UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________
FORM 10-KSB
________________________________________________________________
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
___ SECURITIES ACT OF 1934
For The Fiscal Year Ended October 31, 1999
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
SECURITIES EXCHANGE ACT OF 1934
For the transition period _____________ to ____________
Commission File Number 0-8877
_________________________________________________________________
CREDO PETROLEUM CORPORATION
_________________________________________________________________
(Exact name of registrant as specified in charter)
Colorado 84-0772991
(State of incorporation) (I.R.S. employer identification
number)
1801 Broadway, Suite 900, Denver, Colorado 80202-3837
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code:
(303) 297-2200
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.10 Par Value
2,979,437 Shares Outstanding, Net of Treasury Stock,
at the Close of Business on December 31, 1999
(Title of class and shares outstanding)
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
____
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
_____ _____
As of October 31, 1999, the aggregate market value of common
stock held by non-affiliates of the registrant was approximately
$7,979,000.
DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof - Proxy
Statement to be filed with the Commission in connection with the
company's 2000 Annual Meeting.
<PAGE>
PART I.
ITEM 1. BUSINESS
General
CREDO Petroleum Corporation ("CREDO") was incorporated in
Colorado in 1978. CREDO and its wholly owned subsidiaries, SECO
Energy Corporation and United Oil Corporation ("SECO", "United"
and collectively "the company"), are Denver, Colorado based
independent oil and gas companies which engage in oil and gas
acquisition, exploration, development and production activities
mostly in the Mid-Continent and Rocky Mountain regions of the
United States. The company operates in eight states and has nine
employees. CREDO is an active operator in the Rocky Mountain
Region and in Kansas. United is an active operator doing
business exclusively in Oklahoma, and SECO owns royalty interests
primarily in the Rocky Mountain region. References to years as
used in this report indicate fiscal years ended October 31.
The company's primary business activities are (i) oil and gas
production, (ii) application of recently developed fluid lift
technology to low pressure gas reservoirs, (iii) purchasing
producing oil and gas properties, (iv) exploration for and
development of oil and gas reserves, and (v) operation of oil and
gas properties for the company's interest and for the interests
of third parties.
Oil and Gas Operations
Operations are conducted primarily in the Mid-Continent and Rocky
Mountain regions of the United States. The company owns
producing and non-producing property interests in eight states.
The company's staff oversees the operations of existing
properties, evaluates property acquisition opportunities and
drilling prospects, oversees workovers to install fluid lift
applications, and oversees drilling and completion of new wells.
Operations are concentrated on shallow to medium depth properties
generally ranging from 7,000 to 10,000 feet. A portion of the
funds necessary for acquisition, exploration or development of
properties is raised through farmouts, joint ventures, or other
similar types of cost sharing arrangements. Involvement of
outside participants reduces the company's return on individual
successful ventures. However, it limits the company's risk from
unsuccessful ventures and provides exposure to a larger volume of
activities than would otherwise be possible.
The company acts as 'operator' of 77 wells pursuant to standard
industry Operating Agreements, and it owns an interest in
approximately 290 wells which are operated by outside parties.
In addition, the company is general partner of three private
limited partnerships. The Partnerships are in the production
stage of operations.
Markets and Customers
Marketing of the company's oil and gas production is influenced
by many factors which are beyond the company's control and the
exact effect of which cannot be accurately predicted. These
factors include changes in supply and demand, changes in market
prices, regulatory changes, technological advances, access to
attractive foreign exploration prospects, and actions of major
foreign producers.
The company sells its oil production to crude oil purchasing
companies at competitive spot field prices. Crude oil and
condensate production are readily marketable. Crude oil is cost
efficiently transportable from production centers to demand
centers and is, therefore, subject to world-wide supply and
demand. Oil prices are primarily dependent upon available oil
supplies which can vary significantly depending on production and
pricing policies of OPEC and other major producing countries and
on significant events in major producing regions such as the
Persian Gulf War in 1991 and the continuing U.N. sanctions
against Iraq.
<PAGE>
During 1998, per barrel oil prices fell to less than $10.00 and
subsequently recovered to the low twenty dollar range. At
December 31, 1998, inflation adjusted oil prices stood at 50 year
lows according to the American Petroleum Institute. Oil prices
subsequently recovered and were consistently over $20.00 per
barrel during the second half of 1999. The fall and recovery in
oil prices during the past two years hinged primarily on the
response of major producing OPEC nations to changes in the
worldwide supply and demand for oil which were caused by weather,
production from Iraq, economic changes in Asia, and discovery of
new reserves around the world. Management cannot reasonably
predict the extent or timing of oil price fluctuations.
Deregulation of natural gas pricing and transportation have
resulted in far-reaching and fundamental changes in the
producing, transportation and marketing segments of the natural
gas industry. Gas price decontrol and the advent of an active
spot market for natural gas have resulted in prices received by
the company being subject to significant fluctuations. Prices
tend to be higher in peak demand periods such as fall and winter
and to be lower during weak demand periods. The company
presently sells most of its gas through short-term contracts with
terms of one year or less which are designed to obtain the best
available prices and deliverabilities. Virtually all of the
company's gas contracts provide for prices based on monthly
"spot" prices for the applicable market area. These prices are
reduced ("netted") by the costs of gathering and transporting the
gas.
The company periodically hedges the price of a portion of its
natural gas and crude oil production by forward selling in the
futures markets. Information concerning hedging activities is
contained under "Management's Discussion and Analysis of
Financial Condition and Results of Operations-Product Prices,
Production and Investments" on page 8 and in Note (1) to the
Consolidated Financial Statements.
Information concerning the company's major customers is included
in Note (6) to the Consolidated Financial Statements. The
company's ability to market its oil and gas is generally not
dependent on a single purchaser.
Refer to "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for further information
regarding oil and gas markets and prices.
Competition and Regulation
The oil and gas industry is intensely competitive. The company
competes with larger more well established oil and gas companies
including, on occasion, major companies. The significant areas
of competition are in acquiring producing (or productive) oil and
gas properties (in particular those for application of the
company's recently developed fluid lift technology), acquiring
leases for drilling or development, and selling natural gas. The
primary competitive factors for acquisitions are the price the
company is willing to pay and the financial resources readily
available to the company to fund acquisitions. The primary
factors which affect the company's ability to sell its natural
gas include proximity to markets, proximity to and capacity of
natural gas pipelines and transportation and processing
facilities, and quantities of gas which can be aggregated for
sale. Although both oil and gas are generally readily saleable
at market prices, they compete for market share with each other
and with other energy sources such as coal and nuclear power.
Oil and gas drilling and production operations are regulated by
various Federal, state and local agencies. These agencies issue
binding rules and regulations which increase the company's cost
of doing business and which carry penalties, often substantial,
for failure to comply. It is anticipated that the aggregate
burden on the company of Federal, state and local regulation will
continue to increase particularly in the area of rapidly changing
environmental laws and regulations. The company believes that
its present operations substantially comply with applicable
regulations. To date, such regulations have not had a material
effect on the company's operations, or the costs thereof. There
are no known environmental or other regulatory matters related to
the company's operations which are reasonably expected to result
in material liability to the company. There are, however,
significant water production and disposal issues related to the
burgeoning coal bed methane play in Wyoming. These are currently
the subject of considerable scrutiny by regulatory agencies and
by land and mineral owners. These water issues may result in new
legislation and environmental controls. It is not possible at
this time for the company to predict what such legislation or
controls, if any, might result or what impact they might have on
the company's coal bed methane operations in Wyoming. The company
does not believe that capital expenditures related to
environmental control facilities or other regulatory matters will
be material in fiscal 2000.
No prediction can be made as to what legislation or regulations
may be enacted or what additional legislation or regulations may
be proposed.
