Form F1. Pacific Rubiales Energy Corp. Statement of Reserves Data. And Other Oil and Gas Information

Transcription

1 Form F1 Pacific Rubiales Energy Corp. Statement of Reserves Data And Other Oil and Gas Information As of December 31, 2014

2 Presentation of Oil and Gas Reserves and Production Information All oil and natural gas reserves information contained in this Statement of Reserves Data and Other Oil and Gas Information Statement ) has been prepared and presented in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ). Certain terms used in this Statement but not otherwise defined are defined in NI and, unless the context requires otherwise, shall have the same meanings in this Statement as in NI The reserves of Pacific Rubiales or the Company ) were evaluated by the following independent qualified reserves evaluators effective December 31, 2014: (a) RPS Energy Canada Ltd. ( RPS ), independent qualified evaluators of Calgary, Alberta; (b) Petrotech Engineering Ltd. ( Petrotech ), independent qualified evaluators of Burnaby, British Columbia; (c) Netherland, Sewell and Associates Inc. ( NSAI ), independent qualified evaluators of Dallas, Texas; and (d) DeGolyer and MacNaughton ( D&M ) independent qualified evaluators of Dallas, Texas as follows: 1. RPS prepared: (i) the report dated March 9, 2015, effective December 31, 2014 e report dated March 9, 2015, effective December 31, 2014 ication Report, Year End 2014, Quifa Field, South West (collectively, the RPS Report ). 2. Petrotech prepared: (i) the report dated March 13, 2015, effec of the Reserve of Pacific Rubiales Energy Corp. in the Guama Block in the Lower Magdalena Basin in Colombia for Yearluation of the Reserve of Pacific Rubiales Energy Corp. in the La Creciente Block in the Lower Magdalena Basin in Colombia for Year- the report dated March 13, 2015, ific Rubiales Energy Corp. in Lote 126 in the Ucayali Basin in Offshore Peru for Year- the report dated March 13, 2015, Corp. in Quifa Norte Block in the Eastern Llanos Basin in Colombia for Year- the report dated Pacific Rubiales Energy Corp. in CPE-6 Block in the Eastern Llanos Basin in Colombia for Year-Ending the report dated Heavy Oil Reserve of Pacific Rubiales Energy Corp. in Rio Ariari Block in the Eastern Llanos Basin in Colombia for Year- he report dated March 13, 2015, effective December 31, 2014, the Z-1 Block in the Tumbles- Progreso Basin in offshore Peru for Year- the report dated March 13, 2015, effective Block in the Quifa Block, Eastern Llanos Basin in Colombia for Year- the report dated March 13, 2015, e Energy Corp. in the Sabanero Block in the Eastern Llanos Basin in Colombia for Year- (collectively, the Petrotech Report ). 3. NSAI prepared the report dated March 3, 2015, effective December 31, 2014 Estimates of Reserves and Future Revenue to the Pacific Stratus Energy S.A. Interest in Certain Oil Properties Located in Albacora and Corvina Fields Offshore Peru (the NSAI Report ). 1. D&M prepared: (i Report as of December 31, 2014 on Certain Properties in Colombia for Pacific Stratus Energy, Executive Summary NI ; and (ii) the report dated February 27, 2015, effective December 31, 2014 on Los Angeles Field in Peru for Pacific Rubiales Energy Peru Ltd., Executive Summary NI 51- the D&M Report Reserves Reports Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this Statement. There is no assurance that forecast prices and costs assumed in the Reserves Reports, and presented in this Statement, will be attained and variances from such forecast prices and costs could be material. The 2

3 estimated future net revenue from the production of the disclosed oil and natural gas reserves in this Statement does not represent the fair market value of these reserves. In certain instances, the numbers in the tables below may not total due to computer-generated rounding. Currency All dollar amounts in this Statement are in United States dollars, unless otherwise noted. Boe Conversion Disclosure provided herein that is expressed in barrels of oil equivalent (boe) is derived by converting natural gas to oil in the ratio of five thousand seven hundred cubic feet (Mcf) of natural gas to one barrel (bbl) of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 5.7 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia. The Company has expressed boe using the Peruvian conversion standard of Mcf: 1 bbl required by the Perupetro S.A. for properties in Peru. Abbreviations and Conversion Oil and Natural Gas Liquids Natural Gas Bbl barrel Mcf thousand cubic feet Mbbl thousand barrels MMcf million cubic feet bbl/d barrel per day Mcf/d thousand cubic feet per day Btu British Thermal Units Other API American Petroleum Institute API an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28 API or higher is generally referred to as light crude oil M$ thousands of dollars The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units): To convert from To Multiply by Mcf 1,000 cubic metres of gas ,000 cubic metres of gas Mcf Bbl cubic metres of oil cubic metres of oil Bbl Feet Metres Metres Feet Miles Kilometres kilometres Miles Acres Hectares Hectares Acres

