verification. The EB will issue the CERs equal to the verified GHG Upon_

emission reductions.

The slowdown in world market conditions for carbon credits severelv affected Endesa. necessitating its closure and eventual liquidation. For this reason, eff:ectiv e June1S,Ztjp., MGI and Endesa decided to mutually terminate the ERpA.

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on July 31,2013, MGI entered into

a memorandum of agreement (MoA) with Enel rrade S.P.A (Enel), a company registered and domiciled in Rome, Italy, with the intention of establishing an arrangement for the discussion, negotiation, and cooperation ofa mutually beneficial CER purchase agreement. To date, MGI has not yet closed a CER purchase agreement with Enel. The MOA is valid for one year from the date of its signing.

b. Electricitv

Suppllz Agreement

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

33. Wind Energy Service Contract (WESC)

on september 14,2009, the PetroEnergy was awarded by the DoE with two (2) wESCs (the Wind Energr Projects) covering the areas of Sual, Pangasinan and Nabas, Aklan. These service contracts were awarded pursuant to Republic Act (RA) No. 9513, otherwise known as the "Renewable Energy Act of2008". During the two-year pre-development stage ofthe contracts, PetroEnergy should conduct technical feasibility studies in the contract areas in order to confirm the wind power potential in the two (2) areas. The expected total expenditures for each contract amount to about $420,000. As part of the technical study, PetroEnergy committed to install a 60m wind mast to measure the wind data characteristics and other relevant paxameters, The data from the technical feasibility study will determine whether the wind resource is viable for commercial development and operations.

As stated, PetroEnergy created PetroGreen to carry out its renewable energy projects, which includes the wind energ' projects.

on November 30,20a9, PetroEnergy purchased a 60m wind mast from NRG systems. power Dimension, Inc. (PDI) was hired to erect the mast at the site. Tower lifting began on February 2010 and the mast was fully raised on February 1 8, 201 0.

17,

In September 2010, the Company's Senior Wind Specialist (consultant), the contracted Danish engineering consultant, recommended the installation of a second mast in Nabas, Aklan to increase confidence in the wind data. lnstallation of the second mast was completed on the first week ofJanuary 201 1. Following one year of wind data recording in Nabas (Aklan) and Sual (Pangasinan) wind service cQntract areas in February 201l, initial micrositing and annual enerry production analyses were prepared by the consultant. The consultant reported in May 201 1 that the Sual site has only a fair to modest wind resource potential and unlikely to be commercially viable. This result prompted PGEC to relinquish the sual wind service contract. The DoE formally approved the relinquishment on October 28, 201 l.

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-78 In contrast to Sual, the consultant reported in July 2011 that the Nabas project site can sustain a 50 MW wind farm. This encouraging result led PetroEnergy to start obtaining the first set of development permits and conducting initial engineering studies. SMEC Philippines (SMEC) was engaged in September 201 I to undertake the environmental baseljne survey ofNabas needed to obtain the project's ECC. ln November 2011, PetroEnerry applied with the National Commission on lndigenous Peoples (NCIP) for a Certificate of Non-Overlap (CNO) attesting that the project site does not overlap with any existing indigenous peoples' ancestral domain claims. PetroEnergy also filed with the National Grid Corporation of the Philippines (NGCP) for the conduct of the grid impact study (GIS) which will determine the feasibility of interconnecting the Nabas wind project to the Visayas Grid. A detailed topographic survey of the likely development areas ofthe project, including an inventory of existing private and public lots was likewise undertaken. On November 8, 201l, the DOE approved the Deed of Assignment and Assumption transferring the WESC from the Company to PGEC. The DOE also granted the one-year extension of the piedevelopment phase from September 13,2011 to September 13,2OlZ.

On December 26,2011, PetroGreen obtained the CNO from the NCIP which certified that the project area is free of any ancestral domain claims from indigenous communities. Research costs relating to the wind Energy power project amounted to $165,079, $147,g13, and $114,476 as ofDecember3I,2012,2011 and 2010 respectively. These are included as "research costs" under "General and administrative expenses" in the consolidated statement of income. In 2012, PetroGreen moved to further advance the project towards eventual commerciality. The key activities centered on securing critical government permits, completing technical feasibility studies, and initiating request for engineering, procurement, and construction bids for the wind

farm.

on June 20l2,the critical ECC for the 50 MW Nabas wind power project was released by the DENR Region 6 office in June 2012. This gave petroGreen clearanci to proceed to site development, from road rehabilitation, access road construction, wind furbine installation, transmission line erection, and operation and maintenance ofthe facility subject to compliance to standard environmental regulations. Another government approval sought was DOE's Declaration of Commerciality for the project which was applied on september 10,2012. As part of this application process, the DoE's Renewable-Energy Management Bureau (REMB) conducted a site visii on November 27-Ig,Z0lz to meet with local municipal and barangay officials and DENR staffwho assured the DOE team of the strong support for the project.

With more than two years of wind data, the consultant completed its technical feasibility study in August 2012, concluding the viability of the site to generate 50MW of wind power witli a higir capacity factor. At the same time, NGCP completed its own system impact study that shessJd that the four wind turbine models from different suppliers are all compliant with NG|P standards; further, NGCP recommended the location and type of transmission connection for Nabas. Using these two major technical studies, PetroGreen completed in August its own conceptual engine,ering,design of the project, recommending a phased development with an initial phase of about 36 MW capacity and a second 14 MW phase.

Given the positive results of various technical studies, PetroGreen moved to obtain costing and commitrnent from several likely construction partners for various project components. It started

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by signing a Heads of Agreement (HoA) with EEI corporation for the balance of plant construction contract.

All

the foregoing activities were prompted not only by the positive results of the various technical feasibility studies but also the Energy Regulatory Commission's (ERC) decision to grant a feedin-tariffrate of P8.53/kWh to qualified wind farm developers.

In May 2013, after several months of review, the DOE conferred the Confirmation of Commerciality for the 50 MW NWPP in Nabas, Aklan, In confirming the project commercial, the DOE also effectively converted the Nabas service contract from exploration stage to development phase with a contract life of 25 years, or until 2034. The confirmation of commerciality on Nabas brought to four (4) the number ofPhilippine wind projects officially endorsed for feed-in-tariff (FiT) pre-qualification and competition. As part ofthe venture into wind enerry productiorg PetroEnerry incorporated a new subsidiary PetroWind - on March 6,2013 to handle the Nabas project developmen! Ilom securing financing through project construction and eventual operations and maintenance. DoE approved the transfer of the Nabas seryice conhact from PetroGreen to petrowind in July 2013.