<PAGE>
ITEM 2. PROPERTIES
General
Capital expenditure for oil and gas activities totaled $670,000
(before property sales proceeds) in 1999. During 1999, the
company participated in drilling 33 gas wells in Oklahoma and
Wyoming (including commencing development of certain coal bed
methane leases in Wyoming) and purchased and sold producing
property interests. In addition, the company actively pursued
the application and refinement of new fluid lift technology to
enhance recovery of natural gas reserves from mature wells in low
pressure gas reservoirs. For more complete information regarding
these activities, refer to "Management's Discussion and Analysis
of Financial Condition and Results of Operations-Oil and Gas
Activities".
Capital expenditures for oil and gas activities totaled
$1,421,000 (before property sales proceeds) in 1998. During
1998, the company participated in drilling four gas wells in
Oklahoma and Wyoming, purchased and sold significant interests in
coal bed methane leases in Wyoming, continued to participate in
installation of a waterflood in Oklahoma, and purchased producing
property interests. In addition, the company participated in
development of new technology to enhance recovery of natural gas
reserves from mature wells in low pressure gas reservoirs. For
more complete information regarding these activities, refer to
"Management's Discussion and Analysis of Financial Condition and
Results of Operations-Oil and Gas Activities".
The company's reserves are concentrated in relatively few
properties. At October 31, 1999, approximately 75% of the value
of the company's estimated reserves were concentrated in 23% of
the company's producing wells. The company's most significant
producing property during 1999 (placed on production in early
1998) accounted for approximately 25% of the company's total gas
production and about 6% of the company's estimated proved gas
reserve quantities at fiscal year end. The company owns 49% of
the well and is the operator. The well is currently producing at
the rate of approximately 466 Mcfg per day with minor amounts of
oil and water. Measured surface casing pressures for the well
have declined faster than expected indicating that the reservoir
is smaller than originally anticipated. Although the pressures
have been taken into account in estimating remaining recoverable
reserves for the well, they are based on limited data and are
less precise than reserve estimates for wells with an extended
production history. Accordingly, reserves estimates must be
viewed as being subject to significant change as more data about
the well becomes available.
Over the past two years, the company participated in developing
new fluid lift technology. The technology is designed to
efficiently lift fluids from wellbores using pressure
differentials, and is primarily applicable to mature natural gas
wells in low pressure reservoirs. At July 31, 1999, the company
has applications on four of its wells. All of the applications
have initially resulted in gas production rates which have
equaled or exceeded the company's expectations. The most recent
application, completed in July 1999, resulted in restoring a
previously producing zone which was abandoned in 1994 to daily
production of 620 to 675 Mcfg and minor amounts of oil and water.
The company owns 75% of the well and is the operator. Since the
well commenced production in July 1999, it has accounted for
approximately 9% of the company's total gas production and, at
October 31, 1999, it accounted for about 13% of the company's
estimated proved gas reserve quantities. The well is the
company's largest producing well in terms of production and
reserves. It has a very limited operating history using the new
production technology, and accordingly, reserve estimates must be
viewed as being subject to significant change as more data about
the well becomes available.
During fiscal 1999, the Tracy Federal #1 well, which was
worked-over and restored to production last year, produced at
daily rates up to 300 Mcfg, four to five barrels of oil and four
to six barrels of water. During the fourth quarter of fiscal
1999, the company sold its 78.25% working interest in the well
for $487,000. In accordance with full cost accounting rules, the
sale proceeds were credited to oil and gas properties and do not
affect operating results.
<PAGE>
Estimated Proved Oil and Gas Reserves and Future Net Revenues
In 1999, 1998, and 1997, McCartney Engineering, Inc., an
independent petroleum engineering firm, estimated proved reserves
for the company's significant properties which represented 64% in
1999, 62% in 1998 and 60% in 1997 of the total estimated future
value of estimated reserves. Remaining reserves were estimated
by the company in all years. At October 31, 1999, natural gas
represented 78% and crude oil represented 22% of total reserves
denominated in equivalent barrels using a six Mcf of gas to one
barrel of oil conversion ratio.
The following table sets forth, as of October 31 of the indicated
year, information regarding the company's proved reserves which
is based on the assumptions set forth in Note (6) to the
Consolidated Financial Statements where additional reserve
information is provided. The average price used to calculate
estimated future net revenues was $21.01, $12.59, and $19.97 per
barrel for oil and $2.73, $2.03, and $2.69 per Mcf for gas as of
October 31, 1999, 1998, and 1997, respectively. Amounts do not
include estimates of future Federal and state income taxes.
<TABLE>
<CAPTION>
Estimated Future
Oil Gas Estimated Future Net Revenues
Year bbls)* (Mcf)* Net Revenues Discounted at 10%
________________________________________________________________
<S> <C> <C> <C> <C>
1999 321,000 6,683,000 $16,254,000 $9,856,000
1998 314,000 6,676,000 $11,385,000 $7,415,000
1997 368,000 5,868,000 $14,212,000 $8,518,000
</TABLE>
* Of 1999, 1998 and 1997 amounts, proved developed reserves were
287,000, 302,000, and 335,000 barrels of oil and 5,703,000,
5,909,000, and 4,874,000 Mcf of gas, respectively.
Production, Average Sales Prices and Average Production Costs
The company's net production quantities and average sales price
per unit for the indicated years are set forth below.
<TABLE>
<CAPTION>
1999 1998 1997
_______________________________________________________________
Product Volume Price Volume Price Volume Price
_______________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
Gas (Mcf) 858,000 $ 2.14 781,000 $ 1.98 545,000 $ 2.21
Oil (bbls) 39,000 $15.64 40,000 $14.10 39,000 $20.31
</TABLE>
Average production costs, including production taxes, per unit of
production (using a six to one conversion ratio of Mcfs to
barrels) were $4.49, $5.00, and $5.90 per barrel in 1999, 1998,
and 1997, respectively.
Productive Wells and Developed Acreage
Developed acreage at October 31, 1999 totaled 17,400 net and
96,800 gross acres. At October 31, 1999, the company owned
working interests in 49.51 net (177 gross) wells consisting of
19.72 net (45 gross) oil wells and 29.79 net (132 gross) gas
wells. In addition, the company owned royalty and production
payment interests in approximately 184 oil and gas wells. In
1999, the company divested of 5.63 net (14 gross) wells. In the
same period, the company drilled and acquired interests in 4.84
net (34 gross) wells in which it did not previously own an
interest and 12 wells where the company previously owned an
interest.
<PAGE>
Undeveloped Acreage
The following table sets forth the number of undeveloped acres
which will expire during the next five fiscal years (and
thereafter) unless production is established in the interim.
Undeveloped acres "held-by-production" represent the undeveloped
portions of producing leases which will not expire until
commercial production ceases. A "Net Royalty Acre" is the
equivalent of a 12.5% royalty or production payment interest in
one net working interest acre under lease.
<TABLE>
<CAPTION>
Working
Royalty Interest Acreage Interest Acreage
____________________________________________________________
Expiration Net
Year Ending Royalty
October 31 Gross Net Acres Gross Net
____________________________________________________________
<S> <C> <C> <C> <C> <C>
2000 600 600 - 5,900 1,700
2001 - - - 3,800 1,600
2002 5,300 5,300 100 13,200 900
2003 3,700 3,700 100 20,700 2,300
2004 2,400 2,400 - 13,500 4,100
Thereafter 1,100 1,100 - 31,800 10,200
Held-By-Production 110,200 89,100 7,700 11,700 2,500
____________________________________________________________
123,300 102,200 7,900 100,600 23,300
============================================================
</TABLE>
The acreage in the above table is located in eight states
including Oklahoma, Colorado, Wyoming, North Dakota and Utah.
Royalty and production payment interests are referred to
collectively as royalty interests. In general, "royalty" and
"production payment" interests are non-operated interests which
are not burdened by costs of exploration or lease operations,
while "working interests" have operating rights and participate
in such costs.
