EXHIBIT 99.3

RALPH E.DAVIS

ASS0CIATES, I N C.

May 29, 2012

Cook Inlet Energy

601 W. 5th Ave, Suite 310

Anchorage, Alaska 99501

Gentlemen

At the request of Miller Petroleum, Inc. ("Miller"), your parent company, in connection with Miller's Annual Report to its shareholders, the firm of Ralph E. Davis Associates, Inc ("Davis") of Houston, Texas USA has prepared an estimate of the oil and natural gas reserves on specific leaseholds in which Cook Inlet Energy (CIE) has interest for CIE and Miller. This report presents our estimate of the proved developed producing, proved developed non-producing and proved undeveloped as well as the probable and possible reserves anticipated to be produced from those leaseholds and remaining as of April 30, 2011. The subject properties are located in the State of Alaska, USA. This report was completed on May 29, 2012. The report is reissued as a revised report from that previously prepared and dated June 13, 2011 to exclude the Redoubt Shoal North Stepout location as a proved location.

Davis has reviewed 100% of CIE's proved, probable and possible properties located in Alaska. It is our opinion that these properties represent all of CIE's oil and gas assets that may be classified as proved, probable or possible as per the Securities Exchange Commission directives as detailed later in this report.

The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210-Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975. A summation of these definitions is included as a portion of this letter.

1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.com Worldwide Energy Consultants Since 1924

RALPH E. DAVIS

ASS0CIATES, INC.  

Cook Inlet Energy	May 29, 2012
	Page 2

It should be understood that the various reserve categories have different risk associated with them. Proved reserves are more likely to be produced than probable reserves; and, probable reserves are more likely to be produced than possible reserves. Therefore the different reserve categories should not be considered to be directly additive.

We have also estimated the future net revenue and discounted present value associated with these reserves as of April 30, 2011, utilizing a scenario of non-escalated product prices as well as non­escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.

The results of our study are summarized as follows:

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Cook Inlet Energy

As of April 30, 2011

	PROVED
	PRODUCING		NON- PRODUCING		UNDEVELOPED		TOTAL
Net Reserves
Oil/Condensate-MBbls		1,585		786.6		6,486		8,858
Gas-MMCF		400.3		1,339		584		2,323
Income Data (M$)
Future Gross Revenue	$	117,281	$	64,753	$	465,450	$	647,484
Ad Valorem and Other Taxes	$	2,521	$	1,393	$	10,004	$	13,917
Severance Taxes	$	573	$	279	$	2,308	$	3,159
Operating Costs	$	56,856	$	17,071	$	25,010	$	98,936
Capital Costs	$	0	$	18,419	$	60,292	$	78,711
Future Net Income (FNI)	$	57,331	$	27,592	$	367,837	$	452,760
FNI @ 10%	$	41,984	$	20,908	$	238,832	$	301,725

Note: There are differences in the addition as a result of computer program rounding of numbers.

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

RALPH E. DAVIS

ASS0CIATES, INC.  

Cook Inlet Energy	May 29, 2012
	Page 3

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Cook Inlet Energy

As of April 30, 2011

	PROBABLE
	NON- PRODUCING		UNDEVELOPED		TOTAL
Net Reserves
Oil/Condensate-MBbls		0		7,306		7,306
Gas-MMCF		6,456		3,677		10,132
Income Data (M$)
Future Gross Revenue	$	43,448	$	545,677	$	589,125
Ad Valorem and Other Taxes	$	939	$	11,730	$	12,669
Severance Taxes	$	0	$	2,605	$	2,605
Operating Costs	$	2,786	$	29,981	$	32,767
Capital Costs	$	4,150	$	124,261	$	128,411
Future Net Income (FNI)	$	35,574	$	377,100	$	412,674
FNI @ 10%	$	24,149	$	208,768	$	232,917

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Cook Inlet Energy

As of April 30, 2011

	POSSIBLE
		UNDEVELOPED
Net Reserves
Oil/Condensate-MBbls			1,049
Gas-MMCF			238,244
Income Data (M$)
Future Gross Revenue		$	1,677,738
Ad Valorem and Other Taxes		$	36,231
Severance Taxes		$	372
Operating Costs		$	100,010
Capital Costs		$	415,990
Future Net Income (FNI)		$	1,125,136
FNI @ 10%		$	663,943

Note: There are differences in the addition as a result of computer program rounding of numbers.

