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FORM 6-K

 

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Issuer

March 28, 2006

Pursuant to Rule 13a-16 or 15d-16 of

The Securities and Exchange Act of 1934

 

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OAO TATNEFT

(also known as TATNEFT)

(name of Registrant)

 

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75 Lenin Street

Almetyevsk, Tatarstan 423450

Russian Federation

(Address of principal executive offices)

 

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Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40F.

Form 20-F      X            Form 40-F              

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes                      No      X        

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Date: March 28, 2006

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March 28, 2006

On March 24, 2006 OAO Tatneft published on its web site at www.tatneft.ru the following revised evaluation of its reserves as of January 1, 2005 prepared by Miller and Lents, Ltd., independent international oil and gas consultants.

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[Miller & Lents, Ltd. Letterhead]

March 20, 2006

 

Mr. Shafagat F. Takhautdinov

General Director

Tatneft Joint Stock Company

75 Lenin Str.

Almetyevsk 423400

Republic of Tatarstan, Russia

 

Dear Mr. Takhautdinov:

At your request, we revised our estimate of the net oil and gas reserves and future net revenues as of January 1, 2005, for Tatneft JSC (Tatneft) in certain oil fields of Tatarstan. The revised evaluation changed the oil price from $21.53 per barrel to $17.47 per barrel and changed the ownership interest in the Stepnoozerskoye and Yelginskoye Fields from 49 percent to 3.5 percent. The properties evaluated are located in the Volga-Ural Oil Basin and include 73 developed and producing oil fields containing approximately 27,800 active completions and 7 undeveloped oil fields. Attachment 1 is a location map of the Republic of Tatarstan that shows the producing areas.

We performed our evaluations, which are designated as the Constant Price Case, using the prices and expenses provided by Tatneft. The Constant Price Case assumes no future escalations of oil or gas prices, operating expenses, capital, or taxes above the respective January 1, 2005 values. The aggregate results of our revised evaluations for Tatneft are as follows:

 

		Net Reserves				Future Net Revenues
Reserve Category		Crude and Condensate, MMBbls.		Gas, Bcf		Undiscounted, MM$		Discounted at 10% Per Year, MM$
Proved Developed Producing		3,453.9		732.2		26,908.6		10,581.2
Proved Developed Nonproducing		2,075.9		440.1		14,840.9		2,402.0
Proved Undeveloped		271.2		57.5		1,551.0		211.0
Additional Capital and Property Taxes		0.0		0.0		-3,266.0		-1,363.0
Total Proved		5,801.1		1,229.8		40,034.4		11,831.2
Probable		1,237.8		262.4		8,671.9		584.0
Possible		153.5		32.5		692.4		-8.4

Proved, probable, and possible reserves were estimated in accordance with standards of the Society of Petroleum Engineers, Inc. and World Petroleum Congresses as defined on Attachment 2. The unified tax (previously a combination of royalty, mineral replacement tax, and crude oil excise tax) was deducted from gross revenues in determining net revenues but was not deducted from gross reserves in determining net reserves. Reserves were projected for the economic life of the field, without consideration of production or exploration license terms.

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Tatneft also provided us with license term dates. These dates for each field are shown in the Appendix. Our revised estimates of the proved reserves and future net revenues as of January 1, 2005 for the time period until the license term date are as follows:

For the Time Period Until the License Term Date

 

Reserve Category		Net Reserves				Future Net Revenues
		Crude and Condensate, MMBbls.		Gas, Bcf		Undiscounted, MM$		Discounted at 10% Per Year, MM$
Proved Developed Producing		1,285.5		272.5		11,060.8		7,487.1
Proved Developed Nonproducing		145.0		30.7		1,342.4		737.1
Proved Undeveloped		45.6		9.7		233.2		86.2
Additional Capital and Property Taxes		0.0		0.0		-1,078.8		-725.9
Total Proved		1,476.0		312.9		11,557.6		7,584.5

The revised estimated proved reserves and future net revenues forecast for the time period following the current license expiration dates are as follows:

For the Time Period After the License Term Date

 

Reserve Category		Net Reserves				Future Net Revenues
		Crude and Condensate, MMBbls.		Gas, Bcf		Undiscounted, MM$		Discounted at 10% Per Year, MM$
Proved Developed Producing		2,168.4		459.7		15,847.8		3,094.1
Proved Developed Nonproducing		1,930.9		409.4		13,498.5		1,664.9
Proved Undeveloped		225.6		47.8		1,317.8		124.8
Additional Capital and Property Taxes		0.0		0.0		-2,187.2		-637.1
Total Proved		4,325.1		916.9		28,476.8		4,246.7

Future net revenues as used herein are defined as the total gross revenues less unified tax, operating costs, and capital expenditures. The total gross revenues are the total revenues received by Tatneft after deduction of transportation costs, export and customs duties, port expenses, excise tax, value added tax, and special taxes. The oil and gas prices employed in the computations of gross revenues were provided by Tatneft and are shown on Attachment 3. Future net revenues do not include deductions for either federal or local taxes on net profit.

