UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended July 31, 2010
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 0-8877
CREDO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
|
Delaware |
|
84-0772991 |
|
(State or other jurisdiction of incorporation or organization) |
|
(IRS Employer Identification No.) |
|
1801 Broadway, Suite 900, Denver, Colorado |
|
80202 |
|
(Address of principal executive offices) |
|
(Zip Code) |
303-297-2200
(Registrant’s telephone number, including area code)
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 o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-Y during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. (See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act.)
|
Large accelerated filer o |
|
Accelerated filer x |
|
|
|
|
|
Non-accelerated filer o |
|
Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, net of treasury stock, as of the latest practicable date.
|
Date |
|
Class |
|
Outstanding |
|
September 7, 2010 |
|
Common stock, $.10 par value |
|
10,099,000 |
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly Report on Form 10-Q For the Period Ended July 31, 2010
The terms “CREDO”, “Company”, “we”, “our”, and “us” refer to CREDO Petroleum Corporation and its subsidiaries unless the context suggests otherwise.
PART I - FINANCIAL INFORMATION
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
ASSETS
|
|
|
July 31, |
|
October 31, |
|
||
|
|
|
2010 |
|
2009 |
|
||
|
|
|
(Unaudited) |
|
|
|
||
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Current Assets: |
|
|
|
|
|
||
|
Cash and cash equivalents |
|
$ |
8,556,000 |
|
$ |
12,348,000 |
|
|
Short-term investments |
|
1,955,000 |
|
635,000 |
|
||
|
Receivables: |
|
|
|
|
|
||
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Accrued oil and gas sales |
|
1,640,000 |
|
1,566,000 |
|
||
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Trade |
|
296,000 |
|
487,000 |
|
||
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Derivative assets |
|
117,000 |
|
104,000 |
|
||
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Other current assets |
|
586,000 |
|
859,000 |
|
||
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Total current assets |
|
13,150,000 |
|
15,999,000 |
|
||
|
|
|
|
|
|
|
||
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Long-term Assets: |
|
|
|
|
|
||
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Oil and gas properties, at cost, using full cost method: |
|
|
|
|
|
||
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Unevaluated oil and gas properties |
|
9,086,000 |
|
7,363,000 |
|
||
|
Evaluated oil and gas properties |
|
80,503,000 |
|
76,127,000 |
|
||
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Less: accumulated depreciation, depletion and amortization of oil and gas properties |
|
(55,503,000 |
) |
(53,211,000 |
) |
||
|
Net oil and gas properties, at cost, using full cost method |
|
34,086,000 |
|
30,279,000 |
|
||
|
|
|
|
|
|
|
||
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Intangible Assets, net of accumulated amortization of $762,000 in 2010 and $436,000 in 2009 |
|
3,687,000 |
|
4,013,000 |
|
||
|
|
|
|
|
|
|
||
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Compressor and tubular inventory to be used in development |
|
2,064,000 |
|
1,865,000 |
|
||
|
|
|
|
|
|
|
||
|
Other, net |
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60,000 |
|
396,000 |
|
||
|
|
|
|
|
|
|
||
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Total Assets |
|
$ |
53,047,000 |
|
$ |
52,552,000 |
|
LIABILITIES AND STOCKHOLDERS‘ EQUITY
|
|
|
July 31, |
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October 31, |
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||
|
|
|
2010 |
|
2009 |
|
||
|
|
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(Unaudited) |
|
|
|
||
|
|
|
|
|
|
|
||
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Current Liabilities: |
|
|
|
|
|
||
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Accounts payable |
|
$ |
717,000 |
|
$ |
407,000 |
|
|
Revenue distribution payable |
|
712,000 |
|
653,000 |
|
||
|
Accrued compensation |
|
430,000 |
|
948,000 |
|
||
|
Other accrued liabilities |
|
222,000 |
|
394,000 |
|
||
|
Income taxes payable |
|
16,000 |
|
55,000 |
|
||
|
Total current liabilities |
|
2,097,000 |
|
2,457,000 |
|
||
|
|
|
|
|
|
|
||
|
Long Term Liabilities: |
|
|
|
|
|
||
|
Deferred income taxes, net |
|
3,105,000 |
|
2,537,000 |
|
||
|
Asset retirement obligation |
|
1,277,000 |
|
1,502,000 |
|
||
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Total liabilities |
|
6,479,000 |
|
6,496,000 |
|
||
|
|
|
|
|
|
|
||
|
Commitments: |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Stockholders’ Equity: |
|
|
|
|
|
||
|
Preferred stock, no par value, 5,000,000 shares authorized, none issued |
|
— |
|
— |
|
||
|
Common stock, $.10 par value, 20,000,000 shares authorized, 10,660,000 issued |
|
1,066,000 |
|
1,066,000 |
|
||
|
Capital in excess of par value |
|
31,528,000 |
|
31,472,000 |
|
||
|
Treasury stock at cost, 548,000 shares in 2010 and 419,000 in 2009 |
|
(4,144,000 |
) |
(2,803,000 |
) |
||
|
Retained earnings |
|
18,118,000 |
|
16,321,000 |
|
||
|
Total stockholders’ equity |
|
46,568,000 |
|
46,056,000 |
|
||
|
|
|
|
|
|
|
||
|
Total Liabilities and Stockholders’ Equity |
|
$ |
53,047,000 |
|
$ |
52,552,000 |
|
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
|
|
|
Nine Months Ended |
|
Three Months Ended |
|
||||||||
|
|
|
July 31, |
|
July 31, |
|
||||||||
|
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Oil sales |
|
$ |
5,252,000 |
|
$ |
4,142,000 |
|
$ |
1,722,000 |
|
$ |
2,024,000 |
|
|
Natural gas sales |
|
3,752,000 |
|
3,156,000 |
|
1,195,000 |
|
813,000 |
|
||||
|
|
|
9,004,000 |
|
7,298,000 |
|
2,917,000 |
|
