For inclusion in the AIM Admission Document

Competent Person s Report Interests held by Northcote Energy, Ltd. in the United States of America as of 01 November 2012 Prepared for Northcote Energy, Ltd. For inclusion in the AIM Admission Document by Moyes & Co. 20 December, 2012 Page 1 of 53

20 December 2012 Moyes & Co. 8235 Douglas Ave Suite 1221 Dallas TX 75225 The Directors Northcote Energy Limited Formerly Everest Energy Limited C/O Ogier Fiduciary Services (BVI) Limited Nemours Chambers, Road Town, Tortola VG1110 British Virgin Islands The Directors The Directors Beaumont Cornish Limited, Shore Capital Stockbrokers Ltd 2nd Floor, Bowman House, Bond Street House 29 Wilson Street, 14 Clifford Street London London EC2M 2SJ W1S 4JU RE: COMPETENT PERSON S REPORT ON INTERESTS HELD BY NORTHCOTE ENERGY, LTD. The Directors of Northcote Energy Limited (formerly Everest Energy Limited) ( Everest ) have requested Moyes & Co. ( Moyes ) to prepare an independent report on the reserves, resources, and value of the producing properties and undeveloped leasehold mineral interests of Northcote Energy, Ltd. ( Northcote ). This report is to be included in an admission document to be issued by Everest in connection with its acquisition of Northcote and subsequent admission to the AIM Market ( the Admission Document ). Northcote has existing oil and gas production and reserves and is also focused on expanding its production and reserves in one of the conventional resource plays in the USA, referred to as the Mississippian Lime Resources Play. The undeveloped minerals, leasehold, and prospects are principally in the Mississippian formation, Layton and Cleveland sands, and Hunton oil and gas plays in Oklahoma, USA. Moyes hereby consents to the inclusion of this report, with the inclusion of its name, in the form and context in which it appears, in the Admission Document. Very truly yours, P. Dee Patterson, P.E. Managing Director Moyes & Co. dpatterson@moyesco.com Page 2 of 53

Table of Contents 1 Executive Summary... 4 2 Introduction... 8 2.1 Summary... 8 2.2 Northcote s Lease Holdings and Producing Assets... 8 2.3 General Nature of USA Petroleum Rights... 13 3 Mississippian Lime Horizontal Play... 15 3.1 Current Activity... 15 3.2 Petroleum Geology... 15 3.3 Reservoir Analysis... 16 4 Reserves... 20 5 Oil and Gas Prices... 22 6 Planned Expenditures... 25 7 Conclusions... 28 8 Disclosures... 29 8.1 Data... 29 8.2 Qualifications of Moyes & Co... 29 8.3 Basis of Report... 30 8.4 Responsibility... 30 Appendix A Northcote Assets... 31 Appendix B Summary of Reserves by Asset... 33 Appendix C Cash Flow Forecasts... 35 Appendix D Glossary of Terms and Abbreviations... 42 Appendix E Definitions of Oil and Gas Reserves... 48 Page 3 of 53

1 Executive Summary Northcote Energy, Ltd. ( Northcote ) is an independent oil and gas investment company based in London and Dallas, that is engaged in the acquisition, exploitation, and development of oil and gas properties located onshore in the United States, in what is referred to as the Mississippian Lime Resources Play. Northcote owns certain rights to producing assets and certain drilling leases in Oklahoma: Leases in Osage and Woods Counties, Oklahoma, totaling 480.7 net acres (6,626 gross) with 11 producing leases. The working interests in 10 producing leases (9 Mississippian wells and 1 Layton well) and an additional override interest in one of the producing leases in Oklahoma are in Osage County and are operated by Glenn Supply Company, Inc ( Glenn Supply ) of Tulsa, Oklahoma; these produce a net 28.5 BOEPD and provide cash flow to support the completion of the development program on the leases. Combined with the behind pipe reserves, production is expected to reach net 579 BOEPD by early 2014, these assets provide a base for a long life cash flow allowing for greater expansion in both Osage and Woods Counties. In Woods County, Northcote has 1 producing lease, 1 drilled well awaiting completion of pipelines, and a 12 well continuous drilling program scheduled for 2013. The Woods County properties are primarily operated by Midstates Petroleum Company (acquirer of Eagle Energy of Oklahoma) ( Midstates ) although other operators including Chesapeake Energy Corporation ( Chesapeake ) and SandRidge Energy, Inc ( Sandridge ) are also active and propose wells in the area in which Northcote has lease interests. Northcote holds three option agreements allowing for the acquisition of additional working and override interests in Osage County. Together the option agreements would permit Northcote to acquire up to an additional 18.33% (average) working interest and additional override royalty interests of 2.19% (average) in the nine leases in Osage County producing Page 4 of 53

from the Mississippian. These interests, if acquired, would substantially increase the reserve and NPV set forth herein. The Northcote assets contain a net 665 MBO and 1,688 MMcf of Proved Reserves (1P), 670 MBO and 1,702 MMCF of Proved and Probable Reserves (2P), and 674 MBO and 1,717 MMcf of Proved, Probable, and Possible Reserves (3P). The table in 1-1 is the summary of appendix C. Reserve Class/Category As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 417 1,401 29 100 2,958 1,466-1,492 937 Proved Developed Behind Pipe 2,492 6,582 521 1,376 52,178 7,185 1,104 43,889 28,488 Proved Shut In 300 944 1 2 57 8-48 33 Proved Undeveloped 3,464 9,830 111 199 10,625 1,587 949 8,089 4,359 Total Proved 6,672 18,757 661 1,678 65,818 10,246 2,053 53,518 33,817 Probable Behind Pipe - - - - - - - - - Probable Undeveloped 1,800 5,366 3 8 259 38 41 179 102 Total Probable 1,800 5,366 3 8 259 38 41 179 102 Total 2P 8,472 24,124 664 1,685 66,076 10,284 2,095 53,698 33,919 Possible Behind Pipe - - - - - - - - - Possible Undeveloped 2,100 6,210 3 9 300 44 48 208 117 Total Possible 2,100 6,210 3 9 300 44 48 208 117 Total 3P 10,572 30,334 667 1,694 66,376 10,328 2,143 53,906 34,036 Figure 1-1: Summary of Northcote Reserves Page 5 of 53

The tables in 1-2 and 1-3 are these same net reserves, cash flows, and present worth s separated by their respective Osage and Woods County locations. Reserve Class/Category (Osage County) As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 122 473 29 99 2,920 1,461-1,459 915 Proved Developed Behind Pipe 2,492 6,582 521 1,376 52,178 7,185 1,104 43,889 28,488 Proved Shut In - - - - - - - - - Proved Undeveloped 464 863 105 180 9,976 1,491 845 7,639 4,109 Total Proved 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Probable Behind Pipe - - - - - - - - - Probable Undeveloped - - - - - - - - - Total Probable - - - - - - - - - Total 2P 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Possible Behind Pipe - - - - - - - - - Possible Undeveloped - - - - - - - - - Total Possible - - - - - - - - - Total 3P 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Figure 1-2: Summary of Northcote Reserves for Osage County, Operated by Glenn Supply Reserve Class/Category (Woods County) As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 295 928 0.4 1.2 39 6-33 23 Proved Developed Behind Pipe - - - - - - - - - Proved Shut In 300 944 0.6 1.8 57 8-48 33 Proved Undeveloped 3,000 8,967 6.4 19.1 649 95 104 450 250 Total Proved 3,595 10,839 7.4 22.1 745 109 104 531 305 Probable Behind Pipe - - - - - - - - - Probable Undeveloped 1,800 5,366 2.6 7.7 259 38 41 179 102 Total Probable 1,800 5,366 2.6 7.7 259 38 41 179 102 Total 2P 5,395 16,205 9.9 29.8 1,003 147 145 711 407 Possible Behind Pipe - - - - - - - - - Possible Undeveloped 2,100 6,210 3.0 8.9 300 44 48 208 117 Total Possible 2,100 6,210 3.0 8.9 300 44 48 208 117 Total 3P 7,495 22,416 12.9 38.7 1,303 191 193 919 525 Figure 1-3: Summary of Northcote Reserves for Woods County, Operated mainly by Midstates Northcote is party to a series of standard Joint Operating Agreements ( JOA ) on both the Osage and Woods County leases. These contain certain provisions detailing Northcote s funding commitments and its rights and obligations in respect of the leases. The operator of each of our current and planned wells is detailed in Appendix A. Section 4 of this report contains further analysis of reserves on a project basis. The table in Figure 1-4 shows the sensitivities to the major uncertainties of revenue, capital cost, operating expense, and discount rate. The table shows the impact of a plus or minus 10% change in each of the variables and percentage change in the variable, except for discount rate. The table shows the change in Net Present Value from a 10% discount rate to a 15% and 20% discount rate. Page 6 of 53

Sensitivities (M$), Impact on Net Present Value Variable -10% +10% PDP Reserves (NPV10 = $937) Revenue 754 1,122 Change % -20% 20% Capital 937 937 Change % 0% 0% OPEX 1,025 855 Change % 9% -9% Discount Rate, NPV15 Change % Discount Rate, NPV20 Change % 811-13% 725-23% 1P Reserves (NPV10 = $33,817) Revenue 30,005 37,631 Change % -11% 11% Capital 34,007 33,627 Change % 1% -1% OPEX 34,031 33,605 Change % 1% -1% Discount Rate, NPV15 Change % Discount Rate, NPV20 Change % 28,459-16% 24,544-27% 3P Reserves (NPV10 = $34,036) Revenue 30,169 37,904 Change % -11% 11% Capital 34,240 33,832 Change % 1% -1% OPEX 34,252 33,821 Change % 1% -1% Discount Rate, NPV15 Change % Discount Rate, NPV20 Change % 28,635-16% 24,688-27% Figure 1-4: Northcote NPV10 Sensitivities by Category Page 7 of 53