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

RALPH E. DAVIS

ASS0CIATES, INC.  

Cook Inlet Energy	May 29, 2012
	Page 4

Crude oil volumes are expressed in standard 42 gallon barrels. Gas volumes are expressed in million cubic feet (MMCF) at the official temperature of 60 degrees Farenheit and pressure base of 14.73 psia.

DATA SOURCE

Basic well and field data used in the preparation of this report were furnished by CIE. Records as they pertain to factual matters such as acreage controlled, the number and depths of wells, reservoir pressure and production history, the existence of contractual obligations to others and similar matters were accepted as presented.

Additionally, the analyses of these properties utilized not only the basic data on the subject wells but also data on analogous properties if needed. Well logs, ownership interest, revenues received from the sale of products and operating costs were furnished by CIE. No physical inspection of the properties was made nor any well tests conducted.

Operating cost data for the previous twelve month period for which data was available were provided by CIE along with an average of each property's lease operating expense and well operating expense for the same time period. This data was used to determine the direct cost of operation for each property or producing unit. In the case of properties that are currently not producing, CIE's 2012 budget for that property or estimates made by CIE were used.

RESERVE ESTIMATES

The reserves presented in this report have been estimated using engineering and geological methods widely accepted in the industry. For the proved developed producing, the estimates were made when considered to be definitive, using performance methods that utilize extrapolations of various historical data including, but not limited to, oil, gas and water production and pressure history. For the other proved producing, proved behind pipe reserves, proved undeveloped reserves, and probable and possible reserves estimates were made using volumetric methods.

The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. The quantities presented herein are estimated reserves of oil that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. The reserves are calculated using acceptable methods and procedures and are believed to be reasonable; however, future reservoir performance may justify revision of these estimates.

PRICING PROVISIONS

The unit price used throughout this report for crude oil, condensate and natural gas is based upon the appropriate price in effect the first trading day of each month from May 1, 2010 through April 1,2011 and averaged for the year.

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

RALPH E. DAVIS

ASS0CIATES, INC.  

Cook Inlet Energy	May 29, 2012
	Page 5

Crude Oil- The unit price used throughout this report for crude oil is based upon the average of prices for the above indicated period. An average crude oil price of $85.55 per barrel was held constant throughout the contract life of the property. Prices for liquid reserves scheduled for initial production at some future date were estimated using current prices on the same properties. Adjustments were made to this price as follows:

1. Plus $0.995 for non-Redoubt crude.

2. Minus $0.45 for Redoubt crude.

3. Minus the ANS discount of $1.715/bbl was used.

4. Minus a "CISPRI allowance" (a spill response coop) of $0.374/bbl.

5. Minus a shipping charge of $1.184/bbl.

6. Minus a pipeline tariff of $7.20/bbl.

7. Minus the pipeline tariff (KPL tariff) of $0.059/bbl.

Natural Gas- The unit price used throughout this report for natural gas is based upon the average of prices for the above indicated period. An average natural gas price of $4.14 per MMBTU was calculated then adjusted by the area differential calculated of $2.59 per MMBTU with a resultant area price of $6.73 per MMBTU. This price was held constant throughout the life of the property. Prices for gas reserves scheduled for initial production at some future date were estimated using current prices on the same properties

Costs - Drilling, operating and abandonment costs were supplied by CIE for each property and were held constant for this report. These costs are based upon Authorities for Expenditure for the actual project or are estimated based upon comparison to similar work within the same area.

FUTURE NET INCOME

Future net income is based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense.

Direct lease operating expense includes direct cost of operations of each lease or an estimated value for future operations based upon analogous properties. Lease operating expense and/or capital costs for drilling and completion were held constant throughout the remaining contract life of the properties.

GENERAL

Cook Inlet Energy has provided access to all of its accounts, records, geological and engineering data, reports and other information as required for this investigation. The ownership interests, product classifications relating to prices and other factual data were accepted as furnished without verification.

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

RALPH E. DAVIS

ASS0CIATES, INC.  

