[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934.
Colorado 84-0772991
(State of Incorporation) (IRS Employer Identification)
1801 Broadway, Suite 900 80202
Denver, Colorado (Zip Code)
(Address of principal executive office)
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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
Indicate the number of shares outstanding of each of the issuer's classes of common stock, net of treasury stock, as of August 31, 2000: Common stock, $.10 par value - 2,979,000
Preferred stock, no par value - None issued
Consolidated Balance Sheets
As of July 31, 2000 (Unaudited) and October 31, 1999
Consolidated Statements of Earnings and Changes in Retained Earnings (Unaudited) For the Nine and Three Month Periods Ended July 31, 2000 and 1999
Consolidated Statements of Cash Flows (Unaudited) For the Nine Month Periods Ended July 31, 2000 and 1999
Management's Discussion and Analysis of Financial Condition and Results of Operations
Not Applicable
The financial information furnished in this Form 10-QSB reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial position of the company for the periods presented.
CREDO PETROLEUM CORPORATION
Consolidated Balance Sheets
A S S E T S
July 31, October 31,
2000 1999
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(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents $ 246,000 $ 184,000
Short term investments 5,017,000 4,055,000
Receivables:
Trade 364,000 443,000
Accrued oil and gas sales 483,000 362,000
Other 59,000 77,000
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6,169,000 5,121,000
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OIL AND GAS PROPERTIES, net, at cost,
full cost method:
Unevaluated 1,011,000 788,000
Evaluated 5,046,000 5,126,000
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6,057,000 5,914,000
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OTHER, net 78,000 43,000
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$12,304,000 $11,078,000
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L I A B I L I T I E S A N D S T O C K H O L D E R S '
E Q U I T Y
CURRENT LIABILITIES:
Accounts payable $ 729,000 $ 739,000
Income taxes payable 246,000 147,000
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975,000 886,000
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DEFERRED INCOME TAXES 1,359,000 1,227,000
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COMMITMENTS ___________ ___________
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STOCKHOLDERS' EQUITY:
Preferred stock, without
par value 5,000,000 shares
authorized, none issued - -
Common stock, $.10 par value,
20,000,000 shares authorized,
3,678,000 shares issued 367,000 367,000
Capital in excess of par value 6,235,000 6,235,000
Retained earnings 4,583,000 3,578,000
Treasury stock, at cost, 699,000
shares in 2000 and 1999 (1,215,000) (1,215,000)
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9,970,000 8,965,000
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$12,304,000 $11,078,000
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See accompanying notes.
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CREDO PETROLEUM CORPORATION
Consolidated Statements of Earnings And Changes in
Retained Earnings - Unaudited
Nine Months Nine Months Quarter Quarter
Ended Ended Ended Ended
July 31, July 31, July 31, July 31
2000 1999 2000 1999
----------- ----------- ----------- -----------
REVENUES:
Oil and gas sales $ 2,100,000 $ 1,799,000 $ 784,000 $ 554,000
Operating 316,000 322,000 104,000 105,000
Investment income
and other 399,000 296,000 54,000 51,000
Non-recurring
litigation settlement 345,000 - - -
----------- ----------- ----------- -----------
3,160,000 2,417,000 942,000 710,000
----------- ----------- ----------- -----------
COSTS AND EXPENSES:
Oil and gas production 680,000 591,000 246,000 210,000
Depreciation, depletion
and amortization 434,000 664,000 146,000 183,000
General and
administrative 610,000 550,000 167,000 161,000
----------- ----------- ----------- -----------
1,724,000 1 ,805,000 559,000 554,000
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INCOME BEFORE
INCOME TAXES 1,436,000 612,000 383,000 156,000
INCOME TAXES (431,000) (214,000) (94,000) (54,000)
----------- ----------- ----------- -----------
NET INCOME 1,005,000 398,000 289,000 102,000
RETAINED EARNINGS,
BEGINNING OF PERIOD 3,578,000 2,967,000 4,294,000 3,263,000
----------- ----------- ----------- -----------
RETAINED EARNINGS,
END OF PERIOD $ 4,583,000 $ 3,365,000 $ 4,583,000 $ 3,365,000
=========== =========== =========== ===========
BASIC NET INCOME
PER SHARE $ .34 $ .13 $ .10 $ .03
=========== =========== =========== ===========
DILUTED NET INCOME
PER SHARE $ .32 $ .13 $ .09 $ .03
=========== =========== =========== ===========
See accompanying notes.