2 Introduction 2.1 Summary Northcote is an independent oil and gas company based in London and Dallas, that is engaged in the acquisition, exploitation, and development of oil and gas properties located onshore in the United States. Northcote owns acreage and producing assets and intends to participate in developmental wells, principally located in the Mississippian formation, commonly referred to as the Mississippian Lime Resources Play. 2.2 Northcote s Lease Holdings and Producing Assets Northcote owns certain rights to producing assets in Oklahoma. These comprise: Leases in Osage County, Oklahoma, totaling 1,680 gross acres with 10 producing leases. Nine of these producing leases are producing from the Mississippian formation and one lease is producing from the shallower Layton formation. Leases in Woods County, Oklahoma, covering 5,026 gross acres of which approximately 3,800 will be held by production on completion of the contemplated drilling program. On the leases in Woods County, 1 is a producing well, 1 drilled well awaiting completion of pipelines, and a 12 well continuous drilling program currently scheduled for 2013, with further drilling anticipated in 2014. These assets are summarized in the table below and are detailed in Appendix A. SUMMARY TABLE OF ASSETS Operator Interest (%) Osage County, OK Glenn Supply Woods County, OK Midstates, Chesapeake Osage County, OK Glenn Supply Woods County, OK Midstates, Chesapeake Development 27.9% to 29.7% WI with mean NRI 75% of WI 0.02% to 0.50% WI with mean NRI 78% of WI Production 27.9% to 29.7% WI with mean NRI 75% of WI 0.02% to 0.50% WI with mean NRI 78% of WI Lease Expiry Date Total Gross Lease Area (acres) HBP 1,600 < 3 years 5,026 HBP 1,600 HBP 1,239 WI = Working Interest; NRI = Net Revenue Interest; HBP = Held By Production In respect of the Woods County Development Lease interest, the contemplated drilling program will further secure the leases as upon completion and initiation of production operations the leases become HBP. A single well will typically secure up to 320 to 640 acres, thus a single well can hold by production one to three additional drilling locations. Oklahoma Summary: Northcote holds acreage in Osage and Woods County, Oklahoma. Page 8 of 53

Osage County The Osage project consists of 9 horizontal wells, targeting the Mississippian and 1 vertical well targeting the Layton. The current Mississippian wells are all horizontal wells and in total have 21 laterals that expose over 25,000 feet of reservoir rock that has been produced naturally. The 10 producing wells are located in three sub-areas all in close proximity, as detailed in appendix A. These areas also have secondary objectives up hole that have seen significant development in the surrounding areas. From West to East the sub areas are informally named Big Hill, Little Drum, and Mathis. The project is operated by Glenn Supply; however, Northcote intends to become a bonded operator in the State of Oklahoma and Osage County. The Company does not have any fixed obligations over the timing or the order of the fracture stimulation program at Osage County; however the Company s plans are described in section 6. The Company plans to frac its horizontal wells, as set out below, to realize their upper potential as fracture stimulation has been demonstrated, by recent industry activity in the play, to be a critical component of maximizing production and reserve recovery from Mississippian wells. The Mississippian is a compartmentalized reservoir that can demonstrate significant variance in porosity over short intervals; fracture stimulation increases the connectivity of more porous areas within the wellbore. The first fracture stimulation is expected to be at the Mathis area in early 2013. The Mathis is located in section 11 of 25N 5E on the far East end of the play and has two wells, Steele 2-11H and Steinberger 1H-10 that produce from the Mississippian formation. Both of these wells could benefit from fracture stimulation and it is expected that the Steele 2-11H well, will be the first Osage County area to be targeted in the fracture stimulation program. The Little Drum area is located in Sections 16, 17 and 18 of 25N-4E and has four total wells; four producing from the Mississippian formation, Lauren (MS2), Little Drum (MS1), Sarah (MS1) and West Little Drum (MS2). The first project in Little Drum will be to run a salt water disposal line to the Big Hill area in preparation for the first stimulation of a Mississippian lateral. The Sarah (MS1) well has only one lateral and is a good candidate for the Company s second fracture stimulation, following the frac of Steele 2-11H and is expected to be performed in early 2013. The funding for the fracture stimulation of Sarah (MS1) well is dependent on the results of the first fracture stimulation of Steele 2-11H being in line with the expectations set out in this report. Sarah (MS1) is planned as the first stimulation at Little Drum because it has the least complicated wellbore. Following a successful stimulation of the Sarah (MS1) well, there are three other Mississippian wells on the lease with seven unfrac d laterals that will all be frac d in 2013 or early 2014. The Big Hill area is located in section 12 of 25N-3E and has three horizontal wells, Big Hill 1H-12, Big Hill 2H-12 and Big Hill 4H-12 that produce from the Mississippian formation and also contains the vertical oil well Burkhart #3, which produces from the Layton. The Big Hill section is the planned location for the Company s third production enhancement, which will be the fracture stimulation of the Big Hill 1H-12 well, which is intended for May 2013. The ability of the Company to fund the fracture stimulation of this well and each of the six other remaining unfrac d wells, from internally generated cash flow, will be dependent upon the wells performing in line with the expectations set out in this report. The fracture stimulation of the other two Mississippian laterals at Big Hill 2 and 4 is currently expected in 2014. Page 9 of 53

The Burkhart #3 well was drilled to exploit 13 feet of productive Layton sand, which were observed in the mud logs when the Big Hill 4H-12 was drilled. As explained above Big Hill 4H-12 was completed in the Mississippian as originally planned but the Burkhart #3 well was drilled to target the Layton sand. The Burkhart #3 well indicates that there are further development opportunities for additional wells targeting the shallower Layton and Cleveland sands in the southern portions of the Osage leases. Consequently, in addition to the planned fracture stimulation of the Mississippian wells, the company intends to revisit the Layton sand by drilling new vertical wells, Layton #1 and #2 as further described in section 6. In addition to the planned Layton #1, in January 2013,and Layton #2 well in October 2013, Northcote intends to further develop uphole potential, including the Layton sand, on an opportunistic basis both through new drilling and eventually through recompletion of existing well bores. Furthermore, it is expected that because of the favorable production results from these two wells, that the Mathis area will be the first Osage County area for additional Mississippian drilling, which is expected to occur in 2014.. In respect of the 10 producing wells, each has access to one of three production facilities, located within each section. Each locations facility contains at least one salt water disposal well, at least one water separation unit and water and oil tanks along with monitoring equipment. Oil extraction is by contracted vehicles. When the lease ends because the well ceases to be in production, each lease has plug and abandonment obligations ( P&A ), which are required to be met by the WI partners. Northcote and its WI partners have in place plans to ensure that their P&A obligations are met in a responsible manner. The incremental cost of plugging and abandoning each well is not currently expected to be significant. Figure 2-1: Northcote Lease Outline for Osage County Woods County Page 10 of 53

Northcote currently holds an approximate average of 0.35% (35 percent of one percent) working interest, detailed in Appendix A, in the Woods County prospects and has started negotiations for increasing the working interest position further. Northcote intends to participate in each well proposed by the operator. The operators are planning a continuous Woods County drilling program, in which Northcote will participate, and the drilling program currently indicated by the operator, Midstates, includes 12 new wells through 2013 or roughly 1 per month, targeting the Mississippian. As a non-operating working interest partner in the Woods County prospect Northcote has the right to participate in all wells, which are proposed on the lease by the operator, however as non-operator the Company cannot control the timing of the drilling program. Other operators active in the area may from time to time propose wells which include leasehold held by Northcote. The only other operator to have proposed a well at the date of this report, in which the Company plans to participate, is planned for late 2012/early 2013 and has been proposed by Chesapeake as operator. The wells are operated under standard JOA in respect of each producing well. Furthermore the current Woods County lease has 10 additional locations that could be drilled in 2014. The currently drilled and planned wells will take total drilling on the Woods County lease to 25 wells, which is expected to hold an approximate 3,800 to 4,000 gross acres by production assuming that each well is a producing well. In addition to the planned 22 wells currently contemplated in section 6 (planned expenditures), the Woods County lease has the potential for additional locations based on continued successful drilling results. Each well has its own production facility with a water separation unit, water and oil tanks along with monitoring equipment and is tied in to a salt water disposal well for reinjection of produced waste water volumes. Oil extraction is by contracted vehicles. When the lease ends because the well ceases to be in production, each lease has plug and abandonment obligations ( P&A ), which are required to be met by the WI partners. Northcote and its WI partners have in place plans to ensure that their P&A obligations are met in a responsible manner. The incremental cost of plugging and abandoning each well is not currently expected to be significant. Northcote's Woods County leases are situated between and on trend with some of the most productive areas in the Mississippian Play. Chesapeake has developed the area northwest of Northcote. Chesapeake is credited with kicking off the play with the Serenity well that produced over 130 MBO in the first year. Eagle, since purchased by Midstates, has developed to the east-southeast in Alfalfa County and is the operator of the majority of Northcote s Woods County leases. From time to time other operators with leases in the area of Northcote s Woods County leases may propose wells through Oklahoma s forced pooling statutes which encourage development of oil and gas leases. Northcote has in the past and may in the future elect to participate in certain of these wells while in other cases it may sell some acreage for cash and or over-riding royalty interests in such wells. Active operators in the area with whom Northcote has elected to participate with are Chesapeake and Midstates. Their drilling has resulted in many of the best producing wells in the play. Finally, to the northeast Sandridge has made dozens of wells to date and continues to develop the area. Together these companies have pioneered some of the most successful strategies for completing and producing the Mississippian. Geologically this area is situated on the Anadarko Shelf and is part of a vast Mississippian age basin that at last estimate may cover more than 16 million acres in NW Oklahoma and Western Kansas. Page 11 of 53

During the vertical drilling stage of the Mississippian development the rocks had been treated as a thick, almost undifferentiated lime section with weathering at the top that is loosely referred to as the Chat. Many wells only "notched" in the top of the formation and produced until they watered out. Later, more vertical wells drilled the entire section and placed fracs (small by today s standards) on the most favorable intervals as determined by electric and mud logs. Current thinking on Mississippian deposition is focused on repetitive depositional systems primarily laid down in basin ward, prograding wedges. This concept has become critical to understanding oil, water relationships and the key to determining at which interval the "lateral" well bores should penetrate. Much of the oil is probably sourced from the Mississippian but it is the contact to the organic rich Woodford that allows the wells to have such large reserves. In spite of the high organic content these wells will always make water in their production mix, but with the high expected volumes and the tremendous flush production after treatment these are very economical targets and Northcote is in an excellent area for continued development of this expanding play. Figure 2-2: Woods County Map Page 12 of 53