Subsequently, on July 15, 2013 EEIPC, a subsidiary of EEI Corporation, subscrib ed a 20Vo stake in PetroWind ( EEIPC formally became a stockholder of PertroWind upon the SEC's approval of PetroWind's increase in authorized capital stock on August 23,2013), ieaving PetroGreen with an 80% interest in PetroWind as of December 31, 2013. On November 4,2013, Development Bank of the Philippines (DBP) granted to PetroWind a F2.8 Billion loan for the project payable in 15 years; such loan was the firsi ever extended by DBp for a wind power proj ect attesting to its confidence to petrowind to tum NWpp into reality. Substantial progress was likewise achieved in the technical design and construction aspects ofthe project. Even as PetroWind awaited DOE's decision on ou. confi.mation of commerciality, PetroWind initiated the rehabilitation of the existing access road to the wind farm as part of corporate social responsibility efforts. The rehabilitation was started in May,20l3 with the goal of making the 5-km long barangay road accessible only by motorcycles into a road wide enou!.r to accommodate the entry of the initial wave of heavy equipment. While road rehabilitation efforts were starting, PetroWind also signed in late 2013 key construction or supply contracts covering the switchyard and transmission line with Cendaur Engineering, civil *o.t i on the wind farm including intemal roads, turbine foundations, and control roombuildings with EEI Corporation, and wind turbine supply, installation, and maintenance and operation with Gu111"sa Eolica of S.L. Unipersonal Spain. All these have set the stage for an expedited program to finish the installation of the wind turbines by late2014 ro early 2015.

34. MGI Contracts and Agreements

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 systJm to be established by the Fuji Electric. Further, Fuji Electric shall provide site techniJaL services to the power plant in instances wherein the power plant encounters technical problems during emergency situation.

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-80For the remote monitoring services, the fee amounts to Y3 million. For the technical advisory services, the fee is based on a certain rate per hour and per day. This agreement shall be for period ofone (1) year commencing on the expiry ofthe warranty period of the EPC contract for the construction ofpower plant, renewable every year thereafter upon agreement of both parties.

Interconnection A greement

MGI signed an Interconnection Agreement (ICA) with MERALCO for the physical interconnection of the generation and connection facilities of MGI's 20 Mw power plant to MERALCO's distribution system. The power facility being constructed in Brgy. San Rafael, Sto. Tomas, Batangas will be connected to MERALCo's existing 1 l5 kV line in calamba, Laguna.

MGI and MERALCO, along with rrans-Asia oil and Enerry Development corporation $R+!F-AS4), also signed on December 6,2012 a Memorandum of Agreement (MOA). The MoA defined the respective rights and obligations among the partiei: MGI as a G_eneration Facility to be interconnected with MERALCO's distribution system under the ICA, and TRANS-ASIA as the sole off-taker of MGI's electricity output under the Electricity Sales Agreement (ESA), which shall sell said output through MERALCo's distribution system.

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

35. PetroWind Contracts and Agreements

Wind Turbine Generators Supply, Services and Maintenance Agreements On August 30,2013, PetroWind entered into a Supply Agreement with Gamesa Eolica S.L. Unipersonal for the supply and purchase of wind turbine generators (WTG). The price of the equipment amounted to $36,028,966 and the price to transport the equipment amounted to $2,233,40 5 that adds up to a total of $38,262,37 l.

The services Agreement with Gamesa Eolica s.L. unipersonal philippines Branch was entered by Petrowind also on August 30,2013 which covers inland transportation, installation, start up, commissioning and testing of the equipment and the, execution of certain electrical works and associated civil works. The contract price for the services is $12,835,816.94. The Maintenance Agreement with Gamesa Eolica S.L. Unipersonal Philippines Branch which is for a term of 5 years covers the full scope operation and maintenance s-ervices of certain wind turbine generators and related equipment. The annual price is $65,s00 per wrG plus inspection and repair fee of$2,500 per wrG per year and $9,g00 per year foi the weather/wind production forecasting.

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Civil Works Contract Agreement on August r,2013, Petrowind signed a contract Agreement with EEI corporation for the civil works to include construction of i 8 units wTG foundations, roadways and temporary landing pad intended for the 36MW Nabas Wind Power Project (NWPP). The contractor shall complete the works within I 1 calendar months from the commencement of works. The contract price amounted to $14,794,459 (p656,s00,000). Transmission Line and Switchyard Contract Agreement PWEI signed a contract Agreement with cendaur Engineering on July 5, 2013 for the design selection, supply, delivery, erection, installarion, and tisting oittt" lo traw Nwpp 69kv Switchyard. Total contract price is $ 1 ,252,750 (for foreignlomponent, excluding duties and taxes) plus $861,662 (P38,253,500) (for local component), exclusive oflocal Vaiue Added Tax. Contract Agreement with the same contractor was entered into on August 5, ZOl4 1 for the 69kV transmission line in the amount of $696,291 (p30,911,g54).

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36. Reclassifrcation of Accounts Previously, the short'term investments account was shown under advances, prepaid expenses and other current assets account. In 2013, the short-term investment account was presented separately in the consolidated statement of financial position. Accordingly, the December 3l,20lz presentation was revised to conform with the December lt ioil presentation. ,

similarly, the input VAT account was shown previously under advances, prepaid expenses and other current assets account. In 20 I 3, the inp;t VAT was presented undei advances and other noncurrent assets account. Accordingly, the December 31,2012 and January l, 2012 presentation was revised to conform with the December 31,2013 presentation. Management believes that the new presentation is more appropriate.

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Buildino a better workin(j world

Co. Tel: (632) 891 0307 Avenue Fax: (632) 819 0872 City ey.com/ph Philippines Sycip Gorres Velayo & 6760 Ayala 1 226 Nlakati

BOtuPRC Reg. No. 0001, December 28, 2012, valid until December 31, 2015 SEC Accr€ditation No. 0012-FR-3 (croup A), November '15. 2012. valid until November 16, 201 5

II\DEPENDENT AUDITORS' REPORT ON SI]PPLEMENTARY SCHEDULES

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

We have audited in accordance with Philippine Standards on Auditing the consolidated financial statements of PetroEnergy Resources Corporation and Subsidiaries (collectively referred to as'the Group"), as at December 3l, 2013 and 2012 and for each ofthe three years in the period ended December 31,2013, included in this Form 17-A, and have issued our report thereon dated February 18,2014. Our audis were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The schedules listed in the Index to the Consolidated Financial Statements and Supplementary Schedules are the responsibility of the Group's management. These schedules are presented for purposes of complying with the Securities Regulation Code Rule 68, as Amended (2011) and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audit ofthe basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the information required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.

SYCIP GORRES VELAYO & CO.

Michael C. Sabado

Partner

CPA Certificate No. 89336 SEC Accreditation No. 0664-AR-l (Group A), March 11,2011, valid until March 10,2014 Tax Identification No. 160-302-865 BIR Accreditation No. 08-001 998-73-2012. April 11,2012, valid until April 10, 2015

PTRNo. 4225212, January 2,z|l4,Makati Cify Februarv 18.2014

A.nember finn o! Emsl & YounE Grob.l L,nit6d

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PETROENERGY RESOI]RCES CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS A}{D SUPPLEMENTARY SCIIEDULES SEC FORM 17.A CONSOLIDATED FINAIICIAL STATEMENTS statement of Management's Responsibility for consolidated Financial Statements Report of Independent Auditors' Report Consolidated Statements of Financial Position as at December 31,2013 and20lZ Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 201 1

Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 201 1 Consolidated Statements ofChanges in Equity for the years ended December 31, 2013, 2012 and 201 1 Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and, 201 1 Notes to Consolidated Financial Statements

SUPPLEMENTARY SCHEDULES Report of Independent Auditors' on Supplementary Schedules Schedules Required under SRC Rule 68-E Financial Assets