4 Forward Looking Statements This Statement - - forward-looking information applicable securities legislation which involves known and unknown risks, uncertainties, and other factors which may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking information. When used in this Statement -looking information reflects current expectations regarding future events and operating performance and speaks only as of the date of this Statement. Forward-looking information involves significant risks and uncertainties, should not be read as a guarantee of future performance or results, and will not necessarily be an accurate indication of whether or not such results will be achieved and accordingly undue reliance should not be placed on such statements. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information, including, but not limited to, the March 17, 2015 AIF. Although the forward-looking information contained in this Statement is based upon what management of the Company believes are reasonable assumptions, the Company cannot assure readers that actual results will be consistent with the forward-looking information. This forward-looking information is made as of the date of the Statement, and the Company assumes no obligation to update or revise it to reflect new events or circumstances. In particular, this Statement contains, or incorporates by reference, forward-looking information pertaining to the following: drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells; plans for facilities construction and completion and the timing and method of funding thereof; oil and natural gas properties; drilling, completion and facilities costs; results of various projects of the Company; timing of development of undeveloped reserves; natural gas reserves; projections of market prices and costs; supply and demand for oil and natural gas; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions, exploration and development; treatment under governmental regulatory regimes and tax laws; and capital expenditure programs and the timing and method of financing thereof. With respect to forward-looking information contained in this Statement, the Company has made certain assumptions regarding, among other things: future prices for oil and natural gas; future currency and interest rates; and capital markets to meet its future obligations; the regulatory framework representing taxes and environmental matters in the countries in which the Company conducts its business; and -efficient manner to meet the Co Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by the Company and described in the forward-looking information contained in this Statement. The material risk factors include, but are not limited to: 4

5 volatility in market prices for oil and natural gas; the potential for the return of conditions persisting during the recent global financial crisis and economic downturn; liabilities inherent in oil and gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; fluctuations in foreign exchange or interest rates and stock market volatility; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; and Information relating to reserves is deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions about the profitable production of the resources and reserves described. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking information contained in this Statement is expressly qualified by this cautionary statement. The Company does not undertake any obligation to publicly update or revise any forward-looking information, other than as required by applicable securities laws. For further information regarding forward-looking information or the risks associated with the Company, please see the AIF. Part 1 Date of Statement Item 1.1 Relevant Dates 1. Date of Statement: March 18, Effective Date: December 31, Preparation Date: March18,

6 Part 2 Disclosure of Reserves Data Item 2.1 Reserves Data (Forecast Prices and Costs) Item Breakdown of Reserves (Forecast Case) Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids Total Gross Net Gross Net Gross (MMcf) Net (MMcf) Gross Net Gross (MBOE) Net (MBOE) Developed Producing Colombia 41,259 37,977 54,456 44, , , , ,188 Peru 3,695 3, ,050 29, ,858 8,858 Total Developed Producing 44,954 41,672 54,456 44, , , , ,047 Developed Non-Producing Colombia 9,735 8,962 4,093 3, ,828 12,396 Peru Total Developed Non-Producing 10,043 9,271 4,093 3, ,136 12,704 Undeveloped Colombia 11,773 10, ,584 89, , ,597 5,741 5, , ,902 Peru 11,367 11, ,367 11,367 Total Undeveloped 23,140 22, ,584 89, , ,597 5,741 5, , ,270 Colombia 62,767 57, , , , ,995 5,903 5, , ,486 Peru 15,370 15, ,050 29, ,534 20,534 Total 78,137 73, , , , ,045 5,903 5, , ,020 Colombia 20,383 18, ,786 95, , ,366 5,674 5, , ,805 Peru 32,368 32, , , ,062 55,061 Total 52,752 51, ,786 95, , ,039 5,674 5, , ,866 Plus Colombia 83,150 76, , , , ,361 11,577 11, , ,291 Peru 47,738 47, , , ,595 75,595 Total Plus 130, , , , , ,084 11,577 11, , ,886 The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia and the Peruvian conversion standard of Mcf: 1 bbl required by Petropetro S.A. for those properties located in Peru. 6

