LGO Energy CPR Report by LGO Energy

LGO Energy Plc.

Competent personâ&#x20AC;&#x2122;s report Assessment of Goudron Field, Trinidad

Effective date: April 30, 2016

Deloitte LLP 700, 850 – 2nd Street SW Calgary, AB T2P 0R8 Canada Tel: 403-267-1700 Fax: 587-774-5398 www.deloitte.ca

July 13, 2016

LGO Energy Plc. Suite 3B, Princes House 38 Jermyn Street London, England SW1Y 6DN RE:

LGO Energy Plc. Competent person’s report

Deloitte LLP (Deloitte) has been engaged by LGO Energy Plc. (LGO) to prepare an independent evaluation of the oil and gas assets located in the Goudron Field of Trinidad of LGO Energy Plc., effective April 30, 2016 using Deloitte March 31, 2016 forecast pricing (the Report). Unless otherwise noted, all dollar values are American dollars. This Report has been prepared for the exclusive use of LGO and has been prepared following the guidelines set out by AIM. This Report should be referred to in its entirety for a full description of each asset, associated material liabilities, the data available to Deloitte, evaluation procedures, and our qualifications. No part of this Report shall be reproduced, distributed or made available to any other person, company, regulatory body or organization without the written consent of Deloitte. Deloitte confirms that we: 1. are professionally qualified and members in good standing of a self-regulating organization of engineers and geoscientists; 2. have at least five years’ relevant experience in the estimation, assessment and evaluation of oil and gas reserves; 3. are independent of the Company, its directors, senior management and advisers; 4. will receive a fee for the preparation of the Report in accordance with normal professional consulting practice. This fee is not contingent on the admission of the Company to AIM, or value of the Company and we will receive no other benefit; 5. are not a sole practitioner; 6. have the relevant and appropriate qualifications, experience and technical knowledge to appraise professionally and independently the oil and gas assets owned by the Company; 7. consider that the scope of the Report is appropriate and includes and discloses all information required to be included therein and was prepared in accordance with the Guidance Note for Mining, Oil & Gas Companies issued by London Stock Exchange plc in June 2009 (“Guidance Note”); and

LGO Energy Plc. Competent persons report Page 2

8. do not have, at the date of this letter, and have not had within the previous two years, any shareholding in or other relationship with the Company or the principal current assets in which the Company is interested and consequently considers itself to be independent of the Company. Further details are included in the Professional Qualifications section. The standard being used for the oil and gas reserves calculations and income projections, upon which this Report is based, is the Petroleum Reserves and Resources Definitions (PRMS) as prepared by the Society of Petroleum Engineers (SPE). The reserves definitions, price and market demand forecasts and general procedure used by Deloitte in its determination of this evaluation are included within the report. A site visit was not made by Deloitte during the completion of this Report. The extent and character of ownership and all factual data supplied by LGO were accepted as presented. This Report is complete up to and including April 30, 2016. Having taken all reasonable care to ensure that such is the case, we confirm that, to the best of our knowledge, the information contained in the Report is in accordance with the facts, contains no omission likely to affect its results, and no material change has occurred from April 30, 2016 to the date hereof that would require any amendment to the Report. Deloitte reserves the right to revise any opinions provided herein if any relevant data existing prior to preparation of this report was not made available or if any data provided is found to be erroneous. We accept responsibility for this letter and the Report for the purposes of a Competent Person's Report pursuant to the Guidance Note. This Report contains forward looking statements including expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e. operational risks in development, exploration and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; the uncertainty of estimates and projections relating to production, costs and expenses, political and environmental factors), and commodity price and exchange rate fluctuation. Present values for various discount rates documented in this report may not necessarily represent fair market value of the reserves. A Boe conversion ratio of six (6) Mcf: one (1) barrel has been used within this report. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. No value has been assigned in this evaluation for non-reserve lands. Yours truly, Original signed by: â&#x20AC;&#x153;Robin G. Bertramâ&#x20AC;? Robin Bertram, P. Eng. Partner Deloitte LLP /ct

Table of contents Page 1.0 2.0

3.0

4.0

Introduction Corporate summary 2.1 Net present value of the reserves 2.2 Reserves 2.3 Resources 2.4 Summary of oil and gas assets Property descriptions, geology, reserves and production forecast 3.1 Geology 3.2 Geophysics 3.3 Reserves and production forecast 3.4 Resources Economic parameters 4.1 License details 4.2 Operating and capital expenditures 4.3 Other economic parameters

Appendix 1: List of Tables Table 1: Table 2: Table 3: Table 4: Table 5: Table 6: Table 7: Table 8: Table 9:

P90 Cash flow profile P50 Cash flow profile P10 Cash flow profile P90 Notional overriding royalty P50 Notional overriding royalty P10 Notional overriding royalty P90 Development schedule P50 Development schedule P10 Development schedule

Appendix 2: List of Figures Property location map Goudron Block, Trinidad – Existing wells Goudron Block, Trinidad – Original oil-in-place areas Figure 1: Goudron Mayaro New well type well Figure 2: Goudron Mayaro Recompletion type well Figure 3: C-Sand New well Figure 4: Low Case production profile Figure 5: Mid-case production profile Figure 6: High case production profile

Appendix 3: Qualifications Appendix 4: Evaluation procedure

2 2 3 3 4 4 5 5 7 7 9 10 10 11 12

LGO Energy Plc.

Goudron Field, Trinidad

Effective date: April 30, 2016

Prepared by: J. D. Listoe, P. Eng. L. G. Mitchell, P. Eng. D. L. Horbachewski, P. Geol.

ÂŠ Deloitte LLP and affiliated entities. 1

1.0

Introduction

Pursuant to your request, Deloitte LLP (Deloitte) has prepared an evaluation of the crude oil reserves, including a forecast of future production and revenue, of the interests held by LGO Energy Plc. (LGO) in the Goudron Field, onshore Trinidad. The Goudron Field is located in southeast Trinidad and produces light oil. LGO acquired the field in 2012 and began drilling operations in 2014. The future net revenues and net present values presented in this report are effective as of April 30, 2016 and were estimated using forecast prices and costs and are presented in US dollars. All data used to prepare this report was provided by LGO. The reserves estimates and future net revenue forecasts have been prepared in accordance with the Petroleum Resource Management System (PRMS). The format and content of this report follows the guidance set out in the June 2009 Note for Mining and Oil & Gas Companies published by the London Stock Exchange. To prepare this report, Deloitte has reviewed information and interpretation supplied by LGO. Deloitte has accepted the results where they were deemed reasonable and made adjustments where necessary. LGO operates the Goudron Field on behalf of the Petroleum Company of Trinidad and Tobago Limited (Petrotrin) and has 100 percent working interest. The Incremental Production Service Contract (IPSC) for the Goudron Field was originally signed by Cameron Oil and Gas Company Limited and Petrotrin in November 2009. LGO acquired the rights and the IPSC was amended in 2013 effective August 1, 2013. The amendment states a contract term of 10 years with five year extensions permitted after that point. No truncation of production has been forecast to account for the IPSC not being extended as it is expected this will occur as required.

2.0

Corporate summary

Deloitte reviewed the production on a well by well basis within the Goudron Field as well as the analysis provided by LGO to prepare the forecasts.

Tables 1 through 4 provide a detailed summary of our

evaluation. It should be noted that LGO is not currently booking any reserves to the Goudron Field and the following are only representative of what would be attributable to LGO if they were in the position to book reserves.