A. B.

D. E. F. G. H.

Amounts Receivable from Directors, Officers, Employees, Related parties, and Principal Stockholders (Other than Related Parties) Amounts Receivable from Related Parties which are Eliminated durins the Consolidation of Financial Statements Intangible Assets - Other Assets Long-term Debt lndebtedness to Related Parties Guarantees of Securities of Other Issuers Capital Stock

Additional Components Schedule of Financial Soundness Indicators Schedule of Retained Eamings Available for Dividend Declaration Schedule of all the effective standards and interpretations under PFRS as of December 31, 2013

Map of the relationships of the Companies within the Group

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION AND DISCLOSURES REQUIRED ON SRC RULE 68 AS AMENDED DECEMBER 31,2013

Philippine Securities and Exchange Commission (SEC) issued the amended Securities Regulation Code Rule SRC Rule 68 which consolidates the two separate rules and labeled in ihe amendment as "Part I" and "Part II", respectively. It also prescribed the additional information and schedule requirements for issuers of securities to the public. Below are the additional information and schedules required by SRC Rule 68, as Amended (2011) that are relevant to the Company. This information is presented for purposes of filing with the SEC and is not required part ofthe basic financial statements. Schedule A. Financial Assets

The Group is not required to disclose the financial assets in equity securities as the total financial assets at fair value through profit and loss securities amounting to $0.14 million do not constitute 5% or more ofthe total current assets of the group as at December 31,2013.

and Principal Stockholders (Other than Related Parties) As of Decernber 31, 2013 there are no amounts receivable from directors, officers, employees, related parties and principal stockholders that aggregates each to more than P100,000 or loZ oftotal assets

which-ever is less. The $ I ,747 advances to Engr. Jose V. Villena (Head Purchasing -PetroGreen) as of December 3 l, 2013 do not constitute the Pl00,000 or 1% oftotal assets. This is demandable and classified under current assets. There were no amounts written off during the year

The following is the schedule of receivables from related parties, which are eliminated in the consolidated financial statements as at December 31, 2073: Balance at beginning of

of Corporation Inc. Inc.

Nme=and D=esiBndign Petrocreen Energy Maibarara Geothermal, PetroWind Energy

NRpc;='=

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Balance at

$2,607,5'17 $l 163,349 153,325 3,617,037

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Not Cunent end of period

10,024

3.617.037

(st,tz6)

'Dillerence is ' due to' foreign exchange differences.

Transactions with other related parties outside the Group,

PetroEnergy has engaged House of Investrnents, Inc. (HI) to perform intemal audit services to PetroEnergy. HI charges retainer fee of F56,000 ($ 1,261) per month totaling to approximately $ I 5,837 per annum. Also in 201 2, PetroEnergy engaged HI to perform prociss review of its hiring, purchasing and disbursement processes. The engagement fee amounted to P600,000

($14,141).

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PetroWind has engaged EEI Corporation for the civil works on the construction of wind farm including internal roads, turbine foundations and control room buildings. The Contract is approximately $14.79 million (P656.8 million). As of December 31,2013, PetroWind paid down-payment amounting to $4.4 million (F197 million).

On September 2,2011 , Maibarara engaged EEI Corporation for the Engineering, Procurement and Constnrction of the MGPP. Contact price is approximately $37 million (FI.6 billion). Total payment made amounted to $35,9 million (Pl.5 billion). As of December 31, 2013 rhe contract is 96.43% complete.

Schedule D. Intangible Asset The Group has an insignificant amount of intangible assets as of December 31,2013 amounting to $46,539. This mainly pertains to the Groups purchased accounting software. Schedule E. Lons-term Debt Below is the schedule oflong-term debt ofthe Group as ofDecember

3l,Z0l3:

Amount

Title oflssue and type ofobligation PetroEnergy Loans payable - various lenders Less Unamortized defened financine

shown

Noncurrent portion shown under caption portion of long-term "Loans payable" in the Amount authorized debt" in the Statement Statement of by indenture ofFinancial Financial position under caption

"Current

Position

$10,257,518

$2,2s2,s03

$8,005,012

cost

Loans payable Less Unamortized deferred fi nancing

$50,456,132

l.l

cost

total

$50,456,132

Loans

Payable

9,273,492

gS9,+52,632 @

Please refer to the Consolidated Audited Financial Statement,

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949.273.492

Notel6forfurther details of the loans.

schedule F. Indebtedness to Related Parties (Long Term Loans from Related companies) The Group has no outstanding long-term indebtedness to related parties as of Decernber 31, 2013. Schedule G. Gu4rantees of Securities of Other Issuers The Group does not have guarantees of securities of other issuers as of December

2013.

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Schedule H. Capital Stock

of Number of issued Shares and reserved for outstanding options, as shown waJTants, Number of Number of under related conversion shares held shares balance sheet and other by related Titl"=of isru. , ,alt Common Shares 330,000,000 273,824,220 -M Number

Directors, Officers and

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PETROENERGY RESOURCES CORPORATION RECONCILIATION OF RETAINED EARNINGS AVAILABLE FOR DIVIDEND DECLARATION DECEMBER 31,2013

Unappropriated Retained Earnings, Beginning Prior Year Adjustments:

$9,180,459

Unrealized foreign exchange gain - net Unrealized actuarial sains Unrealized MTM gain on FVPL DTA that reduced the amount oftax

(48,605)

(5,779) (40,522)

Unappropriated Retained Earnings, as adiusted Jan Net income based on the face of audited financial statements

Less:

3,832,460

Non-actual/unrealized income net of tax Equity in net income of an associate/W

Unrealized foreign exchange gain

net (except

those attributable to cash and cash equivalents) Unrealized actuarial gain Fair value adjustment (marked-to-market gains) Fair value adjustrnent of investment properties resulting to gain

(7,4s6)

Adjustment due to deviation from PFRS/GAAP gain

Other unrealized gains or adjustments to the retained earnings as a result of certain

Add:

transactions accounted for under PFRS

3,551

Non-actual/unrealized losses net of tax Depreciation on revaluation increment Adjustment due to deviation from PFRS/GAAP loss

Loss on fair value adjustment of investment properties Movement in deferred tax assets

ir""ll",tctr,"Y.ga fl"t Less: Dividend declarations during the year

j,gZS"Sss (31s,248)

ins the

Total Parent Company Unappropriated Retained Earnings Available For Dividend

December 31.2013

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES SCHEDULE OF ALL THE EFFECTIVE STANDARDS AND INTERPRETATIONS UNDER PFRS AS OF DECEMBER 31. 2013 Below is the list of all effective Philippine Financial Reporting standards (pFRs), philippine Accounting Standards (PAS) and Philippine lnterpretations of International Financial Reporting Interpretations Committee QFRIC) as of December 3l,Z0I3:

Framework for the Preparation and Presentation of Financial Statements Conceptual Framework Phase A: Objectives and qualitative characteristics

{

PFRSs Practice Statement Management Commentary

Philippine Financial Reporting Standards PFRS I (Revised)

First-time Adoption of Philippine Financial Reporting

Standards

Amendments to PFRS I and PAS 27: Cost of an Investment in a Subsidiary, Jointly Controlled Entity or

Associate

Amendments to PFRS l: Additional Exemptions for Firsttime Adopters

{

Amendment to PFRS l: Limited Exemption fiom Comparative PFRS 7 Disclosures for First-time Adopters Amendments to PFRS l: Severe Hyperinflation and Removal of Fixed Date for First-time Adopters Amendments to PFRS PF'RS 2

{ {

Govemment Loans

Share-based Parrment

Amendments to PFRS 2: Vestins Conditions and Cancellations Amendments to PFRS 2: Group Cash-settled Share-based

{

Payment Trans actions

PFRS 3 @evised)

Business Combinations

{

PFRS 4

Insurance Contracts

{

Amendments to PAS 39 and PFRS 4: Financial Guarantee Conhacts

{

Non-current Assets Held for Sale and Discontinued

PFRS 5

Operations

PFRS 6

Exploration for and Evaluation of Mineral Resources

PFRS 7

Financial Instruments: Disclosuros Amendments to PAS 39 and PFRS 7: Reclassification Financial Assets

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{

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PFRS 7

(cont.)

