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(Address of principal executive offices and zip code) 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: $5,807,000 As of December 31, 2001, the aggregate market value of common stock held by non-affiliates of the registrant was approximately $15,397,000. DOCUMENTS INCORPORATED BY REFERENCE into Part III hereof - Proxy Statement to be filed with the Commission in connection with the company's 2002 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 eight states and has ten 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) exploration for and
development of oil and gas reserves, Except for development, testing and application of Calliope, operations are concentrated on 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 Calliope are concentrated below 10,000 feet and, to date, have not required external sources of capital. The company acts as "operator" of 83 wells pursuant to standard industry Operating Agreements, and it owns working and royalty interests in approximately 563 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 and their results are proportionately consolidated in the company's financial statements. Over the past four years, the company has participated in developing, testing, refining, and patenting the Calliope Gas Recovery 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 Calliope on eight wells ranging in depth from 6,500 feet to 18,600 feet. Of the eight applications, three rank as the company's second, third and seventh most valuable producing properties. Although Calliope 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 company believes it has proven Calliope's breadth and economic viability on actual field applications of wells it owns and operates. 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 oil price fall to below $10.00 per barrel in 1999 and recovery to over $30.00 in 2000 demonstrates its extreme price volatility.
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. Gas price decontrol, the advent of an active spot market for natural gas, changes in supply and demand for natural gas, and weather patterns cause prices received by the company to be subject to significant fluctuations. The company presently sells virtually all 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 2001, gas prices rose to historic highs as demand growth 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 hampered its ability to respond to surging demand. However, as the year progressed, gas demand was lost due to high prices resulting in rapidly increasing gas storage inventories and a dramatic gas price reversal during the year. Currently, gas inventories are very high, demand is weak due to a warm start to the winter, and prices are soft, particularly compared to last year. 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. The company does not believe that capital expenditures related to environmental control facilities or other regulatory matters will be material in fiscal 2002. The company cannot predict what subsequent legislation or regulations may be enacted or what effect it will have on the company's business.
General In fiscal 2001, capital expenditures for oil and gas activities totaled $2,688,000 (before $34,000 of property sales proceeds). During the year, the company participated in drilling 11 gas wells in Oklahoma and Wyoming which were successfully completed as commercial gas wells. The company's interest in the wells ranged from 5% to 60%. During the year, the electrical, gathering and water disposal infrastructures were installed for the 22 coal bed methane wells drilled last year on the company's 10% owned Recluse property. The property recently commenced production and is in the start-up phase. The company also significantly refined and extended the limits of its patented Calliope technology. The company believes that it has proved the economic viability and breadth of the Calliope system.
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 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. 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, 2001, approximately 61% of the value of the company's estimated reserves were concentrated in 15% of the company's producing wells. The J. C. Carroll well was the company's most significant producing property during 2001. The company purchased the Carroll well in mid-1999 and installed Calliope. The well accounted for approximately 12% of total gas production in 2001 and about 6% of total reserve quantities at fiscal year-end. The Carroll well ranks as the company's second largest well in terms of reserve quantities. The Glendena #1 well was drilled late in fiscal 2001 and appears to be a very significant well. It was not placed on production until the last few days of the fiscal year, and therefore, did not contribute to 2001 production. It was, however, included in the company's fiscal year-end reserve estimates and accounted for approximately 7% of total reserves. The Glendena well ranks as the company's largest well in terms of reserve quantities. These wells have a limited, or no, production history (as configured in the case of the Carroll), and accordingly, reserve estimates must be viewed as being subject to significant change as more data about the wells 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 62% in 2001, 63% in 2000, and 64% in 1999 of the total estimated future value of estimated reserves. Remaining reserves were estimated by the company in all years. At October 31, 2001, natural gas represented 82% and crude oil represented 18% 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 $20.61, $31.82, and $21.01 per barrel for oil and $2.87, $4.33, and $2.73 per Mcf for gas as of October 31, 2001, 2000, and 1999, respectively. Amounts do not include estimates of future Federal and state income taxes.
