| Miller Energy Resources 9721 Cogdill Road, Suite 302 O: (865) 223-6575 F: (865) 691-8209 |
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June 21, 2012
'CORRESP'
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street N.E.
Washington, D.C. 20549
Attention: | Robert Carroll |
| Ethan Horowitz, Branch Chief |
Re: | Miller Energy Resources, Inc. (formerly Miller Petroleum, Inc.) |
| Form 10-K/A for Fiscal Year Ended April 30, 2010 Filed July 28, 2010 Form 10-K/A for Fiscal Year Ended April 30, 2011 Filed August 29, 2011 |
| File No. 001-34732 |
Dear Mr. Carroll:
Miller Energy Resources, Inc. (the “Company”) is providing the following response to the comment letter dated May 1, 2012, from the staff of the Division of Corporation Finance (“Staff”) of the U.S. Securities and Exchange Commission (“SEC”) regarding our response letter filed with the Staff on November 18, 2011. The comment letter requests information from the Company regarding our Form 10-K/A for Fiscal Year Ended April 30, 2010 (“ 2010 Form 10-K”) and our Form 10-K/A for Fiscal Year Ended April 30, 2011 (“ 2011 Form 10-K”) The response provided below corresponds to the Staff’s comment, which has been reproduced herein.
We acknowledge that (i) the Company is responsible for the adequacy and accuracy of the disclosures in the Form 10-K and Form 10-Q; (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the SEC from taking any action with respect to the filing; and (iii) the Company may not assert Staff comments as a defense in any proceedings initiated by the SEC or any person under the federal securities laws of the United States.
Net Reserves at April 30, page 4
1.
In comment two of our October 28, 2011 letter, we requested evidence for the proved undeveloped reserves you have claimed for the RU 17 location mapped in the Northern Step Out 2 fault block in the Cook Inlet. We do not agree that the submitted well logs and structure map offer sufficient evidence for proved reserves in this non-productive fault block, given the very small volume of oil recoved by drill stem test from the same well. The Note to Rule 4-10(a)(26) of Regulation S-X states “Reserves should be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated andevaluated 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, ornegative test results).” Please present definitive evidence for these volumes as PUD reserves or remove them from your document.
RESPONSE: After further review of the supporting materials in the Company’s possession, though we respectfully do not agree with the Staff’s conclusion, we are adopting the position of the Staff as set forth above. Attached to this response as Exhibit A and B, respectively, are revised reserve reports replacing both Exhibits 99.1 for fiscal year 2010 and fiscal year 2011 with the RU 17 location removed from proved reserves. In lieu of amending our previously filed 2010 Form 10-K and 2011 Form 10-K, we are requesting that we reflect the removal of the proved reserves in the RU 17 location in our Form 10-K for the fiscal year ending April 30, 2012, which we currently intend to file on or prior to July 16, 2012. We have assessed the impact of removing the RU 17 location to our previously reported unaudited Supplemental Oil and Gas disclosures and have concluded that the impact is not material to those disclosures taken as a whole. In addition, as we previously disclosed in our 2011 Form 10-K, the removal of the these proved undeveloped reserves has no impact on our reported depletion as the Redoubt field was not in production during the 2010 and 2011 fiscal years.
We respectfully request an opportunity to discuss this response letter further with the Staff if, following a review of this information, the Staff does not concur with our proposed course of action. If you have further questions or comments, or if you require additional information, please do not hesitate to contact the undersigned by telephone at (865) 223-6575 or by facsimile at (865) 691-8209.
| Sincerely, |
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| /s/ David J. Voyticky |
| David J. Voyticky President and Acting Chief Financial Officer |
2
EXHIBIT A
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RALPH E.DAVIS
ASS0CIATES, I NC.
May 18, 2012
Cook Inlet Energy
601 W. 5th Ave, Suite 310
Anchorage, Alaska 99501
RE: | Revised Report for April 30, 2010 |
| Using SEC Parameters |
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 reserves anticipated to be produced from those leaseholds and remaining as of April 30, 2010. The subject properties are located in the State of Alaska, USA.This report was completed on May 18, 2012. The report is reissued as a revised report from that previously prepared and dated May 14, 2010 to exclude the Redoubt Shoal North Stepout location as a proved location.