Amendments to PAS 39 and PFRS 7: Reclassification Financial Assets - Effective Date and Transition Amendments to PFRS 7: Improving Disclosures about Financial Instruments Amendments to PFRS 7: Disclosures - Transfers Financial Assets

,f ,/

Amendments to PFRS 7: Disclosures - Offsetting Financial Assets and Financial Liabilities Amendments to PFRS 7: Mandatory Effective Date PFRS 9 and Transition Disclosures PFRS 8

Operating Segments

PFRS 9

Financial lnstnrments

J {

Amendments to PFRS 9: Mandatory Effective Date PFRS 9 and Transition Disclosures

New Hedge Accounting Requirements PFRS IO

Consolidated Financial Statements

Amendments to PFRS 10: Investment Entities PFRS

PFRS 12

Joint Arransements

{

Disclosure of Interests in Other Entities

{

Amendments to PFRS 12: lnvestment Entities

PFRS 13

{

Fair Value Measurement

Philippine Accounting Standards PAS T

(Revised)

Presentation of Financial Statements

{

Amendment to PAS I : Capital Disclosures Amendments to PAS 32 and PAS l: Puttable Financial Instruments and Obligations Arising on Liquidation

{

Amendments to PAS I : Presentation of Items of Other Comprehensive Income or OCI

{

PAS 2

Inventories

PAS 7

Statement of Cash Flows

{ {

PAS 8

Accounting Policies, Changes in Accounting Estimates and Errors

{

PAS TO

Events after tlre Reporting Date

{

PAS

Construction Contracts

PAS 12

Income Taxes

Amendment to PAS l2 - Deferred Tax: Recoverv Underlying Assets

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PAS 16

Property, Plant and Equipment

PAS 17

Leases

PAS 18

Revenue

PAS 19 (Revised)

Employee Benefits

PAS 20

{ { { {

Amendments to PAS 19: Defined Benefit Plans Employee Contributions

Accounting for Govemment Grants and Disclosure

J of

{

Government Assistance PAS 21

The Effects of Changes in Foreign Exchange Rates

Amendment: Net Investrnent in a Foreign Operation PAS 23

Borrowine Costs

@evised) PAS 24

{

Related Party Disclosures

(Revised) PAS 26

Accounting and Reporting by Retirement Benefit plans

PAS 27

Separate Financial Statements

(Amended) PAS 28

,f {

Amendments to PAS 27: Investment Entities Investments in Associates and Joint Ventures

(Amended) PAS 29

Financial Reporting in Hyperinflationary Economies

PAS 32

Financial lnstruments: Disclosure and presentation

{ { { {

Amendments to PAS 32 and pAS l: puftable Financial Instruments and Obligations Arising on Liquidation

{

Amendment to PAS 32: Classification of Riehts Issues

{

Amendments to PAS 32: Offsetting Financial Assets and Financial Liabilities

{

PAS 33

Eamings per Share

{

PAS 34

Interim Financial Reporting

PAS 36

Impairment of Assets

Amendments to PAS 36: Impairment of Assets Recoverable Amount Disclosures for Non-Financial

Assets PAS 37

Provisions, Contingent Liabilities and Contingent Assets

PAS 38

Intangible Assets

PAS 39

Financial Instruments: Recognition and Measurement

{ {

(cont.)

Amendments to PAS 39: Transition and Initial Recognition of Financial Assets and Financial Liabilities

J riltililtilill ]ililflilrilrfi ililililtililil||ililil]

PAS 39

Amendments to PAS 39: Cash Flow Hedge Accounting Forecast Intragroup Transactions

{

Amendments to PAS 39: The Fair Vaiue Option Amendments to PAS 39 and pFRS 4: Financial Guarantee

{

Contracts

Amendments to PAS 39 and PFRS 7: Reciassification Financial Assets

Amendments to PAS 39 and PFRS 7: Reclassification Financial Assets - Effective Date and Transition

{

Amendments to Philippine Interpretation IFRIC 9 and PAS 39: Embedded Derivatives

{

Amendment to PAS 39: Eligible Hedged Items

{

Amendments to PAS 39: Financial Insauments: Recognition and Measurement - Novation of Derivatives and Continuation of Hedge Accounting PAS 40

Investrnent Property

PAS 4I

Agriculture

./ ./

Philippine Interpretations

IFRIC I

Changes in Existing Decommissioning, Restoration and

Similar Liabilities

IFRIC

Members' Share in Co-operative Entities and Similar Instruments

IFRIC

Determining Whether

IFRIC

Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds

IFRIC

Liabilities arisingfrom Participating in a SpeciJic Market - Waste Electrical and Elecnonic Equipment

{

IFRIC 7

Applying the Restatement Approach under pAS 2g Financial Reporting in Hyper$ationary Economies

IFRIC 8

Scope ofPFRS 2

IFRIC 9

Reassessment of Embedded Derivatives

Arrangement Contains a Lease

{

Amendments to Philippine Interpretation IFRIC 9 and PAS 39: Embedded Derivatives

IFRIC IO

Interim Financial Reporting and Impairment

IFRIC 1I

PFRS 2 - Group and Treasury Share Transactions

IFRIC

Service Concession Anangements

IFRIC I3

Customer Loyalry Programmes

IFRIC

The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction

{ { { { { tiltilutilil1ilililililtililfi tffi uil ililil]ilililNl

-5-

IFRIC

Amendments to Philippine Interpretations IFRIC - 14, Prepayments of a Minimum Funding Requirement

IFRIC

Agreenrerrts for the Construction ofReal Estate

IFRIC

Hedges of a Net Investment in a Foreign Operation

IFRIC

Distributions of Non-cash Assets to Owners

(cont.)