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CREDO PETROLEUM CORPORATION
Consolidated Statements of Cash Flows - Unaudited
Nine Months Ended
July 31,
--------------------------
2000 1999
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OPERATING ACTIVITIES:
Net income $ 1,005,000 $ 398,000
Noncash expenses included in net income:
Depreciation, depletion and amortization 434,000 664,000
Deferred income taxes 132,000 214,000
Other 28,000 9,000
Changes in operating assets and liabilities:
Proceeds from short term investments 1,261,000 1,906,000
Purchase of short term investments (2,223,000) (2,885,000)
Trade receivables 79,000 (69,000)
Accrued oil and gas sales (121,000) (48,000)
Other 18,000 -
Accounts payable (10,000) 506,000
Income tax payable 99,000 (133,000)
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NET CASH PROVIDED BY OPERATING ACTIVITIES 702,000 562,000
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INVESTING ACTIVITIES:
Oil and gas properties, net (577,000) (486,000)
Changes in long-term assets (63,000) (15,000)
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NET CASH USED IN INVESTING ACTIVITIES (640,000) (501,000)
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FINANCING ACTIVITIES:
Purchase of treasury stock - (95,000)
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NET CASH USED IN FINANCING ACTIVITIES - (95,000)
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INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 62,000 (34,000)
CASH AND CASH EQUIVALENTS:
Beginning of Period 184,000 349,000
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End of Period $ 246,000 $ 315,000
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See accompanying notes.
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Management's Discussion and Analysis of Financial
Condition and Results of Operations
July 31, 2000
LIQUIDITY AND CAPITAL RESOURCES
The company's working capital and cash flow represent a significant capital resource and source of liquidity. At third quarter end, working capital was $5,194,000, up 29% from the fiscal year ended October 31, 1999. Cash flow from operating activities before working capital changes totaled $1,599,000 for the nine months, up 24% from the same period last year. Cash flow was used to fund oil and gas property expenditures totaling $1,095,000, before $518,000 of property sales proceeds. Excess cash flow is reflected in the increase in working capital.
Existing working capital and anticipated cash flow are expected to be sufficient to fund fiscal 2000 operations. However, if the company were to make one or more major acquisition during the coming year, bank borrowing, issuance of additional stock, or other forms of debt financing would be considered. 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 third quarter-end. The timing of most capital expenditures for exploration and development is relatively discretionary. Therefore, the company can plan expenditures to coincide with available funds in order to minimize business risks.
PRODUCT PRICES, PRODUCTION AND OPERATIONS
Numerous uncertainties exist in the oil and gas exploration and production industry which are beyond the company's ability to predict with reasonable accuracy.
Gas price decontrol, the advent of an active spot market for natural gas, and increased energy commodity market trading have resulted in gas prices received by the company being subject to significant monthly fluctuations. Gas prices generally accelerate in peak demand periods such as the winter months and subside during lower demand periods.
Uncertainties also exist with respect to the supply of oil available to world markets. OPEC and other major foreign producers exercise considerable influence over the worldwide oil supply which in turn affects prices for petroleum products.
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. 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 and gains or losses recognized for financial reporting purposes as related production occurs. However, hedges 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.
The company's present natural gas hedge covers the months of August 2000 through October 2000. At July 31, 2000, open hedge positions totaled 60,000 Mcfg (thousand cubic feet gas) at an average price of $3.01 per Mcf and represented approximately 35% of expected natural gas production for the months of August through October 2000.
Hedging losses of $48,000 are included in oil and gas income for the three and nine month periods ended July 31, 2000. The company had hedging losses of $35,000 for the third quarter 1999 and hedging gains of $167,000 for the nine months ended July 31, 1999. At July 31, 2000, hedging losses related to futures contract months beyond third quarter-end (August through October) have been deferred and will be recognized as the related production occurs. These losses totaled $45,000 of which $14,000 are realized and $31,000 are unrealized. Current natural gas prices are continuing to be above the company's $3.01 average hedge price as fundamentals have steadily improved. Accordingly, the company expects to realize a significant hedging loss on the remaining portion of the hedge which should be offset by increased cash market prices expected to be received by the company.