Cook Inlet Energy	May 29, 2012
	Page 6

No consideration was given in this report to potential environmental liabilities (except for a scheduled Performance Bond deposit required by the State of Alaska) which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

You should be aware that state regulatory authorities could, in the future, change the allocation of reserves allowed to be produced from a particular well in any reservoir, thereby altering the material premise upon which our reserve estimate may be based.

We have used all methods and procedures as is considered necessary under the circumstances to prepare this report.

If investments or business decisions are to be made in reliance on these estimates by anyone other than our client, such person with the approval of our client is invited to arrange a visit so that he can evaluate the assumptions made and the completeness and extent of the data available on which the estimates are made.

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on its estimates of reserves and future income for the subject properties.

Very truly yours,

RALPH E. DAVIS ASSOCIATES, INC.

L. B. Branum, P.E.

Vice President

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

RALPH E. DAVIS

ASS0CIATES, INC.

CERTIFICATE OF QUALIFICATION

I, Lloyd B. Branum, of 1717 St. James Place, Suite 460, Houston, Texas 77056 hereby certify:

1. I am an employee of Ralph E. Davis Associates, Inc., that has prepared an estimate of the oil and gas reserves on specific leaseholds in which Cook Inlet Energy has certain interests. The effective date of this evaluation is April 30, 2011.

2. I am Licensed Professional Engineer by the State of Texas, P.E. License number 42019.

3. I attended the University of Missouri at Rolla, Rolla, Missouri and graduated with a Bachelor of Science Degree in Petroleum Engineering in 1970. I have thirty eight years of experience in the Petroleum Industry of which over thirty years experience are in the conduct of evaluation and engineering studies relating to both domestic U.S. oil and gas fields and international energy assets.

4. I have prepared reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings in foreign countries, domestic regulatory filings, financial disclosures and corporate strategic planning. I personally supervised and participated in the evaluation of the Cook Inlet Energy properties that are the subject of this report.

5. I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Cook Inlet Energy or any affiliated organizations.

6. A personal field inspection of the properties was not made, however, such an inspection was not considered necessary in view of the information available from information, records and the files of the operator of the properties.

SIGNED: May 29, 2012

Lloyd. B. Branum, P.E.

Vice President

Ralph E. Davis Associates, Inc.

1717 St. James Place. Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 WIWI.ralphedavis.com

Worldwide Energy Consultants Since 1924

SECURITIES AND EXCHANGE COMMISSION

DEFINITIONS OF RESERVES

The following information is taken from the United States Securities and Exchange Commission:

PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975

Rules of General Application

§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

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.

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).

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

(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:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable 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

Securities and Exchange Commission	Page 2
§ 210.4-10 Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(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.

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.

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.

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.

(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.

(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.

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.

(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.

(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

Securities and Exchange Commission	Page 3
§ 210.4-10 Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

formation thickness or other geological discontinuities and that 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.

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

(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.

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.

(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.

(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.

Additional Definitions:

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.

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.

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.