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Estimated Future
Oil Gas Estimated Future Net Revenues
Year (bbls)* (Mcf)* Net Revenues Discounted at 10%
----------------------------------------------------------------
2001 330,000 9,121,000 $ 21,843,000 $ 13,874,000
2000 373,000 7,413,000 $ 31,475,000 $ 18,700,000
1999 321,000 6,683,000 $ 16,254,000 $ 9,856,000
* Of 2001, 2000 and 1999 amounts, proved developed reserves were
296,000, 340,000, and 287,000 barrels of oil and 8,249,000,
6,511,000, and 5,704,000 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.
2001 2000 1999 --------------------------------------------------------------- Product Volume Price Volume Price Volume Price --------------------------------------------------------------- Gas (Mcf) 800,000 $ 5.00 668,000 $ 2.84 858,000 $ 2.14 Oil (bbls) 44,000 $26.45 39,000 $27.88 39,000 $15.64 |
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Average production costs, including production taxes, per unit of production (using a six to one conversion ratio of Mcfs to barrels) were $6.40, $6.21, and $4.49 per barrel in 2001, 2000, and 1999, respectively. Productive Wells and Developed Acreage Developed acreage at October 31, 2001 totaled 19,600 net and 103,000 gross acres. At October 31, 2001, the company owned working interests in 53.68 net (182 gross) wells consisting of 19.80 net (44 gross) oil wells and 33.88 net (138 gross) gas wells. In addition, the company owned royalty and production payment interests in approximately 453 oil and gas wells. In 2001, the company sold .53 net (7 gross) wells. In the same period, the company drilled and acquired interests in 2.34 net (13 gross) wells in which it did not previously own an interest and .49 net (5 gross) wells where the company previously owned an interest. Undeveloped Acreage The following table sets forth the number of undeveloped acres |
Royalty Working
Interest Acreage Interest Acreage
---------------------------------------------------------------
Expiration
Year Ending
October 31 Gross Net Gross Net
---------------------------------------------------------------
2002 5,300 100 14,300 1,900
2003 6,200 400 3,500 600
2004 8,600 1,000 13,500 3,400
2005 1,700 500 10,800 3,700
2006 1,100 100 6,900 1,600
Thereafter 3,300 100 11,900 2,700
Held-By-Production 146,500 8,200 11,800 2,600
---------------------------------------------------------------
172,700 10,400 72,700 16,500
===============================================================
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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
-----------------------------------------------------------------------
Year Ended Total Gross Exploratory Development
------------------- --------------------
October 31 Wells Oil Gas Dry Oil Gas Dry
-----------------------------------------------------------------------
2001 11 - 9(1) - - 2 -
2000 32 1 22(2) 4 - 4 1
1999 33 - 31(2) - - 2 -
1978-1998 145 11 33 72 15 10 4
-----------------------------------------------------------------------
221 12 95 76 15 18 5
=======================================================================
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Net Wells
-----------------------------------------------------------------------
Year Ended Total Net Exploratory Development
--------------------- ---------------------
October 31 Wells Oil Gas Dry Oil Gas Dry
-----------------------------------------------------------------------
2001 2.236 - 2.097(1) - - .139 -
2000 4.021 .156 2.448(2) .550 - .367 .500
1999 3.841 - 3.701(2) - - .140 -
1978-1998 25.617 1.401 5.784 10.943 4.350 1.654 1.485
-----------------------------------------------------------------------
35.715 1.557 14.030 11.493 4.350 2.300 1.985
=======================================================================
(1) Includes two shallow coal bed methane gas wells at less than
1,000 feet in depth in which the company owns approximately 5%.
(2) 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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2001 2000 --------------------------------------------------------------- Fiscal Quarter Ended High Low High Low --------------------------------------------------------------- January 31 $ 7.69 $ 4.75 $ 3.75 $ 3.06 April 30 7.50 6.31 4.00 3.00 July 31 10.30 6.29 6.00 3.44 October 31 7.75 4.87 9.25 4.69 |
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At December 31, 2001, the company had 3,888 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
At fiscal year-end October 31, 2001, working capital was $5,791,000. Cash generated by operating activities (before working capital changes) totaled $3,392,000 in 2001, and $34,000 of cash was generated from property sales. Cash flow was used primarily to fund oil and gas acquisition and development expenditures totaling $2,688,000 and to increase working capital. Existing working capital and anticipated cash flow are expected to be sufficient to fund fiscal 2002 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 Gas price decontrol, the advent of an active spot market for natural gas, changes in supply and demand for natural gas, and weather patterns cause prices received by the company to be subject to significant fluctuations. The company presently sells virtually all 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. 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 in November 2000. This fall and recovery in oil prices demonstrates their extreme volatility. 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 at a time when 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 gains of
$663,000 in 2001, losses of $141,000 in 2000, and gains of $118,000 in 1999. At
October 31, 2001, the company's open hedge positions totaled 580,000 Mcf
covering the months of November 2001 through July 2002 at an average price of
$3.39 per Mcf. This hedge represents approximately 76% of the company's
estimated gas production for those months. |
Gas and oil sales volume and price comparisons for the indicated years ended October 31 are set forth below.