Drilling and New Zone Recompletions
The following tables set forth the number of gross and net oil
and gas wells in which the company has participated in drilling
or new zone recompletions and the results thereof for the periods
indicated.
<TABLE>
<CAPTION>
Gross Wells
____________________________________________________________
Year Ended Total Gross Exploratory Development
_______________ ________________
October 31 Wells Oil Gas Dry Oil Gas Dry
____________________________________________________________
<S> <C> <C> <C> <C> <C> <C> <C>
1999 33 - 31(1) - - 2 -
1998 4 - 3 1 - - -
1997 3 - 2 - - 1 -
1978-1996 138 11 28 71 15 9 4
____________________________________________________________
178 11 64 72 15 12 4
============================================================
</TABLE>
<TABLE>
<CAPTION>
Net Wells
_______________________________________________________________
Year Ended Total Net Exploratory Development
__________________ ___________________
October 31 Wells Oil Gas Dry Oil Gas Dry
_______________________________________________________________
<S> <C> <C> <C> <C> <C> <C> <C>
1999 3.841 - 3.701(1) - - .140 -
1998 1.061 - .811 .250 - - -
1997 1.250 - .750 - - .500 -
1978-1996 23.306 1.401 4.223 10.693 4.350 1.154 1.485
_______________________________________________________________
29.458 1.401 9.485 10.943 4.350 1.794 1.485
===============================================================
(1) Shallow coal bed methane gas wells at less than 1,000 feet
in depth.
</TABLE>
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
The company is not a party to any material pending legal
proceedings. No such proceedings have been threatened and none
are contemplated by the company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during
the fourth quarter of fiscal 1999.
PART II.
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The company's common stock is traded on the National Association
of Securities Dealers Automated Quotation System under the symbol
"CRED". Market quotations
shown below were reported by the National Association of
Securities Dealers, Inc. and represent prices between dealers
excluding retail mark-up or commissions.
<TABLE>
<CAPTION>
1999 1998
______________________________________________________________
Fiscal Quarter Ended High Low High Low
______________________________________________________________
<S> <C> <C> <C> <C>
January 31 $2.00 $1.75 $3.50 $2.88
April 30 3.00 1.75 3.00 2.28
July 31 3.38 2.88 2.94 2.56
October 31 4.13 3.13 2.63 1.63
</TABLE>
At December 31, 1999, the company had 4,237 shareholders of
record. The company has never paid a dividend and does not
expect to pay any dividends in the foreseeable future. Earnings
are reinvested in business activities.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
October 31
1999 1998 1997 1996 1995
______________________________________________________________
<S><C> <C> <C> <C> <C>
Revenues
$ 3,196,000 $ 2,813,000 $ 2,669,000 $ 2,287,000 $ 2,129,000
Net income
(loss)
$ 611,000 $ 328,000 $ 439,000 $ 260,000 $ 251,000
Per share amounts:
Basic and
Diluted
$.20 $.11 $.14 $.08 $.08
Total
assets
$11,078,000 $10,206,000 $10,546,000 $ 9,187,000 $ 8,718,000
Long-term debt
- - - - -
Stockholders'
Equity
$ 8,965,000 $ 8,449,000 $ 8,185,000 $ 7,789,000 $ 7,688,000
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
The company's working capital and cash flow represent a
significant capital resource and source of liquidity. At fiscal
year-end October 31, 1999, working capital was $4,235,000. Cash
generated by operating activities (before working capital
changes) totaled $1,515,000 in 1999 and funds generated from sale
of properties was $605,000. Cash flow was used primarily to fund
oil and gas acquisition and development expenditures totaling
$670,000, to purchase 50,000 shares of treasury stock for $95,000
and to increase working capital.
Existing working capital and anticipated cash flow are expected
to be sufficient to fund fiscal 2000 operations. However, if the
company were to make one or more major acquisitions during the
coming year, issuance of additional stock, bank borrowings or
other forms of debt financing might be considered. At fiscal
year-end, the company had no lines of credit or other bank
financing arrangements. Because earnings are anticipated to be
reinvested in operations, cash dividends are not expected to be
paid in the foreseeable future. Commitments for future capital
expenditures were not material at fiscal year- end. The timing
of most capital expenditures for exploration and development is
relatively discretionary. Therefore, the company can normally
plan expenditures to coincide with available funds. The company
has no defined benefit plans and no obligations for post
retirement employee benefits. The company experienced no
significant year 2000 related problems.
Product Prices, Production and Investments
Numerous uncertainties exist in the oil and gas industry which
could adversely affect the company and which are beyond the
company's ability to predict with reasonable accuracy.
Deregulation of natural gas pricing and transportation have
resulted in far-reaching and fundamental changes in the natural
gas industry. Gas price decontrol and the advent of an active
spot market for natural gas have resulted in gas prices received
by the company being subject to significant fluctuations. Prices
generally respond to North American supply and demand which are
often weather related. OPEC and world events (such as the Persian
Gulf War) significantly influence worldwide supply and demand and
prices for petroleum products. At December 31, 1998, inflation
adjusted oil prices stood at 50 year lows but recovered to well
over $20.00 per barrel in the second half of 1999. The fall and
recovery in oil prices during the past two years hinged primarily
on the response of major producing OPEC nations to changes in the
worldwide supply and demand for oil which were caused by, among
other things, weather, production from Iraq, economic changes in
Asia and other developing areas, and discovery of new reserves
around the world.
Although product prices are key to the company's ability to
operate profitably and to budget capital expenditures, they are
beyond the company's control and are difficult to predict. Since
1991, the company has periodically hedged product prices by
forward selling a portion of its production in the NYMEX futures
market. This is done when the price relationship (the "basis")
between the futures markets and the cash markets where the
company sells its gas is stable within historical ranges, and
when, in the company's opinion, the current price of a product is
adequate to insure reasonable returns and downside price risks
appear to be substantial. The company closes its hedges by
purchasing offsetting "long" positions in the futures market at
then prevailing prices. Accordingly, the gain or loss on the
hedge position will depend on futures prices at the time
offsetting "long" positions are purchased. Hedging gains and
losses are included in revenues from oil and gas sales. The
company's most significant hedging risk is that expected
correlations in price movements as discussed above do not occur,
and thus, that gains or losses in one market are not fully offset
to opposite moves in the other market. During 1999, 1998 and
1997, the company hedged substantial portions of its gas
production. Hedging gains totaled $118,000 in 1999. Hedging
gains and losses were immaterial in 1998 and 1997. There were no
open hedge or speculative positions at October 31, 1999.
<PAGE>
Gas and oil sales volume and price comparisons for the indicated
years ended October 31 are set forth below.
<TABLE>
<CAPTION>
1999 1998 1997
________________________________________________________________
Product Volume Price Volume Price Volume Price
________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
Gas (Mcf) 858,000 $ 2.14 781,000 $ 1.98 545,000 $ 2.21
% change +10% +8% +43% -10% -1% +39%
Oil (bbls) 39,000 $15.64 40,000 $14.10 39,000 $20.31
% change -2% +11% +3% -31% -7% +3%
</TABLE>
Pending deployment into oil and gas assets, the company invests
surplus cash with professional money managers. At
October 31, 1999, approximately 82% of such investments were with
managers who specialize in market timing using U.S. mutual funds.
These managers attempt to reduce market risk by entering and
exiting stock mutual fund trades on a frequent and short-term
basis. Remaining investments are primarily in professionally
managed limited partnerships. Most investments have a readily
determinable market value and can be converted for use by the
company within a few days. Average returns on these investments
were approximately 12% in 1999 and 1998. This investment
strategy is not expected to yield returns which are equivalent to
a "buy and hold" strategy. However, the company believes the
strategy is more conservative than a "buy and hold" strategy, and
that it will produce higher returns and provide greater liquidity
than certificates of deposit. The company believes that the most
significant risk of its investment strategy is a single day
catastrophic negative effect on the stock market of major,
unexpected news.