Oil and gas sales volume and price comparisons for the indicated periods are set forth below.
Nine Months Nine Months
Ended July 31, 2000 Ended July 31, 1999 Percent Percent
------------------- ------------------- Volume Price
Product Volume Price Volume Price Change Change
------- ------- ------- ------- ------- ------- -------
Gas (Mcf) 511,800 $ 2.62(1) 650,900 $ 2.12(2) - 21% + 24%
Oil (bbls) 28,400 $26.72 29,400 $14.21 - 3% + 88%
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Three Months Three Months
Ended July 31, 2000 Ended July 31, 1999 Percent Percent
------------------- ------------------- Volume Price
Product Volume Price Volume Price Change Change
------- ------- ------ ------- ------ ------- -------
Gas (Mcf) 166,400 $ 3.09(3) 197,400 $ 1.88(4) - 16% + 64%
Oil (bbls) 9,300 $28.90 10,200 $17.97 - 9% + 61%
(1) Includes $.09 Mcf hedging loss.
(2) Includes $.26 Mcf hedging gain.
(3) Includes $.29 Mcf hedging loss.
(4) Includes $.18 Mcf hedging loss.
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The decline in fiscal 2000 oil and gas production for the nine month and three month periods compared to the same periods last year primarily reflects the sale of the Tracy Federal #1 well and a steep (but expected) production decline on the Cline #11-1 well, both as discussed below.
During the fourth quarter of fiscal 1999, the company sold its 78% interest in the Tracy Federal #1 well for $487,000. The well accounted for 9% and 7%, respectively, of the company's gas production for the three and nine month periods ended July 31, 1999. At the time of the sale, the well was producing approximately 300 Mcfgd. The sale was precipitated by declining production rates and concern that the wellbore was loading-up' with fluids which could not be efficiently removed due to the well's depth, its remote location, and pipeline restraints. Proved reserves attributed to the well at the time of sale were 455,000 Mcfg and 6,000 barrels of oil. Sale proceeds were recorded as a reduction to oil and gas property costs.
During fiscal 1999, the Cline #11-1 was the company's largest producing well accounting for 28% of gas production for both the three and nine month periods ended July 31, 1999. Production from the well declined steeply and accounted for only 3% and 7%, respectively, of the company's gas production for the comparable three and nine month periods ended July 31, 2000. Of four productive Morrow sands in the wellbore, only the Basal Morrow sand was opened for production due to mechanical issues related to completing all four sands at the same time. In the area, the Basal Morrow sand is generally wet', but in the Cline #11-1 well it was slightly above the gas/water contact and had excellent porosity and permeability. The Basal Morrow sand produced high volumes of gas but pressures depleted rapidly indicating a limited gas reservoir above the water contact. It was, therefore, expected that the Basal Morrow zone would have a limited life, and as anticipated, it watered out' and was abandoned during the third quarter of 1999. It produced over
1.10 Bcfg and 6,700 barrels of oil in about 26 months. Three additional Morrow zones located above the Basal Morrow sand are currently being completed for production. Combined estimated reserves and production from the upper sands are expected to exceed those of the Basal sand, however, the upper sands are not as porous and, thus, are expected to produce at significantly lower rates than the Basal sand. The company owns 49% of the well and is the operator.
Lower fiscal 2000 gas production resulting from the rapid production decline from the Basal Morrow sand in the Cline #11-1 well and sale of the Tracy Federal #1 well (both described above) was partially offset by new wells added which accounted for 20% and 25% of the company's gas production for the three and nine month periods ended July 31, 2000, respectively. One such well, the J. C. Carroll #1, on which the company installed the patented fluid lift technology discussed below, is presently the company's largest producing well accounting for 13% and 18% of the company's gas production for the three and nine month periods ended July 31, 2000, respectively. The well is currently producing 600 to 630 Mcfgd. The Carroll well was expected to contribute a greater percentage of production in the nine month period, however, it was down approximately two and a half months due to down-hole pressure control problems related to down-hole valves being cut by sand produced from the Morrow formation. After several attempts, the company successfully modified the valves, and the well has produced since late February 2000 without recurrence of the problem. Estimated reserves attributed to the well are 1.5 Bcfge of which the company's share is 886,000 Mcfge. The well has a very limited operating history using the new fluid lift technology, and accordingly, production levels and reserve estimates must be viewed as being subject to significant change as more data about the well becomes available. The company owns a 75% working interest and a 60% net revenue interest in the J. C. Carroll well and is the operator.