2,837,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
||||
|
Oil and gas production |
|
2,480,000 |
|
2,394,000 |
|
822,000 |
|
771,000 |
|
||||
|
Depreciation, depletion and amortization |
|
2,648,000 |
|
3,499,000 |
|
925,000 |
|
960,000 |
|
||||
|
Write-down of oil and natural gas properties (Note 3) and impairment of long lived assets (Note 8) |
|
— |
|
24,653,000 |
|
— |
|
— |
|
||||
|
General and administrative |
|
1,629,000 |
|
1,953,000 |
|
510,000 |
|
564,000 |
|
||||
|
|
|
6,757,000 |
|
32,499,000 |
|
2,257,000 |
|
2,295,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Income (loss) from operations |
|
2,247,000 |
|
(25,201,000 |
) |
660,000 |
|
542,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
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Other income and (expense) |
|
|
|
|
|
|
|
|
|
||||
|
Realized and unrealized gains (losses) from derivative contracts |
|
66,000 |
|
1,911,000 |
|
39,000 |
|
(16,000 |
) |
||||
|
Investment and other income (loss) |
|
52,000 |
|
(66,000 |
) |
9,000 |
|
54,000 |
|
||||
|
|
|
118,000 |
|
1,845,000 |
|
48,000 |
|
38,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Income (loss) before income taxes |
|
2,365,000 |
|
(23,356,000 |
) |
708,000 |
|
580,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Income taxes |
|
(568,000 |
) |
9,108,000 |
|
(153,000 |
) |
(227,000 |
) |
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net income (loss) |
|
$ |
1,797,000 |
|
$ |
(14,248,000 |
) |
$ |
555,000 |
|
$ |
353,000 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Earnings (loss) per share of Common Stock-Basic |
|
$ |
0.18 |
|
$ |
(1.38 |
) |
$ |
0.06 |
|
$ |
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Earnings (Loss) Per Share Of Common Stock-Diluted |
|
$ |
0.18 |
|
$ |
(1.38 |
) |
$ |
0.06 |
|
$ |
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Weighted average number of shares of Common Stock and dilutive securities: |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
10,179,000 |
|
10,341,000 |
|
10,146,000 |
|
10,305,000 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Diluted |
|
10,200,000 |
|
10,341,000 |
|
10,151,000 |
|
10,333,000 |
|
||||
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
|
|
|
Nine Months Ended |
|
||||
|
|
|
July 31, |
|
||||
|
|
|
2010 |
|
2009 |
|
||
|
Cash flows from operating activities: |
|
|
|
|
|
||
|
Net income (loss) |
|
$ |
1,797,000 |
|
$ |
(14,248,000 |
) |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
||
|
Write-down of oil and natural gas properties and impairment of long lived assets |
|
— |
|
24,653,000 |
|
||
|
Depreciation, depletion and amortization |
|
2,648,000 |
|
3,499,000 |
|
||
|
ARO liability accretion |
|
59,000 |
|
85,000 |
|
||
|
Unrealized (gains) loss on derivative instruments |
|
(13,000 |
) |
1,046,000 |
|
||
|
Deferred income taxes |
|
568,000 |
|
(9,159,000 |
) |
||
|
Loss on short term investments |
|
(14,000 |
) |
65,000 |
|
||
|
Compensation expense related to stock options granted |
|
56,000 |
|
24,000 |
|
||
|
Other |
|
— |
|
(5,000 |
) |
||
|
Changes in operating assets and liabilities: |
|
|
|
|
|
||
|
Proceeds from short-term investments |
|
194,000 |
|
2,292,000 |
|
||
|
Purchase of short-term investments |
|
(1,500,000 |
) |
— |
|
||
|
Accrued oil and gas sales |
|
(74,000 |
) |
473,000 |
|
||
|
Trade receivables |
|
191,000 |
|
597,000 |
|
||
|
Other current assets |
|
273,000 |
|
(123,000 |
) |
||
|
Accounts payable and accrued liabilities |
|
(690,000 |
) |
(1,103,000 |
) |
||
|
Income taxes payable |
|
(39,000 |
) |
47,000 |
|
||
|
|
|
|
|
|
|
||
|
Net cash provided by operating activities |
|
3,456,000 |
|
8,143,000 |
|
||
|
|
|
|
|
|
|
||
|
Cash flows from investing activities: |
|
|
|
|
|
||
|
Additions to oil and gas properties |
|
(6,100,000 |
) |
(11,299,000 |
) |
||
|
Proceeds from sale of oil and gas properties |
|
86,000 |
|
— |
|
||
|
Changes in other long-term assets |
|
107,000 |
|
(54,000 |
) |
||
|
Purchase intangible assets |
|
— |
|
(4,400,000 |
) |
||
|
|
|
|
|
|
|
||
|
Net cash used in investing activities |
|
(5,907,000 |
) |
(15,753,000 |
) |
||
|
|
|
|
|
|
|
||
|
Cash flows from financing activities: |
|
|
|
|
|
||
|
Purchase of treasury stock |
|
(1,638,000 |
) |
(1,232,000 |
) |
||
|
Proceeds from exercise of stock options |
|
297,000 |
|
— |
|
||
|
|
|
|
|
|
|
||
|
Net cash used in financing activities |
|
(1,341,000 |
) |
(1,232,000 |
) |
||
|
|
|
|
|
|
|
||
|
Decrease in cash and cash equivalents |
|
(3,792,000 |
) |
(8,842,000 |
) |
||
|
|
|
|
|
|
|
||
|
Cash and cash equivalents: |
|
|
|
|
|
||
|
Beginning of period |
|
12,348,000 |
|
22,332,000 |
|
||
|
|
|
|
|
|
|
||
|
End of period |
|
$ |
8,556,000 |
|
$ |
13,490,000 |
|
|
|
|
|
|
|
|
||
|
Additions to oil and gas properties in current liabilities |
|
$ |
384,000 |
|
$ |
390,000 |
|
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To Consolidated Financial Statements (Unaudited)
July 31, 2010
1. BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been prepared in accordance with U. S. generally accepted accounting principles for interim financial information and with the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U. S. generally accepted accounting principles for complete financial statements. In the opinion of management, the consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the company’s results for the periods presented. For a more complete understanding of the company’s financial condition and accounting policies, these consolidated financial statements should be read in conjunction with the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2009. The results for interim periods are not necessarily indicative of annual results.
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 at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.
