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Form 10KSB for CREDO PETROLEUM CORP filed on Jan 29 2001
Colorado 84-0772991
(State of incorporation) (I.R.S. employer identification
number)
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-B 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-KSB or any amendment to
this Form 10-KSB. 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
Issuer's revenues for its most recent fiscal year: $4,204,000
As of December 31, 2000, the aggregate market value of common stock held by non-affiliates of the registrant was approximately $11,637,000.
DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof - Proxy Statement to be filed with the Commission in connection with the company's 2001 Annual Meeting.
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 nine states and has nine employees. CREDO is an active operator in Kansas and the Rocky Mountain Region. 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.
Business Activities
The company's primary business activities consist of (i) oil and gas
production, (ii) application of recently developed fluid lift technology to low
pressure gas reservoirs ("Calliope System"),
(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.
Except for development, testing and application of the Calliope System, 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 the company's operation is raised through various cost sharing arrangements. Applications of the Calliope System are concentrated below 10,000 feet and, to date, have not required external sources of capital.
The company acts as "operator" of 80 wells pursuant to standard industry Operating Agreements, and it owns working and royalty interests in approximately 466 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.
Over the past three years, the company has participated in developing, testing, refining, and patenting the Calliope System. 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. During 2000, the company purchased an unrestricted, exclusive license to the technology. The term of the license is 10 years, and it can be extended an additional five years to cover the entire 15 year term of the patent. At fiscal year end, the company had installed the technology on eight wells ranging in depth from 6,500 feet to 18,600 feet. Of the eight applications, three rank as the company's first, fifth, and sixth most valuable producing properties. Although the technology operated successfully on all of the applications, two of the applications were not economic due to wellbore problems (scaling and a casing leak) unrelated to the technology. The technology is being tested and refined with the objective of expanding its range of application and standardizing its application.
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, market prices, and regulation, and actions of major foreign producers. The most recent oil price fall to below $10.00 per barrel and recovery to over $30.00 demonstrates the extreme volatility in oil prices.
Oil production is sold to crude oil purchasing companies at competitive spot field prices. Crude oil and condensate production are readily marketable. Crude oil prices are subject to world-wide supply and demand, and are primarily dependent upon available 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.
Deregulation of natural gas pricing and transportation has resulted in far-reaching and fundamental changes in the producing, transportation and marketing segments of the natural gas industry. Gas price decontrol, the advent of an active spot market for natural gas, changes in demand for natural gas, and weather patterns cause prices received by the company to be subject to significant fluctuations. The company presently sells most of its gas through short-term contracts with terms of one year or less based on monthly "spot" prices. These prices are reduced ("netted") by the costs of gathering and transporting the gas.
During fiscal 2000, gas prices rose to historic highs as accelerating demand outpaced the industry's ability to readily respond with additional supplies of natural gas. The industry's diminished size and capacity after 12 to 15 years of relative depression caused by low energy prices hampers its ability to respond to surging demand. For example, in the early 1980s the industry had approximately 4,000 drilling rigs compared to approximately 1,100 active rigs today. Management cannot reasonably predict the extent or timing of natural gas price fluctuations.
As discussed elsewhere in this Form 10-KSB, 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 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 highly competitive. As a small independent oil and gas company, the company must compete against companies with substantially larger financial and other resources in all aspects of its business.
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 2001. The company cannot predict what subsequent legislation or regulations may be enacted or what effect it will have on the company's business.
ITEM 2. PROPERTIES
General
In 2000, capital expenditures for oil and gas activities totaled $1,855,000 (before property sales proceeds of $552,000). The company participated in drilling 31 gas wells and one oil well in Oklahoma and Wyoming (including 22 coal bed methane wells on its Recluse Prospect located on the east side of the Powder River Basin in Wyoming). The company also purchased interests in several properties and disposed of several non-strategic property interests. The company sold its remaining interest in the Sheridan coal bed methane property located on the west side of the Powder River Basin for $500,000 plus reimbursement and assumption by the buyer of approximately $850,000 of costs incurred by the company from inception of the project. A primary activity during 2000 centered on acquiring control of the Calliope System, and on continuing to test and refine the technology.
In 1999, capital expenditures for oil and gas activities totaled $670,000 (before property sales proceeds of $605,000). The company participated in drilling 33 gas wells in Oklahoma and Wyoming (including 30 coal bed methane wells on its Sheridan Prospect located on the western side of the Powder River Basin in Wyoming), and purchased and sold several producing property interests. During the fourth quarter of 1999, the company sold its 78.25% working interest in the Tracy Federal #1 well for $487,000. In addition, the company actively pursued the application and refinement of the Calliope System.
