Attached files
file | filename |
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10-K - FORM 10-K - BRIGHAM EXPLORATION CO | c13309e10vk.htm |
EX-21 - EXHIBIT 21 - BRIGHAM EXPLORATION CO | c13309exv21.htm |
EX-32.2 - EXHIBIT 32.2 - BRIGHAM EXPLORATION CO | c13309exv32w2.htm |
EX-31.1 - EXHIBIT 31.1 - BRIGHAM EXPLORATION CO | c13309exv31w1.htm |
EX-23.1 - EXHIBIT 23.1 - BRIGHAM EXPLORATION CO | c13309exv23w1.htm |
EX-23.2 - EXHIBIT 23.2 - BRIGHAM EXPLORATION CO | c13309exv23w2.htm |
EX-12.1 - EXHIBIT 12.1 - BRIGHAM EXPLORATION CO | c13309exv12w1.htm |
EX-32.1 - EXHIBIT 32.1 - BRIGHAM EXPLORATION CO | c13309exv32w1.htm |
EX-31.2 - EXHIBIT 31.2 - BRIGHAM EXPLORATION CO | c13309exv31w2.htm |
Exhibit 99.1
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
9601 AMBERGLEN BLVD., SUITE 117 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 625 | ||
AUSTIN, TEXAS 78729-1106 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
512-249-7000 FAX 512-233-2618 |
817- 336-2461 FAX 817-877-3728 |
713-651-9944 FAX 713-651-9980 |
||
www.cgaus.com |
January 12, 2011
Mr. Greg Cusack
Brigham Exploration Company
6300 Bridge Point Parkway
Building 2, Suite 500
Austin, Texas 78730
Brigham Exploration Company
6300 Bridge Point Parkway
Building 2, Suite 500
Austin, Texas 78730
Re: | Evaluation Summary | |||
Brigham Oil & Gas, L. P. Interests | ||||
Proved Reserves | ||||
As of December 31, 2010 | ||||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Dear Mr. Cusack:
As requested, this report was prepared on January 12, 2011 for Brigham Exploration Company for
the purpose of submitting our summary level reserve estimates and economic forecasts attributable
to the subject interests. We evaluated 100% of the Brigham Oil & Gas, L.P. reserves, which are
located in various counties in Louisiana, Montana, North Dakota, Oklahoma and Texas. This report,
with an effective date of December 31, 2010, was prepared using constant prices and costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).
Composite forecasts for the Total Proved, Proved Developed, Proved Developed Producing, Proved
Developed Non-Producing and Proved Undeveloped estimates are presented by category in Tables I-TP,
I-PD, I-PDP, I-PDNP and I-PUD, respectively. Table I-PD is the summation of the Proved Developed
Producing and Proved Developed Non-Producing estimates. The II Tables present estimates of
ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income
and discounted cash flow at ten percent for the individual properties which are listed
alphabetically by lease name for each category.
Brigham Exploration Company (SEC Prices)
January 12, 2011
Page 2
January 12, 2011
Page 2
The proved reserves and economics by category are summarized as follows:
Proved | ||||||||||||||||
Total | Developed | Undeveloped | ||||||||||||||
Net Reserves |
||||||||||||||||
Oil bbl |
52,208,590 | 17,521,908 | 34,686,684 | |||||||||||||
Gas Mcf |
87,821,742 | 36,537,117 | 51,284,617 | |||||||||||||
Net Revenue |
||||||||||||||||
Oil $ |
3,700,987,250 | 1,244,022,375 | 2,456,964,250 | |||||||||||||
Gas $ |
530,569,062 | 207,980,250 | 322,588,750 | |||||||||||||
Net BOE Production BOE |
66,845,539 | 23,611,428 | 43,234,117 | |||||||||||||
Ad Valorem
Tax $ |
13,528,012 | 6,550,199 | 6,977,813 | |||||||||||||
Operating
Expense $ |
677,165,812 | 259,770,875 | 417,395,000 | |||||||||||||
Production
Severance Tax $ |
427,454,969 | 144,554,531 | 282,900,469 | |||||||||||||
Investments
$ |
770,356,562 | 31,458,750 | 738,897,812 | |||||||||||||
Future Net
Cash Flow $ |
2,344,497,750 | 1,011,115,562 | 1,333,382,250 | |||||||||||||
Discounted @ 10%
(Present Worth) $ |
1,108,685,000 | 598,838,438 | 509,846,438 |
Future revenue is prior to deducting state production taxes and Ad Valorem
taxes. Future net cash flow is after deducting these taxes, future capital costs and operating
expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the
future net cash flow has been discounted at an annual rate of ten percent to determine its present
worth. The present worth is shown to indicate the effect of time on the value of money and should
not be construed as being the fair market value of the properties.