Oil and Gas Activities
Capital expenditures for oil and gas activities totaled $670,000
(before $605,000 of property sales proceeds) in fiscal 1999.
During the year, the company participated for an average 11%
interest in drilling, or new zone recompletions, of 33 gas wells
located in Wyoming and Oklahoma.
The company's most significant drilling activity occurred in the
active coal bed methane play in the Powder River Basin of
Wyoming. During fiscal year 1999, 30 shallow wells were drilled
on the company's 15,000 gross acre (1,875 net acre) Sheridan
Prospect. Subsequent to fiscal year end, 44 additional wells
were drilled on the prospect, bringing to 77 the total number of
wells drilled. Last year the company sold one-half of its
original 25% interest in the prospect which had a cost of
$184,000 for $541,000. Subsequent to this fiscal year end, the
company reduced its interest in the prospect to 10% by selling an
additional 2.5% to the operator for $117,000 plus assumption of
2.5% of all drilling and completion costs incurred to date.
Sales proceeds reduce oil and gas property costs.
The Sheridan Prospect is a "wildcat" prospect located in an
unproved area. Drilling targets three separate coal seams at
less than 1,000 feet. The operator is presently drilling at the
rate of approximately 20 to 25 wells per month. Completed wells
are estimated by the operator to cost approximately $30,000
($3,000 net to the company's 10% interest), and the operator is
considering drilling up to 300 wells. Estimated costs to build
gathering and pipeline systems and to produce gas are not
complete but are expected to approximate the cost of the wells.
Such costs may be incurred directly or through payments over time
to third party pipeline companies who install the pipelines and
gathering systems.
The operator of the Sheridan prospect considers drilling results
to date to be very positive with gas shows in virtually all wells
and excellent shows in certain wells. No wells are currently
hooked-up and producing, however, the operator is building
gathering and pipeline facilities into a portion of the wells in
order to commence pipeline gas sales during January 2000.
Accordingly, there is considerable uncertainty as to reserves,
production rates, operating costs, gas markets and product prices
which make the economic viability of the play uncertain at this
time. There are important environmental issues related to water
production and disposal which must be resolved in order for the
play to be economically viable. The company also has concerns
about the speed at which the operator is developing the property
in the absence of concrete production data. Nevertheless, the
company presently believes that the repeatability and the upside
economic potential of the play justifies its very significant
risks. At October 31, 1999, the costs of the project were
classified as Unevaluated Oil and Gas Properties and the company
had not recorded any proved reserves for the project.
<PAGE>
During fiscal 1999, the company also participated in drilling
development gas wells in the South Fork Field located in Woods
County, Oklahoma. The company purchased interests in 13 wells
and took advantage of good product prices to sell its interest in
13 marginal wells. The company also sold its 78% interest in the
Tracy Federal #1 well for $487,000. The well was worked over
last year and restored to production at about 300 Mcfg per day.
It was one of the company's largest producing wells in value and
reserves. Sale proceeds were recorded as a reduction to oil and
gas property costs. Proved reserves attributed to the well were
455,000 Mcfg and 6,000 barrels of condensate.
As reported last year, the company is participating in the
refinement and application of patented fluid lift technology.
The technology efficiently lifts fluids from wellbores using
down-hole pressure differentials, and is primarily applicable to
mature natural gas wells in low pressure reservoirs. Application
of the technology reduces the hydrostatic pressure exerted
against a producing formation by removing fluids which build-up
in a wellbore, and it increases formation permeability to gas by
drying-out the formation/wellbore interface. The technology is
most effective in wells which produce from depths below 10,000
feet where conventional fluid lift systems lose efficiency.
Application of the technology is in its early stages. However,
the company believes that it will provide a cost effective, low
risk and repeatable means to significantly increase its gas
production and reserves. For example, during fiscal 1999, the
company installed the technology on a well where the objective
Morrow formation was abandoned in 1994. The technology restored
Morrow formation production to approximately 600 to 650 Mcf gas
per day, and the company estimates gross recoverable reserves to
be 1.50 Bcf gas of which the company's interest is 886,000 Mcfg
gas. This well is the company's largest property in reserves and
production. The company has installed the technology on four
other wells of which three have equaled or exceeded the company's
expectations.
The company owns an indefinite term "non-exclusive" license to
use the technology as well as a one-third ownership interest in
the Licensing Entity (which holds the indefinite term "exclusive"
license to the technology). Accordingly the company has the
indefinite right to apply the technology in the normal course of
its business as well as the right to participate in any benefits
from future licensing or sale of the technology to third parties
through its ownership in the Licensing Entity.
The company has devoted a substantial portion (approximately 40%)
of both its capital budget and the time of its operations and
engineering staff to development and application of the
technology. The company anticipates equal or greater allocation
of its resources in fiscal 2000. Access to good prospects for
application of the technology is the major impediment to this
project.
In 1998, capital expenditures for oil and gas activities totaled
$1,421,000 (before $576,000 of property sales proceeds). During
the year, the company participated for an average 27% interest in
four gas wells drilled in Wyoming and Oklahoma. One gas well in
which the company owns a 31% interest was completed as a field
extension on the company's 2,800 gross acre Morrow sand prospect
in Ellis County, Oklahoma. The company owns interests ranging
from 31% to 98% in six wells located on this prospect. The
remaining three wells were drilled on the company's 15,000 gross
acre Sheridan Coal Bed Methane prospect located near Sheridan,
Wyoming which is discussed above.
During 1998, the company participated for a 20% interest in the
installation of a new waterflood in Carter County, Oklahoma, and
expanded its producing property base by purchasing interests in
12 wells located in Oklahoma. At October 31, 1998, the company
had installed its fluid lift technology (discussed above) on
three of its gas wells, and had successfully restored the 13,800
foot Tracy Federal #1 well to production.
<PAGE>
The company's reserves are concentrated in relatively few
properties. At October 31, 1999, approximately 75% of the value
of the company's estimated reserves were concentrated in 23% of
the company's producing wells. The company's most significant
producing property during 1999 (placed on production in early
1998) accounted for approximately 25% of the company's total gas
production and about 6% of the company's estimated proved gas
reserve quantities at fiscal year end. The company owns 49% of
the well and is the operator. The well is currently producing at
the rate of approximately 470 Mcfg per day with minor amounts of
oil and water. Measured surface casing pressures for the well
have declined faster than expected indicating that the reservoir
is smaller than originally anticipated. Although the pressures
have been taken into account in estimating remaining recoverable
reserves for the well, they are based on limited data.
Accordingly, reserves estimates must be viewed as being subject
to significant change as more data about the well becomes
available.
Another well on which the company recently installed its fluid
lift technology (discussed above) is located in Oklahoma and is
the company's largest producing property in reserves and value.
The company owns a 75% working interest and a 60% net revenue
interest in the well and is the operator. From the time the well
was placed on production by the company in the third quarter of
1999, it has accounted for approximately 9% of the company's
total gas production. At October 31, 1999, 13% of the company's
estimated natural gas reserve quantities were attributed to the
well. The well has a very limited operating history using the
new production technology, and accordingly, reserve estimates
must be viewed as being subject to significant change as more
data about the well becomes available.
Results of Operations
In 1999, total revenues rose 14% to $3,196,000 compared to
$2,813,000 in 1998. As the oil and gas price/volume table on
page 9 shows, total gas price realizations, which reflect hedging
transactions, rose 8% to $2.14 per Mcf and oil price realizations
rose 11% to $15.64 per barrel. The net effect of these price
changes was to increase oil and gas sales by $189,000. Hedging
gains were $118,000 in 1999 and were immaterial in 1998. Gas
volumes produced rose 10% and oil volumes produced declined 2%.
