Adira Energy Ltd.: Exhibit 99.6 - Filed by newsfilecorp.com

In accordance with your request, we have estimated the unrisked contingent and prospective resources, as of March 1, 2012, to the Adira Energy Ltd (Adira) interest in discoveries and prospects located in Block 378 (Gabriella), offshore Israel. The preparation date of this report is March 5, 2012; we did not consider any geological, engineering, or financial data for this evaluation after that date. The estimates in this report have been prepared in accordance with the definitions and guidelines set forth in Canadian National Instrument 51-101––Standards of Disclosure for Oil and Gas Activities and Section 5 of Volume 1, Second Edition, of the Canadian Oil and Gas Evaluation Handbook (COGEH), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the latter of which is now the Petroleum Society of Canada). As presented in the COGEH, reserves, contingent resources, and prospective resources should not be combined without recognition of the significant differences in the criteria associated with their classification. Contingent and prospective resources estimates involve additional risks, specifically the risk of not achieving commerciality and exploration risk, respectively, not applicable to reserves estimates. Therefore, when resources classifications are combined, it is important that each component of the summation also be provided, and it should be made clear whether and how the components in the summation were adjusted for risk. Definitions are presented immediately following this letter. Following the definitions are certificates of qualification and a list of abbreviations used in this report.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable because of one or more contingencies. The contingent resources shown in this report are contingent upon project sanctioning and demonstration of the economic viability of the project. If these contingencies are successfully addressed, some portion of the contingent resources estimated in this report may be reclassified as reserves; our estimates have not been risked to account for the possibility that the contingencies are not successfully addressed. This report does not include economic analysis for these properties. Based on analogous field developments, it appears that the best estimate contingent resources in this report have a reasonable chance of being commercial. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

We estimate the unrisked gross (100 percent) contingent resources and the unrisked company gross interest contingent resources to the Adira interest in the Jurassic Formation, as of March 1, 2012, to be:

The oil volumes shown include light and medium crude oil only. Oil volumes are expressed in millions of barrels (MMbbl); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in billions of cubic feet (Bcf) at standard temperature and pressure bases. Oil equivalent volumes are expressed in millions of barrels of oil equivalent (MMBOE), determined using the ratio of 6 Bcf of gas to 1 MMbbl of oil.

The contingent resources shown in this report have been estimated using probabilistic methods. Once all contingencies have been successfully addressed, the probability that the quantities of contingent resources actually recovered will equal or exceed the estimated amounts is 90 percent for the low estimate, 50 percent for the best estimate, and 10 percent for the high estimate. For the purposes of this report, the volumes and parameters associated with the low, best, and high estimate scenarios of contingent resources are referred to as 1C, 2C, and 3C, respectively. The estimates of contingent resources included herein have not been adjusted for development risk.

Prospective resources are those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. The prospective resources included in this report should not be construed as reserves or contingent resources; they represent exploration opportunities and quantify the development potential in the event a petroleum discovery is made. A geologic risk assessment was performed for these prospective reservoirs, as discussed in subsequent paragraphs. This report does not include economic analysis for these prospective reservoirs. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.

We estimate the unrisked gross (100 percent) prospective resources and the unrisked company gross interest prospective resources to the Adira interest for these prospective reservoirs, as of March 1, 2012, to be:

The prospective resources shown in this report have been estimated using probabilistic methods and are dependent on a petroleum discovery being made. If a discovery is made and development is undertaken, the probability that the recoverable volumes will equal or exceed the unrisked estimated amounts is 90 percent for the low estimate, 50 percent for the best estimate, and 10 percent for the high estimate.

Unrisked prospective resources are estimated ranges of recoverable oil and gas volumes assuming their discovery and development and are based on estimated ranges of undiscovered in-place volumes. Geologic risking of prospective resources addresses the probability of success for the discovery of significant quantities of potentially moveable petroleum; such risk analysis is conducted independent of estimations of petroleum volumes and without regard to the chance of development. Principal geologic risk elements of the petroleum system include (1) trap and seal characteristics; (2) reservoir presence and quality; (3) source rock capacity, quality, and maturity; and (4) timing, migration, and preservation of petroleum in relation to trap and seal formation. Risk assessment is a highly subjective process dependent upon the experience and judgment of the evaluators. The following table shows the geologic risk elements and overall probability of geologic success for each prospective reservoir.

Each prospective reservoir was evaluated to determine ranges of in-place and recoverable petroleum and was risked as an independent entity without dependency between potential prospective reservoir drilling outcomes. If petroleum discoveries are made, smaller-volume prospective reservoirs may not be commercial to independently develop, although they may become candidates for satellite developments and tie-backs to existing infrastructure at some future date. The development infrastructure and data obtained from early discoveries will alter both geologic risk and future economics of subsequent discoveries and developments.