The operating expenses employed in estimating future net revenues are the average operating expenses for the year 2004 that were provided by Tatneft. We removed from the operating expenses the depreciation, well restoration costs, and the unified tax. Restoration costs were included as capital for the portion of the proved nonproducing reserves attributed to the restoration of shut-in wells. The operating expenses for Tatneft are shown on Attachment 4.

We allocated a portion of the operating expenses to the number of active wells on a per-well basis and the remainder to the oil production rates on a per-barrel basis, employing the allocations provided to us by Tatneft. We assumed that the number of active wells for the large waterfloods would decline to approximately one-half the fully developed well count estimated in last year’s evaluation as the fields declined in production and approached their economic limit.

Future capital costs for drilling and workover operations are based on 2004 costs provided by Tatneft and are shown on Attachment 5. The forecasts for capital expenditures, other than drilling and completions, were based on data provided by Tatneft through the year 2021 and are shown on Attachment 6.

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The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, or in a few cases, by volumetric calculations. For some reservoirs with insufficient performance history to establish trends, we estimated future production by analogy with other reservoirs having similar characteristics. Production declines were extrapolated to economic limits based on operating cost and oil price data. The past performance trends of many reservoirs were influenced by production curtailments, workovers, waterfloods, and/or infill drilling; extrapolations of future performance are based, whenever possible, upon the average performance trend of active wells during periods of stable field activity.

The estimated proved developed nonproducing reserves can be produced from existing well bores but require capital costs for workovers, recompletions, or restoration of shut-in wells. For wells shut in awaiting mechanical repair, we assumed that the wells producing at rates greater than the economic limit at the time of shut in will be returned to production at pre-shut-in levels and will decline in production at the average reservoir decline rate. For wells requiring recompletion, the estimates of reserves and producing rates are based on volumetric calculations and analogies with other wells that commercially produce from the same formation in the same field.

The estimated proved undeveloped reserves require significant capital expenditures, such as (1) costs for future development and infill wells and (2) surface facilities. The proved undeveloped reserves are expected to be produced from undeveloped portions of known reservoirs that have been adequately defined by wells. Reserve estimates are based upon volumetric calculations that employ recovery factors based on the performance of analogous reservoirs. Producing rates are based upon analogy.

The estimated probable and possible reserves are mainly undeveloped and require significant capital expenditures. As new wells are drilled, portions of these probable and possible reserve quantities will be either upgraded to a higher reserve category or dropped entirely. The estimated probable reserves are expected to be produced from undeveloped portions of known reservoirs not adequately defined to be classified as proved. Another component of probable reserves was included for reservoirs with water-oil ratio trends that indicated higher reserves than calculated from linear production decline curve analyses. For these reservoirs, future production was assumed to decline hyperbolically, and the incremental production above the linear decline was classified as probable. The estimated possible reserves are expected to be produced from undeveloped portions of known reservoirs (1) where the reservoir is thin and uncertain to be developed or (2) where subsurface control is limited. Estimates of reserves for undeveloped portions of known reservoirs were estimated by volumetric methods.

Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced.

The probable and possible reserve volumes and the estimated future net revenues therefrom have not been adjusted for uncertainty. None of the proved, probable, or possible reserve volumes, nor the revenues projected therefrom, should be combined with either of the other without adjustment for uncertainty. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and any future costs of restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment.

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Estimated net gas reserves are based upon the past ratio of sales gas to produced oil. Net gas reserves do not represent the total volumes of gas expected to be produced with the net oil reserves.

Structural maps, isopach maps of net oil sand, well status maps, seismic data, cross sections, oil and water production data, well logs and core information on key wells, and the Tatneft interpretation of key reservoir parameters were provided by Tatneft. These were reviewed in detail and were generally found to be acceptable interpretations. In certain cases, where appropriate, original maps were prepared. The reservoir maps were employed to estimate original oil in place and to classify the potentially productive areas as either proved developed producing, proved developed nonproducing, proved undeveloped, probable, or possible. Volumetric methods were employed to estimate the original oil in place for each classified area.

Attachments 7a and 7b show a composite production forecast for Tatneft in barrels and tonnes, respectively. These figures show the contribution of production from each proved reserve category. Following the attachments are one-line summaries in both barrels and tonnes that show reserves and cumulative future net revenues for each evaluated field. Tatneft assigned fields to specific groups, which are also identified in the one-line summaries.

Following the one-line summaries are exhibits that are projections of future production and net revenues for each reserve category and group.

In conducting this evaluation, we relied upon (1) production histories, (2) accounting and cost data, (3) ownership, (4) geological, geophysical, and engineering data, and (5) drilling, recompletion, and workover schedules supplied by Tatneft. These data were accepted as represented, as verification of such data and information was beyond the scope of this assignment.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in Tatneft or any related company. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Preparation of this report was supervised by an officer of Miller and Lents, Ltd., who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 20 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

 

JCP/mk

END