SecProbe.io

CORRESP
1
filename1.htm

April
12, 2005

Securities
and Exchange Commission

450
Fifth Street, N.W.

Washington,
D.C. 20549-0405

Re:          Comment Letter Received March 7,
2005

Credo Petroleum Corporation

Form
10-KSB, Filed January 27, 2005

File
No. 000-08877

Attention:  Ms. Jennifer Goeken

Dear
Ms. Goeken:

This
letter is Credo Petroleum Corporation’s (the “Company”) response to the comment
letter received from the Securities and Exchange Commission (‘SEC”) dated March
7, 2005.  This letter will address each
of the SEC’s comments in the order that they appear in the comment letter along
with the Company’s proposed response.

Through
its year ended October 31, 2004, the Company has been a “small business issuer”
as defined by Regulation S-B and has filed its 1934 Act filings using the limited
disclosures required by Regulation S-B.
Effective November 1, 2004, the Company no longer qualifies as a “small
business issuer” and will file its future 1934 Act filings using the
disclosures required by Regulation S-K and

S-X.

Management’s
Discussion and Analysis, page 7

Drilling
Activities, page 9

1.                      The Company replaced 183% of the reserves
produced in fiscal 2004.  This reserve
replacement percentage is derived directly from the line items disclosed in the
reconciliation of beginning and ending proved reserve quantities contained in Footnote
6 to the consolidated financial statements, Supplementary Oil and Gas
Information, page 24 of the Company’s Form 10-KSB.  The ratio is calculated in Mcf of
gas-equivalent (‘Mcfge”) for the fiscal year ended October 31, 2004 as the sum
of revisions of previous estimates, extensions and discoveries, and purchases
of reserves in place divided by production in Mcfge for the same period.  The table below shows the calculation used by
the Company.

  Description

  Gas (Mcf)

  Oil (Bbls)

  Conversion

  Bbls to Mcf

  Oil

  (Mcfge)

  Total

  (Mcfge)

  Revisions of previous estimates

  68,000

  39,000

  6

  234,000

  302,000

  Extensions and discoveries

  2,999,000

  23,000

  6

  138,000

  3,137,000

  Purchases of reserves in place

  130,000

  1,000

  6

  6,000

  136,000

  Total reserve additions

  3,197,000

  63,000

  378,000

  3,575,000

  Production

  1,710,000

  41,000

  6

  246,000

  1,956,000

  Reserve replacement percentage

  183

  %

1

For
the year ended October 31, 2004 the Company’s finding cost per Mcfge was $1.98.  Finding costs are derived from the line item
Total Including Asset Retirement Obligation disclosed in the table identifying
Acquisition, Exploration and Development Costs Incurred contained in Footnote 6
to the consolidated financial statements, Supplementary Oil and Gas
Information, page 23 of the Company’s Form 10-KSB and from the line items
disclosed in the reconciliation of beginning and ending proved reserve
quantities contained in Footnote 6 to the consolidated financial statements,
Supplementary Oil and Gas Information, page 24 of the Company’s Form 10-KSB.  Finding costs have been calculated by
dividing the line item called Total Including Asset Retirement Obligation by
the amount of estimated net proved reserves added through revisions of previous
estimates, discoveries and purchases expressed in Mcfge.  The table below shows the calculation used by
the Company.

  Description

  2004

  Total Acquisition, Exploration and
  Development Costs Incurred including

  Asset Retirement Obligation

  7,089,000

  Divided By

  Total reserve additions (see above
  calculation)

  3,575,000

  Finding cost per Mcfge

  1.98

Net proved reserve additions including the portions that are proved
developed versus proved undeveloped can be calculated from the information in
Footnote 6 to the consolidated financial statements, Supplementary Oil and Gas
Information, page 24 of the Company’s Form 10-KSB. Net proved reserve additions
from extensions and discoveries totaled 3,137,000 Mcfge consisting of proved
developed reserves of 1,857,000 Mcfge and proved undeveloped reserves of 1,280,000
Mcfge.  As is stated in Management’s
Discussion and Analysis of Financial Condition and Results of Operations, Oil
and Gas Activities, Drilling Activities, and Calliope Gas Recovery System on
page 9 of the Company’s Form 10-KSB, these proved reserve additions for the
fiscal year ended October 31, 2004 were primarily the result of activity on the
Company’s two core projects, drilling along the shelf of the Northern Anadarko
Basin in northwest Oklahoma and application of the Company’s patented liquid
lift system on low pressure gas wells.  The
remaining net proved reserve additions of 438,000 Mcfge were comprised of revisions
of previous estimates of 302,000 Mcfge and purchases of proved developed
reserves in place of 136,000 Mcfge.