Davis has reviewed 100% of CIE's proved 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 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.
We have also estimated the future net revenue and discounted present value associated with these reserves as of April 30, 2010, utilizing a scenario of non-escalated product prices as well as non escalated 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.
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 18, 2012 |
| Page 2 |
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, 2010
|
| PROVED |
| |||||||||||||||||
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| PRODUCING |
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| NON- PRODUCING |
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| UNDEVELOPED |
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| EXPENSES |
|
| TOTAL |
| |||||
Net Reserves |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil/Condensate-MBbls |
|
| 1,695 |
|
|
| 856 |
|
|
| 6,601 |
|
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| 0 |
|
|
| 9,152 |
|
Gas-MMCF |
|
| 1,085 |
|
|
| 0 |
|
|
| 3,722 |
|
|
| 0 |
|
|
| 4,807 |
|
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Income Data (M$) |
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|
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Future Gross Revenue |
| $ | 111,508.1 |
|
| $ | 51,975.8 |
|
| $ | 423,051.7 |
|
| $ | 0.0 |
|
| $ | 586,535.7 |
|
Ad Valorem Taxes |
| $ | 1,201.4 |
|
| $ | 779.2 |
|
| $ | 6,003.0 |
|
| $ | 0.0 |
|
| $ | 7,983.6 |
|
Production Taxes |
| $ | 53.5 |
|
| $ | 26.6 |
|
| $ | 224.4 |
|
| $ | 0.0 |
|
| $ | 304.5 |
|
Operating Costs |
| $ | 1,809.0 |
|
| $ | 1,664.3 |
|
| $ | 11,037.7 |
|
| $ | 94,233.0 |
|
| $ | 108,744.0 |
|
Capital Costs |
| $ | 275.0 |
|
| $ | 4,000.0 |
|
| $ | 41,350.0 |
|
| $ | 0.0 |
|
| $ | 45,625.0 |
|
Future Net Income (FNI) |
| $ | 108,169.3 |
|
| $ | 45,505.7 |
|
| $ | 364,436.4 |
|
| $ | (94,233.0 | ) |
| $ | 423,878.4 |
|
FNI @ 10% |
| $ | 75,596.4 |
|
| $ | 26,222.3 |
|
| $ | 232,697.0 |
|
| $ | (57, 103.4 | ) |
| $ | 277,412.3 |
|
Note: There are differences in the addition as a result of computer program rounding of numbers.
Crude oil volumes are expressed in standard 42 gallon barrels. Gas volumes are expressed in thousand cubic feet (MCF) 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.
RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529
RALPH E. DAVIS
ASS0CIATES, INC.
Cook Inlet Energy | May 18, 2012 |
| Page 3 |
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.
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 and proved undeveloped 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, 2009 through April1, 2010 and averaged for the year.
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 $73.01 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 $2.00/bbl was used.
4.
Minus a "CISPRI allowance" (a spill response coop) of $0.72/bbl in 2009 escalated at 5% annually.
5.
Minus a shipping charge of $1.184/bbl in 2003 escalated at 5% annually.
6.
Minus a pipeline tariff of $4.08/bbl.
RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529
RALPH E. DAVIS
ASS0CIATES, INC.
Cook Inlet Energy | May 18, 2012 |
| Page 4 |
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 $3.957 per MMBTU was calculated then adjusted by the area differential calculated of $0.884 per MMBTU with a resultant area price of $4.841 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.
No consideration was given in this report to potential environmental liabilities 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 it 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.
RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529
RALPH E. DAVIS
ASS0CIATES, INC.
Cook Inlet Energy | May 18, 2012 |
| Page 5 |
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, |
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| RALPH E. DAVIS ASSOCIATES, INC. |
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| L. B. Branum, P.E. |
|
| Vice President |
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RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529
![[mill_corresp005.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp005.jpg)
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, 2010.