As previously reported, the company participated in developing new fluid lift technology for low-pressure (significantly depleted) gas reservoirs. This patented technology employs down-hole pressure differentials to efficiently lift fluids from the wellbores. Among other things, removing the fluids from the wellbore reduces the hydrostatic pressure against the formation thereby allowing gas to flow into the wellbore. The technology is most effective in wells deeper than 10,000 feet where conventional fluid lift systems lose efficiency. The technology is installed on a total of five wells, including the J. C. Carroll well discussed above, with depths ranging from 6,500 to 12,000 feet. All but one have equaled or exceeded expectations. The J. C. Carroll well ranks as the company's largest producing well while another application ranks as the company's fourth largest well.
During the third fiscal quarter 2000, in an attempt to significantly extend the operating limits of the Technology, the company installed it on an 18,600-foot well located in Oklahoma. The Technology operated successfully lifting approximately 20 barrels of water per day to the surface. However analysis of the water indicated that it was from an up-hole casing leak. The company elected to expose the casing to the producing formation based on results of a casing integrity test that proved to be inaccurate. Had the casing integrity test provided accurate information about the condition of the casing, the problem would have been avoided. The Technology has been removed in order to perform remedial work on the well. Remedial work consists of isolating the casing leak (which has been done), and then reperforating and acidizing the Hunton formation to attempt to re-establish communication between the wellbore and the formation. If that work is successful, the Technology will be reinstalled on the well. If it is not successful, the well will be abandoned and the Technology will be removed to another well.
Three additional installations or expected to be completed on 12,000 foot, or deeper, wells during the next six to eight months. The company believes that the technology will prove to be a cost effective, low risk, and repeatable means to significantly increase its gas production and reserves.
During fiscal 1999 and the first quarter of fiscal 2000, the company participated in a significant wildcat drilling program to develop coal bed methane (CBM) reserves on its 13,000 gross acre (1,253 net acre) Sheridan Prospect located on the west side of Wyoming's Powder River Basin. Approximately 100 wells were drilled on the prospect. The company estimated that its share of drilling and infrastructure (gathering, electricity, water disposal, etc.) costs incurred was $600,000 to $700,000. There has been no significant production from the prospect, and the company's share of total costs to fully develop the prospect ranged up to $3,000,000. During the second quarter of fiscal 2000, the company sold its remaining interest in the Sheridan Prospect for approximately $375,000 plus assumption by the buyer of all drilling and infrastructure costs incurred by the company from inception of the project. The company also retained a small overriding royalty interest in the prospect. Sales proceeds were recorded as a reduction in oil and gas property costs.
The company also owns 17,000 gross (3,900 net) acres of CBM leases located on the eastern side of the Powder River Basin, including the 5,000 gross acre Recluse Prospect in which the company owns a 10% interest. Approximately 20 wells have been drilled on the Recluse Prospect that have been logged and are awaiting completion for production. Logs indicate that the prospect area contains productive coals. Production testing and pipeline connection are expected during the fourth quarter of fiscal 2000.
INCOME TAXES
The company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), which requires 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. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.
The total future deferred income tax liability under SFAS 109 is extremely complicated for any oil company to estimate due in part to the long-lived nature of depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.
RESULTS OF OPERATIONS
Nine Months Ended July 31, 2000 Compared to Nine Months Ended July 31, 1999
For the nine months ended July 31, 2000, net income increased 153% to $1,005,000 compared to $398,000 for the same period last year.