2.3 General Nature of USA Petroleum Rights Unlike in other parts of the world, onshore mineral (including petroleum) rights in the United States are primarily vested in, or derived from, the original landowner rather than the State. Mineral rights can be held separately from ownership of the surface rights. Holders of mineral rights may lease their mineral rights to operators who wish to drill wells or to non-operators who wish to participate in the drilling of wells on the acreage owned by the mineral rights holder. Individual leases are usually much smaller in size than is common elsewhere, and a company s rights holdings in an area will often comprise many small leases rather than fewer, larger, ones. Leases are typically granted for a relatively short period, such as three to five years, unless production is established on the lease. At that point some or all of the leases can continue to be held while production operations continue, the exact area reflecting the permitted drilling density for the particular formation being produced. Osage County, Oklahoma, due to its status as tribal lands of the Osage Nation, differs in certain ways from privately owned onshore leases in the United States. The Osage Mineral Estate is the oil, gas, and other mineral sub-surface of the approximately 1.47 million acre Osage Reservation. The Osage Tribal Allotment Act of 1906 established that the Osage Nation is the beneficial owner the Osage Mineral Estate. The United States holds title to the Osage Mineral Estate in trust for the Osage Nation. No individual or group of individuals owns the Osage Mineral Estate. The Bureau of Indian Affair s (a bureau of the United States Department of Interior) Osage Agency manages the Osage Mineral Estate. Since there is only one Fee Lease mineral owner for the entire county all leasing is from the tribe by auction or negotiated concession similar to other lands managed by the United States federal government. This process reduces title work and risk; however lessor title chain is still the same process as privately owned mineral leases. The terms of the concession agreements are typically negotiated directly with the Osage Nation and these concessions usually cover large lease areas. The lease auctions are under standard terms, whereby the successful bidder in the mineral lease auction has a period of 18 months to develop the acreage. The drilling of wells, and the rates at which they can be produced, are controlled by the relevant regulatory body; in Oklahoma it is the Oklahoma Corporation Commission ( OCC ). These regulatory bodies are charged with ensuring the orderly and optimum development of reservoirs and, as such, establish field rules which define the maximum drilling density allowed in an area and compliance with all environmental regulations. The net impact of this ownership and regulatory environment is that acquiring and maintaining leases in good order may take considerably more effort than that usually required in other countries. The Northcote leases are generally small lease tracts that will be combined with other leases to form a drilling unit. The drilling unit can be formed voluntarily or compulsorily by state commission ruling such as the OCC. Through either arrangement, the leaseholder has the option to join in the drilling of the well, farm out the lease to a third party to support the drilling of the well, or sell its interest in the lease. If the leaseholder elects to join, an operator is selected and a JOA, a standardized contract based on model forms that carry standard amendments that address issues common to the oil and gas industry, between co-tenants or separate owners of oil and gas properties being jointly operated, is executed. A JOA sets out terms and agreements between the owners for operation of a lease. One of the parties to the JOA is designated operator for the joint account. The JOA sets out the provisions for decision making and accounting procedures, among other things, key provisions of a JOA often include: Page 13 of 53

identification of leases and lands associated with a well; identification of the property interests of the parties in a well; commitment of the parties to participate in operations on the lease; procedure for dealing with disagreements among the parties about operations to be conducted; duties of the operator, including operations, accounting, insurance and other activities;. sharing of expenses for and the allocation of liability with respect to joint operations; and, remedies for a party s failure to pay its share of expenses; and, rights of the parties in production from well. There are no obligations to drill a well on any of the leases except to extend the lease beyond its primary term. Leases have a primary term in which the lease will expire if production is not established. Drilling operations will need to commence on, or prior to, the lease expiration date in order to perpetuate the lease. As long as there is continuous activity on the lease of a drilling or production nature, the lease will continue. The lease will terminate on the later of the primary term expiry date or the end of production from the well(s) in the spacing unit containing the lease. Should Northcote acquire new leases, the terms may provide for a cash payment to the owner of the mineral interest called a lease bonus. The primary term of the lease is negotiable, but usually is 3 to 5 years. In that time Northcote would need to drill a well and establish production to perpetuate the lease. Page 14 of 53

3 Mississippian Lime Horizontal Play 3.1 Current Activity The Mississippian Lime Horizontal Drilling Play is a re-activation of the development of the Mississippian Lime formation in northern Oklahoma and southern Kansas. The Mississippian oil and gas bearing system is a proven commercial trend producing from several thousand vertical wells for more than 50 years. The play area includes multiple counties of the Northwest Shelf of the Anadarko Basin and the Nemaha Uplift in North Central Oklahoma and Southern Kansas. The core of the play involves drilling horizontal laterals in existing vertical wells or new horizontal wells in the vicinity of historical Mississippian producers or dry holes. These liquid-rich zones were once thought to have been extinguished by vertical, conventional drilling many years ago. Now, with the technological advancements made with horizontal drilling and fracing, operators are able to unlock vast amounts of hydrocarbons. Active companies in the play include Chesapeake, SandRidge, Range Resources Corporation ( Range Resources ), EOG Resources, Inc, Midstates, and Red Fork Energy Ltd ( Red Fork Energy ). There are currently approximately 40-50 rigs actively drilling in the play. Since the beginning of 2009, there have been over 600 horizontal wells drilled in the play and approximately 56 wells have a meaningful production history that can be used to estimate their ultimate recovery. A map of the historical Mississippian production and a listing of the operators and their focus area are shown in Figure 3-1. Range Resources, Red Fork Energy, and SandRidge are the larger active companies in the area of the Northcote area of interest. Figure 3-1: Mississippi Lime Historical Wells and Companies Focus Areas. (Courtesy of Oil and Gas Journal) 3.2 Petroleum Geology The Mississippian Oil trend is an expansive carbonate stratigraphic trap producing at shallow depths ranging from 4,500 to 7,000 feet below the surface. The reservoirs lie at the regional Pennsylvanian/Mississippian unconformity, as a result of uplift, alteration and erosion of shallow marine Mississippian carbonates. A graphic of the target Mississippian formation is shown in Figure 3-2. Page 15 of 53

The uppermost Mississippian member is a widespread debris-flow deposit formed through a combination of uplift and erosion of the Mississippian Limestone, consisting of varying amounts of weathered chert, limestone and dolomite called the Mississippi Chat. The Mississippian Lime underlies the chat and also exhibits good reservoir characteristics. The formation was subject to weathering and digenesis and erosion at the regional unconformity. This results in greatly varying reservoir properties both horizontally and vertically. Where the digenesis and weathering have enhanced the reservoir properties, the porosity is generally 15 to 20% and can be more than 100 feet thick. Where it has not been enhanced, the porosity is only 4-6% and has low permeability. This results in laterally discontinuous reservoirs that are ideally developed with horizontal drilling technology. The formation s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. The horizontal wells drilled in the play have lateral lengths of between 2,500 ft and 5,000 ft and are fracture stimulated in 6-12 stages. The fracture stimulation treatments are not as large as those in the Bakken play or the other unconventional resource play such as the Eagle Ford. Because of the shallow depths and smaller fracture stimulation treatments the typical completed well cost ranges from $2.4-$4.0 million. Current drilling times are approximately 17-28 days from spud to rig release. Figure 3-2: Mississippian Lime Horizontal Play Concept Cross Section 3.3 Reservoir Analysis The active operators in the play have published significant information on their results and expectation on the performance of wells in the play. This information corroborates that the Mississippian Lime Horizontal Play is a region that is appropriate for development. Furthermore the Page 16 of 53

data collected from these operators can be used to further understand the characteristics, performance and behavior of wells that are drilled in the play. SandRidge currently has over 2 million acres under lease and the company has completed over 300 wells in the play, as of December 2011. They estimate they have about 8,000 potential drilling locations. SandRidge s published type curve for well performance is 456 MBOE with expected well recoveries ranging from 300 to 500 MBOE at an average drill and complete cost of $3.2 million including allocated salt water disposal well costs. SandRidge plans to operate an average of 29 rigs in the Mississippian play in 2012, and drill 380 wells during the year. Of the 29 rigs, 5 of them are dedicated to drilling salt water disposal wells, emphasizing the heavy water production from the Mississippian that drives operating costs. Chesapeake has approximately 1.8 million net acres under lease and has drilled approximately 50 wells in the trend. Chesapeake is currently producing 11,300 BOEPD from the Mississippian oil play and estimates that its production mix is composed of 40% crude oil, 15% natural gas liquids, and 45% natural gas. Chesapeake s published type curve is 360 MBOE with a cost to drill and complete wells of $2.8 million, including salt water disposal facilities. Chesapeake is currently operating 22 rigs in this play. Range Resources has published a type curve based on seven wells that have been completed and the average estimated ultimate recovery (EUR) is 485 MBOE. The type curve is for a 2,200 ft horizontal lateral well completed with a 12 stage fracture treatment. They indicate this equates to 4-9% of the original oil in place. Range Resources has 125,000 net acres prospective for the Mississippian oil play and plans to operate as many as three rigs here in 2012. Figure 3-3 shows a typical log section for the Mississippian Lime. The tops of the productive formations are highlighted including the Mississippi Lime, Chat, Woodford, and Arbuckle. Figure 3-3: Mississippian Type Log Gamma measures the radioactivity of rock and is most often used to quantitatively derive clay, or shale, volumes. Gamma ray will decrease in the presence of carbonates because of the general lack of shales. The decrease in gamma over these formations is a result of the carbonates in the Mississippian along with the harder dense limestone. Most rock materials are insulators, while their enclosed fluids have conductive properties and for water saturation is tied to salinity (resistivity increases with more saline water). Hydrocarbons are infinitely resistive. The low resistivity in these formations is an indicator of good porosity and high water saturation, emphasizing the need for water disposal facilities. Page 17 of 53

