SCHEDULE 1
Response to Comments of the Staff of
The Securities and Exchange Commission
by letter dated November 8, 2010 with respect to
Form 10-K for the fiscal year ended December 31, 2009,
Form 10-Q for the fiscal quarter ended March 31, 2010 and
Form 10-Q for the fiscal quarter ended June 30, 2010
Spindletop Oil & Gas Co.
Commission File No. 000-18774
_________________
The following information is to provide a response to comments of the
Staff of the Securities and Exchange Commission rendered by letter dated
November 8, 2010 with respect to Form 10-K Annual Report to the Securities and
Exchange Commission for the fiscal year ended December 31, 2009 of Spindletop
Oil & Gas Co. (the "Company" or "Spindletop") as well as Form 10-Q for the
quarter ended March 31, 2010 and Form 10-Q for the quarter ended June 30, 2010.
For convenience, each comment of the Staff is restated below, with our response
noted immediately following the comment. Also included in such response is a
letter/page reference to the text of each instrument where applicable.
Form 10-K for the Fiscal Year Ended December 31, 2009
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Financial Statements
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Note 2 - Summary of Significant Accounting Policies, page 59
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Oil and Gas Properties, page 60
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Comment/Observation No. 1. We note you disclose that you use the full
cost method of accounting for oil and gas properties. Please expand your
disclosure to discuss the limitation on your capitalized costs (i.e. the
ceiling test), noting the guidance in Rule 4-10(c)(4) of Regulation S-X.
Response to Comment/Observation No. 1.
Oil and Gas Properties
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The Company follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs associated with acquisition, exploration
and development of oil and gas reserves are capitalized and accounted for in
cost centers, on a country-by-country basis. For each cost center, capitalized
costs, less accumulated amortization and related deferred income taxes, shall
not exceed an amount (the cost center ceiling) equal to the sum of:
a) The present value of estimated future net revenues computed by applying
current prices of oil and gas reserves (with consideration of price
changes only to the extent provided by contractual arrangements) to
estimated future production of proved oil and gas reserves as of the date
of the latest balance sheet presented, less estimated future expenditures
(based on current costs) to be incurred in developing and producing the proved
reserves computed using a discount factor of ten percent and assuming
continuation of existing economic conditions; plus
b) The cost of properties not being amortized; plus
c) The lower of cost or estimated fair market value of unproven properties
included in the costs being amortized; less
d) Income tax effects related to differences between the book and tax basis
of the properties.
If unamortized costs capitalized within a cost center, less related deferred
income taxes, exceed the cost center ceiling (as defined), the excess is
charged to expense and separately disclosed during the period in which the
excess occurs. Amounts required to be written off will not be reinstated for
any subsequent increase in the cost center ceiling. Accordingly, no impairment
of oil and gas properties charge was recorded for 2010 or 2009.
Depreciation and amortization for each cost center are computed on a composite
unit-of-production method, based on estimated proven reserves attributable to
the respective cost center. All costs associated with oil and gas properties
are currently included in the base for computation and amortization. Such
costs include all acquisition, exploration, development costs and estimated
future expenditures for proved undeveloped properties as well as estimated
dismantlement and abandonment costs as calculated under the asset retirement
obligation category, net of salvage value. All of the Company's oil and gas
properties are located within the continental United States.
Gains and losses on sales of oil and gas properties are treated as adjustments
of capitalized costs. Gains or losses on sales of property and equipment, other
than oil and gas properties, are recognized as part of operations.
Expenditures for renewals and improvements are capitalized, while expenditures
For maintenance and repairs are charged to operations as incurred.
Note 18 - Supplemental Reserve Information (unaudited), page 75
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Comment/Observation No. 2. Please describe the internal controls you use
in your reserves estimation and the qualifications of the technical person
primarily responsible for overseeing the preparation of your reserves
estimates. Refer to Item 1202(a)(7) of Regulation S-K for guidance.
Response to Comment/Observation No. 2.
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company's net proved oil and natural gas reserves as of December 31, 2009
have been estimated by Company personnel. The Company's net proved oil and
natural gas reserves as of December 31, 2008, and 2007 have been estimated by
Netherland, Sewell & Associates, Inc.
All estimates are in accordance with generally accepted petroleum engineering
and evaluation principles and definitions and guidelines established by the
Securities and Exchange Commission. Our policies and practices regarding
internal control over the estimating of reserves are structured to objectively
and accurately estimate our oil and natural gas reserve quantities and present
values in compliance with the SEC's regulations and U.S. Generally Accepted
Accounting Principles. We maintain an internal staff of petroleum engineers
and geosciences professionals who work closely with the accounting and
financial departments to insure the integrity, accuracy and timeliness of data
used in the estimation process. The data used in our reserve estimation
process is based on historical results for production, oil and natural gas
prices received, lease operating expenses and development costs incurred,
ownership interest and other required data. Historical oil and gas prices,
lease operating expenses, and ownership interests are provided by and verified
by the Company's accounting department. While we have no formal committee
specifically designated to review reserve reporting and reserve estimation,
our senior management reviews and approves the reserve report and any
internally estimated significant changes to our proved reserves on a timely
basis.
