independent reserve and resource evaluation report ... · has conducted an independent assessment...

Independent Reserve and Resource Evaluation Report

ESTIMATION OF THE METHANE AND

HELIUM RESERVES OF THE TETRA4

VIRGINIA GAS FIELD IN THE FREE

STATE OF THE REPUBLIC OF SOUTH

AFRICA

Renergen Limited

Prepared for: Mr. Stefano Marani

730 17th St, Suite 410 Denver, CO 80202 USA

Phone: 01 303 277 0270

Email: [email protected] www.mhausa.com

Renergen | March 7, 2018 Page | 2

March 7, 2018

Mr. Stefano Marani Chief Executive Officer Renergen Limited 1 Bompas Road Dunkeld West Johannesburg, 2196 Republic of South Africa

Re: ESTIMATION OF METHANE AND HELIUM RESERVES AND RESOURCES AND ASSOCIATED ECONOMICS OF THE TETRA4 VIRGINIA GAS FIELD IN THE FREE STATE OF THE REPUBLIC OF SOUTH AFRICA

Dear Mr. Marani:

At the request of Renergen Limited (Renergen), MHA Petroleum Consultants (MHA)

has conducted an independent assessment of the unconventional methane and helium

reserves and resources in the Tetra4 Virginia Gas Field, located in the Free State of the

Republic of South Africa. This evaluation, based on the analysis methodology

described herein using technical and economic data supplied by Tetra4, has an

effective date of March 1, 2018.

This evaluation includes estimates of recoverable methane and helium volumes from

Proved Developed Non-Producing wells (PDNP’s), Proved Undeveloped locations

(PUDs), total proved, probable, and possible reserves. No Proved Developed

Producing reserves (PDPs) could be assigned at this time. Associated pre-tax net

present value of future income for selected discount rates are presented for Reserves

volumes. MHA has estimated the volumes of Contingent Resources, those volumes of

gases that are discovered but are not yet considered commercially viable for extraction

due to one or more contingencies. MHA has also estimated the volumes of Prospective

Resources, those volumes of gases that are undiscovered but the likelihood of their

existence can be estimated. Prospective Resources thus carry significant exploration

risk. All Prospective Resources volumes presented in this report are un-risked.

Resource and reserve estimates and associated economics contained in this report are

prepared in accordance with the Society of Petroleum Engineers (SPE) Petroleum

Resources Management (PRMS) guidance and provides a Technical Value, defined as

an assessment of a mineral asset’s future net economic benefit at the valuation date

under a set of assumptions deemed most appropriate by a practitioner excluding any

premium or discount to account for market considerations. These estimates are aligned


with the South African Code for the Report of Oil and Gas Resources (SAMOG) which

is used by the Johannesburg Stock Exchange (JSE) in conjunction with the SPE PRMS

guidance and specific additional rules. Our evaluation based upon data supplied by

Tetra4, supplemented where necessary by MHA’s corporate awareness of current

South African industry costs and best practices.

RESERVE AND RESOURCE ESTIMATES The reserve and resource estimates presented in this report have been prepared for

publication in South Africa under the SAMOG regulatory guides using an evaluation

approach for unconventional resources consistent with Society of Petroleum Engineers

Petroleum Resources Management System (SPE PRMS) 2007 and the SPE 2011

PRMS guidelines (attached). Sustained commercial sales of methane gas from pilots

located on the Tetra4 licenses and periodic measurements of the free flow gas volumes

from multiple blowers, some producing for decades, allow estimation of the gas

production decline rate and thus ultimate recoverable volumes of gas.

Estimated net methane and helium reserves and net present values at Tetra4 specified

discount rates are summarized in Table 1.


Table 1: Summary of Methane and Helium Net Gas Reserves and Net Present Values at Selected Discount Rates

Virginia Gas Project – Specified Prices and Costs

PDNP PUDs

Total Proved

(1P) Probable

Proved +Probable

(2P) Possible

Proved+ Probable+ Possible

(3P)

Methane (BCF) 12.60 23.77 36.36 91.03 127.39 141.66 269.05

Helium (BCF) 0.30 0.56 0.87 2.12 2.99 3.22 6.21

Net Present Value (MZAR)

Undiscounted 6,910 12,980 11,251 62,055 62,117 112,413 164,713

5% 3,312 6,163 5,226 24,067 25,516 37,812 59,871

8% 2,352 4,349 3,576 16,012 17,037 24,024 38,514

10% 1,935 3,562 2,849 12,812 13,358 18,815 30,124

15% 1,298 2,362 1,726 8,258 8,407 11,675 18,290

20% 954 1,715 1,112 5,935 5,731 8,156 12,339

30% 605 1,062 494 3,648 3,097 4,778 6,631

Unrisked net Contingent Resources were calculated from the technically recoverable

gas volumes for each type well multiplied by the number of locations in the portion of

the Virginia Gas Field classified as Contingent Resources and, in the case of helium,

multiplied by a constant helium content of 3%. These gas volumes were combined with

the same prices and costs used for estimating Reserves to obtain the net Contingent

Resources in Table 2 below.


Table 2: Summary of Net Methane and Helium Contingent Resources Virginia Gas Field – Specified Prices and Costs

Category

Contingent Resources (BCF)

Low Case (C1) Best Case (C2) High Case (C3)

Methane 258.1 494.2 764.2

Helium 8.64 16.3 24.6

Unrisked gross Prospective Resources (Table 3) were calculated volumetrically as the

technically recoverable gas volumes for each type well multiplied by the number of

locations in that portion of the Virginia Gas Field classified as Prospective Resources.

No economics were calculated for methane Prospective Resources and no helium

Prospective Resources were estimated as part of this work.

Table 3: Summary of Gross Methane Prospective Resources Virginia Gas Field

Category

Prospective Resources (BCF)

Low Case Best Case High Case

Methane 640 1,278 2,069


STATEMENT OF RISK

The accuracy of resource, reserve, and economic evaluations is always subject to uncertainty.

The magnitude of this uncertainty is generally proportional to the quantity and quality of data

available for analysis. As a prospect, project, or well matures and new information becomes

available revisions may be required which may either increase or decrease the previous

estimates. Sometimes these revisions may result not only in a significant change to the reserves

and value assigned to a property, but also may impact the total company reserve and economic

status. The resources, reserves and economic forecasts contained in this report were based

upon a technical analysis of the available data using accepted geoscience and engineering

principles. However, they must be accepted with the understanding that further information and

future reservoir performance subsequent to the date of the estimate may justify their revision. It

is MHA’s opinion that the estimated resources, reserves, economics, and other information as

specified in this report are reasonable, and have been prepared in accordance with generally

accepted geoscience and petroleum engineering and evaluation principles. Notwithstanding the

aforementioned opinion, MHA makes no warranties concerning the data and interpretations of

such data. In no event shall MHA be liable for any special or consequential damages arising

from Renergen’s use of MHA’s interpretation, reports, or services produced as a result of its

work for Renergen. Neither MHA, nor any of our employees have any interest in the subject

properties and neither the employment to do this work, nor the compensation, is contingent on

our estimates of the resources or economic evaluations for the properties in this report. This

report was prepared for the exclusive use of Renergen and will not be released by MHA to any

other parties without Renergen’s written permission (other than the stated purpose set out

above). The data and work papers used in this preparation of this report are available for

examination by authorized parties in our offices.

Thank you for this opportunity to be of service to Renergen. If you have any questions or wish

to discuss any aspect of the report further, please feel free to contact me.

Sincerely,

Jeffrey B. Aldrich

Partner MHA Petroleum Consultants John P. Seidle

Partner

MHA Petroleum Consultants


TABLE OF CONTENTS

Estimation of the Methane and Helium Reserves of the Tetra4 Virginia Gas Field in the Free State of the Republic of South Africa .......................................................................................... 1

Reserve and Resource Estimates .............................................................................................. 3

Statement of Risk ....................................................................................................................... 6

Table of Contents ....................................................................................................................... 7

Table of Figures ..................................................................................................................... 8

Table of Tables ....................................................................................................................... 8

Background ................................................................................................................................ 9

Geology ....................................................................................................................................11

Regional Geology ..................................................................................................................11

Existing Wells and Production History .......................................................................................15

Historic Wells .........................................................................................................................15

Evaluated Wells .....................................................................................................................15

Methodology .............................................................................................................................17

Data Set .............................................................................................................................17

Analysis .............................................................................................................................17

Volumetrics ...............................................................................................................................18

Past Studies ..........................................................................................................................18

2017 Assessment ..............................................................................................................19

Economics ................................................................................................................................27

Tetra4 Operating Conditions and Sales Agreements .............................................................27

Economic parameters ...............................................................................................................30

Reserve economics ..................................................................................................................35

Contingent resource economics ................................................................................................36

Conclusions ..............................................................................................................................37

Qualifications ............................................................................................................................38

Bibliography ..............................................................................................................................39

Appendix 1: Methane and Helium Prices...................................................................................40

Appendix 2: Reserve Category Cash Flow Summaries .............................................................43

Appendix 3: Petroleum Resources Management System ..........................................................60

Appendix 4: Abbreviations ........................................................................................................76


TABLE OF FIGURES

Figure 1: Location Map .............................................................................................................. 9

Figure 2: Permit Map.................................................................................................................10

Figure 3: Regional Geologic Map ..............................................................................................12

Figure 4: Map of Known Rand Group Faults .............................................................................13

Figure 5: West to East Cross-Section .......................................................................................14

Figure 6: Structure Map on the Base of the Karoo Supergroup .................................................16

Figure 7: Idealized Spacing of New Field Development Wells ...................................................20

Figure 8: Typical Spacing of Field Development Wells Influenced by Faults .............................21

Figure 9: Map Proved, Probable and Possible well locations ....................................................22

Figure 10: Map of Helium Concentration in % ...........................................................................26

Figure 11: Map Tetra4 Virginia Gas License and Current Plus Planned Wells ..........................29

Figure 12: Renergen Type Wells ...............................................................................................30

Figure 13: Renergen Type Wells – Cumulative Gas Production ................................................31

Figure 14: Methane and Helium Monthly Prices ........................................................................33

TABLE OF TABLES

Table 1: Summary of Methane and Helium Net Gas Reserves and Net Present Values at

Selected Discount Rates ............................................................................................................ 4

Table 2: Summary of Net Methane and Helium Contingent Resources ...................................... 5

Table 3: Summary of Gross Methane Prospective Resources ................................................... 5

Table 4: List of Existing Blowers (PDNP wells)..........................................................................17

Table 5: Technically Recoverable Methane Volume Estimates-Virginia Gas Field ....................23

Table 6: Technically Recoverable Contingent Methane Volume Estimates of the Virginia Gas

Field ..........................................................................................................................................23

Table 7: Technically Recoverable Prospective Methane Volume Estimates of the Virginia Gas

Field ..........................................................................................................................................24

Table 8: Technically Recoverable Helium Estimates of the Virginia Gas Project .......................27

Table 9: Technically Recoverable Helium Volume Estimates by Contingent Resource Category -

Virginia Gas Field ......................................................................................................................27

Table 10: Wellcount by Reserve and Contingent Resource Category .......................................34

Table 11: Gross and Net Methane and Helium Reserves at a 10% Discount Rate ....................35

Table 12: Virginia Gas Field – Methane and Helium Reserves ..................................................36

Table 13: Net Methane and Helium Contingent Resources and Net Present Values .................37

Table 14: Virginia Gas Field - Gross and Net Methane and Helium Reserves and Contingent

Resources .................................................................................................................................37


BACKGROUND

Renergen’s Tetra4’s South Africa Virginia project, which is located in the Free State, is

approximately 250 km southwest of Johannesburg. The exploration right covers a large

area where gas emitting boreholes have been identified from mineral exploration

activities. Several of these boreholes are flowing gas at high production rates and have

been doing so for decades. Past studies have conducted a work program which involved

the cataloging and sampling of the gas emitting boreholes, a soil gas geochemistry

survey, and structural mapping. The gas emitting boreholes, or “blowers,” were drilled by

mining companies to explore for gold in Witwatersrand formations which underlie the coal-

bearing Karoo and Ventersdorp lavas. Some flowing wells were capped because of what

was regarded as dangerously high gas emission rates. Tetra4 now owns 100% working

interest in 187,427.2189 hectares (Figure 1) that currently has 18 wells currently

producing gas and 28 wells that are known to have produced gas in the past but are now

currently capped.

Figure 1: Location Map

Figure 1: Location Map

100 km

Free State Gas Rights

Exploration Right

Production Right

Evander Gas Rights

Exploration Right 27

Exploration Right 31

National Highway

Towns

Provincial Boundary

Free State Gas Rights Evander Gas

Rights


The Tetra4 Production License is subject to a 5% state tax plus an overriding royalty

(ORRI) on certain concurrent leases that are owned by GFI Mining South Africa

(GFIMSA) of Goldfields. The Goldfields ORRI is an additional 1% on top of the state tax

on all wells and locations that are located within the Goldfields mining leases. These two

reductions in the revenue stream, the state tax and the GFIMSA ORRI, have been

accounted for in the economic analysis.

Figure 2: Permit Map

s


GEOLOGY

REGIONAL GEOLOGY

The Virginia Gas Field Project overlies Witwatersrand PreCambrian age Supergroup of

meta-sediments that host the Welkom Goldfield. These ‘basement’ lithologies have been

tectonically flexed into a large north to south trending anticline that is in turn bisected by a

large extensional graben (low area) and many large faults that extend deep into the

earth’s crust. Uncomfortably overlying the Witwatersand Supergroup is the Venterdorp

Supergroup of primarily volcanic lithologies. Many of the larger faults do not extend

beyond the upper Ventersdorp formations. After another large unconformity lies the

Karoo Supergroup, a Permian aged sedimentary section composed of sandstones, coal

seams and carbonaceous shales. There is often a basal glacial deposit on top of the

unconformity that separates the Karoo from the Ventersdorp known as the Dwyka Tillite.

The primary source of the Methane gas is primarily microbial in origin from deep within

the Witwatersrand Supergroup with groundwater circulating through the large faults and

coming in contact with bacteria living deep within the crust. Methane isotope studies

demonstrate that very little, if any, of the methane can be attributed to the Karoo coal

beds or the carbonaceous shales. Thus the methane is a biogenic and a continuing

renewable resource. Being a renewing resource conventional in-place, static, estimates

of gas volumes are not applicable and the authors of this study have instead relied on

pressure decline analysis. The helium, as with almost all helium around the world, is

either mantle derived, that is from deep within the earth or from decay of radioactive

minerals within the crust, and as the helium moves up the large faults mixes with the

microbial methane in the deep subsurface.


Figure 3: Regional Geologic Map

Figure 3: Regional Geologic Map of the surface geology. The Virginia Gas Project is annotated in

the southwest corner of the map.

Free State

311Moz @ 4g/t


Figure 4: Map of Known Rand Group Faults

Figure 4: Map of Known faults through the Virginia Gas Project. The known gas wells are

associated with the wells intersecting the faults that penetrate the Witwatersrand Supergroup.

N

a

b

C

Free State Gas Rights


Figure 5: West to East Cross-Section

Figure 5: West to East Cross-sections, within the area of the Virginia Gas Project, demonstrating

the tilted nature of the rock strata and the penetration of the faults into the Witwatersrand

Supergroup.

Stuirmanspan Fault De Bron Faultb

Stuirmanspan Fault De Bron Faulta

Stuirmanspan Fault De Bron Faultc

MD5 HAK8


EXISTING WELLS AND PRODUCTION HISTORY

HISTORIC WELLS

There are nearly two thousand wellbores that have been drilled, either for water, for

mining assessment, or for disposal, across the Welkom District over the past several

decades and many tens of these wells have naturally produced flammable gas and have

been called “blowers.” Data from the South Africa Council for Geosciences lists at least

136 historic wells within the production area and notes that 68 of them produced gas in

the past, 18 are currently producing gas (blowers), 29 have odors, and 28 are dormant.

EVALUATED WELLS

Twelve wells were evaluated for the original 2008 Molopo reserves evaluation study

(Burning Flame, Burning Cross, Flame 1, ML-1, Retreat, Sand, SP-3, Squatter, DBE-1,

Kotze EX-1, ST23, and Tewie). Molopo drilled three additional wells in 2009 (HADV1,

HADV2, and HADR1). Tetra4 took over the project and drilled 4 wells in 2016 (MDR1,

MDR4, MDR5 and 2057) and in 2017 reworked an older well that had resumed flowing

gas (2190).


Figure 6: Structure Map on the Base of the Karoo Supergroup

Figure 6: Map of the Production license and a structure map of the Base of the Karoo Supergroup

(top of the reservoir) with the known faults in red. Existing wellbores are annotated with circles.


METHODOLOGY

Data Set

Tetra4 delivered to MHA driller’s logs, completion reports, LAS files, gas analysis reports,

production test data, and license data from the Virginia Gas Fields Project in the Free

State in South Africa.

Analysis

MHA reviewed the well data, LAS files, gas analysis reports, production test data and

historical geological data to ascertain the source of the gas, reservoir conditions, reservoir

extents, Tetra4 development plans and market conditions.

Table 4: List of Existing Blowers (PDNP wells)

Tetra4 Existing Methane Producers

CH4 Producer

He Producer

HDR 1 X X

BEI 02 X X

Burning Cross X X

EX 1 X X

Highpipe X X

HZON 1 X X

MDR 5 X X

ML 1 X X

Retreat X X

ST 23 X X

SPG 3 \ Lucky X X

Squatter X X

Tewie-1400 X X

Burning Flame X X

DBE 1 X X

SP 3 X X

Flame 1 X

Sand X


VOLUMETRICS

PAST STUDIES

Volumetric Assessments have been conducted by MHA Petroleum Consultants in 2008

and by Venmyn-Deloitte in 2015 and 2016. The 2008 MHA study analyzed 12 existing

blowers and concluded that the best well decline rates ranged from 3 to 7% with an

economic cutoff of 30,000 scf/day. Initial production rates ranged from a low of 150,000

scf/day to a high of 380,000 scf/day with a best case of 260,000 scf/day. The MHA study

determined that the Estimated Ultimate Recovery (EUR), on a per well basis of

marketable gas, varied from a Low case of 0.9 BCF to a High Case of 2.6 BCF with a

Best Case of 1.7 BCF.

The 2016 Venmyn-Deloitte assessment was done after the HADV1, HADV2, HDR1,

HPAL1, HZON1, MDR1, MDR4, MDR5, and 2057 wells were drilled. In drilling these 9

wells, there were 7 wells with gas shows and 5 wells that had sustained gas production.

The Venmyn-Deloitte report concluded that the decline rates averaged from 2 to 6% but

did not use an economic cut off to calculate the EURs. They ran their range of Initial

Production rates from 140,000 scf/day to 300,000 scf/day and used 150,000 scf/day as

the Best Case. The production runs were allowed to run out 49.5 years into the future,

which gave a slightly optimistic EUR. The EURs that were presented in the report ranged

from a Low case of 0.9 BCF to a High Case of 3.5 BCF.

The 2008 MHA report assigned 54 locations to the P2 (Probable) Reserve Category, an

additional 63 locations to the P3 (Possible) Reserve Category, and no locations to the

Proved Category. There were 357 locations assigned to the Contingent Resources

Category.

The 2016 Venmyn-Deloitte report assigned 52 locations to P1 (Proved), 60 to the P2

(Probable), and 128 locations to P3 (Possible). Thus far, at best 17 wells that have tested

gas, and a drilling program that has about a 60% commercial success rate Venmyn-

Deloitte assigned 240 well locations to the Reserve Category and with 22% of the

locations having a 90% confidence factor of delivering the base case EUR. There were no

Contingent Resources assigned.

In 2017 MHA conducted another assessment (below) for IDC reviewing the updated test

information and new wells. This report, prepared for an update on the JSE Stock

Exchange News Service, draws substantially from the IDC Report, with permission from

IDC. It uses the IDC 2017 Reserve and Resource volumetric assessments but generates

a different economic analysis based on the complete 1P-2P-3P volumes of gas rather

than a limited first phase field development plan that was used for the 2017 IDC report.


