Table of Contents - Volga Gascontent.volgagas.com/media/22554/report_2017_spe_prms_eng_.pdfVolgo-Urals, along with Western Siberia are the largest oil and gas basins of Russia. Volga-Urals

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Table of Contents:

Table of Contents: ............................................................................................................................................. 2

1. EXECUTIVE SUMMARY .................................................................................................................................. 3

2. GENERAL ........................................................................................................................................................ 8

3. REGION REVIEW ............................................................................................................................................ 9

4. REGULATORY PROVISIONS ........................................................................................................................ 12

5. OVERVIEW OF ASSETS ................................................................................................................................ 16

6. FIELD INFRASTRUCTURE AND HYDROCARBON PRODUCTION .............................................................. 21

7. RESERVE VALUATION ................................................................................................................................. 34

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1. EXECUTIVE SUMMARY

This report was prepared by GeoStream Assets Management (hereinafter referred to as

GeoStream), as of December 31, 2016.

GeoStream is an independent competent person (CP). Production of this report was supervised

by Mr. Svyatoslav Igorevich Bilibin who meets the requirements for the independent CP (see

“Qualifications and Basis of Judgement ").

GeoStream estimated net oil and gas reserves and future net revenues as of December 31, 2016,

attributed to the interests of Volga Gas plc (VG) in the Vostochno-Makarovskoye gas/condensate

field, Dobrinskoye gas/condensate field, Uzenskoye oil field and Sobolevskoye oil field located in

the Volgograd and Saratov regions, Russian Federation.

The reserves and resources reported herein were estimated in accordance with the standards of

Petroleum Resources Management System (PRMS), which was prepared by the Oil and Gas

Reserves Committee of the Society of Petroleum Engineers (SPE). The document (SPE-PRMS) was

reviewed and jointly sponsored by the World Petroleum Council, the American Association of

Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. It was approved by

the SPE Board of Directors in March 2007. Definitions from the SPE-PRMS are included in

Appendix 1 to this report.

The results of these evaluations as of December 31, 2016, are shown below:

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Reserves Summary

Category Gross Reserves Net Reserves

Operator

1P 2P 1P 2P

Oil & Liquids Reserves per

Asset

Oil Condensate Oil Condensate Oil Condensate Oil Condensate

Mbbl Mbbl Mbbl Mbbl Mbbl Mbbl Mbbl Mbbl

Dobrinskoye 0 480 0 702 0 480 0 702 Volga Gas plc

Vostochno-Makarovskoye 0 4,069 0 5,049 0 4,069 0 5,049 Volga Gas plc

Sobolevskoye 315 0 315 0 315 0 315 0 Volga Gas plc

Uzenskoye 6,087 0 6,087 0 6,087 0 6,087 0 Volga Gas plc

Total Oil & Liquids 6,402 4,549 6,402 5,751 6,402 4,549 6,402 5,751

Gas & LPG Reserves per Asset Sales Gas LPG Sales Gas LPG Sales Gas LPG Sales Gas LPG

Operator

Mscf Mtonnes Mscf Mtonnes Mscf Mtonnes Mscf Mtonnes

Dobrinskoye 6,478 0 9,717 0 6,478 0 9,717 0 Volga Gas plc

Vostochno-Makarovskoye 92,027 277 121,815 367 92,027 277 121,815 367 Volga Gas plc

Total Gas & LPG 98,505 277 131,532 367 98,505 277 131,532 367

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Reserves Summary by Field

RESERVE CATEGORY

NET RESERVES

Oil & Condensate Gas LPG

FIELD Mbbl Mtonnes MMcf MMm3 Mtonnes

CATEGORY: TOTAL PROVED RESERVES

Sobolevskoye 315 42 0 0 0

Dobrinskoye 480 56 6,478 184 0

Vostochno-Makarovskoye 4,069 454 92,027 2,606 277

Uzenskoye 6,087 791 0 0 0

Total 10,951 1,343 98,505 2,790 277

CATEGORY: PROVED PRODUCING RESERVES


Dobrinskoye 478 56 6,478 184 0


Uzenskoye 397 49 0 0 0

Total 4,944 559 98,505 2,790 277

CATEGORY: PROVED NON-PRODUCING RESERVES


Dobrinskoye 0 0 0 0 0

Vostochno-Makarovskoye 0 0 0 0 0

Uzenskoye 3,887 513 0 0 0

Total 3,887 513 0 0 0

CATEGORY: PROVED UNDEVELOPED RESERVES


Dobrinskoye 0 0 0 0 0

Vostochno-Makarovskoye 0 0 0 0 0

Uzenskoye 1,915 243 0 0 0

Total 2,230 285 0 0 0

CATEGORY: TOTAL PROVED + PROBABLE RESERVES


Dobrinskoye 702 82 9,717 275 0


Uzenskoye 6,087 791 0 0 0

Total 12,153 1,479 131,532 3,725 367

CATEGORY: TOTAL POSSIBLE RESERVES ,

Total 0 0 0 0 0

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Revenues

RESERVE CATEGORY

Net Sales

Revenue

Net

Operating

Expenses

Net Taxes

FUTURE NET REVENUE

(including past losses)

Net Capital

Expenses Disc.

Undisc.

at 12%

M$ M$ M$ M$ M$ M$

Total Proved 662,045 160,541 227,557 17,756 247,618 140,250

Total Proved +

Probable 793,951 195,553 258,101 17,756 313,969 162,279

RESERVE CATEGORY Cash Flow

(M$)

Present Worth at 12%

(M$)

Proved Producing 207,567.35 122,838.97

Total Proved 247,617.84 140,249.73

Proved + Probable 313,968.99 162,278.79

Estimates of reserves and resources are based on the data and information provided to

GeoStream by VG. Estimates can be changed when additional information is received, and also

depend on uncertainties related to the application of solution factors. Maximum oil production

volumes can significantly differ from the estimates presented in this report.

We relied on the information on ownership in the license areas, provided by VG, and accepted it

as represented, as verification of such data and information was beyond the scope of this

assignment.

The estimated proved developed producing reserves can be produced from existing wellbores

operating as of the date of estimate in the report, i.e. as of December 31, 2016. Reserves for

these wells were estimated by production decline extrapolation to economic limits (minimum

allowable rate). The estimated proved developed non-producing reserves can be produced from

existing wells, but require capital costs for restoration or recompletion and hooking up flow lines.

Reserves for such wells were estimated using volumetric method, when the start of production

was based on VG plans to return these wells to production.

The estimated proved undeveloped reserves require significant capital expenditures, such as

drilling costs. The proved undeveloped reserves were estimated by volumetric method using

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recovery factors based on forecasts of history-matched simulation models with the use of data

on other analogous fields.

The estimated probable reserves include reserves in undeveloped areas of the fields, which,

by GeoStream opinion, are more likely to be recovered than not. The estimated probable reserves

also include incremental recoveries, if recovery efficiencies beyond that assumed for proved

reserves.

Possible reserves were not estimated, as VG does not have any assets with such category.

Reserves estimates from volumetric calculations and from analogies are often less certain than

reserve estimates based on well performance obtained over a period during which a substantial

portion of the reserves was produced. Reserves were forecasted over the future field life of 25

years, no provision was made for expiration of production or exploration licenses.

8

2. GENERAL

The results presented in this Competent Person’s Report (CPR) are derived from the application

of reservoir engineering and geological data provided to GeoStream by VG and, in some cases,

of analog field data and public sources of information. GeoStream did not independently gather

any information other than that provided by VG and other information from public domains. This

data and information was accepted by GeoStream as represented, as verification of such data

and information was beyond the scope of this assignment. The fundamental data provided to

GeoStream included data acquired in drilling of wells (logs, cores, tests and fluid samples);

production test measurements and actual production histories; pressure measurements; and

seismic data. Analysis of available data resulted in various conclusions regarding deposits as for

the geological model, physical sizes and recovery process. Our estimates of reserves were made

with the use of deterministic method.

In general, infrastructure facilities look well maintained, without visible evidence of spills or other

damage to environment. The required guidelines for spill reduction, communication system and

safety guidelines seem to be available.

Infrastructure facilities include various equipment for storage, processing and metering, as well as

appropriate office budilings. Description of facilities of each field is presented in section “Field

Infrastructure and Hydrocarbon Production”.

9

3. REGION REVIEW

Russia is a major player in the world petroleum industry, being the third largest in the world in oil

production and the second largest in gas production in 2016, according to US Energy Information

Administration (EIA). Volgo-Urals, along with Western Siberia are the largest oil and gas basins

of Russia.

Volga-Urals was the largest region in production through late 1970s, then Western Siberia

became the first. Today this region is second in production, accounting for about 22% of total

Russian production. The giant Romashkinskoye field (discovered in 1948) is the largest in the

region.

Europe and Russia interdependent on export of Russian energy products. Almost 30% of

European oil import and over 30% of natural gas are accounted for Russian supplies. Based on

2015 data, almost 60% of produced oil and over 75% of produced natural gas Russia exports to

Europe. According to the Russian Federation Ministry of Energy, oil and gas yield about 8% of

gross domestic product of Russia. Below is the map showing major production areas.

The territory of the Russian Federation includes a few basins shown above. Three most important

basins by reserves include West-Siberian, Volgo-Urals and Timan-Pechora. VG licenses are

located in the Volgo-Urals oil and gas basin.

The Volgo-Urals oil and gas basin is confined to the eastern part of the East-European platform

and Pre-Urals foredeep; limited in the north and the east by Timan, Urals, in the south borders

the Pre-Caspian syneclise, and in the west – the Voronezhsky arch and Tokmovsko-Syselskaya

arch system. The platform basement is Pre-Cambrian, heterogenic. In the eatern part of the

platform the thickness of the Riphean-Vendian and Paleozoic mantle (with minor occurrence of

Mesozoic) is 9 to 12 km. Sedimentary interval is represented with continental, litoral-marine and

10

marine (clastic and carbonate) formations of the Riphean-Vendian, Devonian, Carboniferous and

Permian age. A number of major archs (Tatarsky, Permsko-Bashkirsky, Zhigulyovsko-

Orenburgsky, etc.), depressions, swells and troughs are identified, which are complicated with

over 2 thousands local uplifts, with the sizes ranging from 1 х 2 to 10 х 50 km and amplitudes

ranging from 10 to 100 m and more. Commercial oil and gas discoveries were made in the

Devonian, Carboniferous and Permian, and oil shows were identified in the Riphean-Vendian

rocks. Productive horizons were identified at the depth ranging from 0.5 to 5 km and more.