ÂŠ Deloitte LLP and affiliated entities. 2

2.1

Net present value of the reserves

The net present value of the reserves is based on an analysis of future production forecasts, capital expenditures, operating expenses, production sharing contract terms, and product prices and is presented below:

Summary of oil and gas reserves and net present value Asset

Oil Mbbl

Net attributable reserves Gas NGL Boe MMscf Mbbl Mbbl Total proved 1,336 1,336 Proved + probable

Net present value (M$) 0%

10%

11,943 11,943

8,421 8,421

5,824 5,824

Goudron Total

1,336 1,336

Goudron

10,270

143,526

96,317

66,790

Total

10,270

143,526

96,317

66,790

Proved + probable + possible Goudron

22,351

378,870

243,998

163,281

Total

22,351

378,870

243,998

163,281

Note: "Net attributable" are those reserves attributable to the company after deduction of royalties and the State share of production (excluding the Notional Overriding Royalty, which is considered a fee and not a share of production in the IPSC). bbl – Barrels, scf - Standard Cubic Feet, 1 Boe = 6 Mscf

2.2

Reserves

A summary of the estimated reserves are presented in the following table:

Summary of oil and gas reserves by status Gross (all figures in Mbbls) Oil & liquids reserves Total oil & liquids

Net attributable* Proved + Proved + Proved probable + probable possible

Proved

Proved + probable

Proved + probable + possible

Goudron

1,580

11,791

25,598

1,336

10,270

22,351

Total

1,580

11,791

25,598

1,336

10,270

22,351

Asset

Operator LGO

Note: "Gross" are 100% of reserves and/or resources attributable to the license whilst "Net attributable" are those attributable to the company after deduction of royalties and the State share of production. bbls – Barrels, scf - Standard Cubic Feet, 1 Boe = 6 Mscf

2.3

Resources

A summary of the estimated contingent resources associated with the potential for a waterflood in the Goudron Field are presented in the following table:

Summary of oil and gas contingent resources (all figures in Mbbls)

Low Estimate

Gross Best Estimate

High Estimate

3,150

22,200

63,400

2,756

19,425

55,453

3,150

22,200

62,400

2,756

19,425

55,453

Oil & liquids contingent resources (development unclarified) Total oil & liquids

Net attributable Low Best High Estimate Estimate Estimate

Risk Factor

Operator

40%

LGO

Given that no pilot project has been undertaken to prove the commerciality of a waterflood in this field, no cash flows have been developed for these contingent resources. As such, the economic status of these contingent resources are considered as “Undetermined” at this time. A risk factor of 40 percent has been associated with these resources to account for the chance of commerciality of a waterflood in the Goudron Field. While there is currently a market for the sale of oil from this field and much of the necessary infrastructure is in place for the production and transportation of this oil, LGO will need to perform a pilot project to determine if a waterflood in this field would be economically and technically feasible. They will also need to secure a water supply and develop infrastructure associated with water transportation and treatment before a full field waterflood could be implemented. 2.4

Summary of oil and gas assets

A summary of the land attributable to each asset is presented in the following table:

Asset (1)

Operator

Goudron

LGO Energy Plc.

Summary of oil and gas assets License Interest License area Status expiry % (acres) date 100

Producing

2023

2,817

Comments Contract was signed with 10 year term in 2013 with 5 year extensions permitted

(1) All assets located onshore Trinidad.

3.0

Property descriptions, geology, reserves and production forecast 3.1

Geology

The Goudron Field is a mature oilfield located in southeast Trinidad. The sediments within the Goudron Field were deposited by a wave-dominated delta system prograding onto a storminfluenced and current-influenced shelf. The high rates of sediment supply filled all available proximal space, creating a broad and low slope coastal plain. The sediments represent two different depositional belts: Goudron Mayaro Sand and C-Sand. Two reservoir targets have been identified for hydrocarbon production in the Gourdron field; the Goudron Mayaro Formation and the C-Sands incorporating the Lower Morne and Lower Cruse Formations (Figure 1). Oil accumulations occur in sands deposited in the Pilote syncline.

The accumulations are

confined to an area at the south-eastern rim of syncline where the Gros Morne anticline and Kapur Ridge anticline converge. Stratigraphic column for Goudron block (Source: LGO Goudron Field overview May 2016 presentation)

ÂŠ Deloitte LLP and affiliated entities. 5

Goudron Mayaro Sands The late Pliocene Goudron Mayaro Sandstone Member of the Goudron Formation consists of inner shelf sedimentary facies represented by shore face deposits with some fluvial influence. The Goudron Mayaro Sand is well connected and extensive across the field. C-Sand Member The late Miocene to early Pliocene C-Sand Member of the Lower Cruse and Lower Morne Formations was deposited in a predominantly shaly distal delta front to prodelta environment. The C-Sand consists of slope channelized sand or fan lobes. Sand content and quality is controlled by the geometry of these lobes. Pre-Cruse Member The early Miocene Pre-Cruse Member consists of sands deposited along with deep-water calcareous clays and marls in a bathyal environment. The sands occur as narrow, elongate turbidite fans, trending northeast-southwest. Log analysis and original oil-in-place LGO provided a Petrel project which models the reservoirs of the Goudron Field. Within this model a petrophysical evaluation of the logs was done to calculate the effective porosity, water saturation, and net pay. The effective porosity was calculated using a 16 percent cutoff for the Goudron Mayaro Sand and a 12 percent cutoff for the C-Sand.

The water saturation was

calculated using a 65 percent cutoff. A clay volume cutoff of 55 percent for the Goudron Mayaro Sand and 60 percent for the C-Sand was used to calculate the net pay. These parameters were converted into 3D grids for the Goudron Mayaro Sand and C-Sand members. The volumetric calculations used these grids to determine the original oil-in-place (OOIP) for the field. Deloitte reviewed and evaluated this Petrel model and found the methodology to be reasonable and acceptable. LGO has constrained the OOIP using three areas within the Goudron block: historical field, well constrained, and upside. The historical field area has the densest drilling to date, while the well constrained area is consistent with the limits of the Goudron Mayaro sands outcrop and within reasonable well control. The upside area reflects the limits of the Goudron Mayaro outcrop extending to the northeast of the license. LGO considers the upside area to have potential in

ÂŠ Deloitte LLP and affiliated entities. 6

both the Goudron and C sands but there is currently very little in terms of well control and requires more development prior to assigning reserves. Summary of P50 OOIPs by Area Area Historical Field Well Constrained Upside

3.2

Goudron Mayaro

P50 Original oil-inplace (MMbbl) 101.9

C-Sands

155.7

Goudron Mayaro

146.7

Formation

C-Sands

408.7

Goudron Mayaro

266.0

C-Sands

610.9

Geophysics

No seismic data is available directly within the Goudron Block. The 2D seismic lines shot on the outskirts of the block have not been reviewed in this analysis. 3.3

Reserves and production forecast

Prior to LGO taking over the operating of the Goudron Field, there were 147 wells on the license, LGO has since drilled 15 wells in 2014 and 2015. There are a total of 92 wells targeting the shallower Goudron Mayaro sand and 70 wells targeting the deeper C-sand with only a total of 67 wells currently producing.

The production data for the field is limited with only cumulative

production recorded prior to 2010 and no reservoir production allocation data for the wells. LGO provided production forecasts for the Goudron Mayaro and C-sand existing wells as separate groups. Wells that are producing from both the C-sand and the Goudron Mayaro, LGO allocated production to the separate groups based on pay thickness.

Decline analysis was

performed on each group of existing wells by LGO using an exponential decline for the low case (P90), a hyperbolic decline with an exponent of 0.3 for the mid case (P50), and for the high case (P10) a hyperbolic decline of 0.6 was used. Deloitte is in agreement with the forecasts applied by LGO to the existing wells. Technical remaining volume by reservoir

Existing wells

Formation

P90 (Mbbl)

P50 (Mbbl)

P10 (Mbbl)

Goudron Mayaro

277.7

376.9

558.1

C-Sands

113.4

175.9

288.4

391.1

552.8

846.5

Total

ÂŠ Deloitte LLP and affiliated entities. 7

Future re-completions in the Goudron Mayaro sand are expected to be completed in 51 wells in the P50 case and forecasts for the re-completions are based on the performance of wells with recompletions in that zone. All recently drilled C-sand wells penetrate the Goudron Mayaro sand but not all are expected to be re-completed because interference could occur at the current well spacing. Development wells for both the Goudron Mayarao and C-sand are expected to be drilled in the field, with 64 Goudron Mayaro and 108 C-sand wells forecast for the P50 case. Production profiles for both types of wells are forecast using a type well generated from the average performance of wells over the last few years. The Goudron Mayaro type well is specifically based on the performance of the legacy wells, with the expectation that a well specifically targeting the Gourdron Mayaro will perform better than a well targeting the C-Sand with a Goudron Mayaro recompletion. There has only been one well drilled by LGO that has been completed in the Goudron Mayaro (GY-672), which has performed in line with the type well expectations. This well was originally targeting the C-sand reservoir. LGO also forecast a type well for the C-sand that includes the Pre-Cruse zone, which is based on the performance of one well (GY-670) that was recently re-completed in this zone. LGO expects 40 percent of the C-sand wells will be able to target the Pre-Cruse zone and has created a hybrid type well to reflect this. Deloitte recognizes that there is potential in the Pre-Cruse based on the current performance of the GY-670 well, however as the production data from this zone is limited, Deloitte has adjusted the original LGO volume to reflect a more conservative initial production rate until more data is available on the performance of this zone. LGO has only assigned C-sand wells in the P50 and P10 cases as this formation is not a priority at current prices. Type well technical volumes per well

Development wells Re-completions

Formation

P90 (Mbbl)

P50 (Mbbl)

P10 (Mbbl)

Goudron Mayaro

100

C-Sands

Goudron Mayaro

LGO has performed an analysis of the existing well drainage areas to back up the drilling program for the field. Deloitte has reviewed the analysis performed and the expected number of future locations and deemed it reasonable. LGO has also accounted for a 10 percent dry hole rate in the development plan, which Deloitte has deemed reasonable based on the historical success rate seen in the field.

