DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244

Transcription

1 DeGolyer and MacNaughton 51 Spring Valley Road Suite East Dallas, Texas This is a digital representation of a DeGolyer and MacNaughton report. Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

2 5 I SPRING VALLEY ROAD SUITE EAST DALLAS, TEXAS REPORT as of MARCH 31, 216 on RESERVES and REVENUE of CERTAIN PROPERTIES owned by CARACOL PETROLEUM, LLC in the SOUTHERN MILUVEACH UNIT QUALIFIED PERSONS REPORT

3 TABLE of CONTENTS Page FOREWORD... l Scope of Investigation... 1 Authority... 3 Source of Information... 4 Qualified Person... 4 EXECUTIVE SUMMARY... 6 DEFINITION of RESERVES... SOUTHERN MILUVEACH UNIT GEOLOGY and EXPLORATION DATA SOUTHERN MILUVEACH UNIT DEVELOPMENT ESTIMATION ofreserves FINANCIAL ANALYSIS... 1 SUMMARY and CONCLUSIONS APPENDIX

4 5 I SPRING VALLEY ROAD SUITE EAST DALLAS, TEXAS REPORT as of MARCH 31, 216 on RESERVES and REVENUE of CERTAIN PROPERTIES owned by CARACOL PETROLEUM, LLC in the SOUTHERN MILUVEACH UNIT QUALIFIED PERSONS REPORT FOREWORD Scope of Investigation This report presents estimates, as of March 31, 216, of the extent and value of the proved, proved-plus-probable, and proved-plus-probable-plus-possible oil reserves of certain properties in which CaraCol Petroleum, LLC (CaraCol) has represented that it owns a 3.17-percent working interest with a percent net revenue interest. The reserves estimated in this report are located in the Southern Miluveach Unit (SMU), North Slope Alaska, to be developed and operated by Brooks Range Petroleum Corporation (BRPC) from the Mustang drillsite pad. This report has been prepared to meet the requirements of the Singapore Stock Exchange. It has been prepared for disclosure on the Singapore Exchange Network by Alpha Energy Holdings Limited, the holding company of CaraCol, for public viewing and access. At the time of the preparation of this report, CaraCol has represented that BRPC was proceeding with final design engineering and procuring long-lead equipment. Five wells have been drilled into the SMU, and all of these wells encountered the reservoir target to be developed. The last two wells were drilled in 212 and 214, respectively, and both are planned

5 2 to be utilized in the development of SMU. Subsequent wells are scheduled to resume drilling by mid-217. Estimates of reserves presented in this report have been prepared in accordance with the Petroleum Resources Management System (PRMS) approved in March 27 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. These reserves definitions are discussed in detail in the Definition of Reserves section of this report. Reserves estimated in this report are expressed as gross, company gross, and net reserves. Gross reserves are defined as the total estimated petroleum that is recoverable from these properties after March 31, 216. Company gross reserves are the portion of the gross reserves attributable to CaraCol's working interest. Net reserves are defined as that portion of the gross reserves attributable to the CaraCol working interest after deducting landholder and overriding royalty interests owned by others. The table below summarizes the five leases (ADL #396, 3961, 3969, 39691, and 39692) and licenses held by CaraCol in the SMU. CaraCol's License License Asset Interest Development Expiration Area Type of Name/Countrv (%) Status Date (acres) Deoosit Remarks Southern 3.17% working SMU December 31, 217,96 CaraCol pays Miluveach Unit, interest, 3.549% development is (see notes below) % of North Slope revenue interest. on-going. drilling costs. Alaska USA Notes: 1. Subject to the terms and conditions of an approved plan of development, the Unit automatically terminates 5 years from the Effective Date (March 31, 211) unless: a well in the Unit area has been certified as capable of producing oil or gas in commercial quantities, in which case the Unit will remain in effect for so long as oil or gas is being produced in commercial quantities; or for as long as oil or gas is being produced from within the Unit in commercial quantities and operations are being conducted in accordance with the approved plan of development; or should production cease, for so long thereafter as diligent operations are in progress to restore production and then so long after as oil or gas is being produced from within the Unit in commercial quantities; or exploration operations are being conducted under an approved development plan and the unit term is extended by the Commissioner of the Alaskan Department of Natural Resources. No single extension will exceed 5 years. 2. Production of oil and gas in commercial quantities is defined as production sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid. 3. On March 3, 216, BRPC and CaraCol received approval from the State of Alaska, Department of Natural Resources, to extend the term of the Unit until December 31, 217. Based on the development schedule provided herein, the Unit will be producing in commercial quantities before December 31, 217, and the Unit will remain in effect for so long as commercial quantities are being produced.