7 Item Net Present Value of Future Net Revenue Based on Forecast Prices and Costs Before Deducting Future Income Taxes After Deducting Future Income Taxes (M$US) 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% Developed Producing Colombia 4,008,978 3,342,834 2,914,668 2,614,130 2,388,396 3,363,521 2,774,129 2,398,327 2,137,449 1,943,958 Peru 154, , , , , , , ,946 93,822 84,510 Total Developed Producing 4,163,277 3,479,498 3,036,747 2,724,242 2,488,668 3,497,381 2,892,313 2,503,273 2,231,271 2,028,468 Developed Non-Producing Colombia 349, , , , , , , , , ,664 Peru 21,376 18,508 16,331 14,639 13,295 18,545 16,005 14,039 12,474 11,205 Total Developed Non-Producing 371, , , , , , , , , ,869 Undeveloped Colombia 2,675,001 1,954,033 1,442,317 1,070, ,274 2,200,607 1,586,412 1,157, , ,574 Peru 418, , , , , , , , , ,990 Total Undeveloped 3,093,463 2,267,557 1,675,071 1,240, ,236 2,569,780 1,863,032 1,362, , ,564 Colombia 7,033,689 5,570,350 4,575,799 3,863,411 3,331,772 5,856,372 4,586,507 3,735,304 3,133,741 2,690,195 Peru 594, , , , , , , , , ,706 Total 7,627,826 6,039,046 4,946,963 4,158,038 3,567,302 6,377,950 4,997,315 4,058,804 3,388,030 2,890,901 Colombia 3,629,468 2,253,779 1,442, , ,308 3,072,023 1,894,162 1,208, , ,004 Peru 1,730,451 1,147, , , ,554 1,511,954 1,001, , , ,355 Total 5,359,919 3,401,666 2,236,116 1,508,023 1,036,862 4,583,977 2,895,749 1,896,716 1,275, ,358 Plus Colombia 10,663,157 7,824,129 6,018,464 4,805,649 3,953,080 8,928,395 6,480,668 4,943,636 3,923,268 3,213,199 Peru 2,324,588 1,616,583 1,164, , ,084 2,033,532 1,412,396 1,011, , ,061 Total Plus 12,987,745 9,440,712 7,183,079 5,666,061 4,604,163 10,961,927 7,893,065 5,955,520 4,663,491 3,766,260 Item (a) (b) Additional Information Concerning Future Net Revenue (Forecast Case) Revenue Oil Royalties Gas & Overriding Royalties Prod. & Min. Tax Operating Costs Capital Development Costs Abandonment and Reclamation Costs Future Net Revenue Before Income Taxes Future Income Taxes Future Net Revenue After Income Taxes (M$US) Colombia 17,489,888 33,826 1,343, ,298,646 2,515, ,327 7,033,689 1,129,700 5,903,989 Peru 1,438, , , ,949 21, ,138 72, ,578 Total 18,928,320 33,825 1,343,289 77,263 6,813,877 2,745, ,180 7,627,826 1,202,259 6,425,567 Plus Colombia 29,126,989 49,631 1,551, ,008,180 5,471, ,762 10,663,157 1,701,845 8,961,312 Peru 5,039, ,738 1,667, ,872 42,651 2,324, ,056 2,033,532 Total Plus 34,166,589 49,631 1,551, ,738 12,675,931 6,157, ,413 12,987,745 1,992,901 10,994,844 Colombian oil royalties (including PAP) are paid in kind. Colombian natural gas and natural gas liquids royalties are paid in cash pursuant to recent legislation. Peruvian production is subject to production and mineral tax instead of royalties. 7

8 Item (c) Unit Value of Net Present Value of Future Net Revenue based on Forecast Prices and Costs Future Net Revenue Before Income Taxes (Discounted at 10% Per Year) Unit Value Developing Producing (M$US) ($/BOE) Light and medium oil 1,186, Heavy oil 1,272, Natural gas 577, Total Developed Producing 3,036, Developed Non-Producing Light and medium oil 188, Heavy oil 46, Natural gas Total Developed Non-Producing 235, Undeveloped Light and medium oil 412, Heavy oil 1,165, Natural gas 97, Total Undeveloped 1,675, Light and medium oil 1,787, Heavy oil 2,484, Natural gas 674, Total 4,946, Light and medium oil 1,301, Heavy oil 738, Natural gas 195, Total 2,236, Plus Light and medium oil 3,089, Heavy oil 3,223, Natural gas 870, Total Plus 7,183, Unit values are based on net reserves volumes. The Company has expressed boe using the Canadian conversion standard 6.0 Mcf: 1 bbl required by NI