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, 2000, approximately 61% of the value of the company's estimated reserves were concentrated in 14% of the company's producing wells. The company's most significant producing property during 2000, the J.C. Carroll well, accounted for approximately 16% of total gas production and about 10% of the company's estimated proved gas reserve quantities at fiscal year end. The company owns 75% of the well and is the operator. The well is currently producing at the rate of approximately 610 Mcfg per day with minor amounts of oil and water. The company installed its Calliope System on this well in mid-1999 and within one month the technology restored a Morrow formation zone in the well, which was abandoned in 1994, to daily production of 620 to 675 Mcfg. The well has exceeded initial performance projections, and during 2000 the company increased its estimates of total reserves which will ultimately be recovered using the new fluid lift technology to 1.7 billion cubic feet of gas equivalent (Bcfge). The well has a limited operating history using the Calliope System, and accordingly, reserve estimates must be viewed as being subject to significant change as more data about the well becomes available.
Estimated Proved Oil and Gas Reserves and Future Net Revenues
McCartney Engineering, Inc., an independent petroleum engineering firm, estimated proved reserves for the company's significant properties which represented 63% in 2000, 64% in 1999 and 62% in 1998 of the total estimated future value of estimated reserves. Remaining reserves were estimated by the company in all years. At October 31, 2000, natural gas represented 77% and crude oil represented 23% 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 $31.82, $21.01, and $12.59 per barrel for oil and $4.33, $2.73, and $2.03 per Mcf for gas as of October 31, 2000, 1999, and 1998, respectively. Amounts do not include estimates of future Federal and state income taxes.
Estimated Future
Oil Gas Estimated Future Net Revenues
Year (bbls)* (Mcf)* Net Revenues Discounted at 10%
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2000 373,000 7,413,000 $ 31,475,000 $ 18,700,000
1999 321,000 6,683,000 $ 16,254,000 $ 9,856,000
1998 314,000 6,676,000 $ 11,385,000 $ 7,415,000
* Of 2000, 1999 and 1998 amounts, proved developed reserves were
340,000, 287,000, and 302,000 barrels of oil and 6,511,000,
5,704,000, and 5,909,000 Mcf of gas, respectively.
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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.
2000 1999 1998 ------------------------------------------------------------------- Product Volume Price Volume Price Volume Price ------------------------------------------------------------------- Gas (Mcf) 668,000 $ 2.84 858,000 $ 2.14 781,000 $ 1.98 Oil (bbls) 39,000 $27.88 39,000 $15.64 40,000 $14.10 |
Average production costs, including production taxes, per unit of production (using a six to one conversion ratio of Mcfs to barrels) were $6.21, $4.49, and $5.00 per barrel in 2000, 1999, and 1998, respectively. The increase in 2000 is primarily due to higher production taxes on significantly increased revenues resulting from higher product prices.
Productive Wells and Developed Acreage
Developed acreage at October 31, 2000 totaled 18,800 net and 101,300 gross acres. At October 31, 2000, the company owned working interests in 51.37 net (170 gross) wells consisting of 19.42 net (44 gross) oil wells and 31.96 net (126 gross) gas wells. In addition, the company owned royalty and production payment interests in approximately 376 oil and gas wells. In 2000, the company sold 3.88 net (39 gross) wells. In the same period, the company drilled and acquired interests in 5.67 net (31 gross) wells in which it did not previously own an interest and .08 net (six gross) wells where the company previously owned an interest.
Undeveloped Acreage
The following table sets forth the number of undeveloped acres (90% located in the Mid-Continent and Rocky Mountain Regions) 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.
Royalty Working
Interest Acreage Interest Acreage
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Expiration
Year Ending
October 31 Gross Net Gross Net
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2001 - - 1,200 1,000
2002 5,300 100 14,800 2,400
2003 5,800 100 5,800 1,400
2004 8,700 100 14,000 3,500
2005 1,000 500 13,300 4,600
Thereafter 4,400 100 15,600 3,700
Held-By-Production 138,900 8,100 11,800 2,600
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164,100 9,000 76,500 19,200
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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 and the results thereof for the periods indicated.
Gross Wells
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Year Ended Total Gross Exploratory Development
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October 31 Wells Oil Gas Dry Oil Gas Dry
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2000 32 1 22(1) 4 - 4 1
1999 33 - 31(1) - - 2 -
1998 4 - 3 1 - - -
1978-1997 141 11 30 71 15 10 4
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210 12 86 76 15 16 5
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Net Wells
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Year Ended Total Net Exploratory Development
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October 31 Wells Oil Gas Dry Oil Gas Dry
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2000 4.021 .156 2.448(1) .550 - .367 .500
1999 3.841 - 3.701(1) - - .140 -
1998 1.061 - .811 .250 - - -
1978-1997 24.556 1.401 4.973 10.693 4.350 1.654 1.485
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33.479 1.557 11.933 11.493 4.350 2.161 1.985
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(1) Shallow coal bed methane gas wells at less than 1,000 feet in
depth in which the company owns approximately 10%.
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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 2000.
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.