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7 4 Source oflnformation Data used in the preparation of this report were obtained from CaraCol, from BRPC, and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by CaraCol with respect to its property interests, production flow tests from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report, as no production facilities are yet in place, and we are comfortable that State of Alaska well drilling and reporting guidelines are monitored by the state. DeGolyer and MacNaughton has made reasonable enquiries and exercised its judgement on the reasonable use of such data and information, and has no reason to doubt the accuracy or reliability of the information provided or extracted. Qualified Person DeGolyer and MacNaughton, operating from its offices at 51 Spring Valley Road, Suite BOOE, Dallas, Texas, 75244, USA, is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since Provision of professional services has been solely on a fee basis. Mr. Dennis W. Thompson, P.E., Assistant Manager of our North American Division, has supervised the evaluation. He graduated from Eastern New Mexico University with a Bachelor of Science Degree in Geology in 1973 and he earned a Master of Science Degree in Petroleum Engineering from the University of Texas at Austin in He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers, with 37 years of experience in the evaluation of oil and gas fields. Mr. Thompson fulfills the following criteria for a qualified person: 1. The qualified person is not a sole practitioner; 2. The qualified person producing the report is a Senior Vice President of DeGolyer and MacNaughton; 3. The qualified person and officers and staff ofdegolyer and MacNaughton are independent of Alpha Energy Holdings Limited (Alpha), Alpha directors, and substantial shareholders;

8 5 4. The qualified person and officers and staff ofdegolyer and MacNaughton do not have any interest, direct or indirect, in Alpha or its subsidiaries, and will not receive benefits other than fees paid in connection with the qualified person's report; and 5. Our fees are not contingent on the results of our evaluation.

9 6 EXECUTIVE SUMMARY At the request of CaraCol, an evaluation has been prepared of the oil reserves, expenditures, and revenue for the interests that CaraCol has represented that it owns in the SMU of the Kuparuk River Field as of March 31, 216. This unit is operated by BPRC in North Slope Alaska, United States. No site visit was undertaken by us. The SMU is expected to produce oil from the Cretaceous-age Kuparuk River Formation sandstones. The reservoir has been delineated by all five of the previously drilled wells in the SMU. The wells were drilled between 22 and 214, and the last two wells drilled are expected to be utilized in the development of the SMU. The remaining development wells are scheduled to resume drilling operations by mid-217. The reserves are expected to be fully developed by the middle of 219, with production scheduled to begin in November 217. Planned development for proved reserves will require producers and 13 injectors. Planned development for proved-plus-probable reserves and proved-plus-probable-plus-possible reserves will require one more producer and two more injectors. CaraCol has represented that it owns a 3.17-percent working interest with a percent revenue interest in the SMU. Estimates of reserves presented in this report have been prepared in accordance with the PRMS approved in March 27 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. These reserves definitions and other terms are discussed in detail in following sections of this report.

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11 DEFINITION of RESERVES Estimates of proved, probable, and possible reserves presented in this report have been prepared in accordance with the PRMS approved in March 27 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. The petroleum reserves are defined as follows: Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. Proved Reserves - Proved Reserves are those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 9-percent probability that the quantities actually recovered will equal or exceed the estimate. Unproved Reserves - Unproved Reserves are based on geoscience and/or engineering data similar to that used in estimates of Proved Reserves, but technical or other uncertainties preclude such reserves being classified as Proved. Unproved Reserves may be further categorized as Probable Reserves and Possible Reserves. Probable Reserves - Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is

12 9 equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 5-percent probability that the actual quantities recovered will equal or exceed the 2P estimate. Possible Reserves - Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible Reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 1-percent probability that the actual quantities recovered will equal or exceed the 3P estimate. Reserves Status Categories - Reserves status categories define the development and producing status of wells and reservoirs. Developed Reserves - Developed Reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from ( 1) completion

13 1 intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. Undeveloped Reserves - Undeveloped Reserves are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Estimates of probable and possible reserves in this report have not been adjusted in consideration of these additional risks to make them comparable to estimates of proved reserves.

