APPENDIX H

LAROCHE TECHNICAL EXPERT’S REPORTTECHNICAL EXPERT’S REPORT

(109)

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

1

Independent Technical Specialist’s Report

On the Petroleum Properties of

Amadeus Petroleum Inc.

17 October 2012

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

3

TABLE OF CONTENTS

1. Executive Summary ............................................................................................................. 7 1.1 Asset Overview ............................................................................................................... 7 1.2 Evaluation Methodology .................................................................................................. 9 1.3 Prices and Costs ........................................................................................................... 10 1.4 Qualifications ................................................................................................................ 13 1.5 Condition of Properties ................................................................................................. 13 1.6 Independence ............................................................................................................... 14 1.7 Consent… ..................................................................................................................... 14

2. Oklahoma Properties ......................................................................................................... 15 2.1 Red Creek Project ........................................................................................................ 15

3. Texas Properties ................................................................................................................ 17 3.1 Ford East Field Project ................................................................................................ 17 3.2 Halletsville Project ........................................................................................................ 21 3.3 Morgans Bluff Field Project .......................................................................................... 243.4 Other Producing Properties Project ............................................................................. 26 3.5 Raccoon Bend Field Project ........................................................................................ 28 3.6 Stephens-Shackleford Counties Project ....................................................................... 32 3.7 TNT Producing Properties Project ............................................................................... 37 3.8 North Knox City Unit .................................................................................................... 39 3.9 Parker, J.E. Waterflood ................................................................................................ 42 3.10 Upside Potential .......................................................................................................... 46

4. Appendix ............................................................................................................................ 554.1 List of Terms ................................................................................................................. 55 4.2 Reserve Definitions ....................................................................................................... 57

4.3 Production Profiles ...................................................................................................... 60 4.4 Operating Expense Profiles .......................................................................................... 70 4.5 Net Capital Expense Profiles ........................................................................................ 74

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

4

LIST OF FIGURES

Figure 1-1 Permian – Texas Project Location Map …………………….. 7Figure 1-2 Net Total Proved PV10% by Reserve Category …………………….. 8Figure 1-3 Net Total Proved PV10% by Project Area …………………….. 9Figure 1-4 NYMEX Oil – WTI Price vs Time …………………….. 11Figure 1-5 NYMEX Gas – Henry Hub Price vs Time …………………….. 11Figure 1-6 Product Price Differentials …………………….. 12Figure 2-1 Barrett, Rash 24 – Production Performance Curve …………………….. 16Figure 3-1 Ford East Field Location Map …………………….. 17Figure 3-2 Ramsey Sand Isochore Map …………………….. 19Figure 3-3 Ford East Field Proved Location Map …………………….. 20Figure 3-4 Halletsville Project Location Map …………………….. 21Figure 3-5 New Henderson – Production Performance Curve …………………….. 22Figure 3-6 Morgans Bluff Hackberry Unit Location Map …………………….. 24Figure 3-7 Morgans Bluff Hackberry Unit – Production Performance Curve …………………….. 25Figure 3-8 Higgins Pool Unit – Production Performance Curve …………………….. 27Figure 3-9 Raccoon Bend Field Location Map …………………….. 28Figure 3-10 Raccoon Bend Sample Log Section …………………….. 29Figure 3-11 Stephens County Lease Location Map …………………….. 32Figure 3-12 Duke-Keathly Lease – Production Performance Curve …………………….. 34Figure 3-13 Fambro/Randall/Thomas Lease Location Map …………………….. 35Figure 3-14 Hittson 2 PUD Location Map …………………….. 36Figure 3-15 TNT Properties Location Map …………………….. 37Figure 3-16 Marshall A – Production Performance Curve …………………….. 38Figure 3-17 North Knox City Unit Location Map …………………….. 39Figure 3-18 North Knox City Unit – Production Performance Curve …………………….. 40Figure 3-19 North Knox City Unit - Water-Oil Ratio vs Cumulative Oil …………………….. 41Figure 3-20 Parker Ranch Waterflood – Harper (San Andres) Field …………………….. 43Figure 3-21 Parker Ranch – Isochore Map of San Andres P1 Zone …………………….. 44Figure 3-22 Parker Ranch – Isochore Map of San Andres P2 Zone …………………….. 44Figure 3-23 Hittson & Moon Ranch Location Map …………………….. 46Figure 3-24 Hittson Log Section …………………….. 47Figure 3-25 Moon Ranch 2 Log Section …………………….. 48Figure 3-26 Sikes-Randall Log Section …………………….. 49Figure 3-27 R.O. Thomas Cross Section …………………….. 50Figure 3-28 Net Sand Isochore - Strawn Formation, Archer/Young Counties …………………….. 52Figure 3-29 Offset Strawn Producers, Archer/Young Counties …………………….. 53Figure 3-30 Garvey C-5 Log, Strawn Formation …………………….. 54

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

5

LIST OF FIGURES (Cont'd)

Figure 4-1 Red Creek PDP Production Profile …………………….. 60Figure 4-2 Ford East PDP Production Profile …………………….. 60Figure 4-3 Ford East PNP Production Profile …………………….. 61Figure 4-4 Ford East PUD Production Profile …………………….. 61Figure 4-5 Halletsville PDP Production Profile …………………….. 62Figure 4-6 Halletsville PNP Production Profile …………………….. 62Figure 4-7 Morgans Bluff PDP Production Profile …………………….. 63Figure 4-8 Morgans Bluff PUD Production Profile …………………….. 63Figure 4-9 Other PDP Production Profile …………………….. 64Figure 4-10 Raccoon Bend PDP Production Profile …………………….. 64Figure 4-11 Raccoon Bend PNP Production Profile …………………….. 65Figure 4-12 Raccoon Bend PUD Production Profile …………………….. 65Figure 4-13 Stephens-Shackleford PDP Production Profile …………………….. 66Figure 4-14 Stephens-Shackleford PNP Production Profile …………………….. 66Figure 4-15 Stephens-Shackleford PUD Production Profile …………………….. 67Figure 4-16 TNT PDP Production Profile (Excl. North Knox) …………………….. 67Figure 4-17 North Knox PDP Production Profile …………………….. 68Figure 4-18 North Knox PNP Production Profile …………………….. 68Figure 4-19 Parker, J E Waterflood PUD Production Profile …………………….. 69Figure 4-20 Ford East PDP Operating Expense Profile …………………….. 70Figure 4-21 Halletsville PDP Operating Expense Profile …………………….. 70Figure 4-22 Morgans Bluff PDP Operating Expense Profile …………………….. 71Figure 4-23 Other PDP Operating Expense Profile …………………….. 71Figure 4-24 Raccoon Bend PDP Operating Expense Profile …………………….. 72Figure 4-25 Stephens-Shackleford PDP Operating Expense Profile …………………….. 72Figure 4-26 TNT PDP Operating Expense Profile …………………….. 73Figure 4-27 Ford East PUD Net Capital Expense Profile …………………….. 74Figure 4-28 Morgans Bluff PUD Net Capital Expense Profile …………………….. 74Figure 4-29 Raccoon Bend PUD Net Capital Expense Profile …………………….. 75Figure 4-30 Stephens-Shackelford PUD Net Capital Expense Profile …………………….. 75Figure 4-31 Parker Waterflood PUD Net Capital Expense Profile …………………….. 76