2. CONCENTRATION OF CREDIT RISK
Credo’s accounts receivable are primarily from purchasers of the company’s oil and natural gas production and from other exploration and production companies which own joint working interests in the properties that the company operates. This industry concentration could adversely impact the company’s overall credit risk, because the company’s customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices, and other conditions. Credo’s oil and gas production is sold to various purchasers in accordance with the company’s credit policies and procedures. These policies and procedures take into account, among other things, the creditworthiness of potential purchasers and concentrations of credit risk. For most joint working interest partners, the company has the right of offset against related oil and natural gas revenues.
3. OIL AND NATURAL GAS PROPERTIES
Depreciation, depletion and amortization of oil and natural gas properties for the nine months ended July 31, 2010 and 2009 were $2,292,000 and $3,100,000 respectively, and were $807,000 and $838,000 for the three months ended July 31, 2010 and 2009, respectively. The company uses the full cost method of accounting for costs related to its oil and natural gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Costs for unevaluated properties, which typically include lease rentals, geology and seismic costs, are capitalized but are excluded from the amortizable pool during the evaluation period. When determinations are made whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are reclassified to the full cost pool.
The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. The ceiling test is calculated using oil and natural gas prices in effect as of the balance sheet date. If such capitalized costs exceed the ceiling, the company will record a write-down to the extent of such excess as a non-cash charge to earnings, unless the company considers price increases subsequent to the balance sheet date which may reduce or eliminate a write-down. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.
At July 31, 2010 the estimated present value of future net revenues from proved reserves, net of related income tax considerations, exceeded the capitalized costs of the company’s oil and natural gas properties. Therefore, a ceiling test write-down was not required. For the nine months ended July 31, 2009, the company recorded ceiling test write-downs of $23,726,000.
Changes in oil and natural gas prices have historically had the most significant impact on the company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and natural gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the company’s reserves by the company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the test period. See Footnote 12. for description of new SEC rules which Credo will adopt, effective October 31, 2010.
4. STOCK-BASED COMPENSATION
For the nine months ended July 31, 2010 and 2009, the company recognized stock based compensation expense of $56,000 and $24,000 respectively. For the three months ended July 31, 2010 and 2009, the company recognized stock based compensation expense of $22,000 and $8,000, respectively. The estimated unrecognized compensation cost from unvested stock options as of July 31, 2010 was approximately $149,000 which is expected to be recognized over an average of 2.5 years.
No options were granted during fiscal year 2009. The fair value of the 50,000 options granted during the nine months ended July 31, 2010 was estimated as of the grant date using the Black-Scholes option pricing model with the following assumptions: volatility, 51.6%; expected option term, 3 years; risk-free interest rate, 2.69% and; expected dividend yield, 0%. If option grants are made in the future, compensation expense for all such share-based payments granted, based upon the grant-date fair value estimate will also be included in compensation expense.
Plan activity for the nine months ended July 31, 2010 is set forth below:
|
|
|
|
|
Weighted |
|
|
|
||
|
|
|
|
|
Average |
|
Aggregate |
|
||
|
|
|
Number of |
|
Exercise |
|
Intrinsic |
|
||
|
|
|
Options |
|
Price |
|
Value |
|
||
|
Outstanding at October 31, 2009 |
|
179,063 |
|
$ |
7.46 |
|
$ |
530,000 |
|
|
Granted |
|
50,000 |
|
9.30 |
|
— |
|
||
|
Exercised |
|
(50,000 |
) |
5.93 |
|
— |
|
||
|
Cancelled or forfeited |
|
— |
|
— |
|
— |
|
||
|
Outstanding at July 31, 2010 |
|
179,063 |
|
$ |
8.40 |
|
$ |
158,000 |
|
|
|
|
|
|
|
|
|
|
||
|
Exercisable at July 31, 2010 |
|
124,063 |
|
$ |
7.86 |
|
$ |
158,000 |
|
|
|
|
|
|
|
|
|
|
||
|
Weighted average contractual life at July 31, 2010 |
|
|
|
5.48 |
years |
|
|
||
|
|
|
Outstanding |
|
Exercisable |
|
||||||||
|
|
|
Number |
|
Weighted Average |
|
Weighted |
|
Number |
|
|
|
||
|
Range of |
|
Outstanding |
|
Remaining |
|
Average |
|
Exercisable at |
|
Weighted |
|
||
|
Exercise |
|
at July 31, |
|
Contractual |
|
Exercise |
|
July 31, |
|
Average |
|
||
|
Prices |
|
2010 |
|
Life in Years |
|
Price |
|
2010 |
|
Exercise Price |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$ 5.93 |
|
89,063 |
|
2.87 |
|
$ |
5.93 |
|
89,063 |
|
$ |
5.93 |
|
|
$ 9.30 |
|
50,000 |
|
9.42 |
|
9.30 |
|
— |
|
9.30 |
|
||
|
$12.78 |
|
40,000 |
|
6.35 |
|
$ |
12.78 |
|
35,000 |
|
$ |
12.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$ 5.93 -$12.78 |
|
179,063 |
|
5.48 |
|
$ |
8.40 |
|
124,063 |
|
$ |
7.86 |
|
5. OIL AND NATURAL GAS DERIVATIVES
The company is exposed to certain commodity price risks relating to its ongoing operations. The company periodically uses derivatives as economic hedges of the price of a portion of its estimated production when the potential for significant downward price movement is anticipated. These transactions typically take the form of costless collars for oil and forward short positions based upon the NYMEX futures market for natural gas, and are closed by purchasing offsetting positions. Such contracts do not exceed estimated production volumes and are authorized by the company’s Board of Directors. Contracts 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.
For the nine months ended July 31, 2010 and 2009, the company had realized gains on derivatives of $53,000 and $2,957,000 respectively, and unrealized gains (losses) of $13,000 and ($1,046,000) respectively. For the quarter ended July 31, 2010 and 2009 the company had realized gains on derivatives of $49,000 and $682,000 respectively, and unrealized losses of $11,000 and $698,000, respectively.
At July 31, 2010 the company held open derivative contracts representing natural gas short sales positions for 180,000 MMBtus at NYMEX basis prices ranging from $5.55 to $7.27 and covering the production months of August 2010 through December 2010. The company also held open offsetting derivative contracts with the same counterparty for 160,000 MMBtus at NYMEX basis prices ranging from $5.44 to $5.83 and covering the production months of August 2010 through December 2010. These positions are presented net due to the contractual netting provisions with the counterparty. The open derivative contracts net to 20,000 MMBtus with a net unrealized gain of $110,000 at July 31, 2010. Average natural gas prices received in the company’s primary market have historically been 15% - 17% below NYMEX prices due to basis differentials compared to the current differentials of about 10%.