14 11 SOUTHERN MILUVEACH UNIT GEOLOGY and EXPLORATION DATA The SMU encompasses approximately 12 contiguous square miles (7,6 acres) in the North Slope oil productive region of Alaska. It is located directly north of the Tarn field, south of the Palm field, and southwest of the 2M drilling pad of the Kuparuk River Unit, Kuparuk field. Five wells have been drilled into the SMU as follows: the Kuparuk River Unit 2L-3 well drilled in the south (22), the North Tarn 1 (211), and la (212) wells situated in the center, the Mustang 1 (212) and SMU M-2 (214) wells drilled to the eastern side. All of these wells encountered Early Cretaceous-age Upper Kuparuk River Formation sandstones, which make up the oil development objective of the SMU and the prolific oil producer in the Kuparuk River and Palm fields. The Kuparuk River Formation includes several sandstone and shale members above the Kingak Formation and below the Kalubik Shale Formation. The main objective oil interval includes the bioturbated shallow marine C sandstone lobe, which, where present, has a net sand true vertical thickness (TVT) of generally 15 feet to more than 5 feet in the local multi-field area. This clean and blocky sand lobe often includes siderite and glauconite components, but core data in offset wells indicate permeability of 1 to 1 millidarcys within these heteromineralogy zones. The regional Upper Cretaceous unconformity lies at the base of the C lobe. The thin-bedded progradational lower shoreface sandstones of the upper A interval of the Kuparuk River Formation lie beneath the unconformity and, where paleotopography and faulting are favorable, are preserved and contribute as an oil-bearing lower component to the overall reservoir. In the wells drilled within the SMU, the net oil varies from 17 to 25 feet TVT at an average depth of 6,35 feet true vertical depth subsea (TVDSS). Reservoir thickness in the North Tarn 1 well was estimated from mud log oil shows, since well difficulties precluded obtaining a wireline log suite. The North Tarn la well penetrated the reservoir within 1, feet of the original hole and had 1 7 feet TVT of net oil. The la well was pressure and flow tested in January 212 and produced oil at a rate of 62 barrels per day with a very high wellbore skin value of Average net oil thickness for the SMU is 17.5 feet TVT. Average porosity and water saturation for the SMU are 21.1 percent and 19.3 percent, respectively. The Kuparuk River Formation in the SMU exhibits a moderately faulted undulating structure that varies from 5,9 to 6,2 feet TVDSS. A dual-direction tensional stress regime is manifested in a bimodal normal fault pattern. This is dominated by a series of north/south-trending,

15 12 down-to-the-east normal faults, which are complemented by multiple northwest/southeast-trending cross faults. The displacements across these faults within the SMU may be sufficient to effect reservoir separation and cause compartmentalization. Seismic data also indicate fault separation from the 2M drilling pad development of the Kuparuk River Unit, Kuparuk field, which borders the SMU to the east and northeast. However, an initial pressure buildup test, conducted in the North Tarn la well, indicated that the Kuparuk C reservoir was approximately 5 pounds per square inch above the expected pressure. The elevated pressures at the North Tarn la well are most likely caused by the current waterflood operations in the Kuparuk River Unit and support the interpretation that the C sand is continuous between the Kuparuk River Unit waterflood injectors and the location of the North Tarn la well. The SMU was recognized by the Division of and Gas of the State of Alaska on January 26, 212, subject to the completion of additional well work and sanction by BRPC by October 1, 212. CaraCol has represented that those requirements have been met, and that development has been ongoing. On March 3, 216, BRPC and CaraCol received approval from the State of Alaska, Department of Natural Resources, to extend the term of the SMU until December 31, 217. Based on the development schedule provided herein, the Unit will be producing in commercial quantities before December 31, 217, and the Unit will remain in effect for so long as commercial quantities are being produced.

16 13 SOUTHERN MILUVEACH UNIT DEVELOPMENT The development of the SMU from a single drillsite pad (the Mustang pad), the capital costs necessary to construct the Mustang drillsite pad, the schedule of development, and the expenses to operate were provided by CaraCol and BRPC. The development plan, the associated capital costs, and the operating expenses appeared reasonable and were accepted as presented. As part of the overall development of the SMU, CaraCol has represented that one of the other working interest owners (with 2-percent ownership) in the project is to pay for the cost of the surface production facilities. The contractual arrangement between this surface facility working interest owner and the remaining working interest owners is similar to a purchase/lease back arrangement. Any funds accruing from the 2-percent working interest that are over and above the calculated lease payments are to be refunded to the other working interest owners. Any potential payments from the surface facility working interest owner to CaraCol have not been included in this analysis. CaraCol and the other remaining working interest owners are to pay for the cost to drill and complete the wells. Because of this arrangement, CaraCol is expected to pay percent of the drilling and completion costs. The proved estimate of reserves presented herein requires the drilling and completion of single-lateral horizontal wells paired with 13 vertical water injection wells to effectively waterflood the targeted Kuparuk C reservoir. The proposed Mustang drill pad is located at the surface site of the existing North Tarn 1, la, and Mustang 1 wellbores in section 2 (Figure 1). The sections developed in the proved reserves estimate are the nine contiguous sections centered around the proposed Mustang drill pad in section 2, as well as section 25. This area is generally within a 12,-foot drilling radius from the centralized planned drillsite pad location and also is located above the lowest known oil (LKO) depth at 6,15 feet TVDSS, which is seen in the Kuparuk River Unit 2L-3 well. The planned proved reserves development is to orient the horizontal producers and 13 vertical water injectors in a parallel direction with the dominant north-south faulting in order to minimize areas of stranded oil. Because it is unknown if these faults are sealing, each horizontal producer will be paired with one or two vertical water injectors located approximately 2,5 to 5, feet away so that they both lie within the same fault