2017 Assessment

MHA has reviewed the updated test data from the HADV1, HADV2, HDR1, HZON1,

MDR1, MDR5, and 2057 wells plus addition flare and test data from selected historic

blowers. This data has confirmed, but not altered, MHA’s original assessment of a range

of well performance and lacking sustained, long-term, well production data MHA is not

altering, at this time, either the range of expected decline rates nor the range of expect

EURs for the wells. MHA believes the current ranges capture the inherent uncertainties

and as more data is made available through sustained production the range of

uncertainties will be reduced.

The continued drilling and testing, plus the advancement of gas sales agreements and

Tetra4’s advancement of development and marketing plan has allowed MHA to elevate

many of the locations into the PROVED category. MHA is assigning Proved, Developed,

Non-Producing (PDNP) status, on a project basis subject to the submitted Tetra4

development plan and budget, to all wells that have tested significant rates of gas and

assigned two offset Proved Undeveloped (PUD) locations to each well, except for well

MDR5 which has no offset locations. Thus MHA has assigned 18 PDNP and 34 PUD

locations for 52 Proved well locations. In addition MHA has assigned 4 Possible and 4

Probable well locations for seventeen PDNP locations; thus there are 68 Possible and 68

Probable locations for a total of 188 total Reserve locations. All offset wells are expected

to be drilled on a spacing of about 1well\ 0.91 km2 or 225 acres. It is important to note that

wherever MHA has assigned an undrilled location it is for the purposes of accounting for

undrilled reserves and may not be the exact location that Tetra4, for operational or

permitting reasons chooses, to drill. All wells in the program and economics are planned

as vertical wells however Tetra4 has expressed interest and has started planning for slant

wells that might intersect more fault and fracture surfaces. As this style of wells has not

been executed as of the time of this report MHA has not included them in the economics

nor constructed a type curve for these wells.

Based on this discussion the Technically Recoverable Methane Volumes associated with

the reserve categories are referenced in Table 5 (below).


Figure 7: Idealized Spacing of New Field Development Wells

Figure 7: Idealized spacing of an existing Blower (Retreat) and a symmetrical spacing of

two PUD wells (blue triangles), four Probable wells (red hexagons), and four Possible

wells (small red diamonds).


Figure 8: Typical Spacing of Field Development Wells Influenced by Faults

Figure 8: A more typical development scenario where wells are spaced out along known

fault and fracture spacing around an existing blower, HZON1 with two PUD wells (blue

triangles), four Probable wells (red hexagons), and four Possible wells (small red

diamonds).


Figure 9: Map Proved, Probable and Possible well locations

Figure 9: Map of the existing wells and the future wells with Proved locations (Blue

Triangles with purple centers), Probable locations (Red Hexagons with purple centers)

and Possible locations (small Red diamonds with purple centers). In the black outline is

the area defined as the “Core Area” for the Contingent Resources. All Prospective

Resources are outside of the “Core Area.”


Table 5: Technically Recoverable Methane Volume Estimates-Virginia Gas Field

Category Recoverable Volumes (Bcf) Totals (Bcf)

Developed Undeveloped

Proven (1P) 16.2 30.6 46.8

Probable (P2) 115.6 115.6

Possible (P3) 176.8 176.8

Total (P+P+P) 16.2 323 339.2

MHA has defined a core area that has been delineated by drilling and testing within the

production license of 505.12 Km2. Within that area are 17 development locations of 11

wells each (187 well locations) and a reserve development area of approximately 170

Km2 or 0.91km2/well. Removing the 170 Km2 that have been assigned to the Reserve

area from the total 505.12 Km2 in the core production area leaves 335.12 Km2 of area in

the Contingent Resource Category. With a well spacing of 0.91 Km2/well that equates to

368 contingent wells. MHA assigned volumes to these wells probabilistically using a

range of EURs, with the C1 category of 0.9 BCF/well, C2 category 1.7 BCF/well and C3

category 2.6 BCF/well.

Table 6: Technically Recoverable Contingent Methane Volume Estimates of the Virginia Gas Field

Category

EUR/Well Total BCF

Contingent (C1) 0.9 313.48

Contingent (C2) 1.7 625.6

Contingent (C3) 2.6 1,012.3

MHA has assigned all of the production area outside of the defined core area as

Prospective Resource area. This area has historic gas blowers on the license, there are

existing deep gold and other metal mines and there are, in the South African Geologic

Survey and literature, mapped faults that extend deep into the sub-surface. There is

reasonable expectation that there will be the same type of gas occurrences within the rest

of the production area however neither the historic operators nor the current operators of

the license have delineated the resource to an extent that it can be considered a

Contingent Resource. MHA has taken the same range of EURs/well as in the Contingent

Resource area but has, until there is sufficient information to warrant updating the

evaluation, doubled the distance between the wells from the well spacing used in the

Contingent Resource evaluation area to 1.82 Km2/well.

The entire production license is 1,874.2 Km2 and once the 505.12 Km2 core production

area is removed their remains 1,369.08 Km2 of Prospective Resource area. Using a 1.82


Km2/well density that will equate to an unrisked, a potential 752 wells. MHA has run a

probabilistic distribution of recoverable volumes using the range of EURs calculated for

the recoverable methane in the development area. No helium is assessed as there is

insufficient information at this time.

Table 7: Technically Recoverable Prospective Methane Volume Estimates of the Virginia Gas Field

Category

EUR/Well Total BCF

Prospective Resource Low Estimate 0.9 640.6

Prospective Resource Best Estimate 1.7 1,278.4

Prospective Resource High Estimate 2.6 2,068.9

TECHNICALLY RECOVERABLE HELIUM RESERVES

MHA has used the He concentration data supplied by Tetra4 to map the spatial

distribution of He enrichment in the produced gases. Seven of the tested wells tested

Helium (He) concentrations at least 2% by volume or greater and some of wells tested

over 10%; including the 2057 well. The 2016 Venmyn-Deloitte report made the

assumption that all wells would produce an average of 2% He and all wells would be

scrubbed for He and the He sold. MHA has used the data available and mapped out the

He concentrations by well and found that there appears to be a significant enrichment

trend on the west side of the De Bron fault with all wells to the east of the fault showing no

testable He concentrations, at least until you cross the Virginia fault and move further

east. Only the AD1 well, outside of the production license and well to the east of the

Virginia fault, shows enrichment of He gas on the eastern side of the production area. It is

very important to note that there is A) a sparsity of well sampling over the structural high,

B) most of the wells that did have gas compositional sampling did not sample for helium,

and C) there is antidotal evidence that even those wells that attempted to sample for

helium used improper methodologies. It is therefore a distinct possibility that there is

sufficient helium concentration over the entire lease for gathering and commercial sales

and once sufficient data is gathered the maps are subject to revision.

This area of low to zero concentrations coincides with a structural high of the Base of the

Karoo. All other known readings of He gas east of the De Bron fault until the Virginia fault

is crossed, appear, at this time until more data is available, to have low to zero

enrichment of He. Thus MHA has assigned He reserves only to a mapped area in the

center of the production license but has increased the average He concentration in those

wells to 3-4%. Gas percentages of up to 4% are found in this zone and an average He


concentration of 3.05% over 202.4 Km2 has been mapped. Within the mapped He

concentration area MHA has 7 known blowers or wells that all have tested greater than

2% He concentrations. Within the concentration area MHA has mapped an additional 14

Proved well locations, 26 Probable well locations and 27 Possible well locations. The

estimated volumes of technically recoverable helium are shown in Tables 8 and 9.


Figure 10: Map of Helium Concentration in %

Figure 10: Map of the Helium concentration. Wells with measured helium concentrations

have green annotations. The Yellow polygon is the area of the Goldfields Mining Lease.


Table 8: Technically Recoverable Helium Estimates of the Virginia Gas Project

Category

Recoverable Volumes (Bcf) Totals (Bcf)

Number of Wells

He (BCF)/Well

Developed Undeveloped

Proven (1P) PDNP & PUD

13 & 24 0.02745 0.357 0.659 1.016

Probable (P2) 48 0.05185 x 2.489 2.489

Possible (P3) 48 0.07930 x 3.086 3.086

Total (P+P+P) 133 x 0.357 6.234 6.591

Table 9: Technically Recoverable Helium Volume Estimates by Contingent Resource Category - Virginia Gas Field

ECONOMICS

TETRA4 OPERATING CONDITIONS AND SALES

AGREEMENTS

Tetra4 operates under a Production License from the Petroleum Authority of South Africa

and must pay a 5% royalty based on wellhead price to the South African Revenue

Service. An additional royalty of one percent of wellhead price is owed to the GFI Mining

South Africa (GFIMSA) or Goldfields on all new wells located on their existing licenses.

Tetra4 has provided to MHA a signed Gas Sales Agreement (GSA) with Unitrans

Passenger Limited (Megabus) for the purchase of natural gas. The gas will be sold in

liquefied state by the liter and the purchase price is indexed to a local pricing point for

sulphur free diesel at the Megabus purchase price minus a 22.5% discount.

Tetra4 has also provided MHA a signed Gas Sales Agreement with Linde Global Helium

(Linde) for the purchase of Helium gas at the price point of approximately $200/mcf

escalating according to US CPI index.

Number of Wells

Low Case (C1)

(Bcf)

Best Case (C2)

(Bcf)

High Case (C3)

(Bcf)

368 10.1 19.1 29.2


The Tetra4 field development plans call for the construction of a gas gathering system,

setting compression, the installation of the above-mentioned gas processing facilities and

as production increases, an expansion of the entire system. MHA has reviewed Tetra4’s

detailed plans for abandonment and rehabilitation of the wells and all infrastructures that

have been submitted to, and accepted by, the Petroleum Authority of South Africa

(PASA). These plans meet, and in places exceed, governmental regulations for

abandonment, rehabilitation, and monitoring.


Figure 11: Map Tetra4 Virginia Gas License and Current Plus Planned Wells


ECONOMIC PARAMETERS

Type Wells

MHA constructed three type wells for this report, each with a different initial rate and the

same exponential decline of 5%. Initial rates of the 1P, 2P, and 3P type wells are 150

mcfd, 260 mcfd, and 380 mcfd, respectively. The associated 1P, 2P, and 3P EUR’s are

0.9 bcf, 1.65 bcf, and 2.59 bcf, respectively. All three type wells rates and recoveries are

shown in Figures 12 and 13.

Figure 12: Renergen Type Wells

1

10

100

1000

0 50 100 150 200 250 300 350 400

gas p

rod

ucti

on

rate

, m

cfd

month

1P 2P 3P


Figure 13: Renergen Type Wells – Cumulative Gas Production

0

500

1,000

1,500

2,000

2,500

3,000

0 50 100 150 200 250 300 350 400

cu

mu

lati

ve g

as p

rod

ucti

on

, m

mcf

month

1P 2P 3P


Type well rates and recovery are on a gross gas volume. Produced gas volumes were

multiplied by 0.9 to account for 10% impurities in the produced gas stream and were

subject to a 5% shrink. Helium production was forecasted from methane production

volumes and the assumed 3% helium in the wellhead gas stream.

Capital Costs

Well drilling and completion CAPEX was 1.5 mZAR per well. The recent drilling campaign

of 9 wells resulted in 5 producers and 4 dry holes. This dry hole risk of roughly 40% was

addressed by increasing the nominal single well capital to 2.1 mZAR. Connection CAPEX

was 1.0 mZAR per well. Pipeline capital was 125 mZAR was allocated into two payments

of 50 mZAR (scheduled for Apr 18 and Jan 19) and one payment of 25 mZAR (in Apr 19).

Capital for the initial methane and helium liquefaction plants was 121.48 mZAR and 52.48

mZAR, respectively. Development of the Virginia Field will require additional liquefaction

plants for each 3 mmcfd increment in gross gas production. CAPEX for these additional

methane and helium liquefaction plants was 162.8 mZAR and 58.1 mZAR, respectively.

Based on the three type wells discussed above, new plants will be required for every 20

1P wells drilled (3 mmcfd/150 mcfd per well), every 12 2P wells, and every 8 3P wells. All

capital costs were escalated at 2 %/yr

Operating expenses

Fixed lease operating expenses (LOE’s), assigned at the plant level rather than individual

wells, were 2.11 mZAR per month. The variable OPEX was 13.9 ZAR/mcf, reflecting truck

transport of the methane and helium. All operating expenses were escalated at 2%yr for

the life of the project.

Prices

The methane price was a constant 214.68 ZAR/Gj for the first two months of this project,

March and April 2018, then was escalated at the average South African CPI of 5.813%/yr.

The helium price was a constant 2338.8 ZAR/mcf ( 200 USD/mcf) for the first two months

of this project then was escalated at the average US CPI of 2.2%/yr. forecast. Monthly

methane and helium prices are plotted in Figure 14 and listed in Appendix 1.


Figure 14: Methane and Helium Monthly Prices

MHA assumed a methane BTU factor of 1.01 Gj/mcf (0.960 mmbtu/mcf). Shrink, which

accounts for gas used by the plant, measurement imbalances, and surface losses as well

as helium extraction, was assumed to be a constant 5 % throughout the life of the field.

All wells are burdened with a 5% overriding royalty interest (ORRI) on the wellhead gas

price plus those wells in the Goldfields area are subject to an additional 1% ORRI. The

well counts associated with field development of Reserves and Contingent Resources are

given in Table 10 below.

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0

50

100

150

200

250

300

350

400

450

Dec-14 Sep-17 Jun-20 Mar-23 Dec-25 Sep-28 Jun-31 Feb-34

he

lium

pri

ce, Z

AR

/mcf

me

than

e p

rice

, ZA

R/G

j

date

methane helium


Table 10: Wellcount by Reserve and Contingent Resource Category

Reserves PDNP Total Proved (1P)

Probable Proved + Probable (2P)

Possible Proved + Probable + Possible (3P)

Number of wells

18 52 68 120 68 188

Contingent Resources

Low Case

Best Case

High Case

Number of Methane wells

368 368 368

Number of He wells

264 264 264


RESERVE ECONOMICS

Based on the economic parameters discussed above, reserves and economics were calculated

for the Virginia Gas Field. Gross and net methane and helium reserves based on a 10% discount

rate are collected in Table 11.

Table 11: Gross and Net Methane and Helium Reserves at a 10% Discount Rate

1P

Reserve Cat Gross CH4 (MMCF)

Gross Helium (MMCF)

Net CH4 (MMCF)

Net Helium (MMCF)

TOTAL PDNP 13,988.2 321.3 12,587.5 304.2

TOTAL PUD 26,422.2 593.2 23,772.2 561.5

TOTAL 1P PRV 40,410.4 914.5 36,359.6 865.8

2P


Gross Helium (MMCF)

Net CH4 (MMCF)

Net Helium (MMCF)

TOTAL PDNP 13,988.2 321.3 12,587.5 304.2

TOTAL PUD 26,422.2 593.2 23,772.2 561.5

TOTAL PROVED 40,410.4 914.5 36,359.6 865.8

TOTAL PROBABLE 101,176.1 2,242.8 91,028.8 2,123.2

TOTAL 2P PRV+PRB 141,586.5 3,157.3 127,388.4 2,989.0

3P


Gross Helium (MMCF)

Net CH4 (MMCF)

Net Helium (MMCF)

TOTAL PDNP 13,988.2 321.3 12,587.5 304.2

TOTAL PUD 26,422.2 593.2 23,772.2 561.5

TOTAL PROVED 40,410.4 914.5 36,359.6 865.8

TOTAL PROBABLE 101,176.1 2,242.8 91,028.8 2,123.2

TOTAL POSSIBLE 157,455.3 3,402.7 141,663.5 3,221.2

TOTAL 3P PRV+PRB+POS

299,041.9 6,559.9 269,051.9 6,210.2


At the request of Tetra4, net present values associated with the reserves volumes were calculated

for various discount rates. The results are shown in Table 12.

Table 12: Virginia Gas Field – Methane and Helium Reserves Net Present Values for Selected Discount Factors, mZAR

Discount Factor PDNP

Total Proved

(1P) Probable

Proved + Probable

(2P) Possible

Proved + Probable +

Possible (3P)

Undiscounted 6,910 11,251 62,055 62,117 112,413 164,713

5% 3,312 5,226 24,067 25,516 37,812 59,871

8% 2,352 3,576 16,012 17,037 24,024 38,514

10% 1,935 2,849 12,812 13,538 18,815 30,124

15% 1,298 1,726 8,258 8,407 11,675 18,290

20% 954 1,112 5,935 5,731 8,156 12,339

30% 605 494 3,648 3,097 4,778 6,631

CONTINGENT RESOURCE ECONOMICS

According to the PRMS guidance economics are not required, nor normally run, on Contingent

Resources as by definition contingent resources have not met the threshold of “commerciality”

due to one or more contingencies. Per Renergen’s request, MHA has run Contingent Resource

economics for the Virginia Gas Project utilizing costs and prices discussed above. The resulting

gas volumes and associated un-risked net present values are in Table 13 below. Contingencies

to be resolved include quantification of in-place methane volumes and recharge rates of this

biogenic gas play and confidence that the proposed development program will not deplete the

contingent resource gas volumes.


Table 13: Net Methane and Helium Contingent Resources and Net Present Values Virginia Gas Field – Specified Prices and Costs

CONCLUSIONS

Based on analysis of technical and economic data provided by Tetra4, MHA has estimated

methane and helium Reserves and Resources for the Virginia Gas Field under SPE PRMS and

SAMOG guidances. Estimated Reserves and Contingent Resource gross and net methane and

helium volumes are presented in Table 14. Net present values of the Reserves as requested

discount rates are given in Table 12 above.

Table 14: Virginia Gas Field - Gross and Net Methane and Helium Reserves and Contingent Resources


Gross Helium (MMCF)

Net CH4 (MMCF)

Net Helium (MMCF)

RESERVES TOTAL 1P 40,410.4 914.5 36,359.6 865.8

TOTAL 2P 141,586.5 3,157.3 127,388.4 2,989.0

TOTAL 3P 299,041.9 6,560.0 269,051.9 6,210.2

CONTINGENT RESOURCES

TOTAL C1 285,981.4 9.09 258,098.2 8.64

TOTAL C2 547,541.6 17.19 494,156.3 16.33

TOTAL C3 846,718.8 25.91 764,163.6 24.61

Low (C1) Best (C2) High (C3)

Methane (BCF) 258 494 764

Helium 8.64 16.3 24.6

Net Present Value (MZAR)

Undiscounted 91,663 281,278 539,863

5% 40,560 101,519 174,669

8% 26,948 63,862 106,702

10% 21,072 49,019 81,049

15% 12,234 28,199 46,197

20% 7,635 17,947 29,474

30% 3,338 8,546 14,311


QUALIFICATIONS

Jeffrey B. Aldrich is a Partner in MHA Petroleum Consultants, Inc. (MHA) and is a Certified

Petroleum Geologist, #6254, by the American Association of Petroleum Geologists (AAPG) and a

Licensed Professional Geoscientist, #394; He is an active member of the AAPG and the Society

of Petroleum Engineers (SPE). He has over thirty years as a practicing petroleum

geologist/geophysicist and over twenty years of experience in oil and gas reserve evaluations. He

holds a Bachelor’s of Science degree in Geology from Vanderbilt University and a Master’s of

Science degree in Geology from Texas A&M University. He is an instructor in the PetroSkills

Alliance and is the Course Director for “Prospect and Play Analysis”, Evaluating and Developing

Shale Reservoirs”, “Unconventional Resource and Reserve Estimation”, and “Coalbed Methane

Reservoirs”.

John Seidle is a Partner and Senior Reservoir Engineer with MHA Petroleum Consultants LLC in

Denver, Colorado. He has more than thirty-five years of experience in unconventional gas and oil

reservoir engineering in domestic and international plays. His current duties include

unconventional reservoir engineering, reserve studies and economic evaluations, unconventional

well performance analysis, and serving as an expert witness for litigation and regulatory hearings.