At July 31, 2010 the company also held natural gas basis differential hedges on 200,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of August 2010 through December 2010. These open basis differential contracts represent unrealized gains of $3,000 at July 31, 2010.
Subsequent to July 31, the August and September natural gas related derivative contracts closed, resulting in realized derivative gains of $59,210.
At July 31, 2010 the company also held costless collar derivative contracts for 3,000 barrels of oil for the production months of August through October 2010, priced at NYMEX WTI $75.00 floor and $95.00 ceiling. There were no realized gains or losses on these derivatives for the three or six months ended July 31, 2010. Unrealized gains (losses) on oil derivative contracts were $4,000 and ($8,000) for the three and nine month periods ended July 31, 2010. There were no oil hedges in 2009. Subsequent to July 31, the August contract closed with no realized gain or loss on the transaction.
The company has a hedging line of credit with its bank which is available, at the discretion of the company, to meet margin calls. To date, the company has not used this facility and maintains it only as a precaution related to possible margin calls. The maximum credit line available is $7,200,000 with interest calculated at the prime rate. The facility is unsecured and has covenants that require the company to maintain $3,000,000 in cash or short term investments, none of which are required to be maintained at the company’s bank, and prohibits funded debt in excess of $500,000. The line expires May 1, 2013.
The company has elected not to designate its commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at fair value on the balance sheet and changes in fair value are recorded in the statement of operations as they occur. The location and amount of derivative fair values and related gain (loss) are indicated in the following tables.
Derivatives not designated as hedging instruments:
|
|
|
As of July 31, 2010 |
|
|||
|
|
|
Balance Sheet Location |
|
Fair Value |
|
|
|
Natural Gas Forward Positions |
|
Derivative Asset |
|
$ |
110,000 |
|
|
Natural Gas Basis Positions |
|
Derivative Asset |
|
3,000 |
|
|
|
Crude Oil Collars |
|
Derivative Asset |
|
4,000 |
|
|
Amount of Gain or (Loss) Recognized in Income on Derivatives:
Derivatives not designated as hedging instruments:
|
|
|
Location of Gain/(Loss) |
|
Nine Months |
|
|
|
|
|
Recognized in |
|
Ended |
|
|
|
|
|
Income on Derivatives |
|
July 31, 2010 |
|
|
|
Natural Gas Forward Positions |
|
Other Income and (Expense) |
|
$ |
85,000 |
|
|
Natural Gas Basis Positions |
|
Other Income and (Expense) |
|
(24,000 |
) |
|
|
Crude Oil Collars |
|
Other Income and (Expense) |
|
5,000 |
|
|
6. EARNINGS PER SHARE
The company’s calculation of earnings (loss) per share of common stock is as follows:
|
|
|
Nine Months Ended July 31, |
|
||||||||||||||
|
|
|
2010 |
|
2009 |
|
||||||||||||
|
|
|
|
|
|
|
Net |
|
|
|
|
|
Net |
|
||||
|
|
|
Net |
|
|
|
Income |
|
Net |
|
|
|
(Loss) |
|
||||
|
|
|
Income |
|
Shares |
|
Per Share |
|
(Loss) |
|
Shares |
|
Per Share |
|
||||
|
Basic earnings (loss) per share |
|
$ |
1,797,000 |
|
10,179,000 |
|
$ |
0.18 |
|
$ |
(14,248,000 |
) |
10,341,000 |
|
$ |
(1.38 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Effect of dilutive shares of common stock from stock options |
|
— |
|
21,000 |
|
— |
|
— |
|
— |
|
— |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Diluted earnings (loss) per share |
|
$ |
1,797,000 |
|
10,200,000 |
|
$ |
0.18 |
|
$ |
(14,248,000 |
) |
10,341,000 |
|
$ |
(1.38 |
) |
|
|
|
Three Months Ended July 31, |
|
||||||||||||||
|
|
|
2010 |
|
2009 |
|
||||||||||||
|
|
|
|
|
|
|
Net |
|
|
|
|
|
Net |
|
||||
|
|
|
Net |
|
|
|
Income |
|
Net |
|
|
|
Income |
|
||||
|
|
|
Income |
|
Shares |
|
Per Share |
|
Income |
|
Shares |
|
Per Share |
|
||||
|
Basic earnings per share |
|
$ |
555,000 |
|
10,146,000 |
|
$ |
.06 |
|
$ |
353,000 |
|
10,305,000 |
|
$ |
.03 |
|
|
Effect of dilutive shares of common stock from stock options |
|
— |
|
5,000 |
|
— |
|
— |
|
28,000 |
|
— |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Diluted earnings per share |
|
$ |
555,000 |
|
10,151,000 |
|
$ |
.06 |
|
$ |
353,000 |
|
10,333,000 |
|
$ |
.03 |
|
The company’s outstanding options were not included in the calculation of diluted income (loss) per share for the nine month period ended July 31, 2009 as their inclusion would have an antidilutive effect.
7. INCOME TAXES
The company uses 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 effective tax rate varies from the statutory rate primarily due to utilization of percent depletion deductions.
The total future deferred income tax liability is complicated for any energy 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.
As of July 31, 2010, the company remains subject to examination of its 2006 and 2008 Federal and 2006 through 2008 state tax returns, except Colorado, in which the 2005 tax year also remains open.
8. INTANGIBLE ASSETS
The company owns all of the patents underlying the Calliope Gas Recovery Technology and patents covering a new fluid lift technology for shallow wells known as Tractor Seal. The patents are being amortized on a straight line basis over the remaining lives ranging from 6.9 to 16.2 years.
|
|
|
July 31, 2010 |
|
||||
|
|
|
Gross Carrying |
|
Accumulated |
|
||
|
|
|
Amount |
|
Amortization |
|
||
|
Amortized intangible assets: |
|
|
|
|
|
||
|
Calliope intangible assets |
|
$ |
4,449,000 |
|
$ |
762,000 |
|
|
|
|
|
|
|
|
||
|
Aggregate amortization expense: |
|
|
|
|
|
||
|
For the nine months ended July 31, 2010 |
|
|
|
$ |
326,000 |
|
|
The company reviews the value of its intangible assets for impairment whenever events or changes in business circumstances indicate that the carrying amount of the assets may not be fully recoverable or that the useful lives of these assets are no longer appropriate. For the nine months ended July 31, 2009, the company recorded a non-cash impairment expense of $926,000 related to other intangible assets.