17 14 block. The north/south-oriented horizontal laterals are estimated to range in length between 5, and, feet and are estimated to cost an average of U.S.$12.4 million each. Since it is uncertain whether BRPC will be able to re-enter the Mustang 1 wellbore, extend the well horizontally, and complete it as a horizontal producer along the eastern boundary, capital has been included to re-drill the well. The rate forecast for the proved case was estimated using the BRPC full-field model. The recovery factor for the proved reserves case is approximately 3 percent of the original oil in place (OOIP) in the SMU. The proved reserves development schedule represents the following: the gravel road and pad have already been installed; equipment procurement is underway and module fabrication is to finish by late 216 to early 217; module transportation to the North Slope is to begin by mid- 217 and installation to finish by the end of 217. Functional check out and commissioning is planned for the third quarter of 217 with an anticipated plant startup date of November 1, 217. Development drilling is planned to resume in July 217. The development drilling is expected to continue until May 219. The proposed production facilities on the Mustang pad are to be designed with a capacity of 15, barrels of fluid per day (BFPD). It is anticipated that initial oil production from the eight horizontal producing wells will be able to exceed the 15, BFPD limit. As such, the total oil production from the field is estimated to reach 15, barrels of oil per day (BOPD) by the first half of 21 as the producers are completed, and remain at 15, BOPD throughout 21. It is projected that water production will begin to increase after 21 as water breakthrough occurs between the paired injectors and producers, and oil production will begin to decline as the total fluid produced remains at the production facility capacity of 15, BFPD. The estimate of probable reserves presented herein requires the drilling and completion of one additional horizontal producer and two vertical injectors, in addition to those planned for the proved reserves development. These additional laterals are required to develop the Kuparuk C reservoir in the western sections of the SMU under sections 4 and 9. For the probable reserves estimate, the oil productive limits of the Kuparuk C have been extrapolated downdip an additional 5 feet below the LKO to 6,155 feet TVDSS, and the probable reserves recovery factor was increased from 3 percent, used in the proved reserves evaluation, to 35 percent. The estimate of possible reserves presented herein does not require any additional wells over that contemplated under

18 15 the probable reserves development. For the possible reserves estimate, the recovery factor was increased from 35 percent used in the probable reserves evaluation to 4 percent. Figure 1 below is a map of the SMU development plan showing the boundaries of the SMU and the locations of the proposed horizontal producers and high-angle injectors Scale= 1 : ~ t # L--HP-P-Silver---ll------t f -HP-l"Diablo Mustang-1RD Mustang HP-D-Cactus - - V"Y-Chicksa w '< ''HP-EE-Clover Figure 1: SMU development plan map No gas reserves have been evaluated for this report. There are no gas sales markets available on the North Slope and all gas that is to be produced is expected to be either used as fuel or reinjected for pressure maintenance.

19 16 ESTIMATION of RESERVES Estimates of reserves presented in this report have been prepared in accordance with the Petroleum Resources Management System (PRMS) approved in March 27 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry were used. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by CaraCol, and the analyses of areas offsetting existing wells with test or production data, reserves were categorized as proved, probable, or possible. The volumetric method was used to estimate the OOIP. Structure maps were prepared by BRPC and reviewed for this report to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. Simulation results prepared by a third party and provided by BRPC for this report were also used to help estimate the anticipated future recoverable volumes. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and analogous production histories in the Kuparuk C reservoir in the nearby Kuparuk River field and Palm field. An analysis of analogous reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. The estimated proved (lp), provedplus-probable (2P), and proved-plus-probable-plus-possible (3P) reserves, as of

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22 19 Operating Expenses, Transportation Expenses, Capital Costs, and Abandonment Costs Operating expenses, transportation expenses, capital costs, and abandonment costs (in 215 United States dollars) were provided by CaraCol and BRPC. Estimates of operating expenses, based on estimated future fixed and variable expenses, transportation expenses, and capital costs were held constant for the lives of the properties and were not adjusted or escalated for inflation. The costs of surface facilities are paid by a separate legal entity established for the sole purpose of financing said facilities. CaraCol has represented that it is contractually responsible for a disproportionate share of percent of the drilling capital. Production Taxes and Ad Valorem Taxes The severance tax law, SB21, in the State of Alaska is very complex. Provisions of the new law include a variety of capital, loss carry forward, and small producer tax credits. The large negative production taxes in the early years of the project are primarily due to loss carry forward credits payable under SB21 that are generated from the high capital expenditures required for the SMU development. CaraCol and BRPC have represented that each intends to apply to the State of Alaska each year, where applicable, for Alaska to purchase the applicable tax credit. Based on this representation, the value of the tax credit has been included as a negative production tax payment herein. CaraCol has represented that it is eligible for the small-producer tax credit, and at CaraCol's request, this credit has been included in the production tax calculation herein. A Crude Conservation Tax of $.5 per barrel of net production has also been included in the production tax calculation. Ad valorem taxes were calculated at 2 percent of the depreciated capital investment, including tangible drilling costs. As of March 31, 216, the estimated balance for ad valorem tax purposes was $24 million.