Dr. Seidle is an instructor for industry classes, primarily unconventional reservoirs. Privileged to

work with others on over 29 technical papers, he is the author of “Fundamentals of Coalbed

Methane Reservoir Engineering”. John is editor and chapter author of SPEE Monograph 4,

“Estimating Ultimate Recovery of Developed Wells in Low-Permeability Reservoirs”. He received

a PhD in Mechanical Engineering from the University of Colorado, is a member of SPE, AAPG,

and SPEE, and is a Registered Professional Engineer in Colorado, Oklahoma, and Wyoming.

Unconventional reservoir experience includes USA, Canada, Australia, China, India, South Africa,

New Zealand, Colombia, Mexico, France, UK, Turkey, Poland, Mongolia, Ukraine.


BIBLIOGRAPHY

Hugo, P. (1963). Helium in the Orange Free State Gold-Field. Pretoria: The Government Printer.

Lollar, B. S., Lacrampe-Couloume, G., Slater, G., Ward, J., Moser, D., Gihring, T., et al. (2006).

Unravelling abiogenic and biogenic sources of methane in the Earth’s deep subsurface.

Chemical Geology, 328-339.

Lollar, B. S., Westgate, T., Ward, J., Slater, G., & Lacrampe-Couloume, G. (2002). Abiogenic

formation of alkenes in the Earth's crust as a minor source for global hydrocarbon

reservoirs. Nature, 522-524.

McCarthy, T. (2006). The Witwatersrand Supergroup. Geology of South Africa, 155-186.

SPE/AAPG/WPC/SPEE/SEG. (2007). Petroleum Resources Management System. Society of

Petroleum Engineers.

The South African Oil and Gas (SAMOG) Committee. (2015). The South African Code for the

Reporting of Oil and Gas Resources. Marshalltown: The South African Oil and Gas

(SAMOG) Committee.

van der Westhuizen, W., & de Bruiyn, H. (2006). The Ventersdorp Subgroup. Geology of South

Africa, 187-208.

Ward, J., Slater, G., Moser, D., Lin, L.-H., Lacrampe-Couloume, G., Bonin, A., et al. (2004).

Microbial hydrocarbon gases in the Witwatersrand Basin, South Africa: Implications for the

deep biosphere. Geochimica et Cosmochimica Acta, 3239-3250.


APPENDIX 1: METHANE AND HELIUM PRICES

As discussed above, the methane price was a constant 214.68 ZAR/Gj for the first two

months of this project, March and April 2018, then was escalated at the average South

African CPI of 5.813%/yr. The helium price was a constant 2338.8 ZAR/mcf (200

USD/mcf) for the first two months of this project then was escalated at the average US

CPI of 2.2%/yr. Monthly methane and helium prices are listed in Table A.1 below.

Methane Helium

Methane Helium

Date ZAR/GJ ZAR/mcf

Date ZAR/GJ ZAR/mcf

31-Aug-17 214.7 2,338.80

29-Feb-20 240.4 2,442.80

30-Sep-17 214.7 2,338.80

31-Mar-20 240.4 2,442.80

31-Oct-17 214.7 2,338.80

30-Apr-20 254.3 2,496.60

30-Nov-17 214.7 2,338.80

31-May-20 254.3 2,496.60

31-Dec-17 214.7 2,338.80

30-Jun-20 254.3 2,496.60

31-Jan-18 214.7 2,338.80

31-Jul-20 254.3 2,496.60

28-Feb-18 214.7 2,338.80

31-Aug-20 254.3 2,496.60

31-Mar-18 214.7 2,338.80

30-Sep-20 254.3 2,496.60

30-Apr-18 227.2 2,390.30

31-Oct-20 254.3 2,496.60

31-May-18 227.2 2,390.30

30-Nov-20 254.3 2,496.60

30-Jun-18 227.2 2,390.30

31-Dec-20 254.3 2,496.60

31-Jul-18 227.2 2,390.30

31-Jan-21 254.3 2,496.60

31-Aug-18 227.2 2,390.30

28-Feb-21 254.3 2,496.60

30-Sep-18 227.2 2,390.30

31-Mar-21 254.3 2,496.60

31-Oct-18 227.2 2,390.30

30-Apr-21 269.1 2,551.50

30-Nov-18 227.2 2,390.30

31-May-21 269.1 2,551.50

31-Dec-18 227.2 2,390.30

30-Jun-21 269.1 2,551.50

31-Jan-19 227.2 2,390.30

31-Jul-21 269.1 2,551.50

28-Feb-19 227.2 2,390.30

31-Aug-21 269.1 2,551.50

31-Mar-19 227.2 2,390.30

30-Sep-21 269.1 2,551.50

30-Apr-19 240.4 2,442.80

31-Oct-21 269.1 2,551.50

31-May-19 240.4 2,442.80

30-Nov-21 269.1 2,551.50

30-Jun-19 240.4 2,442.80

31-Dec-21 269.1 2,551.50

31-Jul-19 240.4 2,442.80

31-Jan-22 269.1 2,551.50

31-Aug-19 240.4 2,442.80

28-Feb-22 269.1 2,551.50

30-Sep-19 240.4 2,442.80

31-Mar-22 269.1 2,551.50

31-Oct-19 240.4 2,442.80

30-Apr-22 284.8 2,607.60

30-Nov-19 240.4 2,442.80

31-May-22 284.8 2,607.60

31-Dec-19 240.4 2,442.80

30-Jun-22 284.8 2,607.60

31-Jan-20 240.4 2,442.80

31-Jul-22 284.8 2,607.60


Methane Helium

Methane Helium

Date ZAR/GJ ZAR/mcf

Date ZAR/GJ ZAR/mcf

31-Aug-22 284.8 2,607.60

31-Jan-26 337.4 2,783.60

30-Sep-22 284.8 2,607.60

28-Feb-26 337.4 2,783.60

31-Oct-22 284.8 2,607.60

31-Mar-26 337.4 2,783.60

30-Nov-22 284.8 2,607.60

30-Apr-26 357 2,844.80

31-Dec-22 284.8 2,607.60

31-May-26 357 2,844.80

31-Jan-23 284.8 2,607.60

30-Jun-26 357 2,844.80

28-Feb-23 284.8 2,607.60

31-Jul-26 357 2,844.80

31-Mar-23 284.8 2,607.60

31-Aug-26 357 2,844.80

30-Apr-23 301.3 2,665.00

30-Sep-26 357 2,844.80

31-May-23 301.3 2,665.00

31-Oct-26 357 2,844.80

30-Jun-23 301.3 2,665.00

30-Nov-26 357 2,844.80

31-Jul-23 301.3 2,665.00

31-Dec-26 357 2,844.80

31-Aug-23 301.3 2,665.00

31-Jan-27 357 2,844.80

30-Sep-23 301.3 2,665.00

28-Feb-27 357 2,844.80

31-Oct-23 301.3 2,665.00

31-Mar-27 357 2,844.80

30-Nov-23 301.3 2,665.00

30-Apr-27 377.7 2,907.40

31-Dec-23 301.3 2,665.00

31-May-27 377.7 2,907.40

31-Jan-24 301.3 2,665.00

30-Jun-27 377.7 2,907.40

29-Feb-24 301.3 2,665.00

31-Jul-27 377.7 2,907.40

31-Mar-24 301.3 2,665.00

31-Aug-27 377.7 2,907.40

30-Apr-24 318.8 2,723.60

30-Sep-27 377.7 2,907.40

31-May-24 318.8 2,723.60

31-Oct-27 377.7 2,907.40

30-Jun-24 318.8 2,723.60

30-Nov-27 377.7 2,907.40

31-Jul-24 318.8 2,723.60

31-Dec-27 377.7 2,907.40

31-Aug-24 318.8 2,723.60

31-Jan-28 377.7 2,907.40

30-Sep-24 318.8 2,723.60

29-Feb-28 377.7 2,907.40

31-Oct-24 318.8 2,723.60

31-Mar-28 377.7 2,907.40

30-Nov-24 318.8 2,723.60

30-Apr-28 399.7 2,971.30

31-Dec-24 318.8 2,723.60

31-May-28 399.7 2,971.30

31-Jan-25 318.8 2,723.60

30-Jun-28 399.7 2,971.30

28-Feb-25 318.8 2,723.60

31-Jul-28 399.7 2,971.30

31-Mar-25 318.8 2,723.60

31-Aug-28 399.7 2,971.30

30-Apr-25 337.4 2,783.60

30-Sep-28 399.7 2,971.30

31-May-25 337.4 2,783.60

31-Oct-28 399.7 2,971.30

30-Jun-25 337.4 2,783.60

30-Nov-28 399.7 2,971.30

31-Jul-25 337.4 2,783.60

31-Dec-28 399.7 2,971.30

31-Aug-25 337.4 2,783.60

31-Jan-29 399.7 2,971.30

30-Sep-25 337.4 2,783.60

28-Feb-29 399.7 2,971.30

31-Oct-25 337.4 2,783.60

31-Mar-29 399.7 2,971.30

30-Nov-25 337.4 2,783.60

30-Apr-29 422.9 3,036.70

31-Dec-25 337.4 2,783.60

31-May-29 422.9 3,036.70


Methane Helium

Date ZAR/GJ ZAR/mcf

30-Jun-29 422.9 3,036.70

31-Jul-29 422.9 3,036.70

31-Aug-29 422.9 3,036.70

30-Sep-29 422.9 3,036.70

31-Oct-29 422.9 3,036.70

30-Nov-29 422.9 3,036.70

31-Dec-29 422.9 3,036.70

31-Jan-30 422.9 3,036.70

28-Feb-30 422.9 3,036.70

31-Mar-30 422.9 3,036.70

30-Apr-30 447.5 3,103.50

31-May-30 447.5 3,103.50

30-Jun-30 447.5 3,103.50

31-Jul-30 447.5 3,103.50

31-Aug-30 447.5 3,103.50

30-Sep-30 447.5 3,103.50

31-Oct-30 447.5 3,103.50

30-Nov-30 447.5 3,103.50

31-Dec-30 447.5 3,103.50

31-Jan-31 447.5 3,103.50

28-Feb-31 447.5 3,103.50

31-Mar-31 447.5 3,103.50

30-Apr-31 473.5 3,171.80

31-May-31 473.5 3,171.80

30-Jun-31 473.5 3,171.80

31-Jul-31 473.5 3,171.80

31-Aug-31 473.5 3,171.80

30-Sep-31 473.5 3,171.80

31-Oct-31 473.5 3,171.80

30-Nov-31 473.5 3,171.80

31-Dec-31 473.5 3,171.80

31-Jan-32 473.5 3,171.80

29-Feb-32 473.5 3,171.80

31-Mar-32 473.5 3,171.80

30-Apr-32 501.1 3,241.60

31-May-32 501.1 3,241.60

30-Jun-32 501.1 3,241.60

31-Jul-32 501.1 3,241.60

31-Aug-32 501.1 3,241.60


APPENDIX 2: RESERVE CATEGORY CASH FLOW SUMMARIES

PIPELINE AND PLANT COSTS DATE : 02/22/2018

TIME : 13:30:39

DBS : MHA

SETTINGS : SET0318_ZAR

SCENARIO : MHA0318_1P_ZAR

R E S E R V E S A N D E C O N O M I C S

AS OF DATE: 03/2018

--END-- GROSS GROSS GROSS NET NET NET NET OIL NET CH4 NET HELIUM TOTAL

MO-YEAR OIL CH4 HELIUM OIL CH4 HELIUM PRICE PRICE PRICE NET SALES

------- ---MBBLS-- ---MMCF-- ---MMCF-- ---MBBLS-- ---MMCF-- ---MMCF-- --ZAR/BBL- --ZAR/MCF- --ZAR/MCF- --ZAR M$--

12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2020 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2021 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2022 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2023 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2024 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2025 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2026 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2027 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2028 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2029 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2030 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2031 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2032 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

S TOT 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

TOTAL 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

--END-- NET NET NET TOTAL DIRECT OPER ABANDONMENT EQUITY FUTURE NET CUMULATIVE CUM. DISC.

MO-YEAR OIL SALES CH4 SALES HELIUM SALES TAX EXPENSE COST INVESTMENT CASHFLOW CASHFLOW CASHFLOW

------- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- --ZAR M$-- @10% ZAR M$

12-2018 0.000 0.000 0.000 0.000 21.093 0.000 223.960 -245.053 -245.053 -239.746

12-2019 0.000 0.000 0.000 0.000 128.839 0.000 115.260 -244.099 -489.152 -456.604

12-2020 0.000 0.000 0.000 0.000 183.257 0.000 0.000 -183.257 -672.410 -603.376

12-2021 0.000 0.000 0.000 0.000 186.922 0.000 0.000 -186.922 -859.332 -739.473

12-2022 0.000 0.000 0.000 0.000 190.661 0.000 0.000 -190.661 -1049.993 -865.672

12-2023 0.000 0.000 0.000 0.000 194.474 0.000 0.000 -194.474 -1244.467 -982.693

12-2024 0.000 0.000 0.000 0.000 198.364 0.000 0.000 -198.364 -1442.830 -1091.203

12-2025 0.000 0.000 0.000 0.000 202.331 0.000 0.000 -202.331 -1645.161 -1191.822

12-2026 0.000 0.000 0.000 0.000 206.377 0.000 0.000 -206.377 -1851.538 -1285.123

12-2027 0.000 0.000 0.000 0.000 210.505 0.000 0.000 -210.505 -2062.043 -1371.639

12-2028 0.000 0.000 0.000 0.000 214.715 0.000 0.000 -214.715 -2276.759 -1451.862

12-2029 0.000 0.000 0.000 0.000 219.009 0.000 0.000 -219.009 -2495.768 -1526.251

12-2030 0.000 0.000 0.000 0.000 223.390 0.000 0.000 -223.390 -2719.157 -1595.230

12-2031 0.000 0.000 0.000 0.000 227.857 0.000 0.000 -227.857 -2947.015 -1659.192

12-2032 0.000 0.000 0.000 0.000 232.414 0.000 0.000 -232.414 -3179.429 -1718.503

S TOT 0.000 0.000 0.000 0.000 2840.209 0.000 339.220 -3179.429 -3179.429 -1718.503

AFTER 0.000 0.000 0.000 0.000 5048.399 0.000 0.000 -5048.399 -8227.828 -2279.239

TOTAL 0.000 0.000 0.000 0.000 7888.608 0.000 339.220 -8227.828 -8227.828 -2279.239

OIL GAS P.W. % P.W., ZAR M$

--------- --------- ------ ------------

GROSS WELLS 0.0 0.0 LIFE, YRS. 49.83 0.00 -8227.827

GROSS ULT., MB & MMF 0.000 0.000 DISCOUNT % 10.00 5.00 -3860.269

GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 49.83 8.00 -2748.744

GROSS RES., MB & MMF 0.000 0.000 DISCOUNTED PAYOUT, YRS. 49.83 10.00 -2279.239

NET RES., MB & MMF 0.000 0.000 UNDISCOUNTED NET/INVEST. -23.26 15.00 -1584.847

NET REVENUE, M$ 0.000 0.000 DISCOUNTED NET/INVEST. -6.03 20.00 -1224.048

INITIAL PRICE, $ 0.000 0.000 RATE-OF-RETURN, PCT. 0.00 30.00 -869.726

INITIAL N.I., PCT. 0.000 100.000 INITIAL W.I., PCT. 0.000 60.00 -527.869

80.00 -442.517

100.00 -390.360


PROVED NON-PRODUCING RESERVES DATE : 02/22/2018

TETRA4 VIRGINIA METHANE TIME : 13:30:40

AND HELIUM GAS FIELDS DBS : MHA

REPUBLIC OF SOUTH AFRICA SETTINGS : SET0318_ZAR

AS OF MARCH 1, 2018 SCENARIO : MHA0318_1P_ZAR


AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 599.543 13.894 0.000 539.542 13.158 0.000 230.503 2441.411 156.490

12-2020 0.000 839.976 19.270 0.000 755.854 18.247 0.000 240.750 2482.887 227.276

12-2021 0.000 797.977 18.306 0.000 718.062 17.334 0.000 254.745 2537.510 226.909

12-2022 0.000 758.078 17.391 0.000 682.159 16.468 0.000 269.553 2593.336 226.584

12-2023 0.000 720.174 16.521 0.000 648.051 15.644 0.000 285.222 2650.389 226.302

12-2024 0.000 684.166 15.695 0.000 615.648 14.862 0.000 301.802 2708.697 226.061

12-2025 0.000 649.957 14.911 0.000 584.866 14.119 0.000 319.346 2768.288 225.860

12-2026 0.000 617.460 14.165 0.000 555.622 13.413 0.000 337.909 2829.190 225.698

12-2027 0.000 586.586 13.457 0.000 527.841 12.742 0.000 357.552 2891.433 225.574

12-2028 0.000 557.257 12.784 0.000 501.449 12.105 0.000 378.336 2955.045 225.488

12-2029 0.000 529.394 12.145 0.000 476.377 11.500 0.000 400.329 3020.055 225.438

12-2030 0.000 502.925 11.538 0.000 452.558 10.925 0.000 423.600 3086.497 225.424

12-2031 0.000 477.778 10.961 0.000 429.930 10.379 0.000 448.224 3154.400 225.444

12-2032 0.000 453.889 10.413 0.000 408.434 9.860 0.000 474.280 3223.797 225.498

S TOT 0.000 8815.666 202.738 0.000 7932.950 191.980 0.000 324.407 2767.913 3104.891

AFTER 0.000 5172.550 118.564 0.000 4654.502 112.268 0.000 780.847 3867.026 4068.599

TOTAL 0.000 13988.216 321.302 0.000 12587.453 304.248 0.000 493.187 3173.489 7173.490




12-2018 0.000 7.928 2.919 0.000 0.535 0.000 1.000 9.312 9.312 8.914

12-2019 0.000 124.366 32.123 0.000 8.075 0.000 17.340 131.074 140.386 122.253

12-2020 0.000 181.972 45.305 0.000 11.540 0.000 0.000 215.736 356.122 295.026

12-2021 0.000 182.922 43.986 0.000 11.182 0.000 0.000 215.726 571.849 452.085

12-2022 0.000 183.878 42.706 0.000 10.836 0.000 0.000 215.748 787.597 594.881

12-2023 0.000 184.838 41.463 0.000 10.500 0.000 0.000 215.802 1003.399 724.727

12-2024 0.000 185.804 40.257 0.000 10.174 0.000 0.000 215.886 1219.286 842.815

12-2025 0.000 186.774 39.085 0.000 9.859 0.000 0.000 216.001 1435.287 950.224

12-2026 0.000 187.750 37.948 0.000 9.553 0.000 0.000 216.145 1651.431 1047.934

12-2027 0.000 188.731 36.844 0.000 9.257 0.000 0.000 216.317 1867.749 1136.832

12-2028 0.000 189.717 35.772 0.000 8.970 0.000 0.000 216.518 2084.267 1217.723

12-2029 0.000 190.708 34.731 0.000 8.692 0.000 0.000 216.746 2301.013 1291.338

12-2030 0.000 191.704 33.720 0.000 8.423 0.000 0.000 217.001 2518.014 1358.340

12-2031 0.000 192.705 32.739 0.000 8.161 0.000 0.000 217.282 2735.296 1419.329

12-2032 0.000 193.712 31.786 0.000 7.908 0.000 0.000 217.589 2952.885 1474.852

S TOT 0.000 2573.508 531.383 0.000 133.665 0.000 18.340 2952.885 2952.885 1474.852

AFTER 0.000 3634.455 434.144 0.000 106.318 4.977 0.000 3957.304 6910.190 1934.985

TOTAL 0.000 6207.962 965.527 0.000 239.984 4.977 18.340 6910.190 6910.190 1934.985


--------- --------- ------ ------------

GROSS WELLS 0.0 18.0 LIFE, YRS. 32.75 0.00 6910.189

GROSS ULT., MB & MMF 0.000 13988.214 DISCOUNT % 10.00 5.00 3311.927

GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.08 8.00 2351.930

GROSS RES., MB & MMF 0.000 13988.214 DISCOUNTED PAYOUT, YRS. 0.08 10.00 1934.985

NET RES., MB & MMF 0.000 12587.454 UNDISCOUNTED NET/INVEST. 377.78 15.00 1298.393

NET REVENUE, M$ 0.000 6207963.136 DISCOUNTED NET/INVEST. 118.16 20.00 954.146

INITIAL PRICE, $ 0.000 229.384 RATE-OF-RETURN, PCT. 100.00 30.00 604.902

INITIAL N.I., PCT. 0.000 95.000 INITIAL W.I., PCT. 100.000 60.00 265.605

80.00 185.773

100.00 139.967


PROVED UNDEVELOPED RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 1106.250 24.835 0.000 995.300 23.511 0.000 230.754 2442.840 287.103