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

6

LIST OF TABLES

Table 1-1 Amadeus Net Reserves and PV10% by Reserve Category ……………… 8Table 1-2 NYMEX Forward Pricing ……………… 10Table 2-1 Red Creek Reserve and PV10% Summary ……………… 15Table 2-2 Red Creek Case List ……………… 15Table 3-1 Ford East Reserve and PV10% Summary ……………… 17Table 3-2 Ford East Case List ……………… 18Table 3-3 Halletsville Reserve and PV10% Summary ……………… 21Table 3-4 Halletsville Case List ……………… 21Table 3-5 Morgans Bluff Reserve and PV10% Summary ……………… 24Table 3-6 Morgans Bluff Case List ……………… 24Table 3-7 Other Producing Properties Reserve and PV10% Summary ……………… 26Table 3-8 Other Producing Properties Case List ……………… 26Table 3-9 Raccoon Bend Reserve and PV10% Summary ……………… 28Table 3-10 Raccoon Bend Field Case List ……………… 30Table 3-11 Stephens-Shackleford Reserve and PV10% Summary ……………… 32Table 3-12 Stephens-Shackleford Case List ……………… 33Table 3-13 TNT Reserve and PV10% Summary ……………… 37Table 3-14 TNT Properties Case List (Excluding North Knox City Unit) ……………… 38Table 3-15 North Knox Reserve and PV10% Summary ……………… 39Table 3-16 North Knox City Unit Case List ……………… 40Table 3-17 Parker Waterflood Reserve and PV10% Summary ……………… 42Table 3-18 Parker Waterflood Unit Case List ……………… 42Table 3-19 Stephens-Shackleford Upside Reserve and PV 10% Summary ……………… 46Table 3-20 Amadeus Well Count and Acreage in Stephens County ……………… 51Table 3-21 Ford East Upside Reserve and PV10% Summary ……………… 51Table 3-22 TNT Upside Reserve and PV10% Summary ……………… 52

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

7

1. EXECUTIVE SUMMARY

1.1 Asset Overview LaRoche Petroleum Consultants, Ltd (“LPC”) has been commissioned to provide an Independent Technical Specialist’s Report on the Petroleum Properties of Amadeus Petroleum Inc. (“Amadeus”) for Independent Experts PriceWaterhouseCoopers Securities Ltd (PwCS). The properties consist of operated and non-operated gas and oil interests in Louisiana, Oklahoma, and Texas located in the United States of America. We have assessed the properties in accordance with the Society of Petroleum Engineers 2007 Petroleum Resource Management System and the Technical Assessment and Valuation of Mineral and Petroleum Assets and Securities for Independent Expert Reports (The Valmin Code). LPC has evaluated the proved reserves for Amadeus. No evaluation of probable reserves was performed for this report. The Amadeus properties are characterized as mature and conventional and such properties typically exhibit a limited number of opportunities to develop probable reserves. An exhaustive evaluation of probable reserves does not appear to be warranted for this property set.

Figure 1-1 Texas Project Location Map

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

8

Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net cash flow is after deducting estimated production and ad valorem taxes, operating expenses, and future capital expenditures but before consideration of United States federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and are a technical value which should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the Amadeus interest, as of September 30, 2012, to be:

Net Reserves Future Net Cash Flow ($) Oil Gas Present Category (Barrels) (Mcf) Total Worth at 10% Proved Developed Producing 2,463,302 4,139,711 $172,456,578 $ 78,638,438 Non-Producing 167,855 645,134 $ 14,443,662 $ 7,547,264 Proved Undeveloped 657,943 915,511 $ 39,320,043 $ 12,839,882

Total Proved 3,289,100 5,700,356 $226,220,283 $ 99,025,584

The oil reserves include crude oil and condensate. Oil reserves are expressed in barrels, which are equivalent to 42 United State gallons. Gas reserves are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure basis.

Table 1-1 Amadeus Net Reserves and PV10% by Reserve Category

Figure 1-2 Net Total Proved PV10% by Reserve Category

N

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

9

Figure 1-3 Net Total Proved PV10% by Project Area

Amadeus operated properties in this report are operated by the Amadeus subsidiary, T-N-T Engineering Inc. (TNT).

1.2 Evaluation Methodology Estimates of reserves for this report were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties for which more complete data were available. We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting rather than engineering or geoscience.

The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues there from and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.

Technical information necessary for the preparation of the reserve estimates herein was furnished by Amadeus or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

10

data presented by Amadeus including the extent and character of the interest evaluated. Where applicable, production history for the properties evaluated was available through either June 2012 or July 2012.

The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Prices may vary significantly from those used herein. In addition, future changes in environmental and administrative regulations may significantly affect the ability of Amadeus to produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.

LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the Amadeus interest. Our projections are based on the Amadeus interest receiving its net revenue interest share of estimated future gross oil and gas production.

LPC has previously evaluated all or a portion of the reserves herein on behalf of Amadeus on several occasions beginning in 2006. For purposes of this evaluation the economic program ARIESTM was employed. This report conforms to our understanding of the Valmin Code as it applies to this evaluation.

1.3 Prices and Costs As requested, oil and gas prices used in this report correspond to the average price per year of futures contracts traded on the NYMEX at the close of trading on September 28, 2012. Oil prices are referenced to a per-barrel NYMEX West Texas Intermediate futures contract price adjusted for gravity, transportation fees, and regional price differentials. Gas prices are referenced to a per-MMBtu NYMEX Henry Hub futures contract price adjusted for energy content, transportation fees, and regional price differentials. Prices, before adjustments, have been scheduled in the future as follows:

Oil Price Gas Price Year ($/Barrel) ($/MMBtu) 2012 92.38 3.468 2013 93.71 3.844 2014 91.78 4.180 2015 2016

89.35 87.74

4.370 4.546

Thereafter 86.87 4.737

Table 1-2 NYMEX Forward Pricing

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

11

Figure 1-4 NYMEX Oil – WTI Price vs Time

Figure 1-5 NYMEX Gas – Henry Hub Price vs Time

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

12

Figure 1-6 Product Price Differentials

Due to the Amadeus accounting and data tracking procedures, data are not available to separately identify natural gas liquids (NGL) volumes and revenue. Accordingly, LPC has not separately evaluated reserves or value associated with NGL. Instead revenue that is derived from the production and sales of NGL is included herein in the form of adjustments to the gas price. This method accurately models the current NGL and gas revenue from the properties. Information necessary to derive such adjustments was based on data obtained from Amadeus. LPC has applied a BTU factor of 1 MMBtu per Mcf to all gas volumes included in this report. Accordingly, any price bonus received for the sale of gas with a BTU factor greater than 1.0 is reflected in the gas price differentials employed herein.