Deposits are mainly sheet four-way closure, sheet four-way closure, lithologically truncated,

massive, and, in small number, are faulted. Well rates at normal hydrostatic pressures are medium

(up to 100-200 t/day) and low. As a rule, deposits are developed with formation pressure

maintenance.

The generalized stratigraphic column of the Volgo-Urals basin is shown below:

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Generalized stratigraphic column, Volgo-Urals basin

SYSTEM EPOCH STAGE HORIZON FIELD LITHOLOGY

CR

ETA

CEO

US

Upper

Lower

Albian Uzenskoye Shaley sandstone

Aptian Uzenskoye Sandstone

JUR

ASSIC

Upper Calcareous shale

Middle Shale

Lower Sandey shale

TR

IAS

SIC

Upper N/A

Middle Indersky Uzenskoye Limestone

Lower Limestone/Shale

PE

RM

IA

N

Upper

Tatarian Calcareous shale

Kazanian Limestone

Ufimian Sheshminsky Limestone

Lower

Artinskian Limestone

Sakmarian Limestone

Asselian Limestone

CA

RB

ON

IF

ER

OU

S

Upper

Orenburgian Limestone

Gzelian Limestone

Kasimovian Limestone

Middle Moscovian

Myachkovsky Limestone

Podolsky Limestone

Kashirsky Sandstone

Limestone

Bashkirian Limestone

Lower Serpukhovian

Protvinsky Limestone

Aleksinsky Limestone/Sandstone

Tulsky Sandstone

Bobrikovsky Vostochno-Makarovskoye

Sobolevskoye Sandstone

Radayevsky Shaley limestone

Tournaisian Limestone

DE

VO

NI

AN

Upper

Famennian

Zavolzhsky Limestone

Lebedyano-Dankovsky Limestone

Zadonsko-Yeletsky Dolomite

Frasnian

Yevlansko-Levinsky Vostochno-Makarovskoye

Dolomite Dobrinskoye

Voronensky Limestone

Buregsky Limestone

Mendimsko-Semiluksky Limestone

Domanikovsky Shaley limestone

Sargayevsky Limestone

Kynovsky Sandstone

Pashiisky Sandstone

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4. REGULATORY PROVISIONS

Regulations of Russian Petroleum Industry

Legislative and regulatory framework for the Russian petroleum industry is based (in each case,

as amended from time to time) on the Constitution of the Russian Federation, the Civil Code and

the Law of the Russian Federation “On the Subsoil”, dated February 21, 1992 (the “Subsoil Law”),

Federal Law No. 147-FZ on Natural Monopolies, dated August 17, 1995 (the “Law on

Monopolies”), Federal Law No. 187-FZ, dated November 30, 1995 “On the Continental Shelf of

the Russian Federation”, dated November 30, 1995 (the “Continental Shelf Law”) and Federal Law

No. 225-FZ “On Production Sharing Agreements”, dated December 30, 1995 (the “PSA Law”).

The principal Russian federal authorities regulating the Russian petroleum industry include the

Russian Federation Government, the Ministry of Natural Resources and Ecology, the Federal

Agency for Subsoil Use, the Federal Service for Ecological, Technological and Nuclear Supervision,

the Ministry of Energy, and the Federal Tariff Service. The Ministry of Natural Resources and

Ecology and other agencies under its auspices, including the Federal Agency for Subsoil Use, the

Federal Service for Supervision of Use of Natural Resources, and the Federal Service for Ecological,

Technological and Nuclear Supervision implement and monitor subsoil legislation and are

responsible for granting, monitoring and terminating subsoil licenses. The Ministry of Energy and

the Federal Tariff Service regulate and oversee the oil transportation. among other things.

Subsoil Licensing

Rights to explore and produce oil and gas are granted under mineral licenses issued by THE

Federal Agency for Subsoil Use (Rosnedra). Three relevant categories of subsoil license are as

follows:

1. Licenses for the exploration and assessment

2. Licenses for the production of natural resources

3. Combined licenses for the exploration, assessment and production of natural resources.

The maximum term of an exploration license is five years (or 10 years for offshore exploration),

whereas a production license may be issued for the useful life of the mineral reserves field,

calculated on the basis of an exploration and production feasibility study that ensures the rational

use and protection of the subsoil. The Subsoil Law also provides that the license to use a field

may be extended by the relevant authorities at the request of the license holder, if an extension

is necessary to finish production in the field, provided that the license holder has not violated the

terms of its license. To date, the major Russian oil companies have not experienced significant

problems with the extension of their licenses.

Production licenses and combined exploration and production licenses are granted following a

tender or auction conducted by the Federal Agency for Subsoil Use. In a tender process, the

bidder who submits the most technically competent, financially attractive, and environmentally

sound proposal that meets published tender terms and conditions wins. In an auction process,

the bidder who submits the highest price wins. Production licenses may also be issued, without

13

holding an auction or tender, to holders of exploration licenses who discover mineral resource

deposits through exploration work conducted at their own expense. Offshore licenses may be

granted without a tender or auction in certain cases.

Licenses may be transferred only in certain limited circumstances under the Subsoil Law, including

the reorganization or merger of the license holder or in the event that an initial license holder

transfers its licenses to its subsidiary, its parent company, or a “sister” company, provided that

certain conditions established by the Subsoil Law are met. The transfer of licenses for federal

plots deemed to be of strategical significance to entities under non-Russian participants is

generally prohibited.

A license holder has the right to develop and sell oil produced from the license area that it owns.

The Russian Federation, however, retains ownership of all subsoil resources at all times, and the

license holder has rights to the crude oil only when produced, provided that such right is

contemplated by the relevant licenses. Licenses generally require the license holder to make

various commitments, including the following:

1. Extracting and agreed target amount of reserves annually

2. Cunducting agreed drilling and other exploration and development activities

3. Protecting the ecology in the fields from damage

4. Providing geological information and data to the relevant authorities

5. Submitting formal progress reports to regional authorities on a regular basis

6. Paying the mineral extraction tax when due

The Federal Service for Supervision and Use of Natural Resources and its regional divisions

monitor license holders’ compliance with the terms of their licenses and subsoil legislation. A

license holder can be fined for failing to comply with the terms of its licenses, and a license can

be revoked, suspended, or limited in certain circumstances, including the following:

1. Breach or violation by the license holder of material terms and conditions of the license

2. Repeated violation by license holder of the subsoil regulations

3. Failure by the license holder to commence operations or to produce the required volumes

as specified in its license

4. An emergency situation

5. A direct threat to the life or health of people working or residing in the area affected by the

operations under the license

6. Liquidation of the license holder

7. Failure to submit reporting data in accordance with applicable law

In addition, under the Subsoil Law, a license automatically terminates in certain cases stipulated

in the license or in the event of a transfer of the license in breach of the procedure set out in the

Subsoil Law.

Upon the expiry of a license or termination of subsoil use, all infrastructure facilities in the relevant

license area, including underground infrastructure facilities, must be removed or properly

abandoned. All site facilities, including oil wells, must be maintained so that they are safe for the

14

surrounding population, the environment, buildings, and other infrastructure facilities.

Abandonment procedures must also ensure the conservation of the relevant oil and gas fields,

mining facilities and wells.

Land Use Permits and Ground Allotments

In addition to a subsoil license, surface rights to the license area are required. Subsoil licenses do

not grant any surface rights, which must be obtained separately from the licenses. Most land in

the Russian Federation is owned by federal, regional, or municipal authorities that can sell, license

area, or grant other use rights to the land to third parties through public auctions or tenders or

private negotiations.

Surface rights are granted typically for specified areas upon the submission of standardized

reports, technical studies, pre-feasibility studies, budgets, and impact statements. Documents that

grant surface rights generally require that the holder make license area payments and return the

land plot to a condition sufficient for future use, at the license holder's expense, upon the expiry

of the permit.

Payments for Subsoil Use

Effective January 1, 2002, the previous system of subsoil use payments was modified by merging

royalties, excise taxes, and mineral restoration payments into a single tax called the mineral

production tax. In addition, subsoil users are required to make or pay the following:

1. One-time payments in the circumstances specified in the license

2. Regular payments for subsoil use, such as rent payments for the right to conduct

prospecting/appraising and exploration work

3. Payments to the state for geological subsoil information

4. Fees for the right to participate in tenders and auctions

5. Fees for the issuance of license

The rates for such payments are generally set forth in the relevant license by the federal

authorities within a range of minimum and maximum rates established by the Subsoil Law.

Environmental Requirements

Russian environmental law establishes a “pay-to-pollute” regime administered by the Federal

Service for Ecological, Technological, and Nuclear Supervision and local authorities. Fees are

assessed both for pollution within the agreed-on emissions and effluents limits and for pollution

in excess of these limits. There are additional fines for certain other breaches of environmental

regulations. Under the environmental protection law, compensation must be paid to the budget

for all environmental losses caused by pollution. The prosecutor's office or other authorized

governmental bodies may bring proceedings if there is a dispute over losses caused by breaches

of environmental laws and regulations; there is no right to seek damages for such losses in civil

law. Courts may impose clean-up obligations subject to the agreement of the parties in lieu of or

in addition to imposing fines.

15

Exploration licenses and production licenses generally require license holders to agree to certain

environmental commitments. Although such commitments may be stringent in a particular

license, the penalties for failing to comply with clean-up requirements are generally low. Subsoil

users are also subject to obligations concerning the decommissioning of operational facilities and

the remediation of soil or groundwater at their facilities when they cease operations.

16

Licenses of Volga Gas plc

VG has provided information regarding each licenses, which it holds. GeoStream has not

independently verified the data on the licenses. Our reserve estimates are not limited by the

license expiration date, because VG expects its licenses to be updated before their expiration.