The main pay in the Mississippi Lime is the Chat portion of the Mississippi Lime formation. The Chat has very high porosity (>30%), but contains high water saturations and most wells produce significant water with the oil. Moyes has analyzed the performance of 56 Mississippian Lime horizontal wells that were completed between 2007 and 2011. The wells had 30 day average initial rates ranging from 60 to 750 BOPD. The average estimated oil recovery was 366 MBO from this sampling of wells. This is shown below in Figure 3-5. A type curve based on the analysis is shown in Figure 3-6. Figure 3-4: Mississippian Lime Ultimate Recovery Reserve Distribution Page 18 of 53

Figure 3-5: Mississippian Lime Type Curve Hydraulic fracturing is the primary choice for enhancing production in a majority of low-permeability reservoirs and is often required for a well to produce at economical rates. The combined effects of intersecting natural and hydraulically fracturing the reservoir is largely responsible for improved productivity from horizontal wells as compared with production from vertical wells. Horizontal wells increase reservoir contact area and decrease pressure drawdown. The effectiveness of hydraulic fractures depends mainly on the fracture length and on the fracture conductivity. A hydraulic fracture completion will allow the wellbore to reach further into the formation matrix, increasing the amount of contact with high quality reservoir rock, and typically has the effect of increasing productivity 2 to 30 times compared to an untreated well. In low-permeability reservoirs this results in immediately higher flow rates and higher ultimate recoveries. Generally, the oil and water production rates will increase proportionately. Gas production rates will also increase, but to a lesser extent because the increased mobility of the reservoir fluids. While the typical Mississippi Lime horizontal well will produce without the benefit of a multi-stage hydraulic fracture stimulation, production of fluids will typically increase 10 times the pre-treatment rates. We expect that a successful hydraulic fracture stimulation will allow these wells to produce at rates of or in excess to 300 bopd while maintaining a water cut of 75-95%, especially during flow back of the fracturing fluid. Page 19 of 53

4 Reserves Estimates of oil and natural gas reserves owned by Northcote are shown in the table below. The Proved Developed Producing (PDP) Reserves are from the wells that are producing as of the effective date of this report. The Proved Developed Non-Producing (PDNP) Reserves include shut-in and behind-pipe reserves. The Proven Undeveloped (PUD) Reserves are from undeveloped well locations that are directly offsetting commercial producing wells. The Probable Reserves are from undeveloped well locations that are offsetting PUD well locations and the Possible Reserves are from undeveloped well locations that directly offset a Probable location, given there is justification for the reservoir to extend to the location. The properties evaluated are all those in which Northcote holds an interest in Oklahoma. The producing properties (shown in Appendix A) have been evaluated using decline curve analysis and any plans for enhanced production were accounted for with incremental reserves. The undeveloped leasehold has been evaluated based on analogy with offset production. The offset production was evaluated using decline curve analysis. The cost and timing assumptions for enhanced production and undeveloped wells are shown in Section 7. The table in 4-1 is the summary of appendix C, which shows as of 1 November, 2012, Northcote s net reserves, future net cash flow, and present worth discounted at 10% per annum (NPV) have been estimated to be as follows. Reserve Class/Category As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 417 1,401 29 100 2,958 1,466-1,492 937 Proved Developed Behind Pipe 2,492 6,582 521 1,376 52,178 7,185 1,104 43,889 28,488 Proved Shut In 300 944 1 2 57 8-48 33 Proved Undeveloped 3,464 9,830 111 199 10,625 1,587 949 8,089 4,359 Total Proved 6,672 18,757 661 1,678 65,818 10,246 2,053 53,518 33,817 Probable Behind Pipe - - - - - - - - - Probable Undeveloped 1,800 5,366 3 8 259 38 41 179 102 Total Probable 1,800 5,366 3 8 259 38 41 179 102 Total 2P 8,472 24,124 664 1,685 66,076 10,284 2,095 53,698 33,919 Possible Behind Pipe - - - - - - - - - Possible Undeveloped 2,100 6,210 3 9 300 44 48 208 117 Total Possible 2,100 6,210 3 9 300 44 48 208 117 Total 3P 10,572 30,334 667 1,694 66,376 10,328 2,143 53,906 34,036 Figure 4-1: Summary of Northcote Reserves The tables in 4-2 and 4-3 are these same net reserves, cash flows, and present worth s separated by their respective Osage and Woods County locations. Page 20 of 53

Reserve Class/Category (Osage County) As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 122 473 29 99 2,920 1,461-1,459 915 Proved Developed Behind Pipe 2,492 6,582 521 1,376 52,178 7,185 1,104 43,889 28,488 Proved Shut In - - - - - - - - - Proved Undeveloped 464 863 105 180 9,976 1,491 845 7,639 4,109 Total Proved 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Probable Behind Pipe - - - - - - - - - Probable Undeveloped - - - - - - - - - Total Probable - - - - - - - - - Total 2P 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Possible Behind Pipe - - - - - - - - - Possible Undeveloped - - - - - - - - - Total Possible - - - - - - - - - Total 3P 3,077 7,918 654 1,655 65,073 10,137 1,949 52,987 33,512 Figure 4-2: Summary of Northcote Reserves for Osage County, Operated by Glenn Supply Reserve Class/Category (Woods County) As of November 1, 2012 Gross Reserves Net Reserves Net Cash Flow Oil & Condensate (Mbbl) Natural Gas (MMcf) Oil & Condensate (Mbbl) Natural Gas (MMcf) Future Net Revenue ($000) Future Net OPEX & Taxes ($000) Future Net Capital ($000) Future Net Cash Flow ($000) NPV Disc @ 10% ($000) Proved Developed Producing 295 928 0.4 1.2 39 6-33 23 Proved Developed Behind Pipe - - - - - - - - - Proved Shut In 300 944 0.6 1.8 57 8-48 33 Proved Undeveloped 3,000 8,967 6.4 19.1 649 95 104 450 250 Total Proved 3,595 10,839 7.4 22.1 745 109 104 531 305 Probable Behind Pipe - - - - - - - - - Probable Undeveloped 1,800 5,366 2.6 7.7 259 38 41 179 102 Total Probable 1,800 5,366 2.6 7.7 259 38 41 179 102 Total 2P 5,395 16,205 9.9 29.8 1,003 147 145 711 407 Possible Behind Pipe - - - - - - - - - Possible Undeveloped 2,100 6,210 3.0 8.9 300 44 48 208 117 Total Possible 2,100 6,210 3.0 8.9 300 44 48 208 117 Total 3P 7,495 22,416 12.9 38.7 1,303 191 193 919 525 Figure 4-3: Summary of Northcote Reserves for Woods County, Operated mainly by Midstates. The future net revenue is based on the 1 November 2012 NYMEX futures strip prices for WTI Oil and Henry Hub Gas. The future net cash flow is the future net revenue, less estimated future net OPEX (well operating cost and production taxes) and future net capital. The total reserves are those defined as natural gas and liquid hydrocarbon reserves to Northcote s interest after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to the guidelines adopted by the Society of Petroleum Engineers. Page 21 of 53

5 Oil and Gas Prices The production and undeveloped leases have readily available access to both the oil and gas markets. Production from the existing leases is gathered from the well head to a central processing facility on the lease where the gas is sold into a transportation network and the oil is either sold into a pipeline and transported to a refinery or is trucked from the lease to a pipeline terminal where it is then transported to a refinery. The benchmark for pricing products in the United States is West Texas Intermediate Crude and Henry Hub Natural Gas. The prices in this report are based on the futures strip for these two benchmark products. The oil and gas prices beyond the end of the strip are held constant at the end of NYMEX Strip prices. West Texas Intermediate (WTI) FOB Cushing, Oklahoma, forms the physical basis for futures trading (NYMEX Sweet, Light Crude). Future Crude Oil prices are based on NYMEX Light Sweet Crude plus or minus a differential for gravity adjustment and transportation. Figure 5-1 shows the historical prices and forward curve for NYMEX Sweet Light contracts as of 1 November 2012. Figure 5-2 shows the historical Henry Hub and futures strip prices as of 1 November 2012. Natural Gas prices are based on NYMEX HH Natural gas plus or minus an adjustment for BTU content and transportation. NYMEX has futures SWAPS markets that provide future basis differentials for the various regions in the United States as compared to Henry Hub Pricing. The differentials from the NYMEX Futures Swaps Market are used to regionally adjust the Henry Hub Futures gas prices to the local market. Figure 5-1: Historical and 1 November 2012 NYMEX Futures Contract Crude Oil Prices Page 22 of 53

Figure 5-2: Historical and 1 November 2012 NYMEX Futures Contract US Domestic Gas Prices Figure 5-3 shows the ANR to Henry Hub swap differential. ANR is one of the major trading reference points in Texas. The NYMEX ANR to Henry Hub Basis Swap Differential is used to estimate the relative price of Texas natural gas verses Henry Hub Market. This basis differential trades out through March 2016. The basis differential is expected to increase from a negative $0.13/MMbtu average in 2013 to a negative $0.1650/MMbtu by 2016. The forecast gas price for Oklahoma used the Henry Hub NYMEX Strip less the ANR to Henry Hub Basis differential to arrive at the wellhead gas price. Page 23 of 53

Figure 5-3: NYMEX 1 November 2012 ANR-Henry Hub Basis Swap Differential The western region of the Mississippian Lime is an oil play with a little bit of casing head gas. The close proximity to Cushing Oklahoma, home of the storage facility upon which NYMEX oil is priced, indicates that there will be a very small transportation price differential for the oil produced from this play. Page 24 of 53