2000 1999 ------------------------------------------------------------- Fiscal Quarter Ended High Low High Low ------------------------------------------------------------- January 31 $3.75 $3.06 $2.00 $1.75 April 30 4.00 3.00 3.00 1.75 July 31 6.00 3.44 3.38 2.88 October 31 9.25 4.69 4.13 3.13 |
At December 31, 2000, the company had 4,031 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. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
At fiscal year-end October 31, 2000, working capital was $4,706,000. Cash generated by operating activities (before working capital changes) totaled $2,109,000 in 2000, and $552,000 of cash was generated from sale of properties. Cash flow was used primarily to fund oil and gas acquisition and development expenditures totaling $1,855,000 and to increase working capital.
Existing working capital and anticipated cash flow are expected to be sufficient to fund fiscal 2001 operations. 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 company has no defined benefit plans and no obligations for post retirement employee benefits.
Product Prices, Production and Investments
Deregulation of natural gas pricing and transportation has 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. During 2000, demand for natural gas caused by U.S. economic expansion, return to normal winter temperatures and gas used to generate electricity has outpaced supply additions causing a tight market for natural gas supplies and rapidly increasing prices.
Significant world events and OPEC's production and pricing policies influence worldwide supply and demand and prices for crude oil and petroleum products. At December 31, 1998, inflation adjusted oil prices stood at 50 year lows of less than $10.00 per barrel but subsequently recovered to highs of over $30.00 per barrel during 2000. This fall and recovery in oil prices demonstrates the extreme volatility in oil prices.
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 by opposite moves in the other market. During the past three years, the company hedged portions of its gas production. Hedging transactions resulted in losses of $141,000 in 2000, and gains of $118,000 and $29,000 in 1999 and 1998, respectively. There were no open hedge or speculative positions at October 31, 2000.
Gas and oil sales volume and price comparisons for the indicated years ended October 31 are set forth below.
2000 1999 1998 --------------------------------------------------------------- Product Volume Price Volume Price Volume Price --------------------------------------------------------------- Gas (Mcf) 668,000 $ 2.84 858,000 $ 2.14 781,000 $ 1.98 % change -22% +33% +10% + 8% +43% -10% Oil (bbls) 39,000 $27.88 39,000 $15.64 40,000 $14.10 % change - +78% -2% +11% + 3% -31% |
The decline in natural gas volumes sold was primarily due to the combined effects of selling the Tracy Federal #1 well as discussed under "Oil and Gas Activities" below, and the expected rapid production decline on the Cline #11-1 well. The Cline #11-1 was the company's largest producing well, accounting for 25% of the company's production last year. During 2000, it continued on a steep production decline resulting in the producing Lower Morrow sand being abandoned late in fiscal 2000 after producing 1.1 Bcfg and 6,700 barrels of oil. The steep decline was expected due to the limited areal extent of the sand. Late in fiscal 2000, the Cline well was recompleted in three up-hole Morrow sands and is currently producing about 300 Mcfgd. Loss of the high volume Cline well production together with sale of the Tracy Federal #1 well caused a 22% decrease in gas production in fiscal 2000 compared to last year. The company had hoped to offset the production loss by developing approximately 1,000 Mcfg per day from a Calliope installation on the 18,600-foot Wallace #1 well. However, a casing leak caused during the workover damaged the producing formation resulting in removal of the Calliope System from the well.
Pending deployment into oil and gas assets, the company invests surplus cash with professional money managers. At October 31, 2000, approximately 94% 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. The investments have a readily determinable market value and over 90% can be converted for use by the company within a few days. Average returns on these investments were approximately 14% in 2000 and 12% in both 1999 and 1998. 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
In fiscal 2000, capital expenditures for oil and gas activities totaled $1,855,000 (before $552,000 of property sales proceeds). The company participated for an average 13% interest in drilling 10 conventional wells in Oklahoma and Wyoming and 22 coal bed methane wells on its Recluse Prospect located on the east side of the Powder River Basin in Wyoming.
During the year, the company sold its remaining 12.5% interest in the Sheridan coal bed methane prospect located on the west side of the Powder River Basin of Wyoming. The sale price was approximately $500,000 plus reimbursement and assumption by the buyer of approximately $850,000 of costs incurred by the company from inception of the project. Sales proceeds reduced oil and gas property costs. On the east side of the Powder River Basin, the company commenced development of its Recluse coal bed methane prospect in which it owns a 10% interest. At fiscal year end, 22 wells had been drilled and completed on the prospect at depths of less than 1,000 feet. Production is expected to commence in the first quarter of 2001.
The most significant of the conventional wells was a 7,700 foot Lower Chester sand oil discovery in Ellis County, Oklahoma in which the company owns a 15% interest. The well has stabilized producing 220 barrels of oil and 220 Mcfg per day from one Lower Chester zone. A second zone also appears to be oil productive and will be worked over in early 2001. This well also encountered multiple productive Morrow gas sands that are not completed for production and may require a twin well to develop. Importantly, the company owns a 55% interest, and is operator of a direct offset location on which drilling is expected to commence in January 2001. There are possible additional locations on both the company's 15% and 55% owned acreage.