The Company used only proved reserves to calculate the reserve
replacement percentage and finding costs described above and did not include any
proved reserves attributable to consolidated entities or investments accounted
for using the equity method.

The finding costs and production replacement measures are used by the
Company as one way of measuring the Company’s performance and comparing it to
that of its competitors and the industry.
These performance statistics will subsequently be published by industry
analysts.  The calculation of both of
these performance measures is reliant upon the Company’s estimate of its proved
oil and gas reserve quantities.
Additionally, both of these performance measures are historical in
nature and are calculated as of a specific date and, may not be indicative of
the Company’s future performance.

2

The Company will continue to actively pursue adding reserves through
its two core projects in fiscal 2005 and expects these activities to continue
to be the primary source of its reserve additions.  However, the timing and extent of such
activities can be dependent on many factors which are beyond the Company’s
control, including but not limited to, the availability of oil field services
such as drilling rigs, production equipment and related services and access to
wells for application of the Company’s patented liquid lift system on low
pressure gas wells.  The prevailing price
of oil and gas has a significant affect on demand and, thus, the related cost
of such services and wells.

All of the Company’s oil and gas properties are located on-shore in the
continental United States.  The Company
is not aware of any material adverse issues related to its reserves regarding
regulatory approval, the availability of additional development capital, or the
installation of additional infrastructure.
The Company’s future drilling activities may not be successful, and its
overall drilling success rate may change. Unsuccessful drilling activities
could have a material adverse effect on the Company’s results of operations and
financial condition. Also, the Company may not be able to obtain the right to
drill in areas where it believes there is significant potential for the Company.

The Company’s reserves, and reserve values, are concentrated in 43
properties (“Significant Properties”).
Some of the Significant Properties are individual wells and others are
multi-well properties.  At October 31,
2004, the Significant Properties represent 24% of the Company’s total
properties but a disproportionate 75% of the discounted value (at 10%) of the Company’s
reserves. Individual Calliope wells comprise 26% of the Significant Properties
and represent 37% of the discounted reserve value of such properties.  Wells drilled on the four prospects discussed
in Item 2. Properties, General, comprise 30% of the Significant Properties and
represent 30% of the discounted value of such properties.

Estimates of reserve quantities and values for certain Significant
Properties must be viewed as being subject to significant change as more data
about the properties becomes available.
Such properties include wells with limited production histories
(including wells on which the Company’s patented liquid lift system has been
recently installed) and properties with proved undeveloped or proved
non-producing reserves.  In addition, the
Company’s patented liquid lift system is generally installed on mature
wells.  As such, they contain older down-hole
equipment that is more subject to failure than new equipment.  The failure of such equipment, particularly
casing, can result in complete loss of a well.
At October 31, 2004, natural gas represented 86% and crude oil
represented 14% of total reserves.  At
October 31, 2004, approximately 8% of the Company’s estimated reserves were
classified as proved undeveloped.

Price changes will affect the economic lives of oil and gas properties
and, therefore, price changes may cause reserve revisions.  Historically, such price changes have not
caused significant proved reserve revisions by the Company, except in 1986 when
a 51% decline in oil prices and a 45% decline in gas prices resulted in an 8.7%
reduction in estimated proved reserves.

3

One measure of the life of the Company’s proved reserves can be
calculated by dividing proved reserves at fiscal year end 2004 by production
for fiscal year 2004.  This measure
yields an average reserve life of nine years.
Since this measure is an average, by definition, some of the Company’s
properties will have a life shorter than the average and some will have a life
longer than the average.  The expected
economic lives of the Company’s individual properties varies widely depending
on, among other things, the size and quality of the reservoir, oil and natural
gas prices, possible curtailments in consumption by purchasers, and changes in
governmental regulations or taxation.  As
a result, the Company’s actual future net cash flows from proved reserves could
be materially different from its estimates.