Lease and well operating expenses are based on data obtained from Amadeus. LPC has reviewed and analyzed these expenses; accordingly, any references to those expenses herein represent work done by LPC. Our analysis of lease operating expenses (LOE) was based on detailed, well-by-well data furnished by Amadeus for the period of April 2011 through March 2012. These data list actual expenses incurred for each month; we averaged these expenses for the period after subtracting taxes to derive a figure to utilize on a go-forward basis for PDP wells or leases. This average also served as a guideline for proposed PNP and PUD wells in a given area. Appendix 4.4 is a project-by-project operating cost profile resulting from application of this methodology. Expenses for both Amadeus-operated and outside-operated properties include the per-well overhead costs allowed under joint operating agreements along with direct lease and field level costs. Headquarters general and administrative overhead expenses of Amadeus are not included. Operating expenses are held constant throughout the life of the properties.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

13

Capital costs and timing of all investments have been provided by Amadeus and are included as required for workovers, new development wells, and production equipment. We have reviewed these capital costs and consider them to be a reasonable representation in the context of the location and depth of the targeted formations. LPC has also reviewed and analyzed Amadeus’s estimates of the cost to plug and abandon the wells net of salvage value, and we have included and scheduled those costs at the end of the economic life of individual properties. These costs are held constant until the date of expenditure.

1.4 Qualifications

LaRoche Petroleum Consultants, Ltd. has conducted technical studies and economic evaluations for private and public oil and gas companies, government agencies, and financial institutions throughout the world for over 30 years. We are petroleum engineers, geologists, geophysicists, and technical support staff with a history of customer service and excellence. The average experience level of our staff exceeds 35 years with major and independent oil company backgrounds.

LPC has extensive experience in merger and acquisition evaluations, field studies, and reserve reports, both domestically and internationally. We are experienced in evaluation of non-conventional reservoirs, particularly shales and coalbed methane. Our technical staff has significant reserve analysis experience in all the U.S. producing basins.

The following individuals are primarily responsible for the preparation of this report :

William M. Kazmann, President and Senior Partner, received his Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin in 1973 and 1975, respectively. Mr. Kazmann is a Licensed Professional Engineer in the State of Texas and is a member of the American Association of Petroleum Geologists, Society of Petroleum Engineers, Society of Independent Professional Earth Scientists. He prepared engineering and economic evaluations for this report.

Al C. Iakovakis, Manager of Unconventional Resource Evaluations, is a graduate of the University of Houston with a B.S. degree in Chemical Engineering. He prepared engineering and economic evaluations for this report.

Charles Thomas Daugherty, Senior Staff Geologist, is a graduate of the University of Northern Iowa and holds a B.A. degree in Geology. He prepared geological analyses for this report

Thomas A. Schob, Engineering Associate, graduated from the University of Missouri at Rolla in 1971 with a B.S. degree in Petroleum Engineering and from the University of New Orleans in 1980 with an M.B.A. degree. He is a Licensed Professional Engineer in Texas and a member of the Society of Petroleum Engineers. He prepared engineering and economic evaluations for this report.

1.5 Condition of Properties The properties are comprised of multiple leases and over 300 individual wells located in three states. Since these are mature producing properties and have proved to be mechanically sound for a substantial period of time, an on-site inspection of the properties was not judged to be warranted. Therefore, the mechanical operation or condition of the wells and their related facilities have not been examined by LPC. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows. In addition, all PDP cases with no reserves assigned to them by LPC have been summarized into a single case with only the plugging liability appearing as part of its cash flow.

The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

14

1.6 Independence LPC makes the following disclosures :

We are independent petroleum engineers, geologists, and geophysicists with respect to Amadeus and are not employed on a contingent basis.

Under the terms of engagement between LPC and the independent expert PwCS, LPC will receive a fee for the provision of this report, based on time expended at our current standard terms and conditions. The payment of this fee is not contingent on the outcome of the proposed transaction.

We do not own an interest in Amadeus or the properties listed herein.

1.7 Consent LPC has consented in writing to this Report in the form and context in which it appears being included in the Notice of Annual General Meeting which will accompany the notice of meeting to be issued by the directors of Amadeus and which will be distributed to Amadeus shareholders. LPC has not authorized or caused the issue of all or any part of the notice of meeting or the Notice of Annual General Meeting other than this report. Neither the whole nor any part of this report nor any reference to it may be included in or with or attached to any other document, circular, resolution, letter, or statement without the prior consent of LPC to the form in which it appears.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

15

2. OKLAHOMA PROPERTIES

2.1 RED CREEK PROJECT Jefferson County Hoxbar Formation 2400’-3600’

Table 2-1 Red Creek Reserve and PV10% Summary

In June 2001, Amadeus acquired a working interest in an oil exploration project named Red Creek situated 20 miles north of the Texas/Oklahoma border. An extensive 3-D seismic survey was shot and interpreted in late 2001. Drilling commenced in June 2002 and, since that time, Amadeus has drilled a total of 17 wells. This Project now consists of four PDP cases as listed below. LPC did not investigate any reserve potential beyond the PDP category in this area.

Table 2-2 Red Creek Case List

These are mature oil-producing properties with a distinctive profile that is typical of the Hoxbar formation. Evaluation of these properties was therefore based on performance analysis. The typical profile for the oil is a mild hyperbolic curve with an example shown on the next page.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

16

Figure 2-1 Barrett, Rash 24 - Production Performance Curve

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

17

3. TEXAS PROPERTIES

3.1 FORD EAST FIELD PROJECT Reeves County Bell Canyon Formation Ramsey Sand 3500’

Table 3-1 Ford East Reserve and PV10% Summary

Figure 3-1 Ford East Field Location Map

In July 2005, Amadeus purchased the Ford East prospect which is an oil and gas field situated in Reeves County in West Texas. The field was discovered in 1960 and covers 1,172 acres. Amadeus began an extensive drilling program in 2007 which is scheduled to continue through 2012 and beyond. This Project now consists of six PDP cases, three PNP cases and eight PUD cases.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