12-2020 0.000 1591.757 35.735 0.000 1432.113 33.829 0.000 240.750 2482.886 428.775

12-2021 0.000 1512.170 33.948 0.000 1360.508 32.138 0.000 254.745 2537.510 428.132

12-2022 0.000 1436.561 32.251 0.000 1292.483 30.531 0.000 269.553 2593.335 427.569

12-2023 0.000 1364.733 30.638 0.000 1227.858 29.004 0.000 285.222 2650.389 427.085

12-2024 0.000 1296.496 29.106 0.000 1166.466 27.554 0.000 301.802 2708.697 426.677

12-2025 0.000 1231.671 27.651 0.000 1108.142 26.176 0.000 319.346 2768.289 426.344

12-2026 0.000 1170.089 26.268 0.000 1052.735 24.868 0.000 337.909 2829.190 426.084

12-2027 0.000 1111.583 24.955 0.000 1000.098 23.624 0.000 357.552 2891.434 425.895

12-2028 0.000 1056.004 23.707 0.000 950.093 22.443 0.000 378.337 2955.045 425.775

12-2029 0.000 1003.204 22.522 0.000 902.589 21.321 0.000 400.329 3020.055 425.723

12-2030 0.000 953.044 21.396 0.000 857.459 20.255 0.000 423.600 3086.496 425.736

12-2031 0.000 905.392 20.326 0.000 814.586 19.242 0.000 448.224 3154.399 425.814

12-2032 0.000 860.123 19.310 0.000 773.857 18.280 0.000 474.279 3223.797 425.955

S TOT 0.000 16599.078 372.649 0.000 14934.286 352.775 0.000 325.093 2771.288 5832.666

AFTER 0.000 9823.108 220.529 0.000 8837.909 208.767 0.000 781.962 3869.667 7718.767

TOTAL 0.000 26422.186 593.178 0.000 23772.196 561.542 0.000 494.945 3179.638 13551.434




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 229.670 57.433 0.000 14.900 0.000 107.508 164.694 164.694 138.778

12-2020 0.000 344.781 83.994 0.000 21.868 0.000 0.000 406.906 571.601 464.649

12-2021 0.000 346.582 81.550 0.000 21.190 0.000 0.000 406.941 978.542 760.921

12-2022 0.000 348.392 79.177 0.000 20.534 0.000 0.000 407.035 1385.578 1030.322

12-2023 0.000 350.212 76.872 0.000 19.897 0.000 0.000 407.188 1792.765 1275.323

12-2024 0.000 352.042 74.635 0.000 19.280 0.000 0.000 407.397 2200.162 1498.165

12-2025 0.000 353.881 72.464 0.000 18.682 0.000 0.000 407.662 2607.824 1700.880

12-2026 0.000 355.729 70.355 0.000 18.103 0.000 0.000 407.981 3015.804 1885.311

12-2027 0.000 357.587 68.308 0.000 17.542 0.000 0.000 408.353 3424.157 2053.128

12-2028 0.000 359.455 66.320 0.000 16.998 0.000 0.000 408.776 3832.933 2205.847

12-2029 0.000 361.333 64.390 0.000 16.471 0.000 0.000 409.251 4242.184 2344.843

12-2030 0.000 363.220 62.516 0.000 15.961 0.000 0.000 409.775 4651.960 2471.365

12-2031 0.000 365.117 60.697 0.000 15.466 0.000 0.000 410.348 5062.308 2586.546

12-2032 0.000 367.024 58.931 0.000 14.987 0.000 0.000 410.969 5473.276 2691.415

S TOT 0.000 4855.025 977.641 0.000 251.880 0.000 107.508 5473.276 5473.276 2691.415

AFTER 0.000 6910.907 807.860 0.000 201.997 9.400 0.000 7507.369 12980.647 3562.277

TOTAL 0.000 11765.932 1785.500 0.000 453.877 9.400 107.508 12980.646 12980.647 3562.277


--------- --------- ------ ------------






NET REVENUE, M$ 0.00011765934.080 DISCOUNTED NET/INVEST. 37.63 20.00 1715.760



80.00 291.187

100.00 209.967


TOTAL PROVED (1P) RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 1705.792 38.729 0.000 1534.842 36.668 0.000 230.666 2442.327 443.592

12-2020 0.000 2431.733 55.005 0.000 2187.968 52.076 0.000 240.750 2482.886 656.051

12-2021 0.000 2310.147 52.254 0.000 2078.570 49.472 0.000 254.745 2537.510 655.040

12-2022 0.000 2194.639 49.642 0.000 1974.641 46.998 0.000 269.553 2593.335 654.153

12-2023 0.000 2084.908 47.160 0.000 1875.908 44.649 0.000 285.222 2650.389 653.387

12-2024 0.000 1980.662 44.802 0.000 1782.114 42.416 0.000 301.802 2708.697 652.738

12-2025 0.000 1881.628 42.562 0.000 1693.008 40.295 0.000 319.346 2768.288 652.204

12-2026 0.000 1787.548 40.434 0.000 1608.357 38.281 0.000 337.909 2829.191 651.782

12-2027 0.000 1698.170 38.412 0.000 1527.940 36.366 0.000 357.552 2891.434 651.469

12-2028 0.000 1613.261 36.491 0.000 1451.542 34.548 0.000 378.336 2955.045 651.263

12-2029 0.000 1532.598 34.667 0.000 1378.966 32.821 0.000 400.329 3020.055 651.161

12-2030 0.000 1455.968 32.933 0.000 1310.017 31.180 0.000 423.600 3086.496 651.160

12-2031 0.000 1383.171 31.287 0.000 1244.516 29.621 0.000 448.224 3154.399 651.258

12-2032 0.000 1314.012 29.722 0.000 1182.291 28.140 0.000 474.279 3223.797 651.453

S TOT 0.000 25414.742 575.387 0.000 22867.236 544.754 0.000 324.855 2770.099 8937.556

AFTER 0.000 14995.657 339.093 0.000 13492.411 321.036 0.000 781.577 3868.742 11787.366

TOTAL 0.000 40410.400 914.480 0.000 36359.648 865.790 0.000 494.336 3177.477 20724.922




12-2018 0.000 7.928 2.919 0.000 21.628 0.000 224.960 -235.742 -235.742 -230.832

12-2019 0.000 354.036 89.556 0.000 151.814 0.000 240.108 51.670 -184.072 -195.574

12-2020 0.000 526.753 129.298 0.000 216.666 0.000 0.000 439.386 255.314 156.300

12-2021 0.000 529.504 125.536 0.000 219.295 0.000 0.000 435.745 691.059 473.534

12-2022 0.000 532.270 121.883 0.000 222.030 0.000 0.000 432.123 1123.182 759.530

12-2023 0.000 535.051 118.336 0.000 224.871 0.000 0.000 428.516 1551.698 1017.356

12-2024 0.000 537.845 114.892 0.000 227.818 0.000 0.000 424.920 1976.618 1249.776

12-2025 0.000 540.655 111.549 0.000 230.872 0.000 0.000 421.332 2397.949 1459.282

12-2026 0.000 543.479 108.303 0.000 234.034 0.000 0.000 417.748 2815.697 1648.121

12-2027 0.000 546.318 105.151 0.000 237.304 0.000 0.000 414.165 3229.862 1818.321

12-2028 0.000 549.171 102.091 0.000 240.683 0.000 0.000 410.579 3640.442 1971.708

12-2029 0.000 552.040 99.121 0.000 244.173 0.000 0.000 406.988 4047.430 2109.930

12-2030 0.000 554.924 96.236 0.000 247.773 0.000 0.000 403.387 4450.817 2234.475

12-2031 0.000 557.822 93.436 0.000 251.485 0.000 0.000 399.773 4850.590 2346.683

12-2032 0.000 560.736 90.717 0.000 255.309 0.000 0.000 396.143 5246.733 2447.764

S TOT 0.000 7428.533 1509.023 0.000 3225.755 0.000 465.068 5246.733 5246.733 2447.764

AFTER 0.000 10545.362 1242.004 0.000 5356.713 14.377 0.000 6416.276 11663.009 3218.024

TOTAL 0.000 17973.895 2751.028 0.000 8582.469 14.377 465.068 11663.009 11663.009 3218.024


--------- --------- ------ ------------









80.00 34.443


2P PROVED NON-PRODUCING RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 599.543 13.894 0.000 539.542 13.158 0.000 230.503 2441.411 156.490

12-2020 0.000 839.976 19.270 0.000 755.854 18.247 0.000 240.750 2482.887 227.276

12-2021 0.000 797.977 18.306 0.000 718.062 17.334 0.000 254.745 2537.510 226.909

12-2022 0.000 758.078 17.391 0.000 682.159 16.468 0.000 269.553 2593.336 226.584

12-2023 0.000 720.174 16.521 0.000 648.051 15.644 0.000 285.222 2650.389 226.302

12-2024 0.000 684.166 15.695 0.000 615.648 14.862 0.000 301.802 2708.697 226.061

12-2025 0.000 649.957 14.911 0.000 584.866 14.119 0.000 319.346 2768.288 225.860

12-2026 0.000 617.460 14.165 0.000 555.622 13.413 0.000 337.909 2829.190 225.698

12-2027 0.000 586.586 13.457 0.000 527.841 12.742 0.000 357.552 2891.433 225.574

12-2028 0.000 557.257 12.784 0.000 501.449 12.105 0.000 378.336 2955.045 225.488

12-2029 0.000 529.394 12.145 0.000 476.377 11.500 0.000 400.329 3020.055 225.438

12-2030 0.000 502.925 11.538 0.000 452.558 10.925 0.000 423.600 3086.497 225.424

12-2031 0.000 477.778 10.961 0.000 429.930 10.379 0.000 448.224 3154.400 225.444

12-2032 0.000 453.889 10.413 0.000 408.434 9.860 0.000 474.280 3223.797 225.498

S TOT 0.000 8815.666 202.738 0.000 7932.950 191.980 0.000 324.407 2767.913 3104.891

AFTER 0.000 5172.550 118.564 0.000 4654.502 112.268 0.000 780.847 3867.026 4068.599

TOTAL 0.000 13988.216 321.302 0.000 12587.453 304.248 0.000 493.187 3173.489 7173.490




12-2018 0.000 7.928 2.919 0.000 0.535 0.000 1.000 9.312 9.312 8.914

12-2019 0.000 124.366 32.123 0.000 8.075 0.000 17.340 131.074 140.386 122.253

12-2020 0.000 181.972 45.305 0.000 11.540 0.000 0.000 215.736 356.122 295.026

12-2021 0.000 182.922 43.986 0.000 11.182 0.000 0.000 215.726 571.849 452.085

12-2022 0.000 183.878 42.706 0.000 10.836 0.000 0.000 215.748 787.597 594.881

12-2023 0.000 184.838 41.463 0.000 10.500 0.000 0.000 215.802 1003.399 724.727

12-2024 0.000 185.804 40.257 0.000 10.174 0.000 0.000 215.886 1219.286 842.815

12-2025 0.000 186.774 39.085 0.000 9.859 0.000 0.000 216.001 1435.287 950.224

12-2026 0.000 187.750 37.948 0.000 9.553 0.000 0.000 216.145 1651.431 1047.934

12-2027 0.000 188.731 36.844 0.000 9.257 0.000 0.000 216.317 1867.749 1136.832

12-2028 0.000 189.717 35.772 0.000 8.970 0.000 0.000 216.518 2084.267 1217.723

12-2029 0.000 190.708 34.731 0.000 8.692 0.000 0.000 216.746 2301.013 1291.338

12-2030 0.000 191.704 33.720 0.000 8.423 0.000 0.000 217.001 2518.014 1358.340

12-2031 0.000 192.705 32.739 0.000 8.161 0.000 0.000 217.282 2735.296 1419.329

12-2032 0.000 193.712 31.786 0.000 7.908 0.000 0.000 217.589 2952.885 1474.852

S TOT 0.000 2573.508 531.383 0.000 133.665 0.000 18.340 2952.885 2952.885 1474.852

AFTER 0.000 3634.455 434.144 0.000 106.318 4.977 0.000 3957.304 6910.190 1934.985

TOTAL 0.000 6207.962 965.527 0.000 239.984 4.977 18.340 6910.190 6910.190 1934.985


--------- --------- ------ ------------









80.00 185.773

100.00 139.967


2P PROVED UNDEVELOPED RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 1106.250 24.835 0.000 995.300 23.511 0.000 230.754 2442.840 287.103

12-2020 0.000 1591.757 35.735 0.000 1432.113 33.829 0.000 240.750 2482.886 428.775

12-2021 0.000 1512.170 33.948 0.000 1360.508 32.138 0.000 254.745 2537.510 428.132

12-2022 0.000 1436.561 32.251 0.000 1292.483 30.531 0.000 269.553 2593.335 427.569

12-2023 0.000 1364.733 30.638 0.000 1227.858 29.004 0.000 285.222 2650.389 427.085

12-2024 0.000 1296.496 29.106 0.000 1166.466 27.554 0.000 301.802 2708.697 426.677

12-2025 0.000 1231.671 27.651 0.000 1108.142 26.176 0.000 319.346 2768.289 426.344

12-2026 0.000 1170.089 26.268 0.000 1052.735 24.868 0.000 337.909 2829.190 426.084

12-2027 0.000 1111.583 24.955 0.000 1000.098 23.624 0.000 357.552 2891.434 425.895

12-2028 0.000 1056.004 23.707 0.000 950.093 22.443 0.000 378.337 2955.045 425.775

12-2029 0.000 1003.204 22.522 0.000 902.589 21.321 0.000 400.329 3020.055 425.723

12-2030 0.000 953.044 21.396 0.000 857.459 20.255 0.000 423.600 3086.496 425.736

12-2031 0.000 905.392 20.326 0.000 814.586 19.242 0.000 448.224 3154.399 425.814

12-2032 0.000 860.123 19.310 0.000 773.857 18.280 0.000 474.279 3223.797 425.955

S TOT 0.000 16599.078 372.649 0.000 14934.286 352.775 0.000 325.093 2771.288 5832.666

AFTER 0.000 9823.108 220.529 0.000 8837.909 208.767 0.000 781.962 3869.667 7718.767

TOTAL 0.000 26422.186 593.178 0.000 23772.196 561.542 0.000 494.945 3179.638 13551.434




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 229.670 57.433 0.000 14.900 0.000 107.508 164.694 164.694 138.778

12-2020 0.000 344.781 83.994 0.000 21.868 0.000 0.000 406.906 571.601 464.649

12-2021 0.000 346.582 81.550 0.000 21.190 0.000 0.000 406.941 978.542 760.921

12-2022 0.000 348.392 79.177 0.000 20.534 0.000 0.000 407.035 1385.578 1030.322

12-2023 0.000 350.212 76.872 0.000 19.897 0.000 0.000 407.188 1792.765 1275.323

12-2024 0.000 352.042 74.635 0.000 19.280 0.000 0.000 407.397 2200.162 1498.165

12-2025 0.000 353.881 72.464 0.000 18.682 0.000 0.000 407.662 2607.824 1700.880

12-2026 0.000 355.729 70.355 0.000 18.103 0.000 0.000 407.981 3015.804 1885.311

12-2027 0.000 357.587 68.308 0.000 17.542 0.000 0.000 408.353 3424.157 2053.128

12-2028 0.000 359.455 66.320 0.000 16.998 0.000 0.000 408.776 3832.933 2205.847

12-2029 0.000 361.333 64.390 0.000 16.471 0.000 0.000 409.251 4242.184 2344.843

12-2030 0.000 363.220 62.516 0.000 15.961 0.000 0.000 409.775 4651.960 2471.365

12-2031 0.000 365.117 60.697 0.000 15.466 0.000 0.000 410.348 5062.308 2586.546

12-2032 0.000 367.024 58.931 0.000 14.987 0.000 0.000 410.969 5473.276 2691.415

S TOT 0.000 4855.025 977.641 0.000 251.880 0.000 107.508 5473.276 5473.276 2691.415

AFTER 0.000 6910.907 807.860 0.000 201.997 9.400 0.000 7507.369 12980.647 3562.277

TOTAL 0.000 11765.932 1785.500 0.000 453.877 9.400 107.508 12980.646 12980.647 3562.277


--------- --------- ------ ------------









80.00 291.187

100.00 209.967


2P PROBABLE RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 2701.879 66.123 0.000 2430.656 62.595 0.000 230.754 2442.840 713.794

12-2020 0.000 5574.746 123.268 0.000 5015.646 116.693 0.000 240.750 2482.887 1497.252

12-2021 0.000 5296.012 117.104 0.000 4764.865 110.859 0.000 254.745 2537.511 1495.128

12-2022 0.000 5031.208 111.249 0.000 4526.620 105.316 0.000 269.553 2593.335 1493.283

12-2023 0.000 4779.650 105.687 0.000 4300.288 100.050 0.000 285.222 2650.389 1491.709

12-2024 0.000 4540.667 100.402 0.000 4085.276 95.047 0.000 301.802 2708.699 1490.399

12-2025 0.000 4313.634 95.382 0.000 3881.012 90.295 0.000 319.346 2768.290 1489.347

12-2026 0.000 4097.954 90.613 0.000 3686.961 85.780 0.000 337.909 2829.190 1488.548

12-2027 0.000 3893.057 86.082 0.000 3502.612 81.491 0.000 357.552 2891.434 1487.994

12-2028 0.000 3698.402 81.778 0.000 3327.484 77.417 0.000 378.336 2955.043 1487.678

12-2029 0.000 3513.482 77.689 0.000 3161.109 73.546 0.000 400.329 3020.057 1487.597

12-2030 0.000 3337.810 73.805 0.000 3003.052 69.869 0.000 423.600 3086.495 1487.744

12-2031 0.000 3170.918 70.115 0.000 2852.899 66.375 0.000 448.225 3154.400 1488.113

12-2032 0.000 3012.373 66.609 0.000 2710.258 63.057 0.000 474.279 3223.798 1488.700

S TOT 0.000 56961.796 1265.906 0.000 51248.736 1198.391 0.000 327.035 2776.361 20087.286

AFTER 0.000 44214.352 976.931 0.000 39780.032 924.828 0.000 1009.214 4202.332 44033.016

TOTAL 0.000 101176.144 2242.837 0.000 91028.768 2123.219 0.000 625.151 3397.483 64120.300




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 560.884 152.910 0.000 36.392 0.000 215.016 462.387 462.387 392.611

12-2020 0.000 1207.516 289.737 0.000 76.589 0.000 0.000 1420.663 1883.050 1530.351

12-2021 0.000 1213.823 281.305 0.000 74.214 0.000 0.000 1420.914 3303.964 2564.841

12-2022 0.000 1220.163 273.119 0.000 71.914 0.000 0.000 1421.369 4725.333 3505.587

12-2023 0.000 1226.537 265.171 0.000 69.684 0.000 0.000 1422.025 6147.358 4361.204

12-2024 0.000 1232.944 257.455 0.000 67.524 0.000 0.000 1422.875 7570.232 5139.503

12-2025 0.000 1239.385 249.963 0.000 65.431 0.000 0.000 1423.916 8994.148 5847.564