9 Part 3 Pricing Assumptions Item 3.2 Forecast Prices Used in Estimates Items 3.2.1(a) and NSAI D&M RPS Petrotech WTI 40 API ($US/bbl) Light and Medium Crude Oil WTI 40 API ($US/bbl) WTI 40 API ($US/bbl) WTI 40 API ($US/bbl) Vasconia 25 API ($US/bbl) Heavy Oil Vasconia 25 API ($US/bbl) Natural Gas Colombia La Creciente ($US/MMbtu) Inflation Rate Exchange Rate Percent Per Year ($US/$Cdn) Year Forecast % % % % % 0.87 Thereafter 2% 2% 2% 2% 2% 2% 2% 0.87 Average projected price of three international independent auditors: GLJ Petroleum Consultants, McDaniel and Associates Consultants, Sproule.Consultants. The Company has fixed gas contract prices in place until All forecast prices in the table above were provided by Reserves Report. For 2014, the benchmark index for Colombia was Brent, except for the Putumayo Basin where the benchmark was the South Blend. The benchmark index for offshore Peru was Brent. contracts volumes, escalated at NYMEX futures for heating oil, and based on regulated market price multiplied by adjustment of the sales gas contract. Item 3.2.1(b) For the year ended December 31, 2014, the average realized sales prices before hedging were U.S.$84.24/bbl for Vasconia-based crude oil and U.S.$89.80 for Castilla-based crude oil in Colombia, and U.S.$95.41/bbl for the crude oil domestic market sales offshore Peru, and U.S.$5.49/Mcf for natural gas sales in Colombia. 9

10 Part 4 Reconciliations of Changes in Reserves reserve volume estimates as of December 31, 2014 compared to such reserves as at December 31, 2013 (using forecast prices and costs). Item 4.1 Reserves Reconciliation COLOMBIA P+P Factors Plus Plus (MMcf) (MMcf) Plus (MMcf) Plus At December 31, ,733 35, , , , , ,188 82, , Discoveries 6,363 2,120 8, Extensions & Improved Recovery 1, , Technical Revisions 87-14,063-13,976-43,842-19,088-62,930-1,511 35,412 33,901 5,332 5,569 10,901 Acquisition 9,797 1,739 11, Dispositions Economic Factors -9,270-4,663-13,933-10,735-16,038-26, Production -19, ,022-41, ,360-22, , At December 31, ,767 20,383 83, , , , , , ,361 5,903 5,674 11,577 P+P Factors Light and Medium Oil Plus Heavy Oil Total (Canadian Conversion) Total (Colombian Conversion) Plus At December 31, , , , , , ,959 Discoveries 6,363 2,120 8,483 6,363 2,120 8,483 Extensions & Improved Recovery 1, ,079 1, ,079 Technical Revisions -38,094-21,575-59,668-38,689-21,369-60,058 Acquisition 9,797 1,739 11,536 9,797 1,739 11,536 Dispositions Economic Factors -20,004-20,701-40,705-20,004-20,701-40,705 Production -64, ,173-64, ,372 At December 31, , , , , , ,922 Associated Gas and Non-Associated Gas Natural Gas Liquids The Company has expressed boe using the Canadian conversion standard of 6.0 Mcf: 1 bbl required by NI The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia. PERU P+P Factors Light and Medium Oil Plus (MMcf) Associated Gas and Non-Associated Gas Total (Canadian Conversion) (MMcf) Plus (MMcf) Plus Total (Peruvian Coversion) Plus At December 31, ,674 29,735 45,408 29, , ,723 20,515 51,014 71,529 20,837 52,428 73,265 Discoveries 2,604 8,773 11, ,604 8,773 11,377 2,604 8,773 11,377 Extensions & Improved Recovery 0-8,083-8, ,083-8, ,083-8,083 Technical Revisions Acquisition Dispositions Economic Factors -1,671 1, ,671 1, ,671 1, Production At December 31, ,370 32,368 47,738 29, , ,723 20,212 53,647 73,859 20,534 55,062 75,595 The Company has expressed boe using the Canadian conversion standard of 6.0 Mcf: 1 bbl required by NI The Company has expressed boe using the Peruvian conversion standard of Mcf: 1 bbl required by Petropetro S.A. for those properties located in Peru. 10