18

Table 3-2 Ford East Case List

The six Red Bluff leases consist of a total of 32 producing wells. These leases have been gradually down-spaced, with the TXL 9 lease being fully developed to 20-acre spacing while the other leases present the opportunity for additional drilling. Though the existing PDP cases have sufficient production history to apply a production performance analysis, the LPC methodology used to derive an average per-well recovery was expanded to include offset wells. The PDP cases in this field generally exhibit a hyperbolic character with sharp initial declines, a hyperbolic factor of 2.5 and a terminal decline of seven percent (7%). The terminal decline was derived from the production profile of the mature Red Bluff 1 lease. We have determined the average per-well EUR of these six leases to be 41 Mbo and 66 MMcf. We then conducted an in-depth analysis of the performance of wells in the adjoining East Ford Unit and obtained comparable results though the EUR of wells in the Amadeus leases was observed to be generally higher. Our analysis is supported further by the recent conversion of PUD wells to PDP in the TXL 9 lease where oil production increased from 41 Bopd in August 2010 to 134 Bopd in February 2011. The Ramsey Sand Isochore Map below shows the area of recent activity.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

19

Figure 3-2 Ramsey Sand Isochore Map

The proposed PUD wells are largely confined to the less-developed Sections 10 and 16 and are one offset location away from existing producing wells. The performance of existing wells indicates that down-spacing has not had significant impact on reserves, and the continuity of the formation across all sections adds credence to the potential of this area. We have assigned 41 Mbo and 66 MMcf to each of the proposed locations and relied on typical curves of PDP wells for the production profile of these reserves.

.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

20

Capital Expenses for PUD Locations

Estimates for drilling and completion of PUD wells were furnished by Amadeus. The gross total D&C cost is $544,950 per well.

Figure 3-3 Ford East Field Proved Location Map

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

21

3.2 HALLETSVILLE PROJECT Lavaca County Wilcox Formation 7000’-11000’

Table 3-3 Halletsville Reserve and PV10% Summary

Figure 3-4 Halletsville Project Location Map

In November 2003, Amadeus acquired working interests in the Halletsville exploration project which targeted gas prospects in Lavaca County, approximately 100 miles west of Houston. From April 2004 to the present, Amadeus has drilled 30 wells in this area and utilized 3-D seismic data to identify prospects of interest. This project targeted normally pressured sands of the Upper and Middle Wilcox Sands and geo-pressured Middle Wilcox and Lower Wilcox Sands. This project now consists of 13 PDP cases and 6 PNP cases as listed below:

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

22

Table 3-4 Halletsville Case List

LPC has reviewed the performance of wells in this field over a number of years and has relied upon the following methods to assign reserves to them regardless of reserve classification:

- Volumetric analysis of either the well or, when applicable, the fault block. - Well production performance. - Application of the F.A.S.T. RTA model (Fekete Analysis) which allows use of production and flowing

pressure data to determine gas-in-place and expected ultimate recovery.

With one or two exceptions, these wells produce from the Lower Wilcox which is characterized by a water-drive mechanism. Consequently, the gas recovery can be lower than that of other producing mechanisms and results in a rapid decline of the gas when the water front hits the wellbore. This decline is either exponential in nature or might assume a mild hyperbolic character. A sample curve (for the New Henderson 1 PDP well) is shown below as typical of the behavior of the producing wells.

Figure 3-5 New Henderson 1 - Production Performance Curve

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

23

LPC assigned PNP reserves to several behind-pipe zones in existing wells which have been identified from log analysis, volumetric analysis, and the application of constraints in the areal extent and gas recovery factor which are commensurate with the observed behavior of existing producers.

Capital for PNP Zones

Estimates for recompletion costs of behind-pipe zones were furnished by Amadeus. The gross total capital is $50,000 per well and is incurred on the month of first production.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

24

3.3 MORGANS BLUFF FIELD PROJECT Orange County Hackberry Formation 8600’

Table 3-5 Morgans Bluff Reserve and PV10% Summary

This project consists of 1 PDP case and 1 PUD case as shown below:

Table 3-6 Morgans Bluff Case List

Figure 3-6 Morgans Bluff Hackberry Unit Location Map

This is an oil producing property which has been unitized and under waterflood since 1990. LPC has conducted an in-depth geological and volumetric analysis of the field which is producing from multiple Hackberry stringers which have excellent porosity (close to 30%) and permeability. The projection for the PDP case is based on

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

25

performance analysis due to the maturity of the field and the established profile. The operator has gradually switched from gas-lift to installation of electric submersible pumps which has helped stabilize the production rates. We estimate that the combined primary-plus-secondary recovery in this field ranges from 35% to 37% of the original oil in place.

Figure 3-7 Morgans Bluff Hackberry Unit Production Performance Curve

The proposed PUD location is on the northern edge of the field and updip of the existing 12L producing well. We have assumed a simple closure whereby the fault, if present, is not a sealing fault and thereby calculated 210 acre-ft attributable to this location. Using parameters similar to the field evaluation, we calculate an original-oil-in- place of 166 Mbo, and at the above primary-plus-secondary recovery factor, this translates to reserves of 62 Mbo plus 89 MMcf. Other than normal geological risk, attainment of these reserves may depend on implementation and maintenance of a water-injection program.

Capital for PUD Location

Estimates for drilling and completion of this location were furnished by Amadeus. The gross total D&C capital is $1,400,000 and is incurred two months prior to first production.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

26

3.4 OTHER PRODUCING PROPERTIES PROJECT Baylor, Knox and Nolan Counties Tannehill, Pennsylvanian and Ellenburger Formations

Table 3-7 Other Producing Properties Reserve and PV10% Summary

This Project consists of ten PDP cases as listed below. LPC did not investigate any reserve potential beyond the PDP category in this area.

Table 3-8 Other Producing Properties Case List

These are mature oil properties producing primarily from the Tannehill Formation. LPC has assigned reserves to these cases based on performance analysis since all the properties have distinctive profiles. An example of a production performance curve for the highest-valued property (Higgins Pool Unit) is shown on the next page for reference.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

27

Figure 3-8 Higgins Pool Unit - Production Performance Curve

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

28

3.5 RACCOON BEND FIELD PROJECT Austin and Waller Counties Cockfield, Gutowsky, and Miocene Formations 1700’ – 4500’

Table 3-9 Raccoon Bend Reserve and PV10% Summary

Figure 3-9 Raccoon Bend Field Location Map

The Raccoon Bend Field was acquired by Amadeus in December 2003. Drilling in this area began in 2004 and continued throughout the next three years. As part of a strategic asset review in October 2007, Amadeus sold 75% of its interest. Following the sell down, Enhanced Energy Partners Corporation took over as operator and commenced a four-well drilling program in January 2008. The Raccoon Bend Field is characterized by multiple producing horizons as shown below in a sample log section.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

29

Figure 3-10 Raccoon Bend Field Sample Log Section

This project now consists of 39 PDP cases, 11 PNP cases, and 3 PUD cases as listed on the following page:

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

30

Table 3-10 Raccoon Bend Field Case List

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

31

The Raccoon Bend Field was discovered in 1929 and has produced over 100 MMbo. Even though there has been production from Miocene and Oligocene Formations, the majority of the production to date has been from Eocene Formations such as the Gutowsky, Grawunder, and Cockfield. LPC used production performance analysis for the review of older, mature PDP wells. There are also modern wells which have been drilled as a result of 3-D seismic work in an effort to better tap into the potential of multiple zones in the area. In the case of both PDP wells with a very short production history and the PNP wells shown above, LPC reserves were largely based on geological studies, volumetric analysis, and if necessary, analogy to the performance of offset wells producing from similar horizons.