The Company’s success depends primarily on locating and producing new
reserves, the level of production from existing wells, and prices of oil and natural
gas.  Production from the Company’s oil
and gas properties declines over time. In order to maintain current production
rates the Company must locate and develop or acquire new oil and gas reserves
to replace those being depleted by production. In addition, competition for oil
and gas leases, oil field services, and producing oil and gas properties is
intense and many of the Company’s competitors have financial and other
resources substantially greater than those available to it.  Without success on its core projects, the Company’s
reserves, production and revenues will decline rapidly.

Company
Proposed Response:

The
Company has addressed comment number 1 from the SEC by providing expanded
disclosure, supplemental information and calculations that address each of the
points raised.  The Company proposes to
expand its current disclosure by including the applicable information contained
in this response on a prospective basis for any 1934 Act filings where this
disclosure is required beginning with the second quarter ended April 30, 2005.

Critical
Accounting Policies and Estimates, page 11

In
response to SEC comment number 2, the Company proposes to expand its Critical
Accounting Policy disclosure as set forth below.

2.  Critical
Accounting Policies and Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period.  The
Company bases its estimates on historical experience and on various other
assumptions it believes to be reasonable under the circumstances.  Although actual results may differ from these
estimates under different assumptions or conditions, the Company believes that
its estimates are reasonable and that actual results will not vary
significantly from the estimated amounts. The Company believes the following
accounting policies and estimates are critical in the preparation of its
consolidated financial statements: the carrying value of its oil and gas
properties, the accounting for oil and gas reserves, and the estimate of its
asset retirement obligations.

4

OIL AND GAS PROPERTIES.  The Company
uses the full cost method of accounting for costs related to its oil and gas
properties.  Capitalized costs included
in the full cost pool are depleted on an aggregate basis using the
units-of-production method.  Depreciation,
depletion and amortization is a significant component of oil and gas properties.
A reduction in proved reserves without a corresponding reduction in capitalized
costs will cause the depletion rate to increase.

Both the volume of proved reserves and any estimated future
expenditures used for the depletion calculation are based on estimates such as
those described under “Oil and Gas Reserves” below.

The capitalized costs in the full cost pool are subject to a quarterly ceiling
test that limits such pooled costs to the aggregate of the present value of future
net revenues attributable to proved oil and gas reserves discounted at 10
percent plus the lower of cost or market value of unproved properties less any
associated tax effects.  If such
capitalized costs exceed the ceiling, the Company will record a write-down to
the extent of such excess as a non-cash charge to earnings.  Any such write-down will reduce earnings in
the period of occurrence and result in lower depreciation and depletion in
future periods.  A write-down may not be
reversed in future periods, even though higher oil and gas prices may
subsequently increase the ceiling.

The Company has made only one ceiling write-down in its 26-year
history.  That write down was made in
1986 after oil prices fell 51% and gas prices fell 45% between fiscal year end
1985 and 1986.

Changes in oil and gas prices have historically had the most
significant impact on the Company’s ceiling test. In general, the ceiling is
lower when prices are lower.  Even though
oil and gas prices can be highly volatile over weeks and even days, the ceiling
calculation dictates that prices in effect as of the last day of the test
period be used and held constant.  The
resulting valuation is a snapshot as of that day and, thus, is generally not
indicative of a true fair value that would be placed on the Company’s reserves
by the Company or by an independent third party.  Therefore, the future net revenues associated
with the estimated proved reserves are not based on the Company’s assessment of
future prices or costs, but rather are based on prices and costs in effect as
of the end the test period.

OIL AND GAS RESERVES.  The
determination of depreciation and depletion expense as well as ceiling test
write-downs related to the recorded value of the Company’s oil and gas
properties are highly dependent on the estimates of the proved oil and gas
reserves.  Oil and gas reserves include
proved reserves that represent estimated quantities of crude oil and natural
gas which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions. There are numerous uncertainties inherent in
estimating oil and gas reserves and their values, including many factors beyond
the Company’s control.  Accordingly,
reserve estimates are often different from the quantities of oil and gas
ultimately recovered and the corresponding lifting costs associated with the
recovery of these reserves.

5

The Company’s reserves, and reserve values, are concentrated in 43
properties (“Significant Properties”).
Some of the Significant Properties are individual wells and others are
multi-well properties.  At October 31,
2004, the Significant Properties represent 24% of the Company’s total
properties but a disproportionate 75% of the discounted value (at