2001 2000 1999 --------------------------------------------------------------------- Product Volume Price Volume Price Volume Price --------------------------------------------------------------------- Gas (Mcf) 800,000 $ 5.00 668,000 $ 2.84 858,000 $ 2.14 % change +20% +76% -22% +33% +10% +8% Oil (bbls) 44,000 $26.45 39,000 $27.88 39,000 $15.64 % change +14% -5% - +78% -2% +11% |
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The 2001 increase in natural gas volumes resulted from successful completion of nine gas wells along the Anadarko Shelf of Oklahoma that were placed on production during 2001. The decline in gas volume in 2000 resulted from property divestitures and the expected rapid production decline of a major well. The increase in oil volumes sold was primarily due to production from new discoveries made in the prior year and positive results from an Oklahoma waterflood project. Pending deployment into oil and gas assets, the company invests surplus cash with professional money managers. At October 31, 2001, approximately 75% 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 50% can be converted for use by the company within a few days. Average returns on these investments were approximately 4% in 2001, 14% in 2000 and 12% in 1999. The company believes that the most significant risk of its investment strategy is a single day catastrophic negative effect on the stock market of a major, unexpected event like the September 11, 2001 terrorist attacks. Oil and Gas Activities In fiscal 2001, capital expenditures for oil and gas activities totaled $2,688,000 (before $34,000 of property sales proceeds). The company participated in drilling nine gas wells in connection with its core drilling program along the Anadarko Shelf of Oklahoma which were successfully completed as commercial producers. The company's interests in the wells ranged from 7% to 60%. The most important well drilled in fiscal 2001 was the 7,600-foot Glendena #1 located in Ellis County, Oklahoma. This well tested the Morrow formation on the company's 1,600-acre Sand Creek Prospect. It encountered two Morrow zones totaling 31 feet and was completed naturally (without acid or fracture treatments) from one of the two zones. Initial production and pressure data are very encouraging. Since sales commenced in late October, the well has produced at an average daily rate of about 3.0 MMcfg with minor amounts of condensate and water. The second zone will be completed at a future date. The Glendena well did not contribute to fiscal 2001 results because production commenced near fiscal year end. However, it is expected to have a significant effect on 2002 production. The company currently controls 1,600 acres in the Sand Creek Prospect area, providing ample room to drill offset wells. The first such well is scheduled to spud in late January. CREDO owns a 40% working interest and is the operator. Another good well, the 8,700-foot Bill-Judy Brown #1-6, was drilled in a very active area of Beaver County, Oklahoma to test the Chester, Morrow and St. Louis formations. It is currently producing at the rate of 455 Mcfgd. The company owns a 60% working interest and is the operator.