The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S.
gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract
temperature and pressure base. The net BOE production is based on one barrel of oil being the
equivalent of six Mcf of gas.
Our estimates are for proved reserves only and do not include any probable or possible
reserves nor have any values been attributed to interest in acreage beyond the location for which
undeveloped reserves have been estimated.
Hydrocarbon Pricing
The base oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.376/MMBTU,
respectively. As specified by the SEC, a company must use a 12-month average price, calculated as
the unweighted arithmetic average of the first-day-of-the-month price for each month within the
12-month period prior to the end of the reporting period. The base oil price is based upon
WTI-Cushing spot prices during 2010 and the base gas price is based upon Henry Hub spot prices
during 2010.
Brigham Exploration Company (SEC Prices)
January 12, 2011
Page 3
January 12, 2011
Page 3
The base prices were adjusted for differentials, which may include local basis differentials,
transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity
corrections. After these adjustments, the net realized prices over the life of the total proved
properties was estimated to be $70.888/bbl for oil and $6.041/MCF for gas. All economic factors
were held constant in accordance with SEC guidelines.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the
criteria of the SEC as defined in pages 1 and 2 of the Appendix. The reserves and economics are
predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties
currently in effect except as noted herein. The possible effects of changes in legislation or
other Federal or State restrictive actions which could affect the reserves and economics have not
been considered. However, we do not anticipate nor are we aware of any legislative changes or
restrictive regulatory actions that may impact the recovery of reserves.
This evaluation includes 386 proved undeveloped locations, with 314 locations in the Rocky
Mountain region (Bakken), 42 in West Texas (Wolfberry), 27 in the Gulf Coast region (Vicksburg) and
3 in the Anadarko Basin (Granite Wash, Hunton). Each of these drilling locations proposed as part
of Brighams development plans conforms to the proved undeveloped standards as set forth by the
SEC. In our opinion, Brigham has indicated they have every intent to complete this development plan
within the next five years. Furthermore, Brigham has demonstrated that they have the proper company
staffing, financial backing and prior development success to ensure this five year development plan
will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page 3 of the Appendix. Reserves
for proved developed producing wells were estimated using production performance methods for the
vast majority of properties. Certain new producing properties with very little production history
were forecast using a combination of production performance and analogy to offset production, both
of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast
using either volumetric or analogy methods, or a combination of both. These methods provide a
relatively high degree of accuracy for predicting proved developed non-producing and proved
undeveloped reserves for Brigham properties, due to the mature nature of their properties targeted
for development and an abundance of subsurface control data. The assumptions, data, methods and
procedures used herein are appropriate for the purpose served by this report.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas
price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were
calculated and prepared by Brigham and were thoroughly reviewed by us for accuracy, completeness
and variance from prior years. Lease operating expenses, price differentials and gas shrinkage were
determined at the well level using 12-month averages estimated from August 2009 through July 2010
statements. Ad valorem tax percentages were determined at the well level by comparing 2009 taxes
paid to 2009 total revenue. No ad valorem taxes are paid by Brigham in Louisiana, North Dakota or
Oklahoma.
Brigham Exploration Company (SEC Prices)
January 12, 2011
Page 4
January 12, 2011
Page 4
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office
and available from our files. All estimates represent our best judgment based on the data
available at the time of preparation. Due to inherent uncertainties in future production rates,
commodity prices and geologic conditions, it should be realized that the reserve estimates, the
reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be
more or less than the estimated amounts.
