|July 17, 2008
|-------------

|Mr. John FolnovicTrue North Energy Corporation1400 Woodloch Forest Drive, Suite 530The Woodlands, Texas 77380
|-------------------------------------------------------------------------------------------------------------

|Dear Mr. Folnovic:
|------------------

In accordance with your request, we have estimated the proved developed producing and probable reserves and future revenue, as of April 30, 2008, to the True North Energy Corporation (True North) interest in certain
oil and gas properties located in Old Ocean Field, Brazoria County, Texas, as listed in the accompanying tabulations. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates
of proved reserves and future revenue in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and conform to the Statement of Financial Accounting Standards No. 69,
except that per-well overhead expenses and future income taxes are excluded for all properties. Definitions are presented immediately following this letter. Inasmuch as the SEC does not recognize probable reserves, the sections of this report
dealing with such reserves should not be used in filings with the SEC.

As presented in the accompanying summary projections, Tables I and II, we estimate the net reserves and future net revenue to the True North interest in these properties, as of April 30, 2008, to be:

|                           |  | Net Reserves |  | Future Net Revenue ($)
|-------------------------- |  | ------------ |  | ----------------------
|                           |  |              |  |                       
|                           |  | Oil          |  | Gas                   
|Category                   |  | (Barrels)    |  | (MCF)                 
|                           |  |              |  |                       
|                          
|Proved Developed Producing |  | 08,407       |  | 500,999               
|                          
|Probable                   |  | 82,595       |  | 512,936               

The oil reserves shown include crude oil and condensate.  Oil volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard
temperature and pressure bases.

The estimates shown in this report are for proved developed producing and probable reserves.  Our study indicates that there are no proved developed non-producing or proved undeveloped reserves for these properties at
this time.  No study was made to determine whether possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which
undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have
not been adjusted for risk.  For each reserves category this report includes one-line summaries of reserves, economics, and basic data by lease.

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Future gross revenue to the True North interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses
but before consideration of federal income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should
not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities.  We have not investigated
possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment or the cost of
abandoning the properties.

Oil prices used in this report are based on a April 30, 2008, West Texas Intermediate posted price of $110.00 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials.
Gas prices used in this report are based on a April 30, 2008, Henry Hub spot market price of $10.935 per MMBTU and are adjusted by lease for energy content, transportation fees, and regional price differentials.  All prices are held constant
throughout the lives of the properties.

Lease and well operating costs used in this report are based on operating expense records of True North and include only direct lease- and field-level costs. As requested, these costs do not include the per-well
overhead expenses allowed under joint operating agreements, nor do they include the headquarters general and administrative overhead expenses of True North. Lease and well operating costs are held constant throughout the lives of the properties.
Capital costs are included as required for workovers, a new development well, and production equipment. The future capital costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the True North interest. Therefore, our estimates of reserves and future revenue do not include
adjustments for the settlement of any such imbalances; our projections are based on True North receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related
thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from
assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering
and geologic.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were
obtained from True North Energy Corporation, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on

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file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

|Sincerely,
|----------

|NETHERLAND, SEWELL & ASSOCIATES, INC.
|-------------------------------------

|/s/ C.H. (Scott) Rees III, P.E.
|-------------------------------

|By:
|---

|C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer
|---------------------------------------------------------------

|/s/ Danny D. Simmons, P.E.By:Danny D. Simmons, P.E.President and Chief Operating OfficerDate Signed: July 17, 2008
|------------------------------------------------------------------------------------------------------------------

|/s/ David E. Nice, P.G.By:David E. Nice, P.G.Vice PresidentDate Signed: July 17, 2008
|-------------------------------------------------------------------------------------

|LWC:PSF
|-------

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.

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|DEFINITIONS OF OIL AND GAS RESERVES
|-----------------------------------

Adapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers

PROVED RESERVES ________________________________________________________________________The following definitions of proved reserves are set forth in U.S. Securities and
Exchange Commission (SEC) Regulation S-X Section 210.4 -10(a). Also included (in italics) are certain subsequent interpretations set forth in the SEC's Corporate Finance Accounting Interpretations and Guidance [SEC Interpretations]; SEC Staff
Accounting Bulletins: Topic 12 [SEC Topic 12]; the Statement of Financial Accounting Standards No. 69 [FASB 69]; and the 2007 Petroleum Resources Management System prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers
(SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE) [SPE-PRMS].

Proved Oil and Gas Reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.  Prices include consideration of changes
in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The determination of reasonable certainty is generated by supporting geological and engineering data. There must be data available which indicate that assumptions such as decline rates,
recovery factors, reservoir limits, recovery mechanisms and volumetric estimates, gas-oil ratios or liquid yield are valid. If the area in question is new to exploration and there is little supporting data for decline rates, recovery factors,
reservoir drive mechanisms etc., a conservative approach is appropriate until there is enough supporting data to justify the use of more liberal parameters for the estimation of proved reserves. The concept of reasonable certainty implies that, as
more technical data becomes available, a positive, or upward, revision is much more likely than a negative, or downward, revision.

Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and marketing arrangements, ownership and/or
entitlement terms and regulatory requirements that are extant on the effective date of the estimate. An anticipated change in conditions must have reasonable certainty of occurrence; the corresponding investment and operating expense to make that
change must be included in the economic feasibility at the appropriate time. These conditions include estimated net abandonment costs to be incurred and duration of current licenses and permits.

If oil and gas prices are so low that production is actually shut-in because of uneconomic conditions, the reserves attributed to the shut-in properties can no longer be classified as
proved and must be subtracted from the proved reserve data base as a negative revision.  Those volumes may be included as positive revisions to a subsequent year's proved reserves only upon their return to economic status. [SEC Interpretations]

A standardized measure of discounted future net cash flows relating to an enterprise's interests in (a) proved oil and gas reserves (paragraph 10) and (b) oil and gas subject to
purchase under long-term supply, purchase, or similar agreements and contracts in which the enterprise participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves
(paragraph 13) shall be disclosed as of the end of the year. The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. The following information shall be
disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraph 12:

|a. | Future cash inflows. These shall be computed by applying year-end prices of oil and gas relating to the enterprise's proved reserves to the year-end quantities of those reserves. Future price changes shall be
considered only to the extent provided by contractual arrangements in existence at year-end.                                                                                                                                                                                    
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|  
|b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.                                                                           
|  
|c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows
relating to the enterprise's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to permanent differences and tax credits and allowances relating to the enterprise's proved oil
and gas reserves.
|  
|d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.                                                                                                                                                                                                                                                                                                                              
|  
|e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.                                                                                                                                                                                                                                                                                                               
|  
|f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. [FASB 69]                                                                                                                                                                                                                                                                                                                                                         
|  

Definitions - Page 1 of 4

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|DEFINITIONS OF OIL AND GAS RESERVES
|-----------------------------------

Adapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.
In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Proved reserves may be attributed to a prospective zone if a conclusive formation test has been performed or if there is production from the zone at economic rates. It is clear to the
SEC staff that wireline recovery of small volumes (e.g. 100 cc) or production of a few hundred barrels per day in remote locations is not necessarily conclusive. Analyses of open-hole well logs which imply that an interval is productive are not
sufficient for attribution of proved reserves. If there is an indication of economic producibility by either formation test or production, the reserves in the legal and technically justified drainage area around the well projected down to a known
fluid contact or the lowest known hydrocarbons, or LKH may be considered to be proved.

In order to attribute proved reserves to legal locations adjacent to such a well (i.e. offsets), there must be conclusive, unambiguous technical data which supports reasonable certainty
of production of such volumes and sufficient legal acreage to economically justify the development without going below the shallower of the fluid contact or the LKH. In the absence of a fluid contact, no offsetting reservoir volume below the LKH
from a well penetration shall be classified as proved.

Upon obtaining performance history sufficient to reasonably conclude that more reserves will be recovered than those estimated volumetrically down to LKH, positive reserve revisions
should be made. [SEC Interpretations]

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable
certainty that those reserves can be recovered in future years under existing economic and operating conditions.  The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves
cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs
in the same field which are producing or have demonstrated the ability to produce on a formation test. [SEC Topic 12]

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

If an improved recovery technique which has not been verified by routine commercial use in the area is to be applied, the hydrocarbon volumes estimated to be recoverable cannot be
classified as proved reserves unless the technique has been demonstrated to be technically and economically successful by a pilot project or installed program in that specific rock volume. Such demonstration should validate the feasibility study
leading to the project. [SEC Interpretations]

|Estimates of proved reserves do not include the following:
|----------------------------------------------------------

|(A) | oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";                                                                       
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(B) | crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
|   
|(C) | crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and                                                                                                
|   
|(D) | crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.                                                            
|   

Geologic and reservoir characteristic uncertainties such as those relating to permeability, reservoir continuity, sealing nature of faults, structure and other unknown characteristics
may prevent reserves from being classified as proved. Economic uncertainties such as the lack of a market (e.g. stranded hydrocarbons), uneconomic prices and marginal reserves that do not show a positive cash flow can also prevent reserves from
being classified as proved. Hydrocarbons "manufactured" through extensive treatment of gilsonite, coal and oil shales are mining activities reportable under Industry Guide 7. They cannot be called proved oil and gas reserves. However, coal bed
methane gas can be classified as proved reserves if the recovery of such is shown to be economically feasible.

In developing frontier areas, the existence of wells with a formation test or limited production may not be enough to classify those estimated hydrocarbon volumes as proved reserves.
Issuers must demonstrate that there is reasonable certainty that a market exists for the hydrocarbons and that an economic method of extracting, treating and transporting them to market exists or is feasible and is likely to exist in the near
future. A commitment by the company to develop the necessary production, treatment and transportation infrastructure is essential to the attribution of proved undeveloped reserves. Significant lack of progress on the development of such reserves may
be evidence of a lack of such commitment.

|Definitions - Page 2 of 4
|-------------------------

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|DEFINITIONS OF OIL AND GAS RESERVES
|-----------------------------------

Adapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers

Affirmation of this commitment may take the form of signed sales contracts for the products; request for proposals to build facilities; signed acceptance of bid proposals; memos of understanding between the
appropriate organizations and governments; firm plans and timetables established; approved authorization for expenditures to build facilities; approved loan documents to finance the required infrastructure; initiation of construction of facilities;
approved environmental permits etc. Reasonable certainty of procurement of project financing by the company is a requirement for the attribution of proved reserves.  An inordinately long delay in the schedule of development may introduce doubt
sufficient to preclude the attribution of proved reserves.