The S. E. Hewitt Waterflood Unit located in Carter County, Oklahoma in which the company owns a 20% interest is outperforming initial expectations, and is currently producing 220 barrels of oil per day and is continuing to increase. Additional drilling is being considered to develop additional reserves and accelerate production. At Southfork Field in Woods County, Oklahoma, four development gas wells have been drilled and six additional wells are planned. The company owns a 7% interest.
During fiscal 2000, the company purchased an unrestricted, exclusive license for the Calliope System. The initial License term is ten years. The License includes an option to extend the term to the remaining life of the patent(s). The License purchase price is $1,115,000, of which $170,000 has been paid. The balance is due in annual increments of $105,000 over the next nine years. In addition, the Licensor will receive a net 8.3% carried interest in any installation of the technology. If the option to extend the License after the initial ten-year term is exercised, the cost will be $94,000 per year plus the carried interest, and the term will run to the expiration of the last patent. The License grants CREDO unrestricted, exclusive rights to enter into any business transaction to apply or sell the technology including licensing and joint venturing.
The company participated in developing, testing and patenting the technology, and previously owned one-third of an exclusive license covering the technology as well as a non-exclusive license to use the technology on company wells.
Eight Calliope Systems have been installed at depths ranging from 6,500 feet to 18,600 feet. Each of these applications was a rigorous test for Calliope. Three applications were on dead wells--one for six years--that were scheduled to be plugged and abandoned. After being reinvigorated by Calliope, the three wells represent CREDO's first, fifth and sixth most valuable producing properties. Calliope wells represent 17% of the company's estimated proved reserves quantities at fiscal 2000 year-end, and 20% of the undiscounted value of such reserves.
During 2000, the company installed Calliope Systems on three wells. One system is operating successfully at about 9,800 feet. Another, at 12,600 feet, is installed but the start-up phase of operations is being hampered by bad weather in Oklahoma. The third system, at 18,600 feet, is temporarily abandoned due to formation damage from a casing leak during the Calliope installation. The installation at 18,600 feet was an attempt to significantly extend the application depth from the previous deepest application at 11,900 feet, and to develop reserves of about 2.0 Bcfge. The application was also the first attempt to use two concentric strings of coil tubing from top to bottom of a wellbore. Although the Calliope System worked effectively lifting approximately 18 barrels of fluid per day from 18,600 feet to the surface, a casing leak was created by an elective installation procedure that damaged the formation by dumping water which precipitated solids in the formation and plugged its permeability. The company has removed the Calliope System, isolated the casing leak, and is considering whether to treat the well further in an attempt to mitigate formation damage. The installation at 9,800 feet is a prototype application and the company's first attempt to use two concentric strings of very small coil tubing inside the well's conventional 2-3/8ths inch tubing. The prototype procedure was designed to avoid reconfiguring wellbores and exposing the producing formations to casing leaks similar to that which occurred on the 18,600 foot well. The installation was successful and increased the well's production about five-fold. The installation at 12,600 feet extends the 9,800-foot prototype application to a greater depth and attempts to develop about 1.3 Bcfge.
A Calliope System at depths of 10,000 to 13,000 feet generally costs $150,000 to $300,000, depending on individual well depths, pressures, and other down-hole considerations. The company expects to develop between 500 to 2000 million cubic feet of gas with one application at an average finding cost of less than $0.40 per Mcfg. If unsuccessful, a large portion of the cost consists of equipment which is reusable on other applications. Although Calliope operates successfully at shallow depths, the company believes it will be most effective on wells below 10,000 feet where conventional fluid lift systems lose efficiency at higher abandonment pressures.
The company's reserves are concentrated in relatively few properties. At October 31, 2000, approximately 61% of the value of the company's estimated reserves were concentrated in 14% of the company's producing wells. The company's most significant producing property during 2000, the J.C. Carroll well, accounted for approximately 16% of total gas production and about 10% of estimated proved gas reserve quantities at fiscal year-end. The company owns 75% of the well and is the operator. The well is currently producing at the rate of approximately 610 Mcfg per day with minor amounts of oil and water. The company installed a Calliope System on this 11,900 foot well in mid-1999 and within one month Calliope restored a Morrow formation zone which was abandoned in 1994 to daily production of 620 to 675 Mcfg. The well has exceeded initial performance projections, and during 2000 the company increased its estimate of total reserves which will ultimately be recovered using the Calliope System technology to 1.7 Bcfge. The well has a limited operating history using the Calliope System, and accordingly, reserve estimates must be viewed as being subject to significant change as more data about the well becomes available.
In fiscal 1999, capital expenditures for oil and gas activities totaled $670,000 (before $605,000 of property sales proceeds). 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 on the Sheridan Prospect in the active coal bed methane play on the west side of the Powder River Basin of Wyoming. During fiscal year 1999, 30 shallow wells were drilled on the 15,000 gross acre (1,875 net acre) prospect.