9. FAIR VALUE MEASUREMENTS
The company utilizes derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. These derivatives are carried at fair value on the consolidated balance sheets. Additionally, the company’s short-term investments consist partially of professionally managed limited partnerships which include investments that are not publicly traded and may have less readily determinable market values. Accounting standards established a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows:
· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.
· Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
· Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.
The classification of financial assets or liabilities within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The determination of the fair values below incorporates various factors required under fair value accounting guidance, including the impact of the counterparty’s non-performance risk with respect to the company’s financial assets and the company’s non-performance risk with respect to the company’s financial liabilities. The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of July 31, 2010:
|
|
|
As of July 31, 2010 |
|
||||||||||
|
|
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
|
|
|
(in thousands) |
|
||||||||||
|
Asset: |
|
|
|
|
|
|
|
|
|
||||
|
Short-term investments |
|
$ |
1,816 |
|
$ |
— |
|
$ |
139 |
|
$ |
1,955 |
|
|
Derivative asset |
|
$ |
— |
|
$ |
117 |
|
$ |
— |
|
$ |
117 |
|
Level 3 instruments are comprised of the company’s investments in professionally managed limited partnerships. The fair value represents the net asset value of the company’s share in each partnership. The
company identified the investments as Level 3 instruments due to the fact that quoted prices for the underlying investments in the partnerships cannot be obtained and there is not an active market for the underlying investments or the partnerships shares. The company utilizes periodic fund statements along with current fund redemption activity and communication with investment advisors to determine the valuation of its investment.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three and nine months ended July 31, 2010:
|
|
|
Three Months |
|
Nine Months |
|
||
|
|
|
Ended |
|
Ended |
|
||
|
|
|
July 31, 2010 |
|
July 31, 2010 |
|
||
|
|
|
(in thousands) |
|
||||
|
|
|
|
|
|
|
||
|
Balance as of April 30, 2010 and October 31, 2009, respectively(1) |
|
$ |
235 |
|
$ |
342 |
|
|
Total gains (losses): |
|
|
|
|
|
||
|
Included in earnings(2) |
|
3 |
|
(9 |
) |
||
|
Additions |
|
— |
|
— |
|
||
|
Redemptions |
|
(99 |
) |
(194 |
) |
||
|
Balance as of July 31, 2010(1) |
|
$ |
139 |
|
$ |
139 |
|
(1) This amount is included in short-term investments on the balance sheet.
(2) This amount is included in investment and other income (loss) on the statement of operations.
10. COMMON STOCK
On September 22, 2008, the company’s Board of Directors authorized a stock repurchase program. Under the program, the company could acquire up to $2,000,000 of its common stock. On April 9, 2009, the Board authorized expanding the repurchase program to $4,000,000 and on July 29, 2010 the program was expanded to $5,000.000. The repurchases may be made on the open market, in block trades or otherwise. The stock repurchase program may be expanded, suspended or discontinued at any time. During the quarter ended July 31, 2010, the company acquired 63,767 shares of its common stock at an aggregate cost of $524,000. For the nine months ended July 31, 2010, the company acquired 179,202 shares of its common stock at an aggregate cost of $1,638,000. A total of 474,636 shares have been repurchased under the program at an average price per share of $8.81. Subsequent to July 31, 2010 through September 9, 2010, 13,000 shares have been acquired at an average cost per share of $7.88.
11. COMMITMENTS AND CONTINGENCIES
The company was named as a defendant in a lawsuit alleging breach of contract, and other issues, arising in the normal course of its oil and gas activities. The suit was settled August 11, 2010 at a cost of $25,000 to Credo.
The company has also been named as a defendant in a lawsuit brought by a former employee. The suit alleges breach of contract and other employment issues. Although the company believes the allegations are without merit and that the company will ultimately prevail, the ultimate outcome of this lawsuit cannot be determined at this time.
The company has no material outstanding commitments at July 31, 2010.
12. RECENT ACCOUNTING PRONOUNCEMENTS
In February 2010, the FASB issued authoritative guidance that eliminated the requirement to disclose the date through which management evaluated subsequent events in the financial statements. Such subsequent events must still be evaluated by management through the date that financial statements are issued. The new guidance was effective immediately and the company adopted the guidance for financial statements issued subsequent to February 24, 2010. There was no impact on the company’s financial position or results of operations as a result of the adoption.
In January 2010, the FASB issued authoritative guidance titled “Improving Disclosures about Fair Value Measurements.” This guidance amends existing authoritative guidance to require additional disclosures regarding fair value measurements, including the amounts and reasons for significant transfers between Level 1 and Level 2 of the fair value hierarchy, the reasons for any transfers into or out of Level 3 of the fair value hierarchy, and presentation on a gross basis of information regarding purchases, sales, issuances, and settlements within the Level 3 rollforward. This guidance also clarifies certain existing disclosure requirements. The guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements within the Level 3 rollforward, which are effective for interim and annual reporting periods beginning after December 15, 2010. The adoption of this authoritative guidance had no impact on our financial position or results of operations.
In December 2008, the Securities and Exchange Commission (“SEC”) adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure of probable and possible reserves; allow the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing the reserves estimates or conducting a reserves audit; require the filing of the independent reserve engineers’ summary report; and permit the disclosure of a reserves sensitivity analysis table to illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 (October 31, 2010 for the company) with early adoption prohibited. The company is currently evaluating the impact that the adoption of these amendments will have on the company’s financial position, results of operations, and disclosures. In January 2010, the Financial Accounting Standards Board (“FASB”) issued oil and gas reserve estimation and disclosure authoritative accounting guidance effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s (“SEC”) final rule. The new FASB guidance includes changes to pricing used to estimate oil and gas reserves, broaden the types of technologies that a company may use to establish oil and gas reserves estimates, and broaden the definition of oil and gas producing activities to include the extraction of non-traditional resources.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q, other than statements of historical facts, address matters that the company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:
· the company’s future financial position, including working capital and anticipated cash flow;
· amounts and nature of future capital expenditures;
· operating costs and other expenses;
· wells to be drilled or reworked;
· oil and natural gas prices and demand;
· existing fields, wells and prospects;
· diversification of exploration;
· estimates of proved oil and natural gas reserves;
· reserve potential;
· development and drilling potential;
· expansion and other development trends in the oil and natural gas industry;
· the company’s business strategy;
· production of oil and natural gas;
· matters related to the Calliope Gas Recovery System;
· effects of federal, state and local regulation;
· insurance coverage;
· employee relations;
· investment strategy and risk; and
· expansion and growth of the company’s business and operations.