It should be understood that the prospective resources discussed and shown herein are those undiscovered, highly speculative resources estimated beyond reserves or contingent resources where geological and geophysical data suggest the potential for discovery of petroleum but where the level of proof is insufficient for classification as reserves or contingent resources. The unrisked prospective resources shown in this report are the range of volumes that could reasonably be expected to be recovered in the event of the discovery and development of this prospect.

As shown in the Table of Contents, the Technical Discussion section of this report includes a discussion of the history of the properties, a regional geologic overview, a brief review of the data available for this assessment, and a discussion of the technical approach used in our analysis. Included in the Figures section are pertinent maps, displays, and tables.

For the purposes of this report, we did not perform any field inspection of the properties. Based on the information provided by Adira, it is our opinion that a field visit was not required and would not materially affect our evaluation. We have not investigated possible environmental liability related to the properties.

The contingent resources and prospective resources shown in this report are estimates only and should not be construed as exact quantities. Estimates may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. Our estimates of contingent resources are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the contingent resources, and that our projections of future production will prove consistent with actual performance.

For the purposes of this report, we used technical data including, but not limited to, well logs, geologic maps, seismic data, well test data, and property ownership interests. The contingent resources and prospective resources in this report have been estimated using probabilistic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to classify, categorize, and estimate volumes in accordance with COGEH definitions and guidelines. The contingent and prospective resources shown in this report are for undeveloped locations; such volumes are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Adira, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience and work data are on file in our office. The contractual rights to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality as provided in the standards pertaining to the estimating of oil and gas resources information included in the COGEH. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF RESERVES
Section 5.4 of Volume 1, Second Edition, of the Canadian Oil and Gas Evaluation Handbook, Prepared Jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the latter of which is now the Petroleum Society of Canada)

The following reserves definitions and guidelines are designed to assist evaluators in making reserves estimates on a reasonably consistent basis, and assist users of evaluation reports in understanding what such reports contain and, if necessary, in judging whether evaluators have followed generally accepted standards.

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable, and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgement combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. These concepts are presented and discussed in greater detail within the guidelines in Section 5.5.

The following definitions apply to both estimates of individual reserves entities and the aggregate of reserves for multiple entities.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on

Reserves are classified according to the degree of certainty associated with the estimates.

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves.

Other criteria that must also be met for the classification of reserves are provided in Section 5.5.4.

Each of the reserves categories (proved, probable, and possible) may be divided into developed and undeveloped categories.

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production but are shut in and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status.

The qualitative certainty levels contained in the definitions in Section 5.4.1 are applicable to "individual reserves entities," which refers to the lowest level at which reserves calculations are performed, and to "reported reserves," which refers to the highest level sum of individual entity estimates for which reserves estimates represented. Reported reserves should target the following levels of certainty under a specific set of economic conditions:

DEFINITIONS OF RESOURCES
Sections 5.2 and 5.3 of Volume 1, Second Edition, of the Canadian Oil and Gas Evaluation Handbook, Prepared by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society)

The following definitions relate to the subdivisions in the resources classification framework of Figure 5-1 and use the primary nomenclature and concepts contained in the 2007 SPE-PRMS, with direct excerpts shown in italics.

Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").

Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.

Production is the cumulative quantity of petroleum that has been recovered at a given date.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status. Refer to the full definitions of reserves in Section 5.4.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified 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.

Unrecoverable is that portion of Discovered or Undiscovered PIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources," the remainder as "unrecoverable."

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.

Reserves, contingent resources, and prospective resources should not be combined without recognition of the significant differences in the criteria associated with their classification. However, in some instances (e.g., basin potential studies) it may be desirable to refer to certain subsets of the total PIIP. For such purposes the term "resources" should include clarifying adjectives "remaining" and "recoverable," as appropriate. For example, the sum of reserves, contingent resources, and prospective resources may be referred to as "remaining recoverable resources." However, contingent and prospective resources estimates involve additional risks, specifically the risk of not achieving commerciality and exploration risk, respectively, not applicable to reserves estimates. Therefore, when resources categories are combined, it is important that each component of the summation also be provided, and it should be made clear whether and how the components in the summation were adjusted for risk.

For petroleum quantities associated with simple conventional reservoirs, the divisions between the resources categories defined in Section 5.2 may be quite clear, and in such instances the basic definitions alone may suffice for differentiation between categories. For example, the drilling and testing of a well in a simple structural accumulation may be sufficient to allow classification of the entire estimated recoverable quantity as contingent resources or reserves. However, as the industry trends toward the exploitation of more complex and costly petroleum sources, the divisions between resources categories are less distinct, and accumulations may have several categories of resources simultaneously. For example, in extensive "basin-center" low-permeability gas plays, the division between all categories of remaining recoverable quantities, i.e., reserves, contingent resources, and prospective resources, may be highly interpretive. Consequently, additional guidance is necessary to promote consistency in classifying resources. The following provides some clarification of the key criteria that delineate resources categories. Subsequent volumes of COGEH provide additional guidance.