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 had high deliverability (about 300 Mcfg per day) but limited remaining reserves. Eight months after the sale, the well ceased producing. 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.
In 2000, total revenues rose 32% to $4,204,000 compared to $3,196,000 in 1999. As the oil and gas price/volume table on page 8 shows, total gas price realizations, which reflect hedging transactions, rose 33% to $2.84 per Mcf and oil price realizations rose 78% to $27.88 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,076,000. Hedging losses were $141,000 in 2000 compared to hedging gains of $118,000 in 1999. Gas volumes produced declined 22% and oil volumes produced remained unchanged. The net effect of these volume changes was to decrease oil and gas sales by $550,000. As further explained on page 8, the decline in natural gas volumes sold was primarily due to the combined effects of selling the Tracy Federal #1 well and expected production declines on the Cline #11-1 well which was the company's largest producing well. Investment income and other rose 46% primarily due to an increase in funds invested.
Non-recurring litigation settlement income of $345,000 ($245,000 after tax) resulted from settlement of a lawsuit related to investment losses incurred by the company in 1990.
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 8 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 compared to $29,000 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 2000, total costs and expenses rose marginally to $2,307,000 compared to $2,298,000 in 1999. DD&A fell 32% compared to 1999 due primarily to lower production volumes and proceeds from sales of certain properties that reduced the amortization base. Oil and gas production expenses rose 14% primarily due to increased production taxes on higher oil and gas revenues and costs associated with timing of workovers and repairs. General and administrative expenses rose 15% due to inflationary pressures and additional staffing. The effective tax rate was 29% in 2000 compared to 32% in 1999.
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.
Cautionary Statement Pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995
This Form 10-KSB includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this Form 10-KSB, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Such statements are subject to various assumptions, risks and uncertainties, many of which are beyond the control of the company. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those described in the forward-looking statements.
ITEM 7. FINANCIAL STATEMENTS
Index to Consolidated Financial Statements
Consolidated Balance Sheets, October 31, 2000 and 1999
Consolidated Statements of Operations for the Three Years Ended October 31, 2000
Consolidated Statements of Stockholders' Equity for the Three Years Ended October 31, 2000
Consolidated Statements of Cash Flows for the Three Years Ended October 31, 2000
Notes to Consolidated Financial Statements
CONSOLIDATED BALANCE SHEETS
October 31, 2000 and 1999
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------
Assets 2000 1999
----------------------------------------------------------------
Current assets:
Cash and cash equivalents $ 484,000 $ 184,000
Short-term investments 4,626,000 4,055,000
Receivables:
Trade 227,000 443,000
Accrued oil and gas sales 472,000 362,000
Other 108,000 77,000
----------------------------------------------------------------
Total current assets 5,917,000 5,121,000
----------------------------------------------------------------
Oil and gas properties, net, at cost,
using full cost method:
Unevaluated 1,601,000 788,000
Evaluated 5,134,000 5,126,000
----------------------------------------------------------------
Net oil and gas properties 6,735,000 5,914,000
----------------------------------------------------------------
Exclusive license agreement, net of
amortization of $12,000 688,000 -
----------------------------------------------------------------
Other, net 166,000 43,000
----------------------------------------------------------------
$ 13,506,000 $ 11,078,000
================================================================
Liabilities and Stockholders' Equity
----------------------------------------------------------------
Current liabilities:
Accounts payable and
accrued liabilities $ 935,000 $ 739,000
Income taxes payable 276,000 147,000
----------------------------------------------------------------
Total current liabilities 1,211,000 886,000
----------------------------------------------------------------
Deferred income taxes, net 1,408,000 1,227,000
----------------------------------------------------------------
Exclusive license obligation,
less current obligations
of $40,000 500,000 -
----------------------------------------------------------------
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 6,271,000 6,235,000
Retained earnings 4,925,000 3,578,000
Treasury stock, 679,000
and 699,000 shares at cost (1,176,000) (1,215,000)
----------------------------------------------------------------
Total shareholders' equity 10,387,000 8,965,000
----------------------------------------------------------------
$ 13,506,000 $ 11,078,000
================================================================
See accompanying notes to consolidated financial statements.
|
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended October 31, 2000
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------
2000 1999 1998
----------------------------------------------------------------
Revenues:
Oil and gas sales $ 2,971,000 $ 2,445,000 $ 2,105,000
Operating 417,000 428,000 465,000
Investment income
and other 471,000 323,000 243,000
Non-recurring litigation
settlement 345,000 - -
----------------------------------------------------------------
4,204,000 3,196,000 2,813,000
----------------------------------------------------------------
Costs and expenses:
Oil and gas production 934,000 818,000 851,000
Depreciation, depletion
and amortization 481,000 706,000 774,000
General and
administrative 892,000 774,000 682,000
----------------------------------------------------------------
2,307,000 2,298,000 2,307,000
----------------------------------------------------------------
Income before
income taxes 1,897,000 898,000 506,000
Income taxes (550,000) (287,000) (178,000)
----------------------------------------------------------------
Net income $ 1,347,000 $ 611,000 $ 328,000
================================================================
Basic income per share $ .45 $ .20 $ .11
Diluted income per share $ .43 $ .20 $ .11
================================================================
See accompanying notes to consolidated financial statements.
