Exhibit 99.3
| | | | | | |
| |  | | | | FAX (713) 651-0849 |
| | | |
| | | 1100 LOUISIANA SUITE 3800 | | HOUSTON, TEXAS 77002-5218 | | TELEPHONE (713) 651-9191 |
November 15, 2005
Transmeridian Exploration, Inc.
397 N. Sam Houston Parkway, E., Suite 300
Houston, Texas 77060
Gentlemen:
At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold interests of Transmeridian Exploration, Inc. (Transmeridian), and attributable to a proposed buyout of interests currently owned by Bramex Management Inc. (Bramex) and Kornerstone Investment Group Limited (Kornerstone) as of October 1, 2005.The net interests used in this report are based on Transmeridian acquiring the interests of Bramex and Kornerstone bringing their total working interest to 100 percent. On the date of this report, the interests of Bramex and Kornerstone have not been acquired, but at the request of Transmeridian, this has been assumed to occur on January 1, 2006. The subject property is located in South Alibek Field, License Number 1557, in the Republic of Kazakhstan. At the request of Transmeridian, the income data were estimated using constant pricing and costs.
The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. The hydrocarbon price in effect on September 30, 2005 was provided by Transmeridian and was used in the preparation of this report. Future prices may vary significantly from the September 30, 2005 price. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
CONSTANT PRICING AND COSTS
Estimated Net Reserves and Income Data
South Alibek Field
100% Working Interest Ownership
| | | | | | | | | | | | |
As of October 1, 2005
|
| | | Proved
|
| | | Developed
| | Undeveloped
| | Total Proved
|
| | | Producing
| | Non-Producing
| | |
Net Remaining Reserves | | | | | | | | | | | | |
Oil/Condensate – Barrels | | | 139,218 | | | 1,668,534 | | | 71,900,739 | | | 73,708,492 |
Gas – MMCF | | | 0 | | | 0 | | | 0 | | | 0 |
| | | | |
Income Data | | | | | | | | | | | | |
Future Gross Revenue | | $ | 5,682,893 | | $ | 68,109,562 | | $ | 2,934,988,174 | | $ | 3,008,780,629 |
Deductions | | | 1,743,796 | | | 13,144,945 | | | 725,546,910 | | | 740,435,651 |
| | |
|
| |
|
| |
|
| |
|
|
Future Net Income (FNI) | | $ | 3,939,097 | | $ | 54,964,617 | | $ | 2,209,441,264 | | $ | 2,268,344,977 |
| | | | |
Discounted FNI @ 10% | | $ | 3,737,301 | | $ | 29,313,687 | | $ | 988,673,793 | | $ | 1,021,724,781 |
| | | | |
1200, 530 8TH AVENUE, S.W. CALGARY, ALBERTA T2P 3S8 | | TEL (403) 262-2799 | | FAX (403) 262-2790 |
621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 | | TEL (303) 623-9147 | | FAX (303) 623-4258 |
Transmeridian Exploration, Inc.
November 15, 2005
Page 2
Liquid hydrocarbons are expressed in standard 42 gallon barrels.
The future gross revenue is after the deduction of the normal direct costs of operating the wells, recompletion costs, and development costs. The future net income is before the deduction of Kazakhstan income tax and excess profit tax. No gas pipeline is in place nor is there a contract in place for sale of gas; therefore, no income is included for the gas that will be produced. Liquid hydrocarbon reserves account for all of the total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.
| | |
| | | Discounted Future Net Income As of October 1, 2005
|
Discount Rate Percent
| | Total Proved
|
5 | | $1,499,151,982 |
8 | | $1,186,889,220 |
12 | | $ 883,495,421 |
15 | | $ 716,116,324 |
The results shown above are presented for your information and should not be construed as our estimate of fair market value. These results are based on the proposed buyout of interests currently owned by Bramex and Kornerstone. At the request of Transmeridian, the proposed buyout of interests has been assumed to occur on January 1, 2006.
Reserves Included in This Report
Theproved reserves included herein conform to the definition approved by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC). The definitions of proved reserves are included under the tab “Petroleum Reserves Definitions” in this report.
Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled.
Transmeridian has additional interests in this concession that may contain substantial hydrocarbon potential not included herein. Transmeridian has stated that they have an active exploratory and development drilling program that may result in the discovery or reclassification of significant additional volumes.
The various reserve status categories are defined under the tab “Petroleum Reserves Definitions” in this report. The developed non-producing reserves included herein are comprised of the shut-in and behind-pipe category.