As shown in Figure 5-1, the total petroleum initially in place is first subdivided based on the discovery status of a petroleum accumulation. Discovered PIIP, production, reserves, and contingent resources are associated with known accumulations. Recognition as a known accumulation requires that the accumulation be penetrated by a well and have evidence of the existence of petroleum. COGEH Volume 2, Sections 5.3 and 5.4, provides additional clarification regarding drilling and testing requirements relating to recognition of known accumulations.

Commercial status differentiates reserves from contingent resources. The following outlines the criteria that should be considered in determining commerciality:

COGEH Volume 2, Sections 5.5 to 5.8, provides addition details relating to the foregoing aspects of commerciality relating to classification as reserves versus contingent resources.

In order to assign recoverable resources of any category, a development plan consisting of one or more projects needs to be defined. In-place quantities for which a feasible project cannot be defined using established technology or technology underdevelopment are classified as unrecoverable. In this context "technology underdevelopment" refers to technology that has been developed and verified by testing as feasible for future commercial applications to the subject reservoir. In the early stage of exploration or development, project definition will not be of the detail expected in later stages of maturity. In most cases recovery efficiency will be largely based on analogous projects.

Estimates of recoverable quantities are stated in terms of the sales products derived from a development program, assuming commercial development. It must be recognized that reserves, contingent resources, and prospective resources involve different risks associated with achieving commerciality. The likelihood that a project will achieve commerciality is referred to as the "chance of commerciality." The chance of commerciality varies in different categories of recoverable resources as follows:

By definition, reserves are commercially (and hence economically) recoverable. A portion of contingent resources may also be associated with projects that are economically viable but have not yet satisfied all requirements of commerciality. Accordingly, it may be a desirable option to subclassify contingent resources by economic status:

Economic Contingent Resources are those contingent resources that are currently economically recoverable.

Sub-Economic Contingent Resources are those contingent resources that are not currently economically recoverable.

Where evaluations are incomplete such that it is premature to identify the economic viability of a project, it is acceptable to note that project economic status is "undetermined" (i.e., "contingent resources – economic status undetermined").

In examining economic viability, the same fiscal conditions should be applied as in the estimation of reserves, i.e., specified economic conditions, which are generally accepted as being reasonable (refer to COGEH Volume 2, Section 5.8).

Resources may be further subclassified based on development and production status. For reserves, the terms "developed" and "undeveloped" are used to express the status of development of associated recovery projects, and "producing" and "non-producing" indicate whether or not reserves are actually on production (see Section 5.4.2).

Similarly, project maturity subcategories can be identified for contingent and prospective resources; the SPE-PRMS (Section 2.1.3.1) provides examples of subcategories that could be identified. For example, the SPE-PRMS identifies the highest project maturity subcategory as "development pending," defined as "a discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future."

Estimates of resources always involve uncertainty, and the degree of uncertainty can vary widely between accumulations/projects and over the life of a project. Consequently, estimates of resources should generally be quoted as a range according to the level of confidence associated with the estimates. An understanding of statistical concepts and terminology is essential to understanding the confidence associated with resources definitions and categories. These concepts, which apply to all categories of resources, are outlined in Sections 5.5.1 to 5.5.3.

The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as low, best, and high estimates as follows:

This approach to describing uncertainty may be applied to reserves, contingent resources, and prospective resources. There may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production. However, it is useful to consider and identify the range of potentially recoverable quantities independently of such risk.

I, Richard B. Talley, Jr., Registered Professional Engineer, 1221 Lamar Street, Suite 1200, Houston, Texas 77010, hereby certify:

I am an employee of Netherland, Sewell & Associates, Inc., which prepared a detailed analysis of certain discoveries and prospects of Adira Energy Ltd (Adira). The effective date of this evaluation is March 1, 2012.

I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Adira or its affiliated companies.

I attended Tulane University, and I graduated in 2001 with a Master of Business Administration Degree. I attended the University of Oklahoma, and I graduated in 1998 with a Bachelor of Science Degree in Mechanical Engineering; I am a Registered Professional Engineer in the State of Texas, United States of America; and I have in excess of 13 years of experience in petroleum engineering studies and evaluations.

A personal field inspection of the discoveries and prospects was not made; however, such an inspection was not considered necessary in view of the information available from public information or records, the files from Adira, and the appropriate provincial or state regulatory authorities.