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 18, 2012
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| Lloyd. B. Branum, P.E. |
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| Vice President |
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| Ralph E. Davis Associates, Inc. |
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![[mill_corresp006.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp006.jpg)
![[mill_corresp007.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp007.jpg)
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) |
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Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter |
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(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) |
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Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter |
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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 PROVED PROPERTIES
AS OF APRIL 30, 2010
SORTED BY FIELD, RESERVE CATEGORY, LEASE
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% |
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| (YRS) |
| (MBBLS) |
| (MMCF) |
| (MBBLS) |
| (MMCF) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
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WEST MCARTHUR RIVER |
| WMRU 6 |
| HEMLOCK‐SEG B |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 11.7 |
| 1,231 |
| ‐ |
| 983 |
| ‐ |
| 61,579 |
| 29 |
| 677 |
| ‐ |
| ‐ |
| 60,872 |
| 41,805 |
REDOUBT SHOAL |
| REDOUBT 04A |
| HEMLOCK CENTRAL FB |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 17.3 |
| 1,322 |
| ‐ |
| 1,196 |
| ‐ |
| 72,770 |
| 41 |
| 1,091 |
| 2,326,535 |
| 2,300,000 |
| 67,012 |
| 40,711 |
REDOUBT SHOAL |
| REDOUBT 05A |
| HEMLOCK SOUTH FB |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 14.5 |
| 1,125 |
| ‐ |
| 1,018 |
| ‐ |
| 62,235 |
| 35 |
| 933 |
| 1,979,509 |
| 2,400,000 |
| 56,888 |
| 37,629 |
REDOUBT SHOAL |
| REDOUBT 03A |
| HEMLOCK SOUTH FB |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 14.4 |
| 1,125 |
| ‐ |
| 1,018 |
| ‐ |
| 62,258 |
| 35 |
| 933 |
| 1,979,509 |
| 4,600,000 |
| 54,710 |
| 35,911 |
REDOUBT SHOAL |
| REDOUBT 02A |
| HEMLOCK SOUTH FB |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 15.1 |
| 1,125 |
| ‐ |
| 1,018 |
| ‐ |
| 62,079 |
| 35 |
| 931 |
| 1,979,509 |
| 3,500,000 |
| 55,634 |
| 34,547 |
WEST MCARTHUR RIVER |
| WMRU 9 |
| HEMLOCK‐SEG B |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 11.6 |
| 1,100 |
| ‐ |
| 872 |
| ‐ |
| 54,808 |
| 30 |
| 603 |
| ‐ |
| 6,000,000 |
| 48,176 |
| 33,808 |
REDOUBT SHOAL |
| REDOUBT SOUTH STEPOUT |
| HEMLOCK SSO |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 16.6 |
| 1,191 |
| ‐ |
| 1,078 |
| ‐ |
| 65,466 |
| 37 |
| 981 |
| 2,096,183 |
| 4,600,000 |
| 57,752 |
| 32,869 |
WEST MCARTHUR RIVER |
| WMRU 5 |
| HEMLOCK‐SEG B |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 11.7 |
| 756 |
| ‐ |
| 603 |
| ‐ |
| 37,803 |
| 21 |
| 416 |
| ‐ |
| ‐ |
| 37,366 |
| 25,662 |
REDOUBT SHOAL |
| REDOUBT 01 |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED NON PRODUCING |
| 17.2 |
| 700 |
| ‐ |
| 633 |
| ‐ |
| 38,404 |
| 19 |
| 576 |
| 1,231,999 |
| 2,000,000 |
| 34,578 |
| 19,715 |
WEST MCARTHUR RIVER |
| WMRU 8 |
| HEMLOCK‐SEG C |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 5.6 |