Summary of license’s expiration dates is shown below:

ASSET OPERATOR INTEREST

(%) STATUS LICENCE EXPIRY DATE

Russia, Sobolevskoye VolgaGaz pls 100 Development August 2032

Russia, Dobrinskoye VolgaGaz pls 100 Development January 2026

Russia, Vostochno-Makarovskoye VolgaGaz pls 100 Production June 2026

Russia, Karpenskiy, Uzenskoye VolgaGaz pls 100 Development July 2021

5. OVERVIEW OF ASSETS

Vostochno-Makarovskoye and Dobrinskoye Fields

Administratively, the Vostochno-Makarovskoye and Dobrinskoye fields are located within the

Zhirnovsky district, Volgograd region, near the north-eastern boundary with the Saratov region.

The Vostochno-Makarovsky and Dobrinsky license areas in accordance with the geological oil

and gas zonation are related to the Lower-Volga oil and gas region (OGR). The Vostochno-

Makarovskoye field was discovered in 1989 as a part of the single Makarovskoye field. The

Dobrinskoye field was discovered in 1987 in prospecting Well No.22, which was drilled in the crest

of reef uplift. Geologically, the structure include the Paleozoic, Mesozoic and Cenozoic.

Commercial presence of gas is confined to the Bobrikovsky sandstones and reef Upper Frasnian,

Yevlanovsko-Livensky age.

The field is located within the Aleshnikovskaya prospect included into the Dobrinsko-Ilovlinskaya

reef system. The geological structure of the Vostochno-Makarovskoye uplift was mapped on nine

reflectors. In 2007 3D seismic acquisition was performed in the license area. In this year, only 2D

seismic acquisition was performed in the Dobrinskoye field. The survey resulted in structure

building on five reflectors.

The field well count includes:

Vostochno-Makarovskoye - 6 wells

Dobrinskoye – 7 wells

By type of reservoir, the Yevlanovsko-Livensky gas/condensate deposit of the Vostochno-

Makarovskoye field is massive, with water source. The deposit height to the employed contact is

17

187.3 m. The size of the Yevlanovsko-Livensky deposit is 3.9 х 1.7 km. Reservoir rock is composed

of dense, hard and vuggy dolomites.

The Yevlanovsko-Livensky horizon is penetrated in all wells. To the southwest of the crestal part

of the uplift the reefogenic productive interval is replaced with denser, tight carbonates. The

gross thickness of the Yevlanovsko-Livensky horizon ranges from 28.4 m to 312.9 m, averaging

156.6 m. The gas net pay thickness ranges from 5.4 m to 167.5 m. The average gas net pay

thickness is 72 m. Attachment 3 shows the structure map and the gas isopach map of the

Yevlanovsko-Livensky deposit.

The Yevlanovsko-Livensky interval was tested in all wells drilled at the Vostochno-Makarovskoye

field. Performed well tests allowed for adequate update of the deposit geometry, clarify the

location of GWC, and study the fluid properties.

Drill stem test data on Well 42 at the interval of 2,824-2,849 m (-2,533.1-2,558.0 m subsea)

showed that reservoir rock is wet. By log data confirmed by test data Well 62 had no reservoir

encountered. Test data on Wells Nos. 30 Dobrinskaya, 1, 2 and 4, Vostochno-Makarovskoye,

proved the presence of gas-bearing reservoir rocks. The location of GWC is determined at -

2,465.3 m subsea by log data on Well No. 4, Vostochno-Makarovskoye field. By IL, LL and LLS

(large sonde) data resistivity is lower at this depth. The employed location of GWC is confirmed

by test data on Well No. 4.

By reservoir type, the deposit in the Bobrikovsky sandstones, Vostochno-Makarovskoye field, is

sheet, four-way closure, with water source. The size of the Bobrikovsky deposit is 1.4 km х 1.6

km.

Productivity of the Bobrikovsky horizon is confined to clastic reservoir rocks (sandstone and

siltstone). Two reservoirs are identified in the horizon. The net pay thickness of the upper I

reservoir ranges from 3 m to 3.7 m. The I reservoir is continuous and occurs in all wells. Core

analysis indicated that sandstones of I reservoir are of the best reservoir properties. The lower II

reservoir is composed of sandstone of possibly bar type. The net pay thickness of the II reservoir

ranges from 28.3 m to 37.5 m, with the gas net pay thickness of 8.7 m. Attachment 4 shows the

structure map and the gas isopach map of the Bobrikovsky deposit. The Bobrikovsky horizon was

tested in open hole in all the wells, except for Well No. 62 Dobrinskaya. GWC is employed at -

1,627.2 m subsea, corresponding to the base of reservoir rock identified in Well No. 42.

The commercial presence of gas determined by test data on Well No. 22 at the Dobrinskoye field

is related to the Yevlanovsko-Livensky. In productive Well No. 26 the gas net pay thickness is up

to 57.9 m, whereas in Well No. 22 – 34.4 m; in other wells of the field the reservoir is wet. The

gross thickness of the Yevlanovsko-Livensky within the field is 42.2 m, with the net pay thickness

of reservoir rocks of 31.8 m. The average gas net pay thickness for the deposit is 31.6 m.

By log data on the wells, reservoir rocks of reef type have sufficient homogeneity, without tight

streaks. Conventionally, the stratification and continuity degrees (analog to net-to gross ratio for

carbonate reservoir rocks) are employed to be 1.

18

The gas-water contact was determined by both test, and log data. First, Well No. 22 a formation

tester tested 20 Mm3/day of gas at the drawdown of 5.7 MPa from the interval of 2,613 - 2630 m

(- 2,387.9 – 2,404.9 m subsea), and then 211 m3/day of formation water at the drawdown of 8.9

MPa from the interval of 2,629 – 2,640 m (– 2,403.9 – 2,414.8 m subsea). In cased hole the well

tested 113 Mm3/day of gas and 63 m3/day of condensate through a 8-mm schoke from the

interval of 2,595 – 2,615 m (-2,369.7 - 2,391.9 m subsea). By log data on Well No. 22 the gas-

water contact was established at 2,624 m (-2,404 m subsea). Well No. 26 tested (in open hole)

90 Mm3/day of gas, and 40 m3/day of condensate through a 7-mm choke from the interval of

2,580 – 2,610 m (-2,337.7 to 2,367.7 m subsea).

The deposit is massive, four-way closure, with the gas area of 2.22 km2 and the hight of 58 m.

Proved and probable reserves were estimated for these fields. As the Vostochno-Makarovskoye

and Dobrinskoye fields are in pressure communication, it should be expected that the existing

wells are draining all the volume of original gas in-place. Gas reserves are subject to heterogeneity

of productive reservoir rock. Thus, in addition to proved producing reserves, probable reserves

were estimated, which account for uncertainty of heterogeneity of reservoir rock defining various

sweep efficiencies for gas displacement with water.

Drilling of one new well is planned in the Dobrinskoye field.

Additionally, the LPG (Liquid Petroleum Gas) reserves were estimated. LPG is assumed to produce

at ther LPG plant, which technical characteristics and construction stages are shown in Section 6,

and the production cost - in Section 7.

19

Sobolevskoye Field

The field was discovered in 1991. Administratively, the Sobolevskoye field is located in the

Fedorovsky district, Saratov region, 90 km southeast of Saratov. The activity area is related to the

Stepnovsky oil and gas district, Lower-Volga oil and gas region, Volgo-Urals oil and gas basin.

Within the license area boundary there are the Tambovskoye and Sobolevskoye fields. In close

proximity to the license area a number of fields were discovered, with deposits confined to the

Devonian (Severo-Vasnetsovskoye, Vasnetsovskoye, Lyubimovskoye, Mechetkinskoye, etc).

The commercial productivity within the Sobolevskoye field was established in clastic reservoirs of

the Bobrikovsky horizon, Vizeisky stage, Lower Carboniferous system.

Oil at the rate of 326.9 m3/day was tested from the Bobrikovsky at the interval of 2,641.0-2,660.0

m. Natural flow of 193 m3/day of oil and 61.4 Mm3/day of gas was tested in cased hole through

a 8-mm choke from the intervals of 2,647.2-2,648.2 and 2,649.4-2,653.0 m (-2,560.9-2,561.9 and

-2,650.8-2,566.7 m subsea, respectively). The measured reservoir pressure is 29.06 MPa.

The oil deposit in the Bobrikovsky sandstones is sheet, four-way closure, with the size of 1.3 km х

0.76 km and the hight of 26.7. Attachment 5 shows the structure map and the gas isopach map

of the deposit. The net pay thickness penetrated in Well No. 11 is 8.9 m, whereas the oil net pay

thickness is 5.0 m. The water-oil contact is established at the depth of – 2,566.7 m subsea, at the

lower perfs of the perforated interval which tested hydrocarbons.

The Sobolevskoye field is planned to be developed with a side-track in Well No. 11.

Uzenskoye Field

The field is located within the Karpensky license area in the Saratov region. It was discovered in

1967 by drilling the exploration Well No. 22, which tested oil from the Inderian stage, Middle

Triassic. After additional exploration in 2008, oil deposits were discovered in the Aptian and Albian

stages, Lower Carboniferous. Administratively, the Uzenskoye field is located in the Saratov

Zavolzhye area, within the Pitersky and Novouzensky districts, Saratov region, 22.5 km northwest

of the district center of Novouzensk. The field is 220 km southeast of the regional center of

Saratov.

As of the date of report there are 18 wells drilled in the field.

Reginal tectonically, the Uzenskaya supra-salt structure is located in the northwestern part of the

Precaspian depression, in the zone of salt tectonics. It is confined to to zone of submerged salt

domes.

The Uzenskoye field is located within the North-Caspian oil and gas region. Within this territory

the following fields were discovered in the Upper Jurassic and Triassic: gas – Talovskoye,

Starshinovskoye and Sprotivnoye, and oil - Uzenskoye and Kurilovskoye. All these fields are

related to structures of submerged salt domes with Mesozoic draping.

20

The oil deposit of the Indersky horizon is located in the northern block of the Uzenskoye uplift

and confined to carbonates. By type of structure, the deposit is sheet, four-way closure,

tectonically truncated in the south. The fluid phase state at reservoir conditions is one-phase oil.