LIQUIDITY AND CAPITAL RESOURCES
At July 31, 2010, working capital was $11,053,000 compared to $13,542,000 at October 31, 2009. For the nine months ended July 31, 2010, net cash provided by operating activities was $3,456,000 compared to $8,143,000 for the same period in 2009. The principle difference resulted from transfers between cash and short term investments. Income before taxes increased $25,720,000 primarily due to impairment losses of $24,653,000 in 2009, an increase in revenue of $1,706,000 and decreased other costs and expenses of $1,089,000 in 2010.
For the nine months ended July 31, 2010 and 2009, net cash used in investing activities was $5,907,000 and $15,753,000, respectively. Investing activities primarily included oil and gas exploration and development expenditures, including Calliope, totaling $6,100,000 and $11,299,000 respectively.
Existing working capital and anticipated cash flow are expected to be sufficient to fund operations and capital commitments for at least the next 12 months. At July 31, 2010, the company had no lines of credit or other bank financing arrangements except for the hedging line of credit discussed in Note 5. Because earnings are anticipated to be reinvested in operations, cash dividends are not expected to be paid. The company has no defined benefit plans and no obligations for post retirement employee benefits.
The company’s adjusted earnings before interest, taxes, depreciation, depletion and amortization, including impairment losses, (“EBITDA”) was $5,012,000 for the nine months ended July 31, 2010 compared to $4,769,000 for the nine months ended July 31, 2009. EBITDA is not a GAAP measure of operating performance. The company uses this non-GAAP performance measure primarily to compare its performance with other companies in the industry that make a similar disclosure. The company believes that this performance measure may also be useful to investors for the same purpose. Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the company’s operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between EBITDA and net income is provided in the table below:
|
|
|
Nine Months Ended July 31, |
|
||||
|
|
|
2010 |
|
2009 |
|
||
|
RECONCILIATION OF EBITDA: |
|
|
|
|
|
||
|
Net Income (loss) |
|
$ |
1,797,000 |
|
$ |
(14,248,000 |
) |
|
Add Back (Deduct): |
|
|
|
|
|
||
|
Income Tax Expense (Benefit) |
|
567,000 |
|
(9,108,000 |
) |
||
|
Depreciation, Depletion and Amortization Expense Including Write-Down and Impairment |
|
2,648,000 |
|
28,152,000 |
|
||
|
EBITDA |
|
$ |
5,012,000 |
|
$ |
4,796,000 |
|
OFF-BALANCE SHEET FINANCING
The company has no off-balance sheet arrangements at July 31, 2010.
PRODUCT PRICES AND PRODUCTION
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 the price of a portion of its estimated natural gas production when the potential for significant downward price movement is anticipated. Hedging transactions typically take the form of forward short positions, swaps and collars which are executed on the NYMEX futures market or by indexing to regional index prices associated with pipelines in proximity to the company’s production. The company’s current hedges are indexed to NYMEX, except basis hedges which are over the counter.
The oil and natural gas average sales prices reflected in the table below excludes the effects of commodity derivative instruments. See Note 5 of the Notes to Consolidated Financial Statements and comments at “Results of Operations for more information on gains and losses relating to commodity derivative instruments.
|
|
|
Nine Months Ended July 31, |
|
||||||||||||
|
|
|
2010 |
|
2009 |
|
% Change |
|
||||||||
|
Product |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Oil (bbls) |
|
73,600 |
|
$ |
71.35 |
|
90,500 |
|
$ |
45.77 |
|
- 19 |
% |
+ 56 |
% |
|
Gas (Mcf) |
|
783,000 |
|
$ |
4.79 |
|
940,000 |
|
$ |
3.36 |
|
- 17 |
% |
+ 43 |
% |
|
BOE (Barrels of Oil Equivalent) |
|
204,000 |
|
$ |
44.12 |
|
247,200 |
|
$ |
29.52 |
|
- 17 |
% |
+ 49 |
% |
|
|
|
Three Months Ended July 31, |
|
||||||||||||
|
|
|
2010 |
|
2009 |
|
% Change |
|
||||||||
|
Product |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
Volume |
|
Price |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Oil (bbls) |
|
25,000 |
|
$ |
68.66 |
|
35,500 |
|
$ |
56.98 |
|
- 29 |
% |
+ 21 |
% |
|
Gas (Mcf) |
|
260,000 |
|
$ |
4.60 |
|
293,000 |
|
$ |
2.75 |
|
- 11 |
% |
+ 67 |
% |
|
BOE (Barrels of Oil Equivalent) |
|
68,400 |
|
$ |
42.64 |
|
84,300 |
|
$ |
33.63 |
|
- 19 |
% |
+ 27 |
% |
The effect of realized derivative gains and losses on total price realizations are reflected in the following table:
|
|
|
Nine Months Ended July 31, |
|
||||||||||||||||
|
|
|
2010 |
|
2009 |
|
||||||||||||||
|
|
|
Net |
|
Realized |
|
Effective |
|
Net |
|
Realized |
|
Effective |
|
||||||
|
|
|
Wellhead |
|
Derivative |
|
Price |
|
Wellhead |
|
Derivative |
|
Price |
|
||||||
|
Product |
|
Price |
|
Gain |
|
Realization |
|
Price |
|
Gain |
|
Realization |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Oil |
|
$ |
71.35 |
|
$ |
— |
|
$ |
71.35 |
|
$ |
45.77 |
|
$ |
— |
|
$ |
45.77 |
|
|
Gas |
|
$ |
4.79 |
|
$ |
0.07 |
|
$ |
4.86 |
|
$ |
3.36 |
|
$ |
3.14 |
|
$ |
6.50 |
|
|
|
|
Three Months Ended July 31, |
|
||||||||||||||||
|
|
|
2010 |
|
2009 |
|
||||||||||||||
|
|
|
Net |
|
Realized |
|
Effective |
|
Net |
|
Realized |
|
Effective |
|
||||||
|
|
|
Wellhead |
|
Derivative |
|
Price |
|
Wellhead |
|
Derivative |
|
Price |
|
||||||
|
Product |
|
Price |
|
Gain |
|
Realization |
|
Price |
|
Gain |
|
Realization |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Oil |
|
$ |
68.66 |
|
$ |
— |
|
$ |
68.66 |
|
$ |
56.98 |
|
$ |
— |
|
$ |
56.98 |
|
|
Gas |
|
$ |
4.60 |
|
$ |
0.19 |
|
$ |
4.79 |
|
$ |
2.75 |
|
$ |
2.33 |
|
$ |
5.08 |
|
OPERATIONS
During the first nine months of fiscal 2010, the company’s operations have focused on two principle projects — oil drilling in the North Dakota Bakken shale play and in central Kansas.