| 523 |
| ‐ |
| 401 |
| ‐ |
| 25,417 |
| 14 |
| 279 |
| ‐ |
| 6,000,000 |
| 19,124 |
| 15,571 |
REDOUBT SHOAL |
| REDOUBT 07 |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED NON PRODUCING |
| 11.3 |
| 246 |
| ‐ |
| 222 |
| ‐ |
| 13,571 |
| 8 |
| 203 |
| 432,265 |
| 2,000,000 |
| 10,928 |
| 6,507 |
WEST MCARTHUR RIVER |
| WMRU 1A |
| HEMLOCK‐SEG A |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 2.8 |
| 80 |
| ‐ |
| 60 |
| ‐ |
| 3,824 |
| 2 |
| 42 |
| ‐ |
| 275,000 |
| 3,505 |
| 3,154 |
WEST MCARTHUR RIVER |
| WMRU 7A |
| HEMLOCK‐SEG A |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 9.9 |
| 61 |
| - |
| 48 |
| - |
| 3,049 |
| 2 |
| 34 |
| - |
| - |
| 3,014 |
| 2,207 |
WEST FORELAND |
| WF 1 (9200‐9400) |
| WF#1 9200 & 9400` SAND |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 9.3 |
| ‐ |
| 791 |
| ‐ |
| 638 |
| 3,088 |
| ‐ |
| 12 |
| 1,068,480 |
| ‐ |
| 2,007 |
| 1,598 |
RAPTOR |
| RAPTOR 1 |
| TYONEK |
| COOK INLET |
| GAS |
| PROVED UNDEVELOPED |
| 10.7 |
| ‐ |
| 3,819 |
| ‐ |
| 3,342 |
| 16,177 |
| ‐ |
| 178 |
| 577,500 |
| 10,600,000 |
| 4,821 |
| 1,471 |
WEST FORELAND |
| WF 2 LONG STRING |
| WF#2‐9200` SAND |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 8.2 |
| ‐ |
| 460 |
| ‐ |
| 371 |
| 1,798 |
| ‐ |
| 7 |
| 633,080 |
| ‐ |
| 1,158 |
| 946 |
THREE MILE CREEK |
| THREE MILE CREEK 1 |
| BELUGA/TYONEK |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 3.8 |
| ‐ |
| 254 |
| ‐ |
| 65 |
| 316 |
| ‐ |
| 13 |
| 81,000 |
| ‐ |
| 222 |
| 203 |
THREE MILE CREEK |
| THREE MILE CREEK 3 |
| BELUGA/TYONEK |
| COOK INLET |
| GAS |
| PROVED UNDEVELOPED |
| 4.8 |
| ‐ |
| 1,482 |
| ‐ |
| 380 |
| 1,841 |
| ‐ |
| 74 |
| 99,000 |
| 1,350,000 |
| 319 |
| 180 |
KUSTATAN |
| KUSTATAN FIELD #1 |
| TYONEK |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 3.3 |
| ‐ |
| 6 |
| ‐ |
| 5 |
| 24 |
| ‐ |
| 0 |
| 10,000 |
| ‐ |
| 14 |
| 11 |
THREE MILE CREEK |
| THREE MILE CREEK 2 |
| BELUGA/TYONEK |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 0.7 |
| ‐ |
| 17 |
| ‐ |
| 4 |
| 21 |
| ‐ |
| 1 |
| 14,400 |
| ‐ |
| 6 |
| 6 |
WEST FORELAND |
| WF 2 SHORT STRING |
| WF#2‐8500` SAND |
| COOK INLET |
| GAS |
| PROVED PRODUCING |
| 0.2 |
| ‐ |
| 2 |
| ‐ |
| 1 |
| 7 |
| ‐ |
| 0 |
| 2,000 |
| ‐ |
| 4 |
| 4 |
REDOUBT SHOAL |
| REDOUBT 05 |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
KUSTATAN FACILITY |
| KUSTATAN FACILITY EXPENSES |
|
|
| COOK INLET |
| OIL |
| PROVED EXPENSES |
| 15.7 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 21,620,000 |
| ‐ |
| (21,620) |
| (11,226) |
REDOUBT SHOAL |
| FIXED OPERATING COSTS |
| OSPREY PLATFORM |
| COOK INLET |
| OIL |
| PROVED EXPENSES |
| 14.7 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 25,853,000 |
| ‐ |
| (25,853) |
| (17,657) |
WEST MCARTHUR RIVER |
| FIXED OPERATING COSTS |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED EXPENSES |
| 11.7 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 46,760,000 |
| ‐ |
| (46,760) |
| (28,220) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| GRAND TOTAL |
| 242.4 |
| 10,584 |
| 6,831 |
| 9,152 |
| 4,807 |
| 586,536 |
| 304 |
| 7,984 |
| 108,743,969 |
| 45,625,000 |
| 423,879 |
| 277,412 |
| 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 |
EXHIBIT B
![[mill_corresp008.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp008.jpg)
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.