I, David E. Nice, Registered Professional Geoscientist, 1221 Lamar Street, Suite 1200, Houston, Texas 77010, hereby certify:

I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Adira or its affiliated companies.

I attended University of Wyoming, I graduated in 1985 with a Master of Science Degree in Geology, and I graduated in 1982 with a Bachelor of Science Degree in Geology; I am a Licensed Geoscientist in the State of Texas, United States of America; and I have in excess of 26 years of experience in geological and geophysical studies and evaluations.

A personal field inspection of the discoveries and prospects was not made; however, such an inspection was not considered necessary in view of the information available from public information or records, the files of Adira, and the appropriate provincial or state regulatory authorities.

°	degree
1C	low estimate scenario of contingent resources
2C	best estimate scenario of contingent resources
3C	high estimate scenario of contingent resources
Adira	Adira Energy Ltd
API	American Petroleum Institute
bbl	barrels
Bcf	billions of cubic feet
bopd	barrels of oil per day
C₂	ethane
C₄	butane
COGEH	Canadian Oil and Gas Evaluation Handbook
HIIP	hydrocarbons initially-in-place
km	kilometers
km²	square kilometers
m	meters
MD	measured depth
MMbbl	millions of barrels
MMBOE	millions of barrels of oil equivalent
NSAI	Netherland, Sewell & Associates, Inc.
ppg	pounds per gallon
rb/stb	reservoir barrels per stock tank barrel
scf/rcf	standard cubic feet per reservoir cubic foot
USA	United States of America

Netherland, Sewell & Associates, Inc. (NSAI) has estimated the unrisked contingent and prospective resources, as of March 1, 2012, to the Adira Energy Ltd (Adira) interest in discoveries and prospects located in Block 378 (Gabriella), offshore Israel. The preparation date of this report is March 5, 2012; we did not consider any geological, engineering, or financial data for this evaluation after that date.

Prospective resources are those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. The prospective resources included in this report should not be construed as reserves or contingent resources; they represent exploration opportunities and quantify the development potential in the event a petroleum discovery is made. A geologic risk assessment was performed for these prospective reservoirs. This report does not include economic analysis for these prospective reservoirs. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.

The estimates in this report have been prepared in accordance with the definitions and guidelines set forth in Canadian National Instrument 51-101––Standards of Disclosure for Oil and Gas Activities and Section 5 of Volume 1, Second Edition, of the Canadian Oil and Gas Evaluation Handbook (COGEH), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the latter of which is now the Petroleum Society of Canada).

The Gabriella Block is located offshore Israel, approximately 24 kilometers (km) northwest of Tel Aviv as shown on the location map in Figure 1. The block covers an area of approximately 390 square kilometers (km²) and is in water depths that range from 100 meters (m) on the east side of the block to just over 425 m on the southwest side of the block. One well, the Yam Yafo 1, has been drilled on the block.

The Delta 1 well, located on the Yitzhak Block to the north of the Gabriella Block, was drilled by Belpetco Israel Ltd. in 1970 to test a high at the Upper Cretaceous level. The Delta 1 well was abandoned after experiencing hole troubles at a measured depth (MD) of 4,171 m and was subsequently sidetracked from 3,774 m to a final depth of 4,423 m in the 1A hole. The Delta 1A well reached total depth in the Delta Formation of the Upper Jurassic. Poor oil shows were noted in the Cenomanian at 1,906 m MD and traces of dead oil or asphalt were recorded coming from Hauterivian and Berriasian Limestones. No gas shows were reported in the wells and no well tests were conducted.

The Yam Yafo 1 well, located on the Gabriella Block, was drilled from January to August 1994 by Isramco Inc., Israel Branch and other partners in the Med Tel Aviv License. The well was drilled to test Jurassic carbonates on a large structure. The well reached a total depth of 5,785 m MD in the Early Jurassic Qeren Formation. The Yam Yafo 1 well encountered oil and/or gas shows while drilling in the Middle Jurassic Barnea, Shederot, and Zohar Formations. All these formations have hydrocarbon indications as evidenced by log analysis. The Barnea Formation located below the Shederot Formation was drillstem tested but recovered only 39.6 barrels (bbl) of brine. The Barnea Formation was then acidized with 172 bbl of 15 percent hydrochloric acid and 130 bbl of water behind the acid. Only 187 bbl of brine was recovered, and the Barnea Formation testing was abandoned. The Shederot and Zohar Formations were tested together and flowed both oil and water at a rate of 821 barrels of oil per day (bopd) and 475 bbl of water per day. After attempts were made to isolate the Shederot Formation, the Zohar Formation was retested but it also produced oil and water. The attempt to isolate what was thought to be water from the Shederot Formation was unsuccessful.