Estimates for recompletion of behind-pipe zones were furnished by Amadeus. The gross total capital ranges from $40,000 to $75,000 per well and is incurred on the month of first production.

Diemer, Mrs Alberta 23 Updip PUD Location Grawunder Formation

This proposal was evaluated by LPC during prior reviews. This is an updip location in the fault block and quantification of reserves was based on volumetric analysis. We have assigned this location 69 Mbo and 28 MMcf. If successful, this would be the first Grawunder production in the fault block. The location exhibits higher risk since the downdip well that establishes this fault block as productive tested oil from this formation at a high water-cut and was not commercial.

Estimates for drilling and completion of this location were furnished by Amadeus. The gross total D&C capital is $540,000 and is incurred on the month of first production.

Hardy No. 33 S/T (DY-2) PUD Location D-Y 2 Formation

This proposal was evaluated by LPC during prior reviews. The proposal involves drilling a side-track well to the existing Hardy 33 location. The DY-2 zone produced 570 Mbo before watering out. Assignment of LPC reserves was based on volumetrics. In the absence of a porosity log, we have used an analogy to the DY-3 zone which is 100’ below the base of the DY-2 zone and assigned this well reserves of 9 Mbo.

Estimates for drilling and completion of this location were furnished by Amadeus. The gross total D&C capital is $450,000 and is incurred on the month of first production.

Hardy No. 33 S/T (Paine) PUD BP Location Paine Formation

This proposal was evaluated by LPC during prior reviews. It involves completion of the behind-pipe Paine zone in the new PUD well. Assignment of LPC reserves was based on volumetric analysis. This well has been assigned 14 Mbo of reserves.

Estimates for recompletion of this zone were furnished by Amadeus. The gross total capital cost is $50,000 and is incurred on the month of first production.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

32

3.6 STEPHENS-SHACKLEFORD COUNTIES PROJECT

PDPStephens and Shackleford Counties Strawn (1500’ – 3100’), Caddo Limestone (3300’), Conglomerate, Marble Falls Limestone (3700’), Lake Sand (3500’), Duffer Limestone (3900’), Mississippi, Ellenburger

Table 3-11 Stephens-Shackleford Reserve and PV10% Summary

Figure 3-11 Stephens County Lease Location Map

In July 2005, Amadeus acquired a working interest in several leases located in Stephens and Shackleford Counties. The company owns 3,700 gross acres in this area. 3-D and 2-D seismic is available on six of these leases. This project now consists of 34 PDP cases, 4 PNP cases, and 1 PUD case as listed below.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

33

Table 3-12 Stephens-Shackleford Case List

The wells in this area are classic North Texas shallow, long-lived, and low-decline oil and gas producers. Accordingly, our reserve assignments for PDP wells were based on performance analysis driven by established production profiles. An example of one of the highest-valued, mature PDP wells is shown on the next page.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

34

Figure 3-12 Duke-Keathly Lease - Production Performance Curve

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

35

PNP

LPC assigned PNP reserves to several behind-pipe zones in existing wells which have been identified from log analysis, volumetric analysis and the application of constraints in the areal extent and recovery factor which are commensurate with the observed behavior of existing producers.

Figure 3-13 Fambro/Randall/Thomas Lease Location Map

Thomas R O A 5 PNP (BP) Location Caddo Limestone

These are behind-pipe reserves for the newly drilled Duffer producing well. We have reviewed the logs and assigned no reserves to the upper lobe of the Caddo Formation which appears to be a thin, fractured chert. We have however quantified the thicker, lower lobe where the volumetrics indicate much higher reserves. The electric log strongly suggests depletion, and this observation is consistent with the performance of two strong offset wells. We have expanded the area of volumetric analysis to include the offset wells and assigned this well 24.4 Mbo after taking into consideration interference from the nearest offset.

PUD

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

36

To evaluate the one remaining PUD location for this Project, LPC relied on electric logs, volumetric analysis, and the targeted formation indicated by Amadeus to assign reserves.

Figure 3-14 Hittson #2 Lease Location Map

An estimate for drilling and completion of this well was furnished by Amadeus. The gross D&C cost is $614,104 and is incurred on the month of first production.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

37

3.7 TNT PRODUCING PROPERTIES PROJECT Archer, Cottle, Ector, Knox, Throckmorton, and Young counties Miscellaneous Formations

Table 3-13 TNT Reserve and PV10% Summary

Figure 3-15 TNT Properties Location Map

In 1996 Amadeus acquired majority interests in oil leases in Archer and Young Counties. Since that time, Amadeus expanded this base by acquiring interest in oil and gas leases in several other counties outlined above. This project now consists of 22 PDP cases as listed on the next page. Both the North Knox area and Parker area are also operated by TNT, but they are discussed separately.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

38

Table 3-14 TNT Properties Case List (Excluding North Knox City Unit)

Review of all the PDP cases was based on performance analysis. All these PDP properties are mature oil-producing leases with defined production profiles which were relied upon for our reserve assignment. An example of one of the highest-valued, mature PDP wells is shown below. This specific well is showing a response to water injection as evidenced by the increase in oil production rates.

Figure 3-16 Marshall A - Production Performance Curve

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

39

3.8 NORTH KNOX CITY UNIT Knox County Canyon Formation

Table 3-15 North Knox Reserve and PV10% Summary

This project is a TNT operated property but merits separate discussion. A map of this unit is shown below.

Figure 3-17 North Knox City Unit Location Map

Amadeus began purchase of working interests in this field in 1997. The Company expanded its presence via additional acquisitions in 2002 and purchased deep and shallow rights in 2003. This field consists of 9 producing wells, 4 injection wells and various shut-in wells. The field began production in 1950, water injection began in 1983, and cumulative recovery to date is just over 16 MMbo. The original producing well count was 52, but this

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

40

has gradually diminished as several wells have been shut-in. The biggest change in production profile occurred in 1991 when cumulative recovery had reached 15 MMbo and the composite WOR was 60. In 1991, the operator began shutting in high-WOR wells which resulted in a gradual reduction in WOR to the current level of 10; at the same time, the field has had a flat oil production profile as shown below. We have assumed a 3% exponential decline which results in gross remaining reserves of 765 Mbo.