Estimates of Reserves
On October 1, 2005, wells SA-2 (KT2), SA-5 (KT2), and SA-14 (KT2) were producing. Well SA-2 is currently only producing from the KT2-1 interval, with behind-pipe reserves assigned to the KT2-3,4 and 5 intervals. Well SA-5 is currently producing in the KT2-1&2 reservoirs, but this interval may have
Transmeridian Exploration, Inc.
November 15, 2005
Page 3
been damaged during a previous work-over and a redrill has been included in this report to capture most of the remaining volumetric reserves assigned to this location. Well SA-14 started producing in May 2005 from the KT2-2 reservoir and has additional behind-pipe reserves assigned to the KT2-1,2,3,4 and 5 intervals.
Well SA-1 (KT2) was shut-in during September 2005 to isolate the KT2-1 reservoir which was believed responsible for producing a large volume of gas. Transmeridian is planning to continue production from the KT2-2&3 intervals, and additional behind-pipe reserves are assigned to the KT2-4 interval. Remaining reserves in the KT2-1 interval have been assumed to be recoverable when repressurization occurs from a secondary waterflood program that Transmeridian is planning to initiate.
Well SA-3 (KT2) is classified as proved undeveloped in this report, but started producing in October 2005 from the KT2-1&2 reservoir and has additional undeveloped reserves assigned to the KT2-1,2,3,4 and 5 intervals.
It is estimated that well SA-4 (KT2) was damaged during the drilling phase due to overbalanced mud, and an offset to that well has been included in this report to capture the volumetric reserves assigned to that location.
Well SA-17 (KT2) was hydraulically fractured in March 2005 and started producing in June from the KT2-2 interval. This well was shut-in on the date of this report for paraffin removal from the wellbore. Additional reserves are assigned as proved behind-pipe to the KT2-1,2,3,4 and 5 intervals.
All direct offset well locations in this report are proved undeveloped. All locations have a scheduled KT1 and a KT2 reservoir completion and each of these reservoir completions includes the cost of drilling a separate wellbore. All reserves included in this report were estimated using volumetric methods.
The cost of twenty-five wells have been included in this report for water injection into the KT1 reservoir and the cost of twenty-five wells have been included for water injection into the KT2 reservoir. The inclusion of these undeveloped wells gives a well count of one secondary wellbore to each primary well. The specific location of these wells has not been identified; therefore, the reservoir response to the water injection has not been assigned to specific wells, but a total estimated waterflood recovery from each reservoir is included in the reserve forecasts to represent a waterflood typecurve performance and recovery estimate from each reservoir.
A 15% primary recovery factor was assigned to each developed and undeveloped well in the KT1 and KT2 reservoirs. A secondary recovery factor of 15% was assigned to the KT1 waterflood and to the KT2 waterflood. The total primary and secondary recovery of 30% was based on analogy data from other fields.
An estimated annual decline rate (ADR) of 30% was assigned to the primary forecasts of the undeveloped wells. The final decline assigned to the KT1 and KT2 waterflood typecurve forecasts were also based on an approximate 30% ADR.
Transmeridian Exploration, Inc.
November 15, 2005
Page 4
As provided by Transmeridian, the revenue interests are calculated from a sliding-scale royalty payment made to the Kazakhstan government during the production period of this concession. The royalty percentage is based on the gross annual production as presented in the following table:
| | | | |
Kazakhstan Taxes
|
Annual Oil Production (bbls)
| | Royalty
Percentage
|
from
| | to
| |
| 0 | | 3,750,000 | | 2.0% |
| 3,750,001 | | 7,500,000 | | 2.5% |
| 7,500,001 | | 11,250,000 | | 3.0% |
| 11,250,001 | | 15,000,000 | | 3.5% |
| 15,000,001 | | 18,750,000 | | 4.0% |
| 18,750,001 | | 26,250,000 | | 4.5% |
| 26,250,001 | | 33,750,000 | | 5.0% |
| 33,750,001 | | 37,500,000 | | 5.5% |
| 37,500,001 | | capacity | | 6.0% |
In addition to the royalty payments shown above, Transmeridian has instructed an additional 3.5% overriding royalty interest to be deducted from the remaining revenue interests starting on January 1, 2006, to account for the buyout of Bramex.
Transmeridian has indicated that the South Alibek field will be operated under the terms of their Production Contract beginning January 1, 2006.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
Future Production Rates
Analogy production data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Transmeridian. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.