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| Very truly yours, |
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| RALPH E. DAVIS ASSOCIATES, INC. |
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| L. B. Branum, P.E. |
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| Vice President |
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![[mill_corresp009.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp009.jpg)
![[mill_corresp010.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp010.jpg)
RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529
![[mill_corresp011.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp011.jpg)
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
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| Lloyd. B. Branum, P.E. |
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| Vice President |
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| Ralph E. Davis Associates, Inc. |
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![[mill_corresp012.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp012.jpg)
![[mill_corresp013.jpg]](https://capedge.com/proxy/CORRESP/0000943440-12-000651/mill_corresp013.jpg)
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) |
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Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter |
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(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) |
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Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter |
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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% |
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| (YRS) |
| (MBBLS) |
| (MMCF) |
| (MBBLS) |
| (MMCF) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
| (M$) |
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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 |
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| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 14.7 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 20,240.0 |
| ‐ |
| (20,240.0) |
| (10,901.0) |
WEST MCARTHUR RIVER |
| FIXED OPERATING COSTS |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED PRODUCING |
| 12.7 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 28,608.0 |
| ‐ |
| (28,608.0) |
| (18,768.8) |
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| PROVED PRODUCING Total |
| 89.3 |
| 1,958.0 |
| 736.0 |
| 1,584.7 |
| 400.3 |
| 117,281.0 |
| 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 |
| 1,200.0 |
| 35,044.7 |
| 23,421.7 |
REDOUBT SHOAL |
| REDOUBT 07 |
| HEMLOCK |
| COOK INLET |
| OIL |
| PROVED NON‐PRODUCING |
| 10.3 |
| 245.6 |
| ‐ |
| 216.4 |
| ‐ |
| 15,333.0 |
| 76.7 |
| 329.5 |
| 2,025.1 |
| 1,200.0 |
| 11,701.7 |
| 8,018.2 |
REDOUBT SHOAL |
| REDOUBT 03 |
| G‐0 GAS SAND |
| COOK INLET |
| GAS |
| PROVED NON‐PRODUCING |
| 7.3 |
| ‐ |
| 1,625.0 |
| ‐ |
| 1,309.7 |
| 8,814.6 |
| ‐ |
| 190.4 |
| 172.0 |
| 2,461.0 |
| 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 |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| ‐ |
| 12,000.0 |
| (12,000.0) |
| (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) |
|
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| 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 |
| 3,400.0 |
| 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 |
| 4,900.0 |
| 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 |
| 3,600.0 |
| 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 |
| 4,800.0 |
| 59,465.2 |
| 36,539.0 |
WEST MCARTHUR RIVER |
| WMRU 9 |
| HEMLOCK‐SEG B |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 11.5 |
| 1,100.0 |