IFRIC I8

Transfers of Assets from Customers

IFRIC I9

Extinguishing Financial Liabilities with Equirv Instruments

IFRIC 20

{

Stripping Costs in the Production phase of a Surface

Mine

IFRIC

slc-10

Levies

Govemment Assistance - No Specific Relation to

{

Operating Activities

sIc-r2

Consolidation - Special Purpose Entities Amendment to SIC

{

12: Scope of SIC 12

slc-13

Jointly Controlled Entities - Non-Monetary Contributions by Venturers

slc-15

Operating Leases - lncentives

slc-21

Income Taxes - Recovery ofRevalued Non_Depreciable

{

Assets

sIc-25

Income Taxes - Changes in the Tax Status ofan Entitv or its Shareholders

{

slc-27

Evaluating the Substance ofTransactions Involving the Legal Form of a Lease

{

src-29

Service Concession Arrangements: Disclosures.

sIC-3I

Revenue - Barter Transactions Involving Advertising Services

src-32

Intangible Assets - Web Site Costs

{

standards tagged as "Not applicable" have^been adopted by the Group but have no significant covered transactions for the year ended December 3 l, 2013.

as'Not adopted" are standards issued but not yet effective as ofDecember 31, 2013. adopt the standards and Interpretations when these become effective.

Standards tagged

The Group

will

ililililtilutililtililtfl iltil|lltflililililililIililil

PETROENERGY RESOURCES CORPOBATION AND SUBSIDIARIES MAP OT'RELATIONSHIPS OFTHE COMPAI\IES WM Group Structure Below is a map showing the relationship between and among the Group and its subsidiaries as of December 31. 2013:

PETROENERGY RESOURCES CORPORATION GROUPSTRUCTURE PetroEnergy Resources Corporation

Petrocreen Energy Corporation

PETROEIVERGY RESOURCES CORPORATION REPORT ON SRO PROCEEDS

DECEMBER3T,2OI3

on February 23, 2010, the Bon a l: I Stock fughts offering (SRo). The sRo was undertaken during the :pproved period June 28 to July 4, 2010. The proceeds ofthe sRo imounted to $14.g million.

{s a9^cto-s9{ in the Prospectus the company expects to raise gross proceeds ofapproximately Php 684'56 Mitlion and after deducting listing, iegistration fees related to the offer

usD 14.g2 million or of$14.75 million or php 6g1.656

million.

As of December 31, 2013, remaining proceeds amounted to $3.2

ion or php 144

ion.

Thc tabletelow shows the gross and_ net proceeds; each expenditure item where the proceeds were used and the balance ofthe proceeds as of December j l. 20 t 3.

Procee& from the SRO Cross hoceeds Lrss: Listing and registration Net Procee&

14817328

24,333

,uro -ror,

("t

14,79299s ,Ora

O,lil*-

kss: hpendhrres DOE awards service contract

LGJ & stakeholder coordination Geoscientific studies & resource assessment

Iand rights acquisition Obtain DENR Clearances & Other permits Establish logistic station

land & water supply prrparations Well work-over & drilling preparations Work-over ofthree (3) wells Drilling oftwo (2) new wells Flow test & bore output nrasurernents Elgineering & design ofsteany'brine lines Financing, Gid Inpact Study& power Contract

9,017

7,891

4,797

12,689

t04,900

1,8u,62

69,636

1,779,762 71,886

7r,886

t2,829

422,4y2

12,829

4n,500

144,789 95,49 1,825,8il 362,597

24f,,218 2,188,408

3,593,337 132,%9 357,763 272,n8

67,439

3,7%276 630,591

15,055

84494 12,45

12,405

Construction of fluid collection and reiniection system Power Plant

& administrative expenses Incorporation of MGI koperty & equipment C-eneral

Total

t,25925t

6n,549

r,87%810

53,298

!1092?990 217,497 t0,n0,5% 1,826,600

Effect ofForex Changes

Renaining Procee& as ofDecember 31,2013_In USD Remaining Procee6 as ofDecember 31,2013_In php

53,298

1,3NA77

t2,5t7,t% 1,050,105

$ P

3t4sB06 144,101978

APR

Republic of the Philippines)

)S.S.

CERTIFIC TION I, the undersigned, CARLOTA R. VIRAY, CHIEF X.INANCIAL OFFICER OF PETROENERGY REsouRcEs coRpoRATIoN, with office address at 7e Floor JMT Building, ADB Avenue, Pasig city, after having been swom and in accordance with law hereby states that:

"RESOLVED, that the information contained in the hard copy of the General Form for consofidated Financial statements for the year ended December 31,2013 and the one contained in the compact disc are one and the same."

IN WITNESS WHEREOF, I hereto affixed my signature 2014 at Pasig City.

this

c*toffiinnv AFFIANT

Pasig City, affiant exhibited to me her Tax Identification Number

2014 at

(TIN) 100-732-809.

Control l{o.: Form

Type: GtrS (nv fr06)

SPECIAL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY-HELD AND INVESTMENT COMPAiIIES l{AfitE 0F PETRoE{ERGY RES0URCES CoRPoRATIoN AND SUBStD|AR|ES 7th Floor JMT Buildino. ADB

GURRENT ADDRESS:

TEL.

N0.:

637.2917

COMPANY tf

{tesr n"

FA)(NO.:

OILEXPLORATION

PSIC:

batd

1193

tfon.

Table l.Consolidated Statements of Financial position

FINANCIAL DATA A,

ASSETS (A"1 +

+ A.3 +

+ A.5 + A.6 + A.7 + A"8 + A.9 +

2013

20't2

2011

( in $'000 )

( ln $'000 )

( in $'000 )

A.l0)

r15.519

91,446

60,563

23,383

29,944 21.622

31.585

2,567

21,618

21,899

2,607

1,982

2,076

-15

1.3 Others, specify (A. 1.2. 1.3.1 +A .1.2.1.3.2)

101

A.1.2.1.3.1 Accounts receivable - 0PMC

(65)

(61

A.1 Cunent Assets (A.1,1 +A.1.2 +A.1.3 +A.1.4 *A.1.S) A.1.1 Cash and cash equivatents (A.1.1.1 + A.1.1.2 + A.1.1,3) A.1.1.1 0n hand A.1.1.2 In domestic banks/entities

2.572

21,904

A.1.'1.3 In foreign banks/entities

4.1.2 Trade and other Receivables (A,1.2.1 + A.1.2.2\ A.1.2.1 Due from domestic entities (A.1.2.1.1 + A.1.2.1.2 + A.1,2.1 .1+ A.1,2.1.1 Duq fle1n sustomers (trade)

A,1.2.1.2 Due from related oarlies A. 1.2.