The Petroleum Engineer responsible for the supervision and preparation of the
Company's internally generated reserve report has a Bachelor of Science degree
in Petroleum Engineering from Texas A&M University and has experience in
preparing economic evaluations and reserve estimates. He meets the
requirements regarding qualifications, objectivity and confidentiality set
forth in the Standards Pertaining to the Engineering and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Accordingly, the following reserve estimates were based on existing economic
and operating conditions. Oil and gas prices for 2009 were calculated using a
12-month average price, calculated as the unweighted arithmetic of the first-
day-of-the month price for each month of 2009. Oil and gas prices in effect
at December 31, were used for 2008 and 2007. Operating costs, production and
ad valorem taxes and future development costs were based on current costs with
no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values
should not be construed as the current market value of the Company's oil and
gas reserves or the costs that would be incurred to obtain equivalent reserves.
Comment/Observation No. 3. We note your report proved undeveloped
reserves as of December 31, 2009. Please disclose material changes in your
proved undeveloped reserves that occurred during 2009, discuss investments and
progress you have made during the year to develop these reserves and explain
the reasons why material amounts of proved undeveloped reserves remain
undeveloped for periods greater than give years to the extent you have such
reserves. Refer to Item 1203 of Regulation S-K for additional guidance.
Response to Comment/Observation No. 3.
Proved Undeveloped Reserves at the end of 2008 were calculated to be 8,764 bbl
oil and 2,877,311 mcf gas. At the end of 2009, Proved Undeveloped Reserves
were calculated to be 26,110 bbl oil and 1,848,520 mcf gas, an increase of
17,346 bbl oil and a decrease of 1,028,791 mcf gas. These Proved Undeveloped
reserves are based on the future development of two wells, neither of which
have been included in our reserve report for five years or longer.
The increase in Proved Undeveloped oil reserves from 2008 to 2009 was due to
the addition of an estimated 25,630 bbl oil for a projected
Papalote, E (3250-B) well located in our Papalote Block in Bee County, Texas.
This increase was offset by a reduction in estimated Proved Undeveloped oil
reserves of 8,274 bbl oil and 1,204,675 mcf gas from five Newark, E. (Barnett
Shale) wells that at the end of 2008 were projected to be drilled in our Krum
Block in Denton County, Texas. These drilling locations are held by production.
During 2009, natural gas prices decreased from an average price of $7.95 per
mcf to $3.71 per mcf, a decrease of approximately 53%. This decrease in prices
was not followed by a corresponding decrease in the cost of services and some
of our highly dependent gas projects and drilling programs became marginal to
uneconomic. Therefore we have temporarily removed these projects from the
development program until such time as prices rebound and the economics of
these projects project a proper rate of return.
The overall decrease in our Proved Undeveloped gas reserves was primarily from
these five Newark E. (Barnett Shale) wells and was offset by an increase of
approximately 172,884 mcf in projected gas reserves from a Newark, E (Barnett
Shale) gas well located in our Cresson NE Block in Parker County, Texas.
Projected reserves from this well were included in our 2008 Proved Undeveloped
gas reserves. Offset production to this projected well had matured for another
year and allowed a recalculation of increased ultimate production.
Comment/Observation No. 4. We note that your changes in the standardized
measure of discounted future net cash flows due to revisions of quantity
estimate on page 78 do not appear proportionate to your changes in reserves due
to revisions of previous estimates on page 76. Please provide the analysis
supporting changes in your standardized measure of discounted future net cash
flows due to revisions of quantity estimate for all periods presented.
Response to Comment/Observation No. 4.
Changes in the standardized measure of discounted future net cash flows:
Year Ended December 31,
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2009 2008 2007
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Beginning of the year $ 22,261,000 $ 42,214,000 $ 25,665,000
Oil and gas sales, net of
production costs (4,064,000) (9,169,000) (4,978,000)
Sales of reserves in place - - -
Net change in prices, net of
production costs (20,960,000) (82,308,000) 20,449,000
Extensions, discoveries and additions 1,332,000 16,636,000 7,243,000
Changes in production rates,
timing and other - - -
Revisions of quantity estimate (1) 9,663,000 54,243,000 (4,093,000)
Effect of income tax 5,652,000 (3,576,000) (4,638,000)
Accretion of discount 2,226,000 4,221,000 2,566,000
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End of year $ 16,110,000 $ 22,261,000 $ 42,214,000
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(1) Periodic revisions to the quantity estimates may be necessary as a result
of a number of factors, including reservoir performance, new drilling, oil and
natural gas prices, cost changes, technological advances, new geological or
geophysical data, or other economic factors.
Changes in the discounted future net cash flows were due in part to the net
changes in prices, net of production costs and reflect the wide variation in
prices used in the reserve report calculations between years. These prices
increased from 2007 to 2008, but decreased from 2008 to 2009. The revisions
shown for 2007 and 2008 were calculated by Netherland, Sewell & Assoc.,Inc.,
third party engineering consultants and the 2009 revisions were estimated
by Company personnel. Revisions of quantity estimates decreased from 2008 to
2009 reflecting the reduction in prices which reduced discounted and
undiscounted forecasted cash flows. The decrease in revisions of quantity
estimates between 2008 and 2009 is partially offset by increases in quantity
estimates due to operating efficiencies and lower operating costs and expenses
realized between years as vendors started reducing their charges to reflect
lower production costs in the industry. These lower costs and expenses
increased the calculated lives of proved producing properties and extended
the reserve estimates for many of the Company's proved producing properties.