| ‐ |
| 889.5 |
| ‐ |
| 64,318.4 |
| 321.6 |
| 1,382.3 |
| 1,733.8 |
| 8,640.0 |
| 52,240.7 |
| 36,503.9 |
REDOUBT SHOAL |
| REDOUBT SOUTH STEPOUT 9 |
| HEMLOCK SSO |
| COOK INLET |
| OIL |
| PROVED UNDEVELOPED |
| 16.6 |
| 1,191.0 |
| ‐ |
| 1,049.3 |
| ‐ |
| 74,354.3 |
| 371.8 |
| 1,598.0 |
| 4,336.5 |
| 13,770.0 |
| 54,277.9 |
| 28,890.0 |
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 |
| 9,540.0 |
| 18,516.0 |
| 14,707.6 |
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 |
| ‐ |
| 1,122.0 |
| 1,034.9 |
RAPTOR |
| RAPTOR 1 |
| TYONEK |
| COOK INLET |
| GAS |
| PROVED UNDEVELOPED |
| 9.7 |
| ‐ |
| 3,819.0 |
| ‐ |
| 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 |
| 25,010.0 |
| 60,291.9 |
| 367,837.0 |
| 238,832.4 |
WEST MCARTHUR RIVER |
| WMRU 7A |
| 8500' GAS |
| COOK INLET |
| GAS |
| PROBABLE NON‐PRODUCING |
| 9.1 |
| ‐ |
| 6,340.0 |
| ‐ |
| 5,153.4 |
| 34,682.6 |
| ‐ |
| 749.1 |
| 1,357.4 |
| 3,600.0 |
| 28,976.0 |
| 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 |
| 5,437.0 |
| ‐ |
| 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 |
| 1,313.0 |
| ‐ |
| 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 |
| 4,150.0 |
| 35,573.7 |
| 24,149.3 |
REDOUBT SHOAL |
| REDOUBT SOUTH STEPOUT 10 |
| HEMLOCK SSO |
| COOK INLET |
| OIL |
| PROBABLE UNDEVELOPED |
| 15.3 |
| 1,191.0 |
| ‐ |
| 1,049.3 |
| ‐ |
| 74,354.3 |
| 371.8 |
| 1,598.0 |
| 4,336.5 |
| 13,770.0 |
| 54,277.9 |
| 32,545.3 |
REDOUBT SHOAL |
| REDOUBT NORTH STEPOUT 08 |
| HEMLOCK NS02 |
| COOK INLET |
| OIL |
| PROBABLE UNDEVELOPED |
| 16.1 |
| 1,191.0 |
| ‐ |
| 1,049.3 |
| ‐ |
| 74,354.2 |
| 371.8 |
| 1,598.0 |
| 4,336.5 |
| 14,538.0 |
| 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 |
| 10,920.0 |
| 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 |
| 10,535.0 |
| 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 |
| 1,905.0 |
| 13,020.0 |
| 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 |
| 1,163.0 |
| 3,083.6 |
| 12,240.0 |
| 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 |
| 12,240.0 |
| 36,154.0 |
| 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 |
| 14,538.0 |
| 33,856.0 |
| 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 |
| 4,933.0 |
| 12,240.0 |
| 33,772.9 |
| 11,094.7 |
SABRE |
| SABRE 3 |
| BELUGA‐STERLING |
| COOK INLET |
| GAS |
| PROBABLE UNDEVELOPED |
| 10.9 |
| ‐ |
| 5,770.0 |
| ‐ |
| 3,493.7 |
| 23,512.9 |
| ‐ |
| 507.9 |
| 442.8 |
| 10,220.0 |
| 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 |
| 29,981.0 |
| 124,261.0 |
| 377,100.1 |
| 208,767.7 |
REDOUBT SHOAL |
| REDOUBT SOUTH STEPOUT 15 |
| HEMLOCK SSO |
| COOK INLET |
| OIL |
| POSSIBLE UNDEVELOPED |
| 15.8 |
| 1,191.0 |
| ‐ |
| 1,049.3 |
| ‐ |
| 74,354.2 |
| 371.8 |
| 1,598.0 |
| 4,336.5 |
| 13,770.0 |
| 54,277.9 |
| 31,278.2 |
NORTH ALEXANDER |
| N. ALEXANDER # 02 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.3 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 18,835.0 |
NORTH ALEXANDER |
| N. ALEXANDER # 03 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.3 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 18,686.0 |
NORTH ALEXANDER |
| N. ALEXANDER # 04 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.4 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 18,538.2 |
NORTH ALEXANDER |
| N. ALEXANDER # 05 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.8 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,958.5 |
NORTH ALEXANDER |
| N. ALEXANDER # 06 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.8 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 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 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,675.5 |
NORTH ALEXANDER |