12-2026 0.000 1245.859 242.689 0.000 63.403 0.000 0.000 1425.145 10419.293 6491.811

12-2027 0.000 1252.366 235.627 0.000 61.437 0.000 0.000 1426.557 11845.850 7078.069

12-2028 0.000 1258.908 228.770 0.000 59.532 0.000 0.000 1428.146 13273.996 7611.624

12-2029 0.000 1265.484 222.113 0.000 57.687 0.000 0.000 1429.910 14703.906 8097.273

12-2030 0.000 1272.093 215.649 0.000 55.899 0.000 0.000 1431.845 16135.751 8539.369

12-2031 0.000 1278.740 209.374 0.000 54.166 0.000 0.000 1433.947 17569.698 8941.865

12-2032 0.000 1285.418 203.281 0.000 52.487 0.000 0.000 1436.213 19005.911 9308.348

S TOT 0.000 16760.120 3327.165 0.000 866.358 0.000 215.016 19005.911 19005.911 9308.348

AFTER 0.000 40146.575 3886.436 0.000 964.673 18.801 0.000 43049.533 62055.457 12811.971

TOTAL 0.000 56906.695 7213.601 0.000 1831.031 18.801 215.016 62055.444 62055.457 12811.971


--------- --------- ------ ------------









80.00 990.018

100.00 714.115


TOTAL PROVED + PROBABLE (2P) RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 4407.671 104.852 0.000 3965.498 99.264 0.000 230.720 2442.651 1157.386

12-2020 0.000 8006.479 178.272 0.000 7203.613 168.769 0.000 240.750 2482.887 2153.304

12-2021 0.000 7606.158 169.359 0.000 6843.434 160.331 0.000 254.745 2537.510 2150.168

12-2022 0.000 7225.848 160.891 0.000 6501.262 152.314 0.000 269.553 2593.335 2147.436

12-2023 0.000 6864.558 152.846 0.000 6176.197 144.698 0.000 285.222 2650.390 2145.095

12-2024 0.000 6521.329 145.204 0.000 5867.390 137.464 0.000 301.802 2708.699 2143.137

12-2025 0.000 6195.263 137.944 0.000 5574.020 130.590 0.000 319.346 2768.289 2141.551

12-2026 0.000 5885.503 131.047 0.000 5295.318 124.061 0.000 337.909 2829.191 2140.329

12-2027 0.000 5591.226 124.494 0.000 5030.552 117.858 0.000 357.552 2891.434 2139.463

12-2028 0.000 5311.664 118.270 0.000 4779.026 111.965 0.000 378.336 2955.044 2138.941

12-2029 0.000 5046.080 112.356 0.000 4540.075 106.367 0.000 400.329 3020.056 2138.757

12-2030 0.000 4793.778 106.738 0.000 4313.070 101.048 0.000 423.600 3086.495 2138.904

12-2031 0.000 4554.089 101.401 0.000 4097.415 95.996 0.000 448.225 3154.400 2139.371

12-2032 0.000 4326.386 96.331 0.000 3892.548 91.196 0.000 474.279 3223.797 2140.153

S TOT 0.000 82376.536 1841.293 0.000 74115.984 1743.145 0.000 326.362 2774.404 29024.840

AFTER 0.000 59210.012 1316.023 0.000 53272.444 1245.864 0.000 951.560 4116.371 55820.378

TOTAL 0.000 141586.544 3157.316 0.000 127388.432 2989.010 0.000 587.813 3333.756 84845.216




12-2018 0.000 7.928 2.919 0.000 21.628 0.000 224.960 -235.742 -235.742 -230.832

12-2019 0.000 914.920 242.467 0.000 211.659 0.000 532.644 413.084 177.342 109.374

12-2020 0.000 1734.269 419.035 0.000 388.940 0.000 0.000 1764.363 1941.705 1522.353

12-2021 0.000 1743.328 406.841 0.000 391.109 0.000 0.000 1759.060 3700.765 2803.015

12-2022 0.000 1752.434 395.002 0.000 393.495 0.000 0.000 1753.940 5454.706 3963.864

12-2023 0.000 1761.587 383.507 0.000 396.098 0.000 0.000 1748.998 7203.704 5016.206

12-2024 0.000 1770.789 372.347 0.000 398.915 0.000 0.000 1744.221 8947.925 5970.266

12-2025 0.000 1780.040 361.512 0.000 401.948 0.000 0.000 1739.603 10687.528 6835.296

12-2026 0.000 1789.337 350.992 0.000 405.194 0.000 0.000 1735.135 12422.663 7619.667

12-2027 0.000 1798.684 340.778 0.000 408.654 0.000 0.000 1730.809 14153.472 8330.952

12-2028 0.000 1808.080 330.861 0.000 412.327 0.000 0.000 1726.614 15880.086 8976.006

12-2029 0.000 1817.524 321.234 0.000 416.213 0.000 0.000 1722.544 17602.630 9561.037

12-2030 0.000 1827.017 311.886 0.000 420.312 0.000 0.000 1718.591 19321.221 10091.661

12-2031 0.000 1836.562 302.810 0.000 424.624 0.000 0.000 1714.747 21035.969 10572.968

12-2032 0.000 1846.154 293.998 0.000 429.149 0.000 0.000 1711.003 22746.972 11009.564

S TOT 0.000 24188.654 4836.189 0.000 5520.265 0.000 757.604 22746.972 22746.972 11009.564

AFTER 0.000 50691.936 5128.439 0.000 14955.613 33.178 0.000 40831.586 63578.554 14828.875

TOTAL 0.000 74880.590 9964.628 0.000 20475.877 33.178 757.604 63578.558 63578.554 14828.875


--------- --------- ------ ------------









80.00 925.219

100.00 597.824


3P PROVED NON-PRODUCING RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 599.543 13.894 0.000 539.542 13.158 0.000 230.503 2441.411 156.490

12-2020 0.000 839.976 19.270 0.000 755.854 18.247 0.000 240.750 2482.887 227.276

12-2021 0.000 797.977 18.306 0.000 718.062 17.334 0.000 254.745 2537.510 226.909

12-2022 0.000 758.078 17.391 0.000 682.159 16.468 0.000 269.553 2593.336 226.584

12-2023 0.000 720.174 16.521 0.000 648.051 15.644 0.000 285.222 2650.389 226.302

12-2024 0.000 684.166 15.695 0.000 615.648 14.862 0.000 301.802 2708.697 226.061

12-2025 0.000 649.957 14.911 0.000 584.866 14.119 0.000 319.346 2768.288 225.860

12-2026 0.000 617.460 14.165 0.000 555.622 13.413 0.000 337.909 2829.190 225.698

12-2027 0.000 586.586 13.457 0.000 527.841 12.742 0.000 357.552 2891.433 225.574

12-2028 0.000 557.257 12.784 0.000 501.449 12.105 0.000 378.336 2955.045 225.488

12-2029 0.000 529.394 12.145 0.000 476.377 11.500 0.000 400.329 3020.055 225.438

12-2030 0.000 502.925 11.538 0.000 452.558 10.925 0.000 423.600 3086.497 225.424

12-2031 0.000 477.778 10.961 0.000 429.930 10.379 0.000 448.224 3154.400 225.444

12-2032 0.000 453.889 10.413 0.000 408.434 9.860 0.000 474.280 3223.797 225.498

S TOT 0.000 8815.666 202.738 0.000 7932.950 191.980 0.000 324.407 2767.913 3104.891

AFTER 0.000 5172.550 118.564 0.000 4654.502 112.268 0.000 780.847 3867.026 4068.599

TOTAL 0.000 13988.216 321.302 0.000 12587.453 304.248 0.000 493.187 3173.489 7173.490




12-2018 0.000 7.928 2.919 0.000 0.535 0.000 1.000 9.312 9.312 8.914

12-2019 0.000 124.366 32.123 0.000 8.075 0.000 17.340 131.074 140.386 122.253

12-2020 0.000 181.972 45.305 0.000 11.540 0.000 0.000 215.736 356.122 295.026

12-2021 0.000 182.922 43.986 0.000 11.182 0.000 0.000 215.726 571.849 452.085

12-2022 0.000 183.878 42.706 0.000 10.836 0.000 0.000 215.748 787.597 594.881

12-2023 0.000 184.838 41.463 0.000 10.500 0.000 0.000 215.802 1003.399 724.727

12-2024 0.000 185.804 40.257 0.000 10.174 0.000 0.000 215.886 1219.286 842.815

12-2025 0.000 186.774 39.085 0.000 9.859 0.000 0.000 216.001 1435.287 950.224

12-2026 0.000 187.750 37.948 0.000 9.553 0.000 0.000 216.145 1651.431 1047.934

12-2027 0.000 188.731 36.844 0.000 9.257 0.000 0.000 216.317 1867.749 1136.832

12-2028 0.000 189.717 35.772 0.000 8.970 0.000 0.000 216.518 2084.267 1217.723

12-2029 0.000 190.708 34.731 0.000 8.692 0.000 0.000 216.746 2301.013 1291.338

12-2030 0.000 191.704 33.720 0.000 8.423 0.000 0.000 217.001 2518.014 1358.340

12-2031 0.000 192.705 32.739 0.000 8.161 0.000 0.000 217.282 2735.296 1419.329

12-2032 0.000 193.712 31.786 0.000 7.908 0.000 0.000 217.589 2952.885 1474.852

S TOT 0.000 2573.508 531.383 0.000 133.665 0.000 18.340 2952.885 2952.885 1474.852

AFTER 0.000 3634.455 434.144 0.000 106.318 4.977 0.000 3957.304 6910.190 1934.985

TOTAL 0.000 6207.962 965.527 0.000 239.984 4.977 18.340 6910.190 6910.190 1934.985


--------- --------- ------ ------------









80.00 185.773

100.00 139.967


3P PROVED UNDEVELOPED RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 1106.250 24.835 0.000 995.300 23.511 0.000 230.754 2442.840 287.103

12-2020 0.000 1591.757 35.735 0.000 1432.113 33.829 0.000 240.750 2482.886 428.775

12-2021 0.000 1512.170 33.948 0.000 1360.508 32.138 0.000 254.745 2537.510 428.132

12-2022 0.000 1436.561 32.251 0.000 1292.483 30.531 0.000 269.553 2593.335 427.569

12-2023 0.000 1364.733 30.638 0.000 1227.858 29.004 0.000 285.222 2650.389 427.085

12-2024 0.000 1296.496 29.106 0.000 1166.466 27.554 0.000 301.802 2708.697 426.677

12-2025 0.000 1231.671 27.651 0.000 1108.142 26.176 0.000 319.346 2768.289 426.344

12-2026 0.000 1170.089 26.268 0.000 1052.735 24.868 0.000 337.909 2829.190 426.084

12-2027 0.000 1111.583 24.955 0.000 1000.098 23.624 0.000 357.552 2891.434 425.895

12-2028 0.000 1056.004 23.707 0.000 950.093 22.443 0.000 378.337 2955.045 425.775

12-2029 0.000 1003.204 22.522 0.000 902.589 21.321 0.000 400.329 3020.055 425.723

12-2030 0.000 953.044 21.396 0.000 857.459 20.255 0.000 423.600 3086.496 425.736

12-2031 0.000 905.392 20.326 0.000 814.586 19.242 0.000 448.224 3154.399 425.814

12-2032 0.000 860.123 19.310 0.000 773.857 18.280 0.000 474.279 3223.797 425.955

S TOT 0.000 16599.078 372.649 0.000 14934.286 352.775 0.000 325.093 2771.288 5832.666

AFTER 0.000 9823.108 220.529 0.000 8837.909 208.767 0.000 781.962 3869.667 7718.767

TOTAL 0.000 26422.186 593.178 0.000 23772.196 561.542 0.000 494.945 3179.638 13551.434




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 229.670 57.433 0.000 14.900 0.000 107.508 164.694 164.694 138.778

12-2020 0.000 344.781 83.994 0.000 21.868 0.000 0.000 406.906 571.601 464.649

12-2021 0.000 346.582 81.550 0.000 21.190 0.000 0.000 406.941 978.542 760.921

12-2022 0.000 348.392 79.177 0.000 20.534 0.000 0.000 407.035 1385.578 1030.322

12-2023 0.000 350.212 76.872 0.000 19.897 0.000 0.000 407.188 1792.765 1275.323

12-2024 0.000 352.042 74.635 0.000 19.280 0.000 0.000 407.397 2200.162 1498.165

12-2025 0.000 353.881 72.464 0.000 18.682 0.000 0.000 407.662 2607.824 1700.880

12-2026 0.000 355.729 70.355 0.000 18.103 0.000 0.000 407.981 3015.804 1885.311

12-2027 0.000 357.587 68.308 0.000 17.542 0.000 0.000 408.353 3424.157 2053.128

12-2028 0.000 359.455 66.320 0.000 16.998 0.000 0.000 408.776 3832.933 2205.847

12-2029 0.000 361.333 64.390 0.000 16.471 0.000 0.000 409.251 4242.184 2344.843

12-2030 0.000 363.220 62.516 0.000 15.961 0.000 0.000 409.775 4651.960 2471.365

12-2031 0.000 365.117 60.697 0.000 15.466 0.000 0.000 410.348 5062.308 2586.546

12-2032 0.000 367.024 58.931 0.000 14.987 0.000 0.000 410.969 5473.276 2691.415

S TOT 0.000 4855.025 977.641 0.000 251.880 0.000 107.508 5473.276 5473.276 2691.415

AFTER 0.000 6910.907 807.860 0.000 201.997 9.400 0.000 7507.369 12980.647 3562.277

TOTAL 0.000 11765.932 1785.500 0.000 453.877 9.400 107.508 12980.646 12980.647 3562.277


--------- --------- ------ ------------









80.00 291.187

100.00 209.967


TOTAL PROVED 3P RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 1705.792 38.729 0.000 1534.842 36.668 0.000 230.666 2442.327 443.592

12-2020 0.000 2431.733 55.005 0.000 2187.968 52.076 0.000 240.750 2482.886 656.051

12-2021 0.000 2310.147 52.254 0.000 2078.570 49.472 0.000 254.745 2537.510 655.040

12-2022 0.000 2194.639 49.642 0.000 1974.641 46.998 0.000 269.553 2593.335 654.153

12-2023 0.000 2084.908 47.160 0.000 1875.908 44.649 0.000 285.222 2650.389 653.387

12-2024 0.000 1980.662 44.802 0.000 1782.114 42.416 0.000 301.802 2708.697 652.738

12-2025 0.000 1881.628 42.562 0.000 1693.008 40.295 0.000 319.346 2768.288 652.204

12-2026 0.000 1787.548 40.434 0.000 1608.357 38.281 0.000 337.909 2829.191 651.782

12-2027 0.000 1698.170 38.412 0.000 1527.940 36.366 0.000 357.552 2891.434 651.469

12-2028 0.000 1613.261 36.491 0.000 1451.542 34.548 0.000 378.336 2955.045 651.263

12-2029 0.000 1532.598 34.667 0.000 1378.966 32.821 0.000 400.329 3020.055 651.161

12-2030 0.000 1455.968 32.933 0.000 1310.017 31.180 0.000 423.600 3086.496 651.160

12-2031 0.000 1383.171 31.287 0.000 1244.516 29.621 0.000 448.224 3154.399 651.258

12-2032 0.000 1314.012 29.722 0.000 1182.291 28.140 0.000 474.279 3223.797 651.453

S TOT 0.000 25414.742 575.387 0.000 22867.236 544.754 0.000 324.855 2770.099 8937.556

AFTER 0.000 14995.657 339.093 0.000 13492.411 321.036 0.000 781.577 3868.742 11787.366

TOTAL 0.000 40410.400 914.480 0.000 36359.648 865.790 0.000 494.336 3177.477 20724.922




12-2018 0.000 7.928 2.919 0.000 21.628 0.000 224.960 -235.742 -235.742 -230.832

12-2019 0.000 354.036 89.556 0.000 175.267 0.000 356.388 -88.063 -323.804 -316.173

12-2020 0.000 526.753 129.298 0.000 355.781 0.000 118.606 181.664 -142.140 -172.675

12-2021 0.000 529.504 125.536 0.000 383.342 0.000 0.000 271.698 129.558 25.117

12-2022 0.000 532.270 121.883 0.000 389.358 0.000 0.000 264.795 394.353 200.359

12-2023 0.000 535.051 118.336 0.000 395.545 0.000 0.000 257.841 652.194 355.484

12-2024 0.000 537.845 114.892 0.000 401.906 0.000 0.000 250.832 903.026 492.673

12-2025 0.000 540.655 111.549 0.000 408.442 0.000 0.000 243.762 1146.788 613.874

12-2026 0.000 543.479 108.303 0.000 415.155 0.000 0.000 236.627 1383.415 720.831

12-2027 0.000 546.318 105.151 0.000 422.048 0.000 0.000 229.421 1612.836 815.102

12-2028 0.000 549.171 102.091 0.000 429.122 0.000 0.000 222.141 1834.977 898.084

12-2029 0.000 552.040 99.121 0.000 436.380 0.000 0.000 214.781 2049.758 971.021

12-2030 0.000 554.924 96.236 0.000 443.824 0.000 0.000 207.335 2257.093 1035.028

12-2031 0.000 557.822 93.436 0.000 451.457 0.000 0.000 199.801 2456.894 1091.101

12-2032 0.000 560.736 90.717 0.000 459.281 0.000 0.000 192.171 2649.065 1140.130

S TOT 0.000 7428.533 1509.023 0.000 5588.537 0.000 699.954 2649.065 2649.065 1140.130

AFTER 0.000 10545.362 1242.004 0.000 21044.652 14.377 0.000 -9271.664 -6622.598 1174.040

TOTAL 0.000 17973.895 2751.028 0.000 26633.189 14.377 699.954 -6622.598 -6622.598 1174.040


--------- --------- ------ ------------

GROSS WELLS 0.0 52.0 LIFE, YRS. 49.83 0.00 -6622.596




NET RES., MB & MMF 0.000 36359.644 UNDISCOUNTED NET/INVEST. -8.46 15.00 844.731



INITIAL N.I., PCT. 0.000 95.000 INITIAL W.I., PCT. 100.000 60.00 -80.990

80.00 -146.537

100.00 -178.295


3P PROBABLE RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 2701.879 66.123 0.000 2430.656 62.595 0.000 230.754 2442.840 713.794

12-2020 0.000 5574.746 123.268 0.000 5015.646 116.693 0.000 240.750 2482.887 1497.252

12-2021 0.000 5296.012 117.104 0.000 4764.865 110.859 0.000 254.745 2537.511 1495.128

12-2022 0.000 5031.208 111.249 0.000 4526.620 105.316 0.000 269.553 2593.335 1493.283

12-2023 0.000 4779.650 105.687 0.000 4300.288 100.050 0.000 285.222 2650.389 1491.709

12-2024 0.000 4540.667 100.402 0.000 4085.276 95.047 0.000 301.802 2708.699 1490.399

12-2025 0.000 4313.634 95.382 0.000 3881.012 90.295 0.000 319.346 2768.290 1489.347

12-2026 0.000 4097.954 90.613 0.000 3686.961 85.780 0.000 337.909 2829.190 1488.548

12-2027 0.000 3893.057 86.082 0.000 3502.612 81.491 0.000 357.552 2891.434 1487.994

12-2028 0.000 3698.402 81.778 0.000 3327.484 77.417 0.000 378.336 2955.043 1487.678

12-2029 0.000 3513.482 77.689 0.000 3161.109 73.546 0.000 400.329 3020.057 1487.597

12-2030 0.000 3337.810 73.805 0.000 3003.052 69.869 0.000 423.600 3086.495 1487.744

12-2031 0.000 3170.918 70.115 0.000 2852.899 66.375 0.000 448.225 3154.400 1488.113

12-2032 0.000 3012.373 66.609 0.000 2710.258 63.057 0.000 474.279 3223.798 1488.700