COOK INLET ENERGY

VARIOUS COOK INLET PROPERTIES

AS OF APRIL 30, 2011

SORTED BY RESERVE CATEGORY THEN BY PV10

FIELD	LEASE	RESERVOIR	OPERATOR	MAJOR	RESERVE CATEGORY	LIFE INDEX	GROSS OIL	GROSS GAS	NET OIL	NET GAS	NET SALES	SEV TAX	AD VAL TAX	OP COST	CAPITAL COST	CASH FLOW		DISC @ 10%
						(YRS)	(MBBLS)	(MMCF)	(MBBLS)	(MMCF)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)		(M$)
WEST MCARTHUR RIVER	WMRU 6	HEMLOCK‐SEG B	COOK INLET	OIL	PROVED PRODUCING	12.7	961.4	‐	779.7	‐	56,378.9	281.9	1,211.7	2,042.9	‐	52,842.5		34,559.3
WEST MCARTHUR RIVER	WMRU 5	HEMLOCK‐SEG B	COOK INLET	OIL	PROVED PRODUCING	12.7	874.1	‐	706.3	‐	51,067.6	255.3	1,097.5	2,042.9	‐	47,671.8		32,706.4
WEST MCARTHUR RIVER	WMRU 1A	HEMLOCK‐SEG A	COOK INLET	OIL	PROVED PRODUCING	11.3	77.0	‐	62.4	‐	4,511.6	22.6	97.0	1,814.4	‐	2,577.7		1,837.9
WEST MCARTHUR RIVER	WMRU 7A	HEMLOCK‐SEG A	COOK INLET	OIL	PROVED PRODUCING	7.5	45.4	‐	36.4	‐	2,628.8	13.1	56.5	1,209.6	‐	1,349.6		1,099.9
WEST FORELAND	WF 2 LONG STRING	WF#2‐9200` SAND	COOK INLET	GAS	PROVED PRODUCING	8.3	‐	388.8	‐	307.5	2,069.8	‐	44.7	700.0	‐	1,325.1		1,079.4
THREE MILE CREEK	THREE MILE CREEK 2	BELUGA/TYONEK	COOK INLET	GAS	PROVED PRODUCING	5.2	‐	189.5	‐	48.6	327.3	‐	7.1	111.6	‐	208.7		183.1
THREE MILE CREEK	THREE MILE CREEK 1	BELUGA/TYONEK	COOK INLET	GAS	PROVED PRODUCING	3.6	‐	151.1	‐	38.8	260.9	‐	5.6	77.4	‐	177.9		162.7
WEST FORELAND	WF 2 SHORT STRING	WF#2‐8500` SAND	COOK INLET	GAS	PROVED PRODUCING	0.8	‐	6.6	‐	5.3	36.0	‐	0.8	9.0	‐	26.2		25.4
KUSTATAN FACILITY	KUSTATAN FACILITY EXPENSES		COOK INLET	OIL	PROVED PRODUCING	14.7	‐	‐	‐	‐	‐	‐	‐	20,240	‐	(20,240	)	(10,901	)
WEST MCARTHUR RIVER	FIXED OPERATING COSTS	HEMLOCK	COOK INLET	OIL	PROVED PRODUCING	12.7	‐	‐	‐	‐	‐	‐	‐	28,608	‐	(28,608	)	(18,768.8	)
					PROVED PRODUCING Total	89.3	1,958	736.0	1,584.7	400.3	117,281	572.9	2,520.9	56,855.8	‐	57,331.4		41,984.3
REDOUBT SHOAL	REDOUBT 01	HEMLOCK	COOK INLET	OIL	PROVED NON‐PRODUCING	12.7	647.3	‐	570.3	‐	40,409.9	202.0	868.5	3,094.7	1,200	35,044.7		23,421.7