Transmeridian is planning to use ESPs (electric submersible pumps) in the field. No costs have been included for the purchase of ESPs and no associated oil rate changes have been assumed to occur in this report. The costs to purchase ESPs and future rate changes will be considered after there is sufficient historical performance to evaluate the results.
Hydrocarbon Prices
Transmeridian furnished us with hydrocarbon prices in effect on September 30, 2005. An oil price contract allows Transmeridian to sell their oil production at a discount of $21.20 per barrel less than Brent DTD quotations published in “Platt’s Crude Oil Marketwire”. This contract is valid through December 31, 2005, after which it may be extended by mutual agreement of the participating parties. The total amount of this contract is valid for the amount of approximately $12,000,000. The quantity of oil to be delivered under the current contract is 7,000 metric tons per month. Addendums to the contract can be established on a monthly basis so that quantities can be adjusted. Transmeridian shall have the right to insist on decreases in the discount applied to the Brent DTD quotations. Both parties of the contract have the right to relieve themselves of the obligations of the contract if agreements cannot be made. The September 30, 2005 oil price received by Transmeridian was $40.82 per barrel. This sale price was used in this report and was held constant for the life of the properties.
Transmeridian Exploration, Inc.
November 15, 2005
Page 5
Costs
Operating costs for the leases and wells in this report were supplied by Transmeridian and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.
Oil production is currently transported by truck to the facilities at the city of Zhem. This transportation cost is $2.00 per barrel of oil and appears under the heading of “other” in the Deductions section of each table. Additional costs provided by Transmeridian include a variable operating cost of $1.70 per barrel of oil and a constant operating cost of $300,000 per month for the primary operating expenses. Additional operating costs include $5,000 per month for each injection well when placed on line for secondary waterflood operations. This cost includes the maintenance of pumps, water filtration units, source water treating, produced water treating, and the water injection stations. A total of twenty-five water injection wells in the KT1 reservoir and twenty-five water injection wells in the KT2 reservoir are scheduled to be on line by the end of years 2010 and 2011, respectively, which is estimated to result in a maximum operating expense of $125,000 per month per reservoir for the water injection program.
Development costs were furnished by Transmeridian and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. Transmeridian is planning to use workover rigs to pre-drill most of the undeveloped wells in the field. The workover rigs will drill to the intermediate casing point, located just above the top of the KT1 reservoir, then traditional rotary drilling rigs will be used to drill the remaining depth. This procedure has an estimated savings of $1,000,000 per wellbore, which is reflected in this report, and is estimated to save 30 days of drilling time per location. The drilling and completion cost for the water injection wells include an additional $300,000 each to pay for the initial construction of the main pressure maintenance facility, the water injection stations, booster stations at the central processing facilities, and water filtration units. In addition to drilling and completion costs, this report includes future gross investments of $15,000,000 for the remaining facility costs, gathering stations, and to pay for a trunkline to connect to the Alibekmola-Kentia pipeline, which is approximately 1.5 kilometers from the South Alibek field.
This report also includes a $600,000 production bonus to be paid January 1, 2006, historical exploration costs of $4,692,433 amortized over the life of the project, and annual costs of $23,600 to cover liquidation costs at the end of the concession. All operating and development costs were held constant throughout the life of the properties.
General
Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 115 present our estimated projection of production and income by years beginning October 1, 2005, by reserve category and by well.
Transmeridian Exploration, Inc.
November 15, 2005
Page 6
While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were not considered in this constant pricing and cost evaluation.
The estimates of reserves presented herein were based upon a detailed study of the properties based on 100% Working Interest Ownership; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Transmeridian has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The proposed ownership interests, prices, and other factual data furnished by Transmeridian were accepted without independent verification. The estimates presented in this report are based on data available through September 2005.
Transmeridian has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.
Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.
This report was prepared for the exclusive use and sole benefit of Transmeridian Exploration, Inc. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Kirt Keelan, P.E.
Vice President
KLK/pl
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE)
AND
WORLD PETROLEUM CONGRESS (WPC)
DEFINITIONS
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms. In presenting these definitions, neither organization is recommending public disclosure of reserves classified as unproved. Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery. Because of potential differences in uncertainty, caution should be exercised when aggregating reserves of different classifications.
Reserves estimates will generally be revised as additional geologic or engineering data becomes available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical petroleum prices and associated costs and may involve an averaging period that is consistent with the purpose of the reserve estimate, appropriate contract obligations, corporate procedures, and government regulations involved in reporting these reserves.