ÂŠ Deloitte LLP and affiliated entities. 8

For the P50 case, LGO plans to drill at a rate of 16 wells per year in the C-sand between 2018 and 2024 and to drill at a rate of 24 wells per year in the Goudron Mayaro between 2016 and 2019. Most Goudron Mayaro re-completions are forecast to occur in 2021 and 2022 at a rate of two per month. LGO drilled eight wells in 2014 and seven wells in 2015 and will need to significantly increase its drilling rate in order to meet the proposed forecast. Summary of production and reserves P90

P50

P10

Original oil-in-place*

MMbbl

210

555

975

Cumulative production (April 30, 2016)

MMbbl

5.3

2.5

1.0

0.5

MMbbl

6.9

17.1

30.9

Current recovery factor Ultimate recoverable Expected recovery factor

3.3

3.1

3.2

MMbbl

1.6

11.8

25.6

Number of new wells

172

243

Number of recompletes

Remaining recoverable

*OOIP volumes represent the historical field area for the P90 case, the well constrained area the P50 case, and the upside area for the P10 case

3.4

Resources

Additional potential exists in the Goudron Field for a future waterflood. A pilot has not been implemented to date; however, a waterflood has been under way since 1969 in the C-sands of the nearby Navette field, since 1953 in the nearby Beach field, and since 1973 in the nearby Trinity Inniss field. An in depth study of these fields was commissioned by LGO and performed by Gerard Garcia in November 2015. A summary of select geological parameters and estimated production performance from this report are outlined below. Select properties of analogous fields Porosity (%) Water Saturation (%) Oil API Estimated Primary Recovery Estimated Incremental Waterflood Recovery

Navette

Beach

Trinity Inniss

24 - 26 26 - 35 32 6 - 17%

21 - 22 22 - 38 31 - 33 11 - 21% 15 - 21%

18 - 24 28 - 40 22% 11%

These analogs show estimated incremental waterflood recovery factors of six to 21 percent. Gerard Garcia also analyzed several sandstone waterfloods in the United States which had estimated incremental recovery factors of nine to 21 percent. However, the primary recovery factors of these analogs were in the range of 11 to 37 percent, compared to the expected primary recovery of three percent from the Goudron Field. Gerard Garcia also outlined concerns about

ÂŠ Deloitte LLP and affiliated entities. 9

the heterogeneity of the reservoir which may reduce sweep efficiency, due to channeling and fingering, and could cause some water injectors to be ineffective due to poor injectivity. Based on the reviewed analogies and Deloitte’s experience with waterflood schemes in Western Canada, incremental recovery factors from waterflood can be expected to be in the range of 50 to 200 percent of the primary recovery factor for a field. As a result, Deloitte has used incremental recovery factors of 1.5 to 6.5 percent when assigning contingent resources to the Goudron Field. A summary of the assigned resources can be seen below. Summary of reserves and resources OOIP (MMbbl) Ultimate primary recovery (MMbbl) Expected primary recovery factor (%) Estimated incremental waterflood recovery factor (%) Gross contingent resources (MMbbl)

4.0

Low 210 6.9 3.3 1.5 3.2

Best 555 17.1 3.1 4 22.2

High 975 30.9 3.2 6.5 63.4

Economic parameters 4.1

License details

The IPSC for the Goudron Field allows for LGO to receive a service fee as compensation for operating the field, which is calculated in the following way: Service Fee = Market Value – Royalty – Notional Overriding Royalty – Facilitation Fee – License Fee – Miscellaneous Deductions The Market Value is the value of the oil delivered to Petrotrin not including the first tranche. The following burdens are applicable to this field based on the details of the IPSC: 

First tranche oil (1,221 bbl/month) is given directly to Petrotrin and LGO received $9/bbl as a handling fee; this is scheduled to end in November 2019



12.5 percent royalty is applied to all oil revenue



Notional overriding royalty (NORR) that fluctuates according to the following schedule:

Market value ($/bbl)

Base NORR (%)

Enhanced NORR (%)

≤10.00 10.01 - 20.00 20.01 – 30.00 30.01 – 40.00 40.01 – 50.00 50.01 – 90.00 90.01 – 120.00 120.01 – 140.00 140.01 – 200.00 ≥200.00

7.0 10.0 12.0 17.5 19.5 23.0 27.0 30.0 32.0 TBN

4.0 5.0 6.0 9.0 10.0 17.0 18.0 19.0 20.0 TBN

The base NORR is applicable to all production beyond the first tranche up to 4,590 bbl per month. The enhanced NORR is applicable to all production beyond the base. 

A fee of $1.25/bbl of production to cover abandonment costs as all wells and facilities will remain the property of Petrotrin.



Supplemental Petroleum Tax of 18 percent is paid when the oil price is greater than $50/bbl.



Facilitation fee is paid on all oil, excluding the first tranche, at a cost of 2.70/bbl escalating at five percent per year.



4.2

The following license fees are to be paid to Petrotrin: Fee type

Fee amount

Escalation

License rent Surface rental Training fee R&D fee Scholarship fee

$4.25/ha $6.25/ha $7,360 $7,360 $50,000

Escalated at 6% per year Escalated at 6% per year Escalated at 6% per year Escalated at 6% per year No escalation

Operating and capital expenses

The operating expenses for the field that were forecast are based on historical expenses from 2015, with adjustments made to account for one-time expenses. The operating expenses have been applied with both a fixed and variable component, but the costs are largely considered fixed. Based on historical costs, it has been estimated that 1.3 MM$ per year of operating expenses are fixed for the field, an incremental $8,400/well is also fixed. Additional fixed costs of $2,500/well are applied when the well count exceeds 83 to account for civil and grass cutting costs. Variable costs of $0.20/bbl have been applied for all volumes greater than 700 bbl/d for costs associated with processing. A LACT unit is expected to be installed in 2018 that will eliminate this cost. Finally, a cost of $0.16/bbl has been forecast to account for power expenses.

Capital costs for new wells drilled were provided by LGO.

A new Goudron Mayaro well is

expected to cost 430 M$, a Goudron Mayaro re-completion is expected to cost 70 M$, and a new C-sand well is expected to cost 1,300 M$. 4.3

Other economic parameters

An oil shrinkage factor has been applied to all technical volumes to account for volumes not sold from the raw production. On existing wells the shrinkage was been applied at 12 percent and on newer wells only five percent has been applied. The older wells has more leakage and therefore will have more losses than the newer wells. The benchmark pricing of WTI has been used with an offset applied of five percent to reflect the received price. This reflects the historical average difference over the last year between the received price for the field and the benchmark. A tangible tax offset for the capital spent is accounted for on a 50, 30, and 20 percent basis over three years beginning in the year that the capital is spent. Petroleum tax is paid at a rate of 50 percent.

ÂŠ Deloitte LLP and affiliated entities. 12

Appendix 1 Tables

ÂŠ Deloitte LLP and affiliated entities. 13

Table 1: P90 Cash Flow Profile

2016 (8) 2017 2018 2019 2020 2021 2022 2023 2024 Total

Gross Oil Oil Price Oil Revenue Royalties Petrotrin Operating Net Operating Capital Before Tax After Tax Cash Volume (bbl) ($/bbl) ($) ($) Fees ($) Expenses ($) Income ($) Costs ($) Cash Flow ($) Taxes ($) Flow ($) 90,396 41.80 3,458,165 821,874 385,062 1,597,671 653,558 2,220,000 -1,566,442 373,882 -1,940,324 238,402 47.50 10,759,991 2,554,725 966,848 2,606,562 4,631,855 10,740,000 -6,108,145 799,528 -6,907,673 344,296 54.34 18,044,743 5,398,855 1,522,819 2,809,449 8,313,619 6,090,000 2,223,619 54,134 2,169,485 278,901 63.03 16,788,131 5,555,676 1,284,349 2,741,985 7,206,121 0 7,206,121 50,364 7,155,756 207,722 71.96 14,948,179 6,476,397 998,856 2,688,990 4,783,937 0 4,783,937 44,845 4,739,092 154,383 78.66 12,143,733 5,304,792 775,468 2,649,687 3,413,784 0 3,413,784 36,431 3,377,353 115,305 85.60 9,869,537 4,357,351 604,917 2,657,829 2,249,440 0 2,249,440 29,609 2,219,831 86,240 87.31 7,529,190 3,369,877 472,408 2,680,890 1,006,016 0 1,006,016 22,588 983,428 64,427 89.06 5,738,047 2,614,671 368,366 2,592,213 162,797 0 162,797 17,214 145,583 1,580,072 68.81 99,279,715 36,454,220 7,379,093 23,025,276 32,421,127 19,050,000 13,371,127 1,428,595 11,942,531