REDOUBT SHOAL	REDOUBT 07	HEMLOCK	COOK INLET	OIL	PROVED NON‐PRODUCING	10.3	245.6	‐	216.4	‐	15,333	76.7	329.5	2,025.1	1,200	11,701.7		8,018.2
REDOUBT SHOAL	REDOUBT 03	G‐0 GAS SAND	COOK INLET	GAS	PROVED NON‐PRODUCING	7.3	‐	1,625	‐	1,309.7	8,814.6	‐	190.4	172.0	2,461	5,991.2		4,591.8
KUSTATAN	KUSTATAN FIELD #1	TYONEK	COOK INLET	GAS	PROVED NON‐PRODUCING	7.9	‐	33.4	‐	29.1	195.6	‐	4.2	46.0	‐	145.4		117.5
REDOUBT SHOAL	PERFORMANCE BOND	OSPREY PLATFORM	COOK INLET	OIL	PROVED NON‐PRODUCING	12.7	‐	‐	‐	‐	‐	‐	‐	‐	12,000	(12,000	)	(7,352.5	)
REDOUBT SHOAL	FIXED OPERATING COSTS	OSPREY PLATFORM	COOK INLET	OIL	PROVED NON‐PRODUCING	12.7	‐	‐	‐	‐	‐	‐	‐	11,732.7	1,558.1	(13,290.8	)	(7,888.4	)
					PROVED NON‐PRODUCING Total	63.5	892.9	1,658.4	786.6	1,338.8	64,753.1	278.7	1,392.6	17,070.5	18,419.1	27,592.1		20,908.4
REDOUBT SHOAL	REDOUBT 04A	HEMLOCK CENTRAL FB	COOK INLET	OIL	PROVED UNDEVELOPED	16.8	1,321.9	323.9	1,164.6	285.3	84,445.4	412.6	1,815.1	4,812.9	3,400	74,004.7		47,437.6
REDOUBT SHOAL	REDOUBT 03A	HEMLOCK SOUTH FB	COOK INLET	OIL	PROVED UNDEVELOPED	14.1	1,124.7	‐	990.9	‐	70,215.7	351.1	1,509.1	4,090.4	4,900	59,365.2		40,418.1
REDOUBT SHOAL	REDOUBT 05A	HEMLOCK SOUTH FB	COOK INLET	OIL	PROVED UNDEVELOPED	14.5	1,124.7	‐	990.9	‐	70,215.7	351.1	1,509.1	4,090.4	3,600	60,665.2		40,035.7
REDOUBT SHOAL	REDOUBT 02A	HEMLOCK SOUTH FB	COOK INLET	OIL	PROVED UNDEVELOPED	15.2	1,124.7	‐	990.9	‐	70,215.7	351.1	1,509.1	4,090.4	4,800	59,465.2		36,539
WEST MCARTHUR RIVER	WMRU 9	HEMLOCK‐SEG B	COOK INLET	OIL	PROVED UNDEVELOPED	11.5	1,100	‐	889.5	‐	64,318.4	321.6	1,382.3	1,733.8	8,640	52,240.7		36,503.9
REDOUBT SHOAL	REDOUBT SOUTH STEPOUT 9	HEMLOCK SSO	COOK INLET	OIL	PROVED UNDEVELOPED	16.6	1,191	‐	1,049.3	‐	74,354.3	371.8	1,598	4,336.5	13,770	54,277.9		28,890
WEST MCARTHUR RIVER	WMRU 8	HEMLOCK‐SEG C	COOK INLET	OIL	PROVED UNDEVELOPED	5.6	523.0	‐	410.4	‐	29,675.4	148.4	637.8	833.3	9,540	18,516		14,707.6