6 Planned Expenditures Northcote s initial focus in Osage County will be on the fracture stimulation program of the producing leases and also the drilling of two new Layton Wells. In Woods County, Northcote expects to participate in 12 wells in 2013, which is in line with operators current drilling program in Woods County. On admission, Northcote expects to have sufficient funds to allow for the following: - In Osage County, Northcote intends to initiate the fracture stimulation program in early 2013. At Admission Northcote will be able to finance the first four well fracture stimulations of the Osage frac program, being Steele 2-11H, Sarah (MS1), Big Hill 1H-12 and Lauren (MS2), without the need for every frac to be fully in line with directors expectations. Based on the $440,000 per frac cost (to 100% WI), Northcote's initial share of capital expenditure for its working interest for the first four wells is expected to be $492,000, which, alongside the group satisfying the farm-in obligations, increases the capital cost of the first four fracs to a total of $1.3 million. - In Osage, Northcote also intends to further develop the Layton sand acreage through the drilling of two new wells in 2013, being Layton #1 and Layton #2. Based on the $250,000 per well drilling cost (to 100% WI), Northcote s initial share of capital expenditure for the drilling of the two wells will be approximately $74,250 per well and hence a total working interest cost of $148,500 (to Northcote s WI). - In Woods County it intends to participate in each well as proposed by the operator. The perwell costs associated with the Woods County leases will range from approximately $11,000 per well to $19,000 per well based on the $3,800,000 cost (to 100% WI) of a new well and the working interests set out above. Therefore, Northcote has allocated a total of $228,000 towards this. - Furthermore the additional capital will allow the Enlarged Group to be able to fully finance, at the Directors election, the exercise of the royalty option at a cost of $285,000 for an average 2.2% royalty interest in the Osage wells. The following table discloses certain assumptions on the current expected Spud/Frac dates for the work program. While not the operator, Northcote retains a high degree of flexibility in respect of managing the timing of the planned new well/ frac programs in Osage County. The ability of the Company to fund, from internally generated cash flow, the fracture stimulation and drilling program at Osage County and the drilling program at Woods County will be dependent upon the wells performing in line with expectations set out in this report. Page 25 of 53

Lease/Well County Township Range Section WI NRI Spud/Frac Net Acres Behind Pipe Steele 2-11H Osage 25N 05E 11 27.875% 20.906% 01-07-2013 44.60 Sarah (MS1) Osage 25N 04E 17 27.875% 20.906% 01-21-2013 44.60 Big Hill 1H-12 Osage 25N 03E 12 27.879% 20.906% 05-01-2013 44.61 Lauren (MS2) Osage 25N 04E 18 29.938% 22.453% 05-01-2013 47.90 Steinberger 1H-10 Osage 25N 05E 10 27.875% 20.906% 09-01-2013 44.60 West Little Drum (MS2) Osage 25N 04E 17 29.938% 22.453% 09-01-2013 47.90 Big Hill 2H-12 Osage 25N 03E 12 27.879% 20.906% 03-01-2014 44.61 Big Hill 4H-12 Osage 25N 03E 12 27.879% 20.906% 03-01-2014 44.61 Little Drum (MS1) Osage 25N 04E 16 27.875% 20.906% 03-01-2014 44.60 Undeveloped NORTHCOTE CAPITAL SCHEDULE Layton 1 Osage 25N 03E 12 29.938% 21.915% 01-15-2013 47.9 Layton 2 Osage 25N 04E 17 29.938% 21.915% 10-15-2013 47.9 Braden School 1 Osage 25N 05E 11 27.875% 20.906% 07-15-2014 44.6 CHK Well Woods 26N 14W 6 0.240% 0.187% 11-15-2012 0.38 Mississippian 01 Woods 26N 15W 12 0.375% 0.293% 01-15-2013 0.60 Mississippian 02 Woods 26N 14W 13 0.239% 0.186% 02-15-2013 0.38 Mississippian 03 Woods 27N 15W 28 0.500% 0.390% 03-15-2013 0.80 Mississippian 04 Woods 26N 14W 7 0.452% 0.352% 04-15-2013 0.72 Mississippian 05 Woods 26N 15W 33 0.240% 0.187% 05-15-2013 0.38 Mississippian 06 Woods 26N 15W 32 0.162% 0.126% 06-15-2013 0.26 Mississippian 07 Woods 27N 15W 34 0.063% 0.049% 07-15-2013 0.10 Mississippian 08 Woods 26N 15W 23 0.070% 0.055% 08-15-2013 0.11 Mississippian 09 Woods 26N 15W 13 0.438% 0.341% 09-15-2013 0.70 Mississippian 10 Woods 26N 14W 6 0.063% 0.049% 10-15-2013 0.10 Mississippian 11 Woods 26N 15W 12 0.375% 0.293% 11-15-2013 0.60 Mississippian 12 Woods 26N 15W 13 0.438% 0.341% 12-15-2013 0.70 Mississippian 13 Woods 26N 14W 5 0.101% 0.079% 01-15-2014 0.16 Mississippian 14 Woods 26N 14W 19 0.241% 0.188% 02-15-2014 0.39 Mississippian 15 Woods 26N 15W 24 0.188% 0.146% 03-15-2014 0.30 Mississippian 16 Woods 26N 15W 34 0.050% 0.039% 04-15-2014 0.08 Mississippian 17 Woods 26N 15W 35 0.113% 0.088% 05-15-2014 0.18 Mississippian 18 Woods 26N 15W 26 0.018% 0.014% 06-15-2014 0.03 Mississippian 19 Woods 26N 15W 27 0.076% 0.059% 07-15-2014 0.12 Mississippian 20 Woods 26N 15W 31 0.063% 0.049% 08-15-2014 0.10 Mississippian 21 Woods 26N 15W 7 0.136% 0.106% 09-15-2014 0.22 Mississippian 22 Woods 26N 14W 7 0.452% 0.352% 10-15-2014 0.72 Figure 6-1: Northcote Future Development with Assumed Capital and Well Timing dates are in US format. The behind pipe reserves in Osage County require a fracture treatment that is expected to cost $440,000 per well. The Layton wells in Osage County are expected to cost $250,000 per well, the Mississippian well in Osage County is expected to cost $2,500,000, and the Mississippian wells in Woods County are expected to cost $3,800,000 per well. Northcote intends to initiate the fracture stimulation program with stimulation of two producing wells in late 2012. Based on the $440,000 per well cost (to 100% WI), Northcote s initial share of capital expenditure for fracture stimulation of its initial two wells will be approximately $123,000 per well. Page 26 of 53

Northcote also intends to further develop the Layton sand, in Osage, through the drilling of two new wells in 2013 being Layton #1 and Layton #2. Based on the $250,000 per well drilling cost (to 100% WI), Northcote s initial share of capital expenditure for the drilling of the two wells will be approximately $74,250 per well and hence a total working interest cost of $148,500 (to Northcote s WI). In Woods County, Northcote intends to participate in each well as proposed by the operator. The perwell costs associated with the Woods County leases will range from approximately $11,000 per well to $19,000 per well based on the $3,800,000 cost of a new well and the working interests set out herein. The total future production forecast, in Figure 6-2, demonstrates the forecast of the existing production and adding the forecast fracture and drilling activity. The forecast shows the result of drilling the Proved, Probable, and Possible well locations all un-risked. Production increases from the current net of 18 BOPD to 351 BOPD in early 2014, based on a successful fracture stimulation program at the current producing locations in Osage County, and the production increases to 360 BOPD in early 2014 by addition of the Woods Field well locations. 10 100 Gas (Mcf/day) Oil (bbl/day) 100 10 10 12 14 16 18 20 22 24 26 28 30 32 34 Figure 6-2: Forward Plan Production Forecast (Net) Page 27 of 53

7 Conclusions Northcote has a well-positioned portfolio of producing properties in one of the most active oil plays in North America. The producing properties and behind-pipe reserves at both Osage and Woods County are reported with a total P1 PV10 of $33,817,000. These reserves are expected to provide a steady cash flow over a long life to support further development and expansion of working and revenue interests. The Fracture stimulation of the Mississippian Lime wells in Oklahoma is expected to yield wells that have high initial oil production rates allowing for a relatively significant early cash flow from newly fracced wells and a quick payout cycle. When combined with the cash flow from existing production, this provides the funds necessary, at the current NYMEX strip pricing, for the Company s plans to fracture stimulate 9 horizontal wells and to participate in the drilling of up to a further 26 wells. In closing the Company s Oklahoma leasehold position has the potential for significant upside to what is included in this report through expansion and continuation of the drilling program as well as through the Osage County options and through Northcote s plans to increase its ownership percentage in Woods County. Page 28 of 53

8 Disclosures 8.1 Data This report is based on data and materials provided by Northcote, and by public domain research carried out by the authors. The information provided by Northcote consisted of background information, a copy of their business plan, lease schedules, copies of leases, mineral ownership schedules, revenue statements by property, Joint Interest Billing statements, AFE s, well logs, and Lease Maps. We have examined Northcote s information and interviewed Northcote s management. We have carried out appropriate due diligence and have critically examined the data provided, but cannot vouch for its accuracy and completeness. Northcote has provided us with an indemnity compensating us for any liability arising from our use of information provided by Northcote which is materially inaccurate or incomplete. Further, Northcote has advised us that all of the data provided to us is either in the public domain or is proprietary to Northcote, and that Northcote has approved the disclosure of proprietary data in the preparation of this report. Moyes has not carried out a site visit to any of the properties, nor was it deemed necessary to prepare the evaluation herein of such properties. Sufficient data is available from public sources and Northcote s files to evaluate the producing properties and the undeveloped leasehold is undeveloped surface lands with nothing to see on the surface. Where Moyes considered it necessary, information provided was supplemented by information to be found in the public domain, by contact with service companies conducting operations in these plays, and from internal sources. Public domain information consisted largely of publications concerning the exploitation of shale gas reservoirs and State records including production statistics, well records, and geological data. 8.2 Qualifications of Moyes & Co. Moyes is an independent consulting firm based in Dallas and Houston, Texas, and London. The firm provides evaluation and other professional advisory services in the energy sector. These services have been provided to Northcote for a fee based solely on professional time billed to the project, and reimbursement of travel and other incidental expenses. No part of the firm s remuneration is based on Northcote being successful in raising funds or on any valuation of Northcote or its assets. Moyes is independent of Northcote, its directors and proposed directors, senior management and advisors. Neither the firm nor any of its employees has any direct or indirect interest in Northcote or its assets. The principal author of this report is P. Dee Patterson, with contributions from David Hyvl (Engineer). Dee Patterson is a Managing Director of Moyes & Co. He has twenty-seven years of industry experience with ARCO, Vastar, and Moyes & Co. He holds a BS degree in Mechanical Engineering from the University of Texas at Arlington and an MBA in Corporate Finance from the University of Dallas. Dee is a member of the SPE, the Society of Petroleum Evaluation Engineers (SPEE), the American Society of Mechanical Engineers (ASME), and AIPN, and is registered Professional Engineer in the State of Texas. Page 29 of 53