The net effect of these volume changes was to increase oil and
gas sales by $151,000. The increase in gas production resulted
from new wells added during the year. Operating income fell 8%
due to the sale of several marginal operated properties.
Investment income and other rose 33% primarily due to the
increase in the amount of short-term investments.
In 1998, total revenues increased 5% to $2,813,000 compared to
$2,669,000 in 1997. As the oil and gas price/volume table on
page 9 shows, total gas price realizations, which reflect hedging
transactions, fell 10% to $1.98 per Mcf and oil price
realizations fell 31% to $14.10 per barrel. The net effect of
these price changes was to reduce oil and gas sales by $365,000.
Hedging gains and losses were immaterial in both years. Gas
volumes produced rose 43% and oil volumes produced rose 3%. The
net effect of these volume changes was to increase oil and gas
sales by $479,000. The increase in production resulted from new
wells added during the year and at the end of last year.
Operating income rose 2% as a result of operated wells added
through drilling and acquisitions. Investment income and other
income rose 11% due to improved performance on certain of the
company's short-term investments.
In 1999, total costs and expenses declined marginally to
$2,298,000 compared to $2,307,000 in 1998. Depreciation,
depletion and amortization ("DD&A") fell 9% compared to 1998 due
primarily to proceeds from sale of certain properties that
reduced the amortization base. Oil and gas production expenses
fell 4% primarily due to significant expenditures to recover
production of the Tracy Federal #1 well, and certain other
expenditures incurred in 1998 that were not repeated in 1999.
General and administrative expenses rose 13% primarily as a
result of a broad upward trend in the costs of administration.
The effective tax rate was 32% in 1999 compared to 35% in 1998.
<PAGE>
In 1998, total costs and expenses rose 16% to $2,307,000 compared
to $1,993,000 in 1997. DD&A increased 26% compared to 1997
primarily due to a 43% increase in gas production quantities.
Oil and gas production expenses rose 11% due to increased costs
associated with new wells drilled and producing property
interests purchased during fiscal 1998 and at the end of last
year, and due to significant expenditures to recover production
of the Tracy Federal #1 well. General and administrative
expenses rose 11% primarily as a result of a broad upward trend
in the costs of administration. The effective tax rate was
approximately 35% in both years.
ITEM 8. FINANCIAL STATEMENTS
Index to Consolidated Financial Statements
Consolidated Balance Sheets, October 31, 1999 and 1998
Consolidated Statements of Operations for the Three Years Ended
October 31, 1999
Consolidated Statements of Stockholders' Equity for
the Three Years Ended October 31, 1999
Consolidated Statements of Cash Flows for the Three Years
Ended October 31, 1999
Notes to Consolidated Financial Statements
Independent Auditors' Report
<PAGE>
CONSOLIDATED BALANCE SHEETS
October 31, 1999 and 1998
<TABLE>
<CAPTION>
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
________________________________________________________________
Assets 1999 1998
________________________________________________________________
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 184,000 $ 349,000
Short-term investments 4,055,000 2,186,000
Receivables:
Trade 443,000 272,000
Accrued oil and gas sales 362,000 272,000
Other 77,000 541,000
________________________________________________________________
Total current assets 5,121,000 3,620,000
________________________________________________________________
Oil and gas properties, net, at cost,
using full cost method:
Unevaluated 788,000 616,000
Evaluated 5,126,000 5,885,000
________________________________________________________________
Net oil and gas properties 5,914,000 6,501,000
________________________________________________________________
Other, net 43,000 85,000
________________________________________________________________
$11,078,000 $10,206,000
================================================================
Liabilities and Stockholders' Equity
________________________________________________________________
Current liabilities:
Accounts payable $ 739,000 $ 662,000
Income taxes payable 147,000 51,000
________________________________________________________________
Total current liabilities 886,000 713,000
________________________________________________________________
Deferred income taxes, net 1,227,000 1,044,000
________________________________________________________________
Commitments
________________________________________________________________
Stockholders' equity:
Preferred stock, without par value, 5,000,000
shares authorized, none issued - -
Common stock, $.10 par value,
20,000,000 shares authorized,
3,678,000 shares issued 367,000 367,000
Capital in excess of par value 6,235,000 6,235,000
Retained earnings 3,578,000 2,967,000
Treasury stock, 699,000
and 648,000 shares at cost (1,215,000) (1,120,000)
________________________________________________________________
Total shareholders' equity 8,965,000 8,449,000
________________________________________________________________
$11,078,000 $10,206,000
================================================================
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended October 31, 1999
<TABLE>
<CAPTION>
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
________________________________________________________________
1999 1998 1997
_________________________________________________________________
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 2,445,000 $ 2,105,000 $ 1,992,000
Operating 428,000 465,000 458,000
Investment income and other 323,000 243,000 219,000
_________________________________________________________________
3,196,000 2,813,000 2,669,000
_________________________________________________________________
Costs and expenses:
Oil and gas production 818,000 851,000 767,000
Depreciation, depletion and
Amortization 706,000 774,000 614,000
General and administrative 774,000 682,000 612,000
_________________________________________________________________
2,298,000 2,307,000 1,993,000
_________________________________________________________________
Income before income taxes 898,000 506,000 676,000
_________________________________________________________________
Income taxes (287,000) (178,000) (237,000)
_________________________________________________________________
Net income $ 611,000 $ 328,000 $ 439,000
=================================================================
Basic and diluted
income per share $ .20 $ .11 $ .14
=================================================================
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended October 31, 1999
<TABLE>
<CAPTION>
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
________________________________________________________________________
Common Stock Capital In Total
_________________ Excess Of Retained Treasury Stockholders'
Shares Amount Par Value Earnings Stock Equity
___________ ____________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
Balances,
October 31, 1996
3,666,000 $366,000 $6,236,000 $2,200,000 $(1,013,000) $7,789,000
Purchase of
treasury
stock
- - - - (43,000) (43,000)
Net income
- - - 439,000 - 439,000
__________________________________________________________________________
Balances,
October 31, 1997
3,666,000 366,000 6,236,000 2,639,000 (1,056,000) 8,185,000
Shares issued
33,000 3,000 62,000 - - 65,000
Shares
received
and canceled
(21,000) (2,000) (63,000) - - (65,000)
Purchase of
treasury
stock - - - - (64,000) (64,000)
Net income
- - - 328,000 - 328,000
__________________________________________________________________________
Balances,
October 31, 1998
3,678,000 367,000 6,235,000 2,967,000 (1,120,000) 8,449,000
Purchase of
treasury
stock - - - - (95,000) (95,000)
Net income
- - - 611,000 - 611,000
__________________________________________________________________________
Balances,
October 31, 1999
3,678,000 $367,000 $6,235,000 $3,578,000 $(1,215,000) $8,965,000
=========================================================================
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended October 31, 1999
<TABLE>
<CAPTION>
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
________________________________________________________________
1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Cash flows from operating
activities:
Net income $ 611,000 $ 328,000 $ 439,000
Non-cash expenses included in
net income:
Depreciation, depletion and
Amortization 706,000 774,000 614,000
Deferred income taxes 183,000 141,000 222,000
Other 15,000 16,000 13,000
Changes in operating assets
and liabilities:
Proceeds from
short-term investments 2,241,000 2,859,000 2,138,000
Purchase of
short-term investments (4,110,000) (2,347,000) (2,307,000)
Trade receivables (171,000) 46,000 (175,000)
Accrued oil and gas sales (90,000) 52,000 (89,000)
Other current assets 464,000 (483,000) (22,000)
Accounts payable 77,000 (780,000) 731,000
Income taxes payable 96,000 35,000 10,000
_________________________________________________________________
Net cash provided
by operating activities 22,000 641,000 1,574,000
_________________________________________________________________
Cash flows from investing activities:
Additions to oil
and gas properties (670,000) (1,421,000) (1,350,000)
Proceeds from sale of oil
and gas properties 605,000 576,000 114,000
Other (27,000) (18,000) (4,000)
________________________________________________________________
Net cash used in
investing activities (92,000) (863,000) (1,240,000)
________________________________________________________________
Cash flows from financing activities:
Purchase of
treasury stock (95,000) (64,000) (43,000)
________________________________________________________________
Net cash provided by (used in)
financing activities (95,000) (64,000) (43,000)
________________________________________________________________
Increase (decrease) in cash
and cash equivalents (165,000) (286,000) 291,000
Cash and cash equivalents:
Beginning of year 349,000 635,000 344,000
________________________________________________________________
End of year $ 184,000 $ 349,000 $ 635,000
=================================================================
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
October 31, 1999
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
________________________________________________________________
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Basis of Presentation
The consolidated financial statements include the accounts of
CREDO Petroleum Corporation and its wholly owned subsidiaries
(the "company"). The company engages in oil and gas acquisition,
exploration, development and production activities in the United
States. Certain operations are conducted through three private
limited partnerships (the "Partnerships") which, as general
partner, the company manages and controls. The company's general
and limited partner interests in the Partnerships are combined on
the proportionate share basis in accordance with accepted
industry practice. All significant intercompany transactions
have been eliminated. Certain reclassifications have been made
to prior year amounts with no effect on net income. All
references to years in these Notes refer to the company's fiscal
October 31 year.