COOK INLET ENERGY

VARIOUS COOK INLET PROPERTIES

AS OF APRIL 30, 2011

SORTED BY RESERVE CATEGORY THEN BY PV10

THREE MILE CREEK	THREE MILE CREEK 3	BELUGA/TYONEK	COOK INLET	GAS	PROVED UNDEVELOPED	4.2	‐	717.2	‐	184.1	1,238.7	‐	26.8	90.0	‐	1,122		1,034.9
RAPTOR	RAPTOR 1	TYONEK	COOK INLET	GAS	PROVED UNDEVELOPED	9.7	‐	3,819	‐	114.6	771.1	‐	16.7	‐	‐	754.4		536.6
REDOUBT SHOAL	FIXED OPERATING COSTS	OSPREY PLATFORM	COOK INLET	OIL	PROVED UNDEVELOPED	13.7	‐	‐	‐	‐	‐	‐	‐	932.4	11,641.9	(12,574.3	)	(7,271.1	)
					PROVED UNDEVELOPED Total	121.7	7,510.1	4,860.1	6,486.4	584.0	465,450.3	2,307.6	10,003.9	25,010	60,291.9	367,837		238,832.4
WEST MCARTHUR RIVER	WMRU 7A	8500' GAS	COOK INLET	GAS	PROBABLE NON‐PRODUCING	9.1	‐	6,340	‐	5,153.4	34,682.6	‐	749.1	1,357.4	3,600	28,976		19,457.1
WEST FORELAND	WF 1 (9200‐9400)	WF#1 9200 & 9400` SAND	COOK INLET	GAS	PROBABLE NON‐PRODUCING	10.9	‐	1,021.3	‐	807.9	5,437	‐	117.4	1,221.1	400.0	3,698.4		2,583.4
THREE MILE CREEK	THREE MILE CREEK 2	BELUGA/TYONEK	COOK INLET	GAS	PROBABLE NON‐PRODUCING	5.3	‐	621.1	‐	159.4	1,072.7	‐	23.2	113.4	‐	936.1		841.1
THREE MILE CREEK	THREE MILE CREEK 2	BELUGA/TYONEK	COOK INLET	GAS	PROBABLE NON‐PRODUCING	7.8	‐	760.3	‐	195.1	1,313	‐	28.4	54.0	75.0	1,155.7		668.0
THREE MILE CREEK	THREE MILE CREEK 1	BELUGA/TYONEK	COOK INLET	GAS	PROBABLE NON‐PRODUCING	4.6	‐	545.7	‐	140.0	942.4	‐	20.4	39.6	75.0	807.5		599.7
					PROBABLE NON‐PRODUCING Total	37.6	‐	9,288.4	‐	6,455.8	43,447.7	‐	938.5	2,785.6	4,150	35,573.7		24,149.3
REDOUBT SHOAL	REDOUBT SOUTH STEPOUT 10	HEMLOCK SSO	COOK INLET	OIL	PROBABLE UNDEVELOPED	15.3	1,191	‐	1,049.3	‐	74,354.3	371.8	1,598	4,336.5	13,770	54,277.9		32,545.3
REDOUBT SHOAL	REDOUBT NORTH STEPOUT 08	HEMLOCK NS02	COOK INLET	OIL	PROBABLE UNDEVELOPED	16.1	1,191	‐	1,049.3	‐	74,354.2	371.8	1,598	4,336.5	14,538	53,509.9		29,644.9
SWORD	SWORD 1	G SAND	COOK INLET	OIL	PROBABLE UNDEVELOPED	14.9	1,106.5	‐	832.1	‐	60,165.8	300.8	1,293.1	2,832.9	10,920	44,818.9		26,481.7
SABRE	SABRE 2	G SAND	COOK INLET	OIL	PROBABLE UNDEVELOPED	12.5	1,152.5	‐	697.8	‐	50,458.6	252.3	1,084.5	1,943.5	10,535	36,643.4		23,464.8
SABRE	SABRE 1	G SAND	COOK INLET	OIL	PROBABLE UNDEVELOPED	11.7	1,152.5	‐	697.8	‐	50,458.7	252.3	1,084.5	1,905	13,020	34,196.9		22,155.8
REDOUBT SHOAL	REDOUBT 13	HEMLOCK NORTHERN FB	COOK INLET	OIL	PROBABLE UNDEVELOPED	13.3	847.0	207.5	746.2	182.8	54,108.9	264.4	1,163	3,083.6	12,240	37,357.9		20,022.1
REDOUBT SHOAL	REDOUBT 12	HEMLOCK NORTHERN FB	COOK INLET	OIL	PROBABLE UNDEVELOPED	13.1	847.0	‐	746.2	‐	52,878.5	264.4	1,136.5	3,083.6	12,240	36,154		19,784.8
REDOUBT SHOAL	REDOUBT 14	HEMLOCK NORTHERN FB	COOK INLET	OIL	PROBABLE UNDEVELOPED	13.6	847.0	‐	746.2	‐	52,878.5	264.4	1,136.5	3,083.6	14,538	33,856		17,191.5
REDOUBT SHOAL	REDOUBT NORTH STEPOUT 11	HEMLOCK NS02	COOK INLET	OIL	PROBABLE UNDEVELOPED	22.3	838.3	‐	738.5	‐	52,332.3	261.7	1,124.7	4,933	12,240	33,772.9		11,094.7
SABRE	SABRE 3	BELUGA‐STERLING	COOK INLET	GAS	PROBABLE UNDEVELOPED	10.9	‐	5,770	‐	3,493.7	23,512.9	‐	507.9	442.8	10,220	12,342.2		6,269.8
COSMOPOLITAN	HANSEN OFFSET 1	STARCHKOF/HEMLOCK	PIONEER	OIL	PROBABLE UNDEVELOPED	13.9	482.7	‐	2.4	‐	174.5	0.9	3.8	‐	‐	169.9		112.3
					PROBABLE UNDEVELOPED Total	157.6	9,655.5	5,977.5	7,305.9	3,676.6	545,677.1	2,604.7	11,730.4	29,981	124,261	377,100.1		208,767.7
REDOUBT SHOAL	REDOUBT SOUTH STEPOUT 15	HEMLOCK SSO	COOK INLET	OIL	POSSIBLE UNDEVELOPED	15.8	1,191	‐	1,049.3	‐	74,354.2	371.8	1,598	4,336.5	13,770	54,277.9		31,278.2
NORTH ALEXANDER	N. ALEXANDER # 02	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.3	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3		18,835
NORTH ALEXANDER	N. ALEXANDER # 03	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.3	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3		18,686
NORTH ALEXANDER	N. ALEXANDER # 04	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.4	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3		18,538.2
NORTH ALEXANDER	N. ALEXANDER # 05	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.8	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3		17,958.5
NORTH ALEXANDER	N. ALEXANDER # 06	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.8	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3		17,816.4