11 The Company has expressed boe using the Canadian conversion standard of 6.0 Mcf: 1 bbl required by NI The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia and the Peruvian conversion standard of Mcf : 1 bbl required by Petropetro S.A. for those properties located in Peru. Part 5 Additional Information Relating to Reserves Data Item 5.1 Undeveloped Reserves Item The following table outlines the proved undeveloped reserves and the probable undeveloped reserves attributed to Light and Medium Oil First Attributed Associated Gas and Total Oil Equivalent Heavy Oil Non-Associated Gas Natural Gas Liquids (Canadian Conversion) (MMcf) (MBOE) First First First First Booked Attributed Booked Attributed Booked Attributed Booked Attributed Booked Total Oil Equivalent (Colombian and Peruvian Conversion) (MBOE) First Attributed Booked Prior to ,838 32, , ,134 3,361 6, , , , , ,928 41,217 32, ,446 65,350 92, , ,145 69, , ,523 45,294 51, ,824 72, , , ,668 80, , ,046 23, ,584 35, ,597 5,332 5,741 21, ,398 21, ,447 Prior to ,392 34, , ,819 1,793 3, , , , , ,960 57, , ,310 77, , , , , , ,244 64,985 37, , , , , , , ,893 51, ,786 43, ,039 5,569 5,674 23, ,990 24, ,442 The Company has expressed boe using the Canadian conversion standard of 6.0 Mcf: 1 bbl required by NI The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia and the Peruvian conversion standard of Mcf: 1 bbl required by Petropetro S.A. for those properties located in Peru. undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. within the following five years. This timetable may be altered depending on outside market forces, changes in capital allocations and impact of future acquisitions and dispositions. 11

12 undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. five years. In general, development of these reserves requires additional evaluation data to increase the probability of success to an acceptable level for the Company. This increases the timeline for the development of these reserves. This timetable may be altered depending on outside market forces, changes in capital allocations and impact of future acquisitions and dispositions. Item 5.2 Significant Factors or Uncertainties Item The process of evaluating reserves is inherently complex. It requires significant judgements and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserves estimates contained herein are based on current production forecasts, prices, and economic conditions. These factors and assumptions, among others, include: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the reserves. As circumstances change and additional data becomes available, reserves estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performances, prices, economic conditions, and government restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance, and geologic conditions or production. These revisions can be either positive or negative. For details of important economic factors or significant uncertainties that affect particular components of the reserves data please refer to the headings entitled Risks and Uncertainties and Advisories Management Discussion and Analysis dated March 17, See also the heading entitled Risk Factors in the March 17,

13 Item 5.3 Future Development Costs Item (a) and (b) The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs). Total Total Plus (M$US) Esitmated Using Forecast Prices and Costs Estimated Using Forecast Prices and Costs Colombia , , , , ,391 1,072, , , , ,172 Remainder 134,731 1,083,810 Total for all years undiscounted 2,515,937 5,471,203 Peru , , , , , , , ,430 Remainder 0 13,719 Total for all years undiscounted 229, ,872 Item The Company intends to primarily use internal general cash flows to fund future development costs as well as funds raised from the capital markets. There can be no guarantee that funds will be available or that the board of directors of the Company will allocate funding to develop all of the reserves attributed by Petrotech, RPS, NSAI or D&M. Failure to develop those reserves would have a negative impact on future cash flow of the Company. The only cost of interest associated with debt financing is not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending on the funding source utilized. The Company does not expect that interest or other funding costs could make development uneconomic. Item Not applicable. 13