The electrical, gathering and water disposal infrastructures were installed for the 22 coal bed methane wells drilled last year on the company's 10% owned Recluse property. The property recently commenced production and is in the start-up phase. During the year, the company significantly refined and extended the limits of its patented Calliope Gas Recovery System. The company believes that it has proved the economic viability and breadth of the Calliope system on wells it owns and operates. However, the run-up in gas prices the last two years has severely hindered the company's efforts to purchase wells for Calliope. The company's challenge is to acquire or otherwise obtain more wells for application of its Calliope system. The original plan was to use Calliope exclusively on company-owned wells. However, difficulty buying wells has necessitated consideration of other strategies such as joint venturing with certain large companies to install Calliope on their wells. The company is well under way developing a highly sophisticated multimedia presentation to market Calliope. The company has also retained a reconnaissance firm to interview the appropriate decision makers in the companies and determine how to best present the technology in a way that meets their needs. As a gas well depletes, technologies that rely on bottom hole pressure to
lift liquids that load-up the well and restrict gas flow become inefficient. In
many gas wells, the operating limits of conventional liquid lift technologies
cause billions of cubic feet of gas to be left behind and substantial profits to
be lost. For those wells, Calliope will achieve substantially lower reservoir
abandonment pressure than conventional production methods because it does not
rely on bottom hole pressure or adequate fluid volumes to lift liquids. Actual
field results from Calliope applications on previously dead wells owned by the
company include: (i) adding low risk reserves at a cost of $.50 per Mcfg, or
less; (ii) reviving combined production to over 1,000,000 cubic feet of gas per
day on three dead wells that were scheduled by the operators to be plugged;
(iii) lowering abandonment pressures to less than 60 psi at 8,500 feet; and The company has proved to its satisfaction that Calliope will add .5 to 2.0 Bcf of gas reserves to many dead or uneconomic gas wells. The 11,800-foot J. C. Carroll well provides an excellent example of Calliope's potential. When the well was purchased for salvage value in 1999, it had not produced commercially in five years. Calliope immediately restored production to 660 thousand cubic feet of gas per day. The company estimates that Calliope will recover 1.7 billion cubic feet of additional gas from the Carroll well. It is the company's second most valuable asset. 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 five years--that were scheduled to be plugged and abandoned. After being reinvigorated by Calliope, these three wells are currently CREDO's second, third and seventh most valuable producing properties. Calliope wells accounted for 22% of the company's fiscal 2001 gas production volume, and they represent 24% of the company's estimated proved reserves quantities at fiscal 2001 year-end. The cost of a Calliope system varies with depth, well conditions, and other related factors. 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, 2001, approximately 61% of the value of the company's estimated reserves were concentrated in 15% of the company's producing wells. The J. C. Carroll well was the company's most significant producing property during 2001. The company purchased the Carroll well in mid-1999 and installed Calliope. The well accounted for approximately 12% of total gas production in 2001 and about 6% of total reserve quantities at fiscal year-end. The Carroll well ranks as the company's second largest well in terms of reserve quantities. The Glendena #1 well was drilled late in fiscal 2001 and appears to be a very significant well. It was not placed on production until the last few days of the fiscal year, and therefore, did not contribute to 2001 production. It was, however, included in the company's fiscal year-end reserve estimates and accounted for approximately 7% of total reserves. The Glendena well ranks as the company's largest well in terms of reserve quantities. These wells have a limited, or no, production history (as configured in the case of the Carroll), and accordingly, reserve estimates must be viewed as being subject to significant change as more data about the wells becomes available.
In 2001, total revenues rose 38% to $5,807,000 compared to $4,204,000 in 2000. As the oil and gas price/volume table on page 8 shows, total gas price realizations, which reflect hedging transactions, rose 76% to $5.00 per Mcf and oil price realizations fell 5% to $26.45 per barrel. The net effect of these price changes was to increase oil and gas sales by $1,388,000. Hedging gains were $663,000 in 2001 compared to hedging losses of $141,000 in 2000. Gas volumes and oil volumes produced rose 20% and 14%, respectively. The net effect of these volume changes was to increase oil and gas sales by $804,000. The increase in gas production resulted from new wells added during the year. Operating income rose 9% due to drilling supervision income and additional operated properties. Investment income and other declined 60% due primarily to a volatile and down trending stock market during fiscal 2001 which limited investment opportunities for the market timers that manage the bulk of the company's investments. 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. 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 2001, total costs and expenses rose 30% to $2,987,000 compared to $2,307,000 in 2000. The 22% increase in oil and gas production expenses primarily reflects increased production taxes on higher oil and gas sales revenue. Depletion, depreciation and amortization ("DD&A") increased 58% due to increases in oil and gas production and amortization of the cost of an exclusive license agreement which was not effective in the prior year. General and administrative expenses rose 14% due to inflationary pressures and additional staffing. Interest expense relates to the exclusive license agreement note payment that was not effective in the prior year. The effective tax rate was 29% in 2001 and 2000.