The deposit is 0.4 × 1.4 km in size and 45 m in height. The productive reservoir is composed of

ligh grey, fractured limestone, dense in places, hard, with leached porous zones along fractures.

By log data on Wells Nos. 1 and 22 the Indersky reservoir rock is oil-bearing, whereas in Wells

Nos. 2 and 24 is wet, which was confirmed by test data. Oil rates were tested. Well No. 1 tested

(DST) 125.4 m3/day of oil at reservoir pressure of 91.2 atm (by build-up pressure test data). After

perforating, swabbing allowed for recovery of 54.5 m3 of fluid (44 m3 of oil).

Wells No. 22 tested 2,16 м3/day of oil through a 2-mm choke. Then the well tested at the

estimated rate of 2.88 m3/day of oil through a 3-mm choke over 3 hours and died. The lowest

known oil was established at -945 m subsea.

The commercial presence of oil of the K1a sand was established with log data and confirmed with

test data in open hole and cased hole after perforating. Oil-bearing reservoir rock was penetrated

in five wells. Well No. 3 was perforated at the interval of -913.5 – 921.9 m subsea and tested 72

m3/day of oil through a 6-mm choke at the reservoir pressure of 10 MPa. After perforating at

the interval of -956.0 – 961.0 m subsea Well No. 4 tested 75.6 m3/day of oil through a 6-mm

choke. Well No. 5 was perforated at the interval of -902.3 – 907.3 m subsea and tested 71 m3/day

of oil through a 7-mm choke at the drawdown of 0.2 MPa.

The water-oil contact (WOC) in the Aptian deposit was established at -966.7 m subsea. Test data

confirm the location of WOC.

The deposit confined to the K1a reservoir is sheet, four-wau closure, tectonically and lithologically

truncated. In the north the deposit is limited with a steep wall of a salt dome. Also, the deposit is

broken with mostly subparallel faults into partially permeable blocks. The deposit is 0.6 х 2.2 km

in size and 100 m in hight. The average oil net pay thickness is 6 m.

The presence of oil and gas of the productive reservoir of the Albian substage was established by

log data and confirmed by test data on Wells Nos. 4 and 5 (DST) and test data on Well No. 8.

Well No. 4 was tested in open hole in two intervals. The well tested low-gassy oil at the estimated

rate of 31.9 m3/day (first cycle) from the interval of -690.0 – 728.0 m subsea, and formation water

at the rate of 344.4 m3/day from the interval of -753.0 – 789.6 m subsea. Well No. 5 tested oil

and mud filtrate at the estimated rate of 42 m3/day from the interval of -677.3 – 733.3 m subsea.

Well No. 8 was drill stem tested at the estimated rate of 209.9 м/3day of oil from the Lower Albian

(open hole) at the interval of -712.6 – 729.4 m subsea. Well No. 8 was perforated at -708.6-714.6

and -718.6-726.6 m subsea, and tested 5.4 m3/day of oil and 1.1 m3/day of water at the drawdown

of 7.1 atm and the reservoir pressure of 76.08 atm.

WOC in the Lower Albian is confirme with lower resistivity on electric log curves in Well No. 5 at

the depth of 805.4 m and in Well No. 9 at the depth of 805.6 m (-730.7 m subsea). A gas cap

21

was discovered in a single fault block penetrated with well No. 9-bis. The gas-oil contact (GOC)

in the block is established at -720 m subsea.

The deposit of the K1al1 reservoir is two-phase – oil, with a gas cap. By structure, the deposit is

massive, lithologically and tectonically truncated. It is 0.8 х 2.2 km in size and 40 m in height. The

average oil net pay thickness of the deposit is 6.7 m. The gas cap is 130 x 600 m in size and 6 m

in height.

It is expected to drill two new wellbores – a side-track and a lateral section to recover remaining

reserves. Also, it is planned to put into production the side-tarck of Well 4-ST drilled to the Albian.

In 2016 Geomage reprocessed and reinterpreted 3D seismic data resulting in substantial

clarification of the tectonic structure of the field. Attachments 6-8 show the structure map and

the gas isopach map of oil deposits of the Uzenskoye field.

Original hydrocarbons in-place was evaluated the the use of volumetric method and 3D

geological model based on 2016 seismic data. Only proved reserves were estimated for this field.

Proved developed reserves were confined to well locations 500 meters of the existing producing

wells and wells which tested commercial rates. Proved undeveloped reserves were assigned 1,000

meters of the drilled wells. As proved area covers almost all the deposit area, probable reserves

were not estimated.

The cumulative oil production was 2,530 Mbbl as of December 31, 2016.

6. FIELD INFRASTRUCTURE AND HYDROCARBON PRODUCTION

6.1 ”Gaznefteservis” – Dobrinskoye and Vostochno-Makarovskoye Fields

Hydrocarbon Production and Transportation to CGTF.

Development Well Count, Vostochno-Makarovskoye Gas/Condensate Field:

Wells Nos. 1 and 2 are producing from the Yevlanovsky-Livensky deposit.

Well No. 4 is under infrastructure construction after reactivation by side-tracking.

Well No. 30 is producing from the Bobrikovsky deposit.

Well No. 3, drilled and completed to the Yevlanovsky-Livensky deposit, is waiting on unploading

and hook-up after drilling.

There are also two exploratory wells (Nos. 42 and 62) within the license area. They were drilled

in 1990 and plugged and abandoned due to geological reasons.

22

Well Count, Dobrinskoye Gas/Condensate Field:

Total development well count includes 2 wells:

Wells Nos. 22 and 26 are producing from the Yevlanovsky-Livensky deposit.

The license area also has three exploratory wells (Nos. 13, 12, 21 Dobr.) plugged and abandoned

after drilling due to geological reasons, as well as well No. 23 restored by LLC “GNS” from

abandonment after drilling due to geological reasons.

Well No. 23 is now disposal for injection of separated and sewage water into the Myachkovsky-

Podolsky carbonates.

Hydrocarbon Production and Transportation

Now hydrocarbon at the Vostochno-Makarovskoye gas/condensateом field are produced from

three producers (Nos. 1, 2, 30), which optimum productivity is as follows:

- Well No. 1: gas rate of 330-350 Mm3/day at drawdown of 2.5-3.0 atm;

- Well No. 2: gas rate of 100-120 Mm3/day at drawdown within 50 atm;

- Well No. 30: gas rate of 120-300 Mm3/day at drawdown within 20 atm;

Gas/condensate system produced from the wells of the Vostochno-Makarovskoye field is moved

to the Complex Gas Treatment Facilities (CGTF) site of the Dobrinskoye gas/condensate field

through a 5.8-km main gas gathering line. At CGTF the system is separated into gas and liquid

components. Gas component is treated to the required conditions and sold to the gas

transportation system of LLC “GazproMtonnesransgaz-Volgograd”.

Liquid phase is stabilized and trucked from the CGTF site.

Hydrocarbon from the Dobrinskoye gas/condensate field are produced from two producers (Nos.

26, 22). Gas/condensate system from the wells through separate flow lines is also moved for

further treatment at the CGTF site of the Dobrinskoye gas/condensate field.

Early in 2017, after commissioning the new drilled well No. 4 at the Vostochno-Makarovskoye

gas/condensate field, it is planned to increase daily hydrocarbon production.

To date, the daily production from the two fields is as follows (considering the existing

hydrocarbon treatment and purification technology):

- 940-950 Mm3 of gas

- 220-230 t of condensate

23

When Wells Nos. 26 and 2 are commissioned, the estimated daily production in 2017 may amount

to:

- 1,124 Mm3 of gas

- 300 t of condensate

The CGTF process infrastructure throughput is enough for handling such volumes of hydrocarbon.

Infrastructure for Hydrocarbon Treatment

Dobrinskoye Field

The Complex Gas Treatment Facilities (CGTF) of the Dobrinskoye gas/condensate field is designed

to produce:

Sales gas in accordance with the requirements of industry state standard OST 51.40-93 “Combustible Natural Gases Sold Through Main Pipelines”. It is moved through a pipeline

to the branch gas pipeline to Zhirnovsk and then to the OJSC “Gazprom” transportation

system;

Stable condensate in accordance with the requirements of the industry state standard OST 51.65-80 “Stable Gas Condensate”.

Year of CGTF commissioning: 2009.

Year of refurbishment: 2013.

Infrastructure History, Dobrinskoye Gas/Condensate Field:

1. Infrastructure construction at the Dobrinskoye gas/condensate field was performed in

accordance with the design “Infrastructure, Dobrinskoye Gas/Condensate Field”. The design was

compiled by LLC “Volgogradnefteproekt” in 2008. In 2008 the Saratov Affiliate of the

“Glavgosekspertiza of Russia” Federal State-Funded Institution issued an approval No. 0480-

08/SGE-0089/02 in 2008.

The design also included the final design concept for line section and custody sales point “Gas

Pipeline, Dobrinskoye field to Branch Pipeline to Zhirnovsk” compiled by LLC “Gaznadzor”,

Volgograd Gas Technical Center.

2. In 2012 “Retrofitting and Upgrading of Sulfur Recovery Unit, CGTF, Dobrinskoye

Gas/Condensate Field” was compiled which allowed to integrate the desulfurization unit into the

existing process. The documentation was compiled by LLC “VolgaTEKinzhiniring” and was

approved after industrial safety peer review (Reg. No. 39-PD-00575-2012).

24

3. Over the period of 2013 - 2016 a staged refurbishment, retrofitting and upgrading was

performed at CGTF of the Dobrinskoye gas/condensate field. Engineering work was performed

by LLC “VolgaTEKinzhiniring”.

The design documentation “Refurbishment of CGTF, Dobrinskoye Gas/Condensate Field” was

approved by “Glavgosekspertiza of Russia” Federal State-Funded Institution (No. 961-13/GGE-

8757/02) and permit for construction No. VLG-3000066-UVS/S). The design documentation was

compiled considering with work performed under the documentation “Retrofitting and

Upgradingе of CGTF, Dobrinskoye Gas/Condensate Field (Sulfur Recovery Unit, Condensate

Stabilizer Unit, Low-Temperature Separator)”. The documentation passed the industrial safety

peer review (Reg. No. 39-PD-00575-2012).