S TOT 0.000 56961.796 1265.906 0.000 51248.736 1198.391 0.000 327.035 2776.361 20087.286

AFTER 0.000 44214.352 976.931 0.000 39780.032 924.828 0.000 1009.214 4202.332 44033.016

TOTAL 0.000 101176.144 2242.837 0.000 91028.768 2123.219 0.000 625.151 3397.483 64120.300




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 560.884 152.910 0.000 36.392 0.000 215.016 462.387 462.387 392.611

12-2020 0.000 1207.516 289.737 0.000 76.589 0.000 0.000 1420.663 1883.050 1530.351

12-2021 0.000 1213.823 281.305 0.000 74.214 0.000 0.000 1420.914 3303.964 2564.841

12-2022 0.000 1220.163 273.119 0.000 71.914 0.000 0.000 1421.369 4725.333 3505.587

12-2023 0.000 1226.537 265.171 0.000 69.684 0.000 0.000 1422.025 6147.358 4361.204

12-2024 0.000 1232.944 257.455 0.000 67.524 0.000 0.000 1422.875 7570.232 5139.503

12-2025 0.000 1239.385 249.963 0.000 65.431 0.000 0.000 1423.916 8994.148 5847.564

12-2026 0.000 1245.859 242.689 0.000 63.403 0.000 0.000 1425.145 10419.293 6491.811

12-2027 0.000 1252.366 235.627 0.000 61.437 0.000 0.000 1426.557 11845.850 7078.069

12-2028 0.000 1258.908 228.770 0.000 59.532 0.000 0.000 1428.146 13273.996 7611.624

12-2029 0.000 1265.484 222.113 0.000 57.687 0.000 0.000 1429.910 14703.906 8097.273

12-2030 0.000 1272.093 215.649 0.000 55.899 0.000 0.000 1431.845 16135.751 8539.369

12-2031 0.000 1278.740 209.374 0.000 54.166 0.000 0.000 1433.947 17569.698 8941.865

12-2032 0.000 1285.418 203.281 0.000 52.487 0.000 0.000 1436.213 19005.911 9308.348

S TOT 0.000 16760.120 3327.165 0.000 866.358 0.000 215.016 19005.911 19005.911 9308.348

AFTER 0.000 40146.575 3886.436 0.000 964.673 18.801 0.000 43049.533 62055.457 12811.971

TOTAL 0.000 56906.695 7213.601 0.000 1831.031 18.801 215.016 62055.444 62055.457 12811.971


--------- --------- ------ ------------









80.00 990.018

100.00 714.115


3P POSSIBLE RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 270.465 8.276 0.000 242.909 7.824 0.000 230.754 2442.839 75.166

12-2020 0.000 6925.554 158.995 0.000 6231.258 150.532 0.000 242.481 2487.567 1885.417

12-2021 0.000 8005.548 172.376 0.000 7202.646 163.183 0.000 254.747 2537.520 2248.935

12-2022 0.000 7621.284 164.102 0.000 6856.917 155.350 0.000 269.556 2593.347 2251.198

12-2023 0.000 7255.458 156.225 0.000 6527.784 147.893 0.000 285.225 2650.399 2253.864

12-2024 0.000 6907.196 148.726 0.000 6214.454 140.794 0.000 301.805 2708.710 2256.926

12-2025 0.000 6575.650 141.588 0.000 5916.162 134.036 0.000 319.349 2768.301 2260.372

12-2026 0.000 6260.022 134.791 0.000 5632.182 127.602 0.000 337.913 2829.202 2264.201

12-2027 0.000 5959.534 128.321 0.000 5361.838 121.477 0.000 357.556 2891.445 2268.401

12-2028 0.000 5673.482 122.162 0.000 5104.468 115.646 0.000 378.341 2955.059 2272.969

12-2029 0.000 5401.156 116.298 0.000 4859.454 110.095 0.000 400.334 3020.068 2277.898

12-2030 0.000 5141.898 110.716 0.000 4626.200 104.811 0.000 423.605 3086.512 2283.181

12-2031 0.000 4895.086 105.402 0.000 4404.144 99.780 0.000 448.229 3154.414 2288.813

12-2032 0.000 4660.122 100.342 0.000 4192.747 94.990 0.000 474.284 3223.812 2294.786

S TOT 0.000 81552.448 1768.321 0.000 73373.168 1674.014 0.000 333.858 2799.198 29182.126

AFTER 0.000 75902.856 1634.347 0.000 68290.328 1547.179 0.000 1165.729 4392.333 86403.768

TOTAL 0.000 157455.296 3402.668 0.000 141663.488 3221.194 0.000 734.870 3564.401 115585.892




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 56.052 19.113 0.000 3.643 0.000 78.336 -6.813 -6.813 -6.698

12-2020 0.000 1510.959 374.459 0.000 95.147 0.000 139.414 1650.857 1644.044 1302.566

12-2021 0.000 1834.856 414.079 0.000 112.184 0.000 0.000 2136.751 3780.795 2858.190

12-2022 0.000 1848.323 402.876 0.000 108.935 0.000 0.000 2142.264 5923.059 4276.041

12-2023 0.000 1861.889 391.975 0.000 105.780 0.000 0.000 2148.084 8071.143 5568.498

12-2024 0.000 1875.554 381.370 0.000 102.717 0.000 0.000 2154.208 10225.352 6746.807

12-2025 0.000 1889.321 371.052 0.000 99.742 0.000 0.000 2160.631 12385.982 7821.190

12-2026 0.000 1903.188 361.013 0.000 96.853 0.000 0.000 2167.347 14553.330 8800.937

12-2027 0.000 1917.156 351.245 0.000 94.049 0.000 0.000 2174.353 16727.682 9694.495

12-2028 0.000 1931.227 341.742 0.000 91.325 0.000 0.000 2181.644 18909.325 10509.543

12-2029 0.000 1945.403 332.496 0.000 88.680 0.000 0.000 2189.218 21098.543 11253.068

12-2030 0.000 1959.682 323.500 0.000 86.112 0.000 0.000 2197.069 23295.611 11931.423

12-2031 0.000 1974.065 314.747 0.000 83.618 0.000 0.000 2205.194 25500.805 12550.389

12-2032 0.000 1988.554 306.231 0.000 81.197 0.000 0.000 2213.590 27714.394 13115.227

S TOT 0.000 24496.230 4685.898 0.000 1249.981 0.000 217.750 27714.394 27714.394 13115.227

AFTER 0.000 79608.037 6795.728 0.000 1686.218 18.801 0.000 84698.726 112413.131 18814.921

TOTAL 0.000 104104.264 11481.627 0.000 2936.199 18.801 217.750 112413.123 112413.131 18814.921


--------- --------- ------ ------------






NET REVENUE, M$ 0.000************ DISCOUNTED NET/INVEST. 104.16 20.00 8155.687



80.00 1082.951

100.00 738.392


TOTAL PROVED + PROBABLE + POSSIBLE (3P) RESERVES DATE : 02/22/2018






AS OF DATE: 03/2018




12-2018 0.000 40.507 1.288 0.000 36.558 1.224 0.000 216.863 2385.038 10.847

12-2019 0.000 4678.136 113.129 0.000 4208.407 107.088 0.000 230.722 2442.664 1232.552

12-2020 0.000 14932.034 337.267 0.000 13434.870 319.301 0.000 241.553 2485.094 4038.721

12-2021 0.000 15611.706 341.735 0.000 14046.080 323.513 0.000 254.746 2537.515 4399.103

12-2022 0.000 14847.132 324.993 0.000 13358.179 307.664 0.000 269.554 2593.341 4398.634

12-2023 0.000 14120.016 309.071 0.000 12703.980 292.591 0.000 285.224 2650.395 4398.959

12-2024 0.000 13428.524 293.930 0.000 12081.844 278.258 0.000 301.804 2708.704 4400.063

12-2025 0.000 12770.913 279.531 0.000 11490.182 264.626 0.000 319.348 2768.295 4401.923

12-2026 0.000 12145.524 265.838 0.000 10927.500 251.663 0.000 337.911 2829.197 4404.530

12-2027 0.000 11550.760 252.816 0.000 10392.390 239.335 0.000 357.554 2891.440 4407.865

12-2028 0.000 10985.146 240.431 0.000 9883.494 227.611 0.000 378.339 2955.051 4411.911

12-2029 0.000 10447.236 228.654 0.000 9399.530 216.462 0.000 400.331 3020.062 4416.655

12-2030 0.000 9935.676 217.454 0.000 8939.269 205.859 0.000 423.603 3086.504 4422.085

12-2031 0.000 9449.176 206.803 0.000 8501.560 195.776 0.000 448.227 3154.407 4428.184

12-2032 0.000 8986.508 196.674 0.000 8085.295 186.187 0.000 474.282 3223.805 4434.938

S TOT 0.000 163929.008 3609.615 0.000 147489.136 3417.160 0.000 330.091 2786.549 58206.974

AFTER 0.000 135112.880 2950.370 0.000 121562.776 2793.044 0.000 1071.874 4269.238 142224.146

TOTAL 0.000 299041.888 6559.985 0.000 269051.904 6210.204 0.000 665.243 3453.390 200431.124




12-2018 0.000 7.928 2.919 0.000 21.628 0.000 224.960 -235.742 -235.742 -230.832

12-2019 0.000 970.973 261.580 0.000 215.302 0.000 649.740 367.511 131.769 69.739

12-2020 0.000 3245.228 793.494 0.000 527.516 0.000 258.019 3253.185 3384.954 2660.242

12-2021 0.000 3578.183 820.920 0.000 569.740 0.000 0.000 3829.363 7214.318 5448.149

12-2022 0.000 3600.757 797.878 0.000 570.207 0.000 0.000 3828.428 11042.745 7981.987

12-2023 0.000 3623.476 775.483 0.000 571.010 0.000 0.000 3827.950 14870.695 10285.187

12-2024 0.000 3646.343 753.718 0.000 572.147 0.000 0.000 3827.915 18698.611 12378.983

12-2025 0.000 3669.361 732.564 0.000 573.615 0.000 0.000 3828.309 22526.919 14282.628

12-2026 0.000 3692.525 712.005 0.000 575.411 0.000 0.000 3829.118 26356.038 16013.578

12-2027 0.000 3715.840 692.023 0.000 577.533 0.000 0.000 3830.331 30186.369 17587.665

12-2028 0.000 3739.307 672.603 0.000 579.979 0.000 0.000 3831.931 34018.300 19019.250

12-2029 0.000 3762.927 653.729 0.000 582.747 0.000 0.000 3833.908 37852.209 20321.360

12-2030 0.000 3786.699 635.385 0.000 585.835 0.000 0.000 3836.249 41688.457 21505.819

12-2031 0.000 3810.627 617.557 0.000 589.241 0.000 0.000 3838.942 45527.400 22583.353

12-2032 0.000 3834.708 600.229 0.000 592.965 0.000 0.000 3841.974 49369.375 23563.704

S TOT 0.000 48684.880 9522.086 0.000 7704.876 0.000 1132.719 49369.375 49369.375 23563.704

AFTER 0.000 130299.970 11924.168 0.000 23695.540 51.978 0.000 118476.620 167845.986 32800.934

TOTAL 0.000 178984.845 21446.255 0.000 31400.415 51.978 1132.719 167845.986 167845.986 32800.934


--------- --------- ------ ------------









80.00 1926.432

100.00 1274.211


TOTAL CONTINGENT RESOURCES DATE : 03/02/2018




AS OF MARCH 1, 2018 SCENARIO : MHA0318_C1_ZAR


AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2020 0.000 2289.903 72.819 0.000 2066.638 69.178 0.000 244.168 2496.581 677.316

12-2021 0.000 10572.600 336.209 0.000 9541.759 319.398 0.000 255.750 2541.399 3252.023

12-2022 0.000 16371.347 520.607 0.000 14775.138 494.578 0.000 269.907 2594.656 5271.175

12-2023 0.000 16365.412 520.420 0.000 14769.795 494.399 0.000 285.222 2650.392 5523.030

12-2024 0.000 15547.166 494.399 0.000 14031.287 469.679 0.000 301.802 2708.701 5506.887

12-2025 0.000 14769.795 469.679 0.000 13329.739 446.196 0.000 319.345 2768.291 5491.993

12-2026 0.000 14031.288 446.196 0.000 12663.284 423.886 0.000 337.909 2829.185 5478.288

12-2027 0.000 13329.739 423.886 0.000 12030.097 402.691 0.000 357.551 2891.435 5465.738

12-2028 0.000 12663.284 402.691 0.000 11428.584 382.557 0.000 378.336 2955.046 5454.317

12-2029 0.000 12030.097 382.557 0.000 10857.152 363.430 0.000 400.330 3020.047 5444.014

12-2030 0.000 11428.584 363.430 0.000 10314.289 345.258 0.000 423.601 3086.493 5434.785

12-2031 0.000 10857.152 345.258 0.000 9798.589 327.994 0.000 448.224 3154.407 5426.588

12-2032 0.000 10314.289 327.994 0.000 9308.634 311.595 0.000 474.280 3223.800 5419.433

S TOT 0.000 160570.640 5106.144 0.000 144914.992 4850.839 0.000 345.469 2841.136 63845.589

AFTER 0.000 125410.792 3988.062 0.000 113183.248 3788.659 0.000 821.099 3933.797 107838.407

TOTAL 0.000 285981.440 9094.207 0.000 258098.240 8639.498 0.000 554.046 3320.298 171684.004




12-2018 0.000 0.000 0.000 0.000 275.605 0.000 0.000 -275.605 -275.605 -264.944

12-2019 0.000 0.000 0.000 0.000 337.341 0.000 0.000 -337.341 -612.946 -562.139

12-2020 0.000 504.607 172.709 0.000 475.428 0.000 613.836 -411.949 -1024.895 -899.090

12-2021 0.000 2440.306 811.719 0.000 847.942 0.000 651.583 1752.503 727.609 361.546

12-2022 0.000 3987.911 1283.261 0.000 1701.783 0.000 240.083 3329.307 4056.915 2557.081

12-2023 0.000 4212.670 1310.351 0.000 1805.649 0.000 0.000 3717.366 7774.282 4793.786

12-2024 0.000 4234.675 1272.221 0.000 1829.591 0.000 0.000 3677.304 11451.587 6805.231

12-2025 0.000 4256.792 1235.199 0.000 1854.390 0.000 0.000 3637.597 15089.183 8614.070

12-2026 0.000 4279.036 1199.252 0.000 1880.054 0.000 0.000 3598.229 18687.412 10240.668

12-2027 0.000 4301.377 1164.356 0.000 1906.581 0.000 0.000 3559.162 22246.574 11703.333

12-2028 0.000 4323.846 1130.473 0.000 1933.978 0.000 0.000 3520.332 25766.906 13018.519

12-2029 0.000 4346.444 1097.575 0.000 1962.273 0.000 0.000 3481.738 29248.643 14201.031

12-2030 0.000 4369.140 1065.636 0.000 1991.444 0.000 0.000 3443.343 32691.986 15264.180

12-2031 0.000 4391.962 1034.626 0.000 2021.513 0.000 0.000 3405.076 36097.061 16219.940

12-2032 0.000 4414.897 1004.519 0.000 2052.479 0.000 0.000 3366.937 39463.997 17079.078

S TOT 0.000 50063.663 13781.895 0.000 22876.054 0.000 1505.502 39463.997 39463.997 17079.078

AFTER 0.000 92934.636 14903.816 0.000 52105.990 101.745 0.000 55630.696 95094.710 23637.998

TOTAL 0.000 142998.307 28685.711 0.000 74982.048 101.745 1505.502 95094.694 95094.710 23637.998


--------- --------- ------ ------------









80.00 361.866

100.00 71.322








AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2020 0.000 3969.162 124.632 0.000 3582.173 118.400 0.000 244.168 2496.580 1170.247

12-2021 0.000 18325.882 575.431 0.000 16539.046 546.658 0.000 255.751 2541.406 5619.150

12-2022 0.000 28376.996 891.038 0.000 25610.222 846.485 0.000 269.907 2594.662 9108.722

12-2023 0.000 28366.688 890.715 0.000 25600.958 846.179 0.000 285.222 2650.391 9544.649

12-2024 0.000 26948.342 846.179 0.000 24320.916 803.870 0.000 301.802 2708.697 9517.555

12-2025 0.000 25600.958 803.870 0.000 23104.888 763.676 0.000 319.346 2768.292 9492.511

12-2026 0.000 24320.918 763.676 0.000 21949.636 725.494 0.000 337.910 2829.189 9469.536

12-2027 0.000 23104.890 725.494 0.000 20852.170 689.217 0.000 357.551 2891.438 9448.563

12-2028 0.000 21949.636 689.217 0.000 19809.548 654.757 0.000 378.336 2955.048 9429.519

12-2029 0.000 20852.170 654.757 0.000 18819.098 622.019 0.000 400.329 3020.064 9412.351

12-2030 0.000 19809.548 622.019 0.000 17878.130 590.918 0.000 423.600 3086.508 9397.033

12-2031 0.000 18819.098 590.918 0.000 16984.206 561.373 0.000 448.225 3154.399 9383.540

12-2032 0.000 17878.130 561.373 0.000 16135.008 533.304 0.000 474.280 3223.793 9371.767

S TOT 0.000 278322.432 8739.320 0.000 251186.016 8302.350 0.000 345.469 2841.140 110365.147

AFTER 0.000 269219.136 8453.479 0.000 242970.272 8030.804 0.000 1050.348 4255.239 289376.469

TOTAL 0.000 547541.568 17192.800 0.000 494156.288 16333.154 0.000 692.049 3536.434 399741.616




12-2018 0.000 0.000 0.000 0.000 275.605 0.000 0.000 -275.605 -275.605 -264.944

12-2019 0.000 0.000 0.000 0.000 337.341 0.000 0.000 -337.341 -612.946 -562.139

12-2020 0.000 874.653 295.596 0.000 498.498 0.000 692.906 -21.157 -634.103 -595.743

12-2021 0.000 4229.872 1389.279 0.000 956.589 0.000 772.560 3890.004 3255.901 2210.439

12-2022 0.000 6912.381 2196.343 0.000 1873.385 0.000 281.216 6954.130 10210.032 6800.800

12-2023 0.000 7301.946 2242.706 0.000 1980.611 0.000 0.000 7564.034 17774.066 11352.041

12-2024 0.000 7340.100 2177.439 0.000 1999.140 0.000 0.000 7518.407 25292.472 15464.569

12-2025 0.000 7378.451 2114.078 0.000 2018.687 0.000 0.000 7473.838 32766.310 19181.064

12-2026 0.000 7417.001 2052.559 0.000 2039.254 0.000 0.000 7430.289 40196.600 22540.001

12-2027 0.000 7455.717 1992.828 0.000 2060.849 0.000 0.000 7387.707 47584.305 25576.075

12-2028 0.000 7494.670 1934.839 0.000 2083.467 0.000 0.000 7346.040 54930.346 28320.567

12-2029 0.000 7533.836 1878.537 0.000 2107.119 0.000 0.000 7305.241 62235.587 30801.699

12-2030 0.000 7573.180 1823.872 0.000 2131.802 0.000 0.000 7265.239 69500.822 33044.916

12-2031 0.000 7612.752 1770.795 0.000 2157.520 0.000 0.000 7226.002 76726.821 35073.196

12-2032 0.000 7652.504 1719.263 0.000 2184.278 0.000 0.000 7187.483 83914.301 36907.250

S TOT 0.000 86777.061 23588.135 0.000 24704.145 0.000 1746.681 83914.301 83914.301 36907.250

AFTER 0.000 255203.410 34172.989 0.000 85907.333 101.745 0.000 203367.399 287281.709 53487.272

TOTAL 0.000 341980.479 57761.124 0.000 110611.481 101.745 1746.681 287281.709 287281.709 53487.272


--------- --------- ------ ------------









80.00 1402.431

100.00 714.122








AS OF DATE: 03/2018




12-2018 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2019 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12-2020 0.000 5802.077 177.544 0.000 5236.377 168.666 0.000 244.168 2496.586 1699.647