The company believes that, in combination, its drilling and Calliope projects provide an excellent (and possibly unique) balance for achieving its goal of adding long-lived reserves and production at reasonable costs and risks. However, it should be expected that successful results will occur unevenly for both the drilling and Calliope projects. Drilling results are dependent on both the timing of drilling and on the drilling success rate. Calliope results are primarily dependent on the timing, volume and quality of Calliope installations available to the company.
The company will continue to actively pursue adding reserves through its two core projects in fiscal 2010, and expects these activities to be a reliable source of reserve additions. However, the timing and extent of such activities can be dependent on many factors which are beyond the company’s control, including but not limited to, the cost and quality of oil field services such as drilling rigs, production equipment and related services, and access to wells for application of the company’s patented gas recovery system on low pressure gas wells. The prevailing price of oil and natural gas has a significant effect on demand and, thus, the related cost of such services and wells.
In recent years, the company has significantly expanded both the volume and breadth of its drilling activities with new projects in central Kansas and North Dakota’s Williston Basin (Bakken Shale). Compared to drilling in Oklahoma, the North Dakota projects involve higher costs and greater risks but
significantly higher per well reserve potential. In contrast, drilling in central Kansas is less expensive than the company’s Oklahoma drilling projects while still yielding excellent economics.
All of the company’s oil and natural gas properties are located on-shore in the continental United States. The company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the company’s results of operations and financial condition. Also, the company may not be able to obtain the right to drill in areas where it believes there is significant potential for the company.
Recent Drilling Activities.
Bakken Shale — At July 31, 2010, the company’s first Bakken horizontal well, the Petro Hunt 148-94-17D-08-1H (“17-D”), located on the Fort Berthold Reservation, has been on production for approximately six months and is continuing to flow without artificial lift. Through the first six months the well flowed 57,000 Boe. Credo owns a 10% working interest.
Credo’s second horizontal Bakken well, also on the Fort Berthold Reservation, commenced drilling in May and has reached TD. The 147-94-3A-10-1H (“3-A”) well was drilled on a 1,280 acre spacing unit located about four miles southeast of the 17-D. The 3-A well is operated by Petro-Hunt and is awaiting completion. Credo owns an 18.75% working interest.
Credo has leased approximately 8,000 gross (6,000 net) acres on the Ft. Berthold Reservation containing about 50 drillable spacing units. The company’s interests range up to 51% depending on the size of the spacing unit. It is expected that more than one well will be drilled on many spacing units.
In Williams County, North Dakota, Credo’s third horizontal Bakken well has been drilled and is awaiting completion. The Brigham Exploration Weisz 11-14#1-H (“Weisz”) is located on a 1,280 acre spacing unit about one mile east of Brigham’s Olson 10-15-H well which has produced 126,000 Boe in 18 months. Credo owns a 6% working interest and, based on Brigham’s exploration plan for the area, expects up to three Bakken wells to be drilled in the spacing unit and potentially three additional wells to develop the deeper Sanish/Three Forks formation. The company’s acreage is generally located south and west of Parshall Field and is in the vicinity of several recently announced significant Bakken discoveries. The Reservation is surrounded on three sides by horizontal Bakken production, and drilling activity on the Reservation is escalating rapidly.
Central Kansas Uplift — Last year, Credo discovered a significant new field in Barton County, Kansas (the Huslig Field) in which it owns an 85% working interest. That field has produced over 110,000 barrels of oil in about 18 months. Credo is continuing an aggressive prospect generation and lease acquisition program. The company has significantly increased its acreage holdings on the Central Kansas Uplift and western Kansas, and currently owns 147,000 gross (85,000 net) acres. The acreage contains 34 blocks in which the company owns interests ranging from 12.5% to 100%.
To date, Credo has drilled 63 wells on its Central Kansas Uplift acreage, of which 41% have been successful. The company is currently drilling two to three wells per month and expects to maintain that pace for the next few years.
Calliope Gas Recovery Technology
Calliope Gas Recovery System — The company is continuing to actively discuss commercial Calliope terms with several companies. We have demonstrated that Calliope will perform as advertised. Credo has previously published statistics on its Calliope wells which show finding costs of about $0.50 per Mcf and total costs to deliver gas into the pipeline of about $1.00 per Mcf. The statistics also show that Calliope is
very low risk when installed on suitable wells.
Calliope’s low finding and production costs have become increasingly attractive as the economics on many industry drilling projects deteriorate due to lower product prices. We also believe that lower natural gas prices may stimulate divestitures of marginal properties by other companies, including properties that have Calliope potential.
Results of Operations
Nine Months Ended July 31, 2010 Compared to Nine Months Ended July 31, 2009
For the nine months ended July 31, 2010, oil and gas revenues increased 23% to $9,004,000 compared to $7,298,000 during the same period last year. As the oil and gas price/volume table on page 16 shows, oil sales prices increased 56% to $71.35 per barrel and natural gas sales prices increased 43% to $4.79 per Mcf. The net effect of these price changes was to increase oil and gas sales by $3,666,000. On an energy equivalency basis (six Mcf equals one barrel of oil), for the first nine months production was down 17% primarily due to the impact of flush oil production last year from the company’s Huslig Field discovery. For the period, oil production was down 19% and natural gas production was down 17%. This resulted in an oil and gas sales decrease of $1,960,000 for the nine months ended July 31, 2010.