Cash, Cash Equivalents, and Short-Term Investments
Cash equivalents consist of highly liquid investments with
original maturities of three months or less. At
October 31, 1999, short-term investments are 82% allocated to
professional money managers who specialize in market timing using
U.S. mutual fund groups. These managers generally enter and exit
stock fund trades on a frequent and short-term basis and use
mutual fund money market accounts when not invested in stock
funds. Other short-term investments consist primarily of
professionally managed limited partnerships which provide readily
determinable market values and highly liquid limited partner
interests. The partnerships are invested primarily in energy
financial instruments. Unrealized gains on limited partnerships
total $63,000 and $23,000 at October 1, 1999 and 1998,
respectively. Short-term investments are classified a "trading"
and are stated at fair value with realized and unrealized gains
and losses immediately recognized.
Oil and Gas Properties
The company follows the full cost method of accounting for its
oil and gas operations. Under this method all costs incurred in
the acquisition, exploration, and development of oil and gas
properties are capitalized in one cost center, including certain
internal costs directly associated with such activities which
totaled approximately $100,000 in 1999, 1998 and 1997. Proceeds
from sales of oil and gas properties are credited to the cost
center with no gain or loss recognized unless such adjustments
would significantly alter the relationship between capitalized
costs and proved oil and gas reserves. Estimated dismantlement,
restoration, and abandonment costs are approximately offset by
estimated residual values of lease and well equipment.
Accordingly, no accrual for such costs has been recorded.
If capitalized costs, less related accumulated amortization and
deferred income taxes, exceed the "full cost ceiling", the excess
is expensed in the period such excess occurs. The full cost
ceiling includes an estimated discounted value of future net
revenues attributable to proved reserves using current product
prices and operating costs, and an estimate of the value of
unproved properties which are included in the cost center. Cost
of oil and gas properties are amortized using the units of
production method. The company's composite depreciation,
depletion and amortization ("DD&A") rate per equivalent barrel
produced was $3.57 in 1999, $4.09 in 1998 and $4.07 in 1997.
Unevaluated properties consist primarily of lease acquisition and
maintenance costs. Evaluation normally takes three to five
years. Of the unevaluated property costs, $104,000 and $316,000
were incurred in 1999 and 1998, respectively. During fiscal
1998, a 50% interest in certain unevaluated properties with a
cost of $184,000 was sold for $541,000. The proceeds reduced the
net carrying value of properties and had no impact on operating
results.
<PAGE>
Natural Gas and Crude Oil Price Hedging
The company periodically hedges the price of its oil and gas
production when the potential for significant downward price
movement is anticipated. Hedging transactions take the form of
forward, or "short", selling in the NYMEX futures market, and are
closed by purchasing offsetting "long" positions. Such hedges do
not exceed anticipated production volumes, are expected to have
reasonable correlation between price movements in the futures
market and the cash markets where the company's production is
located, and are authorized by the company's Board of Directors.
Hedges are expected to be closed as related production occurs but
may be closed earlier if the anticipated downward price movement
occurs or if the company believes that the potential for such
movement has abated. All other futures transactions are
accounted for as speculative transactions and gains and losses
are immediately recognized in other income.
Hedging gains and losses are recognized as adjustments to oil and
gas sales as the hedged product is produced. Hedging gains were
$118,000 in 1999 and were immaterial in prior years, and gains
and losses on speculative transactions were immaterial in all
years. There were no open hedge or speculative positions at
October 31, 1999.
Accounting Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Significant estimates with regard to these financial statements
include the estimate of proved oil and gas reserve quantities and
the related present value of estimated future net cash flows
therefrom.
Per Share Amounts
Basic income per share is computed using the weighted average
number of shares outstanding. Diluted earnings per share
reflects the potential dilution that would occur if stock options
were exercised using the average market price for the company's
stock for the period. The assumed exercise of stock options
would increase the weighted average shares outstanding from
2,985,000 to 3,085,000 in 1999 and from 3,042,000 to 3,137,000
shares in 1998. The assumed conversion had no dilutive effect
compared to basic earnings per share in any of the years.
Impact of New Accounting Pronouncement
The FASB has issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This statement is effective for all quarters of
fiscal years beginning after June 15, 2000, and will be adopted
by the company effective November 1, 2000. This Standard requires
companies to report the fair-market value of derivatives on the
balance sheet and record in income or other comprehensive income,
as appropriate, any changes in the fair value of the derivative.
The Standard is not expected to have a material impact on the
company.
<PAGE>
(2) COMMON STOCK AND PREFERRED STOCK
During 1999 and 1998, the company acquired 50,000 and 24,000
shares of its common stock at a total cost of $95,000 and
$64,000, respectively. These transactions have been recorded as
treasury stock.
The company has authorized 5,000,000 shares of preferred stock
which may be issued in series and with preferences as determined
by the company's Board of Directors. Approximately 100,000
shares of the company's authorized but unissued preferred stock
have been reserved for issuance pursuant to the provisions of the
company's Shareholders' Rights Plan.
The company's 1997 Stock Option Plan (the "Plan") authorizes the
granting of incentive and nonqualified options to purchase shares
of the company's common stock. The maximum number of shares
which can be issued cannot exceed 15% of outstanding shares. The
Plan is administered by the Board of Directors which determines
the terms pursuant to which any option is granted. The Board
generally expects that option exercise prices will not be less
than the fair market value of the company's stock on the grant
date, and that vesting will cover two to four years. The Plan
provides that upon a change in control of the company, options
then outstanding will immediately vest and the company will take
such actions as are necessary to make all shares subject to
options immediately salable and transferable. Plan activity is
set forth below.
<TABLE>
<CAPTION>
Years Ended
October 31 1999 1998 1997
________________________________________________________________
Weighted Weighted Weighted
Number Average Number Average Number Average
of Exercise of Exercise of Exercise
Options Price Options Price Options Price
_________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
Outstanding at 371,667 $ 1.94 415,000 $ 1.94 50,000 $ 1.88
Beginning
of year
Granted 20,000 3.19 20,000 1.63 415,00 1.94
Exercised - (33,333) 1.94 -
Cancelled or
Forfeited (30,000) 1.94 (30,000) 1.94 (50,000) 1.88
_________________________________________________________________
Outstanding
at end of year 361,667 $ 2.10 371,667 $ 1.94 415,000 $ 1.94
=================================================================
Exercisable at
end of year 259,163 $ 1.93 147,083 $ 1.94 73,333 $ 1.94
=================================================================
Weighted average
Remaining
contractual life 2.9 years 3.8 years 4.8 years
================================================================
</TABLE>
Under current accounting rules the company has elected to follow
APB 25 for recognizing the costs associated with employee stock
options, and is only subject to the disclosure items of FASB 123.