12-2021 0.000 26811.176 820.422 0.000 24197.034 779.401 0.000 255.752 2541.408 8169.216

12-2022 0.000 41566.708 1271.940 0.000 37513.976 1208.343 0.000 269.909 2594.667 13260.601

12-2023 0.000 41632.788 1273.962 0.000 37573.636 1210.264 0.000 285.225 2650.400 13924.599

12-2024 0.000 39634.440 1212.813 0.000 35770.036 1152.173 0.000 301.806 2708.704 13916.494

12-2025 0.000 37731.968 1154.598 0.000 34053.096 1096.866 0.000 319.350 2768.303 13911.248

12-2026 0.000 35920.764 1099.176 0.000 32418.510 1044.219 0.000 337.913 2829.202 13908.978

12-2027 0.000 34196.596 1046.417 0.000 30862.476 994.095 0.000 357.556 2891.452 13909.404

12-2028 0.000 32555.166 996.187 0.000 29381.028 946.378 0.000 378.342 2955.064 13912.638

12-2029 0.000 30992.524 948.370 0.000 27970.666 900.954 0.000 400.335 3020.066 13918.573

12-2030 0.000 29504.888 902.852 0.000 26628.172 857.706 0.000 423.604 3086.512 13927.161

12-2031 0.000 28088.698 859.512 0.000 25350.044 816.537 0.000 448.229 3154.412 13938.309

12-2032 0.000 26740.414 818.256 0.000 24133.186 777.341 0.000 474.284 3223.816 13952.019

S TOT 0.000 411178.208 12582.049 0.000 371088.224 11952.942 0.000 345.933 2842.597 162348.892

AFTER 0.000 435540.608 13327.536 0.000 393075.328 12661.161 0.000 1165.729 4392.331 513831.502

TOTAL 0.000 846718.848 25909.584 0.000 764163.584 24614.104 0.000 767.625 3639.759 676180.394




12-2018 0.000 0.000 0.000 0.000 275.605 0.000 0.000 -275.605 -275.605 -264.944

12-2019 0.000 0.000 0.000 0.000 337.341 0.000 0.000 -337.341 -612.946 -562.139

12-2020 0.000 1278.556 421.090 0.000 523.679 0.000 791.743 384.222 -228.725 -280.977

12-2021 0.000 6188.446 1980.776 0.000 1075.497 0.000 873.374 6220.340 5991.615 4210.460

12-2022 0.000 10125.346 3135.248 0.000 2061.913 0.000 342.915 10855.791 16847.406 11378.136

12-2023 0.000 10716.941 3207.684 0.000 2174.028 0.000 0.000 11750.581 28597.987 18448.302

12-2024 0.000 10795.599 3120.895 0.000 2187.789 0.000 0.000 11728.701 40326.689 24863.736

12-2025 0.000 10874.852 3036.458 0.000 2202.692 0.000 0.000 11708.587 52035.277 30685.946

12-2026 0.000 10954.650 2954.307 0.000 2218.718 0.000 0.000 11690.236 63725.511 35970.548

12-2027 0.000 11035.057 2874.378 0.000 2235.885 0.000 0.000 11673.517 75399.029 40767.861

12-2028 0.000 11116.065 2796.606 0.000 2254.186 0.000 0.000 11658.452 87057.482 45123.416

12-2029 0.000 11197.628 2720.941 0.000 2273.609 0.000 0.000 11644.969 98702.451 49078.424

12-2030 0.000 11279.797 2647.320 0.000 2294.164 0.000 0.000 11632.992 110335.443 52670.173

12-2031 0.000 11362.615 2575.696 0.000 2315.863 0.000 0.000 11622.466 121957.908 55932.441

12-2032 0.000 11445.989 2506.005 0.000 2338.682 0.000 0.000 11613.327 133571.232 58895.811

S TOT 0.000 128371.540 33977.399 0.000 26769.650 0.000 2008.032 133571.232 133571.232 58895.811

AFTER 0.000 458219.520 55612.010 0.000 98666.504 101.745 0.000 415063.343 548634.591 87572.349

TOTAL 0.000 586591.044 89589.408 0.000 125436.150 101.745 2008.032 548634.558 548634.591 87572.349


--------- --------- ------ ------------









80.00 2531.648

100.00 1410.419


APPENDIX 3: PETROLEUM RESOURCES MANAGEMENT SYSTEM

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within

the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be -

discovered accumulations; resources evaluations are focused on those quantities that can

potentially be recovered and marketed by commercial projects. A petroleum resources

management system provides a consistent approach to estimating petroleum quantities,

evaluating development projects, and presenting results within a comprehensive classification

framework.

International efforts to standardize the definitions of petroleum resources and how they are

estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work

initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for

all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then

known as the World Petroleum Congress), working independently, published Reserves definitions

that were strikingly similar. In 1997, the two organizations jointly released a single set of

definitions for Reserves that could be used worldwide. In 2000, the American Association of

Petroleum Geologists (AAPG), SPE, and WPC jointly developed a classification system for all

petroleum resources. This was followed by additional supporting documents: supplemental

application evaluation guidelines (2001) and a glossary of terms utilized in resources definitions

(2005). SPE also published standards for estimating and auditing reserves information (revised

2007).

These definitions and the related classification system are now in common use internationally

within the petroleum industry. They provide a measure of comparability and reduce the subjective

nature of resources estimation. However, the technologies employed in petroleum exploration,

development, production, and processing continue to evolve and improve. The SPE Oil and Gas

Reserves Committee works closely with other organizations to maintain the definitions and issues

periodic revisions to keep current with evolving technologies and changing commercial

opportunities.

This document consolidates, builds on, and replaces guidance previously contained in the 1997

Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions

publications, and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and

Resources”; the latter document remains a valuable source of more detailed background

information, and specific chapters are referenced herein. Appendix A is a consolidated glossary

of terms used in resources evaluations and replaces those published in 2005.

These definitions and guidelines are designed to provide a common reference for the

international petroleum industry, including national reporting and regulatory disclosure agencies,

and to support petroleum project and portfolio management requirements. They are intended to


improve clarity in global communications regarding petroleum resources. It is expected that this

document will be supplemented with industry education programs and application guides

addressing their implementation in a wide spectrum of technical and/or commercial settings.

It is understood that these definitions and guidelines allow flexibility for users and agencies to

tailor application for their particular needs; however, any modifications to the guidance contained

herein should be clearly identified. The definitions and guidelines contained in this document

must not be construed as modifying the interpretation or application of any existing regulatory

reporting requirements.

This SPE/WPC/AAPG/SPEE Petroleum Resources Management System document, including its

Appendix, may be referred to by the abbreviated term “SPE-PRMS” with the caveat that the full

title, including clear recognition of the co-sponsoring organizations, has been initially stated.

1.0 Basic Principles and Definitions

The estimation of petroleum resource quantities involves the interpretation of volumes and values

that have an inherent degree of uncertainty. These quantities are associated with development

projects at various stages of design and implementation. Use of a consistent classification system

enhances comparisons between projects, groups of projects, and total company portfolios

according to forecast production profiles and recoveries. Such a system must consider both

technical and commercial factors that impact the project’s economic feasibility, its productive life,

and its related cash flows.

1.1 Petroleum Resources Classification Framework

Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous,

liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of

which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon

content could be greater than 50%.

The term “resources” as used herein is intended to encompass all quantities of petroleum

naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and

unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum

whether currently considered “conventional” or “unconventional.”


Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification

system. The system defines the major recoverable resources classes: Production, Reserves,

Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from

an accumulation by a project, while the vertical axis represents the “Chance of Commerciality,

that is, the chance that the project that will be developed and reach commercial producing status.

The following definitions apply to the major subdivisions within the resources classification:

TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist

originally in naturally occurring accumulations. It includes that quantity of petroleum that is

estimated, as of a given date, to be contained in known accumulations prior to production plus

those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is

estimated, as of a given date, to be contained in known accumulations prior to production.

PRODUCTION is the cumulative quantity of petroleum that has been recovered at a

given date. While all recoverable resources are estimated and production is measured in

terms of the sales product specifications, raw production (sales plus non-sales) quantities

are also measured and required to support engineering analyses based on reservoir

voidage (see Production Measurement, section 3.2).

Multiple development projects may be applied to each known accumulation, and each project will

recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided


into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified

as Reserves and Contingent Resources respectively, as defined below.

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.

CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given

date, to be potentially recoverable from known accumulations, but the applied project(s)

are not yet considered mature enough for commercial development due to one or more

contingencies. Contingent Resources may include, for example, projects for which there

are currently no viable markets, or where commercial recovery is dependent on

technology under development, or where evaluation of the accumulation is insufficient to

clearly assess commerciality. Contingent Resources 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 their economic status.

UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum

estimated, as of a given date, to be contained within accumulations yet to be discovered.

PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given

date, to be potentially recoverable from undiscovered accumulations by application of

future development projects. Prospective Resources have both an associated chance of

discovery and a chance of development. Prospective Resources are further subdivided in

accordance with the level of certainty associated with recoverable estimates assuming

their discovery and development and may be sub-classified based on project maturity.

UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-

Place quantities which is estimated, as of a given date, not to be recoverable by future

development projects. A portion of these quantities may become recoverable in the future as

commercial circumstances change or technological developments occur; the remaining

portion may never be recovered due to physical/chemical constraints represented by

subsurface interaction of fluids and reservoir rocks.

Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be

applied to any accumulation or group of accumulations (discovered or undiscovered) to define

those quantities of petroleum estimated, as of a given date, to be potentially recoverable under


defined technical and commercial conditions plus those quantities already produced (total of

recoverable resources).

In specialized areas, such as basin potential studies, alternative terminology has been used; the

total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total

recoverable or EUR may be termed Basin Potential. The sum of Reserves, Contingent

Resources, and Prospective Resources may be referred to as “remaining recoverable

resources.” When such terms are used, it is important that each classification component of the

summation also be provided. Moreover, these quantities should not be aggregated without due

consideration of the varying degrees of technical and commercial risk involved with their

classification.

1.2 Project-Based Resources Evaluations

The resources evaluation process consists of identifying a recovery project, or projects,

associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-

Place, estimating that portion of those in-place quantities that can be recovered by each project,

and classifying the project(s) based on its maturity status or chance of commerciality.

This concept of a project-based classification system is further clarified by examining the primary

data sources contributing to an evaluation of net recoverable resources (see Figure 1-2) that may

be described as follows:

The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum

Initially-in-Place and the fluid and rock properties that affect petroleum recovery.

The Project: Each project applied to a specific reservoir development generates a unique production and cash flow schedule. The time integration of these schedules taken to the project’s technical, economic, or contractual limit defines the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to Total Initially-in-Place quantities defines the ultimate recovery efficiency for the development project(s). A project may be defined at various levels and stages of maturity; it may include one or many wells and associated production and processing facilities. One project may develop many reservoirs, or many projects may be applied to one reservoir.

The Property (lease or license area): Each property may have unique associated contractual


rights and obligations including the fiscal terms. Such information allows definition of each participant’s share of produced quantities (entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A property may contain both discovered and undiscovered accumulations.

In context of this data relationship, “project” is the primary element considered in this resources

classification, and net recoverable resources are the incremental quantities derived from each

project. Project represents the link between the petroleum accumulation and the decision-making

process. A project may, for example, constitute the development of a single reservoir or field, or

an incremental development for a producing field, or the integrated development of several fields

and associated facilities with a common ownership. In general, an individual project will represent

the level at which a decision is made whether or not to proceed (i.e., spend more money) and

there should be an associated range of estimated recoverable quantities for that project.

An accumulation or potential accumulation of petroleum may be subject to several separate and

distinct projects that are at different stages of exploration or development. Thus, an accumulation

may have recoverable quantities in several resource classes simultaneously.

In order to assign recoverable resources of any class, a development plan needs to be defined

consisting of one or more projects. Even for Prospective Resources, the estimates of recoverable

quantities must be stated in terms of the sales products derived from a development program

assuming successful discovery and commercial development. Given the major uncertainties

involved at this early stage, the development program will not be of the detail expected in later

stages of maturity. In most cases, recovery efficiency may be largely based on analogous

projects. In-place quantities for which a feasible project cannot be defined using current, or

reasonably forecast improvements in, technology are classified as Unrecoverable.

Not all technically feasible development plans will be commercial. The commercial viability of a

development project is dependent on a forecast of the conditions that will exist during the time

period encompassed by the project’s activities (see Commercial Evaluations, section 3.1).

“Conditions” include technological, economic, legal, environmental, social, and governmental

factors. While economic factors can be summarized as forecast costs and product prices, the

underlying influences include, but are not limited to, market conditions, transportation and

processing infrastructure, fiscal terms, and taxes.

The resource quantities being estimated are those volumes producible from a project as

measured according to delivery specifications at the point of sale or custody transfer (see

Reference Point, section 3.2.1). The cumulative production from the evaluation date forward to

cessation of production is the remaining recoverable quantity. The sum of the associated annual

net cash flows yields the estimated future net revenue. When the cash flows are discounted

according to a defined discount rate and time period, the summation of the discounted cash flows

is termed net present value (NPV) of the project (see Evaluation and Reporting Guidelines,

section 3.0).


The supporting data, analytical processes, and assumptions used in an evaluation should be

documented in sufficient detail to allow an independent evaluator or auditor to clearly understand

the basis for estimation and categorization of recoverable quantities and their classification.

2.0 Classification and Categorization Guidelines

To consistently characterize petroleum projects, evaluations of all resources should be conducted

in the context of the full classification system as shown in Figure 1-1. These guidelines reference

this classification system and support an evaluation in which projects are “classified” based on

their chance of commerciality (the vertical axis) and estimates of recoverable and marketable

quantities associated with each project are “categorized” to reflect uncertainty (the horizontal

axis). The actual workflow of classification vs. categorization varies with individual projects and is

often an iterative analysis process leading to a final report. “Report,” as used herein, refers to the

presentation of evaluation results within the business entity conducting the assessment and

should not be construed as replacing guidelines for public disclosures under guidelines

established by regulatory and/or other government agencies.

Additional background information on resources classification issues can be found in Chapter 2 of

the 2001 SPE/WPC/AAPG publication: “Guidelines for the Evaluation of Petroleum Reserves and

Resources,” hereafter referred to as the “2001 Supplemental Guidelines.”

2.1 Resources Classification

The basic classification requires establishment of criteria for a petroleum discovery and thereafter

the distinction between commercial and sub-commercial projects in known accumulations (and

hence between Reserves and Contingent Resources).

2.1.1 Determination of Discovery Status

A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for

which one or several exploratory wells have established through testing, sampling, and/or logging

the existence of a significant quantity of potentially moveable hydrocarbons.

In this context, “significant” implies that there is evidence of a sufficient quantity of petroleum to

justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential

for economic recovery. Estimated recoverable quantities within such a discovered (known)

accumulation(s) shall initially be classified as Contingent Resources pending definition of projects

with sufficient chance of commercial development to reclassify all, or a portion, as Reserves.

Where in-place hydrocarbons are identified but are not considered currently recoverable, such

quantities may be classified as Discovered Unrecoverable, if considered appropriate for resource

management purposes; a portion of these quantities may become recoverable resources in the

future as commercial circumstances change or technological developments occur.

2.1.2 Determination of Commerciality


Discovered recoverable volumes (Contingent Resources) may be considered commercially

producible, and thus Reserves, if the entity claiming commerciality has demonstrated firm

intention to proceed with development and such intention is based upon all of the following

criteria:

Evidence to support a reasonable timetable for development.

A reasonable assessment of the future economics of such development projects meeting defined investment and operating criteria:

A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required to justify development.

Evidence that the necessary production and transportation facilities are available or can be made available:

Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated.

To be included in the Reserves class, a project must be sufficiently defined to establish its

commercial viability. There must be a reasonable expectation that all required internal and

external approvals will be forthcoming, and there is evidence of firm intention to proceed with

development within a reasonable time frame. A reasonable time frame for the initiation of

development depends on the specific circumstances and varies according to the scope of the

project. While 5 years is recommended as a benchmark, a longer time frame could be applied

where, for example, development of economic projects are deferred at the option of the producer

for, among other things, market-related reasons, or to meet contractual or strategic objectives. In

all cases, the justification for classification as Reserves should be clearly documented.

To be included in the Reserves class, there must be a high confidence in the commercial

producibility of the reservoir as supported by actual production or formation tests. In certain

cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that

the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that

are producing or have demonstrated the ability to produce on formation tests.

2.1.3 Project Status and Commercial Risk

Evaluators have the option to establish a more detailed resources classification reporting system

that can also provide the basis for portfolio management by subdividing the chance of

commerciality axis according to project maturity. Such sub-classes may be characterized by

standard project maturity level descriptions (qualitative) and/or by their associated chance of

reaching producing status (quantitative).

As a project moves to a higher level of maturity, there will be an increasing chance that the

accumulation will be commercially developed. For Contingent and Prospective Resources, this

can further be expressed as a quantitative chance estimate that incorporates two key underlying

risk components:

The chance that the potential accumulation will result in the discovery of petroleum. This is referred to as the “chance of discovery.”

Once discovered, the chance that the accumulation will be commercially developed is


referred to as the “chance of development.”

Thus, for an undiscovered accumulation, the “chance of commerciality” is the product of these

two risk components. For a discovered accumulation where the “chance of discovery” is 100%,

the “chance of commerciality” becomes equivalent to the “chance of development.”

2.1.3.1 Project Maturity Sub-Classes

As illustrated in Figure 2-1, development projects (and their associated recoverable quantities)

may be sub-classified according to project maturity levels and the associated actions (business

decisions) required to move a project toward commercial production.

Project Maturity terminology and definitions have been modified from the example provided in the

2001 Supplemental Guidelines, Chapter 2. Detailed definitions and guidelines for each Project

Maturity sub-class are provided in Table I. This approach supports managing portfolios of

opportunities at various stages of exploration and development and may be supplemented by

associated quantitative estimates of chance of commerciality. The boundaries between different

levels of project maturity may be referred to as “decision gates.”

Decisions within the Reserves class are based on those actions that progress a project through

final approvals to implementation and initiation of production and product sales. For Contingent


Resources, supporting analysis should focus on gathering data and performing analyses to clarify

and then mitigate those key conditions, or contingencies, that prevent commercial development.

For Prospective Resources, these potential accumulations are evaluated according to their

chance of discovery and, assuming a discovery, the estimated quantities that would be

recoverable under appropriate development projects. The decision at each phase is to undertake

further data acquisition and/or studies designed to move the project to a level of technical and

commercial maturity where a decision can be made to proceed with exploration drilling.

Evaluators may adopt alternative sub-classes and project maturity modifiers, but the concept of

increasing chance of commerciality should be a key enabler in applying the overall classification

system and supporting portfolio management.

2.1.3.2 Reserves Status

Once projects satisfy commercial risk criteria, the associated quantities are classified as

Reserves. These quantities may be allocated to the following subdivisions based on the funding

and operational status of wells and associated facilities within the reservoir development plan

(detailed definitions and guidelines are provided in Table 2):

Developed Reserves are expected quantities to be recovered from existing wells and facilities.

o Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

o Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Undeveloped Reserves are quantities expected to be recovered through future investments.

Where Reserves remain undeveloped beyond a reasonable timeframe, or have remained

undeveloped due to repeated postponements, evaluations should be critically reviewed to

document reasons for the delay in initiating development and justify retaining these quantities

within the Reserves class. While there are specific circumstances where a longer delay (see

Determination of Commerciality, section 2.1.2) is justified, a reasonable time frame is generally

considered to be less than 5 years.

Development and production status are of significant importance for project management. While

Reserves Status has traditionally only been applied to Proved Reserves, the same concept of

Developed and Undeveloped Status based on the funding and operational status of wells and

producing facilities within the development project are applicable throughout the full range of

Reserves uncertainty categories (Proved, Probable and Possible).

Quantities may be subdivided by Reserves Status independent of sub-classification by Project

Maturity. If applied in combination, Developed and/or Undeveloped Reserves quantities may be

identified separately within each Reserves sub-class (On Production, Approved for Development,

and Justified for Development).