23 2 The estimated future revenue and costs to be derived from the production and sale of CaraCol's estimated net reserves, as of March 31, 216, for the development of the SMU are summarized as follows, expressed in thousands of United States dollars (M U.S.$): IP (MU.S.$) 2P (MU.S.$) 3P (MU.S.$) Future Gross Revenue Ad Valorem and Production Taxes Transportation Expenses Operating Expenses Capital and Abandonment Costs Future Net Revenue Present Worth at 1 Percent 3,1 (19,96) 59,152 5,295 12,372 63,977 34,325 54,249 (11,351) 95,654 11, , ,92, ,13 (7,69) 1, , , ,321 1,64 Notes: 1. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves. 2. Future income taxes were not taken into account in the preparation of these estimates. The appendix bound with this report includes (1) a summary projection of estimated proved reserves and revenue, (2) a summary projection of estimated proved-plus-probable reserves and revenue, and (3) a summary projection of estimated proved-plus-probable-plus-possible reserves and revenue.

24 21 SUMMARY and CONCLUSIONS BRPC is developing certain properties located in the SMU on the North Slope, Alaska. CaraCol has represented that it owns a 3.17-percent working interest in the project. The estimated proved (lp), proved-plus-probable (2P), and proved-plus-probable-plus-possible (3P) oil reserves of the properties evaluated, as of March 31, 216, are summarized as follows, expressed in thousands of barrels (Mbbl): Company Gross Gross Net Category (Mbbl) (Mbbl) (Mbbl) lp 2,169 7,72 6,162 2P 32,616 12,455 9,964 3P 37,15 14,19 11,351 Notes: 1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves. 2. All oil reserves estimated herein are considered undeveloped. Estimated future net revenue attributable to CaraCol's interests in the SMU, as of March 31, 216, of the properties evaluated under the aforementioned assumptions concerning future prices and costs is summarized as follows, expressed in thousands of United States dollars (M U.S.$): IP (MU.S.$) 2P (MU.S.$) 3P (MU.S.$) Future Gross Revenue Future Net Revenue Present Worth at 1 Percent 3,1 63,977 34,325 54, ,92, ,13 211,321 1,64 Notes: 1. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves. 2. Future income taxes were not taken into account in the preparation of these estimates. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil reserves, we are not aware of any such governmental actions which would restrict the recovery of the March 31, 216, estimated oil reserves.