Commissioning of refurbished, retrofitted and upgraded facilities started in 2013. As of now, the

following stages of refurbishment were completed:

Stage 1 “Sulfur Recovery System and Condensate Stabilizer Unit” Stage 2 “Flaring System” Stage 3 “Low-Temperature Separation” Stage 5 “Boiler No. 2”

4. In 2013, to improve CGTF performance safety, the documentation “Retrofitting and Upgrading

of MGS Blocks and Absorbers with Inhibitor Proportioning at CGTF, Dobrinskoye Gas/Condensate

Field” was compiled by LLC “VolgaTEKinzhiniring” and passed the industrial safety peer review

(Reg. No. 39-PD-12042-2013).

5. In 2015, to improve sulfur recovery process, the documentation “Retrofitting and Upgrading of

Sulfur Recovery Unit at CGTF, Dobrinskoye Gas/condensate field. Replacement of “Desulfon-

SNPKh-1200” to SULFANOX, ASULPHER H2S and Mercaptane Scavanger” was compiled by LLC

“VolgaTEKinzhiniring: and passed the industrial safety peer review (Reg. No. 39-TP-10496-2015).

25

Fig. 6.1 – Complex Gas Treatment Facilities (CGTF), Dobrinskoye gas/condensate field.

According to the design CGTF includes the following main facilities:

Two trains for gas treatment, with the throughput of 800 Mnm3/day (sales gas) One train of gas condensate stabilization, with the throughput of 50 m3/day (stable

condensate)

One train of absorbent recovery

26

Flare units: two high-pressure flares (FVD-1 and FVD-2), low-pressure flare (FND), horizontal flare (GFU-5)

Two module corrosion inhibitor proportioning units (BDR, BDR-2) Two module methanole proportioning units (BDM, BDM-2) Fuel gas treatment module (FGTM) Closed drainage system with three drainage vessels Custody sales gas metering unit (CSGMU) Bottle storage: 10 oxygen cylinders, 10 nitrogen cylinders Propane cylinder storage Wharehouse, including methanole storage, shelted wharehouse, packaged chemicals

storage

Steam condensate drum Nitrogene ramp Two boilers

The natural gas treatment train from wells of the Dobrinskoye gas/condensate field includes:

H2S recovery unit, including S-1 and S-2 input and metering separators, A-1 and A-2 absorbers and N-6/1, 2 pumps

Low-temperature separator module, including MGS-1 mobile gas separator, TO-5/3 gas-gas exchanger, MGS-2 low-temperature separator, TVT triple-flow vortex tube

The natural gas treatment train from wells of the Vostochno-Makarovskoye gas/condensate field

includes:

Input unit, including pressure reducer unit, S-3 and S-4 separators

Sulfur recovery unit, including A-3 and A-4 absorbers, N-7/1, 2 pumps and TO-8 and TO-9 heat exchangers

Low-temperature separator module, including S-5 input separator, TO-6 gas-gas exchanger, S-7 low-temperature separator

The combined condensate stabilization train includes:

TO-5 heat exchanger and splitter/weathering tank

Stable condensate storage, including four 63-m3 tanks (E-1/1, E-1/2, E1/3, E-1/4), a two-stack truck loading point and a process pumping unit

Service tank site, including three 200-m3 tanks (E-3/1, E-3/2, E-3/3)

The absorbent recovery train includes:

E-4 mud trap, TO-1 and TO-2 heat exchangers, E-2 absorbent degasser, terminal separation units (KSU-1, 2)

27

63-m3 absorbent storage tank (E-1/4)

CGTF Loading

Gas Treatment Train from the Dobrinskoye Gas/Condensate Field:

At the module input unit of the Dobrinskoye gas/condensate field the pressure of gas/condensate

system, feeding the unit through flow lines from wells Nos. 22 and 26, is reduced (choked) with

choke chambers to 12.0 MPa. Then the gas/condensate system is fed to the natural gas

desulfurization unit, including an input three-phase separator and a downflow pack absorber.

The estimated throughput of the sulfur recovery unit by H2S is 3.8 kg/hr at 10 Mnm3/hr of gas.

Gas Treatment Train from the Vostochno-Makarovskoye Gas/Condensate Field:

At the input unit from the Vostochno-Makarovskoye gas/condensate field the pressure of

gas/condensate system is fed to the unit through flow lines from wells Nos. 1, 2, 3, 4 and 30D, is

reduced (choked) with manually-driven pressure reducers to 8,0 MPa. Then the gas/condensate

system is fed to the S-3 and S-4 input separators and later – to the absorber site for H2S recovery.

The estimated total throughput of the sulfur recovery unit by H2S is 62.6 kg/hr at 33.3 Mnm3/hr

of gas.

Own stable condensate with addition of SULFANOX or Reaton-21-2K H2S scavenger is sued as

an absorbent. The H2S-loaded absorbent is discharged at absorber base.

H2S-stripped natural gas after sour component recovery is fed to the low-temperature separation

stage to to treat it to transportation conditions to consumers as sales natural gas meeting the

requirements of the industry state standard OST 51.40-93.

Combined Absorbent Recovery Line:

Absorbent (stable condensate) is recovered at lower pressure and higher temperature. The

system equilibrium is broken at changed thermodynamic conditions and is accompanied with

separation of components absorbed from the gas system.

Combined Condensate Stabilization Line:

Gas condensate is output from the base of the S-1, S-2, S-3 and S-4 input separators from the

MGS-1 and MGS-2 of the LTS unit of the Dobrinskoye train, from S-5 and S-7 of the LTS unit of

the Vostochno-Makarovskoye train, combined and fed to stabilization, which equipment includes

the TO-5 heat exchanger, splitter/weathering tank, stable condensate storage and condensate

service tanks.

Stable condensate from the service and storage tanks is loaded to users.

28

The treated gas of the Dobrinskoye train and treated gas of the Vostochno-Makarovskoye train

are combined and fed to the custody gas metering unit and further to the branch gas pipeline to

Zhirnovsk.

Fig. 6.2 – The Complex Gas Treatment Facilities (CGTF), Dobrinskoye and Vostochno-

Makarovskoye gas/condensate fields.

Construction of Liquified Petroleum Gas Plant

To improve the economic efficiency of the field development, the Company implements the

Liquified Petroleum Gas Plant (Unit) construction project on the basis of CGTF.

The plant (unit) construction is based on designing concepts compiled by LLC “Aerogaz”.

LLC “Aerogaz” performed engineering designing work for the following faclities:

Low-pressure gas recovery unit at CGTF of the Dobrinskoye field (condensate

stabilization unit)

Fractionation unit (module) at the CGTF of the Dobrinskoye field

The implementation of the design concepts will allow:

29

To ensure for production of commercial propane/butane mix to the amount of

over 4 t/hr (35,000 m3/year) at the input gas rate of 40 Mnm3/hr; (350,000

Mm3/year)

To have additional gas sales revenue due to flare gas ejecting

The following new modules will be installed in addition to the existing CGTF equipment:

- condensate stabilization module

- ejection unit

- fractionation module

- commercial propane/butane mix stirage and loading module

as well as the LTS module will be upgraded

The process flow diagram of the LPG unit envisages that gas/liquid system from the flow lines

enters for separation to the S-3 and S-4 input separators at 10.0 MPa. After the input seperators

gas is split in equal proportions and fed upstream of the A-3 and A-4 absorbers for sulfur

recovery. After the absorbers gas is fed to the LTS and ejection units. To mitigate hydrate build-

up in gas flow downstream absorbers, methanole proportioning is envisaged. Condensate

recovered in these modules is fed to the fractionation module to produce target components.

Condensate downstream the input separators is fed to the condensate stabilization module.

The cost estimation for constriction of the LPG units was provided by the Company and is shown

in Table No. 6.1.

30

Table No. 6.1. Cost estimation.

Cost Estimation '000 RUR

Equipment

Condensate stabilization unit 30 000

Fractionation unit 25 000

Ejection unit 55 000

Low-temperature separation unit 15 000

Project 10 000

Engineering works 25 000

Construction works 50 000

Storage tanks 30 000

Other auxiliary facility 15 000

Total costs ex VAT 255 000

VAT 45 900

Total with VAT 300 900

31

The milestone schedule for designing, obtaining required permits and approvals, procurement

and logistics, construction provided by the Company is shown in Figure 6.3.

Fig. 6.3 – Construction milestone schedule.

The schedule provides for the completion of construction and commissioning and adjustment

work in July 2017.

6.2 Prikaspiiskaya Gas Company. Karpensky License Area. Uzenskoye Oil Field

Production and Infrastructure

Gas/liquid system from Wells Nos. 3, 4, 5, 6-bis of the Uzenskoye field is fed to the Oil Gathering

Station (OGS).