NPV5 ($) -1,893,562 -6,420,189 1,920,363 6,032,440 3,804,900 2,582,470 1,616,551 682,060 96,161 8,421,195

NPV10 ($) -1,850,026 -5,987,462 1,709,523 5,126,030 3,086,228 1,999,478 1,194,724 481,169 64,755 5,824,419

Â© Deloitte LLP and affiliated entities. 14

Table 2: P50 Cash Flow Profile

2016 (8) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total

Gross Oil Oil Price Oil Revenue Petrotrin Operating Net Operating Capital Before Tax After Tax Cash Volume (bbl) ($/bbl) ($) Royalties ($) Fees ($) Expenses ($) Income ($) Costs ($) Cash Flow ($) Taxes ($) Flow ($) 96,675 41.80 3,720,604 881,102 410,730 1,598,659 830,113 2,220,000 -1,389,887 374,818 -1,764,705 328,936 47.50 15,060,376 3,522,365 1,321,327 2,635,238 7,581,446 10,740,000 -3,158,554 816,109 -3,974,663 823,291 54.34 44,073,311 13,077,283 3,566,478 3,470,681 23,958,869 25,990,000 -2,031,131 132,220 -2,163,351 1,256,724 63.03 78,422,741 25,776,344 5,594,314 3,673,664 43,378,419 25,530,000 17,848,419 2,405,698 15,442,721 1,243,978 71.96 89,519,788 33,778,159 5,736,070 3,842,397 46,163,162 20,800,000 25,363,162 12,255,949 13,107,214 1,269,495 78.66 99,858,444 37,871,629 6,063,677 3,988,778 51,934,360 22,200,000 29,734,360 15,918,173 13,816,187 1,413,800 85.60 121,014,173 46,767,273 6,989,708 4,058,056 63,199,136 22,410,000 40,789,136 22,408,817 18,380,319 1,392,343 87.31 121,558,505 47,318,845 7,140,882 4,184,541 62,914,236 20,800,000 42,114,236 22,507,855 19,606,381 1,293,255 89.06 115,180,485 44,628,436 6,889,523 4,122,042 59,540,485 20,800,000 38,740,485 20,875,708 17,864,777 784,929 90.82 71,287,265 30,950,350 4,378,837 4,037,854 31,920,225 0 31,920,225 11,449,986 20,470,239 483,486 92.63 44,782,879 19,550,662 2,832,019 3,916,179 18,484,020 0 18,484,020 7,412,560 11,071,460 349,314 94.48 33,002,321 14,483,729 2,143,959 3,800,732 12,573,902 0 12,573,902 6,414,653 6,159,249 267,835 96.38 25,813,273 11,392,427 1,721,188 3,640,286 9,059,373 0 9,059,373 4,460,095 4,599,278 209,698 98.33 20,618,524 9,157,316 1,410,811 3,624,604 6,425,793 0 6,425,793 2,996,042 3,429,751 166,909 100.27 16,736,407 7,487,447 1,175,386 3,644,533 4,429,042 0 4,429,042 1,886,182 2,542,860 133,369 102.27 13,639,344 6,155,255 983,047 3,585,247 2,915,795 0 2,915,795 1,044,605 1,871,190 111,116 104.31 11,590,546 5,273,943 856,362 3,541,028 1,919,213 0 1,919,213 490,339 1,428,874 94,576 106.40 10,062,868 4,616,784 761,758 3,313,428 1,370,897 0 1,370,897 184,182 1,186,715 71,574 108.54 7,768,450 3,629,864 603,961 3,059,671 474,954 0 474,954 23,305 451,648 11,791,302 84.93 943,710,305 366,319,213 60,580,036 67,737,618 449,073,438 171,490,000 277,583,438 134,057,295 143,526,143

NPV5 ($) -1,722,175 -3,694,165 -1,914,934 13,018,510 10,523,459 10,564,454 13,385,130 13,598,083 11,800,178 12,877,293 6,633,111 3,514,397 2,499,329 1,775,036 1,253,365 878,383 638,808 505,282 183,146 96,316,688

NPV10 ($) -1,682,580 -3,445,175 -1,704,690 11,062,402 8,535,782 8,179,531 9,892,375 9,592,952 7,946,205 8,277,371 4,069,881 2,058,315 1,397,272 947,243 638,452 427,102 296,493 223,859 77,453 66,790,244

Â© Deloitte LLP and affiliated entities. 15

Table 3: P10 Cash Flow Profile

2016 (8) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Total

Oil Price Oil Revenue Gross Oil Volume (bbl) ($/bbl) ($) Royalties ($) 107,031 41.80 4,153,491 978,750 462,283 47.50 21,394,343 4,947,540 1,196,195 54.34 64,336,926 19,372,051 1,900,459 63.03 118,999,017 44,031,926 2,207,354 71.96 158,846,745 61,995,202 2,242,969 78.66 176,431,969 70,177,999 2,387,222 85.60 204,334,294 81,906,032 2,484,589 87.31 216,917,050 87,312,616 2,325,335 89.06 207,100,114 83,409,327 2,118,364 90.82 192,389,806 78,876,553 1,964,713 92.63 181,981,496 74,399,787 1,859,959 94.48 175,724,316 72,228,458 1,128,283 96.38 108,741,132 47,059,699 718,552 98.33 70,651,645 30,676,561 534,269 100.27 53,572,517 23,330,658 420,171 102.27 42,969,800 18,770,284 339,629 104.31 35,426,653 15,525,853 278,886 106.40 29,673,489 13,051,312 231,095 108.54 25,082,521 11,076,646 190,950 110.72 21,142,447 9,381,942 159,511 112.96 18,017,575 8,037,866 140,478 115.19 16,181,292 7,247,898 113,941 117.52 13,389,787 6,047,215 85,942 119.84 10,299,483 4,717,905 25,598,181 91.25 2,167,757,907 874,560,080

Petrotrin Operating Net Operating Capital Costs Before Tax After Tax Fees ($) Expenses ($) Income ($) ($) Cash Flow ($) Taxes ($) Cash Flow ($) NPV5 ($) 452,889 1,600,299 1,121,553 2,220,000 -1,098,447 376,362 -1,474,809 -1,439,267 1,839,244 2,682,633 11,924,925 10,740,000 1,184,925 840,702 344,223 319,931 5,147,847 3,713,582 36,103,447 25,990,000 10,113,447 839,596 9,273,851 8,208,936 8,414,187 4,211,476 62,341,428 31,120,000 31,221,428 20,000,532 11,220,895 9,459,430 10,105,784 4,437,262 82,308,498 25,960,000 56,348,498 30,002,514 26,345,984 21,152,542 10,638,776 4,682,950 90,932,243 22,200,000 68,732,243 36,130,430 32,601,814 24,928,756 11,731,277 4,924,781 105,772,204 22,480,000 83,292,204 45,487,115 37,805,089 27,530,863 12,658,716 5,141,802 111,803,917 21,990,000 89,813,917 49,344,455 40,469,461 28,067,755 12,300,502 5,416,521 105,973,764 20,800,000 85,173,764 46,485,720 38,688,043 25,554,520 11,643,129 5,670,046 96,200,078 20,800,000 75,400,078 41,316,312 34,083,766 21,441,207 11,223,481 5,766,991 90,591,237 20,800,000 69,791,237 38,331,125 31,460,112 18,848,319 11,045,543 5,643,747 86,806,568 18,200,000 68,606,568 36,945,785 31,660,783 18,065,280 7,012,193 5,484,764 49,184,475 0 49,184,475 21,486,685 27,697,791 15,051,469 4,682,636 5,407,774 29,884,674 0 29,884,674 14,046,526 15,838,148 8,196,886 3,645,811 5,331,199 21,264,850 0 21,264,850 11,256,385 10,008,465 4,933,131 3,001,358 5,143,246 16,054,912 0 16,054,912 8,359,111 7,695,801 3,612,598 2,539,504 4,976,453 12,384,842 0 12,384,842 6,317,943 6,066,899 2,712,335 2,183,040 4,807,582 9,631,555 0 9,631,555 4,786,376 4,845,179 2,062,990 1,893,961 4,600,095 7,511,817 0 7,511,817 3,606,747 3,905,070 1,583,532 1,639,059 4,457,317 5,664,129 0 5,664,129 2,578,698 3,085,431 1,191,583 1,433,850 4,474,245 4,071,615 0 4,071,615 1,693,441 2,378,174 874,708 1,320,706 4,240,428 3,372,260 0 3,372,260 1,303,287 2,068,973 724,745 1,122,807 3,890,739 2,329,027 0 2,329,027 721,134 1,607,893 536,411 888,961 3,307,119 1,385,497 0 1,385,497 192,922 1,192,575 378,911 138,565,260 110,013,052 1,044,619,514 243,300,000 801,319,514 422,449,904 378,869,611 243,997,572