In 2000, total costs and expenses rose marginally to $2,307,000 compared to $2,298,000 in 1999. DD&A fell 26% 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 11% due to inflationary pressures and additional staffing. The effective tax rate was 29% in 2000 compared to 32% in 1999. 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, 2001 and 2000 Consolidated Statements of Operations for the Three Years Ended October 31, 2001 Consolidated Statements of Stockholders' Equity for the Three Years Ended October 31, 2001 Consolidated Statements of Cash Flows for the Three Years Ended October 31, 2001 Notes to Consolidated Financial Statements
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CONSOLIDATED BALANCE SHEETS
October 31, 2001 and 2000
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
---------------------------------------------------------------
Assets 2001 2000
---------------------------------------------------------------
Current assets:
Cash and cash equivalents $ 819,000 $ 484,000
Short-term investments 5,283,000 4,626,000
Receivables:
Trade 317,000 227,000
Accrued oil and gas sales 367,000 472,000
Other 241,000 108,000
---------------------------------------------------------------
Total current assets 7,027,000 5,917,000
---------------------------------------------------------------
Oil and gas properties, net, at cost,
using full cost method:
Unevaluated 1,549,000 1,601,000
Evaluated 7,120,000 5,134,000
---------------------------------------------------------------
Net oil and gas properties 8,669,000 6,735,000
---------------------------------------------------------------
Exclusive license agreement, net of
amortization of $82,000 and $12,000 618,000 688,000
---------------------------------------------------------------
Other, net 156,000 166,000
---------------------------------------------------------------
$16,470,000 $13,506,000
===============================================================
Liabilities and Stockholders' Equity
---------------------------------------------------------------
Current liabilities:
Accounts payable
and accrued liabilities $ 1,126,000 $ 935,000
Income taxes payable 110,000 276,000
---------------------------------------------------------------
Total current liabilities 1,236,000 1,211,000
---------------------------------------------------------------
Deferred income taxes, net 1,935,000 1,408,000
---------------------------------------------------------------
Exclusive license obligation,
less current obligations
of $44,000 and $40,000 456,000 500,000
---------------------------------------------------------------
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 6,453,000 6,271,000
Retained earnings 6,927,000 4,925,000
Accumulated other
comprehensive income 14,000 -
Treasury stock, 502,000
and 679,000 shares at cost (918,000) (1,176,000)
---------------------------------------------------------------
Total shareholders' equity 12,843,000 10,387,000
---------------------------------------------------------------
$16,470,000 $13,506,000
===============================================================
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended October 31, 2001
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
----------------------------------------------------------------
2001 2000 1999
------------------------------------------------------------------------
Revenues:
Oil and gas sales $ 5,163,000 $ 2,971,000 $ 2,445,000
Operating 456,000 417,000 428,000
Investment income and other 188,000 471,000 323,000
Non-recurring litigation
settlement - 345,000 -
------------------------------------------------------------------------
5,807,000 4,204,000 3,196,000
------------------------------------------------------------------------
Costs and expenses:
Oil and gas production 1,135,000 934,000 818,000
Depreciation, depletion
and amortization 842,000 533,000 721,000
General and administrative 957,000 840,000 759,000
Interest 53,000 - -
------------------------------------------------------------------------
2,987,000 2,307,000 2,298,000
------------------------------------------------------------------------
Income before income taxes 2,820,000 1,897,000 898,000
Income taxes (818,000) (550,000) (287,000)
------------------------------------------------------------------------
Net income $ 2,002,000 $ 1,347,000 $ 611,000
========================================================================
Basic income per share $ .64 $ .45 $ .20
Diluted income per share $ .61 $ .43 $ .20
========================================================================
See accompanying notes to consolidated financial statements.
|
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended October 31, 2001
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
---------------------------------------------------------------------------------------------------------------------
Accumulated
Common Stock Capital In Other Total
---------------------- Excess Of Retained Comprehensive Treasury Stockholders'
Shares Amount Par Value Earnings Income Stock Equity
---------------------------------------------------------------------------------------------------------------------
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
Comprehensive income:
Net Income - - - 2,002,000 - - 2,002,000
Other comprehensive income,
net of tax: Change in fair
value of derivatives - - - - 14,000 - 14,000
-----------
Comprehensive income - - - - - - 2,016,000
Stock options issued
to consultant - - 12,000 - - - 12,000
Income tax benefit from
exercise of nonqualified
stock options and
premature dispositions - - 170,000 - - - 170,000
Purchase of treasury stock - - - - - (129,000) (129,000)
Exercise of stock options - - - - - 387,000 387,000
---------------------------------------------------------------------------------------------------------------------
Balances, October 31, 2001 3,678,000 $ 367,000 $ 6,453,000 $ 6,927,000 $ 14,000 $ (918,000) $12,843,000
=====================================================================================================================
See accompanying notes to consolidated financial statements.