David Hyvl is a Petroleum Engineer at Moyes & Co. He has three years of industry experience with Moyes & Co. He holds a BS degree in Electrical and Computer Engineering from Baylor University and is working towards a M.Eng degree in Petroleum Engineering from Texas A&M University. David is a member of the Society of Petroleum Engineers (SPE) and the National Society of Professional Engineers (NSPE), and is a registered Engineer in Training (EIT) in the State of Texas. 8.3 Basis of Report In compiling this report we have used the definitions and guidelines set out in the SPE Petroleum Resources Management System 2007. There are numerous uncertainties inherent in estimating hydrocarbon resource potential, and in projecting expenditures and the results of investment activity. Oil and gas resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured with precision. Estimates of oil and gas resource potential prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any resource assessment is a function of the quality of the available data and of engineering and geological interpretation. The results of drilling, testing, and production that post-date the preparation of the estimates may justify revisions, some or all of these revisions may be material. Accordingly, resource estimates are often different from the quantities of oil and gas that may ultimately be recovered (if any), and the timing and cost of those volumes that are recovered may vary from those assumed. This report has been prepared in accordance with the AIM Rules, and specifically the AIM Rules for Mining and Oil & Gas Companies, June 2009. This assessment has been conducted within the context of Moyes understanding of Northcote s petroleum property rights as represented by Northcote s management, and is based on data provided by Northcote and discussions with representatives of the Company. It was not considered necessary to visit the Company s assets because Moyes is very familiar with the region. While certain key contractual documents have been reviewed for understanding the nature of certain business arrangements, Moyes has not reviewed them from a legal perspective. Moyes is not in a position to attest to property title, financial interest relationships, or encumbrances thereon, for any part of the appraised properties or interests. We confirm that this report has been subject to internal review by Moyes. We have reviewed the information elsewhere in the admission document (relating to the information contained in this report) and confirm that it is accurate, balanced, complete, and consistent with this report. 8.4 Responsibility For the purposes of Rule 11 of the AIM Rules, we are responsible for this report as part of the Admission Document and declare that we have taken all reasonable care to ensure that the information contained in this report is, to the best of our knowledge, in accordance with the facts and contains no omissions likely to affect its import. Yours Sincerely, Page 30 of 53

Appendix A Northcote Assets Northcote Assets Producing Properties Asset Operator Interest Status Exp. Date Lease/Well State County Field WI NRI ORRI Net Acres Big Hill 1H-12 OK Osage Big Hill Glenn Supply 27.8785% 20.90625% - HBP End of Prod. 44.6 Big Hill 2H-12 OK Osage Big Hill Glenn Supply 27.8785% 20.90625% - HBP End of Prod. 44.6 Big Hill 4H-12 OK Osage Big Hill Glenn Supply 27.8785% 20.90625% - HBP End of Prod. 44.6 Lauren (MS2) OK Osage Little Drum Glenn Supply 29.9375% 22.453125% - HBP End of Prod. 47.9 Little Drum (MS1) OK Osage Little Drum Glenn Supply 27.8750% 20.90625% - HBP End of Prod. 44.6 Sarah (MS1) OK Osage Little Drum Glenn Supply 27.8750% 20.90625% - HBP End of Prod. 44.6 Steele 2-11H OK Osage Mathis Glenn Supply 27.8750% 20.90625% - HBP End of Prod. 44.6 Steinberger 1H-10 OK Osage Mathis Glenn Supply 27.8750% 20.90625% - HBP End of Prod. 44.6 West Little Drum (MS2) OK Osage Little Drum Glenn Supply 29.9375% 22.453125% - HBP End of Prod. 47.9 Burkhart 3 OK Osage Little Drum Glenn Supply 29.9375% 21.91500% 1.8450% HBP End of Prod. 47.9 Bouziden* OK Woods n/a Midstates 0.2387% 0.1862% - HBP End of Prod. 0.38 Busse 1H-3 OK Woods n/a Midstates 0.1650% 0.1287% - HBP End of Prod. 0.26 *Bouziden (MS01) has been drilled, completed, tested, and is awaiting a nearly completed pipeline. Northcote Assets Under Option Asset Operator Interest Status Exp. Date Lease/Well State County WI NRI ORRI Net Acres Big Hill 1H-12 OK Osage Big Hill Glenn Supply 17.8750% 13.4046% 2.2275% HBP End of Prod. 28.6 Big Hill 2H-12 OK Osage Big Hill Glenn Supply 17.8750% 13.4046% 2.2275% HBP End of Prod. 28.6 Big Hill 4H-12 OK Osage Big Hill Glenn Supply 17.8750% 13.4046% 2.2275% HBP End of Prod. 28.6 Lauren (MS2) OK Osage Little Drum Glenn Supply 19.9375% 14.9531% 2.1030% HBP End of Prod. 31.9 Little Drum (MS1) OK Osage Little Drum Glenn Supply 17.8750% 13.4063% 2.2275% HBP End of Prod. 28.6 Sarah (MS1) OK Osage Little Drum Glenn Supply 17.8750% 13.4063% 2.2275% HBP End of Prod. 28.6 Steele 2-11H OK Osage Mathis Glenn Supply 17.8750% 13.4063% 2.2275% HBP End of Prod. 28.6 Steinberger 1H-10 OK Osage Mathis Glenn Supply 17.8750% 13.4063% 2.2275% HBP End of Prod. 28.6 West Little Drum (MS2) OK Osage Little Drum Glenn Supply 19.9375% 14.9531% 2.1030% HBP End of Prod. 31.9 Page 31 of 53

Northcote Assets Undeveloped Leases Asset Operator Interest Status Lease/Well County Township Range Section WI NRI Net Acres Layton 1 Osage 25N 03E 12 Glenn Supply 29.937500% 21.915000% Prospect 47.9 Layton 2 Osage 25N 04E 17 Glenn Supply 29.937500% 21.915000% Prospect 47.9 Braden School 1 Osage 25N 05E 11 Glenn Supply 27.875000% 20.906250% Prospect 44.6 CHK Well Woods 26N 14W 6 Chesapeake 0.240000% 0.187200% Prospect 0.38 Mississippian 01 Woods 26N 15W 12 Midstates 0.375000% 0.292500% Prospect 0.60 Mississippian 02 Woods 26N 14W 13 Midstates 0.238656% 0.186152% Prospect 0.38 Mississippian 03 Woods 27N 15W 28 Midstates 0.500000% 0.390000% Prospect 0.80 Mississippian 04 Woods 26N 14W 7 Midstates 0.451820% 0.352420% Prospect 0.72 Mississippian 05 Woods 26N 15W 33 Midstates 0.240000% 0.187200% Prospect 0.38 Mississippian 06 Woods 26N 15W 32 Midstates 0.161875% 0.126263% Prospect 0.26 Mississippian 07 Woods 27N 15W 34 Midstates 0.062500% 0.048750% Prospect 0.10 Mississippian 08 Woods 26N 15W 23 Midstates 0.070313% 0.054844% Prospect 0.11 Mississippian 09 Woods 26N 15W 13 Midstates 0.437500% 0.341250% Prospect 0.70 Mississippian 10 Woods 26N 14W 6 Midstates 0.062500% 0.048750% Prospect 0.10 Mississippian 11 Woods 26N 15W 12 Midstates 0.375000% 0.292500% Prospect 0.60 Mississippian 12 Woods 26N 15W 13 Midstates 0.437500% 0.341250% Prospect 0.70 Mississippian 13 Woods 26N 14W 5 Midstates 0.100818% 0.078638% Prospect 0.16 Mississippian 14 Woods 26N 14W 19 Midstates 0.240719% 0.187761% Prospect 0.39 Mississippian 15 Woods 26N 15W 24 Midstates 0.187500% 0.146250% Prospect 0.30 Mississippian 16 Woods 26N 15W 34 Midstates 0.049904% 0.038925% Prospect 0.08 Mississippian 17 Woods 26N 15W 35 Midstates 0.112890% 0.088054% Prospect 0.18 Mississippian 18 Woods 26N 15W 26 Midstates 0.018431% 0.014376% Prospect 0.03 Mississippian 19 Woods 26N 15W 27 Midstates 0.075680% 0.059030% Prospect 0.12 Mississippian 20 Woods 26N 15W 31 Midstates 0.062500% 0.048750% Prospect 0.10 Mississippian 21 Woods 26N 15W 7 Midstates 0.135623% 0.105786% Prospect 0.22 Mississippian 22 Woods 26N 14W 7 Midstates 0.451820% 0.352420% Prospect 0.72 Page 32 of 53