Had compensation cost been recorded under FASB 123, net income
and per share amounts for 1999 would have been $534,000, or $.18
per share basic and $.17 per share diluted, for 1998 would have
been $254,000, or $.08 per share and for 1997 would have been
$420,000 or $.14 per share. For the purpose of this disclosure,
the fair value of each option granted was $1.84 in 1999, $.72 in
1998 and $.87 in 1997. The fair value was estimated on the date
of grant using the Black-Scholes option-pricing model with an
expected volatility of 61% in 1999, and 40.0% in 1998 and 1997, a
risk-free interest rate of 6%, no expected dividends, and an
expected term of 5 years.
(3) COMMITMENTS
The company leases office facilities under a five year lease
agreement effective January 1, 1996. The lease agreement
requires payments of $46,000 in 2000 and 2001. Total rental
expense in fiscal 1999 was $44,000 and approximately $42,000 in
1998 and 1997. The company has no capital leases and no other
operating lease commitments.
<PAGE>
(4) INCOME TAXES
The company follows the asset and liability method of accounting
for deferred income taxes. Deferred tax assets and liabilities
are determined based on the temporary differences between the
financial statement and tax basis of assets and liabilities.
The income tax expense recorded in the Consolidated Statements of
Operations consists of the following:
<TABLE>
<CAPTION>
Years Ended October 31 1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Current $ 104,000 $ 36,000 $ 15,000
Deferred 183,000 141,000 222,000
________________________________________________________________
$ 287,000 $ 177,000 $237,000
================================================================
</TABLE>
The effective income tax rate differs from the U.S. Federal
statutory income tax rate due to the following:
<TABLE>
<CAPTION>
Years Ended October 31 1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Federal statutory income tax rate 34% 34% 34%
Effect of graduated tax rates 2 2 7
State income taxes 2 2 2
Percentage depletion (6) (6) (8)
Other, net - 3 -
________________________________________________________________
32% 35% 35%
================================================================
</TABLE>
The principal sources of temporary differences resulting in
deferred tax assets and tax liabilities at October 31, 1999 and
1998 are as follows:
<TABLE>
<CAPTION>
October 31 1999 1998
________________________________________________________________
<S> <C> <C>
Deferred tax assets:
Percentage depletion carryforwards $ 3,000 $ 198,000
Alternative minimum tax carryforwards - 40,000
Gain on property sales 245,000 153,000
________________________________________________________________
Total deferred tax assets 248,000 391,000
________________________________________________________________
Deferred tax liabilities:
Intangible drilling, leasehold and
other exploration costs capitalized
for financial reporting purposes but
deducted for tax purposes (1,371,000) (1,343,000)
State taxes and other (104,000) (92,000)
________________________________________________________________
Total gross deferred tax liabilities (1,475,000) (1,435,000)
________________________________________________________________
Net deferred tax liability $(1,227,000) $(1,044,000)
================================================================
</TABLE>
At October 31, 1999, the company has statutory depletion
carryforwards of $10,000.
<PAGE>
(5) SUBSEQUENT EVENT (UNAUDITED)
After fiscal year-end 1999, the company settled a lawsuit in
which it was a co-plaintiff. The settlement is subject to
execution of a final agreement which provides, among other
things, that the settlement terms are confidential. The final
dollar amount of the settlement remains subject to certain
calculations and is subject to confidentiality but is expected to
range between $300,000 and $400,000 net of attorney fees and
costs.
(6) SUPPLEMENTARY OIL AND GAS INFORMATION
<TABLE>
<CAPTION>
Capitalized Costs
October 31 1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Unproved properties not being
amortized $ 788,000 $ 616,000 $ 867,000
Properties being amortized 12,884,000 12,991,000 11,895,000
Accumulated depreciation,
depletion and amortization (7,758,000) (7,106,000) (6,418,000)
________________________________________________________________
Total capitalized costs $ 5,914,000 $ 6,501,000 $ 6,344,000
================================================================
</TABLE>
Acquisition, Exploration and Development Costs Incurred
<TABLE>
<CAPTION>
Years Ended October 31 1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Property acquisition costs:
Proved $ 11,000 $ 14,000 $ 145,000
Unproved 104,000 316,000 114,000
Exploration costs 227,000 390,000 860,000
Development costs 328,000 701,000 231,000
Sales proceeds (605,000) (576,000) (114,000)
________________________________________________________________
Net costs incurred $ 65,000 $ 845,000 $1,236,000
================================================================
</TABLE>
Major Customers and Operating Region
The company operates exclusively within the United States.
Except for cash investments, all of the company's assets are
employed in, and all its revenues are derived from, the oil and
gas industry. The company had sales in excess of 10% of total
revenues to oil and gas purchasers as follows: Total Petroleum,
Inc. 18% in 1999 and 1998; GPM Gas Corporation 17% in 1999 and
14% in 1998; and Duke Energy 25% in 1999 and 20% in 1998.
Oil and Gas Reserve Data (Unaudited)
In 1999, 1998 and 1997, independent petroleum engineers estimated
proved reserves for the company's significant properties which
represented approximately 60% in each year of total estimated
future net revenues. The remaining reserves were estimated by
the company. Reserve definitions and pricing requirements
prescribed by the Securities and Exchange Commission were used.
The determination of oil and gas reserve quantities involves
numerous estimates which are highly complex and interpretive.
The estimates are subject to continuing re-evaluation and reserve
quantities may change as additional information becomes
available. Estimated values of proved reserves were computed by
applying prices in effect at October 31 of the indicated year.
The average price used was $21.01, $12.59, and $19.97 per barrel
for oil and $2.73, $2.03, and $2.69 per Mcf for gas in 1999,
1998, and 1997, respectively. Estimated future costs were
calculated assuming continuation of costs and economic conditions
at the reporting date.
<PAGE>
Total estimated proved reserves and the changes therein are set
forth below for the indicated fiscal year.
<TABLE>
<CAPTION>
1999 1998 1997
________________________________________________________________________
Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls)
________________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Balance, November
6,676,000 314,000 5,868,000 368,000 5,816,000 364,000
Revisions of
previous estimates
388,000 52,000 346,000 (25,000) (109,000) 11,000
Extensions and
Discoveries
977,000 1,000 1,000,000 7,000 462,000 32,000
Purchases of
reserves in place
6,000 - 243,000 4,000 248,000 4,000
Sales of reserves
in place
(506,000) (7,000) - - (4,000) (4,000)
Production
(858,000) (39,000) (781,000) (40,000) (545,000) (39,000)
________________________________________________________________________
Balance, October
6,683,000 321,000 6,676,000 314,000 5,868,000 368,000
========================================================================
Proved developed reserves:
Beginning
of period
5,909,000 302,000 4,874,000 335,000 5,048,000 334,000
========================================================================
End of period
5,704,000 287,000 5,909,000 302,000 4,874,000 335,000
========================================================================
</TABLE>
The standardized measure of discounted future net cash flows
from reserves is set forth below as of October 31 of the
indicated fiscal year.
<TABLE>
<CAPTION>
1999 1998 1997
_______________________________________________________________
<S> <C> <C> <C>
Future cash inflows $24,960,000 $17,647,000 $23,112,000
Future production and
development costs (8,707,000) (6,261,000) (8,899,000)
Future income tax expense (3,186,000) (1,790,000) (1,848,000)
_______________________________________________________________
Future net cash flows 13,067,000 9,596,000 12,365,000
10% discount factor (5,143,000) (3,346,000) (4,953,000)
_______________________________________________________________
Standardized measure of
discounted future
net cash flows $ 7,924,000 $ 6,250,000 $ 7,412,000
===============================================================
</TABLE>
The principal sources of change in the standardized measure of
discounted future cash flows from reserves are set forth below
for the indicated fiscal year.