An on-site field inspection of the properties has not been performed nor have the mechanical
operation or condition of the wells and their related facilities been examined nor have the wells
been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to
the properties has not been investigated nor considered. The cost of plugging and the salvage
value of equipment at abandonment have not been included.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up
of independent registered professional engineers and geologists that have provided petroleum
consulting services to the oil and gas industry for over 50 years. This evaluation was prepared by
W. Todd Brooker, Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas
Licensed Professional Engineer (License #83462). We do not own an interest in the properties or
Brigham Exploration Company and are not employed on a contingent basis. We have used all methods
and procedures that we consider necessary under the circumstances to prepare this report. Our
work-papers and related data utilized in the preparation of these estimates are available in our
office.
Yours very truly, | ||
Cawley, Gillespie & Associates, Inc. | ||
Texas Registered Engineering Firm F-693 | ||
W. Todd Brooker, P. E. | ||
Vice President |
APPENDIX
Explanatory Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Property Description Location
Reserve Classification and Development Status
Effective Date of Evaluation
Description of Table Information
Identity of Interest Evaluated
Property Description Location
Reserve Classification and Development Status
Effective Date of Evaluation
FORECAST
(Columns)
(1)(11)
|
Calendar or Fiscal years/months commencing on effective date. | |
(2)(3)
|
Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. (Gross MBOE is shown to right of Ultimate Recovery values in light gray font, calculated by dividing the ultimate gross gas production by six (6) then adding to the ultimate gross oil production.) | |
(4)(5)
|
Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |
(6)
|
Average (volume weighted) Gross Liquid Price per barrel adjusted for average differential above or below Nymex, but before deducting production-severance taxes. (Composite differential in $/bbl shown at left in light gray font) | |
(7)
|
Average (volume weighted) Gross Gas Price per Mcf adjusted for average differential above or below Nymex, but before deducting production-severance taxes. (Composite differential in $/mcf shown at left in light gray font) | |
(8)
|
Revenue derived from oil sales column (4) times column (6). | |
(9)
|
Revenue derived from gas sales column (5) times column (7). | |
(10)
|
Total Revenue column (8) plus column (9). | |
(11)
|
Calendar or Fiscal years/months commencing on effective date. | |
(12)
|
Net MBOE Production (equivalent net oil production) Accruable to evaluated interest is calculated by dividing the net gas production by six (6) then adding to the net oil production. | |
(13)
|
Ad Valorem Taxes. | |
(14)
|
Average Gross Wells. | |
(15)
|
Average Net Wells are gross wells times working interest. | |
(16)
|
Operating Expenses are direct operating expenses to the evaluated working interest. | |
(17)
|
Production Taxes Severance Taxes deducted from gross oil and gas revenue. | |
(18)
|
Investment, if any, includes work-overs, future drilling costs, pumping units, etc. and may be included either tangible or intangible or both. | |
(19)
|
Future Net Cash Flow is column (10) less columns (13), (16), (17) and (18). The data in column (19) are accumulated in column (20). Federal income taxes have not been considered. | |
(20)
|
Cumulative Future Net Cash Flow. | |
(21)
|
Cumulative Cash Flow Discounted @ 10% is calculated by discounting monthly cash flows at the specified annual rates. |
MISCELLANEOUS
DCF Profile
|
| The cash flow discounted at six different rates are shown at the bottom of columns (20-21). Interest has been compounded monthly. | ||
Life
|
| The economic life of the appraised property is noted in the lower right-hand corner of the table. | ||
Footnotes
|
| Comments regarding the evaluation may be shown in the lower left-hand footnotes. | ||
Price Deck
|
| A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
Appendix | ||||
Cawley, Gillespie & Associates, Inc. | Page 1 |
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as
amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions
of oil and gas reserves:
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities
of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically produciblefrom 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 a 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 (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.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of
any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost
of the required equipment is relatively minor compared to the cost of a new well; and
(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.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves
of any category that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development
spacing areas that are reasonably certain of production when drilled, unless evidence using
reliable technology exists that establishes reasonable certainty of economic producibility at
greater distances.
(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.
Appendix | ||||
Cawley, Gillespie & Associates, Inc. | Page 2 |
(18) Probable reserves. Probable reserves are those additional reserves that are
less certain to be recovered than proved reserves but which, together with proved reserves, are as
likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining
quantities recovered will exceed the sum of estimated proved plus probable reserves. When
probabilistic methods are used, there should be at least a 50% probability that the actual
quantities recovered will equal or exceed the proved plus probable reserves estimates.