Other wells that have tested the Middle Jurassic section in nearby waters are the Yam 2 and Yam West 1 wells. The Yam West 1 well, located 35 km to the southwest of the Yam Yafo 1 well, has reported shows of live oil and gas in the Jurassic section. The Yam 2 well, located approximately 38 km south of the Yam Yafo 1 well, tested 47° API gravity oil out of the Zohar Formation at a projected rate of 800 bopd with a water cut of 17 percent.

Both the Yam Yafo 1 and the Yam 2 wells experienced lost mud while drilling the Jurassic carbonate section, and specialized analysis of the well logs indicates that fractures are present in the Jurassic carbonates. The Yam 2 well, while drilling at 5,334 m MD, had a gas peak of 70 percent and mud weight was increased from 14.0 pounds per gallon (ppg) to 14.6 ppg. The hole was losing 20 bbl of mud per hour, so lost circulation material was pumped down the hole. The Yam Yafo 1 well lost 1,795 bbl of mud into the Jurassic carbonates while drilling, and it required mud weights of up to 16.1 ppg to control the well while drilling through the Jurassic section. Based on the amount of fluid lost while drilling the carbonate section in these two wells, it is thought that the produced water is mud filtrate and not formation water.

The Gabriella Block is covered by a 465-km² 3-D seismic data set acquired in 2010 and 2011. The data was shot on an azimuth of 23 degrees and was processed in time in the form of a Quick-Look cube by WesternGeco. This survey was merged with another smaller 197-km² 3-D survey shot on an azimuth of 343 degrees and processed in a depth volume in December 2011.

The Gabriella Block is located in the Levant Basin of the eastern Mediterranean region. The eastern extent of the basin is marked by the Levant Transform Zone (Dead Sea Transform); the western edge of the basin is delineated by the Nile Delta Cone and the Eratosthenes Seamount; and the northern border is defined by the Taurus Fault Zone (Cyprian Arc). The basin has undergone at least three different episodes of structural deformation. The first phase of deformation started in the Late Paleozoic with rifting creating a series of horst and graben structures that evolved in several pulses. The rifting was followed by post-rift cooling and subsidence of the basin. From the Middle Jurassic to Early Tertiary, the basin was a major depocenter for the area. Late Cretaceous convergence of the Eurasian and Afro-Arabian plates may have caused compression of the Levant Basin margin and triggered the formation of a fold belt known as the Syrian Arc in the northeast corner of the basin. Reactivation, in a reverse motion, of normal faults created during the rifting stage accentuated the anticlines created by the convergence and preexisting rift blocks.

Uplift to the east of the Levant Basin and to the south on the Arabian platform is evidenced by an Eocene-aged regional unconformity. This unconformity separates the older, carbonate section from the overlying Oligo-Miocene siliclastics and marks the onset of widespread erosion, canyon development, and basinward transport of sediments on the shelf and into older parts of the basin. The Oligo-Miocene sediments are capped by a thick, Upper Miocene halite and anhydrite deposit formed during a major drop in sea level This deposit is, in turn, covered by a Plio-Pleistocene fine-grained siliclastic wedge formed during gradual sea-level rise.

Permo-Triassic rocks sit on crystalline basement in the nearshore Israel. These rocks probably thin toward the west such that Early Jurassic shallow marine carbonates are unconformably deposited on top of crystalline basement in the offshore, as shown on the stratigraphic column included as Figure 2. The Jurassic section is only partially penetrated in wells in offshore Israel. The oldest rock penetrated in offshore Israel is of Early Jurassic age. The Yam West 1 and Yam Yafo 1 wells penetrated several cycles of oolitic pelletal and intraclast grainstones and skeletal grainstones separated by thin shales of the Qeren Formation. These carbonates are thought to be allochthonous deposits from the shelf edge to the east. Above the Qeren Formation lies the Barnea Formation, a 240-to-300-m-thick sequence of carbonates and shales. Above the Barnea Formation is the Shederot Formation of probable Middle Jurassic age. The Shederot Formation is a carbonate of approximately 50 m in thickness. The 20-m-thick Karmon Formation lies above the Shederot Formation and is composed of marls and shales. The Middle Jurassic Zohar Formation is above the Karmon Formation and is approximately 65 m thick; it is composed predominantly of limestone with minor shale or marl intercalations. The Zohar Formation carbonates are thought to be Bathonian in age and consist of oolitic, pelletal, intraclast, and skeletal grainstones, mudstones, and packstones. Above the Callovian are Oxfordian-to-Kimmeridgian-age rocks of the Delta Formation. The basal part of this section is a transgressive unit that marks the end of the Middle Jurassic carbonate platform. The Delta Formation is composed predominantly of claystone with some limestones, which are occasionally chalky, and dolomites. The Tithonian Yam Formation lies conformably above the Delta Formation. This unit, interpreted as slope and basin deposits, is composed of dark, laminated shale and siltstone generally barren of fauna.