In general, reserves are considered proved if the commercial producibility of the reservoir is supported by actual production or formation tests. In this context, the term proved refers to the actual quantities of petroleum reserves and not just the productivity of the well or reservoir. In certain cases, proved reserves may be assigned on the basis of well logs and/or core analysis that indicate the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) the undrilled portions of the reservoir that can reasonably be judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known occurrence of hydrocarbons controls the proved limit unless otherwise indicated by definitive geological, engineering or performance data.
Reserves may be classified as proved if facilities to process and transport those reserves to market are operational at the time of the estimate or there is a reasonable expectation that such facilities will be installed. Reserves in undeveloped locations may be classified as proved undeveloped provided (1) the locations are direct offsets to wells that have indicated commercial production in the objective formation, (2) it is reasonably certain such locations are within the known proved productive limits of the objective formation, (3) the locations conform to existing well spacing regulations where applicable, and (4) it is reasonably certain the locations will be developed. Reserves from other locations are categorized as proved undeveloped only where interpretations of geological and engineering data from wells indicate with reasonable certainty that the objective formation is laterally continuous and contains commercially recoverable petroleum at locations beyond direct offsets.
Reserves which are to be produced through the application of established improved recovery methods are included in the proved classification when (1) successful testing by a pilot project or favorable response of an installed program in the same or an analogous reservoir with similar rock and fluid properties provides support for the analysis on which the project was based, and (2) it is reasonably certain that the project will proceed. Reserves to be recovered by improved recovery methods that have yet to be established through commercially successful applications are included in the proved classification only (1) after a favorable production response from the subject reservoir from either (a) a representative pilot or (b) an installed program where the response provides support for the analysis on which the project is based and (2) it is reasonably certain the project will proceed.
RESERVES STATUS CATEGORIES
Reserves status categories define the development and producing status of wells and reservoirs.
Developed Reserves
Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be sub-categorized as producing or non-producing.
Producing
Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Non-Producing
Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.
Undeveloped Reserves
Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
| | | | | | |
| |  | | 100% WORKING INTEREST OWNERSHIP ESTIMATED PROJECTION OF FUTURE RESERVES AND INCOME SOUTH ALIBEK FIELD AS OF OCTOBER 1, 2005 CONSTANT PRICES AND COSTS TOTAL BUY-OUT | | TABLE 1 |
GRAND SUMMARY
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | TOTAL PROVED
ALL CATEGORIES |
| | | | | REVENUE INTEREST
| | PRODUCT PRICES
| | |
| | | Expense
Interest
| | Oil/
Condensate
| | Plant
Products
| | Gas
| | Oil/Cond
($/bbl)
| | Plt. Prod.
($/bbl)
| | Gas
($/Mcf)
| | DISCOUNTED FUTURE NET INCOME - $
COMPOUNDED MONTHLY
|
INITIAL | | | | | | | | | | | | | | | | 5.00 | % | | 1,499,151,982 |
FINAL | | | | | | | | | | | | | | | | 8.00 | % | | 1,186,889,220 |
REMARKS | | | | | | | | | | | | | | | | 10.00 | % | | 1,021,724,781 |
| | | | | | | | | | | | | | | | | 12.00 | % | | 883,495,421 |
| | | | | | | | | | | | | | | | | 15.00 | % | | 716,116,324 |
| | | | | | | | | | | | | | | | | | | | |
| | | | | ESTIMATED 8/8THS PRODUCTION
| | COMPANY NET PRODUCTION
| | AVERAGE PRICES
|
Year
| | Number
of Wells
| | Oil/Cond.
(Barrels)
| | Plant Products
(Barrels)
| | Gas
(MMcf)
| | Oil/Cond.
(Barrels)
| | Plant Products
(Barrels)
| | Sales Gas
(MMcf)
| | Oil/Cond.
($/bbl)
| | Plt Prod.