The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether
hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the
conclusion that such approvals and renewal are a matter of course. [SEC Interpretations]

Companies should report reserves of natural gas liquids which are net to their leasehold interests, i.e., that portion recovered in a processing plant and allocated to the leasehold
interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instructions to Item 3 of Securities Act Industry Guide 2 and report such reserves separately and describe the
nature of the ownership. [SEC Topic 12]

Proved Developed Oil and Gas Reserves.Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment
and operating methods.  Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as
"proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or bore hole stimulation treatment would be examples of properties
with proved developed reserves since the majority of the expenditures to develop the reserves has already been spent.

Proved developed reserves from improved recovery techniques can be assigned after either the operation of an installed pilot program shows a positive production response to the
technique or the project is fully installed and operational and has shown the production response anticipated by earlier feasibility studies. In the case with a pilot, proved developed reserves can be assigned only to that volume attributable to the
pilot's influence. In the case of the fully installed project, response must be seen from the full project before all the proved developed reserves estimated can be assigned.  If a project is not following original forecasts, proved developed
reserves can only be assigned to the extent actually supported by the current performance. An important point here is that attribution of incremental proved developed reserves from the application of improved recovery techniques requires the
installation of facilities and a production increase.  [SEC Interpretations]

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

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

Proved Undeveloped Reserves.Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.  Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

The SEC staff points out that this definition contains no mitigating modifier for the word certainty. Also, continuity of production requires more than the technical indication of
favorable structure alone (e.g. seismic data) to meet the test for

|Definitions - Page 3 of 4
|-------------------------

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|DEFINITIONS OF OIL AND GAS RESERVES
|-----------------------------------

Adapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers

proved undeveloped reserves.  Generally, proved undeveloped reserves can be claimed only for legal and technically justified drainage areas offsetting an existing productive well (but structurally no lower than
LKH). If there are at least two wells in the same reservoir which are separated by more than one legal location and which show communication (reservoir continuity), proved undeveloped reserves could be claimed between the two wells, even though the
location in question might be more than an offset well location away from any of the wells. In this illustration, seismic data could be used to help support this claim by showing reservoir continuity between the wells, but the required data would be
the conclusive evidence of communication from production or pressure tests. The SEC staff emphasizes that proved reserves cannot be claimed more than one offset location away from a productive well if there are no other wells in the reservoir, even
though seismic data may exist.  The use of high-quality, well calibrated seismic data can improve reservoir description for performing volumetrics (e.g. fluid contacts). However, seismic data is not an indicator of continuity of production and,
therefore, can not be the sole indicator of additional proved reserves beyond the legal and technically justified drainage areas of wells that were drilled. Continuity of production would have to be demonstrated by something other than seismic data.

In a new reservoir with only a few wells, reservoir simulation or application of generalized hydrocarbon recovery correlations would not be considered a reliable method to show
increased proved undeveloped reserves. With only a few wells as data points from which to build a geologic model and little performance history to validate the results with an acceptable history match, the results of a simulation or material balance
model would be speculative in nature. The results of such a simulation or material balance model would not be considered to be reasonably certain to occur in the field to the extent that additional proved undeveloped reserves could be recognized.
The application of recovery correlations which are not specific to the field under consideration is not reliable enough to be the sole source for proved reserve calculations.

Reserves cannot be classified as proved undeveloped reserves based on improved recovery techniques until such time that they have been proved effective in that reservoir or an analogous
reservoir in the same geologic formation in the immediate area.  An analogous reservoir is one having at least the same values or better for porosity, permeability, permeability distribution, thickness, continuity and hydrocarbon
saturations.

|(g) | Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins states:                                                                                                                                                                                                                                       
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|    | In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs
in the same field which are producing or have demonstrated the ability to produce on a formation test.
|   

If the combination of data from open-hole logs and core analyses is overwhelmingly in support of economic producibility and the indicated reservoir properties are analogous to similar
reservoirs in the same field that have produced or demonstrated the ability to produce on a conclusive formation test, the reserves may be classified as proved. This would probably be a rare event especially in an exploratory situation. The essence
of the SEC definition is that in most cases there must at least be a conclusive formation test in a new reservoir before any reserves can be considered to be proved. [SEC Interpretations]

|PROBABLE AND POSSIBLE RESERVES
|------------------------------

The SPE-PRMS sets forth additional categorizations beyond proved reserves.  However, inasmuch as the SEC does not recognize probable or possible reserves, the sections of this report dealing with such reserves should
not be used in filings with the SEC.

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

It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there
should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.  Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are
less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves.Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable
Reserves.

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic
methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and
interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir
by a defined project.  Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

|Definitions - Page 4 of 4
|-------------------------

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