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended October 31, 2001
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
---------------------------------------------------------------
2001 2000 1999
----------------------------------------------------------------------------
Cash flows from operating activities:
Net income $ 2,002,000 $ 1,347,000 $ 611,000
Non-cash expenses included in
net income:
Depreciation, depletion and
amortization 842,000 533,000 721,000
Deferred income taxes 527,000 181,000 183,000
Other 21,000 48,000 -
Changes in operating assets
and liabilities:
Proceeds from
short-term investments 3,209,000 2,418,000 2,241,000
Purchase of
short-term investments (3,866,000) (2,989,000) (4,110,000)
Trade receivables (90,000) 216,000 (171,000)
Accrued oil and gas sales 105,000 (110,000) (90,000)
Other current assets 12,000 (31,000) 464,000
Accounts payable
and accrued liabilities 191,000 156,000 77,000
Income taxes payable (140,000) 129,000 96,000
----------------------------------------------------------------------------
Net cash provided
by operating activities 2,813,000 1,898,000 22,000
----------------------------------------------------------------------------
Cash flows from investing activities:
Additions to oil and gas properties (2,688,000) (1,855,000) (670,000)
Proceeds from sale of oil and gas
properties 34,000 552,000 605,000
Acquisition of exclusive license
agreement - (159,000)(1) -
Other (42,000) (175,000) (27,000)
----------------------------------------------------------------------------
Net cash used in investing activities (2,696,000) (1,637,000) (92,000)
----------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from exercise
of stock options 387,000 40,000 -
Purchase of treasury stock (129,000) (1,000) (95,000)
Principal payment on exclusive
license obligation (40,000) - -
----------------------------------------------------------------------------
Net cash provided by (used in)
financing activities 218,000 39,000 (95,000)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents 335,000 300,000 (165,000)
Cash and cash equivalents:
Beginning of year 484,000 184,000 349,000
----------------------------------------------------------------------------
End of year $ 819,000 $ 484,000 $ 184,000
============================================================================
(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, 2001 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, 2001, short-term investments are 75% 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 $97,000 and $41,000 at October 31, 2001 and 2000, 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 $200,000 in 2001 and 2000 and $100,000 in 1999. 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 $4.06 in 2001, $3.21 in 2000 and $3.57 in 1999. Unevaluated properties consist primarily of lease acquisition and maintenance costs. Evaluation normally takes three to five years. Of the unevaluated property costs, $121,000 and $237,000 were incurred in 2001 and 2000, respectively.
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, which are accounted for as cash flow 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 gains of $663,000 in 2001, hedging losses of $141,000 in 2000 and hedging gains of $118,000 in 1999. Gains and losses on speculative transactions were immaterial in all years. The company has recorded in other comprehensive income a gain of $14,000 (net of tax) relating to the estimated fair value of open future positions at October 31, 2001. Any hedge ineffectiveness, which is currently immaterial, is immediately recognized in other income. At October 31, 2001, the company's open hedge position totaled 580,000 Mcf covering the months of November 2001 through July 2002 at an average price of $3.39 per Mcf. This hedge represents approximately 76% of the company's estimated gas production for those months. 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 3,110,000 to 3,271,000 in 2001, 2,981,000 to 3,175,000 in 2000 and from 2,985,000 to 3,085,000 in 1999. Impact of New Accounting Pronouncement In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. This statement is effective for fiscal years beginning after June 15, 2002. The effect of this standard on the company's results of operations and financial position is not expected to be material.