The Uzenskoye OGS facilities include the following:

- Flow line (oil pipeline) from Wells Nos. 3, 4, 5, 6-bis and 8

- Process lines at OGS

- 2 horizontal separator

- oil heater

- 11 horizontal storage tanks (3 x 75 m3 and 8 x 100 m3)

- 25-m3 diesel fuel storage tank

- 3 truck oil loading platforms, including two platforms equipped with DS-125 and Sh-80

gear pump, one for each

- 4 gas/piston power stations (2 x GPES-100 kW and 2 x GPES-200 kW)

- 2 diesel power stations (60 kW)

- 2 flare units

- 2 drainage tanks (5 m3 and 75 m3)

- 50 m3-fire tank

Contracts

PFD and P&ID layout

Equipment ordering

Skids production and shipping

Project scketches

RTN assesment

Construction layouts

Additional equipment

RTN paper work

Construction

Production roll-out

May Jun Jul

2016 2017

Nov Dec Jan Feb Mar Apr

32

Wells Nos. 3, 5 and 6-bis produce oil with density of 0.805 g/cm3 (легкая) and Well No. 4

produces heavy oil with density of 0.889 g/cm3. Well performance is as follows:

- Well No. 3 produces on ESP at the average daily oil rate of 100 m3/day and water cut

of 60 %

- Well No. 5 produces on ESP at the average daily oil rate of 120 m3/day and water cut

of 50 %

- Well No. 6-bis produces on natural flow at the average daily oil rate of 40 m3/day and

no water cut

- Well No. 4 produces intermittently at the average daily oil rate of 6 m3/day and water

cut of 4 %

The OGS includes the following processes:

- Gathering production from Wells Nos. 3, 4, 5 and 6-bis of the Uzenskoye field to storage

tanks

- Gravity settlement and discharge of water to the drainage tank from production of Wells

Nos. 3, 4 and 5

- Pumping water from OGS and water injection on Well No. 8

- Pumping, demulsifier proportioning, heating, gravity settlement and discharge of

separated water

- Truck loading of treated oil at the oil loading points Nos. 1, 2 and 3

Fluid production from Wells Nos. 3, 4 and 5 at the pressure of 5 кg/cm2 through TN-90-V, 90-

mm x 12 mm polyethylene sheathed high-pressure pipelines is fed to the NGS-1-1.6-1200 No. 2

oil/gas separator. Production from Well 6-bis through a pipeline of the same brand is moved to

the NGS-1-1.6-1200 No. 1 oil/gas separator. Associated petroleum gas is separated from oil in

the separators. Fluid charge and pump-off levels in the separators are controlled with automation,

namely, level gauges, RUPT float level gauges and diaphragm actuator valves. To prevent the

separators from overpressurizing, they are equipped with SPPK-4(80х16) safety valves. Oil from

the separator No. 2 at the pressure of 1.5-2.0 кg/cm2 through 90-mm x 10-mm, steel pipelines is

fed into 100-m3 storage horizontal vessels Nos. 5 and 6. Oil from the separator No. 1 is fed only

into the 100-m3 vessel No. 7.

The main volume (95%) of separated associated gas at the pressure of 1.5 кg/cm2 through a 50-

mm x 3.5-mm gas pipeline is fed to the gas piston power stations (GPES-100 and GPES -200) to

generate 50-Hz, three-phase alternating current, 400 V, for OGS power supply. In total, the GPES

rated gas consumption is 240-260 m3/hr. Rated horsepower of generated electricity is 600 kW.

The remaining associated gas (5%) is fed to the flare units for flaring. The flared gas is metered

with SVG TM-1600, Nos. 1 and 2 gas meters.

All oil production is subject to mandatory accounting. To this end, all the intake tanks have

strapping tables made by the Saratov Center of Standartization, Metrology and Certification. Fluid

(oil) levels in the intake tanks are determined each four hours with standard MShS-3.5 thief rods

33

and a strapping table, with subsequent entry into oil production accounting log in accordance

with the “Manual for Oil Accounting at Oil and Gas Production Associations” (RD 39-30-627-81).

Production from Wells Nos. 3, 4 and 5 is settled, and water is alternatively discharged from the

Tanks Nos. 5 and 6. Water by gravity is fed through 90-mm x 10-mm, steel pipelines equipped

with a glass insert for visual water cut-off control from the accumulated volume of production is

fed to the 75-m3 drainage tank. Then it is pumped with the NB-80 (NB-32) pump through the

90-mm x 12-mm, TN-90-V, polyethylene, sheathed, high-pressure at the pressure of 25-35

кg/cm2 into Well No. 8.

Water-free oil from Wells Nos. 3 and 5 from two 100-m3 tanks Nos. 5 and 6, and oil from Well

No. 6 from the 100-m3 tank No. 7 is alternatively pumped through the 90-mm x 10-mm, steel

pipelines with the KM-50 pump, through the BR chemical module, where DIN-4 dimulsifier is

proportioned into oil at 15 g/t with the ND proportioning pump, through the PPT02G in-line oil

heater where oil is heated to the temperature of 55-60 ºC, and 75-m3, RGS steel horizontal tanks

Nos. 1, 2 and 3 of the upstream farm. These tanks are designed for secondary gravity settlement

and discharge of separated water. Water by gravity flows through 90-mm, steel pipelines from

the tank to the 75-m3 drainage tank, and is pumped off with the NB-80 (NB-32) pump.

From the 75-m3 tanks Nos. 1, 2 and 3 treated oil through the 159-mm x 10-mm pipeline by

gravity can flow to the loading point No. 1 to load into tank trucks, or through 90-mm x 12-mm,

steel pipelines by gravity flows into 100-m3 sales oil storage tanks Nos. 8, 9, 10, 11 and 12. From

the tanks Nos. 8, 9, 10 and 12 treated oil through the 159-mm pipeline is pumped off with the

DS-125 gear pump to the loading point No. 2. From the 100-m3 tank No. 11 threated oil through

the 159-mm pipeline is pumped off with the Sh-90 gear pump to the loading point No. 3.

Fig. 4.4 – Oil Gathering Station, Uzenskoye field.

34

7. RESERVE VALUATION

In this report revenues were estimated using initial data on prices and expenses provided by Volga

Gas PLC. The cost estimates shown in the report were performed in US dollars (US$) at the

exchange rate of the Central Bank of the Russian Federation effective as of December 31, 2016,

in the amount of 60.6569 Rubles per US$. In this report values of proved and proved plus

probable reserves were base don future production forecasts and revenues, prepared for the

subject fields without risked re-estimates of probable reserves. Probable reserves are related to

lower certainty than proved reserves. Revenue values for probable reserves were not re-

estimated considering such uncertainties; assigning such correction is required to adjust value

estimates of probable reserves to value estimates of proved reserves. Assumptions shown below

were presented and used for estimation of future prices and expenses for the preparation of this

report.

Prices - Volga Gas PLC provided with oil, gas, condensate, LPG prices shown in Tables 7.1 and

7.2. Prices were held constant for the life of fields.

Revenue. Gross future revenueа is the revenue related to production and sale of estimated total

reserves at sales price.

Cash flow. Cash flow was estimated by deduction of estimated operating expenses, capital

investments and abandonment costs, mineral extraction taxes and other taxes, as well as revenue

tax from gross revenues.

Volga Gas PLC cash flow. Volga Gas PLC cash flow is attributed to the interest of Volga Gas PLC

in cash flow after deduction of interests attributed to other owners.

Volga Gas PLC present worth. Present worth of the Customer is determined as cash flow

discounted at arbitrary rate over the period of expected sale. In this report the present worth of

Volga Gas PLC at the Discount Rate of 12% is shown in details. Present worth at the Discount

Rates of 0 to 100% is shown as a profile.

Operating expense and capital investments - Operating and capital expenses and cost forecasts

as of December 31, 2016, provided by the Customer and used for the estimate of future costs

required for field development (Tables 7.1 and 7.2). Future expenses were used without price

escalation due to inflation.

Operating expenses. Operating expenses include fixed and variable components which are

forecasted so as to provide for production and its sale from the fields evaluated and are based

on actual historical expenses in the region and forecasted expenses provided by Volga Gas PLC.

Compared to the operating expenses forecasted for analogous objects located near the subject

fields, forecasted operating expenses of Volga Gas PLC seem to be justified for the expected

operation conditions.

35

Capital investments. Capital investments for well drilling, side-tracking, infrastructure and other

programs required for development of the evaluated fields were based on the actual historical

costs in the region and forecasted costs provided by Volga Gas PLC. Compared to capital

investments forecasted for analogous objects located near the subject fields, the capital

investment forecast seem to be justified for the expected operation conditions.

Depreciation. Future capital investments were depreciated over 7 years. Depreciation was

applied to the first year of incurred costs. Capital investments were considered evenly allocated

over a year and depreciation was estimated monthly. Besides, the estimated depreciation includes

30 per cent of accelerated depreciation in the first year of depreciation and commissioning assets

in accordance with possible tax incentives envisaged by the tax laws of the Russian Federation.

Taxes

For the purposes of this analysis it was assuumed that teh tax laws effective as of December 31

continues to be effective over the period of estimate. The description of the principle taxes is

shown below.

Mineral extraction tax

Oil. The base rate is 919 Rubles per tonne of oil production. This tax rate is multiplied by the

factor relevant to world oil price history (Kts). The product is reduced by the value of parameter

Dm characterizing specific oil production.

Gas condensate. The base rate is 42 Rubles per tonne of gas condensate production. This rate

is multiplied by the base value of a unit of conditional fuel (Eut), by the factor characterizing the

degree of complexity of combustible natural gas and/or gas condensate production from a

hydrocarbon deposit (Ks), and by the adjustment factor (Kkm).

Gas. The base rate is 35 Rubles per 1,000 cubic meters of gas for production of combustible

natural gas. The specified tax rate is multiplied by the base value of a unit of conditional fuel (Eut),

and by the factor characterizing the degree of complexity of combustible natural gas and/or gas

condensate production from a hydrocarbon deposit (Ks). The product is totaled with the value

of the parameter characterizing combustible natural gas transportation expenses (Tg).

Value-added tax

VAT is estimated at the rate of 18 per cent of the sales price of hydrocarbons sold in the domestic

market.

Property tax

Property tax is estimated annually at the rate of 2.2 per cent of the remaining balance of field

facilities.

36

Deductions to extra-budgetary funds

The base for the assessment of insurance payments is determined as a sum of payments and

other fees estimated by insurance contribution payers over the estimate period infavor of natural

persons on all grounds. The total rate of insurance over 2017 - 2018 is 30% of the payroll fund

and since 2019 - 34% of the payroll fund.

Revenue tax

Revenue tax is estimated at the rate of 20% of taxable revenue. The taxable revenue is estimated

by deduction of operating expenses, depreciation allowances of taxes from the future gross

revenue.

Summary and conclusions

Estimates of cash flow and present worth of Volga Gas PLC related to proved and proved plus

probable reserves attributed to Volga Gas PLC at the Uzenskoye, Sobolevskoye, Dobrinskoye and

Vostochno-Makarovskoye fields as of December 31, 2016, with the price and expenses

assumptions mentioned above, are shown below in thousand US dollars (M$). Values were

estimated in US dollars at the excahge rate of 60.6569 Rubles per US$ as of December 31, 2016.