<TABLE>
<CAPTION>
1999 1998 1997
________________________________________________________________
<S> <C> <C> <C>
Balance, November 1 $ 6,250,000 $ 7,412,000 $ 7,601,000
Sales of oil and gas produced,
net of production costs (1,509,00) (1,253,000) (1,225,000)
Net changes in prices, production
and development costs 2,126,000 (2,609,000) (328,000)
Extensions and discoveries, net of
future development and production
costs 1,272,000 1,373,000 389,000
Revisions of quantity
estimates and other 1,198,000 252,000 (44,000)
Purchases of reserves
in place 10,000 296,000 269,000
Sales of reserves in place (1,201,000) - (37,000)
Accretion of discount 625,000 741,000 760,000
Net change in income taxes (847,000) 38,000 27,000
________________________________________________________________
Balance, October 31 $ 7,924,000 $ 6,250,000 $ 7,412,000
================================================================
</TABLE>
<PAGE>
<Audit-Report>
INDEPENDENT AUDITORS' REPORT
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
The Board of Directors and Stockholders
CREDO Petroleum Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of
CREDO Petroleum Corporation and subsidiaries as of
October 31, 1999 and 1998, and the related consolidated
statements of operations, stockholders' equity, and cash flows
for each of the years in the three year period ended
October 31, 1999. These consolidated financial statements are
the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of CREDO Petroleum Corporation and subsidiaries as of
October 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the years in the three year
period ended October 31, 1999, in conformity with generally
accepted accounting principles.
HEIN + ASSOCIATES LLP
Denver, Colorado
January 11, 2000
</Audit-Report>
<PAGE>
PART III.
ITEM 9. EXECUTIVE COMPENSATION
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's fiscal year 1999.
ITEM 10. MANAGEMENT REMUNERATION AND TRANSACTIONS
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's fiscal year 1999.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's fiscal year 1999.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference to the company's Proxy Statement to be
filed with the Commission pursuant to Regulation 14A within 120
days of the end of the company's fiscal year 1999.
PART IV.
ITEM 13. FINANCIAL STATEMENTS AND SCHEDULES, EXHIBITS AND
REPORTS ON FORM 8-K
(a) The Index to Financial Statements is set forth under
Item 8.
(c) Exhibits
3(a)(i) Articles of Incorporation of CREDO Petroleum
& 4(a) Corporation (incorporated by reference to Form 10-K
dated October 31, 1982).
3(a)(ii) Articles of Amendment of Articles of Incorporation,
dated March 9, 1982 (incorporated by reference to
Form 10-K dated October 31, 1982).
3(a)(iii) Articles of Amendment of Articles of Incorporation,
dated October 28, 1982 (incorporated by reference to
Form 10-K dated October 31, 1982).
3(a)(iv) Articles of Amendment of Articles of Incorporation
dated April 18, 1984 (incorporated by reference to
Form 10-K dated October 31, 1984).
3(a)(v) Articles of Amendment of Articles of Incorporation
dated April 18, 1984 (incorporated by reference to
Form 10-K dated October 31, 1984).
3(a)(vi) Articles of Amendment of Articles of Incorporation
dated April 2, 1985 (incorporated by reference to Form
10-K dated October 31, 1985).
3(a)(vii) Articles of Amendment of Articles of Incorporation
dated March 25, 1986 (incorporated by reference to
Form 10-K dated October 31, 1986).
3(a)(viii) Articles of Amendment of Articles of Incorporation
dated March 24, 1988 (incorporated by reference to
Form 10-K dated October 31, 1989).
3(a)(ix) Articles of Amendment to Articles of Incorporation
dated May 11, 1990.
(b)(i) By-Laws of CREDO Petroleum Corporation, as amended
May 27, 1981 (incorporated by reference to Form 10-K
dated October 31, 1981).
3(b)(ii) By-Laws of CREDO Petroleum Corporation, as amended
May 27, 1981 and January 30, 1985 (incorporated by
reference to Form 10-K dated October 31, 1985).
3(b)(iii) By-Laws of CREDO Petroleum Corporation, as amended
October 30, 1986 (incorporated by reference to
Form 10-K dated October 31, 1986).
3(b)(iv) Amendment to Article X of CREDO Petroleum
Corporation's By-Laws dated March 24, 1988
(incorporated by reference to the company's
definitive proxy dated February 5, 1988).
4(i) Shareholders' Rights Plan, dated April 11, 1989.
4(ii) Amendment to Shareholders' Rights Plan, dated
February 24, 1999 (incorporated into Part II of the
company's Form 10-QSB dated January 31, 1999).
10(a) CREDO Petroleum Corporation Non-qualified Stock Option
Plan, dated January 13, 1981 (incorporated by
reference to Amendment No. 1 to Form S-1 dated
February 2, 1981).
10(b) CREDO Petroleum Corporation Incentive Stock Option
Plan, dated October 2, 1981 (incorporated by
reference to the company's definitive proxy
statement, dated January 22, 1982).
10(b) CREDO Petroleum Corporation 1997 Incentive Stock
Option Plan (incorporated by reference to Form 10-K
dated October 31, 1998).
10(c) Model of Director and Officer Indemnification
Agreement provided for by Article X of CREDO
Petroleum Corporation's By-Laws (incorporated by
reference to Form 10-K dated October 31, 1987).
22 CREDO Petroleum Corporation (a Colorado corporation)
and its subsidiaries SECO Energy Corporation (a
Nevada corporation) and United Oil Corporation (an
Oklahoma corporation) are located at 1801 Broadway,
Suite 900, Denver, CO 80202-3837.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
CREDO PETROLEUM CORPORATION
By:/s/ James T. Huffman
___________________________
James T. Huffman,
Chief Executive Officer
By:/s/ Alford B. Neely
___________________________
Alford B. Neely
Vice President and
Chief Financial Officer
Date: January 3, 2000
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the date
indicated.
Date Signature Title
_______________ _________________________ _________
January 3, 2000 /s/ William N. Beach Director
_________________________
William N. Beach
January 3, 2000 /s/ Otto P. Butterly Director
_________________________
Otto P. Butterly
January 3, 2000 /s/ William D. Howell Director
_________________________
William D. Howell
January 3, 2000 /s/ James T. Huffman Chairman of
_________________________ the Board,
James T. Huffman President,
Treasurer
January 3, 2000 /s/ William F. Skewes Director,
_________________________ Corporate
William F. Skewes Secretary,
General Counsel
January 3, 2000 /s/ Richard B. Stevens Director
_________________________
Richard B. Stevens
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
THE CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED STATEMENTS OF
OPERATIONS FOUND IN THE COMPANY'S 10-KSB FOR THE FISCAL YEAR ENDED
OCTOBER, 31, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS AND ACCOMPANYING FOOTNOTES.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> OCT-31-1999
<PERIOD-START> NOV-01-1998
<PERIOD-END> OCT-31-1999
<CASH> 184,000
<SECURITIES> 4,055,000
<RECEIVABLES> 882,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 5,121,000
<PP&E> 13,672,000
<DEPRECIATION> (7,758,000)
<TOTAL-ASSETS> 11,078,000
<CURRENT-LIABILITIES> 886,000
<BONDS> 0
0
0
<COMMON> 367,000
<OTHER-SE> 8,598,000
<TOTAL-LIABILITY-AND-EQUITY> 11,078,000
<SALES> 2,445,000
<TOTAL-REVENUES> 3,196,000
<CGS> 818,000
<TOTAL-COSTS> 1,524,000
<OTHER-EXPENSES> 774,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 898,000
<INCOME-TAX> 287,000
<INCOME-CONTINUING> 611,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 611,000
<EPS-BASIC> 0.20
<EPS-DILUTED> 0.20
</TABLE>