Table 3-16 North Knox City Unit Case List

Figure 3-18 North Knox City Unit - Production Performance Curve

We have investigated alternative methods to predict remaining reserves and used the WOR-versus-cumulative oil production method. Under the assumption that WOR will increase at a rate which mirrors earlier trends, the predicted remaining recovery is 750 Mbo.

P

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

41

Figure 3-19 North Knox City Unit - Water-Oil Ratio vs Cumulative Oil

NORTH KNOX CITY UNIT PNP CASES Canyon Formation

We have investigated the feasibility of returning seven shut-in wells to production and installing either electrical submersible pumps or pumping units. Our analysis was based on analogy to eleven wells in this field which have recently been similarly re-activated (Wells # 7,14,18,19, 28, 35, 40, 45, 46, 49 and 53). These wells commonly return to production at the last oil production rate prior to abandonment and usually tend to decline at roughly a 10% exponential decline though this may vary depending on location as well as water production levels and/or supporting injection. We, therefore, reviewed the proposed candidates’ oil production rates prior to abandonment and forecast oil production which declines at exponential rates ranging from 10% to 20%, thereby resulting in variable remaining reserves. We did not investigate benefits that may be derived via polymer treatments to shut off excess water or any other mechanism of adding injection. LPC assigned reserves to five of these proposals and rejected two as it appears that these two wells have already been returned to production.

Estimates for reactivations were furnished by Amadeus. The gross total capital ranges from $20,000 per well for the cases where a pumping unit is installed to $60,000 per well for the cases where an electric submersible pump is installed. This capital cost is incurred on the month of first production.

.

.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

42

3.9 PARKER, J. E. WATERFLOOD Ector County San Andres Formation 4100’ – 4425’

Table 3-17 Parker Waterflood Reserve and PV10% Summary

Table 3-18 Parker, J.E. Secondary Waterflood Case List

This project is a TNT-operated property but merits separate discussion. A map of this unit is shown on the next page.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

43

Figure 3-20 Parker Ranch Waterflood – Harper (San Andres) Field

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

44

Figure 3-21 Parker Ranch – Isochore Map of San Andres P1 Zone

Figure 3-22 Parker Ranch – Isochore Map of San Andres P2 Zone

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

45

PUD assignment for this lease was based on analysis of the following:

- A review of a waterflood study of this lease provided by Amadeus. - The performance of offset waterfloods implemented in the same formation in the East Harper Unit, the

Paul Moss lease, and the Paul Moss “C” lease. - Volumetric analysis to determine magnitude of unswept areas on this lease.

Our analysis showed that these three waterfloods exhibit a secondary-to-primary ratio which ranges from 0.38 to 0.46 and have an average value of 0.41. Note that the San Andres has two main intervals designated “P1” and “P2.” We have conducted an in-depth analysis of both the P1 zone which is penetrated in all wells on the J.E. Parker lease and the P2 zone which is thinner, less continuous, and only penetrated by approximately half of the wells on the lease. We then determined that the target volume is 1,198 Mbo and that at the above secondary-to-primary ratio, a reasonable estimate of remaining secondary reserves is 492 Mbo. The operator is planning an inverted nine-spot waterflood whereby an additional four producing wells will be drilled to effectively drain the zone of interest. Our production profile assumes a gradual increase in oil production to a peak rate of 1,500 Bopm which is sustained for a number of years before it declines hyperbolically to an economic limit. Derivation of this profile is based on analogy to the previous response of the three floods to water injection. The success of this project depends on the effective sweep of the oil by water injection.

Capital for the PUD case

Estimates for capital requirements were furnished by Amadeus. These requirements include:

- A cost of $402,100 to drill a water supply well. - A cost of $363,700 to drill and complete a producing well. A total of four new producing wells are being

planned. - A cost of $40,000 per well to deepen nine existing producing wells to the P2 zone. - A cost of $641,200 to workover existing producing wells. - A cost of $78,200 to workover existing injection wells. - A cost of $85,000 to install an injection pump capable of handling 5,000 barrels of water per day. - A cost of $154,000 for injection lines. - A contingency cost of $150,000. -

The gross total investment for this project $3,326,000. The investments are scheduled to occur over an eleven-month period.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

46

3.10 UPSIDE POTENTIAL The Amadeus asset portfolio presents a range of opportunities within certain project areas. The focus of our analysis is on those assets, identified by Amadeus, which have potential reserves or resources that entail higher risk or uncertainty than those reserves quantified within the 2P reserves category. Those assets are in the Stephens-Shackleford Project, The Ford East Project and the TNT Project. Each of those projects is listed separately below.

STEPHENS-SHACKLEFORD PROJECT

Table 3-19 Stephens-Shackleford Prospective Resources and PV10% Summary

There are several projects in this area primarily involving the development of the Caddo Limestone Formation.

HITTSON 1 WELL

The 320-acre Hittson lease contains only one producing well, the Hittson # 1 which is currently producing from the Conglomerate at 3862’. This project entails development of the Caddo behind-pipe zone at 3315’-3434’. The map below shows the location of the well. Assignment of volumes was based on volumetric analysis which was derived from review of the log shown in Figure 3-24.

Figure 3-23 Hittson & Moon Ranch Location Map

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

47

Figure 3-24 Hittson Log Section

Our volumetric analysis was based in part on the use of logs from the R. O. Thomas A 5 well to define the geological characteristics of the formation. Accordingly, risk should be attached to the exactness of these characteristics, the drainage area of the well and the lack of development of the formation within reasonable distance from this well. Based on our volumetric analysis, we have assigned volumes of 38 Mbo and 56 MMcf to this proposal. We are encouraged by the extensive development of the Caddo Limestone throughout Stephens County where our research indicates that the average cumulative-to-date recovery from 158 wells is 32 Mbo and 48 MMcf. Several of these wells have remaining reserves yet to be recovered. We have classed these volumes as Prospective Resources. We have scheduled this completion for 2013 at a gross estimated cost of $100,000.

MOON RANCH 2 WELL

The 160-acre Moon lease contains two producing wells, the Hittson # 1 and Hittson # 2. The # 2 well was originally completed in the Ellenberger Formation (4321’) and was subsequently plugged back to the Strawn Formation (2977’-2982’) from which it is currently producing. This project entails development of the Caddo behind-pipe zone. The map above shows the location of the well. Assignment of volumes was based on volumetric analysis which was derived from review of the log shown in Figure 3-25.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

48

Figure 3-25 Moon Ranch 2 Log Section

As with the Hittson well above, for geological characteristics volumetric analysis were based in part on the use of logs from the R.O. Thomas A 5 well. Accordingly, risk should be attached to the exactness of these characteristics and the drainage area of the well. Based on our volumetric analysis, we have assigned volumes of 38 Mbo and 56 MMcf to this proposal. We have classified these volumes as Prospective Resources. We have scheduled this completion for 2013 at a gross estimated cost of $100,000.