Unconformably overlying the Yam Formation is the Gevar Am Formation of Early Cretaceous age. This formation is composed of marine shales with conglomerate and sandstone intercalations. The sandstone deposits are thought to represent channel levee and crevasse splay deposits of proximal slope fans, which were deposited during a relative sea level fall caused by tectonic uplift. Uncomformably overlying the Gevar Am Formation is the Talme Yafe Formation, which is a deposit of carbonate debris marked by a coarse conglomerate at the base. The carbonate is thought to be from platform deposits on the shelf that were possibly deposited as debris flows during a pronounced drop in sea level.

The Late Cretaceous is represented by the Negba, Daliya, Ein Zetim, and Ghareb Formations. The basal Negba and Daliya Formations are pelagic chalks thought to represent the drowning of the offshore area during an extensive sea level rise. These pelagic chalks are overlain by a series of chalky limestones, separated by shales, which were deposited during periods of sea level rise that persisted until Middle Miocene time.

During Late Oligocene to early Middle Miocene time, sea level dropped abruptly and erosion and canyon development was renewed. Deepwater turbidites were deposited in the deepest parts of the basin. These turbidites are a primary reservoir target because of the recent Dalit, Leviathan, and Tamar Discoveries by Noble Energy, Inc. This lowstand is the start of the Late Miocene Messinian salinity crisis in the Mediterranean area and is represented by the Lakhish Formation composed of thick, sandy turbidites in the deeper parts of the basin and a dark, grey-green, silty claystone overlying the turbidites and extending to the shore. The Messinian Mavqim Formation was deposited unconformably above the Lakhish Formation and is a thick evaporitic series found throughout much of the Mediterranean area. The Mavqim Formation is composed of halite and anhydrite. It is thought that the Mediterranean area was isolated from the Atlantic Ocean because the sea level curves of the Mediterranean depart from the worldwide sea level curves. The waters in the isolated Mediterranean slowly evaporated, leaving the salts in the large topographic low of the greater Mediterranean Basin.

Sea levels in the Mediterranean again rose during the Pliocene because the feature that was isolating the area was breached, and marine waters again filled the basin. This resulted in the deposition of hemipelagic clays and marls of the Plio-Pleistocene Yafo Formation. The base of the Yafo Formation is marked by a highly condensed hemipelagic marl of the initial transgression. Another drop in sea level lead to the deposition of potentially gas-bearing turbidite sands. Sea levels again rose, and hemipelagic deposition resumed. As the rate of sedimentation increased, progradation of highstand deposits occurred. In some areas, this resulted in over 1,000 m of sediment thickness of the Yafo Formation. The Pleshet Formation lies conformably above the Yafo Formation. The Pleshet Formation is a sequence of clays, sands, silts, and marls of Pleistocene age.

Structural trap formation in the Levant Basin occurred during the Late Cretaceous compressional event with inversion of previous structural lows into structural highs. This has created large anticlinal features in pre-Plio-Pleistocene sediments. The structural Syrian Arc ridge, often referred to as the Eastern Levant Ridge, is divided into three substructures: the Gabriella, Yam, and Yitzhak. Large faults that extend down to basement serve as conduits for the migration of hydrocarbons into these features. There is some seismic evidence that the compressional event has relaxed during Plio-Pleistocene to Recent times, which may suggest a chance for remigration of hydrocarbons from deeper to shallower traps.

To date, the only commercial discoveries in the Levant Basin have been gas, and no liquids associated with these discoveries have been reported. These gas deposits are thought to be biogenic in origin. However, oil has been found in two wells, the Yam 2 and Yam Yafo 1, and there have been shows in other wells such as the Delta 1, Delta 1A, and Yam West 1 drilled in the offshore area. Numerous seafloor seeps are documented in the eastern Mediterranean. Senonian age source rocks are thought to be in the prime oil generation window now, but only gas shows with minor levels of C₂to C₄have been observed in offshore wells from the Cretaceous section. In the deepest part of the basin, Jurassic and Senonian age source rocks are thought to be in the early gas window at this time, and the oil found in the wells mentioned above is very light oil with gravities of 44° to 46° API reported. A recent assessment of undiscovered oil and gas resources of the Levant Basin, published by the United States Geological Survey, reports that there is potential to discover a mean estimate of 1.7 billion bbl of oil (10.2 trillion cubic feet of gas equivalent) and 122 trillion cubic feet of gas. Thus the basin appears to be predominantly a gas play with a slight chance for finding oil.