(2) COMMON STOCK AND PREFERRED 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"), as amended and
restated effective October 25, 2001, authorizes the granting of incentive and
nonqualified options to purchase shares of the company's common stock. 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 2001 2000 1999
---------------------------------------------------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Exercise of Exercise of Exercise
Options Price Options Price Options Price
---------------------------------------------------------------------
Outstanding at 366,667 $2.33 361,667 $2.10 371,667 $1.94
beginning
of year
Granted 125,000 4.90 45,000 4.55 20,000 3.19
Exercised (196,667) 1.97 (20,000) 1.94 - -
Cancelled
or forfeited - - (20,000) 1.63 (30,000) 1.94
--------------------------------------------------------------------
Outstanding
at end of year 295,000 $3.66 366,667 $2.33 361,667 $2.10
====================================================================
|
|
Options are exercisable at weighted average exercise prices as follows: 110,000 in 2001 at $1.94 and 34,999 at $4.58; 51,667 in 2002 at $4.67; 43,334 in 2003 at $4.61; 30,000 in 2004 at $4.74; and 25,000 in 2005 at $4.88. Options expire with weighted average exercise prices as follows: 110,000 in 2002 at $1.94; 15,000 in 2004 at $3.19, 45,000 in 2005 at $4.55 and 125,000 in 2006 at $4.90. The weighted average remaining contractual life of options outstanding at October 31, 2001 is 3.0 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 2001 would have been $1,872,000, or $.60 per share basic and $.57 per share diluted, for 2000 would have been $1,257,000, or $.42 per share basic and $.40 per share diluted, and for 1999 would have been $534,000, or $.18 per share basic and $.17 per share diluted. For the purpose of this disclosure, the fair value of each option granted was $2.41 in 2001, $2.26 in 2000 and $1.84 in 1999. All options 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 58% in 2001, 48% in 2000 and 61% in 1999, 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 $42,000 in 2002 through 2005 and $21,000 in 2006. Total rental expense in fiscal 2001 was $43,000, $46,000 in 2000 and $44,000 in 1999. 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 2001 2000 1999
--------------------------------------------------------------
Current $ 291,000 $ 369,000 $ 104,000
Deferred 527,000 181,000 183,000
--------------------------------------------------------------
$ 818,000 $ 550,000 $ 287,000
==============================================================
|
The effective income tax rate differs from the U.S. Federal statutory income tax rate due to the following:
Years Ended October 31 2001 2000 1999
--------------------------------------------------------------
Federal statutory
income tax rate 34% 34% 34%
Effect of graduated tax rates - - 2
State income taxes 2 3 2
Percentage depletion (7) (8) (6)
-------------------------------------------------------------
29% 29% 32%
=============================================================
|
The principal sources of temporary differences resulting in deferred tax
assets and tax liabilities at
October 31, 2001 and 2000 are as follows:
October 31 2001 2000 --------------------------------------------------------------- Deferred tax assets: Gain on property sales $ 371,000 $ 408,000 --------------------------------------------------------------- Total deferred tax assets 371,000 408,000 --------------------------------------------------------------- Deferred tax liabilities: Intangible drilling, leasehold and other exploration costs capitalized for financial reporting purposes but deducted for tax purposes (2,133,000) (1,701,000) State taxes and other (173,000) (115,000) --------------------------------------------------------------- Total deferred tax liabilities (2,306,000) (1,816,000) --------------------------------------------------------------- Net deferred tax liability $(1,935,000) $(1,408,000) =============================================================== |
|
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 $275,000 has been
paid. The balance, which is due in eight remaining annual increments of
$105,000, is 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 2001 2000 1999 ----------------------------------------------------------------------- Unproved properties not being amortized $ 1,549,000 $ 1,601,000 $ 788,000 Properties being amortized 16,080,000 13,374,000 12,884,000 Accumulated depreciation, depletion and amortization (8,960,000) (8,240,000) (7,758,000) ----------------------------------------------------------------------- Total capitalized costs $ 8,669,000 $ 6,735,000 $ 5,914,000 ======================================================================= |
Acquisition, Exploration and Development Costs Incurred Years Ended October 31 2001 2000 1999 ----------------------------------------------------------------------- Property acquisition costs net of divestiture proceeds: Proved $ - $ - $ (594,000) Unproved 87,000 (315,000) 104,000 Exploration costs 2,481,000 1,289,000 227,000 Development costs 86,000 329,000 328,000 ----------------------------------------------------------------------- Net costs incurred $ 2,654,000 $ 1,303,000 $ 65,000 ======================================================================= |
|