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26 PROJECTION OF ESTIMATED PROVED PRODUCTION AND REVENUE AS OF MARCH 31, 216 FROM CERTAIN PROPERTIES OWNED BY CARACOLPETROLEUM,LLC GRAND TOTAL Year Ending Dec31 Com11lelions Gross Production (bbl} Company Gross Production (bbl} Net Production (bbl} ,96 3,94,747 2,99,142 2,34, ,272 1,521,649 1,144,96 91,639 14,21 1,217, ,917 72, ,792,799 1,419,551 1,17,93 1,2,2 2,642 64, ,2 453,633 39, ,54 547, , ,96 311, , ,17 67,57 617,21 555,67 56,31 295, , , , ,34 236,55 21,3 1, , , , , , , , ,194 Subtotal Remaining Total Cumulative Ultimate 2,169,47 2,169,47 2,169,47 7,72,9 7,72,9 6,161,672 6,161,672 Year Ending Dec Prices ($/bbl} Future Gross Revenue m Future Gross Revenue Total m 6,253,714 6,253,714 56,92,716 56,92,716 44,44,276 44,44,276 36,316,23 36,316,23 AdValorem Tl<es m 655,579 71,19 1,3,49 1,374,54 1,294,392 Production Tl<es m Transportation Expenses m -15,451,64-262,279 1,346,91-12,293,52 11,66,265-5,72,694,792, 36,425 6,993, ,44,594 27,44,594 22,437,47 22,437,47 1,969,116 1,969,116 16,47,5 16,47,5 14,193,91 14,193,91 1,194,2 1,95, ,66 96, ,54 27,35 5,257,31 21,64 4,163,1 1,146 3,43,91 15,55 2,992,249 13,42 2,5, ,449,616 12,449,616 11,55,96 11,55,96 9,935,33 9,935,33,935,65,935,65,141,949,141, ,92 597,41 497,43 39, ,55 11,27 2,27,447 1,53 2,16,26 9,435 1,11,914,47 1,629,641 7,735 1,44, ,46,125 7,46,125 6,95,692 6,95, ,54 315,54 7,112 1,365,251 6,6 1,269,62 Subtotal Remaining Total Year Ending Dec Lease Expenses ($) 33,132 2,437,469 5,579,9 3,61,695 3,27,555 3,9,572 3,9,572 3,9,572 3,9,572 13,529,31 13,529,31 Capital and Lifting Abandonment Total Future Net Revenue Present Worth at 1 O Percent Expenses Costs Expenditures Annual Cumulative Annual Cumulative ($} ($} ($} ($} ($} ($} ($} 24,64 21,16 14,514,253 14,514,253 13,94,6 13,94,6 227,56 37,523,66 41,535,12-35, 72, 12-21,25,75-31,3,499-17,134,639 2,112,234 56,65,265 76,2,752 -,141,33-29,346,9-7,5,454-24, 15,93 1,972,622 13,42,16 27,41,223 21,35,199-7,996,79 15,254,31 -,93,262 2,136,19 12,157,452 22,2,14 14,31,35 15,21,767 6,2,55-33,516,59 59,152,55-33,516,59 59,152,55 Gross Com11lelions QjJ Ga&_ Month of Last Production: 12/233 Interests (Percent} Date Working Revenue ,26,17 3,23,136 3,19,553 3,16,11 3,11,734 3,7,76 3,3,759 2,999,971 2,995,476 2,991,297 2,25,21 1,49,21 16,133,179 3,964,44 9,773,13 16,53,643 2,237,139 9,423,463 11,97,446 42,61,93 6,54,92 22,61,735 2,257,95,76,549 9,194,735 52,56,665 4,599,7 27,21,515 2,277,969,26,229 7,29,57 59,266,235 3,27,712 3,4,227 2,22,471 7,2,773 5,51,17 64,767,413 2,274,13 32,754,41 2,293,919 7,572,134 4,16,673 6,936,6 1,566,92 34,321,33 2,34,379 7,324,424 3,123,631 72,59,717 1,67,557 35,3,7 2,319,791 7,131,676 2,296,376 74,356,93 713,775 36,12,662 2,319,461 6,944,57 1,54,52 75,94, ,49 36,55,511 2,326,12 6,2,333 1,16,376 76,956, ,349 36,11,6 Present Worth Profile!I} 5. Percent 47,271, Percent 36,625, Percent 3,119, Percent 24,73,11 2. Percent 17,644, Percent 12,476, Percent,64, Subtotal Remaining Total 2,99,692 2,991,253 5,22 51,346,49 51,346,49 2,331,37 6,67,7 475,729 77,432, ,5 36,923,36 2,344,345 6,64,66 31,92 77,464,646 7,361 36,93,729 12,97,152 13,47,974-13,47,974 63,976,672-2,65,65 34,325,79 33,94,691 12,371,93 264,19, 12 63,976,672 34,325,79 63,976,672 34,325,79 33,94,691 12,371,93 264,19, 12 63,976,672 34,325,79 These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions. DEGOLYER ~ MACNAUGHTON F-716 TEXAS REGISTERED ENGINEERING FIRM

