Exhibit 99.2

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Manager of the Petroleum Reserves Group

BHP Billiton Petroleum

1360 Post Oak Boulevard, Suite 150

Houston, Texas 77056

Dear Sir:

In accordance with your request, we have estimated the proved reserves and future revenue, as of 30 June 2011, to the BHP Billiton
Petroleum (BHP) interest in certain gas properties located in the Fayetteville Shale, Arkansas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute
approximately 25 percent of all proved reserves owned by BHP. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the
exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities  Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for BHPs
use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the gas reserves and future net revenue to the BHP interest in these properties, as of 30 June 2011, to be:



|                               |  |              |              |  |                         |  |             |       |  |  |                     |  |  |  |             | 
|------------------------------ |  | ------------ | ------------ |  | ----------------------- |  | ----------- | ----- |  |  | ------------------- |  |  |  | ----------- | 
|                               |  | Gas Reserves |              |  | Future Net Revenue (M$) | 
|Category                       |  | Gross(MMCF)  |              |  | Net(MMCF)               |  |             | Total |  |  | Present Worthat 10% | 
|Proved Developed Producing     |  |              | 5,823,015.5  |  |                         |  | 1,076,819.3 |       |  |  | 2,155,998.0         |  |  |  | 1,131,872.1 | 
|Proved Developed Non-Producing |  |              | 51,963.9     |  |                         |  | 8,302.5     |       |  |  | 14,980.4            |  |  |  | 8,592.4     | 
|Proved Undeveloped             |  |              | 8,798,696.0  |  |                         |  | 1,535,709.5 |       |  |  | 1,445,613.0         |  |  |  | 5,906.4     | 
|                               |  |              |              |  |                         |  |             |       |  |  |                     |  |  |  |             | 
|Total Proved                   |  |              | 14,673,676.0 |  |                         |  | 2,620,831.3 |       |  |  | 3,616,591.2         |  |  |  | 1,146,371.0 | 

Totals may not add because of rounding.

Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. These properties have never
produced commercial volumes of condensate.

The estimates shown in this report are for proved reserves. No study was made to
determine whether probable or possible reserves might be established for these properties. Proved undeveloped locations in this report are based on BHPs planned drilling program of operating eight rigs for five years for the operated
properties and the expectation that historical drilling rates will be maintained for nonoperated properties for four years. Estimates of proved undeveloped reserves have been included for certain locations that generate positive future net revenue
but have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators declared intent to drill these wells,
as evidenced by BHPs internal budget, reserves estimates, and price forecast. This report does not include any value that could be attributed to interests in undeveloped acreage



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beyond those tracts for which undeveloped reserves have been estimated. Reserves categorisation 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.

Future gross
revenue to the BHP 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 any income taxes. The
future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or
undiscounted, 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 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. Future net revenue estimates include BHPs estimates of the costs to abandon the wells and production facilities, net of any salvage value. Abandonment costs are shown herein as
capital costs.

The gas price used in this report is based on the 12-month unweighted arithmetic average of the
first-day-of-the-month Henry Hub spot price for each month in the period July 2010 through June 2011. The average price of $4.21 per MMBTU is adjusted for energy content, transportation fees, and a regional price differential of $0.07 per MCF. The
adjusted gas price of $3.01 per MCF is held constant throughout the lives of the properties.

Lease and well operating costs
used in this report are based on operating expense records of BHP. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.
Headquarters general and administrative overhead expenses of BHP are included to the extent that they are covered under joint operating agreements for the operated properties. Lease and well operating costs are held constant throughout the lives of
the properties. Capital costs are included as required for workovers, new development wells, 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 BHP
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 BHP 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. Proved
reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market
conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates 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 reserves, and that our projections of future production will prove consistent with actual performance. If the reserves 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.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, well test
data, production data, historical price and cost information, and property ownership interests. The



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reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and
statistical analysis, that we considered to be appropriate and necessary to categorise and estimate reserves in accordance with SEC definitions and guidelines. 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 BHP, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting
geoscience, performance, and work data are on file in our office. The titles 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 set forth in the SPE Standards. 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.



|    |  |                                  |  |  |  |                                          |  |                                     
|--- |  | -------------------------------- |  |  |  | ---------------------------------------- |  | ------------------------------------
|    |  |                                  |  |  |  | Sincerely,                              
|    |  |                                  | 
|    |  |                                  |  |  |  | NETHERLAND, SEWELL & ASSOCIATES, INC.   
|    |  |                                  |  |  |  | Texas Registered Engineering Firm F-2699
|    |  |                                  |  | 
|    |  |                                  |  |  |  | By:                                      |  | /s/ C.H. (Scott) Rees III           
|    |  |                                  |  |  |  |                                          |  | C.H. (Scott) Rees III, P.E.         
|    |  |                                  |  |  |  |                                          |  | Chairman and Chief Executive Officer
|    |  |                                  |  | 
|By: |  | /s/ Emery M. Petrof III          |  |  |  | By:                                      |  | /s/ William J. Knights              
|    |  | Emery M. Petrof III, P.E. 102316 |  |  |  |                                          |  | William J. Knights, P.G. 1532       
|    |  | Vice President                   |  |  |  |                                          |  | Vice President                      
|    |  |                                  |  | 
|    |  | Date Signed: 13 July 2011        |  |  |  |                                          |  | Date Signed: 13 July 2011           

EMP:SBB



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 Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X
Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932,
Extractive Activities  Oil and Gas, and (3) the SECs Compliance and Disclosure Interpretations.