Appendix B Northcote Oil Reserves Summary of Reserves by Asset All Figures in Mbbl Gross Net Attributable Asset Proved 2P 3P Proved 2P 3P BIG HILL 1H-12 0.36 0.08 BIG HILL 2H-12,4H-12 6.64 1.39 BURKHART #3 66.51 17.03 LITTLE DRUM, SARAH (MS1) 10.04 2.10 WEST LITTLE DRUM, LAUREN (MS2) 8.14 1.70 STEELE #2-11H 10.58 2.21 ST EINBERGER 1H-10 20.04 4.19 Busse 1H-3 295.10 0.38 BIG HILL 1H-12{incr} 291.53 60.98 BIG HILL 2H-12,4H-12{incr} 562.08 117.56 LITTLE DRUM, SARAH (MS1){incr} 562.45 117.64 WEST LITTLE DRUM, LAUREN (MS{incr} 557.10 116.52 STEELE #2-11H{incr} 257.27 53.81 ST EINBERGER 1H-10{incr} 260.08 54.40 Bouziden 300.00 0.56 LAYTON 1 81.80 20.94 LAYTON 2 81.80 20.94 Braden School 300.00 62.75 CHK Well 300.00 0.56 MISSISSIPPIAN 01 300.00 0.88 MISSISSIPPIAN 08 300.00 0.16 MISSISSIPPIAN 09 300.00 1.02 MISSISSIPPIAN 10 300.00 0.15 MISSISSIPPIAN 11 300.00 0.88 MISSISSIPPIAN 12 300.00 1.02 MISSISSIPPIAN 13 300.00 0.24 MISSISSIPPIAN 15 300.00 0.44 MISSISSIPPIAN 22 300.00 1.06 MISSISSIPPIAN 02 300.00 0.56 MISSISSIPPIAN 04 300.00 1.06 MISSISSIPPIAN 07 300.00 0.15 MISSISSIPPIAN 14 300.00 0.56 MISSISSIPPIAN 18 300.00 0.04 MISSISSIPPIAN 19 300.00 0.18 MISSISSIPPIAN 03 300.00 1.17 MISSISSIPPIAN 05 300.00 0.56 MISSISSIPPIAN 06 300.00 0.38 MISSISSIPPIAN 16 300.00 0.12 MISSISSIPPIAN 17 300.00 0.26 MISSISSIPPIAN 20 300.00 0.15 MISSISSIPPIAN 21 300.00 0.32 Northcote Gas Reserves Page 33 of 53

All Figures in MMcf Gross Net Attributable Asset Proved 2P 3P Proved 2P 3P BIG HILL 1H-12 2.56 0.54 BIG HILL 2H-12,4H-12 146.09 30.56 BURKHART #3 0.00 0.00 LITTLE DRUM, SARAH (MS1) 31.54 6.60 WEST LITTLE DRUM, LAUREN (MS2) 69.73 14.58 STEELE #2-11H 50.26 10.51 ST EINBERGER 1H-10 183.20 38.32 Busse 1H-3 927.86 1.19 BIG HILL 1H-12{incr} 797.89 166.88 BIG HILL 2H-12,4H-12{incr} 1,464.64 306.34 LITTLE DRUM, SARAH (MS1){incr} 1,521.41 318.21 WEST LITTLE DRUM, LAUREN (MS{incr} 1,482.63 310.10 STEELE #2-11H{incr} 691.93 144.72 STEINBERGER 1H-10{incr} 603.77 126.28 Bouziden 943.58 1.76 LAYTON 1 0.00 0.00 LAYTON 2 0.00 0.00 Braden School 862.71 180.44 CHK Well 939.68 1.76 MISSISSIPPIAN 01 931.32 2.72 MISSISSIPPIAN 08 904.14 0.50 MISSISSIPPIAN 09 900.34 3.07 MISSISSIPPIAN 10 896.43 0.44 MISSISSIPPIAN 11 892.73 2.61 MISSISSIPPIAN 12 888.64 3.03 MISSISSIPPIAN 13 884.92 0.70 MISSISSIPPIAN 15 877.62 1.28 MISSISSIPPIAN 22 851.64 3.00 MISSISSIPPIAN 02 927.81 1.73 MISSISSIPPIAN 04 919.82 3.24 MISSISSIPPIAN 07 908.09 0.44 MISSISSIPPIAN 14 881.45 1.66 MISSISSIPPIAN 18 866.54 0.12 MISSISSIPPIAN 19 862.71 0.51 MISSISSIPPIAN 03 923.78 3.60 MISSISSIPPIAN 05 916.04 1.71 MISSISSIPPIAN 06 912.12 1.15 MISSISSIPPIAN 16 873.93 0.34 MISSISSIPPIAN 17 870.13 0.77 MISSISSIPPIAN 20 858.96 0.42 MISSISSIPPIAN 21 855.35 0.90 Page 34 of 53

Appendix C Cash Flow Forecasts Page 35 of 53

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Appendix D Glossary of Terms and Abbreviations MOYES & CO. This report necessarily uses a large number of geological and petroleum industry technical terms. Capitalized terms used in the report but not defined in the following glossary comprise (a) the names of periods of geological time, (b) geographic locations, and (c) formal or informal names for rock units (Formations, Groups, etc.), which are also, generally, geographic locations. In the definitions, italicized terms are themselves also defined here. % Percentage 1P 2P 3P P2 P3 Proved Reserves Proved plus Probable Reserves Proved plus Probable plus Possible Reserves Probable Reserves Possible Reserves 2-D (survey) Seismic data or a group of seismic lines acquired individually such that there typically are significant gaps (commonly 1 km or more) between adjacent lines. A 2D survey typically contains numerous lines acquired orthogonally to the strike of geological structures (such as faults and folds) with a minimum of lines acquired parallel to geological structures to allow line-to-line tying of the seismic data and interpretation and mapping of structures. 3-D (survey) three-dimensional (seismic data), The acquisition of seismic data as closely spaced receiver and shot lines such that there typically are no significant gaps in the subsurface coverage. A 2D survey commonly contains numerous widely spaced lines acquired orthogonally to the strike of geological structures and a minimum of lines acquired parallel to geological structures to allow line-to-line correlation of the seismic data and interpretation and mapping of structures. AFE anticlinal Aquifer Barnett Shale Authorization for expenditure, A budgetary document, usually prepared by the operator, to list estimated expenses of drilling a well to a specified depth, casing point or geological objective, and then either completing or abandoning the well. Such expenses may include excavation and surface site preparation, the daily rental rate of a drilling rig, costs of fuel, drill pipe, bits, casing, cement and logging, and coring and testing of the well, among others. This estimate of expenses is provided to partners for approval prior to commencement of drilling or subsequent operations. Failure to approve an authority for expenditure (AFE) may result in delay or cancellation of the proposed drilling project or subsequent operation. An arch-shaped fold in rock in which rock layers are upwardly convex, which is a fold with the shape of an arch An aquifer is an underground layer of water-bearing permeable rock A shale-gas producing formation that is now considered the largest gas producing field in Texas, and the second-largest in the United States Page 42 of 53

Barrel BBbl bbl(s) Bcf Bcfe a commercial unit of volume used to measure petroleum, by international agreement a barrel of petroleum equals 42 U.S. gallons Billion barrels Barrel(s) Billion cubic feet, Abbreviation for billion cubic feet, a unit of measurement for large volumes of natural gas. a symbol used in the natural gas industry for 1 billion cubic feet of gas equivalent (cfe). This is really an energy unit equal to about 1.091 petajoules (PJ). billion thousand million (109) BOE BOEPD BOPD CPR barrels of oil equivalent, gas is converted at its energy equivalent of 6000 cubic feet per barrel of oil barrels of oil equivalent per day, barrels of oil per day, Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 US gallons. Competent Person s Report Decline Curve Analysis An established method of estimating reserves utilizing historical production from a well or lease to forecast the future production and production decline. Drilling Unit An area allotted to a well by regulations or field rules issued by a governmental authority having jurisdiction for the drilling of a well. Economic Limit Point at which the operating cost exceeds net revenue from the lease or well. Exploratory facies fraccing ft G&A GOR Activities to establish the presence of reserves. rocks grouped or catalogued by certain characteristics, generally, but not always, indicative of a specific depositional environment A well stimulation treatment performed to restore or enhance the productivity of a well. Fracturing (frac) treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. unit of distance, equal to exactly 30.48 centimeters General and Administrative overhead The ratio of produced gas to produced oil, commonly abbreviated GOR. Usually reported in Standard Cubic Feet of Gas per Stock Tank Barrel ( SCF/STB ), an important a physical characteristic of produced fluid Page 43 of 53

HBP Held by production: A provision in an oil or natural gas property lease that allows the lessee, generally an energy company, to continue drilling activities on the property as long as it is producing a minimum paying amount of oil or gas. The held by production provision thereby extends the lessee s right to operate the property beyond the initial lease term. This provision is also a feature of mineral property leases. Heterogeneous Rock Formation whose properties change with geographic location or throughout HH HI Henry Hub, a Louisiana location widely used as a benchmark geographic location for pricing US domestic natural gas, and forming the physical basis for pricing and settling NYMEX gas futures contracts Hydrogen Index, in petroleum geochemistry, an important measure of oil source rock quality equal to the ratio of hydrocarbons generated under laboratory pyrolysis to TOC Horizontal Laterals Hydraulic Fracturing Horizontal laterals are the horizontal portion of a well bore A well stimulation treatment performed to restore or enhance the productivity of a well. Fracturing (frac) treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Hydrocarbon IP irreducible A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane [CH4], but many are highly complex molecules, and can occur as gases, liquids or solids. The molecules can have the shape of chains, branching chains, rings or other structures. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal. Initial production of a well, typically reported as oil and gas Here, hydrocarbon saturation at or below which hydrocarbons cannot be displaced from a porous rock Isopach (map) The thickness. An Isopach Map is a map of the thickness of a horizon. Lease An area of surface land on which exploration or production activity occurs. Lessor royalty A percentage share of production, or the value derived from production, which is granted to the lessor in the oil and gas lease, and which is free of the costs of drilling and producing. M Thousand Matrix porosity Pore spaces within the body of the rock that can contain gas (and water) MBO Mcfd Thousand Barrels of Oil Thousand Cubic Feet per Day Page 44 of 53

md Mean millidarcies, oilfield unit of permeability Average outcome of a set of data Micro-porosity matrix Small to micro-scale pores within the rock that can contain free gas Mineral Interest Ownership of the right to exploit, mine or produce all minerals lying beneath the surface of a property. In this case, minerals include all hydrocarbons. Mineral interests include: 1. the right to use as much of the surface as is reasonably necessary to access the minerals, 2. the right to execute any conveyances of mineral rights, 3. the right to receive bonus consideration, 4. the right to receive delay rentals and 5. the right to receive royalty. Any or all of the above five rights of mineral ownership may be conveyed by the mineral owner. MM MMBbl MMBtu MMBtu MMcfd MMSTB moldic NRI NYMEX million (thousand thousand not million million), as used in oilfield and heat content units such as MMSTB and MMBtu Million barrels Million British Thermal Units million British thermal units, unit of heat content used, e.g., for natural gas prices Million Cubic Feet per Day million stock tank barrels, unit of oil volume (c.f. STB) porosity in carbonate rocks created by dissolution within grains, where the shape of the original grain is preserved and visible (c.f. intercrystalline, intergranular and mesovuggy) Net Revenue Interest,. A share of production after all burdens, such as royalty and overriding royalty, have been deducted from the working interest. It is the percentage of production that each party actually receives. New York Mercantile Exchange NYMEX Strip NYMEX Strip Pricing is the average of the daily settlement prices of the next 12 months Pricing futures contracts. OPEX ORRI Operating Expense. The cost to operate oil and gas wells. Usually excludes General and Administrative Expense or Overhead. Over Riding Royalty Interest Page 45 of 53