27 PROJECTION OF ESTIMATED PROVED PLUS PROBABLE PRODUCTION AND REVENUE AS OF MARCH 31, 216 FROM CERTAIN PROPERTIES OWNED BY CARACOLPETROLEUM,LLC 2 GRAND TOTAL Year Ending Dec31 Com11lelions Gross Production (bbl} Company Gross Production (bbl} Net Production (bbl} ,4 4,633, 4,292,495 3,754,96 163,592 1,769,52 1,639,16 1,433, 13,74 1,415,62 1,311,334 1,147, ,4,44 2,17,223 1,793,915 1,524,99 1,32, 1,71,2 35,231 65,39 52,315 54,66 56,65 66,16 54,31 465,52 43, ,166,43 1,44,99 94,41 64, ,13 445, ,14 362,332 33,1 34,6 356,33 319,211 29,66 264, , ,565 67,47 637,53 592,92 551,51 21, ,53 243, ,441 21,6 225,322 21,24 194,77 11,153 16,41 Subtotal Remaining Total Cumulative Ultimate 3,76,499 1,47,353 32,615,52 32,615,52 11,749,517 75,446 12,454,963 9,399, ,357 9,963,972 Year Ending Dec31 Prices ($/bbl} Future Gross Revenue m Future Gross Revenue Total m 5,36,97 5,36,97 66,264,31 66,264,31 63,625,952 63,625,952 57,13,15 57,13,15 AdValorem Taxes m 65, ,945 1,415,55 1,429,454 1,3,2 Production Taxes ($} -15,451,64-263,769-12,4,73-2,95,56 57,354 Transportation Expenses ($} 1,256,39 13,59,775 12,5,12 11,12, ,563,14 43,563,14 34,571,9 34,571,9 2,645,64 2,645,64 24,522,432 24,522,432 21,227,249 21,227,249 1,31,6 1,249,2 1,179,799 1,11,399 1,41,2 42,41 33,41 27,43 23,293 2,162,225,94 6,414,579 5,261,11 4,472,177 3,71, ,757,21 1,757,21 16,3,279 16,3,279 15,25,551 15,25,551 13,94,525 13,94,525 12,2,32 12,2,32 971,62 92,21 32, 763, ,99 17,17 15,96 14,495 13,26 12,162 3,42,766 3,64,42 2,72,715 2,535,779 2,334, ,6,965 11,6,965 11,55,64 11,55,64 1,253,132 1,253,132 9,535,7 9,535,7,6,14,6,14 624,62 555,22 45,1 416,4 346,999 11,26 1,53 9,73 9,59,422 2,163,94 2,16,22 1,69,72 1,739,6 1,617,413 Subtotal 5.49 Remaining Total 5.61 Year Lease Ending Expenses Dec31 {$} , ,437, ,59, ,92, ,36, ,54, ,54,927 29,77,744 29,77,744 54,24,671 54,24,671 1,9,27 1,26,91 19,367,17 Capital and Lifting Abandonment Total Future Net Revenue Present Worth at 1 O Percent Expenses Costs Expenditures Annual Cumulative Annual Cumulative {$} {$} {$} {$} {$} {$} {$} 24,64 21,942 14,511,329 14,511,329 13,946,51 13,946,51 212,67 37,523,64 41,43,156-36,44,354-21,533,25-31,359, ,413,123 2,3,352 56,65,264 7,13,44-73,166-22,46, 191-1,24,92-1,662,43 2,12,194 19,259,21 37,932,52 27,214,422 4,,231 19,466,437 4,394 2,24,559 16,29,224 39,44,57 44,256,1 26,275,6 27,79,454-3,746,93 2,219-3,71,64 Gross Com11lelions 9,236,33 5,417,25 95,654,12 Month of Last Production: 12/24 Interests (Percent} Date Working Revenue 221 3,32, ,2, ,24, ,2, ,16, ,12, ,, ,4, ,, ,996, ,992, ,9, ,94, ,9, ,976,774 Subtotal 6,65,23 Remaining 12,472,99 Total 72,537,32 2,214,95 13,472,93 2,72,59 72,95,391 17,39,12 44,477,574 2,195,115 11,637,67 21,651,431 94,636,22 11,915,22 56,392,596 2,175,533 1,46,1 16,977,61 111,614,423,491,526 64,4,122 2,162,27 9,654,641 13,734,99 125,34,522 6,243,241 71,127,363 2,136,91 9,24,315 11,141,77 136,49,292 4,63,26 75,73,631 2,117,91,55,72 9,216,91 145,77,22 3,461,675 79,192,36 2,99,9,171,754 7,713, ,42,566 2,633,569 1,25,75 2,6,142 7,73,37 6,537,69 159,95,435 2,29,147 3,55,22 2,61,9 7,59, 5,529,4 165,4,275 1,559,995 5,415,17 2,43,729 7,374,75 4,721,293 17,29,56 1,21,56 6,625,73 2,25,659 7,11,193 4,43,92 174,253,47 942,7 7,56,76 2,13,247 7,1,232 3,471, ,725,11 735,957,34,717 1,99,12 6,44,474 2,913,119 1,63,3 561,373,66,9 1,972,4 6,692,225 2,41,23 13,56,53 423,725 9,29,15 1,955,122 6,549,39 1,964,4 15,2,57 312,947 9,62,762 3,15,6 113,61,42 32, 16,956 15,2,57 9,62,762 7,655,56 12,93,526 3,52,956-1, 11, ,92,265-3,56,719,22 45,41, ,665,36 34,697, ,92,265,719,22 These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions. Present Worth Profile ($} 5. Percent 123,31, Percent 94,55,5 12. Percent 7,264, Percent 65,263, Percent 4,967, Percent 37,36,26 3. Percent 2,96,434 M MACNAUGHTON F-716 TEXAS REGISTERED ENGINEERING FIRM