4.1.2.1.3.2 Others A.1.2.1.4 Allowance for doubful accounts (neoalive enbv) A.1.2.2 Due from foreign entities, specify + A.1.3.2.2 + A.1 .3.2.3 + A.1.3.2.4) A.1.2.2.1 Accounts receivable - Vaalco

-ou

2,622 2,682

o(7

2,036

z,vzz

2,097

4.1.2.2.2 A, t.z,z,J Ar1.2.2.4 Allowance for doubtful accounts (neoatlve entrv) A.1.3 Inventories (A.1.3.1 +A.1.3,2 +A.1.3.3 +A.1.3.4 +A.1.3.5 +A.1.3.6) A.1.3.1 Rav materials and supplies

€0

(65)

(61

218

415

447

A.1.3.2 Goods in process (including unfinished goods, growing crops,

A.1.3.4 Merchandise/Goods in transi

,3.5 Unbilled Services (in case of service providers)

A.1 ,3,6 Others, specify (A,1.3.6. 1+A.1.3.6.2)

218

415

A.1.3.6.1 Crude oil inventory

218

415

447

138

143

109

138

143

109

138

143

109

A.1.4 Financial Assets other than Cash/Receivables/Equity investments (A.1.4.1 + 4.1.4.2 + A.1.4.3 + A.1.4.4+A.1.4.5+A I 4 6t A.1.4.1 Financial Assets at Fair Value through Prolit or Loss - issued by domestic entities

.1.4.1.1 + A,1.4.1.2 + A.1.4,'1.3 + A..|.4.1 .4 +

A.1.4.1.1 National Govemment A.1.4.1.2 Public Financial Institutions A.1.4.1.3 Public Non-FinanciaUnstitutions A.'1.4.1,4 Private Financial Institutions

4,1.4.1.5 Private Non-Financial Institutions A.1.4.2 Held to Maturity Investments - issued by domestic entities (4.1.4.2.1 + A.1.4.2.2 + A.1.4.2,3 + A.1.4,2.4 + A.1.4.2.5\

41.4.2.1 NationalGovemment A.1.4.2.2 A.1.4.2.3 A.1.4.2.4 A.1.4.2.5

Public Financial Institutions Public Non-Financial lnslitutions Private FinaleieLlnstitutions Private Non-Financial lnstitutions

This general fom is applicable to companios engagod in Agriolture, FisfEry, Fo|estry, Mining, and Quarrying, Manufaturiru, Eleclicity, Gas and Wat€|, Construclion, WDIosde 3nd Retail Trad€, Transportatjon, Storage and Communications, Hotgls and RestauBnts, R6al Estate, Community, Soial and persooal S€rvic€s, olh€r loms o, prcduction, and gen€ral business op€ralions. This brm is also applicable to oth€r companios that do not hav6 industy-specifc Special Foflns. Special tonns shall b€ used by publidy-held companies and those engaged in non-bank fnancial intermediatir activilies, cr€dit granling, and activiti€s auxiliary lo

finamial inteflEdiation, whhh requir€ secondary licens€ lron SEC. Domestic corporations are thos€ which are incoqoraled under Philippine laws or branches/subsidiaies of fueign corporalions that are lbansed h do fusinsss in the Philippines wheE lhs centet of economic intsrest or activity is within tp Philippines. 0n th8 olh6r hand, foreign corporations are those that are inmrporated aboad, including branches of Philippine corporations opersting abroad.

Financia||nslilutionsarecorporationsprincipa||y€nga9€dinfnancia|inlemediation,facilitatin9fnancia|intermediation.oraUxlli8rfnancia|sgvi' institutions r€f6r to cofporations thal ars Fimarily €ngagBd in the prcduction of market gmds and non-fnancial seryices.

Page

Co/,ttol No.:

FwmType:

EFSW

SPECIAL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY.HELD AND INVESTMENT COMPANIES NAME

PETROENERGY RESOURCES CORPORATION AND SUBSIDTARIES

CURREMADDRESS: zttrrtoor.tNr TEL. NO.: 637.2917

COMPANffi lf ftese are based on consolidated financiar

sat@.

Table l.Consolidated Statements of Financiat position

FINANCIAL DATA

(

2013

2012

in $'000 I

( In $'000 )

2011 ( in g'000

A.1.4.3 Loans and Receivables - issued by domestic entities: ( 4.1.4.3.1 + A 1.4.9.2 + A.1.4.3.3 + A.,1.4.3.4 + A. 1.4 3.5t A.1.4.3.1 NationalGovemment A.1.4.3.2 PublicFinanciallnstitutions A.1.4.3.3 PublicNon-Financiallnstitutions A.1.4.3.4 PrivateFinancial lnstitutions A,1.4.3.5 PrivateNon-Financial Institutions A.1.4.4 Availablejor-sale financial assets - issued by domestic entities: 4.1.4.4.1 + A.1.4.4.2 + A-1.4.4.3 + A. i.4.4.4 + A..t.4.4.5t A.1.4.4.1 NationalGovemment 4.1.4.4.2 PublicFinancial Institutions A.1.4.4.3 publicNon-Financialhstitutions

A.1.4.4.4 PrivateFinancial Institutions A.,|.4.4.5 Private Non-Financial Institutions A.1.4.5 Financial Assels issued bv foreion entlties:

A.1.4.5.1 Financial Assets at fair value throuoh oroft or loss A.1.4.5.2 Held-to-maturitv investments

4.1.4.5.3

Loans and Receivables

A.1.4.5.4 Availabl+for-salefinancialassets A.1.4.6 Allowance for decline in market value (neoative entrv)

A.1.5 Other Cunent Assets (state seoaralelv material ilems) fA.1.5.1 +A 152+A 153) A.1.5.1 Advances lo Conhaclor A.1.5.2 Short-term investrnents

17.U8

578?

7.M9

14.697

5 991

915

3.818 815

1.450

il2

796

607

196

75.072

51.456

911

817 688

21.298 724

A.1.5.3 Creditable input VAT

A.1.5.4 Deffened Financinq Cost A.1.5.5 Others - Advances to Emoloyees, Supplies Inventory, preoaid Exoenses and A.2 Propedv. plant. and eouipment (A.2.1 + A.2.2 + A.2.3 + A.2.4 + A.2.5 + A.2.6 + A.2.7+A2.8) A.2.2 Buildinq and improvements includino leasehold improvement A.2.3 Machinerv and equioment (on futnd and in hansit) A.2.4 Transportation/motor vehicles. automotive eouipment, autos and trucks. and deliverv A.2.5 Land and land improvements A.2.5 Others, soecifo (A.2.5.1 + A.2.5.2 + A.2.5.3 + 4.2.5.4 + A.2.S.51 A.2.5.1 Wdls, platforms and other facilities A.2.5.2 FCRS and production Wells- GeothermaL A.2.5.3 Construction in Proaess A.2.6 Appraisal increase, specifo (A.2.6.1 + A.2.6.2 + A.2.6.3 + A.2.6.4) A.2.7 Accumulated Deoreciation/Deoletion (neoative entrv) A.2.8 lmoairment Loss or Reversal (if loss. neoalive entry) A.3 Investments accounted for usino the eouitv method (A.3.1 + A.3.2 + A.3_3 l A.3.1 Eouiiv in domestic subsidiaries/affiliates A.3.? Eouitu in foreion branches/subsidiariesiaffi liates A.3.3 Others. soecifv 1A.3.1.1 + A.3,2.1 + A.3.3.1t A.3.3.4)

961 716

862

363

229 30.205 21.541

46.843

606 919 61.334 22.027 12.751 26.556

-14 65?

f12 9081

11.091)

1.059

86.077

II.YI I '16.25t

868

5.224 3.440

A.3.3.1

A.3.3.2 A.3.3.3 A.3.3.4

A.4 Inveslment Prooertv A.5 Eiolooical A.6 Inlanoihle Assets {4.6.1 + A.5.2} A.6.1 Maior item/s- snecifv (4.6.i

Assets

A.6.1.1 Software Licenses

4.6.1.2 A.6.1.3

A.6.1.4

A.6.2 Others. soecifv {4.6.2.1 + A.6.2.2 + A.6.2.3 + A.6.2.4) A.6.2.1 Software Licenses - Accumulated AmortizatiOn A.6.2.2 A.6.2.3

A.7 Assets Classified as Held for Sale A.8 Assets included in Disoosal Grouos Classified as Held for Sab-^^

Contol No,,

furmTpe:@ SPECIAL FORM FORFINANCIALSTATEMENTSOF PUBLICLY.HELD AND INVESTMENTCOMPANIES NAME OF

GORPORATION:

CURRENT ADDRESS:

TEL.