($/bbl)
| | Gas
($/Mcf)
|
2005 | | 6 | | 122,146 | | 0 | | 78 | | 59,852 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2006 | | 18 | | 1,708,410 | | 0 | | 1,030 | | 1,614,700 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2007 | | 37 | | 4,194,189 | | 0 | | 2,397 | | 3,946,354 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2008 | | 50 | | 6,155,843 | | 0 | | 3,573 | | 5,792,032 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2009 | | 50 | | 5,399,209 | | 0 | | 3,156 | | 5,080,116 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2010 | | 50 | | 5,138,498 | | 0 | | 3,025 | | 4,834,813 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2011 | | 49 | | 6,027,713 | | 0 | | 3,576 | | 5,671,475 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2012 | | 48 | | 7,203,434 | | 0 | | 4,294 | | 6,777,711 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2013 | | 48 | | 7,555,991 | | 0 | | 4,514 | | 7,073,261 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2014 | | 45 | | 6,625,623 | | 0 | | 3,961 | | 6,233,955 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2015 | | 44 | | 5,812,652 | | 0 | | 3,478 | | 5,469,124 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2016 | | 44 | | 5,260,590 | | 0 | | 3,148 | | 4,949,689 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2017 | | 42 | | 5,477,931 | | 0 | | 3,200 | | 5,154,186 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2018 | | 41 | | 4,119,031 | | 0 | | 2,411 | | 3,875,596 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
2019 | | 40 | | 2,881,558 | | 0 | | 1,686 | | 2,725,045 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
| | | | | | | | | | |
Sub-Total | | | | 73,682,817 | | 0 | | 43,528 | | 69,257,909 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
Remainder | | | | 4,706,125 | | 0 | | 2,739 | | 4,450,583 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
Total Future | | | | 78,388,942 | | 0 | | 46,267 | | 73,708,492 | | 0 | | 0 | | 40.82 | | 0.00 | | 0.00 |
| | | | | | | | | | |
Cumulative | | | | 733,469 | | 0 | | 611 | | | | | | | | | | | | |
Ultimate | | | | 79,122,411 | | 0 | | 46,878 | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | COMPANY FUTURE GROSS REVENUE (FGR) - $
| | PRODUCTION TAXES - $
| | FGR AFTER
PRODUCTION
TAXES - $
|
Year
| | From Oil/
Condensate
| | From Plant Products
| | From Gas
| | Other
| | Total
| | Oil/
Condensate
| | Plant Prod./
Other
| | Gas
| |
| 2005 | | 2,443,143 | | 0 | | 0 | | 0 | | 2,443,143 | | 0 | | 0 | | 0 | | 2,443,143 |
| 2006 | | 65,912,059 | | 0 | | 0 | | 0 | | 65,912,059 | | 0 | | 0 | | 0 | | 65,912,059 |
| 2007 | | 161,090,154 | | 0 | | 0 | | 0 | | 161,090,154 | | 0 | | 0 | | 0 | | 161,090,154 |
| 2008 | | 236,430,759 | | 0 | | 0 | | 0 | | 236,430,759 | | 0 | | 0 | | 0 | | 236,430,759 |
| 2009 | | 207,370,319 | | 0 | | 0 | | 0 | | 207,370,319 | | 0 | | 0 | | 0 | | 207,370,319 |
| 2010 | | 197,357,050 | | 0 | | 0 | | 0 | | 197,357,050 | | 0 | | 0 | | 0 | | 197,357,050 |
| 2011 | | 231,509,607 | | 0 | | 0 | | 0 | | 231,509,607 | | 0 | | 0 | | 0 | | 231,509,607 |
| 2012 | | 276,666,155 | | 0 | | 0 | | 0 | | 276,666,155 | | 0 | | 0 | �� | 0 | | 276,666,155 |
| 2013 | | 288,730,522 | | 0 | | 0 | | 0 | | 288,730,522 | | 0 | | 0 | | 0 | | 288,730,522 |
| 2014 | | 254,470,059 | | 0 | | 0 | | 0 | | 254,470,059 | | 0 | | 0 | | 0 | | 254,470,059 |