SIKES-RANDALL 1 WELL

The location of this well is shown in Figure 3-13. This well is currently producing from the Duffer Limestone (3790’-3800’). This project entails development of the Caddo behind-pipe zone. Assignment of volumes was based on volumetric analysis which was derived from review of the log shown in Figure 3-26 on the following page.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

49

Figure 3-26 Sikes-Randall Log Section

As with the Hittson well above, for geological characteristics volumetric analysis were based in part on the use of logs from the R. O. Thomas A 5. Accordingly, risk should be attached to the exactness of these characteristics and the drainage area of the well. Based on our volumetric analysis, we have assigned volumes of 38 Mbo and 56 MMcf to this proposal. We have classified these volumes as Prospective Resources. We have scheduled this completion for 2013 at a gross estimated cost of $100,000.

R.O. THOMAS A-4 WELL

The location of this well is shown in Figure 3-13. The well is situated next to the Thomas A 5 PUD well and is producing from the Conglomerate Formation (3910’-3920’). This project entails development of the Lake Sand behind-pipe zone (3560’-3572’). We have neither logs to adequately define the geological characteristics of this formation or an isochore map to define its presence or extent. Our research indicates 42 wells in Stephens County that have produced from this zone. We are encouraged by the presence of two of the best Lake Sand producers in the area at a distance of three-quarters of a mile to a mile-and-a-half to the east and southeast of this location respectively. Those wells have produced 1.2 and 1.3 Bcf from this zone. We have assigned volumes of 1 Bcf to this well but classify this opportunity as a high-risk proposal due to the uncertainty of productivity and potential volumes for this operation. We have classified these volumes as Prospective Resources. We have scheduled this completion for 2013 at a gross estimated cost of $100,000.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

50

Figure 3-27 R.O. Thomas Cross Section

STEPHENS COUNTY INFILL PROGRAM

This project entails the down-spacing of all existing wells within Amadeus’s acreage from its current configuration to 40 acres. As shown on Table 3-20 below, there are 43 wells within an area covering 3,689 acres for an average “drainage” of 86 acres per well. To down-space this acreage to roughly 40 acres would require the drilling of approximately 49 additional wells.

We have reviewed this proposal on a broad level and high-graded it to a total of sixteen locations. The project appears to cover multiple formations, extend over a large area, and does not have a detailed geologic characterization. Additionally, the area truly drained by each well is not a straight-forward relationship between well-count and available acreage but, rather, the geological characteristics and recovery mechanism. Furthermore, down-spacing to 40 acres does not appear to be prevalent across this acreage or to cover all or any producing horizons. We have reviewed the historical development of the major formations (Conglomerate, Caddo and Duffer) across the entire county and found 683 wells whose cumulative recovery to date is 11 Mbo and 160 MMcf.

We judge this proposal to have high risk and have assigned each of the sixteen proposed locations 11 Mbo and 160 MMcf. We classed these volumes as Prospective Resources. We have scheduled two wells to be drilled per year over the next eight years. The estimated Gross Capital is $400,000 per well.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

51

Table 3-20 Amadeus Well Count and Acreage in Stephens County

FORD EAST PROJECT

Table 3-21 Ford East Possible Reserves and PV10% Summary

The scope of this upside development project consists of the following: - Drilling four additional 20-acre spacing locations in the NE/4 of Section 9. - Drilling ten additional 20-acre spacing locations in Section 10.

With reference to Figures 3-2 and 3-3, we have determined that the historical development of Section 9 is such that the geological risk here is relatively minor. Therefore, the risk of additional drilling is confined to the impact of existing 40-acre wells on more densely spaced (i.e., 20-acre) locations. We have classified the volumes in Section 9 as possible reserves (see definitions). Accordingly, we have assigned to each of the four locations gross reserves of 41 Mbo and 66 MMcf.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

52

We have furthermore determined that drilling 20-acre locations in Section 10 entails a higher geological risk due to the sparse production. Down-spacing this section is contingent on both the presence of the sand and the success of the proposed PUD locations. We have classified these reserves as Possible and assigned each of the proposed locations 41 Mbo and 66 MMcf. The commercial data used for each of these proposals (ownership, capex, opex, P&A costs) are identical to those used for our PUD well evaluation in this area. We have scheduled five of these wells to be drilled in 2013, four wells each year for the next two years and finally one well in 2016. The estimated gross capital required is $454,000 per well.

TNT PROJECT

Table 3-22 TNT Prospective Resources and PV10% Summary

The scope of this project consists of the development of the Strawn Formation (3400’) in Archer and Young Counties. A total of ten wells would be drilled in the Garvey, Marshall, McGlothin, and Smith leases. Figure 3-28 below shows a net sand isochore of this formation which also identifies the location of the proposed wells. This figure shows the thickness to vary from 18’ to over 30’.

Figure 3-28 Net Sand Isochore – Strawn Formation in Archer/Young Counties

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

53

These two counties have a large number of wells that produced from this formation, and Figure 3-29 identifies some of these producing offsets (wells in yellow designate Strawn production)

Figure 3-29 Offset Strawn Producers in Archer/Young Counties

We have researched the public domain and found 331 wells in Archer County that produced from the Strawn Formation. Their average cumulative recovery to date is 37.4 Mbo per well. Additionally, we have been provided with an example log (from the Garvey C-5 well) which is shown on the following page.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

54

Figure 3-30 Garvey C-5 Log, Strawn Formation

Based on our volumetric analysis and assumption of 20-acre drainage, the EUR of a typical well with 20’ of net thickness is 36 Mbo per well. We believe that the lack of geological control suggests that the average thickness over the area of interest may be less than the 30’ which the Garvey C-5 well exhibits. We have used a water saturation of 51% and have found evidence that those wells that produce water have a water-cut (i.e. ratio of water production to water-plus-oil production) that ranges from 75% to 95% and is usually closer to the latter figure. Based on this volumetric analysis and the study of offset wells, we have therefore assigned each of these locations volumes of 36 Mbo and called them Prospective Resources. We have scheduled one of these wells to be drilled in 2013, four wells in 2014, three wells in 2015 and two wells in 2016. The estimated gross capital required is $400,000 per well.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

55

4. APPENDIX

4.1 List of Terms

Abbreviation Definition

AAPG American Association of Petroleum Geologists

API Amadeus Petroleum Inc.