14 Part 6 Other Oil and Gas Information Item Oil and Gas Properties and Wells The following table sets forth a installations: Name of Important Property Location Onshore or Offshore Working Interest Status Statutory or other mandatory relinquishments, surrenders, back-ins or changes in ownership Rubiales Colombia Onshore 40% Production Ending date: July 1, 2016 Piriri Colombia Onshore 50% Production Ending date: July 1, 2016 Quifa Colombia Onshore 60% Production/Exploration Ending date: December 21, 2031 Production/Exploration & Ending date: 24 years after La Creciente (3) Colombia Onshore 100% Evaluation declaration of commerciality Cubiro Colombia Onshore 100% Production Ending date: November 20, 2037 Relinquishment of remaining area, excluding evaluation and exploitation areas at the end of second phase of subsequent exploration program. Ending date: 24 years after declaration of Cravoviejo Colombia Onshore 100% Production/Evaluation commerciality. Relinquishment of remaining area, excluding evaluation and exploitation areas at the end of second phase of subsequent exploration program. Ending date: 24 years after declaration of Casanare Este Colombia Onshore 100% Exploration/Evaluation commerciality. Relinquishment of 50% of exploration contracted area at the end of minimum exploration program and relinquishment of 50% at end of first phase of subsequent exploration program. Ending date: 24 years after declaration of CPE-6 Colombia Onshore 50% Production/Exploration commerciality. Relinquishment of 50% at end of first phase of subsequent Rio Ariari Colombia Onshore 100% Production/Exploration exploration program. Ending date: August 19, Relinquishment of 50% of contracted area, excluding evaluation and exploitation areas at the end of first phase of subsequent exploration program. Ending date: 24 years after declaration of Guama Colombia Onshore 100% Exploration/Evaluation commerciality. Crude oil 30 years as of effective date (being January 29, 2002). Block Z-1 Peru Offshore 49% Production (3) Natural gas 40 years as of effective date (being January 29, 2002). The working interests mentioned for each contract above are net after state royalties. Quifa Block includes Quifa Norte, Quifa SW and Cajua. Each of fields in the La Creciente Block has a different date of declaration of commerciality, therefore the 24-year term counts independently for each commercial declared field. 14

15 Item Gross and net oil and gas wells The following table sets forth the number of wells in which Pacific Rubiales held a working interest as at December 31, 2014: Natural Gas Net Wells Natural Gas Net Wells Oil Gross Wells Oil Net Wells Colombia Producing 1, Non-Producing Producing Non-Producing Total Producing 1, Total Non-Producing Gross refers to the total wells in which Pacific Rubiales has an interest, directly or indirectly. Net refers to the total wells in which Pacific Rubiales has an interest, directly or indirectly, multiplied by the percentage working interest owned by Pacific Rubiales, directly or indirectly. Item 6.2 Properties with No Attributed Reserves properties with no attributed reserves as at December 31, 2014: Gross refers to the total acres in which Pacific Rubiales has an interest, directly or indirectly. Net refers to the total acres in which Pacific Rubiales has an interest, directly or indirectly, multiplied by the percentage working interest owned by Pacific Rubiales, directly or indirectly. Item Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves. s properties with no attributed reserves are geographically and technically diverse. Such properties require a variety of capital investment ranging from seismic acquisition to drilling and development in order to explore and potentially prove-up reserves. Some properties are in the early evaluation stages of exploration while others have discovered hydrocarbons. Management is continuously reviewing the Company's property profile in order to prioritize opportunities to develop its lands. In undeveloped or unexplored areas, it is common to require companies to pledge to carry out work commitments such as seismic acquisition, geophysical studies or exploration drilling in exchange for property exploration and development rights. Management estimates work commitments of approximately U.S.$408 million to retain the related properties located in Colombia, Peru, Brazil, Guatemala, Belize, Papua New Guinea and Guyana over the next three years. 15

16 Item 6.3 Forward Contracts The Company had in place a hedging program to cover the risk associated with oil price fluctuations during The Company regularly enters into risk management contracts to hedge oil price risk. Most of the hedge structure is in the form of what is customarily referred to as a zero cost collar or similar strategies that consist of a put option and a call option, establishing a price band for the West Texas Intermediate and Brent Light Sweet Crude Oil price, with floor and ceiling prices for an agreed volume. If prices fall below the floor price, the Company is compensated in volume and price for the reduction in income. The opposite is true when prices rise above the ceiling price. 31, 2014 and he years ended December Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs Pacific Rubiales has estimated its abandonment costs by determining amounts for facility decommissioning and reclamation costs (including salvage) by area in Colombia and Peru. As well, Pacific Rubiales has determined abandonment costs (including salvage) and reclamation costs per well, by area and applied this amount to its net wells in Colombia and Peru. The number of net wells to be abandoned is 936 in Colombia and 27 in Peru. The total amount of costs including future drilling locations, net of salvage, as estimated in the Reserves Reports, is set forth in the following table: Country Undiscounted (M$US) Discounted@ (M$US) Colombia 219, ,207 Peru 11,138 7,828 Total 230, ,035 Costs associated with abandonment of surface facilities, well site reclamation, pipeline abandonments, nonproducing wells and reclamation costs, not including downhole costs listed above, were estimated by management of the Company as: Country Facilities Undiscounted (M$US) Discounted@ (M$US) Colombia 76,510 59,838 Peru 30,590 20,510 Total 107,100 80,348 Over the next three years, as estimated in the Reserves Reports, Pacific Rubiales expects to pay abandonment and reclamation costs of: Country Undiscounted (M$US) Discounted@ (M$US) Colombia 8,539 8,539 Peru 9,701 8,829 Total 18,240 17,368 Item 6.5 Tax Horizon Not applicable. 16