(1)
Acquisition of properties.Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including
mineral rights is purchased in fee, brokers fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive
mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves,
an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest:



| | (i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
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| | (ii) | Same environment of deposition;
| | ---- | -------------------------------



| | (iii) | Similar geological structure; and
| | ----- | ---------------------------------



| | (iv) | Same drive mechanism.
| | ---- | ---------------------

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favourable in the analog than in the
reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or
semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other
non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original
reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5)
Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves
estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category
that can be expected to be recovered:



| | (i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new
well; and
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| | (ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
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Supplemental definitions from the 2007 Petroleum Resources Management System: 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.


(7) Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating,
gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:



| | (i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing
ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing,
tubing, pumping equipment, and the wellhead assembly.
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| | (iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage
tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
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| | (iv) | Provide improved recovery systems.
| | ---- | ----------------------------------

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or
field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource,
means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as
defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is
the sum of reserves remaining as of a given date and cumulative production as of that date.



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(12)Exploration
costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type
stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include
depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:



| | (i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists,
geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defence, and the maintenance of
land and lease records.
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| | (iii) | Dry hole contributions and bottom hole contributions.
| | ----- | -----------------------------------------------------



| | (iv) | Costs of drilling and equipping exploratory wells.
| | ---- | --------------------------------------------------



| | (v) | Costs of drilling exploratory-type stratigraphic test wells.
| | --- | ------------------------------------------------------------

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are
associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localised geological
features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas
producing activities.



| | (i) | Oil and gas producing activities include:
| | --- | -----------------------------------------



| | (A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (oil and gas) in their natural states and original locations;
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| | (B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
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| | (C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction,
installation, and maintenance of field gathering and storage systems, such as:
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| | (1) | Lifting the oil and gas to the surface; and
| | --- | -------------------------------------------



| | (2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
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| | (D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended
to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
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Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a terminal
point, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:



| | a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading,
the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means
hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.



| | (ii) | Oil and gas producing activities do not include:
| | ---- | ------------------------------------------------



| | (A) | Transporting, refining, or marketing oil and gas;
| | --- | -------------------------------------------------



| | (B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a
revenue interest in such production;
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| | (C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
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| | (D) | Production of geothermal steam.
| | --- | -------------------------------

(17) Possible reserves.Possible reserves are those additional reserves that are less certain to be recovered than probable
reserves.



| | (i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible
reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | (iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed
for probable reserves.
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| | (iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations
within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
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| | (v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation
that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that
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| | have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas
that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated
gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do
not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

(18)Probable reserves.Probable reserves are those additional reserves that are less certain to be recovered than proved reserves
but which, together with proved reserves, are as likely as not to be recovered.



| | (i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.
When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
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| | (ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if
the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with
the proved reservoir.
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| | (iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for
proved reserves.
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| | (iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
| | ---- | ------------------------------------------------------------------------------

(19) Probabilistic estimate.The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the
geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.



| | (i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and
facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
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| | (A) | Costs of labour to operate the wells and related equipment and facilities.
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| | (B) | Repairs and maintenance.
| | --- | ------------------------



| | (C) | Materials, supplies, and fuel consumed and supplies utilised in operating the wells and related equipment and facilities.
| | --- | -------------------------------------------------------------------------------------------------------------------------



| | (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
| | --- | ------------------------------------------------------------------------------------------------------------



| | (E) | Severance taxes.
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| | (ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To
the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and
amortisation of capitalised acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
| | ---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

(21) Proved area.The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible  from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations 
prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to
extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.



| | (i) | The area of the reservoir considered as proved includes:
| | --- | --------------------------------------------------------



| | (A) | The area identified by drilling and limited by fluid contacts, if any, and
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| | (B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas
on the basis of available geoscience and engineering data.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless
geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
| | ---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves
may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
| | ----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the
proved classification when:
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| | (A) | Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved
for development by all necessary parties and entities, including governmental entities.
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| | (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during
the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

(23) Proved properties. Properties with
proved reserves.



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(24) Reasonable
certainty. If deterministic methods are used, reasonable certainty means 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. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and
geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology.Reliable technology is a grouping of one or more technologies (including computational methods) that has
been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the
production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically
producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain
prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).



Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities  Oil
and Gas: 932-235-50-30 A standardised measure of discounted future net cash flows relating to an
entitys interests in both of the following shall be disclosed as of the end of the year:  a.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)  b.
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the
properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardised measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for
which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:  a.
Future cash inflows. These shall be computed by applying prices used in estimating the entitys proved oil and gas 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.




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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 entitys proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and
allowances relating to the entity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.
Standardised measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.


(27) Reservoir. A porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion
may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service
well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for
injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well
is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes
tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as exploratory type if not drilled in a known area or development type if drilled in a
known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.



| | (i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless
evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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| | (ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within
five years, unless the specific circumstances, justify a longer time.
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From the SECs Compliance and Disclosure Interpretations (26 October 2009): Although several types of projects  such as constructing
offshore platforms and development in urban areas, remote locations or environmentally sensitive locations  by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must
always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.




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Factors that a company should consider in determining whether or not circumstances
justify recognising reserves even though development may extend past five years include, but are not limited to, the following:  

The companys level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum
number of wells necessary to maintain the lease generally would not constitute significant development activities);  

The companys historical record at completing development of comparable long-term projects;  

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;  

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development
plan several times without taking significant steps to implement any of those plans, recognising proved undeveloped reserves typically would not be appropriate); and  

The extent to which delays in development are caused by external factors related to the physical operating environment (for example,
restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).




| | (iii) | Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology
establishing reasonable certainty.
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(32) Unproved properties. Properties with no proved reserves.



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