| N. ALEXANDER # 08 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 16.0 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,535.7 |
NORTH ALEXANDER |
| N. ALEXANDER # 09 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 16.1 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,396.9 |
NORTH ALEXANDER |
| N. ALEXANDER # 10 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 16.2 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,259.3 |
NORTH ALEXANDER |
| N. ALEXANDER # 11 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 16.3 |
| ‐ |
| 7,518.0 |
| ‐ |
| 6,503.1 |
| 43,765.6 |
| ‐ |
| 945.3 |
| 1,550.0 |
| 10,000.0 |
| 31,270.3 |
| 17,122.8 |
SABRE |
| SABRE 4 |
| BELUGA‐STERLING |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 12.2 |
| ‐ |
| 8,593.0 |
| ‐ |
| 5,203.1 |
| 35,016.6 |
| ‐ |
| 756.4 |
| 500.5 |
| 10,220.0 |
| 23,539.7 |
| 13,551.0 |
TAZLINA |
| MIDDLE CREEK # 02 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 12.8 |
| ‐ |
| 4,677.7 |
| ‐ |
| 4,046.2 |
| 27,230.9 |
| ‐ |
| 588.2 |
| 1,400.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 11,357.0 |
OTTER |
| OTTER # 01 |
| T2‐4 |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 12.3 |
| ‐ |
| 4,047.8 |
| ‐ |
| 3,501.3 |
| 23,563.8 |
| ‐ |
| 509.0 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 11,178.0 |
TAZLINA |
| MIDDLE CREEK # 03 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.1 |
| ‐ |
| 4,677.7 |
| ‐ |
| 4,046.2 |
| 27,230.9 |
| ‐ |
| 588.2 |
| 1,400.0 |
| 6,000.0 |
| 19,242.7 |
| 10,563.0 |
TAZLINA |
| MIDDLE CREEK # 04 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.1 |
| ‐ |
| 4,677.7 |
| ‐ |
| 4,046.2 |
| 27,230.9 |
| ‐ |
| 588.2 |
| 1,400.0 |
| 6,000.0 |
| 19,242.7 |
| 10,563.0 |
TAZLINA |
| MIDDLE CREEK # 05 |
| TYONEK |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 15.3 |
| ‐ |
| 4,677.7 |
| ‐ |
| 4,046.2 |
| 27,230.9 |
| ‐ |
| 588.2 |
| 1,400.0 |
| 6,000.0 |
| 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 |
| 1,400.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 9,844.0 |
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 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 9,844.0 |
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 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 9,766.2 |
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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 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 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 9,238.0 |
OTTER |
| OTTER # 13 |
| T2‐4 |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 14.3 |
| ‐ |
| 4,047.8 |
| ‐ |
| 3,501.3 |
| 23,563.8 |
| ‐ |
| 509.0 |
| 1,450.0 |
| 6,000.0 |
| 15,604.8 |
| 9,238.0 |
TUTNA |
| TUTNA # 01 |
| TUTNA SAND |
| COOK INLET |
| GAS |
| POSSIBLE UNDEVELOPED |
| 11.0 |
| ‐ |
| 3,406.3 |
| ‐ |
| 2,946.5 |
| 19,829.7 |
| ‐ |
| 428.3 |
| 1,220.0 |
| 6,000.0 |
| 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 |
| 1,220.0 |
| 6,000.0 |
| 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 |
| 6,000.0 |
| 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 |
| 6,000.0 |
| 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 |
| 6,000.0 |
| 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 |
| 8,300.0 |
| 10,000.0 |
| 21,908.9 |
| 1,022.2 |
|
|
|
|
|
|
|
|
|
| POSSIBLE UNDEVELOPED Total |
| 886.8 |
| 1,191.0 |
| 278,004.8 |
| 1,049.3 |
| 238,244.2 |
| 1,677,737.9 |
| 371.8 |
| 36,231.1 |
| 100,009.6 |
| 415,990.0 |
| 1,125,135.4 |
| 663,942.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| GRAND TOTAL |
| 1,356.3 |
| 21,207.5 |
| 300,525.2 |
| 17,213.0 |
| 250,699.7 |
| 2,914,347.1 |
| 6,135.7 |
| 62,817.4 |
| 231,712.4 |
| 623,112.0 |
| 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 |