	RALPH E. DAVIS ASSOCIATES, INC.
Note: There are differences in the addition as a result of computer program rounding of numbers.	Texas Registered Engineering Firm F‐1529

COOK INLET ENERGY

VARIOUS COOK INLET PROPERTIES

AS OF APRIL 30, 2011

SORTED BY RESERVE CATEGORY THEN BY PV10

FIELD	LEASE	RESERVOIR	OPERATOR	MAJOR	RESERVE CATEGORY	LIFE INDEX	GROSS OIL	GROSS GAS	NET OIL	NET GAS	NET SALES	SEV TAX	AD VAL TAX	OP COST	CAPITAL COST	CASH FLOW	DISC @ 10%
						(YRS)	(MBBLS)	(MMCF)	(MBBLS)	(MMCF)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
NORTH ALEXANDER	N. ALEXANDER # 07	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.9	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3	17,675.5
NORTH ALEXANDER	N. ALEXANDER # 08	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	16.0	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3	17,535.7
NORTH ALEXANDER	N. ALEXANDER # 09	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	16.1	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3	17,396.9
NORTH ALEXANDER	N. ALEXANDER # 10	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	16.2	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3	17,259.3
NORTH ALEXANDER	N. ALEXANDER # 11	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	16.3	‐	7,518	‐	6,503.1	43,765.6	‐	945.3	1,550	10,000	31,270.3	17,122.8
SABRE	SABRE 4	BELUGA‐STERLING	COOK INLET	GAS	POSSIBLE UNDEVELOPED	12.2	‐	8,593	‐	5,203.1	35,016.6	‐	756.4	500.5	10,220	23,539.7	13,551
TAZLINA	MIDDLE CREEK # 02	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	12.8	‐	4,677.7	‐	4,046.2	27,230.9	‐	588.2	1,400	6,000	19,242.7	13,089.4
OLSEN CREEK	OLSEN CREEK # 01	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	12.2	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	11,357
OTTER	OTTER # 01	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	12.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	11,178
TAZLINA	MIDDLE CREEK # 03	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.1	‐	4,677.7	‐	4,046.2	27,230.9	‐	588.2	1,400	6,000	19,242.7	10,563
TAZLINA	MIDDLE CREEK # 04	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.1	‐	4,677.7	‐	4,046.2	27,230.9	‐	588.2	1,400	6,000	19,242.7	10,563
TAZLINA	MIDDLE CREEK # 05	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.3	‐	4,677.7	‐	4,046.2	27,230.9	‐	588.2	1,400	6,000	19,242.7	10,396.5
TAZLINA	MIDDLE CREEK # 06	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	15.3	‐	4,677.7	‐	4,046.2	27,230.9	‐	588.2	1,400	6,000	19,242.7	10,396.5
OLSEN CREEK	OLSEN CREEK # 02	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,161.8
OLSEN CREEK	OLSEN CREEK # 03	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,161.8
OLSEN CREEK	OLSEN CREEK # 04	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.4	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,081.4
OLSEN CREEK	OLSEN CREEK # 05	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.4	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,081.4
OLSEN CREEK	OLSEN CREEK # 06	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.5	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,001.7
OLSEN CREEK	OLSEN CREEK # 07	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.5	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	10,001.7
OLSEN CREEK	OLSEN CREEK # 08	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.6	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,922.5
OLSEN CREEK	OLSEN CREEK # 09	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.6	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,922.5
OLSEN CREEK	OLSEN CREEK # 10	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.7	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,844
OLSEN CREEK	OLSEN CREEK # 11	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.7	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,844
OLSEN CREEK	OLSEN CREEK # 12	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.8	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,766.2