Cash flow

(MUS$)

Present worth at

12% disc.rate

(MUS$)

Total proved reserves 247,617.84 140,249.73

Total proved plus probable 313,968.99 162,278.79

Detailed calculations are shown in Tables 7.1-7.9.

37

Table 7.1

ECONOMIC PARAMETERS

as of December 31, 2016

For PGK assets

Exchange rate, Rubles/US$ 60.657

Oil sales allocation

Export market, % 0.00

Domestic market, % 100.00

Domestic oil price Rubles/tonne US$/tonne

Contract price 19700.00 324.78

Less

VAT 3005.08 49.54

Intermediate price 16694.92 275.24

Transportation 0.00 0.00

Net domestic oil price 16694.92 275.24

Operating expenses MRubles/well/mo M$/well/mo

- Fixed 764.30 12.60

Rubles/bbl of oil US$/bbl of oil

- Variable 210.25 3.47

Development costs, M$/well MRubles/well M$/well

- Drilling and completion of deviated well

- Drilling and completion of horizontal well 179677.97 2962.20

- Side-tracking

Uzenskoye field 122927.97 2026.61

Sobolevskoye field 80000.00 1318.89

- Recompletion

- Restoration

Future capital MRubles M$

Uzenskoye field 72353.74 1192.84

Sobolevskoye field 0.00 0.00

38

Table 7.2

ECONOMIC PARAMETERS


for GNS assets

Exchange rate, Rubles/US$ 60.657

Gas sales allocation



Condensate sales allocation



LPG sales allocation



Export condensate Price Rubles/tonne US$/tonne

Contract Price 24318.32 400.92

Less

Commissions and dues 118.32 1.95

Export tariff 0.00 0.00



Net export condensate price 20700.00 341.26

Domestic condensate Price Rubles/tonne US$/tonne

Contract Price 20700.00 341.26

Less

VAT 3157.63 52.06



Domestic condensate price 17542.37 289.21

Domestic gas price Rubles/Mm3 US$/Mm3


Less

VAT 716.95 11.82



Net domestic gas price 3983.05 65.67

Domestic LPG price Rubles/tonne US$/tonne


Less

VAT 2898.31 47.78



Net domestic gas price 16101.69 265.46

39

Operating expenses

- Fixed MRubles/well/mo M$/well/mo

2729.10 44.99

- Variable Rubles/boc US$/boc

240.19 3.96

- Variable Rubles/bbls of LPG US$/bbls of LPG

602.74 9.94

- Variable Rubles/Mm3 US$/Mm3

436.87 7.20

Development costs, US$/well MRubles/well M$/well

- Drilling and completion of deviated well 180000.00 2967.51

- Drilling and completion of horizontal well

- Side-tracking 0.00

Future capital for infrastructure MRubles M$

Dobrinskoye field 12009.03 197.98

Vostochno-Makarovskoye field 430064.00 7090.11

40

Table 7.3 –TOTAL PROVED RESERVES AND CASH FLOW FORECASTS (except for VAT)

As of December 31, 2016

Uzenskoye field

Date

Reserves Future Gross

Revenues

Operating

Expenses

Capital

Investments

MET and Other

Taxes Revenue Tax

PGK Net Interest

(2017-2041)

PGK Net Interest (including past

losses)

Net Cash Flow

Present Worth

at 12%

Disc.Rate

Net Cash Flow

Present Worth

at 12%

Disc.Rate Oil and

Condensate Sales Gas

Mbbl MMcf M$ M$ M$ M$ M$ M$ M$ M$ M$

CF as of

12/31/2016 -6 182.3 -6 182.3

2017 654 0 23 389.2 3 208.7 5 551.9 11 609.6 238.4 2 780.6 2 482.7 2 780.6 2 482.7

2018 490 0 17 508.6 2 668.0 41.9 8 790.9 904.6 5 103.1 4 068.2 5 103.1 4 068.2

2019 448 0 16 027.3 2 531.9 43.6 8 081.9 877.4 4 492.5 3 197.7 4 492.5 3 197.7

2020 422 0 15 095.5 2 446.2 45.3 7 609.1 801.6 4 193.2 2 664.9 4 193.2 2 664.9

2021 392 0 14 000.5 2 345.5 47.1 7 057.3 712.0 3 838.6 2 178.1 3 838.6 2 178.1

2022 361 0 12 895.6 2 244.0 49.0 6 500.5 621.5 3 480.6 1 763.4 3 480.6 1 763.4

2023 330 0 11 802.8 2 143.5 51.0 5 949.5 532.0 3 126.9 1 414.4 3 126.8 1 414.4

2024 305 0 10 910.2 2 061.4 53.0 5 510.5 593.9 2 691.4 1 087.0 2 691.4 1 087.0

2025 283 0 10 112.0 1 988.1 55.2 5 124.2 590.1 2 354.5 849.1 2 354.5 849.1

2026 270 0 9 633.6 1 944.1 57.4 4 892.7 549.1 2 190.3 705.2 2 190.3 705.2

2027 256 0 9 141.8 1 898.9 59.7 4 654.7 507.0 2 021.6 581.1 2 021.6 581.1

2028 235 0 8 418.1 1 832.3 62.0 4 304.5 445.1 1 774.0 455.3 1 774.0 455.3

2029 219 0 7 831.9 1 778.4 64.5 4 020.9 395.0 1 573.1 360.5 1 573.1 360.5

2030 203 0 7 258.2 1 725.7 0.0 3 742.8 348.0 1 441.8 295.0 1 441.8 295.0

2031 187 0 6 690.8 1 673.5 0.0 3 467.3 302.4 1 247.6 227.9 1 247.6 227.9

2032 173 0 6 179.9 1 626.6 0.0 3 219.3 260.5 1 073.6 175.1 1 073.6 175.1

2033 158 0 5 640.2 1 577.0 0.0 2 957.5 216.1 889.6 129.6 889.6 129.6

2034 144 0 5 131.8 1 530.2 0.0 2 711.0 174.5 716.1 93.1 716.1 93.1

2035 129 0 4 615.6 1 482.8 0.0 2 460.9 132.2 539.8 62.7 539.8 62.7

2036 115 0 4 111.4 1 436.4 0.0 2 216.7 90.9 367.4 38.1 367.4 38.1

2037 101 0 3 605.8 1 389.9 0.0 1 972.0 48.8 195.1 18.1 195.1 18.1

2038 87 0 3 106.5 1 344.0 0.0 1 730.2 6.4 25.8 2.1 25.8 2.1

2039 42 0 1 518.5 668.8 0.0 961.6 0.0 -111.8 -8.3 -111.8 -8.3

2040 42 0 1 488.6 666.1 0.0 947.1 0.0 -124.5 -8.2 -124.5 -8.2

2041 41 0 1 466.1 588.4 0.0 903.8 0.0 -26.1 -1.5 -26.1 -1.5

Total 6 087 0 21 7580.6 44 800.4 6 181.6 111 396.4 9 347.3 45 854.9 22 831.4 39 672.5 16 649.1

41

PRESENT WORTH PROFILE (2017-2041)

Discount Rate Present Worth of Future

Net Revenues Discount Rate

Present Worth of Future



Net Revenues

0% 45854.9 25% 13902.1 60% 6300.3

5% 32976.8 30% 11976.3 70% 5390.2

10% 25127.1 35% 10483.3 80% 4694.7

15% 20003.7 40% 9296.2 90% 4147.8

20% 16464.1 50% 7535.8 100% 3707.5

TOTAL PROVED PRODUCING RESERVES AND CASH FLOW FORECASTS (except for VAT)


Uzenskoye field

Date


Revenues

Operating

Expenses

Capital

Investments

MET and

Other Taxes Revenue Tax

PGK Net Interest

(2017-2018) PGK Net Interest (including past

losses)

Net Cash Flow

Present Worth

at 12%

Disc.Rate

Net Cash Flow

Present Worth

at 12%

Disc.Rate Oil and



CF as of

12/31/2016 -6 182.3 -6 182.3

2017 225 0 7 632.3 1 155.3 0.0 2 253.8 0.0 4 223.2 3 770.7 4 223.2 3 770.7

2018 172 0 5 854.3 991.8 0.0 1 751.6 0.0 3 110.9 2 480.0 3 110.9 2 480.0

Total 397 0 13 486.5 2 147.1 0.0 4 005.4 0.0 7 334.0 6 250.7 1 151.7 68.3







Net Revenues

0% 7334.0 25% 5369.5 60% 3854.7

5% 6843.7 30% 5089.4 70% 3560.7

10% 6410.2 35% 4835.2 80% 3306.4

15% 6024.6 40% 4603.7 90% 3084.5

20% 5679.6 50% 4198.1 100% 2889.3

42

Table 7.4 – TOTAL PROVED RESERVES AND CASH FLOW FORECASTS


Sobolevskoye field

Date


Revenues

Operating

Expenses

Capital

Investments

MET and


PGK Net Interest (2017-2025) PGK Net Interest (including past

losses)

Net Cash Flow

Present Worth

at 12%

Disc.Rate

Net Cash Flow

Present Worth

at 12%

Disc.Rate Oil and



2017 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

2018 65 0 2 386.3 370.6 1 318.9 1 193.4 124.9 -621.5 -495.4 -621.5 -495.4

2019 65 0 2 386.3 370.6 0.0 1 206.1 107.0 702.6 500.1 702.6 500.1

2020 56 0 2 053.3 340.0 0.0 1 041.5 103.6 568.2 361.1 568.2 361.1

2021 45 0 1 662.4 304.0 0.0 848.9 71.1 438.3 248.7 438.3 248.7

2022 36 0 1 332.1 273.7 0.0 685.7 43.8 329.0 166.7 329.0 166.7

2023 27 0 1 001.9 243.3 0.0 522.4 16.5 219.7 99.4 219.7 99.4

2024 18 0 668.8 212.7 0.0 357.8 0.0 98.3 39.7 98.3 39.7

2025 5 0 173.4 68.9 0.0 116.3 0.0 -11.8 -4.2 -11.8 -4.2

Total 315 0 11 664.5 2 183.7 1 318.9 5 972.1 466.8 1 722.9 916.0 1 722.9 916.0







Net Revenues

0% 1722.9 25% 485.6 60% 87.2

5% 1314.8 30% 383.2 70% 47.2

10% 1013.9 35% 302.7 80% 20.1

15% 788.5 40% 239.0 90% 1.6

20% 617.3 50% 147.2 100% -11.1

43

Table 7.5 – TOTAL PROVED RESERVES AND CASH FLOW FORECASTS (except for VAT)