NO.:

ADB Avenue, ortigas Center,

ff17.2917

COIiIPANY TYPE

PETROENERGY REsoURcEs coRPoRATIoN AND SUBSIDIARIES

7th Floor JMT

F$e:

olL EXPLoMTION

these are based on co

Table LGonsolidated Statements of Financial Position

FINANCIAL DATA A.9 Long{erm receivables (!et of cunent

portionxAgl + A92 + Ag3)

A.9.1. From domestic entlties, specify (A.9.1.1 + A.9.1 ,2 + A.9.1 A,9.1.1

2013

2012

2011

( In S'000 )

{ in $000 }

( in S000 )

.i + e.Sl.4)

4.9.1.2 A.9.1.3 A.9.1.4 A.9.3 Allowance for doubtful accounts, net of cunent portion (neoative entrv) A.10 Oher Assets (A.10.1 + A.10.2 + A.10.3 + A.10.4+A.10.5) A.10.1 Defened Income Tax

17.032

10,015

7,648

267

140

16,766

9,875

7,566

11,397

6,643

s,832

5,368

3,232

1.734

64,564

41.316

17,502

A.10.2 A.'10.3

A.10.4 0thers, speci! (A.1Q.4.1 + A.10.4.2 + A.10.4.3 a A.10.4.4) A.10.4.1 Detqred oil exploration costs A.10.4.2 Advances and Other Non-Curent Assets A.10.4.3

A.'10.5 Allowance for write-down of defened chageshad accounls (neqative entrv) LIABILITIES (8.1 + 8.2 + 8.3 + q.4 + 8.5) B.'l Cunentl-iabilities (8.1.1 + 8.1.2 + 8.1.3 + 8.1.4 + 8.1.5 + B.1.6 + 8.1.7) 8.1.1 Trade and Other Payables to Domestic Entities B.1. 1.1 Loans/Notes Payables

5,077

3,699

4,979

4,058

2,996

2.741

4.058

2,996

RAA

471

357

175

125

1,883

3,226

2.517

118

236

2,238

8.1.1.2 Trade Pavables 8.1.

1.4

1. 1.4. 1 + 8.1.1.4.2 + 8.1.1.4.1 Accrued exoenses 8.1.1 .4.2 Withholding taxes payable

Others, specify (8.

B. 1.

1.4.3)

8.1.1.4.3 Accounts payable

8..|..|.4.5 Others B.1.3 Provisions

8.1.4 Financial Liabilities (excluding Trade and Other Payables and provisions) 8.1.4.1 8.1.4.4

8.1.5 Liabilities for Cunent Tax

243

722

B.1.6 Defened Tax Liabilities B.1.7 Others, specify (lf material, state separately; indicate if the item is payable to 8.1.7.1 Dividends dqclared and not paid at balance sheet date

1.204

944 |

460

235

260

225

9691

684 |

235

8.1.7.2 8.1.7.3 8.1.7.4 8.1.7.5

8.1.7.2 Accrued Inlerest payable 8. 1.7.6 Any other current liability in excess of 570 of Total Cunent Liabiilities. B.'1.7.6.1

8.1.7.6.2 8.1.7.6.3

Page 3

Contot No.:

FomType:

@S(@

SPECIAL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY.HELD AND INVESTMENT COMPANIES NAME OF

CORPOMTION:

CURRENT ADDRESS:

TEL.

NO.:

PETROENERGY RESOURCES CORPoRATIoN AND SUBSIDIARIES

7th Floor JMT

637.2917

COMPANYTffi ll

these are based on c

Table l.Consolidated Statements of Financial Position 2013

FlNANCIAL DATA

(

B.2 Longterm Debt - Non-cunent Interest-bearinq Liabilities (8.2.1 + 8.2.2 8.2.1 Domestic Public Financial lnstitutions

8.2,3 + 8.2.4 + 8,2,5\

B.2.2 Domestic Public Non-Financial lnstitutions B.2.3 Domestic Private Financial lnstitutions

in f000 ) 57,215

2012

2011

( in $000 )

( In 5'000 )

38,943

13.295

57.215

38,943

13,295

444

zvo

508

296

508

328

238

474

8.2.4 Domestic Private Non-Financial Institutions 8.2.5 Foreign Financial Institutions 8.3 Indebtedness to Affliates and Related Parties (Non-Cunent)

8.4 Liabilities Included in the Disposal GrouDs Classified as Held for Sale B.5 Other Liabilities (8.5.1 + 8.5.2)

8.5.1 Defened Income Tax 8.5.2 others, specify G.5.2.1 +8.5.2.2+8.5.2.3 + 8.5.2.4) 8.5.2.1 Asset retirement obliqation 8.5.2.2 Accrued retirement liability

116

8.5.2.3

8.5.2.4 EQUITY (C.3 + C.4 + C.5 + C.6 + C.7 + C.8 + C,9+C.10)

50,954

c.1 Authorized Capital Stock (no. of shares, par value and total value; show details)

47,130

43,061

330,000

330.000

6,322 6,322

25,245

2s,245

25,245

9,676

5,807

1.169

772

3,852 (69

(6)

(13)

1.121

778

(56)

{C1l+C12+C131 C.l.1 Common shares

330,000,000 shares, $0.02rf5 par value

C.1.2 Prefened Shares C.1.3 Ohers C.2 Subssibed Capital Stock (no. of shares, Dar value and lotal value) (C.2.1 + C.2.2 + C.2.31 C.2.1 Common shares C.2.2 Prefened Shares

C.3 Paid-up Caoital Stock (C.3.1 + C.3.2) C.3.1 Common shares C.3.2 Prefened Shares C.4 Additional Paid-in Capital / Capital in excess of par value / Paid-in Surplus C.5 Minority lnlerest C.6 Others, specifo (C.6.1 + C.6.2 + C.6.3 + C.6.4 + C.6.5) C.6.1 Remeasurements of net accrued retirement liabilitv C.6.2 Cumulative translation adiustment

c.6.3 c.6.4 c.6.5 C.7 Appraisal Sumlus/Revaluation Increment in Property/Revaluation Sumlus C.8 Retained Eaminqs (C.8.1 + C.8.2)

10.880

8,984

C.8.1 Aporopriated

3.150

r,uco

7.712 z,uco

C.8.2 Unappropriated

7.730

6,928

5,656

91,446

60,563

C.9 Head / Home Office Account (for Foreion Branches only) C.10 Cost of Stocks Held in Treasurv (neqative entrv) D. TOTAL LIABILITIES AND EQUITY (B + C)

115,519

Page 4

Contol

No.:

FomTWe:@

PECIAL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY.HELD AND INVESTMENT COMPANTES AIIIE OF PETRoENERGY REsoURcEscoRPoRATIoNAND SUBSIDhRIES

CORPORATION:

URRENT ADDRESS:

OMPANYTYPE:

OILEXPLORATION

PSIC:

these are based on consolidated linancial statements, ptease

so indicate in the caption.