ºAPI A specific gravity scale developed by the American Petroleum Institute (API) for measuring the relative density of various petroleum liquids, expressed in degrees. API gravity is gradated in degrees on a hydrometer instrument and was designed so that most values would fall between 10º and 70º API gravity. The arbitrary formula used to obtain this effect is: API gravity = (141.5/SG at 60ºF) - 131.5, where SG is the specific gravity of the fluid. degree(s) API, oil field measure of the specific gravity or relative density of crude oil (and other liquids) with respect to water, named for the American Petroleum Institute C degree(s) Celsius, to convert to ºF P10 P90 play ppm SCF STB Spacing Unit TCF TD 10th percentile on a probability distribution. 10% of the possible outcomes will result in a value lower than the P10 value. 90th percentile on a probability distribution. 90% of the possible outcomes will result in a value lower than the P90 value. a term used to describe a group of oil prospects that are controlled by the same set of geological circumstances parts per million standard cubic foot, oilfield unit of gas volume, measured at or converted to standard conditions of temperature and pressure A stock tank barrel is 42 U.S. gallons at a temperature of 60 ºF (15.556 ºC) An area allotted to a well by regulations or field rules issued by a governmental authority having jurisdiction for the drilling and production of a well. trillion (10 12 ) standard cubic feet, unit of natural gas volume (c.f. SCF) total depth of an oil or gas well, conventionally measured down the length of the well bore from a reference at or close to the rig floor unless otherwise stated the vertical section Thermal maturity The state of a source rock with respect to its ability to generate oil or gas. As a source rock begins to mature, it generates gas. As an oil-prone source rock matures, the generation of heavy oils is succeeded by medium and light oils. Above a temperature of approximately 100 ºC [212 ºF], only dry gas is generated, and incipient metamorphism is imminent. The maturity of a source rock reflects the ambient pressure and temperature as well as the duration of conditions favorable for hydrocarbon generation. TOC TVD Total Organic Carbon, usually expressed as weight%, which when corrected for maturity is the primary measure of original source rock quality True vertical depth trillion million million (10 12 ) Page 46 of 53

unconformity USGS US$ WI WTI a boundary within a sequence of rocks that indicates a gap (in time) between the underlying and overlying rocks United States Geological Survey (www.usgs.org) United States Dollars Working Interest, a percentage of ownership in an oil and gas lease granting its owner the right to explore, drill and produce oil and gas from a tract of property. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well or unit. After royalties are paid, the working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned. West Texas Intermediate, a crude oil whose price, FOB Cushing, Oklahoma, is widely used as a benchmark for pricing worldwide crude oils, and which forms the physical basis for pricing and settling NYMEX Sweet, Light crude oil futures contracts Page 47 of 53

Appendix E Definitions of Oil and Gas Reserves MOYES & CO. Adapted from the 2007 Petroleum Resources Management System (PRMS) Approved by the Society of Petroleum Engineers (SPE) Petroleum Resources Classification Framework Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarboncontent could be greater than 50%. The term resources as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered conventional or unconventional. Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum. The Range of Uncertainty reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification: Page 48 of 53

TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to total resources ). DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Production Measurement, section 3.2 of the official PRMS document). Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below. RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered. PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified 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 Page 49 of 53

development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources). In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or EUR may be termed Basin Potential. The sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as remaining recoverable resources. When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification. Resources Categorization The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and commercial uncertainty components as follows: The total petroleum remaining within the accumulation (in-place resources). That portion of the in-place petroleum that can be recovered by applying a defined development project or projects. Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., market availability, contractual changes). Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of commerciality. Range of Uncertainty The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2 of the official PRMS document). When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that: There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2 of the official PRMS document). Page 50 of 53

These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned. Category Definitions and Guidelines Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods. (see 2001 Supplemental Guidelines, Chapter 2.5). In many cases, a combination of approaches is used. Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development. For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources. Without new technical information, there should be no change in the distribution of technically recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial Evaluations, section 3.1 of the official PRMS document). The following summarizes the definitions for each Reserves category in terms of both the deterministic incremental approach and scenario approach and also provides the probability criteria if probabilistic methods are applied. Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Page 51 of 53

Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves. Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the best estimate is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see 2001 Supplemental Guidelines, Chapter 2.5). Commercial Evaluations Investment decisions are based on the entity s view of future commercial conditions that may impact the development feasibility (commitment to develop) and production/cash flow schedule of oil and gas projects. Commercial conditions include, but are not limited to, assumptions of financial conditions (costs, prices, fiscal terms, taxes), marketing, legal, environmental, social, and governmental factors. Project value may be assessed in several ways (e.g., historical costs, comparative market values); the guidelines herein apply only to evaluations based on cash flow analysis. Moreover, modifying factors such contractual or political risks that may additionally influence investment decisions are not addressed. (Additional detail on commercial issues can be found in the 2001 Supplemental Guidelines, Chapter 4.) Cash-Flow-Based Resources Evaluations Resources evaluations are based on estimates of future production and the associated cash flow schedules for each development project. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project. The calculation shall reflect: The expected quantities of production projected over identified time periods. The estimated costs associated with the project to develop, recover, and produce the quantities of production at its Reference Point (see section 3.2.1 of the official PRMS document), including environmental, abandonment, and reclamation costs charged to the project, based on the evaluator s view of the costs expected to apply in future periods. The estimated revenues from the quantities of production based on the evaluator s view of the prices expected to apply to the respective commodities in future periods including that portion of the costs and revenues accruing to the entity. Future projected production and revenue related taxes and royalties expected to be paid by the entity. A project life that is limited to the period of entitlement or reasonable expectation thereof. The application of an appropriate discount rate that reasonably reflects the weighted average cost of capital or the minimum acceptable rate of return applicable to the entity at the time of the evaluation. While each organization may define specific investment criteria, a project is generally considered to be economic if its best estimate case has a positive net present value under the organization s standard discount rate, or if at least has a positive undiscounted cash flow. Economic Criteria Evaluators must clearly identify the assumptions on commercial conditions utilized in the evaluation and must document the basis for these assumptions. Page 52 of 53

The economic evaluation underlying the investment decision is based on the entity s reasonable forecast of future conditions, including costs and prices, which will exist during the life of the project (forecast case). Such forecasts are based on projected changes to current conditions; SPE defines current conditions as the average of those existing during the previous 12 months. Alternative economic scenarios are considered in the decision process and, in some cases, to supplement reporting requirements. Evaluators may examine a case in which current conditions are held constant (no inflation or deflation) throughout the project life (constant case). Evaluations may be modified to accommodate criteria imposed by regulatory agencies regarding external disclosures. For example, these criteria may include a specific requirement that, if the recovery were confined to the technically Proved Reserves estimate, the constant case should still generate a positive cash flow. External reporting requirements may also specify alternative guidance on current conditions (for example, year-end costs and prices). There may be circumstances in which the project meets criteria to be classified as Reserves using the forecast case but does not meet the external criteria for Proved Reserves. In these specific circumstances, the entity may record 2P and 3P estimates without separately recording Proved. As costs are incurred and development proceeds, the low estimate may eventually satisfy external requirements, and Proved Reserves can then be assigned. While SPE guidelines do not require that project financing be confirmed prior to classifying projects as Reserves, this may be another external requirement. In many cases, loans are conditional upon the same criteria as above; that is, the project must be economic based on Proved Reserves only. In general, if there is not a reasonable expectation that loans or other forms of financing (e.g., farm-outs) can be arranged such that the development will be initiated within a reasonable timeframe, then the project should be classified as Contingent Resources. If financing is reasonably expected but not yet confirmed, the project may be classified as Reserves, but no Proved Reserves may be reported as above. Economic Limit Economic limit is defined as the production rate beyond which the net operating cash flows from a project, which may be an individual well, lease, or entire field, are negative, a point in time that defines the project s economic life. Operating costs should be based on the same type of projections as used in price forecasting. Operating costs should include only those costs that are incremental to the project for which the economic limit is being calculated (i.e., only those cash costs that will actually be eliminated if project production ceases should be considered in the calculation of economic limit). Operating costs should include fixed property-specific overhead charges if these are actual incremental costs attributable to the project and any production and property taxes but, for purposes of calculating economic limit, should exclude depreciation, abandonment and reclamation costs, and income tax, as well as any overhead above that required to operate the subject property itself. Operating costs may be reduced, and thus project life extended, by various cost-reduction and revenue-enhancement approaches, such as sharing of production facilities, pooling maintenance contracts, or marketing of associated nonhydrocarbons (see Associated Non-Hydrocarbon Components, section 3.2.4 of the official PRMS document). Interim negative project net cash flows may be accommodated in short periods of low product prices or major operational problems, provided that the longer-term forecasts must still indicate positive economics. Page 53 of 53