Vostochno-Makarovskoye field

Date


Revenues

Operating

Expenses

Капиталь-

ные

вложения

MET and


Чистая доля GNS (2017-2033 г.г.) Чистая доля GNS (including past

losses)

Net Cash Flow

Present Worth

at 12%

Disc.Rate

Net Cash Flow

Present Worth

at 12%

Disc.Rate Oil and

Condensate Sales Gas LPG

Mbbl MMcf Mtonnes M$ M$ M$ M$ M$ M$ M$ M$ M$

CF as of

12/31/2016 -2 390.5 -2 390.5

2017 648 10 878 32.7 53 888.2 11 717.7 5 938.2 6 596.4 5 779.4 23 856.5 21 300.4 23 856.5 21 300.4

2018 586 10 878 32.7 51 502.5 11 311.6 76.7 6 801.1 5 749.1 27 564.0 21 973.9 27 564.0 21 973.9

2019 528 10 878 32.7 49 270.4 10 931.7 79.7 6 370.2 5 570.4 26 318.4 18 732.9 26 318.4 18 732.9

2020 485 10 878 32.7 47 600.6 10 647.4 82.9 6 005.1 5 364.3 25 500.8 16 206.2 25 500.8 16 206.2

2021 380 9 119 27.4 38 865.6 8 645.7 86.2 4 810.6 4 254.4 21 068.6 11 954.9 21 068.6 11 954.9

2022 313 7 972 24.0 33 259.7 7 707.7 89.7 4 042.3 3 472.3 17 947.6 9 092.8 17 947.6 9 092.8

2023 266 7 017 21.1 28 893.5 6 978.1 93.3 3 437.4 2 863.7 15 520.9 7 020.9 15 520.9 7 020.9

2024 221 6 028 18.1 24 524.1 6 248.4 97.0 2 921.2 2 985.1 12 272.4 4 956.6 12 272.4 4 956.6

2025 187 5 231 15.7 21 110.2 5 678.6 100.9 2 529.2 2 562.4 10 239.0 3 692.3 10 239.0 3 692.3

2026 157 4 434 13.3 17 820.1 5 129.9 104.9 2 157.8 2 087.7 8 339.8 2 685.2 8 339.8 2 685.2

2027 86 2 490 7.5 9 930.1 3 274.6 109.1 1 232.5 1 065.1 4 248.8 1 221.4 4 248.8 1 221.4

2028 71 2 075 6.2 8 244.5 2 993.6 113.5 1 043.7 821.2 3 272.6 840.0 3 272.6 840.0

2029 57 1 660 5.0 6 595.6 2 718.8 118.0 860.9 582.1 2 315.8 530.7 2 315.8 530.7

2030 42 1 245 3.7 4 928.6 2 441.0 0.0 674.3 344.4 1 468.9 300.6 1 468.9 300.6

2031 21 639 1.9 2 520.9 1 283.9 0.0 364.6 160.6 711.9 130.1 711.9 130.1

2032 14 415 1.2 1 642.9 1 137.6 0.0 84.5 72.6 348.1 56.8 348.1 56.8

2033 7 191 0.6 764.8 532.4 0.0 42.4 28.8 161.1 23.5 161.1 23.5

Total 4 069 92 027 276.9 401 362.3 99 378.8 7 090.1 49 974.4 43 763.7 201 155.3 120 719.1 198 764.8 118 328.7







Net Revenues

0% 201155.3 25% 80658.9 60% 40205.6

5% 159242.5 30% 71022.5 70% 34911.9

10% 129986.7 35% 63273.9 80% 30796.6

15% 108773.5 40% 56933.6 90% 27514.9

20% 92887.2 50% 47232.2 100% 24842.3

44

Table 7.6 – TOTAL PROVED PLUS PROBABLE RESERVES AND CASH FLOW PROFILES (except for VAT)


Vostochno-Makarovskoye field

Date

Reserves

Future Gross

Revenues

Operating

Expenses

Капиталь-

ные

вложения

MET and


Чистая доля GNS (2017-2035) Чистая доля GNS (including past

losses)

Net Cash

Flow

Present Worth

at 12% Disc.Rate Net Cash Flow

Present Worth

at 12%

Disc.Rate

Oil and

Condens

ate

Sales Gas LPG

Mbbl MMcf Mtonnes M$ M$ M$ M$ M$ M$ M$ M$ M$

CF as of

12/31/2016 -2 390.5 -2 390.5

2017 648 10 878 32.7 53 888.2 11 717.7 5 938.2 6 596.4 5 779.4 23 856.5 21 300.4 23 856.5 21 300.4

2018 586 10 878 32.7 51 502.5 11 311.6 76.7 6 801.1 5 749.1 27 564.0 21 973.9 27 564.0 21 973.9

2019 528 10 878 32.7 49 270.4 10 931.7 79.7 6 370.2 5 570.4 26 318.4 18 732.9 26 318.4 18 732.9

2020 485 10 878 32.7 47 600.6 10 647.4 82.9 6 005.1 5 364.3 25 500.8 16 206.2 25 500.8 16 206.2

2021 449 10 878 32.7 46 218.6 10 412.2 86.2 5 687.5 5 196.4 24 836.3 14 092.8 24 836.3 14 092.8

2022 420 10 878 32.7 45 098.2 10 221.5 89.7 5 412.9 5 063.2 24 310.9 12 316.7 24 310.9 12 316.7

2023 360 9 884 29.7 40 147.2 8 853.0 93.3 4 678.5 4 491.3 22 031.1 9 965.8 22 031.1 9 965.8

2024 314 8 928 26.9 35 825.9 8 131.0 97.0 4 163.2 4 620.6 18 814.1 7 598.7 18 814.1 7 598.7

2025 273 7 972 24.0 31 724.7 7 446.5 100.9 3 691.8 4 099.2 16 386.2 5 909.0 16 386.2 5 909.0

2026 235 7 017 21.1 27 691.8 6 773.6 104.9 3 231.8 3 518.5 14 063.0 4 527.9 14 063.0 4 527.9

2027 200 6 061 18.2 23 809.3 6 126.3 109.1 2 796.6 2 957.8 11 819.6 3 397.8 11 819.6 3 397.8

2028 168 5 106 15.4 20 029.8 5 496.5 113.5 2 378.4 2 410.7 9 630.7 2 472.0 9 630.7 2 472.0

2029 83 2 555 7.7 9 976.7 3 281.6 118.0 1 226.5 1 072.6 4 278.0 980.4 4 278.0 980.4

2030 68 2 108 6.3 8 238.4 2 992.1 0.0 1 035.1 824.0 3 387.2 693.1 3 387.2 693.1

2031 61 1 851 5.6 7 256.0 2 504.6 0.0 926.6 751.1 3 073.8 561.6 3 073.8 561.6

2032 53 1 594 4.8 6 273.7 2 341.0 0.0 125.6 749.8 3 057.2 498.7 3 057.2 498.7

2033 46 1 371 4.1 5 404.5 2 115.3 0.0 124.6 623.8 2 540.9 370.1 2 540.9 370.1

2034 39 1 147 3.5 4 535.4 1 565.6 0.0 82.8 570.7 2 316.3 301.2 2 316.3 301.2

2035 32 956 2.9 3 779.5 1 439.6 0.0 82.3 447.4 1 810.1 210.2 1 810.1 210.2

Total 5 049 121 815 366.6 518 271.4 124 308.7 7 090.1 61 417.3 59 860.2 265 595.1 142 109.3 263 204.6 139 718.8

45







Net Revenues

0% 265595.1 25% 89024.2 60% 41558.3

5% 198544.0 30% 77146.0 70% 35811.6

10% 155215.5 35% 67852.5 80% 31415.3

15% 125666.7 40% 60420.4 90% 27952.4

20% 104602.0 50% 49349.9 100% 25159.2

46

Table 7.7 – TOTAL PROVED RESERVES AND CASH FLOW FORECASTS (except for VAT)


Dobrinskoye field

Date


Revenues

Operating

Expenses

Capital

Investments

MET and


PGK Net Interest (2017-2029) PGK Net Interest (including past

losses)

Net Cash Flow

Present Worth

at 12%

Disc.Rate

Net Cash Flow

Present Worth

at 12%

Disc.Rate Oil and



2017 83 1 080 5 375.3 1 873.2 3 078.8 879.5 296.3 -752.6 -671.9 -752.6 -671.9

2018 65 864 4 253.8 1 706.6 5.8 806.3 83.9 1 651.2 1 316.3 1 651.2 1 316.3

2019 62 821 4 019.2 1 671.6 6.0 759.8 109.5 1 472.3 1 048.0 1 472.3 1 048.0

2020 57 777 3 766.5 1 633.4 6.2 699.6 78.4 1 348.6 857.2 1 348.8 857.2

2021 54 734 3 537.9 1 599.4 6.5 643.4 50.6 1 238.1 702.5 1 238.1 702.5

2022 50 691 3 311.8 1 565.7 6.8 587.5 23.1 1 128.6 571.8 1 128.6 571.8

2023 25 345 1 646.9 781.3 7.0 283.0 0.0 575.5 260.3 575.5 260.3

2024 22 302 1 441.0 751.2 7.3 249.4 0.0 433.2 175.0 433.2 175.0

2025 18 259 1 228.5 719.8 7.6 218.6 15.4 267.1 96.3 267.1 96.3

2026 15 216 1 023.7 662.9 7.9 189.1 32.9 130.9 42.2 130.9 42.2

2027 12 173 814.5 524.1 8.2 158.8 24.8 98.5 28.3 98.5 28.3

2028 9 130 610.9 359.4 8.5 129.5 22.9 90.6 23.3 90.6 23.3

2029 6 86 407.3 329.6 8.9 100.2 0.0 -31.4 -7.2 -31.4 -7.2