Total revenues increased 31% to $3,160,000 for the nine months ended July 31, 2000 compared to $2,417,000 last year. Oil and gas sales increased $301,000, or 17%, to $2,100,000. Refer to the table and discussion on pages 7 and 8 for details of oil and gas prices and volumes for the applicable periods. Total gas price realizations rose 24% to $2.62 per Mcf compared to $2.12 last year. Hedging transactions decreased 2000 price realizations by $.09 per Mcf, or 3% compared to an increase in 1999 price realizations from hedging transactions of $.26 per Mcf, or 14%. Net wellhead prices for gas increased 46% to $2.71 per Mcf compared to $1.86 last year. Net wellhead oil price realizations increased 88% to $26.72 per barrel compared to $14.21 last year. The net effect of these price changes, including hedging transactions, was to increase oil and gas sales $705,000. Gas volumes declined 21% and oil volumes declined 3%. The net effect of volume changes was to reduce oil and gas sales by $404,000. Operating income was slightly lower due to sale of several marginal operated properties. Investment income increased 35% due to a substantial increase in funds invested. An Illinois trust company in which the company deposited funds to be managed by a professional money manager recently filed bankruptcy due to a theft of funds by a related company. The trust company's assets were approximately $2.0 billion and it had approximately 20,000 customer accounts. The loss is approximately $68 million representing about 3.5% of the trust company's assets. The trust company served only as a conduit and accounting service for the company's funds which were immediately transferred to a major brokerage house. The court has allowed continued investment of the company's funds by its money manager. The company has filed motions to be excluded from the loss allocation. Due to uncertainties related to this matter and the company's conviction that its account should be excluded from any loss allocation, the company has not reserved for any potential loss. The company currently believes that its maximum exposure to loss allocation is approximately $75,000.
Non-recurring litigation settlement income of $345,000 ($241,000 after tax) resulted from settlement of a lawsuit related to investment losses incurred by the company in 1990.
Total costs and expenses were $1,724,000 for the nine months ended July 31, 2000 compared to $1,805,000 last year. General and administrative expenses rose 11% due to inflationary pressures, additional staffing and the timing of certain expenditures. Depreciation, depletion and amortization fell 35% primarily due to proceeds from sale of certain oil and gas properties reducing the property amortization base, certain operating rights becoming fully amortized during fiscal 1999, and lower gas production volumes in fiscal 2000 compared to fiscal 1999. The 15% increase in oil and gas production expenses primarily reflects increased production taxes on higher oil and gas revenues and costs associated with timing of workovers and repairs. Income taxes were provided at 30% in fiscal year 2000 and 35% in the prior year. The tax rate reduction is based in part on actual tax rates for the prior fiscal year which were determined when the final tax return was filed.
Quarter Ended July 31, 2000 Compared to Quarter Ended July 31, 1999
Net income for the quarter ended July 31, 2000 increased 183% to $289,000 compared to $102,000 for the same quarter last year.
Total revenues increased 33% to $942,000 in the third quarter of 2000. Oil and gas sales increased 42% to $784,000. Refer to the table and discussion on pages 7 and 8 for details of oil and gas prices and volumes for the applicable periods. Total gas price realizations rose 64% to $3.09 per Mcf compared to $1.88 last year. Hedging transactions decreased third quarter 2000 price realizations by $.29 per Mcf, or 9%, compared to a decrease in 1999 price realizations from hedging transactions of $.18 per Mcf, or 7%. Net wellhead prices for gas increased 64% to $3.38 per Mcf compared to $2.06 last year. Net wellhead oil price realizations increased 61% to $28.90 per barrel compared to $17.97 last year. The net effect of these price changes and hedging transactions was to increase oil and gas sales $343,000. Gas volumes declined 16% and oil volumes declined 9%. The net effect of volume changes was to reduce oil and gas sales by $113,000. Operating income did not vary significantly between the periods. Investment income increased 6% due to an increase in funds invested.
Total costs and expenses were $559,000 in the third quarter of 2000 compared to $554,000 last year. General and administrative expenses rose 4% due to inflationary pressures, additional staffing and the timing of certain expenditures. Depreciation, depletion and amortization fell 20% primarily due to proceeds from sale of certain oil and gas properties reducing the property amortization base and lower gas production in fiscal 2000 compared to fiscal 1999. The 17% increase in oil and gas production expenses primarily reflects increased production taxes on higher oil and gas sales revenue. Income taxes were provided at 25% in the third quarter of fiscal 2000 and 35% in 1999. The tax rate reduction is based in part on actual tax rates for the prior fiscal year which were determined when the final tax return was filed.
Pursuant to the requirements 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.
Date: September 12, 2000 By: /s/ James T. Huffman -------------------------- James T. Huffman President and Chief Executive Officer By: /s/ John A. Alsko -------------------------- John A. Alsko Vice President and Chief Financial Officer |
©2000-2004 CREDO Petroleum Corporation. All rights reserved. |