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: Duke Energy 30% in 2001, 10% in 2000, and 25% in 1999; Enogex, Inc. 15% in 2001 and 11% in 2000; Ultramar Diamond Shamrock 5% in 2001, 15% in 2000 and 18% in 1999; GPM Gas Corporation 17% in 2000 and 17% in 1999. Oil and Gas Reserve Data (Unaudited) In 2001, 2000, and 1999, 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 $20.61, $31.82, and $21.01 per barrel for oil and $2.87, $4.33,
and $2.73 per Mcf for gas in 2001, 2000 and 1999, respectively. Estimated future
costs were calculated assuming continuation of costs and economic conditions at
the reporting date. |
2001 2000 1999
-------------------------------------------------------------------------------
Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls) Gas(Mcf) Oil(bbls)
-------------------------------------------------------------------------------
Proved reserves:
Balance, November 1 7,413,000 373,000 6,683,000 321,000 6,676,000 314,000
Revisions of
previous estimates 82,000 (9,000) 169,000 28,000 388,000 52,000
Extensions and
discoveries 2,404,000 5,000 1,206,000 63,000 977,000 1,000
Purchases of
reserves in place 22,000 5,000 36,000 - 6,000 -
Sales of reserves
in place - - (13,000) - (506,000) (7,000)
Production (800,000) (44,000) (668,000) (39,000) (858,000) (39,000)
-------------------------------------------------------------------------------
Balance, October 31 9,121,000 330,000 7,413,000 373,000 6,683,000 321,000
===============================================================================
Proved developed reserves:
Beginning of period 6,511,000 340,000 5,704,000 287,000 5,909,000 302,000
===============================================================================
End of period 8,249,000 296,000 6,511,000 340,000 5,704,000 287,000
===============================================================================
|
The standardized measure of discounted future net cash flows from reserves is
set forth below as of
October 31 of the indicated fiscal year.
2001 2000 1999 ----------------------------------------------------------------------------- Future cash inflows $32,952,000 $43,981,000 $24,960,000 Future production and development costs (11,109,000) (12,506,000) (8,707,000) Future income tax expense (4,589,000) (7,142,000) (3,186,000) ----------------------------------------------------------------------------- Future net cash flows 17,254,000 24,333,000 13,067,000 10% discount factor (6,294,000) (9,877,000) (5,143,000) ----------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $10,960,000 $14,456,000 $ 7,924,000 ============================================================================= |
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.
2001 2000 1999 ----------------------------------------------------------------------------- Balance, November 1 $14,456,000 $ 7,924,000 $ 6,250,000 Sales of oil and gas produced, net of production costs (4,028,000) (2,037,000) (1,509,000) Net changes in prices, production and development costs (8,661,000) 5,910,000 2,126,000 Extensions and discoveries, net of future development and production costs 4,132,000 3,194,000 1,272,000 Revisions of quantity estimates, timing, and other 1,883,000 964,000 1,198,000 Purchases of reserves in place 110,000 93,000 10,000 Sales of reserves in place - (34,000) (1,201,000) Accretion of discount 1,446,000 792,000 625,000 Net change in income taxes 1,622,000 (2,350,000) (847,0000) ----------------------------------------------------------------------------- Balance, October 31 $10,960,000 $14,456,000 $ 7,924,000 ============================================================================= |
|
INDEPENDENT AUDITORS' REPORT CREDO PETROLEUM CORPORATION AND SUBSIDIARIES The Board of Directors and Stockholders We have audited the accompanying consolidated balance sheets of CREDO Petroleum Corporation and subsidiaries as of October 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three year period ended October 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Denver, Colorado 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 2001. 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 2001. 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 2001. 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 2001. |
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.
|
3(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 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 (incorporated by reference to
Form 10-KSB dated October 31, 2000).
10(e) CREDO Petroleum Corporation 1997 Stock Option Plan,
as amended and restated effective October 25, 2001.
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.
|
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.
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 24, 2002
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 24, 2002 /s/ William N. Beach Director
-----------------------
William N. Beach
January 24, 2002 /s/ Clarence H. Brown Director
-----------------------
Clarence H. Brown
January 24, 2002 /s/ Oakley Hall Director
-----------------------
Oakley Hall
January 24, 2002 /s/ James T. Huffman Chairman of the
----------------------- Board, President,
James T. Huffman Treasurer
January 24, 2002 /s/ William F. Skewes Director,
----------------------- Corporate
William F. Skewes Secretary,
General Counsel
January 24, 2002 /s/ Richard B. Stevens Director
-----------------------
Richard B. Stevens
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©2000-2004 CREDO Petroleum Corporation. All rights reserved. |