2.1.3.3 Economic Status


Projects may be further characterized by their Economic Status. All projects classified as

Reserves must be economic under defined conditions (see Commercial Evaluations, section 3.1).

Based on assumptions regarding future conditions and their impact on ultimate economic viability,

projects currently classified as Contingent Resources may be broadly divided into two groups:

Marginal Contingent Resources are those quantities associated with technically feasible projects that are either currently economic or projected to be economic under reasonably forecasted improvements in commercial conditions but are not committed for development because of one or more contingencies.

Sub-Marginal Contingent Resources are those quantities associated with discoveries for which analysis indicates that technically feasible development projects would not be economic and/or other contingencies would not be satisfied under current or reasonably forecasted improvements in commercial conditions. These projects nonetheless should be retained in the inventory of discovered resources pending unforeseen major changes in commercial conditions.

Where evaluations are incomplete such that it is premature to clearly define ultimate chance of

commerciality, it is acceptable to note that project economic status is “undetermined.” Additional

economic status modifiers may be applied to further characterize recoverable quantities; for

example, non-sales (lease fuel, flare, and losses) may be separately identified and documented

in addition to sales quantities for both production and recoverable resource estimates (see also

Reference Point, section 3.2.1). Those discovered in-place volumes for which a feasible

development project cannot be defined using current, or reasonably forecast improvements in,

technology are classified as Unrecoverable.

Economic Status may be identified independently of, or applied in combination with, Project

Maturity sub-classification to more completely describe the project and its associated resources.

2.2 Resources Categorization

The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in

estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a

project. These estimates include both technical and commercial uncertainty components as

follows:

The total petroleum remaining within the accumulation (in-place resources).

That portion of the in-place petroleum that can be recovered by applying a defined development project or projects.

Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., market availability, contractual changes).

Where commercial uncertainties are such that there is significant risk that the complete project

(as initially defined) will not proceed, it is advised to create a separate project classified as

Contingent Resources with an appropriate chance of commerciality.

2.2.1 Range of Uncertainty


The range of uncertainty of the recoverable and/or potentially recoverable volumes may be

represented by either deterministic scenarios or by a probability distribution (see Deterministic

and Probabilistic Methods, section 4.2).

When the range of uncertainty is represented by a probability distribution, a low, best, and high

estimate shall be provided such that:

There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

When using the deterministic scenario method, typically there should also be low, best, and high

estimates, where such estimates are based on qualitative assessments of relative uncertainty

using consistent interpretation guidelines. Under the deterministic incremental (risk-based)

approach, quantities at each level of uncertainty are estimated discretely and separately (see

Category Definitions and Guidelines, section 2.2.2).

These same approaches to describing uncertainty may be applied to Reserves, Contingent

Resources, and Prospective Resources. While there may be significant risk that sub-commercial

and undiscovered accumulations will not achieve commercial production, it useful to consider the

range of potentially recoverable quantities independently of such a risk or consideration of the

resource class to which the quantities will be assigned.

2.2.2 Category Definitions and Guidelines

Evaluators may assess recoverable quantities and categorize results by uncertainty using the

deterministic incremental (risk-based) approach, the deterministic scenario (cumulative)

approach, or probabilistic methods. (see “2001 Supplemental Guidelines,” Chapter 2.5). In many

cases, a combination of approaches is used.

Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation

results. For Reserves, the general cumulative terms low/best/high estimates are denoted as

1 P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and

Possible. Reserves are a subset of, and must be viewed within context of, the complete

resources classification system. While the categorization criteria are proposed specifically for

Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources

conditional upon their satisfying the criteria for discovery and/or development.

For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as

1 C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high

estimates still apply. No specific terms are defined for incremental quantities within Contingent

and Prospective Resources.


Without new technical information, there should be no change in the distribution of technically

recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently

to reclassify a project from Contingent Resources to Reserves. All evaluations require application

of a consistent set of forecast conditions, including assumed future costs and prices, for both

classification of projects and categorization of estimated quantities recovered by each project

(see Commercial Evaluations, section 3.1).

Table III presents category definitions and provides guidelines designed to promote consistency

in resource assessments. The following summarizes the definitions for each Reserves category in

terms of both the deterministic incremental approach and scenario approach and also provides

the probability criteria if probabilistic methods are applied.

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 90% probability that the quantities actually recovered will equal or exceed the estimate.

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 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 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.

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 (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.

Based on additional data and updated interpretations that indicate increased certainty, portions of

Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.

Uncertainty in resource estimates is best communicated by reporting a range of potential results.

However, if it is required to report a single representative result, the “best estimate” is considered

the most realistic assessment of recoverable quantities. It is generally considered to represent the

sum of Proved and Probable estimates (2P) when using the deterministic scenario or the

probabilistic assessment methods. It should be noted that under the deterministic incremental

(risk-based) approach, discrete estimates are made for each category, and they should not be

aggregated without due consideration of their associated risk (see “2001 Supplemental

Guidelines,” Chapter 2.5).

2.3 Incremental Projects


The initial resource assessment is based on application of a defined initial development project.

Incremental projects are designed to increase recovery efficiency and/or to accelerate production

through making changes to wells or facilities, infill drilling, or improved recovery. Such projects

should be classified according to the same criteria as initial projects. Related incremental

quantities are similarly categorized on certainty of recovery. The projected increased recovery

can be included in estimated Reserves if the degree of commitment is such that the project will be

developed and placed on production within a reasonable timeframe.

Circumstances where development will be significantly delayed should be clearly documented. If

there is significant project risk, forecast incremental recoveries may be similarly categorized but

should be classified as Contingent Resources (see Determination of Commerciality, section

2.1.2).

2.3.1 Workovers, Treatments, and Changes of Equipment

Incremental recovery associated with future workover, treatment (including hydraulic fracturing),

re-treatment, changes of equipment, or other mechanical procedures where such projects have

routinely been successful in analogous reservoirs may be classified as Developed or

Undeveloped Reserves depending on the magnitude of associated costs required (see Reserves

Status, section 2.1.3.2).

2.3.2 Compression

Reduction in the backpressure through compression can increase the portion of in-place gas that

can be commercially produced and thus included in Reserves estimates. If the eventual

installation of compression was planned and approved as part of the original development plan,

incremental recovery is included in Undeveloped Reserves. However, if the cost to implement

compression is not significant (relative to the cost of a new well), the incremental quantities may

be classified as Developed Reserves. If compression facilities were not part of the original

approved development plan and such costs are significant, it should be treated as a separate

project subject to normal project maturity criteria.

2.3.3 Infill Drilling

Technical and commercial analyses may support drilling additional producing wells to reduce the

spacing beyond that utilized within the initial development plan, subject to government regulations

(if such approvals are required). Infill drilling may have the combined effect of increasing recovery

efficiency and accelerating production. Only the incremental recovery can be considered as

additional Reserves; this additional recovery may need to be reallocated to individual wells with

different interest ownerships.

2.3.4 Improved Recovery

Improved recovery is the additional petroleum obtained, beyond primary recovery, from naturally

occurring reservoirs by supplementing the natural reservoir performance. It includes


waterflooding, secondary or tertiary recovery processes, and any other means of supplementing

natural reservoir recovery processes.

Improved recovery projects must meet the same Reserves commerciality criteria as primary

recovery projects. There should be an expectation that the project will be economic and that the

entity has committed to implement the project in a reasonable time frame (generally within 5

years; further delays should be clearly justified).

The judgment on commerciality is based on pilot testing within the subject reservoir or by

comparison to a reservoir with analogous rock and fluid properties and where a similar

established improved recovery project has been successfully applied.

Incremental recoveries through improved recovery methods that have yet to be established

through routine, commercially successful applications are included as Reserves only after a

favorable production response from the subject reservoir from either (a) a representative pilot or

(b) an installed program, where the response provides support for the analysis on which the

project is based.

These incremental recoveries in commercial projects are categorized into Proved, Probable, and

Possible Reserves based on certainty derived from engineering analysis and analogous

applications in similar reservoirs.

2.4 Unconventional Resources

Two types of petroleum resources have been defined that may require different approaches for

their evaluations:

• Conventional resources exist in discrete petroleum accumulations related to a localized

geological structural feature and/or stratigraphic condition, typically with each accumulation

bounded by a downdip contact with an aquifer, and which is significantly affected by

hydrodynamic influences such as buoyancy of petroleum in water. The petroleum is

recovered through wellbores and typically requires minimal processing prior to sale.

• Unconventional resources exist in petroleum accumulations that are pervasive throughout a

large area and that are not significantly affected by hydrodynamic influences (also called

“continuous-type deposits”). Examples include coalbed methane (CBM), basin-centered gas,

shale gas, gas hydrates, natural bitumen, and oil shale deposits. Typically, such

accumulations require specialized extraction technology (e.g., dewatering of CBM, massive

fracturing programs for shale gas, steam and/or solvents to mobilize bitumen for in-situ

recovery, and, in some cases, mining activities). Moreover, the extracted petroleum may

require significant processing prior to sale (e.g., bitumen upgraders).

For these petroleum accumulations that are not significantly affected by hydrodynamic influences,

reliance on continuous water contacts and pressure gradient analysis to interpret the extent of

recoverable petroleum may not be possible. Thus, there typically is a need for increased

sampling density to define uncertainty of in-place volumes, variations in quality of reservoir and


hydrocarbons, and their detailed spatial distribution to support detailed design of specialized

mining or in-situ extraction programs.

It is intended that the resources definitions, together with the classification system, will be

appropriate for all types of petroleum accumulations regardless of their in-place characteristics,

extraction method applied, or degree of processing required.

Similar to improved recovery projects applied to conventional reservoirs, successful pilots or

operating projects in the subject reservoir or successful projects in analogous reservoirs may be

required to establish a distribution of recovery efficiencies for non-conventional accumulations.

Such pilot projects may evaluate both extraction efficiency and the efficiency of unconventional

processing facilities to derive sales products prior to custody transfer.

3.0 Evaluation and Reporting Guidelines

The following guidelines are provided to promote consistency in project evaluations and reporting.

“Reporting” refers to the presentation of evaluation results within the business entity conducting

the evaluation and should not be construed as replacing guidelines for subsequent public

disclosures under guidelines established by regulatory and/or other government agencies, or any

current or future associated accounting standards.

3.1 Commercial Evaluations

Investment decisions are based on the entity’s view of future commercial conditions that may

impact the development feasibility (commitment to develop) and production/cash flow schedule of

oil and gas projects. Commercial conditions include, but are not limited to, assumptions of

financial conditions (costs, prices, fiscal terms, taxes), marketing, legal, environmental, social,

and governmental factors. Project value may be assessed in several ways (e.g., historical costs,

comparative market values); the guidelines herein apply only to evaluations based on cash flow

analysis. Moreover, modifying factors such contractual or political risks that may additionally

influence investment decisions are not addressed. (Additional detail on commercial issues can be

found in the “2001 Supplemental Guidelines,” Chapter 4.)

3.1.1 Cash-Flow-Based Resources Evaluations

Resources evaluations are based on estimates of future production and the associated cash flow

schedules for each development project. The sum of the associated annual net cash flows yields

the estimated future net revenue. When the cash flows are discounted according to a defined

discount rate and time period, the summation of the discounted cash flows is termed net present

value (NPV) of the project.


APPENDIX 4: ABBREVIATIONS

This appendix contains a list of abbreviations found in MHA Petroleum Consultants, Inc. reports,

as well as a table comparing Imperial and Metric units. Two conversion tables, used to prepare

this report, are also provided.

AOF absolute open flow

ARTC Alberta Royalty Tax Credit

BOE barrels of oil equivalent

bopd barrels of oil per day

bwpd barrels of water per day

Cr Crown

DCQ daily contract quantity

DSU drilling spacing unit

FH Freehold

GCA gas cost allowance

GOR gas-oil ratio

GORR gross overriding royalty

LPG liquid petroleum gas

Mcfpd thousands of cubic feet per day

MPR maximum permissive rate

MRL maximum rate limitation

NC ‘new’ Crown

NCI net carried interest

NGL natural gas liquids

NORR net overriding royalty

NPI net profits interest

OC ‘old’ Crown

ORRI overriding royalty interest

P&NG petroleum and natural gas

PSU production spacing unit

PVT pressure-volume-temperature

TCGSL TransCanada Gas Services Limited

UOCR Unit Operating Cost Rates for operating gas cost allowance

WI working interest


Imperial Units

Prefixes

Metric Units

M (103) one thousand

MM (106) million

B (109) one billion

T (1012

) one trillion

k (103) one thousand

M (106) million

T (1012

) one billion E

(1018

) one trillion G

(109) one milliard

in. inches

ft feet

mi mile

Length

cm centimetres

m metres

km kilometres

ft2

square feet

ac acres

Area m2

square metres

ha hectares

cf or ft3

cubic feet

scf standard cubic feet

gal gallons

Mcf thousand cubic feet

Mcfpd thousand cubic feet per day

MMcf million cubic feet

MMcfpd million cubic feet per day

Bcf billion cubic feet (109)

bbl barrels

Mbbl thousand barrels

stb stock tank barrel

bbl/d barrels per day

bbl/mo barrels per month

Volume m3

cubic metres

L litres

m3

cubic metre

stm3

stock tank cubic metres

m3/d cubic metre per day

Btu British thermal units

Energy

J joules

MJ/m3

megajoules per cubic metre (106)

TJ/d terajoule per day (1012

)

oz ounce

lb pounds

ton ton

lt long tons

Mlt thousand long tons

Mass

g gram

kg kilograms

t tonne

psi pounds per square inch

psia pounds per square inch absolute

psig pounds per square inch gauge

Pressure

Pa pascals

kPa kilopascals (103)

°F degrees Fahrenheit

°R degrees Rankine

Temperature °C degrees Celsius

K Kelvin

M$ thousand dollars

Dollars

k$ thousand dollars


Imperial Units

Time

Metric Units

sec second

min minute

hr hour

day day

wk week

mo month

yr year

s second

min minute

h hour

d day

week

month

a annum


Conversion Factors — Metric to Imperial

cubic metres (m3) (@ 15°C) x 6.29010 = barrels (bbl) (@ 60°F), water

m3

(@ 15°C) x 6.3300 = bbl (@ 60°F), Ethane

m3

(@ 15°C) x 6.30001 = bbl (@ 60°F), Propane

m3

(@ 15°C) x 6.29683 = bbl (@ 60°F), Butanes

m3

(@ 15°C) x 6.29287 = bbl (@ 60°F), oil, Pentanes Plus

m3

(@ 101.325 kPaa, 15°C) x 0.0354937 = thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)

1,000 cubic metres (103m

3) (@ 101.325 kPaa, 15°C) x 35.49373 = Mcf (@ 14.65 psia, 60°F)

hectares (ha) x 2.4710541 = acres

1,000 square metres (103m

2) x 0.2471054 = acres

10,000 cubic metres (ha.m) x 8.107133 = acre feet (ac-ft)

m3/10

3m

3 (@ 101.325 kPaa, 15° C) x 0.0437809 = Mcf/Ac.ft. (@ 14.65 psia, 60°F)

joules (j) x 0.000948213 = Btu

megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa, x 26.714952 = British thermal units per standard cubic foot (Btu/scf)

15°C) (@ 14.65 psia, 60°F)

dollars per gigajoule ($/GJ) x 1.054615 = $/Mcf (1,000 Btu gas)

metres (m) x 3.28084 = feet (ft)

kilometres (km) x 0.6213712 = miles (mi)

dollars per 1,000 cubic metres ($/103m

3) x 0.0288951 = dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B.C.

($/103m

3) x 0.02817399 = $/Mcf (@ 14.65 psia) Alta.

dollars per cubic metre ($/m3) x 0.158910 = dollars per barrel ($/bbl)

gas/oil ratio (GOR) (m3/m

3) x 5.640309 = GOR (scf/bbl)

kilowatts (kW) x 1.341022 = horsepower

kilopascals (kPa) x 0.145038 = psi

tonnes (t) x 0.9842064 = long tons (LT)

kilograms (kg) x 2.204624 = pounds (lb)

litres (L) x 0.2199692 = gallons (Imperial)

litres (L) x 0.264172 = gallons (U.S.)

cubic metres per million cubic metres (m3/10

6m

3) (C3) x 0.177496 = barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia)

m3/10

6m

3) (C4) x 0.1774069 = bbl/MMcf (@ 14.65 psia)

m3/10

6m

3) (C5+) x 0.1772953 = bbl/MMcf (@ 14.65 psia)

tonnes per million cubic metres (t/106m

3) (sulphur) x 0.0277290 = LT/MMcf (@ 14.65 psia)

millilitres per cubic meter (mL/m3) (C5+) x 0.0061974 = gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf)

(mL/m3) (C5+) x 0.0074428 = gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf)

Kelvin (K) x 1.8 = degrees Rankine (°R)

millipascal seconds (mPa.s) x 1.0 = centipoise


Conversion Factors — Imperial to Metric

barrels (bbl) (@ 60°F) x 0.15898 = cubic metres (m3) (@ 15°C), water

bbl (@ 60°F) x 0.15798 = m3

(@ 15°C), Ethane

bbl (@ 60°F) x 0.15873 = m3

(@ 15°C), Propane

bbl (@ 60°F) x 0.15881 = m3

(@ 15°C), Butanes

bbl (@ 60°F) x 0.15891 = m3

(@ 15°C), oil, Pentanes Plus

thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F) x 28.17399 = m3

(@ 101.325 kPaa, 15°C)

Mcf (@ 14.65 psia, 60°F) x 0.02817399 = 1,000 cubic metres (103m

3) (@ 101.325 kPaa, 15°C)

acres x 0.4046856 = hectares (ha)

acres x 4.046856 = 1,000 square metres (103m

2)

acre feet (ac-ft) x 0.123348 = 10,000 cubic metres (104m

3) (ha.m)

Mcf/ac-ft (@ 14.65 psia, 60°F) x 22.841028 = 103m

3/m

3 (@ 101.325 kPaa, 15°C)

Btu x 1054.615 = joules (J)

British thermal units per standard cubic foot (Btu/Scf) (@ 14.65 psia, x 0.03743222 = megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa,

60°F) 15°C)

$/Mcf (1,000 Btu gas) x 0.9482133 = dollars per gigajoule ($/GJ)

$/Mcf (@ 14.65 psia, 60°F) Alta. x 35.49373 = $/103m

3 (@ 101.325 kPaa, 15°C)

$/Mcf (@ 15.025 psia, 60°F), B.C. x 34.607860 = $/103m

3 (@ 101.325 kPaa, 15°C)

feet (ft) x 0.3048 = metres (m)

miles (mi) x 1.609344 = kilometres (km)

$/bbl x 6.29287 = $/m3

(average for 30°-50° API)

GOR (scf/bbl) x 0.177295 = gas/oil ratio (GOR) (m3/m

3)

horsepower x 0.7456999 = kilowatts (kW)

psi x 6.894757 = kilopascals (kPa)

long tons (LT) x 1.016047 = tonnes (t) pounds

(lb) x 0.453592 = kilograms (kg)

gallons (Imperial) x 4.54609 = litres (L) (.001 m3)

gallons (U.S.) x 3.785412 = litres (L) (.001 m3)

barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia) (C3) x 5.6339198 = cubic metres per million cubic metres (m3/10

6m

3)

bbl/MMcf (C4) x 5.6367593 = (m3/10

6m

3)

bbl/MMcf (C5+) x 5.6403087 = (m3/10

6m

3)

LT/MMcf (sulphur) x 36.063298 = tonnes per million cubic metres (t/106m

3)

gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf) (C5+) x 161.3577 = millilitres per cubic meter (mL/m3)

gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf) (C5+) x 134.3584 = (mL/m3)

degrees Rankine (°R) x 0.555556 = Kelvin (K)

centipoises x 1.0 = millipascal seconds (mPa.s)

independent reserve and resource evaluation report ... · has conducted an independent assessment...

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