|
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended October 31, 2000
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
------------------------------------------------------------------------------
Capital In Total
Common Stock Excess Of Retained Treasury Stockholders'
Shares Amount Par Value Earnings Stock Equity
------------------------------------------------------------------------------
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
Stock options
issued to
consultant - - 36,000 - - 36,000
Purchase of
treasury stock - - - - (1,000) (1,000)
Exercise of
stock options - - - - 40,000 40,000
Net income - - - 1,347,000 - 1,347,000
------------------------------------------------------------------------------
Balances,
October 31,
2000 3,678,000 $367,000 $6,271,000 $4,925,000 $(1,176,000)$10,387,000
==============================================================================
See accompanying notes to consolidated financial statements.
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended October 31, 2000
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
--------------------------------------------------------------------
2000 1999 1998
--------------------------------------------------------------------
Cash flows from operating
activities:
Net income $1,347,000 $ 611,000 $ 328,000
Non-cash expenses included
in net income:
Depreciation, depletion
and amortization 481,000 706,000 774,000
Deferred income taxes 181,000 183,000 141,000
Other 100,000 15,000 16,000
Changes in operating assets
and liabilities:
Proceeds from
short-term investments 2,418,000 2,241,000 2,859,000
Purchase of
short-term investments (2,989,000) (4,110,000) (2,347,000)
Trade receivables 216,000 (171,000) 46,000
Accrued oil and gas sales (110,000) (90,000) 52,000
Other current assets (31,000) 464,000 (483,000)
Accounts payable
and accrued liabilities 156,000 77,000 (780,000)
Income taxes payable 129,000 96,000 35,000
--------------------------------------------------------------------
Net cash provided by
operating activities 1,898,000 22,000 641,000
--------------------------------------------------------------------
Cash flows from
investing activities:
Additions to oil and
gas properties (1,855,000) (670,000) (1,421,000)
Proceeds from sale of oil
and gas properties 552,000 605,000 576,000
Acquisition of exclusive
license agreement (159,000)(1) - -
Other (175,000) (27,000) (18,000)
--------------------------------------------------------------------
Net cash used in investing
activities (1,637,000) (92,000) (863,000)
--------------------------------------------------------------------
Cash flows from financing
activities:
Proceeds from exercise of
stock options 40,000 - -
Purchase of treasury stock (1,000) (95,000) (64,000)
--------------------------------------------------------------------
Net cash provided by (used in)
financing activities 39,000 (95,000) (64,000)
--------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents 300,000 (165,000) (286,000)
Cash and cash equivalents:
Beginning of year 184,000 349,000 635,000
--------------------------------------------------------------------
End of year $ 484,000 $ 184,000 $ 349,000
====================================================================
(1) Supplemental Disclosure of Non-Cash Investing and Financial
Activities: In fiscal 2000, the company had an obligation for
acquisition of an exclusive license agreement of $540,000.
See accompanying notes to consolidated financial statements.
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
October 31, 2000
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, 2000, short-term investments are 94% 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. The partnerships are invested primarily in financial instruments. Unrealized gains on limited partnerships total $41,000 and $63,000 at October 31, 2000 and 1999, respectively. Short-term investments are classified as "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 $200,000 in 2000 and $100,000 in 1999 and 1998. 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 $3.21 in 2000, $3.57 in 1999 and $4.09 in 1998.
Unevaluated properties consist primarily of lease acquisition and maintenance costs. Evaluation normally takes three to five years. Of the unevaluated property costs, $237,000 and $104,000 were incurred in 2000 and 1999, respectively. During fiscal 2000, the company sold its remaining 12.5% interest in a coal bed methane prospect for $452,000. The proceeds reduced the net carrying value of properties and had no impact on operating results.
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. The company had hedging losses of $141,000 in 2000 and hedging gains of $118,000 and $29,000 in 1999 and 1998, respectively. Gains and losses on speculative transactions were immaterial in all years. There were no open hedge or speculative positions at October 31, 2000.
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 income 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 2,981,000 to 3,175,000 in 2000, from 2,985,000 to 3,085,000 in 1999 and from 3,042,000 to 3,137,000 shares in 1998.
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.
(2) COMMON STOCK AND PREFERRED STOCK
During 1999, the company acquired 50,000 shares of its common stock at a total cost of $95,000. 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 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.