Data for the resources assessment was transferred to NSAI from Adira and Gustavson Associates in Denver, Colorado. Included in the data transfer were reports, processed logs, and digital log curves for the Bravo 1, Delta 1, Delta 1A, Yam 2, and Yam Yafo 1 wells; a Seismic Micro Technology project with 3-D seismic data, well data, horizon and fault interpretations, and time structure maps; three reports titled "Report For Block 378 'Gabriella', Offshore Israel and License #380 'Yitzhak' Offshore Israel Prepared according to National Instrument 51-101 As of August 31, 2011", "Interim Report for License #378 'Gabriella' Offshore Israel", July 2010, and "Report on the Hydrocarbon Potential of License #380 'Yitzhak' Offshore Israel", October 2010; and numerous other reports and files on other wells within the offshore Israel.

One discovery, the Middle Jurassic interval, and three other prospective intervals have been evaluated on the Gabriella Block. The prospective intervals are the Gevar Am, Miocene, and Talme Yafe. The discovery and prospective intervals are illustrated in Figure 3.

Petrophysical evaluations have been performed by Adira, NSAI, and Baker RDS, primarily on the Jurassic interval because that is where the most complete log suite is available, and on various other wells with digital log curves. None of the wells had complete suites of log curves across the entire logged interval. The Yam Yafo 1, Yam West 1, and the Yam 2 wells had the most usable set of log curves for the Jurassic carbonates. However, over most of the upper intervals these wells had only a sonic log for porosity determination. None of the wells had a usable photoelectric curve, which makes lithology determination using log data alone difficult. Shale volumes were predicted using a linear gamma ray conversion when the gamma ray log was available. Total porosity was calculated predominantly from sonic log measurements or, where available, from bulk density or density/neutron measurements. Water saturation calculations were performed using two models, the standard Archie model and the Simandoux shaly sand model. A formation water resistivity of 0.04 ohm-meters was calculated from Pickett plot analysis.

To determine net reservoir intervals, the following criteria were used: shale volume less than 50 percent and porosity greater than 3 percent. Gross interval thicknesses were determined for those intervals that calculated net pay. Net-to-gross ratios were calculated by dividing the net pay values by the gross interval thicknesses. Ranges for porosity and water saturation were then determined for input into the Monte Carlo simulation.

For the low side case, in general, gross rock volumes were determined by taking the gross intervals of the units to a structural level the gross thickness below the lowest well on the structure or to a fault independent closure. For the high side case, the gross interval was taken to a structural level just above the spill point. Gross rock volumes off the block were not considered in this assessment.

Reservoir parameters used to estimate resources are based on available data within the Gabriella Block and our experience with similar depositional environments. Bottomhole pressure and temperature data are based on a regional geothermal gradient map and formation pressure test data. Values were estimated for each reservoir and prospect based on estimated depths to formation. Fluid properties are based on black oil and Z-factor correlations using estimated input values for pressure, temperature, oil/condensate and gas gravity, and total gas-oil ratio or yield. Primary recovery factors associated with hydrocarbons initially-in-place (HIIP) are estimated based on anticipated fluid type, expected drive mechanism, depositional environment, and analogy to fields under similar development and operational conditions.

Overall, for each prospective reservoir and prospect, probabilistic ranges for porosity, hydrocarbon saturation, initial formation volume factor, and recovery factor of HIIP were estimated for input into the Monte Carlo simulation.

Contingent resources were estimated for the Middle Jurassic interval because the Yam Yafo 1 well logged pay in the Barnea, Shederot, and Zohar Formations and successfully tested oil in the Shederot and Zohar Formations. The input parameters are shown in the Monte Carlo input distribution summary in Figure 4.

Prospective resources were estimated for Gevar Am, Miocene, and Talme Yafe Formations on the Gabriella Block because the formation evaluation is inconclusive across those intervals in the respective wells. The Miocene potential is unpenetrated on the block. The input parameters are shown in the Monte Carlo input distribution summaries shown in Figure 5.

Note: For the purposes of this report, we used technical data including, but not limited to, well logs, geologic maps, and seismic data.

	Unrisked Contingent Resources
	Gross (100 Percent)		Company Gross Interest⁽¹⁾
	Light/Medium Oil	Gas⁽²⁾	Oil Equivalent	Light/Medium Oil	Gas	Oil Equivalent
Category	(MMbbl)	(Bcf)	(MMBOE)	(MMbbl)	(Bcf)	(MMBOE)

Low Estimate (1C)	29.7	29.7	34.6	4.4	4.4	5.2
Best Estimate (2C)	110.1	110.1	128.4	16.5	16.5	19.3
High Estimate (3C)	264.4	264.4	308.5	39.7	39.7	46.3

⁽¹⁾	Adira owns a 15 percent company gross interest in these properties.
⁽²⁾	Based on well test information, a gas-oil ratio of 1,000 standard cubic feet per barrel was estimated for the 1C, 2C, and 3C estimates.