17 Item 6.6 Costs Incurred Item The following table outlines the costs incurred to the Company for acquisitions of proved and unproved properties, exploration and development for the fiscal year ending December 31, 2014: Property acquisition cost Country ($M) Unproved ($M) Exploration costs ($M) Developme nt costs ($M) Colombia 276, , ,735 Peru , ,965 Brazil ,986 - Guatemala ,317 - Belize ,969 - Papua New Guinea ,818 - Guayana , , ,701 Item 6.7 Exploration and Development Activities Item The following table outlines the number of gross and net wells contributed to oil, gas, service and dry holes drilled in the fiscal year ending December 31, 2014: Exploration Wells Development Wells Gross Net Gross Net Colombia Oil Gas Standing Dry Holes Total Completed Peru Oil Gas Standing Dry Holes Total Completed Brazil Oil Gas Standing Dry Holes Total Completed Papua New Guinea Oil Gas Standing Dry Holes Total Completed

18 Gross refers to the total wells in which Pacific Rubiales has an interest, directly or indirectly. Net refers to the total wells in which Pacific Rubiales has an interest, directly or indirectly, multiplied by the percentage working interest owned by Pacific Rubiales, directly or indirectly. Item Pacific Rubiales has currently budgeted between approximately U.S.$1.0 billion to U.S.$1.3 billion for its 2015 capital program in Colombia, Peru, Brazil, Guatemala, Belize and Guyana. The funds will be used for drilling wells to develop reserves in its onshore Colombia properties in the Llanos Basin, including expenditures on the lands held by Petrominerales Ltd. (which was acquired by Pacific Rubiales in the fourth quarter of 2013 and amalgamated with Pacific Rubiales effective January 1, 2014) and expenditures on the CPE-6 and Rio Ariari blocks to advance these assets to production stage. The Company, in conjunction with its various partners, is also planning to drill wells in Peru and Brazil. A portion of the capital will be allocated to workovers, production optimization, and maintenance capital in each country. Item 6.8 Production Estimates The following table sets forth the volume of production estimated for the fiscal year 2015 as reflected in the estimates of gross proved reserves and gross proved plus probable reserves: (3) The Company has expressed boe using the Canadian conversion standard of 6.0 Mcf: 1 bbl required by NI The Company has expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for those properties located in Colombia and the Peruvian conversion standard of Mcf : 1 bbl required by Petropetro S.A. for those properties located in Peru. In 2015, it is expected that the Rubiales/Piriri Field will contribute approximately 40% of the C gross production. Item 6.9 Production History The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by Pacific Rubiales for each quarter of the fiscal year ending December 31,

19 (3) (4) Corresponds to net average production. Includes rev s fees. Corresponds to royalties paid in cash. Includes lifting costs, transportation costs, diluent costs and over/underlift. Also, includes IFRS adjustments. 19

20 year ending December 31, 2014, for each product type: fiscal Colombia Rubiales/Piriri Year Ended December 31, 2014 Average Daily Production Heavy Oil (bbl/d) 60,368 Light and Medium Oil (bbl/d) Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Quifa Soutwest Average Daily Production Heavy Oil (bbl/d) 23,685 Light and Medium Oil (bbl/d) Natural Gas (boe/d) Natural Gas Liquids (bbl/d) La Creciente Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 24 Natural Gas (boe/d) 10,159 Natural Gas Liquids (bbl/d) Cubiro Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 9,116 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Cravoviejo Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 8,123 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Guatiquia Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 7,078 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) 450 Casimena Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 5,592 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Casanare Este Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 3,736 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Peru Block Z-1 Average Daily Production Heavy Oil (bbl/d) Light and Medium Oil (bbl/d) 2,434 Natural Gas (boe/d) Natural Gas Liquids (bbl/d) Corresponds to net average production. 20