Years Ended October 31 2000 1999 1998
--------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Options Price Options Price Options Price
--------------------------------------------------------------------------
Outstanding at 361,667 $2.10 371,667 $1.94 415,000 $1.94
beginning
of year
Granted 45,000 4.55 20,000 3.19 20,000 1.63
Exercised (20,000) 1.94 - (33,333) 1.94
Cancelled
or forfeited (20,000) 1.63 (30,000) 1.94 (30,000) 1.94
--------------------------------------------------------------------------
Outstanding
at end of year 366,667 $2.33 361,667 $2.10 371,667 $1.94
=========================================================================
|
Options are exercisable at weighted average exercise prices as follows: 267,917 in 2000 at $1.94 and 13,333 at $4.28; 33,750 in 2001 at $1.94 and 18,333 at $4.22; 18,334 in 2002 at $4.22; 10,000 in 2003 at $3.63, and 5,000 in 2004 at $4.06. Options expire with weighted average exercise prices as follows: 301,667 in 2002 at $1.94; 20,000 in 2004 at $3.19, and 45,000 in 2005 at $4.55. The weighted average remaining contractual life of options outstanding at October 31, 2000 is 1.6 years.
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 2000 would have been $1,257,000, or $.42 per share basic and $.40 per share diluted, for 1999 would have been $534,000, or $.18 per share basic and $.17 per share diluted and for 1998 would have been $254,000, or $.08 per share. For the purpose of this disclosure, the fair value of each option granted was $2.26 in 2000, $1.84 in 1999 and $.72 in 1998. All option were granted with an exercise price equal to the market price on the date of grant. The fair value was estimated on the date of grant using the Black-Scholes option-pricing model with an expected volatility of 48% in 2000, 61% in 1999 and 40% in 1998, 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 which was amended to extend the lease term for an additional five years effective May 1, 2001. The lease agreement requires payments of $44,000 in 2001, $42,000 in 2002 through 2005 and $21,000 in 2006. Total rental expense in fiscal 2000 was $46,000, $44,000 in 1999 and $42,000 in 1998. The company has no capital leases and no other operating lease commitments.
(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:
Years Ended October 31 2000 1999 1998
--------------------------------------------------------------
Current $ 369,000 $ 104,000 $ 36,000
Deferred 181,000 183,000 141,000
--------------------------------------------------------------
$ 550,000 $ 287,000 $ 177,000
==============================================================
|
The effective income tax rate differs from the U.S. Federal statutory income tax rate due to the following:
Years Ended October 31 2000 1999 1998
--------------------------------------------------------------
Federal statutory
income tax rate 34% 34% 34%
Effect of graduated
tax rates - 2 2
State income taxes 3 2 2
Percentage depletion (8) (6) (6)
Other, net - - 3
---------------------------------------------------------------
29% 32% 35%
===============================================================
|
The principal sources of temporary differences resulting in deferred tax assets and tax liabilities at October 31, 2000 and 1999 are as follows:
October 31 2000 1999
-------------------------------------------------------------
Deferred tax assets:
Percentage depletion
carryforwards $ - $ 3,000
Gain on property sales 408,000 245,000
-------------------------------------------------------------
Total deferred tax assets 408,000 248,000
-------------------------------------------------------------
Deferred tax liabilities:
Intangible drilling, leasehold and
other exploration costs
capitalized for financial
reporting purposes but
deducted for tax purposes (1,701,000) (1,371,000)
State taxes and other (115,000) (104,000)
-------------------------------------------------------------
Total gross deferred tax
liabilities (1,816,000) (1,475,000)
-------------------------------------------------------------
Net deferred tax liability $(1,408,000) $(1,227,000)
=============================================================
|
(5) EXCLUSIVE LICENSE AGREEMENT OBLIGATION
On September 1, 2000, the company acquired an unrestricted, exclusive license for recently patented technology. The initial license term is ten years and includes an option to extend the term to the remaining life of the patents. The licensor will receive a net 8.3% carried interest in any installation of the technology. The license purchase price is $1,115,000, of which $170,000 has been paid. The balance, which is due in nine annual increments of $105,000, was recorded at 10% present value. The related assets are being amortized over 10 years on a straight-line basis. If the option to extend the license after the initial ten-year term is exercised, the cost will be $94,000 per year to the expiration of the last patent.
(6) SUPPLEMENTARY OIL AND GAS INFORMATION
Capitalized Costs October 31 2000 1999 1998 --------------------------------------------------------------- Unproved properties not being amortized $ 1,601,000 $ 788,000 $ 616,000 Properties being amortized 13,374,000 12,884,000 12,991,000 Accumulated depreciation, depletion and amortization (8,240,000) (7,758,000) (7,106,000) --------------------------------------------------------------- Total capitalized costs $ 6,735,000 $ 5,914,000 $ 6,501,000 =============================================================== |
Acquisition, Exploration and Development Costs Incurred Years Ended October 31 2000 1999 1998 --------------------------------------------------------------- Property acquisition costs net of divestiture proceeds: Proved $ - $ (594,000) $ 14,000 Unproved (315,000) 104,000 (260,000) Exploration costs 1,289,000 227,000 390,000 Development costs 329,000 328,000 701,000 --------------------------------------------------------------- Net costs incurred $ 1,303,000 $ 65,000 $ 845,000 =============================================================== |
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: GPM Gas Corporation 17% in 2000, 17% in 1999 and 14% in 1998; Total Petroleum, Inc. 15% in 2000 and 18% in 1999 and 1998; Enogex, Inc. 11% in 2000 and 0% in 1999 and 1998; Duke Energy 10% in 2000, 25% in 1999 and 20% in 1998.