Table 2: Gonsolidated Statements of Income

FINANCIAL DATA A.

(A.I + A.2 + A.3} A.1 Net Sales or Revenue / Receipts from Operations (manufacturing, miningJjtilities, trade,

REVENUE / INCOME

2013

2012

2011

( in $'000 )

( In $000 )

( In $'000 )

13,717

11,990

13,5{4

13,717

11,990

13,544

services, etc.) (from Plimary Activity)

A.2 Share in the Profit or Loss of Associates and Joint Ventures accounted for usinq ttre A.3 Other Revenue (A.3.1 + A.3.2 + A.3.3 + A.9,4 1 4.3.51 A.3.1 Rental Income fiom Land and Buildinos A.3.2 Receipts from Sale of Merchandise (trading) (fom Secondary-{ctiviM A.3.3 Sale of Real Estate or other Property and Equipment A.3.4 Royalties, Franchise Fees, Copyrights (books, films, records, etc.) A.3.5 others, specify (A.3.5.1 + A.3.5.2 + A.3.5,3 + A.3.5.4 + A.3.5.5 + A.3.5.6 + A.3.5.7) A.3.5.1 Rental Income, Equipment A.3.5.2 A.3.5.3 A.3.5.4 A.3.5.5

4.3.5.6 A.3.5.7 /1.4 Ofter lnmme (non-operatinq) (A.4.1 + A.4.2 + A.4.3 + A.4.4) 4.4.1 Interest Income

(171

903

479

202

506

s25

(219)

397

(46)

(80)

A.4.2 Dividend Income A.4.3 Gain / (Loss) from selling of Assets, speclfu {A43.1 +A.4.3.2 + 4,4.3.3 +A.4.3.4 +A.4.3.5 + A.4.3.6 + A.4.3.7) A.4.3.1

4.4.3.2 A.4.3.4 A.4.4 Gain / (Loss) on Foreiqn Exchanqe (A.4.4.1 + A.4.4.2 + A.4.4.3 + A.4.4.4) A.4.4.1 Net unrealized gain on financial assets at FVPL

A.4.4.2 Miscellaneous A.4.4.3 Net gain on foreign exchange

A.4.4,4 Accretion expense COST OF GOODS SOLD (8.1 + 8.2 + 8.3) B.'l Cost of Goods Manufactured (8.1.1 + B.1.2 + 8.1.3 + 8.1,4 + B.'1.5) B.1.1 Dlrect Material Used

8.1.2 Direct Labor B.'1.3 Other Manufacturino Cost / Overhead

8.1.4 Goods in Process, Beqinninq Q.1.5 Goods in Process, End (nesalwecnln,) 8.2 Finished Goods, Beginning 8.3 Finished Goods, End (nesaliye ldtn )

9OST OF SALES (C.1 + 6.219.31 C.1 Purchases C.2 Merchandise Inventory, Beginning C.3 Merchandise Inventory, End (nggallyeentry) COST OF SERVICES, SPECIFY (0,1 + D.2 + D.3 + D.4 + 0.5 + D.6l 0.1

0.2 0.3 D.4

-T I

u.o

Page 5

I (189)

384

(44

(32)

(62)

Contrcl No.: Form fype:

GFFS (rev

M6)

SPEChL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY.HELD AND INVESTMENT COMPANIES NAME oF

cORPoMTloN:

PETROENERGY REsouRcEs coRpoRATroN AND suBsrDrARrEs

CURRENT

ADDRESS:

7th Floor

TEL.

NO.:

COMPANY TYPE

JilT Bullding, ADB Avenuo, Ortigas Center, paslg City

ffi7-2917

OtL

FAX NO.:

ExPLOMTtoN

fl93

PSIC:

these are based on consolidated linancial statements, please

so lndicate in the caption,

Table 2: Consolidated Statements of Income

FINANCIAL DATA E.

OTHER DTRECT COSTS, SpECtFy (E.1 + E.1 Oil production operating expenses

+E.r

+TIlEs + est

E.2 Depletion, depreciation and amortization

(A. B.C - q.

GROSS PROFTT

OPERATING EXPENSES (G.1 + Q.! + 6.3 G.1 Selling or Marketing Expenses G.2 Admin istrative Expenses

19.4;

20'13

2012

2011

( In $'000 )

( in $'000 )

6,613

6,648

7,287

5.164

5,026

5,432

1.449

1,622

1.855

7,087

6,245

6,736

3,801

3,009

2,693

3,684

3,009

2,693

3,236 (eoo)l

4,043 (1,338)

G.3 General Exoenses G.4 Oher Expenses, specifo (G.4.1 + G.4.2 + c.4.3 + c.4.4 + O.+S + C"+S) G.4.1 Education-related expenditures

117

G.4.2 Miscellaneous exoense G.4.3 Research costs

G.4.4 Interest Exoense

117

G.4.5 G.4.6

J. L.

FINANCECOSTS NET |NCoME (LOSSI BEFORE TAX ( F. G- H) INCOME TAX EXPENSE (neqaliyeqty)

3,287 (1.764'l

Amount of (i) PoshTa( Profit or Loss of Disconiinued Operations; and (ii) Post.Tax Gain or Loss Recognized on theMeasurement of Fair Value

less Cost to Sell or on the Disposal of the Assets or Disposal Group(s) constitutinq the Discontinued Opetation (if any) 1.1 NCI share in nel loss 1.2

M. Profit or Loss Aftributable to Minority Interest

(6881

Profit or Loss Attributable to Equig Holders of the parent

Page 6

2,211

(223t1 2,559

(n0l 2,925

Con'ot lto,:

tom

Type:

GFFS

(ny 20$)

SPECIAL FORM FOR FINANCIAL STATEMENTS OF PUBLICLY.HELD AND INVESTMENT COMPANTES I.|AME OF

CORPORATION:

CURRENT

ADDRESS:

TEL,

PETRoENERGY REsoURcEs coRPoRATIoN AND SUBSIDIARIES 7th FloorJllT Buitding, ADB Avenue, Orligas Center, pasig Ciiy

NO.: 637.A17 : OtL EXPLORATTON

FAX No.:

COMPANY TYPE

lf these are bxad on consoridated financral sfahmonfs, p/eas

psn: o

so indicate in the capton.

Consolidated Statements of Cash Flows

FINANCIAL DATA

Decrease in Long-Term Receivables

OF FOREIGN EXCHANGE RATE CHANGES IN CASH AND CASH EQUIVALENTS

IilcREASE tN CASH AND CASH EQUTVALENTS (A + B + C) Cash and Cash Equivalents

I193

SPECIAL FORM FOR FII{ANCIAL STATEMENTS OF PUBLICLY,HELD AND II.IVESTI/IENI COMPANIES

l{aIE of conPoRAllolt cuRnErar

lto

@IPAIIY fl

AIID SUBSIDLqRIES

tooREss:

IYPE

thB..n h..dd

Ad.r.dnMd.r,bt@.nE p!.,s. 6tn trat lnth. qdn

Statsmsnts of

fIIIAIiCIAT

ATA

Pag€