28 PROJECTION OF ESTIMATED PROVED PLUS PROBABLE PLUS POSSIBLE PRODUCTION AND REVENUE AS OF MARCH 31, 216 FROM CERTAIN PROPERTIES OWNED BY CARACOLPETROLEUM,LLC 3 GRAND TOTAL Year Ending Dec31 Com11lelions Gross Production (bbl} Company Gross Production (bbl} Net Production (bbl} ,4 4,633, 4,35,695 3,5, ,592 1,769,52 1,644,29 1,47,574 13,74 1,415,62 1,315,367 1,176, ,93,917 2,36,96 1,99,355 1,711,63 1,494,526 1,139, ,55 76,53 653,63 57, , ,23 6,43 522, , ,329,444 1,197,2 1,91,93 99, ,257 57, ,27 416,976 31, ,11 46,13 365, ,51 35,75 21, ,757 2,76 749,9 74,21 662, ,16 36,27 26, , ,11 261, ,3 229,11 215,319 22,49 Subtotal Remaining Total Cumulative Ultimate 33,12,7 4,55,579 37,157,666 37,157,666 12,64,641 1,54,69 14,19,339 1,112,514 1,23,95 11,351,472 Year Ending Dec31 Prices ($/bbl} Future Gross Revenue m Future Gross Revenue Total m 5,36,97 5,36,97 66,264,31 66,264,31 63,21,61 63,21,61 5,646,4 5,646,4 AdValorem Taxes m 659, ,2 1,424,3 1,44,293 1,416,976 Production Taxes ($} -15,451,64-264,131-12,49,55-2,953,75 5,25 Transportation Expenses ($} 1,256,39 13,59,775 12,627,525 11,294, ,344,264 46,344,264 37,72,996 37,72,996 31,72,47 31,72,47 27,525,995 27,525,995 24,33,39 24,33,39 1,357,936 1,29,96 1,239,57 1,1,16 1,121,777 45,576 36,463 3,44 26,147 22,3,751,1 7,,355 5,37,212 5,19,939 4,33, ,379,112 21,379,112 19,253,9 19,253,9 17,559,79 17,559,79 16,59,136 16,59,136 14,31,46 14,31,46 1,62,732 1,3, ,653 5,612 26, ,62 65,24 16,6 15,255 14,7 3,9,927 3,511,347 3,22,379 2,92,71 2,74, ,777,712 13,777,712 12,9,372 12,9,372 12,6,743 12,6,743 11,334,49 11,334,49 1,654,792 1,654, ,52 7,4 649,449 59,4 531,36 13,7 12,254 11,456 1,764 1,122 2,512,652 2,352,27 2,199,52 2,67,65 1,943,123 Subtotal 5.61 Remaining Total 5.3 Year Lease Ending Expenses Dec31 {$} Capital and Lifting Abandonment Expenses Costs {$} {$} Total Expenditures {$} 511,793,15 511,793,15 65,21,767 65,21, ,12,52 577,12,52 Future Net Revenue Annual Cumulative {$} {$} 19,39,43 2,25,965 22,665, Present Worth at 1 O Percent Annual Cumulative {$} {$} -3,417,33 61,941-3,355,362 Gross Com11lelions 97,,131 11,94, 1,974, , ,437, ,59, ,93, ,37,767 24,64 212,67 37,523,66 2,3,352 56,65,265 2,12,194 19,259,211 2,24,559 21,96 41,43,37 7,13,464 37,972,144 16,572,334 14,51,295 14,51,295-36,49,9-21,53, 794-1,12-22,419,96 27,354,6 4,934,99 4,59,353 45,533,343 13,945,57 13,945,57-31,363,361-17,41,34-1,255,31-1,673,65 19,566,462 92,57 27,31,453 27,924,31 Month of Last Production: 12/244 Interests (Percent} Date Working Revenue 221 3,33, ,3, ,26, ,23, ,19, ,16, ,12,3 22 3,9, ,5, ,2,34 2,214,95 2,195,115 2,175,533 2,162,27 2,136,91 2,117,91 2,99,9 2,6,142 2,61,9 2,43,729 13,999,931 12,225,79 11,39,615 1,25,571 9,539,79 9,33,134,623,24,29,4 7,996,519 7,75,19 3,94,21 76,474,164 24,167,75 1,641,922 19,472,531 12, 114,453 16,113, ,227,914 13,349, ,577,356 11,1,14 16,57,54 9,561,933 17,149,473,3,292 17,449, 765 7,161,75 15,611,515 6,239,56 191,51,3 1,731,569 46,655,79 13,296,547 59,952,426 9,737,462 69,69, 7,323,541 77,13,429 5,514,44 2,527,913 4,134,64 6,662,553 3,264,232 9,926,75 2,575,79 92,52,494 2,2,37 94,522,531 1,599,969 96,122,5 Present Worth Profile ($} 5. Percent 143,631,66 9. Percent 17,969, Percent,347, Percent 73,41, Percent 54,249, Percent 41,115, Percent 31,672, ,99, ,995, ,991, ,9, ,95,7 Subtotal 6,143,537 Remaining 24,366,44 Total 4,51,21 2,25,659 2,13,247 1,99,12 1,972,4 1,955,122 3,15,6 113,61,46 15,46,57 12,93,526 53,232, ,665,372 7,537,13 7,361,19 7,11,494 7,2,52 6,3,315 39,91, ,29, ,31,639 5,459, ,31,997 4,16,44 22,127,437 4,21,344 26,345, 71 3,75,15 21,5,966 3,229,97 213,2, ,2,953-1,959, ,321, ,321,297 1,272,9 97,395,39 1,2,7 9,416,17 12,567 99,22,54 64,92 99,77,46 514,319 1,391,5 1,391,5 471,66 1,63,671 1,63,671 These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions. M MACNAUGHTON F-716 TEXAS REGISTERED ENGINEERING FIRM

29