Oil and Gas Reserve Data (Unaudited)
In 2000, 1999 and 1998, independent petroleum engineers estimated proved reserves for the company's significant properties which represented approximately 63% 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 $31.82, $21.01 and $12.59 per barrel for oil and $4.33, $2.73 and $2.03 per Mcf for gas in 2000, 1999 and 1998, respectively. Estimated future costs were calculated assuming continuation of costs and economic conditions at the reporting date.
Total estimated proved reserves and the changes therein are set forth below for
the indicated fiscal year.
2000 1999 1998
------------------------------------------------------------------------------
Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls)
------------------------------------------------------------------------------
Proved reserves:
Balance,
November 1 6,683,000 321,000 6,676,000 314,000 5,868,000 368,000
Revisions of
previous
estimates 169,000 28,000 388,000 52,000 346,000 (25,000)
Extensions and
discoveries 1,206,000 63,000 977,000 1,000 1,000,000 7,000
Purchases of
reserves in place 36,000 - 6,000 - 243,000 4,000
Sales of reserves
in place (13,000) - (506,000) (7,000) - -
Production (668,000) (39,000) (858,000) (39,000) (781,000) (40,000)
------------------------------------------------------------------------------
Balance,
October 31 7,413,000 373,000 6,683,000 321,000 6,676,000 314,000
==============================================================================
Proved developed reserves:
Beginning of
period 5,704,000 287,000 5,909,000 302,000 4,874,000 335,000
==============================================================================
End of
period 6,511,000 340,000 5,704,000 287,000 5,909,000 302,000
==============================================================================
|
The standardized measure of discounted future net cash flows from reserves is
set forth below as of October 31 of the indicated fiscal year.
2000 1999 1998
------------------------------------------------------------------------------
Future cash inflows $ 43,981,000 $ 24,960,000 $ 17,647,000
Future production and
development costs (12,506,000) (8,707,000) (6,261,000)
Future income tax expense (7,142,000) (3,186,000) (1,790,000)
------------------------------------------------------------------------------
Future net cash flows 24,333,000 13,067,000 9,596,000
10% discount factor (9,877,000) (5,143,000) (3,346,000)
------------------------------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 14,456,000 $ 7,924,000 $ 6,250,000
==============================================================================
|
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.
2000 1999 1998
------------------------------------------------------------------------------
Balance, November 1 $ 7,924,000 $ 6,250,000 $ 7,412,000
Sales of oil and gas produced,
net of production costs (2,037,000) (1,509,000) (1,253,000)
Net changes in prices, production
and development costs 5,910,000 2,126,000 (2,609,000)
Extensions and discoveries,
net of future development
and production costs 3,194,000 1,272,000 1,373,000
Revisions of quantity
estimates and other 964,000 1,198,000 252,000
Purchases of reserves in place 93,000 10,000 296,000
Sales of reserves in place (34,000) (1,201,000) -
Accretion of discount 792,000 625,000 741,000
Net change in income taxes (2,350,000) (847,000) 38,000
------------------------------------------------------------------------------
Balance, October 31 $ 14,456,000 $ 7,924,000 $ 6,250,000
==============================================================================
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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, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three year period ended October 31, 2000, in conformity with generally accepted accounting principles.
Denver, Colorado
December 29, 2000
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS
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 2000.
ITEM 10. 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 2000.
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 2000.
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 2000.
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) 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-KSB
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).
10(d) CPC Exclusive License Agreement, dated
September 1, 2000.
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.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the last
quarter of the period covered by this report.
|
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.
By:/s/ James T. Huffman ---------------------------- James T. Huffman, Chief Executive Officer By:/s/ John A. Alsko ---------------------------- John A. Alsko Vice President and Chief Financial Officer |
Date: January 4, 2001
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 4, 2001 /s/ William N. Beach Director
------------------------
William N. Beach
January 4, 2001 /s/ Clarence H. Brown Director
------------------------
Clarence H. Brown
January 4, 2001 /s/ Otto P. Butterly Director
------------------------
Otto P. Butterly
January 4, 2001 /s/ Oakley Hall Director
------------------------
Oakley Hall
January 4, 2001 /s/ James T. Huffman Chairman of
------------------------ the Board,
James T. Huffman President,
Treasurer
January 4, 2001 /s/ William F. Skewes Director,
------------------------ Corporate
William F. Skewes Secretary,
General Counsel
January 4, 2001 /s/ Richard B. Stevens Director
------------------------
Richard B. Stevens
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