COOK INLET ENERGY

VARIOUS COOK INLET PROPERTIES

AS OF APRIL 30, 2011

SORTED BY RESERVE CATEGORY THEN BY PV10

OLSEN CREEK	OLSEN CREEK # 13	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.8	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,766.2
OLSEN CREEK	OLSEN CREEK # 14	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.8	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,688.9
OLSEN CREEK	OLSEN CREEK # 15	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.8	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,688.9
OLSEN CREEK	OLSEN CREEK # 16	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.9	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,612.3
OLSEN CREEK	OLSEN CREEK # 17	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.9	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,612.3
OTTER	OTTER # 02	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.9	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,612.3
OTTER	OTTER # 03	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.9	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,612.3
OLSEN CREEK	OLSEN CREEK # 18	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.0	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,536.2
OLSEN CREEK	OLSEN CREEK # 19	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.0	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,536.2
OTTER	OTTER # 04	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.0	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,536.2
OTTER	OTTER # 05	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.0	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,536.2
OLSEN CREEK	OLSEN CREEK # 20	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.1	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,460.8
OLSEN CREEK	OLSEN CREEK # 21	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.1	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,460.8
OTTER	OTTER # 06	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.1	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,460.8
OTTER	OTTER # 07	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.1	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,460.8
OLSEN CREEK	OLSEN CREEK # 22	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.2	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,385.9
OLSEN CREEK	OLSEN CREEK # 23	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.2	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,385.9
OTTER	OTTER # 08	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.2	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,385.9
OTTER	OTTER # 09	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.2	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,385.9
OLSEN CREEK	OLSEN CREEK # 24	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,311.7
OTTER	OTTER # 10	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,311.7
OTTER	OTTER # 11	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,311.7
OTTER	OTTER # 12	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,238
OTTER	OTTER # 13	T2‐4	COOK INLET	GAS	POSSIBLE UNDEVELOPED	14.3	‐	4,047.8	‐	3,501.3	23,563.8	‐	509.0	1,450	6,000	15,604.8	9,238
TUTNA	TUTNA # 01	TUTNA SAND	COOK INLET	GAS	POSSIBLE UNDEVELOPED	11.0	‐	3,406.3	‐	2,946.5	19,829.7	‐	428.3	1,220	6,000	12,181.3	8,452.7
TUTNA	TUTNA # 02	TUTNA SAND	COOK INLET	GAS	POSSIBLE UNDEVELOPED	13.7	‐	3,406.3	‐	2,946.5	19,829.7	‐	428.3	1,220	6,000	12,181.3	6,555.7
STINGRAY NORTH FB	STINGRAY NFB # 03	BELUGA	COOK INLET	GAS	POSSIBLE UNDEVELOPED	7.0	‐	2,425.8	‐	2,098.3	14,121.7	‐	305.0	2,916.2	6,000	4,900.5	3,292.4
STINGRAY NORTH FB	STINGRAY NFB # 02	BELUGA	COOK INLET	GAS	POSSIBLE UNDEVELOPED	8.8	‐	2,425.8	‐	2,098.3	14,121.7	‐	305.0	2,348.9	6,000	5,467.8	3,239.9
STINGRAY NORTH FB	STINGRAY NFB # 01	BELUGA	COOK INLET	GAS	POSSIBLE UNDEVELOPED	6.6	‐	2,352.8	‐	2,035.2	13,696.7	‐	295.8	3,017.5	6,000	4,383.3	2,858.2
NORTH ALEXANDER	N. ALEXANDER # 01	TYONEK	COOK INLET	GAS	POSSIBLE UNDEVELOPED	69.6	‐	7,059.5	‐	6,106.5	41,096.5	‐	887.7	8,300	10,000	21,908.9	1,022.2

COOK INLET ENERGY

VARIOUS COOK INLET PROPERTIES

AS OF APRIL 30, 2011

SORTED BY RESERVE CATEGORY THEN BY PV10

POSSIBLE UNDEVELOPED Total	886.8	1,191	278,004.8	1,049.3	238,244.2	1,677,737.9	371.8	36,231.1	100,009.6	415,990	1,125,135.4	663,942.8
GRAND TOTAL	1,356.3	21,207.5	300,525.2	17,213	250,699.7	2,914,347.1	6,135.7	62,817.4	231,712.4	623,112	1,990,569.7	1,198,584.9

	RALPH E. DAVIS ASSOCIATES, INC.
Note: There are differences in the addition as a result of computer program rounding of numbers.	Texas Registered Engineering Firm F‐1529