(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.
(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
(17) Possible reserves. Possible reserves are those additional reserves that are
less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a
project have a low probability of exceeding proved plus probable plus possible reserves. When
probabilistic methods are used, there should be at least a 10% probability that the total
quantities ultimately recovered will equal or exceed the proved plus probable plus possible
reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves
where data control and interpretations of available data are progressively less certain.
Frequently, this will be in areas where geoscience and engineering data are unable to define
clearly the area and vertical limits of commercial production from the reservoir by a defined
project.
(iii) Possible reserves also include incremental quantities associated with a greater
percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable
reserves.
(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 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 (22)(iii) of this section (above), 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.
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised
January 1, 2010 to state that a registrant engaged in oil and gas producing activities shall
provide the information required by Subpart 1200 of Regulation SK. This is relevant in that
Instruction 2 to paragraph (a)(2) states: The registrant is permitted, but not required, to
disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of
this Item.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and
related substances anticipated to be economically producible, as of a given date, by application of
development projects to known accumulations. In addition, there must exist, or there must be a
reasonable expectation that there will exist, the legal right to produce or a revenue interest in
the production, installed means of delivering oil and gas or related substances to market, and all
permits and financing required to implement the project.
Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by
major, potentially sealing, faults until those reservoirs are penetrated and evaluated as
economically producible. Reserves should not be assigned to areas that are clearly separated from a
known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low
reservoir, or negative test results). Such areas may contain prospective resources (i.e.,
potentially recoverable resources from undiscovered accumulations).
Appendix | ||||
Cawley, Gillespie & Associates, Inc. | Page 3 |
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production
performance, (2) material balance, (3) volumetric and (4) analogy.
Most estimates, although based primarily on one method, utilize other methods depending on the
nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a
large variation exists in the quality, quantity and types of information available on individual
properties. Operators are generally required by regulatory authorities to file monthly production
reports and may be required to measure and report periodically such data as well pressures,
gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in
obtaining and/or making available geological and engineering data. The resulting lack of
uniformity in data renders impossible the application of identical methods to all properties, and
may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and
generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on
the premise that all factors which have controlled the performance to date will continue to control
and that historical trends can be extrapolated to predict future performance. The only information
required is production history. Capacity production can usually be analyzed from graphs of rates
versus time or cumulative production. This procedure is referred to as decline curve analysis.
Both capacity and restricted production can, in some cases, be analyzed from graphs of producing
rate relationships of the various production components. Reserve estimates obtained by this method
are generally considered to have a relatively high degree of accuracy with the degree of accuracy
increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production
and pressure performance on the premise that the reservoir volume and its initial hydrocarbon
content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be
estimated by analyzing changes in pressure with respect to production relationships. This method
requires reliable pressure and temperature data, production data, fluid analyses and knowledge of
the nature of the reservoir. The material balance method is applicable to all reservoirs, but the
time and expense required for its use is dependent on the nature of the reservoir and its fluids.
Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for
compressibility versus cumulative production, requiring only data that are usually available.
Estimates for other reservoir types require extensive data and involve complex calculations most
suited to computer models which makes this method generally applicable only to reservoirs where
there is economic justification for its use. Reserve estimates obtained by this method are
generally considered to have a degree of accuracy that is directly related to the complexity of the
reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid
properties to calculate the volume of hydrocarbons in-place. The data required are well
information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid
content and location. The volumetric method is most applicable to reservoirs which are not
susceptible to analysis by production performance or material balance methods. These are most
commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons
in-place that can be recovered is not an integral part of the volumetric calculations but is an
estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve
estimates obtained by this method are generally considered to have a low degree of accuracy; but
the degree of accuracy can be relatively high where rock quality and subsurface control is good and
the nature of the reservoir is uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is
based on observations of similar situations and includes consideration of theoretical performance.
The analogy method is applicable where the data are insufficient or so inconclusive that reliable
reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are
generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of
estimates. These estimates are subject to continuing change as additional information becomes
available. Reserve estimates which presently appear to be correct may be found to contain
substantial errors as time passes and new information is obtained about well and reservoir
performance.
Appendix | ||||
Cawley, Gillespie & Associates, Inc. | Page 4 |