NPV10 ($) -1,406,176 298,367 7,307,661 8,038,095 17,157,236 19,301,097 20,346,879 19,800,779 17,208,339 13,782,153 11,564,772 10,580,490 8,414,660 4,374,246 2,512,890 1,756,577 1,258,889 913,982 669,675 481,015 337,049 266,571 188,331 126,987 165,280,564

Â© Deloitte LLP and affiliated entities. 16

Table 4: P90 Notional Overriding Royalty First tranche (Mbbl) Base (Mbbl) Enhanced (Mbbl) 2016 (8) 9,768 24,793 100,082 2017 14,652 36,152 187,240 14,652 35,136 294,508 2018 2019 14,652 34,140 230,109 2020 47,816 159,338 2021 46,860 107,523 2022 45,923 69,382 2023 45,004 41,236 2024 44,104 20,147

Average NORR (%) 11.9 11.5 17.6 17.8 18.4 18.8 19.4 20.1 21.1

Table 5: P50 Notional Overriding Royalty First tranche (Mbbl) Base (Mbbl) Enhanced (Mbbl) 2016 (8) 9,768 24,793 109,428 2017 14,652 36,152 277,528 2018 14,652 35,136 773,503 2019 14,652 34,140 1,207,931 2020 47,816 1,192,763 2021 46,860 1,222,635 2022 45,923 1,367,877 2023 45,004 1,347,339 2024 44,104 1,245,617 2025 43,222 741,707 2026 42,358 441,128 2027 41,511 307,803 2028 40,680 226,423 2029 39,867 169,831 2030 39,069 127,840 2031 38,288 95,081 2032 37,522 73,594 2033 36,772 57,804 2034 36,036 35,537

Average NORR (%) 11.8 11.1 17.3 17.2 17.2 17.2 17.2 17.2 17.2 18.5 18.8 19.1 19.4 19.7 20.1 20.6 21.0 21.5 22.5

Table 6: P10 Notional Overriding Royalty First tranche (Mbbl) Base (Mbbl) Enhanced (Mbbl) 2016 (8) 9,768 24,793 124,839 2017 14,652 36,152 410,528 2018 14,652 35,136 1,146,407 2019 14,652 34,140 1,851,667 2020 47,816 2,153,507 2021 46,860 2,196,109 2022 45,923 2,341,299 2023 45,004 2,439,585 2024 44,104 2,274,877 2025 43,222 2,075,142 2026 42,358 1,922,355 2027 41,511 1,818,449 2028 40,680 1,084,520 2029 39,867 678,685 2030 39,069 495,200 2031 38,288 381,883 2032 37,522 302,106 2033 36,772 242,114 2034 36,036 195,059 2035 35,316 155,634 2036 34,609 124,902 2037 33,917 106,561 2038 33,239 80,702 2039 32,574 53,368

Average NORR (%) 11.6 10.8 17.2 17.1 17.1 17.1 17.1 17.1 17.1 18.2 18.2 18.2 18.3 18.5 18.7 18.8 19.0 19.2 19.4 19.7 20.0 20.2 20.6 21.4

ÂŠ Deloitte LLP and affiliated entities. 17

Table 7: P90 Development Schedule Goudron Goudron C-sand Total capital Wells Re-completes wells (M$) 2016 5 1 2,220 2017 24 6 10,740 2018 14 1 6,090 2019 2020 2021 2022 2023 2024 Total 43 8 0 19,050 Table 8: P50 Development Schedule Goudron Goudron C-sand Total capital Wells Re-completes wells (M$) 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Total

5 24 24 11 64

1 6 1 20 23 51

12 16 16 16 16 16 16 108

2,220 10,740 25,990 25,530 20,800 22,200 22,410 20,800 20,800 171,490

Table 9: P10 Development Schedule Goudron Goudron C-sand Total capital Wells Re-completes wells (M$) 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Total

5 24 24 24 12 89

1 6 1 20 24 17 69

12 16 16 16 16 16 16 16 16 14 154

2,220 10,740 25,990 31,120 25,960 22,200 22,480 21,990 20,800 20,800 20,800 18,200 243,300

ÂŠ Deloitte LLP and affiliated entities. 18

Appendix 2 Figures

ÂŠ Deloitte LLP and affiliated entities. 19

A OB

Caribean Sea

ZU ENE

ELA

Chaguaramas Port-of-Spain

Atlantic Ocean

Gulf of Paria

TRINIDAD Pointe-A-Pierre San Fernando

Point Fortin

Goudron

Icacos

Columbus Channel

VENEZUELA

Legend Evaluated Property

LGO Energy Plc. Property location Effective April 30, 2016 By : laj Project : prop loc

Date : 2016/07/12

1121500 1121000 268 271

270

198

52 51

269

236

677,676,675

42 43 241 59

202

49 53 258 245

275

231

! ! !

380 246 273

379

382 ! ! !

237

255

672,673,674 256

296

381 65 215,207,209 211,213 254 214 50 190 188 64 208 234 293 664 291 45 247 63 253 384 62 239 61 243 66 203 248 244 168 167 385 284242 155 250 252 668 376 667 ! 156 192 666 240 281 665 193 251 200 186 377 39 181 278 184 282 378 37 375 283 386 277 280 36 35 292 279 238

!! !

285

383

187

! !

233 289

607

1120000

42A

658 295

232 286X

288 154

160 133

134 257

153

290

! ! ! !

152

669,670, 671,678

1119500

40 23 41

1120500

46 272

157

Legend Goudron Well Locations Status

605

Producing Abandoned

1119000

195 34A

199

Inactive Roads Goudron Field

1:5,000

169

0 62.5 125

250

375

500

1118500

Meters

158

702500

703000

703500

704000

704500

This map was provided by LGO Energy Plc. and has been audited (and adjusted) by Deloitte.

705000

705500

LGO Energy Plc. Goudron Block, Trinidad Existing Wells By : laj Project : goudron block Source : LGO Energy Plc.

Date : 2016/07/12

1121500 1121000 268 271

270

198

52 51

269

236

677,676,675

42 43 241 59

202

49 53 258 245

275

231

! ! !

380 246 273

379

382 ! ! !

237

255

672,673,674 256

296

!! !

285

383

187

! !

233 289

607

1120000

42A

658 295

232 286X

288 154

160 133

134 257

153

290

! ! ! !

152

669,670, 671,678

1119500

40 23 41

1120500

46 272

157 21

Legend Goudron Well Locations Status

605

Producing

Upside Area

1119000

Abandoned 30

195 34A

199

Well Constrained Area

Inactive

Historical Field Area Goudron Field

Roads

1:5,000

169

0 62.5 125

250

375

500

1118500

Meters

158

702500

703000

703500

704000

704500

This map was provided by LGO Energy Plc. and has been audited (and adjusted) by Deloitte.

705000

705500

LGO Energy Plc. Goudron Block, Trinidad Original Oil-in-Place Areas By : laj Project : ooip areas Source : LGO Energy Plc.

Date : 2016/07/12

Figure 1

Figure 2

ÂŠ Deloitte LLP and affiliated entities. 23

Figure 3

Figure 4

ÂŠ Deloitte LLP and affiliated entities. 24

Figure 5

Figure 6

ÂŠ Deloitte LLP and affiliated entities. 25

Appendix 3 Qualifications

ÂŠ Deloitte LLP and affiliated entities. 26

Independent petroleum consultants consent The undersigned firm of Independent Qualified Reserves Evaluators and Auditors of Calgary, Alberta, Canada has prepared an independent evaluation of reserves and future net revenues derived therefrom, of the Petroleum and Natural Gas assets of the interests of LGO Energy Plc. according to the Canadian Oil and Gas Evaluation Handbook. If required, these reserves and future net revenues were estimated using forecast prices and costs (before and after income taxes) according to the requirements of National Instrument 51-101 (NI 51-101). The effective date of this evaluation is April 30, 2016. In the course of the evaluation, LGO Energy Plc. provided Deloitte personnel with basic information which included land, well and accounting (product prices and operating costs) information; reservoir and geological studies, estimates of on-stream dates for certain properties, contract information, budget forecasts and financial data. Other engineering, geological or economic data required to conduct the evaluation and upon which this report is based, were obtained from public records, other operators and from Deloitte non confidential files. The extent and character of ownership and accuracy of all factual data supplied for the independent evaluation, from all sources, has been accepted. A “Representation Letter” dated July 12, 2016 and signed by the Chief Operating Officer and the Finance Director was received from LGO Energy Plc. prior to the finalization of this report. This letter specifically addressed the accuracy, completeness and materiality of all the data and information that was supplied to us during the course of our evaluation of Spoke Resources Ltd.’s reserves and net present values. This letter is included within. A field inspection and environmental/safety assessment of the properties was beyond the scope of the engagement of Deloitte and none was carried out. The “Representation Letter” received from Spoke Resources Ltd. provided assurance that no additional information necessary for the completion of our assignment would have been obtained by a field inspection. The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented herein are considered reasonable, and adhere to the COGE Handbook and NI 51-101 (as applicable), the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Revenue projections presented in this report are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts herein. Present values of future net revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated herein.