| 2015 | | 223,249,639 | | 0 | | 0 | | 0 | | 223,249,639 | | 0 | | 0 | | 0 | | 223,249,639 |
| 2016 | | 202,046,313 | | 0 | | 0 | | 0 | | 202,046,313 | | 0 | | 0 | | 0 | | 202,046,313 |
| 2017 | | 210,393,861 | | 0 | | 0 | | 0 | | 210,393,861 | | 0 | | 0 | | 0 | | 210,393,861 |
| 2018 | | 158,201,841 | | 0 | | 0 | | 0 | | 158,201,841 | | 0 | | 0 | | 0 | | 158,201,841 |
| 2019 | | 111,236,355 | | 0 | | 0 | | 0 | | 111,236,355 | | 0 | | 0 | | 0 | | 111,236,355 |
| | | | | | | | | |
| Sub-Total | | 2,827,107,836 | | 0 | | 0 | | 0 | | 2,827,107,836 | | 0 | | 0 | | 0 | | 2,827,107,836 |
| Remainder | | 181,672,793 | | 0 | | 0 | | 0 | | 181,672,793 | | 0 | | 0 | | 0 | | 181,672,793 |
| Total Future | | 3,008,780,629 | | 0 | | 0 | | 0 | | 3,008,780,629 | | 0 | | 0 | | 0 | | 3,008,780,629 |
| | | | | | | | | | | | | | | | |
| | | DEDUCTIONS - $
| | FUTURE NET INCOME BEFORE TAXES -$
|
Year
| | Operating
Costs
| | Ad Valorem
Taxes
| | Development
Costs
| | Other
| | Total
| | Undiscounted
| | Discounted
@10.00%
|
| | | | | | | Annual
| | Cumulative
| |
| 2005 | | 553,824 | | 0 | | 53,000 | | 122,146 | | 728,970 | | 1,714,172 | | 1,714,172 | | 1,691,814 |
| 2006 | | 6,305,631 | | 0 | | 66,661,000 | | 3,414,750 | | 76,381,381 | | -10,469,322 | | -8,755,150 | | -10,527,640 |
| 2007 | | 11,592,965 | | 0 | | 104,015,000 | | 8,388,377 | | 123,996,342 | | 37,093,812 | | 28,338,662 | | 29,477,796 |
| 2008 | | 15,718,148 | | 0 | | 84,490,000 | | 12,311,685 | | 112,519,834 | | 123,910,926 | | 152,249,588 | | 93,189,861 |
| 2009 | | 15,061,871 | | 0 | | 37,039,000 | | 10,798,418 | | 62,899,289 | | 144,471,030 | | 296,720,618 | | 99,323,277 |
| 2010 | | 15,218,662 | | 0 | | 30,901,000 | | 10,276,996 | | 56,396,658 | | 140,960,392 | | 437,681,010 | | 87,535,088 |
| 2011 | | 17,075,328 | | 0 | | 16,656,000 | | 12,055,426 | | 45,786,753 | | 185,722,854 | | 623,403,864 | | 104,426,903 |
| 2012 | | 19,104,053 | | 0 | | 200,000 | | 14,406,867 | | 33,710,921 | | 242,955,234 | | 866,359,098 | | 123,935,039 |
| 2013 | | 19,693,028 | | 0 | | 600,000 | | 15,111,981 | | 35,405,010 | | 253,325,512 | | 1,119,684,610 | | 117,153,585 |
| 2014 | | 18,111,404 | | 0 | | 400,000 | | 13,251,246 | | 31,762,650 | | 222,707,410 | | 1,342,392,020 | | 93,362,721 |
| 2015 | | 16,739,724 | | 0 | | 2,600,000 | | 11,625,303 | | 30,965,027 | | 192,284,612 | | 1,534,676,632 | | 72,886,503 |
| 2016 | | 15,801,219 | | 0 | | 2,000,000 | | 10,521,180 | | 28,322,399 | | 173,723,913 | | 1,708,400,545 | | 59,646,734 |
| 2017 | | 16,170,700 | | 0 | | 2,600,000 | | 10,955,863 | | 29,726,562 | | 180,667,299 | | 1,889,067,844 | | 56,115,367 |
| 2018 | | 13,860,569 | | 0 | | 0 | | 8,238,062 | | 22,098,631 | | 136,103,210 | | 2,025,171,054 | | 38,361,098 |
| 2019 | | 11,746,494 | | 0 | | 200,000 | | 5,763,117 | | 17,709,610 | | 93,526,745 | | 2,118,697,799 | | 23,861,765 |
| | | | | | | | |
| Sub-Total | | 212,753,620 | | 0 | | 348,415,000 | | 147,241,418 | | 708,410,037 | | 2,118,697,799 | | | | 990,439,909 |
| Remainder | | 22,413,363 | | 0 | | 200,000 | | 9,412,251 | | 32,025,614 | | 149,647,178 | | 2,268,344,977 | | 31,284,872 |
| Total Future | | 235,166,983 | | 0 | | 348,615,000 | | 156,653,669 | | 740,435,651 | | 2,268,344,977 | | | | 1,021,724,781 |
|
| Life of summary is: 19.25 years. |
These data are part of a Ryder Scott report and are subject to the conditions in the text of the report.