ARIESTM Advanced Reserves Information and Evaluation System

BOPD Barrels of Oil Per Day

BTU British Thermal Units

CAPEX Capital Expense

ESP Electric submersible pump

EUR Estimated Ultimate Recovery

HBP Held By Production

HH Henry Hub Gas

LOE Lease Operating Expense

LPC LaRoche Petroleum Consultants, Ltd.

Mbo Thousand US Barrels of Oil

MMbo Million US Barrels of Oil

Mcf Thousand Standard Cubic Feet of Gas

MMcf Million Standard Cubic Feet of Gas

MMBtu Million British Thermal Units

MCFD Thousands of Cubic Feet of Gas Per Day

M$ Million US Dollars

NGL Natural Gas Liquids

OGIP Original Gas in Place

OOIP Original Oil in Place

OPEX Operating Expense

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

56

4.1 List of Terms (Cont’d)

Abbreviation Definition

PV10% Net Present Value (of a series of cash flows) Discounted at 10%

PwCS PriceWaterhouseCoopers Securities Ltd

SPE Society of Petroleum Engineers

SPE-PRMS Petroleum Resources Management System, approved by the Board of the SPE March 2007 and endorsed by the boards of the Society of Petroleum Engineers, American Association of Petroleum Geologists, World Petroleum Council and Society of Petroleum Evaluation Engineers.

SPEE Society of Petroleum Evaluation Engineers

TNT T-N-T Engineering, Inc.

WOR Water to Oil Ratio

WPC World Petroleum Council

WTI West Texas Intermediate Crude Oil

Q

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

57

4.2 Reserve Definitions

DEFINITION OF RESERVES

Condensed from SPE/WPC/AAPG/SPEE Petroleum Reserves Management System Document

Disseminated Jointly By: Society of Petroleum Engineers (SPE) (Approved April 11, 2007)

American Association of Petroleum Geologists (AAPG) World Petroleum Council (WPC)

Society of Petroleum Evaluation Engineers (SPEE)

RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

PROVED RESERVES

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves

Developed Reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

Developed Producing reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

58

Developed Non-Producing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Undeveloped Reserves are quantities expected to be recovered through future investments:

(1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

PROBABLE RESERVES

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved reserves but more certain to be recovered than Possible reserves. It is 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.

Probable reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.

Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

POSSIBLE RESERVES

Possible reserves are those additional reserves which analysis of geoscience and engineering data indicate 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), which is equivalent to the high estimate scenario. 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.

Possible reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project.

Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

59

RESOURCES

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 accumulations 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.

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

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

60

4.3 Production ProfilesThe graphs below represent our projection of the production profile for the combined total of all wells in each project and for each reserve category thereof. The graphs show gross oil and/or gross gas production rates i.e., to the 100% Working Interest.

Figure 4-1 Red Creek PDP Production Profile

Figure 4-2 Ford East PDP Production Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

61

Figure 4-3 Ford East PNP Production Profile

Figure 4-4 Ford East PUD Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

62

Figure 4-5 Halletsville PDP Production Profile

Figure 4-6 Halletsville PNP Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

63

Figure 4-7 Morgans Bluff PDP Production Profile

Figure 4-8 Morgans Bluff PUD Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

64

Figure 4-9 Other PDP Production Profile

Figure 4-10 Raccoon Bend PDP Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

65

Figure 4-11 Raccoon Bend PNP Production Profile

Figure 4-12 Raccoon Bend PUD Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

66

Figure 4-13 Stephens-Shackleford PDP Production Profile

Figure 4-14 Stephens-Shackleford PNP Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

67

Figure 4-15 Stephens-Shackleford PUD Production Profile

Figure 4-16 TNT PDP Production Profile (Excl. North Knox)

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

68

Figure 4-17 North Knox PDP Production Profile

Figure 4-18 North Knox PNP Production Profile

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

69

Figure 4-19 Parker, J E Waterflood PUD Production Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

70

4.4 Operating Expense ProfilesThe graphs below represent our projection of the operating expense profile for the combined total of all wells in each project and for each reserve category thereof. The graphs show average monthly gross operating expense inclusive of overhead to Amadeus’s Working Interest. This data includes the last twelve months of actual expenses and the short-term LPC forecast.

Figure 4-20 Ford East PDP Operating Expense Profile

Figure 4-21 Halletsville PDP Operating Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

71

Figure 4-22 Morgans Bluff PDP Operating Expense Profile

Figure 4-23 Other PDP Operating Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

72

Figure 4-24 Raccoon Bend PDP Operating Expense Profile

Figure 4-25 Stephens-Shackelford PDP Operating Expense Profile

R

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

73

Figure 4-26 TNT PDP Operating Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

74

4.5 Net Capital Expense Profiles

Figure 4-27 Ford East PUD Net Capital Expense Profile

Figure 4-28 Morgans Bluff PUD Net Capital Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

75

Figure 4-29 Raccoon Bend PUD Net Capital Expense Profile

Figure 4-30 Stephens-Shackleford PUD Net Capital Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

76

Figure 4-31 Parker Waterflood PUD Net Capital Expense Profile

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

110 of 110

APPENDIX I

STXRA TECHNICAL EXPERT’S REPORTTECHNICAL EXPERT’S REPORT

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

S

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

Well Number Drill and Complete Cost (Gross M$)

1H $9,107

2H $9,193

3H $8,593

11H $7,300

12H $7,736

13H $7,552

17H $7,755

18H $8,550

19H $7,621

Total $73,407

Item (Note: Negative Numbers are good and indicate 2012 wells cost less than the 2011 wells)

11H, 12H and 13H Combined Savings vs 2011 Wells (Gross M$)

17H, 18H and 19H Combined Savings vs 2011 Wells (Gross M$)

Central Delivery Point Lease Preparation Costs ($260) ($256)

Central Delivery Point Equipment Costs ($484) ($634)

Drilling Costs $194 $339

Completion Costs (Frac is Separate) $1,776 $1,305

Frac Costs ($5,286) ($4,170)

Rental Equipment Costs $383 $325

Water Transportation Costs ($107) ($75)

Overhead & Miscellaneous Costs ($689) ($807)

Casing & Tubulars Costs $157 $147

Wellhead Equipment Costs $13 ($16)

Fishing $0 $875*

Total ($4,304) ($2,967) *Note: If the unplanned planed fishing cost were not incurred, the 17H, 18H, and 19H overall savings versus the 2011 wells would be close to that of the 11H, 12H and 13H.

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

T

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

U

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

SCO

TT PRIN

TR

EG

O

1 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 21 2 1 2

For

per

sona

l use

onl

y

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

This page left blank intentionally

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

This page left blank intentionally

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y

V

This page left blank intentionally

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

SCO

TT P

RIN

TR

EG

O

1212 1212 1212 1212 1212 1212 1212 1212

For

per

sona

l use

onl

y