PERMIT TO PRACTICE Deloitte LLP Permit Number: P-11444 The Association of Professional Engineers and Geoscientists of Alberta

Certificate of qualification

I, L. G. Mitchell, a Professional Engineer, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:

I am an employee of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests of LGO Energy Plc. The effective date of this evaluation is April 30, 2016.

I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of LGO Energy Plc.

I attended the University of Calgary and graduated with a Bachelor of Science Degree in Chemical Engineering in 2008; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of eight years of engineering experience.

I am a Qualified Reserves Evaluator as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2.

A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities.

Original signed by: “L. G. Mitchell” L. G. Mitchell, P. Eng. July 11, 2016 Date

Certificate of qualification

I, J. D. Listoe, a Professional Engineer, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:

I am an employee of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests of LGO Energy Plc. The effective date of this evaluation is April 30, 2016.

I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of LGO Energy Plc.

I attended the University of Calgary and graduated with a Bachelor of Science Degree in Chemical Engineering in 2011; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of five years of engineering experience.

Original signed by: “J. D. Listoe” J. D. Listoe, P. Eng. July 11, 2016 Date

Certificate of qualification

I, D. L. Horbachewski, a Professional Geologist, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:

I am an employee of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests of LGO Energy Plc. The effective date of this evaluation is April 30, 2016.

I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of LGO Energy Plc.

I attended the University of Calgary and graduated with a Bachelor of Science Degree in Geology in 1999; that I am a Registered Professional Geologist in the Province of Alberta; and I have in excess of seventeen years of evaluations experience.

I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2.

Original signed by: “D. L. Horbachewski” D. L. Horbachewski, P. Geol. July 11, 2016 Date

Appendix 4 Evaluation procedure

ÂŠ Deloitte LLP and affiliated entities. 33

Evaluation procedure Definitions and methodology

Effective as of March 2016

Table of contents Definitions ď&#x201A;ˇ

Procedure

ď&#x201A;ˇ

Resource and reserve definitions

Resource and reserve estimation Production forecasts Land schedules and maps Geology Royalties and taxes Capital and operating considerations Price and market demand forecasts Glossary of terms

Procedure Deloitte has prepared estimates of resources and reserves in accordance with the process published in the Petroleum Resources Management System (PRMS) and Guidelines for Application of the PRMS. The reader is referred to the documents for a complete description of the particular process quoted as follows.

Resources or reserves evaluation A “Resources or Reserves evaluation” is the process whereby a qualified reserves evaluator estimates the quantities and values of oil and gas resources or reserves by interpreting and assessing all available pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to generate future net revenue, and it is measured using a set of forward-looking assumptions regarding resources or reserves, production, prices, and costs. Evaluations of oil and gas assets, in particular reserves, include a discounted cash flow analysis of estimated future net revenue.

Reserves audit A “Reserves audit” is the process carried out by a qualified reserves auditor that results in a reasonable assurance, in the form of an opinion, that the reserves information has in all material respects been determined and presented according to the principles and definitions adopted by the Society of Petroleum Evaluation Engineers (SPEE) (Calgary Chapter), and Association of Professional Engineers and Geoscientists of Alberta (APEGA) and are, therefore free of material mis-statement. The reserves evaluations prepared by the company have been audited, not for the purpose of verifying exactness, but the reserves information, company policies, procedures, and methods used in estimating the reserves will be examined in sufficient detail so that Deloitte can express an opinion as to whether, in the aggregate, the reserves information presented by the company are reasonable. Deloitte may require its own independent evaluation of the reserves information for a small number of properties, or for a large number of properties as tests for the reasonableness of the company’s evaluations. The tests to be applied to the company’s evaluations insofar as their methods and controls and the properties selected to be re-evaluated will be determined by Deloitte, in its sole judgment, to arrive at an opinion as to the reasonableness of the company’s evaluations.

Reserves review A “Reserves review” is the process whereby a reserves auditor conducts a high-level assessment of reserves information to determine if it is plausible. The steps consist primarily of enquiry, analytical procedure, analysis, review of historical reserves performance, and discussion with the company’s reserves management staff. “Plausible” means the reserves data appear to be worthy of belief based on the information obtained by the independent qualified reserves auditor in carrying out the aforementioned steps. Negative assurance can be given by the independent reserves auditor, but an opinion cannot. For example, “Nothing came to my attention that would indicate the reserves information has not been prepared and presented in accordance with principles and definitions adopted by the SPEE (Calgary Chapter), and APEGA (Practice Standard for the Evaluation of Oil and Gas Reserves for Public Disclosure). Reviews do not require examination of the detailed document that supports the reserves information, unless this information does not appear to be plausible.

Resource and reserve definitions Resource classification Resources are classified by Deloitte in accordance with the definitions prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE). This document is known as the Petroleum Resource Management System (PRMS). The reader is referred to the document for a complete description of Resources and only the particular definitions are quoted as follows.

The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”

The following definitions apply to the major subdivisions within the resources classification: Total petroleum initially-in-place (PIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations.

It includes that quantity of petroleum that is

estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”). Discovered petroleum initially-in-place is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. Production is the cumulative quantity of petroleum that has been recovered at a given date. Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into commercial and sub-commercial, with the estimated recoverable quantities being classified as reserves and contingent resources respectively, as defined below. Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

Reserves must further satisfy four criteria: they must be discovered,

recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. Contingent resources are those quantities of petroleum estimates, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.

Contingent

resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. An accumulation is an individual body of petroleum-in-place. They key requirement to consider as accumulation as “known,” and hence containing reserves or contingent resources, is that it must

have been discovered, that is, penetrated by a well that has established through testing, sampling, or logging, the existence of significant quantity of recoverable hydrocarbons. Undiscovered petroleum initially-in-place is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

Prospective resources are further subdivided in accordance with the level of

certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. Unrecoverable is that portion of discovered or undiscovered petroleum initially-in-place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as total resource base or hydrocarbon endowment. Total recoverable or estimated ultimate recovery (EUR) may be termed basin potential. The sum of reserves, contingent resources, and prospective resources may be referred to as â&#x20AC;&#x153;remaining recoverable resources.â&#x20AC;? When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.

Reserve classification Reserves are classified by Deloitte in accordance with the definitions and guidelines found in the PRMS. Evaluations may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods.

The following summarizes the definitions for each reserves category in terms of both the deterministic (incremental and scenario) approach and also provides the probability criteria if probabilistic methods are applied. Proved reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the 2P estimate. 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 and 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.

Developed non-producing reserves include shut-in and behind-pipe reserves. 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 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 of (b) install production or transportation facilities for primary or improved recovery projects. Possible reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable then 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 probability methods are used, there should be at least a 10 percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

Resource and reserve estimation Deloitte generally assigns reserves to properties via deterministic methods.

Probabilistic estimation

techniques are typically used where there is a low degree of certainty in the information available and is generally used in resource evaluations. This will be stated within the detailed property reports.

Deterministic Reserves and resources were estimated either by i) volumetric, ii) decline curve analysis, iii) material balance techniques, or iv) performance predictions. Volumetric reserves were estimated using the wellbore net pay and an assigned drainage area or, where sufficient data was available, the reservoir volumes calculated from isopach maps. Reservoir rock and fluid data were obtained from available core analysis, well logs, PVT data, gas analysis, government sources, and other published information either on the evaluated pool or from a similar reservoir in the immediate area. In mature (producing) reservoirs decline curve analysis and/or material balance was utilized in all applicable evaluations.