		Unrisked Prospective Resources
			Gross (100 Percent)		Company Gross Interest⁽¹⁾
Prospective		Gas	Condensate	Oil Equivalent	Gas	Condensate	Oil Equivalent
Reservoir	Category	(Bcf)	(MMbbl)	(MMBOE)	(Bcf)	(MMbbl)	(MMBOE)

Gevar Am	Low Estimate	52.2	1.1	9.8	7.8	0.2	1.5
	Best Estimate	209.3	5.7	40.6	31.4	0.9	6.1
	High Estimate	670.7	21.7	133.5	100.6	3.3	20.0

Miocene	Low Estimate	69.9	1.4	13.0	10.5	0.2	2.0
	Best Estimate	257.1	7.0	49.8	38.6	1.0	7.5
	High Estimate	773.5	25.7	154.6	116.0	3.8	23.2

Talme Yafe	Low Estimate	39.6	0.8	7.4	5.9	0.1	1.1
	Best Estimate	174.7	4.7	33.8	26.2	0.7	5.1
	High Estimate	562.6	18.6	112.3	84.4	2.8	16.8

		Sincerely,

		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699


			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer




	/s/ Richard B. Talley, Jr.		/s/ David E. Nice
By:		By:
	Richard B. Talley, Jr., P.E. 102425		David E. Nice, P.G. 346
	Vice President		Vice President

Date	Signed: March 12, 2012	Date	Signed: March 12, 2012

	/s/ Richard B. Talley, Jr.
By:
	Richard B. Talley, Jr., P.E.
	Vice President
	Texas Registration No. 102425

	Geologic Risk Elements (Percent)				Probability of
Prospective	Trap	Reservoir	Source	Timing/	Geologic Success
Reservoir	Integrity	Quality	Evaluation	Migration	(Percent)

Gevar Am	60	50	90	90	24
Miocene	60	30	90	90	15
Talme Yafe	60	50	90	90	24

	/s/ David E. Nice
By:
	David E. Nice, P.G.
	Vice President
	Texas Registration No. 346

TECHNICAL DISCUSSION
1.0	Overview	1
2.0	Block 378 (Gabriella) History	1
3.0	Geology	2
	3.1 Regional Overview	2
	3.2 Stratigraphy	3
	3.3 Structure and Hydrocarbon Migration	4
4.0	Source Evaluation	4
5.0	Data and Methodology	5
6.0	Reservoir Parameters	5
7.0	Contingent Resources	6
8.0	Prospective Resources	6

FIGURES
Regional Location Map		1
Stratigraphic Column		2
Discovery and Prospective Reservoir Outlines		3
Monte Carlo Input Distribution Summary
	Contingent Resources	4
	Prospective Resources	5

Gross Rock Volume (Acre-feet)		Area (Acres)		Average Gross		Net-to-Gross Ratio (Decimal)		Matrix Porosity (Decimal)
Normal Distribution		Lognormal Distribution		Thickness (Feet)⁽¹⁾		Normal Distribution		Normal Distribution
Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate

516,889	7,630,908	2,002	10,291	258	742	0.500	1.000	0.020	0.080

						Initial Formation
Fracture Porosity (Decimal)		Matrix Oil Saturation (Decimal)		Fracture Oil Saturation (Decimal)		Volume Factor (rb/stb)⁽²⁾		Oil Recovery Factor (Decimal)
Triangular Distribution		Normal Distribution		Triangular Distribution		Normal Distribution		Normal Distribution
Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate

0.0025	0.0200	0.600	0.800	0.800	1.000	2.200	1.500	0.138	0.263

⁽¹⁾	Average gross thickness is calculated by dividing the gross rock volume by the area.
⁽²⁾	The abbreviation rb/stb represents reservoir barrels per stock tank barrel.

					Gas Formation
	Porosity (Decimal)		Gas Saturation (Decimal)		Volume Factor (scf/rcf)⁽³⁾		Gas Recovery Factor (Decimal)
Prospective	Normal Distribution		Normal Distribution		Normal Distribution		Normal Distribution
Reservoir	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate	Low Estimate	High Estimate

Gevar Am	0.150	0.300	0.470	0.730	258	258	0.550	0.750
Miocene	0.180	0.280	0.480	0.660	173	173	0.550	0.750
Talme Yafe	0.180	0.270	0.500	0.700	239	239	0.550	0.750

3.0	GEOLOGY

3.1	REGIONAL OVERVIEW