Probabilistic Because of the uncertainty inherent in reservoir parameters, probabilistic analysis, which is based on statistical techniques, provides a formulated approach by which to obtain a reasonable assessment of the petroleum initially in place and/or the recoverable resource. Probabilistic analysis involves generating a range of possible outcomes for each unknown parameter and their associated probability of occurrence. When probabilistic analysis is applied to resource estimation, it provides a range of possible PIIPs or recoverable resources. In preparing a resource estimate, Deloitte assesses the following volumetric parameters: areal extent, net pay thickness, porosity, hydrocarbon saturation, reservoir temperature, reservoir pressure, gas compressibility factor, recovery factor, and surface loss. A team of professional engineers and geologists experienced in probabilistic resource evaluation considers each of the parameters individually to estimate the most reasonable range of values. Working from existing data, the team discusses and agrees on the low (P90) and high (P10) values for each parameter. To help test the reasonableness of the proposed range, a minimum (P99) and maximum (P1) value are also extrapolated from the low and high values. After ranges

have been established for each parameter, these independent distributions are used to determine a P90, P50, and P10 result which comprise Deloitte’s estimated range of PIIP or recoverable resource. It is important to note that the process used to determine the final P10, P90, and P50 results involves multiplying the various volumetric parameters together. This yields results which require adjustments to maintain an appropriate probability of occurrence. For example, when calculating total reservoir volume (Area x Pay), the chance of getting a volume greater than the P10 Area x P10 Pay is less than 10 percent – the chance of getting the calculated result is only 3.5 percent (p3.5). As you multiply additional P10 values, the probability of achieving the calculated value becomes less likely. Similarly, multiplying P90 parameters together will yield a result that has a probability greater than P90. As such, when multiplying independent distributions together the results must be adjusted via interpolation to determine final P90 and P10 values. The results appearing in this report represent interpolated P90 and P10 values. As defined by PRMS, the P50 estimate is the “best estimate” for reporting purposes.

Production forecasts Production forecasts were based on historical trends or by comparison with other wells in the immediate area producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come on-stream in years three or four from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information. For reserve volumes that meet all reserve category rules but are behind casing and waiting on depletion of the producing zone, these volumes are forecast to be brought on-stream following the end of the existing production.

Land schedule and maps The evaluated company provided schedules of land ownership which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by Deloitte was made to verify the records. Well maps included within this report represent all of the company’s interests that were evaluated in the specified area.

Geology An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis. For properties that are not of a mature production nature a geologic review is conducted. This work consists of: 

developing a regional understanding of the play,



assessing reservoir parameters from the nearest analogous production,



analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation,



auditing of client mapping or developing maps to meet Deloitte’s need to establish volumetric hydrocarbons-in-place.

Procedures specific to the project are discussed in the body of the report.

Royalties and taxes General All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases, or farm-out agreements that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially. Deloitte utilizes a variety of reserves and valuation products in determining the result sets.

Capital and operating considerations Operating and capital costs were based on current costs escalated to the date the cost was incurred, and are in current year dollars. The economic runs provide the escalated dollar costs as found in the Pricing Table 1 in the Price and Market Demand section. Reserves estimated for constant prices and costs (optional), are based on un-escalated operating and capital costs. Capital costs were either provided by the Company (and reviewed by Deloitte for reasonableness); or determined by Deloitte taking into account well capability, facility requirement, and distance to markets. Facility expenditures for shut-in gas are forecast to occur prior to the wellâ&#x20AC;&#x2122;s first production. Operating costs were determined from historical data on the property as provided by the evaluated Company. If this data was not available or incomplete, the costs were based on Deloitte experience and historical database. Operating costs are defined into three types. The first type, variable ($/Unit), covers the costs directly associated with the product production. Costs for processing, gathering and compression are based on raw gas volumes. Over the life of the project the costs are inflated in escalated runs to reflect the increase in costs over time. In a constant dollar review the costs remain flat over the project life. The second type, fixed plant or battery ($/year), is again a fixed component over the project life and reflects any gas plant or battery operating costs allocated back to the evaluated group. The plant or battery can also be run as a separate group and subsequently consolidated at the property level. The third type takes the remaining costs that are not associated with the first two and assigns them to the well based on a fixed and variable component. A split of 65 percent fixed and 35 percent variable assumes efficiencies of operation over time, i.e.: the well operator can reduce the number of monthly visits as the well matures, workovers may be delayed, well maintenance can also be reduced. The basic assumption is that the field operator will continue to find efficiencies to reduce the costs over time to maintain the overall $/Boe cost. Thus as the production drops over time the 35 percent variable cost will account for these efficiencies. If production is flat all the costs will also remain flat. Both the fixed and variable costs in this type are inflated in the escalated case and held constant in the constant dollar review. These costs also include property taxes, lease rentals, government fees, and administrative overhead.

In reserve evaluations conducted for purposes of NI 51-101, or, if an economic analysis was prepared for a resource evaluation, well abandonment and reclamation costs have been included and these costs were either provided by the company (and reviewed by Deloitte for reasonableness) or based on area averages (only the base abandonment costs were utilized and no consideration for groundwater protection, vent flow repair costs, or gas migration costs were considered). If there were multiple events to abandon the costs were increased by a 25 percent factor. Site reclamation costs were based on information provided by the company or based on area averages. For undeveloped reserve estimates for undrilled locations, both abandonment and site reclamation costs are also included for the purpose of determining whether reserves should be attributed to that property in the first year in which the reserves are considered for attribution to the property.

Price and market demand forecasts Base case forecast effective March 31, 2016 The attached price and market forecasts have been prepared by Deloitte, based on information available from numerous government agencies, industry publications, oil refineries, natural gas marketers, and industry trends. The prices are Deloitteâ&#x20AC;&#x2122;s best estimate of how the future will look, based on the many uncertainties that exist in both the domestic Canadian and international petroleum industries.

Inflation forecasts and

exchange rates, an integral part of the forecast, have also been considered. In preparing the price forecast Deloitte considers the current monthly trends, the actual and trends for the year to date, and the prior year actual in determining the forecast. The base forecast for both oil and gas is based on NYMEX futures in US dollars. The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in current data and reflecting a higher percent to the prior year historical. These forecasts are Deloitteâ&#x20AC;&#x2122;s interpretation of current available information and while they are considered reasonable, changing market conditions or additional information may require alteration from the indicated effective date.

Deloitte Resource Evaluation & Advisory International Forecast Base Case Forecast Effective March 31 2016 Escalated Prices Crude Oil Pricing

H i s t o r i c a l F o r e c a s t

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2035+ Notes:

Natural Gas

Ethanol

Average Alaska California Louisiana Louisiana MARS Wyoming Gulf Coast Average NYMEX U.S. WTI North Kern Heavy Light Blend Sweet Brent Argus Sour OPEC Venezuelan Nigerian Arabia UAE Mexico Russia Indonesia Henry Permian San Juan Gulf Coast Louisiana Rocky Mtn. CBOT Sweet Sweet Spot Crude Index Basket Merey Bonny Light Dubai Feteh Maya Urals Minas Hub Waha Ignacio (Onshore) East Texas Opal UK NBP Ethanol USD to GBP USD to EUR Spot Slope River Exchange Exchange US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/gal. Rate Rate Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated Escalated 1.860 1.267 $66.51 $57.64 $55.56 $64.38 $64.41 $57.66 $60.80 $65.86 N/A $61.74 N/A $67.56 $62.19 $52.04 $61.94 $65.77 $6.47 $5.67 $5.59 $6.16 $6.45 $5.03 $4.30 $0.00 2.002 1.371 $72.32 $63.80 $57.28 $70.20 $72.34 $63.80 $64.36 $72.47 N/A $69.07 N/A $75.15 $68.40 $59.85 $69.54 $73.55 $6.98 $6.24 $6.13 $6.56 $6.99 $4.01 $2.93 $0.00 1.852 1.470 $99.57 $91.24 $87.20 $103.62 $100.82 $94.61 $88.38 $96.85 N/A $94.05 N/A $100.24 $93.48 $83.83 $94.51 $100.25 $8.86 $7.44 $7.20 $8.48 $8.89 $6.52 $6.14 $1.84 1.565 1.393 $61.65 $54.84 $48.66 $58.78 $60.29 $56.51 $51.73 $61.49 $50.40 $60.86 $49.37 $53.01 $61.65 $56.41 $60.70 $39.23 $3.95 $3.43 $3.34 $3.76 $3.96 $3.14 $4.53 $1.72 1.546 1.328 $79.40 $72.17 $72.83 $78.16 $79.32 $75.60 $70.44 $79.68 $75.60 $77.38 $69.68 $70.70 $78.04 $70.07 $78.01 $0.00 $4.39 $4.16 $4.09 $4.29 $4.38 $3.94 $6.41 $1.80 1.604 1.392 $94.88 $98.47 $103.11 $107.12 $108.03 $105.37 $87.41 $111.26 $105.37 $107.45 $97.88 $88.28 $106.19 $98.95 $109.19 $0.00 $4.00 $3.88 $3.82 $3.90 $3.98 $3.80 $9.03 $2.51 1.586 1.286 $94.11 $98.35 $103.69 $107.18 $107.19 $104.82 $85.04 $111.99 $104.82 $109.50 $100.11 $111.61 $109.11 $99.74 $110.50 $55.32 $2.75 $2.64 $2.64 $2.68 $2.74 $2.67 $9.47 $2.31 1.565 1.329 $97.91 $95.85 $101.38 $105.80 $106.19 $101.80 $89.97 $108.64 $101.80 $105.51 $96.71 $111.41 $105.51 $98.06 $108.05 $107.54 $3.73 $3.62 $3.64 $3.64 $3.68 $3.64 $10.66 $2.04 1.647 1.329 $93.26 $86.45 $90.38 $96.16 $94.25 $92.95 $83.50 $99.02 $92.95 $96.19 $86.79 $100.77 $96.61 $85.81 $98.01 $98.63 $4.39 $4.28 $4.28 $4.31 $4.04 $4.34 $8.24 $1.93 1.529 1.110 $48.69 $41.34 $44.75 $48.38 $48.32 $46.57 $41.59 $52.39 $46.57 $49.52 $41.17 $52.99 $50.96 $44.10 $51.94 $49.24 $2.63 $2.43 $2.45 $2.51 $2.57 $2.45 $6.53 $1.50 1.450 1.100 $44.00 $38.00 $40.00 $43.00 $44.00 $42.00 $36.50 $46.00 $42.00 $43.00 $35.00 $46.50 $44.00 $38.00 $45.00 $43.00 $2.10 $1.95 $1.95 $2.00 $2.05 $2.00 $4.35 $1.40 1.450 1.100 $50.00 $43.85 $45.90 $48.95 $50.00 $47.95 $42.35 $52.00 $47.95 $48.95 $40.80 $52.55 $50.00 $43.85 $51.00 $48.95 $2.65 $2.50 $2.50 $2.55 $2.60 $2.55 $4.95 $1.45 1.450 1.100 $57.20 $51.00 $53.05 $56.20 $57.20 $55.15 $49.40 $59.30 $55.15 $56.20 $47.85 $59.80 $57.20 $51.00 $58.25 $56.20 $2.90 $2.75 $2.75 $2.80 $2.85 $2.80 $5.25 $1.45 1.450 1.100 $66.35 $59.95 $62.10 $65.25 $66.35 $64.20 $58.35 $68.45 $64.20 $65.25 $56.75 $69.00 $66.35 $59.95 $67.40 $65.25 $3.20 $3.00 $3.00 $3.10 $3.15 $3.10 $5.55 $1.50 1.450 1.100 $75.75 $69.30 $71.45 $74.70 $75.75 $73.60 $67.65 $77.95 $73.60 $74.70 $66.05 $78.50 $75.75 $69.30 $76.85 $74.70 $3.40 $3.25 $3.25 $3.30 $3.35 $3.30 $5.85 $1.50 1.450 1.100 $82.80 $76.20 $78.40 $81.70 $82.80 $80.60 $74.55 $85.00 $80.60 $81.70 $72.85 $85.55 $82.80 $76.20 $83.90 $81.70 $3.65 $3.50 $3.50 $3.55 $3.60 $3.55 $6.15 $1.55 1.450 1.100 $90.10 $83.35 $85.60 $88.95 $90.10 $87.85 $81.65 $92.35 $87.85 $88.95 $79.95 $92.90 $90.10 $83.35 $91.20 $88.95 $3.90 $3.70 $3.70 $3.75 $3.85 $3.75 $6.40 $1.60 1.450 1.100 $91.90 $85.00 $87.30 $90.75 $91.90 $89.60 $83.30 $94.20 $89.60 $90.75 $81.55 $94.75 $91.90 $85.00 $93.05 $90.75 $4.15 $3.95 $3.95 $4.00 $4.10 $4.00 $6.70 $1.60 1.450 1.100 $93.75 $86.70 $89.05 $92.55 $93.75 $91.40 $84.95 $96.10 $91.40 $92.55 $83.20 $96.65 $93.75 $86.70 $94.90 $92.55 $4.40 $4.20 $4.20 $4.30 $4.35 $4.30 $7.05 $1.65 1.450 1.100 $95.60 $88.45 $90.85 $94.40 $95.60 $93.20 $86.65 $98.00 $93.20 $94.40 $84.85 $98.60 $95.60 $88.45 $96.80 $94.40 $4.65 $4.50 $4.50 $4.55 $4.60 $4.55 $7.35 $1.65 1.450 1.100 $97.50 $90.20 $92.65 $96.30 $97.50 $95.10 $88.40 $99.95 $95.10 $96.30 $86.55 $100.55 $97.50 $90.20 $98.75 $96.30 $4.90 $4.70 $4.70 $4.75 $4.80 $4.75 $7.60 $1.70 1.450 1.100 $99.45 $92.00 $94.50 $98.25 $99.45 $97.00 $90.15 $101.95 $97.00 $98.25 $88.30 $102.60 $99.45 $92.00 $100.70 $98.25 $5.05 $4.85 $4.85 $4.90 $4.95 $4.90 $7.85 $1.75 1.450 1.100 $101.45 $93.85 $96.40 $100.20 $101.45 $98.90 $91.95 $104.00 $98.90 $100.20 $90.05 $104.65 $101.45 $93.85 $102.75 $100.20 $5.20 $5.00 $5.00 $5.05 $5.15 $5.05 $8.05 $1.80 1.450 1.100 $103.50 $95.75 $98.30 $102.20 $103.50 $100.90 $93.80 $106.10 $100.90 $102.20 $91.85 $106.70 $103.50 $95.75 $104.80 $102.20 $5.30 $5.10 $5.10 $5.15 $5.25 $5.15 $8.20 $1.80 1.450 1.100 $105.55 $97.65 $100.30 $104.25 $105.55 $102.90 $95.65 $108.20 $102.90 $104.25 $93.70 $108.85 $105.55 $97.65 $106.90 $104.25 $5.40 $5.20 $5.20 $5.30 $5.35 $5.30 $8.40 $1.85 1.450 1.100 $107.65 $99.60 $102.30 $106.30 $107.65 $105.00 $97.60 $110.35 $105.00 $106.30 $95.55 $111.05 $107.65 $99.60 $109.00 $106.30 $5.50 $5.30 $5.30 $5.40 $5.45 $5.40 $8.55 $1.90 1.450 1.100 $109.80 $101.60 $104.35 $108.45 $109.80 $107.10 $99.55 $112.55 $107.10 $108.45 $97.45 $113.25 $109.80 $101.60 $111.20 $108.45 $5.65 $5.40 $5.40 $5.50 $5.55 $5.50 $8.70 $1.90 1.450 1.100 $112.00 $103.60 $106.40 $110.60 $112.00 $109.20 $101.50 $114.80 $109.20 $110.60 $99.40 $115.50 $112.00 $103.60 $113.40 $110.60 $5.75 $5.55 $5.55 $5.60 $5.65 $5.60 $8.90 $1.95 1.450 1.100 $114.25 $105.70 $108.55 $112.85 $114.25 $111.40 $103.55 $117.10 $111.40 $112.85 $101.40 $117.85 $114.25 $105.70 $115.70 $112.85 $5.85 $5.65 $5.65 $5.70 $5.80 $5.70 $9.05 $2.00 1.450 1.100 $116.55 $107.80 $110.70 $115.10 $116.55 $113.65 $105.60 $119.45 $113.65 $115.10 $103.45 $120.20 $116.55 $107.80 $118.00 $115.10 $5.95 $5.75 $5.75 $5.85 $5.90 $5.85 $9.25 $2.05 1.450 1.100 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Venezuelan Merey replaced BCF-17 in the OPEC basket March 1, 2009.

Disclaimer - No representation or warranty of any kind (whether expressed or implied) is given by Deloitte & Touche LLP as to the accuracy, completeness, currency or fitness for any purpose of this document. As such, this document does not constitute the giving of investment advice, nor a part of any advice on investment decisions. Accordingly, regardless of the form of action, whether in contract, tort or otherwise, and to the extent permitted applicable law, Deloitte & Touche LLP accepts no liability of any kind and disclaims all responsibility for the consequences of any person acting or refraining from acting in reliance on this this price forecast in whole or in part. This price forecast is not for dissemination in the United States or for distribution to United States wire services.

Glossary of terms Refer to the Glossary of Terms as defined by the Petroleum Resources Management System.