For the nine months ended July 31, 2010, total costs and expenses, excluding the impairment loss of $24,653,000 in 2009, decreased 14% to $6,757,000 compared to $7,846,000 for the comparable period in 2009. Oil and gas production expenses increased due to additional wells, offset by reduced field level expenses. DD&A decreased primarily due to the effects of the 2009 impairment write-down. General and administrative expenses decreased primarily due to legal and professional fees and decreased salaries and benefits. The effective tax rate was 24% and 39% for the 2010 and 2009 periods, respectively.
Three Months Ended July 31, 2010 Compared to Three Months Ended July 31, 2009
For the three months ended July 31, 2010, oil and gas sales revenues increased 3% to $2,917,000 compared to $2,837,000 during the same period last year. As the oil and gas price/volume table on page 17 shows, oil prices increased 21% to $68.66 per barrel and natural gas sales prices increased 67% to $4.60 per Mcf. The net effect of these price changes was to increase oil and gas sales by $948,000. For the third quarter, total production was down 19%, calculated on the energy equivalency basis due to flush production from the Huslig Field discovery last year and suspension of drilling for natural gas. For the period, oil production was down 29% and natural gas production was down 11%. The company has concentrated on oil drilling in Central Kansas and North Dakota during 2010 and has not drilled for gas due to low natural gas prices. This production decline resulted in an oil and gas sales decrease of $868,000 for the quarter ended July 31, 2010.
For the three months ended July 31, 2010, total costs and expenses fell 2% to $2,258,000 compared to $2,295,000 for the comparable period in 2009. Oil and gas production expenses increased 7% due to additional wells, partially offset by decreased field level costs. Depreciation, depletion and amortization (DD&A) decreased primarily due to the effects of the 2009 impairment write-down. General and administrative expenses decreased primarily due to legal and professional fees. The effective tax rate was 22% and 39% for the 2010 and 2009 periods, respectively.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated production through the use of derivatives, typically costless collars for oil and forward short positions in the NYMEX Oklahoma natural gas futures market. At July 31, 2010 the company held open natural gas derivative contracts representing short sales positions for 180,000 MMBtus at NYMEX basis
prices ranging from $5.55 to $7.27 and covering the production months of August 2010 through December 2010. The company also held open natural gas derivative contracts with the same counterparty representing long positions for 160,000 MMBtus at NYMEX basis prices ranging from $5.44 to $5.83 and covering the production months of August 2010 through December 2010. These positions are presented net due to the contractual netting provisions with the counterparty. The open derivative contracts net to 20,000 MMBtus with a net unrealized gain of $110,000 at July 31, 2010. Average prices in the company’s primary market are currently 10% below NYMEX prices due to basis differentials and transportation costs. However, regional weather conditions and other economic factors can periodically result in substantially higher basis differentials.
At July 31, 2010 the company also held basis differential hedges on 200,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47 and covering the production months of August 2010 through December 2010. These open basis differential contracts represent unrealized gains of $3,000 at July 31, 2010.
At July 31, 2010 the company also held costless collar derivative contracts for 3,000 barrels of oil for the production months of August through October 2010, priced at NYMEX WTI $75.00 floor and $95.00 ceiling. There were no realized gains or losses on these derivatives for the three or six months ended July 31, 2010. Unrealized gains (losses) on oil derivative contracts were $4,000 and ($8,000) for the three and nine month periods ended July 31, 2010. There were no oil hedges in 2009. Subsequent to July 31, the August contract closed with no realized gain or loss on the transaction.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, with the participation of Marlis E. Smith, Jr., our Chief Executive Officer, and Alford B. Neely, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of July 31, 2010. Based on the evaluation, these officers have concluded that:
Our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and
Our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
There has not been any change in our internal control over financial reporting that occurred during the quarter ended July 31, 2010 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.
Reference is made to “Notes to Consolidated Financial Statements (Unaudited) — Note 11, Commitments and Contingencies”, in Part I, Item I of this Form 10-Q and incorporated by reference into this Part II, Item I.
There have been no material changes from the risk factors previously disclosed in the company’s Annual Report on Form 10-K for the fiscal year ended October 31, 2009.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities.
During the first nine months of fiscal year 2010, the company repurchased 179,202 shares of its common stock on the open market at a weighted average price of $9.14. The purchases were made pursuant to a stock repurchase plan announced on September 24, 2008 and extended by the Board of Directors on April 9, 2009 and July 29, 2010. The extended plan authorized repurchases up to $5,000,000, but could be expanded, suspended or discontinued at any time. At July 31, 2010, the company has repurchased 474,636 shares of common stock at an average price per share of $8.81. Subsequent to July 31, 2010, and through September 9, 2010, the company has repurchased 13,327 shares, bringing the total shares repurchased to 487,963 at an average price per share of $8.74.
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
Total number |
|
Maximum |
|
||
|
|
|
|
|
|
|
of shares |
|
dollar value |
|
||
|
|
|
|
|
|
|
purchased |
|
of shares |
|
||
|
|
|
|
|
|
|
as part of |
|
that may yet |
|
||
|
|
|
Total number of |
|
Average price |
|
publicly |
|
be purchased |
|
||
|
Period |
|
shares purchased |
|
paid per share |
|
announced plan |
|
under the plan |
|
||
|
|
|
|
|
|
|
|
|
|
|
||
|
November 1, 2008 – October 31, 2009 |
|
295,434 |
|
$ |
8.61 |
|
295,434 |
|
$ |
1,456,000 |
|
|
November 1 – 30, 2009 |
|
40,937 |
|
$ |
10.19 |
|
40,937 |
|
$ |
1,039,000 |
|
|
December 1 – 31, 2009 |
|
— |
|
$ |
— |
|
— |
|
$ |
1,039,000 |
|
|
January 1 – 31, 2010 |
|
26,520 |
|
$ |
9.38 |
|
26,520 |
|
$ |
790,000 |
|
|
February 1 – 28, 2010 |
|
23,800 |
|
$ |
8.87 |
|
23,800 |
|
$ |
579,000 |
|
|
March 1-31, 2010 |
|
7,800 |
|
$ |
9.73 |
|
7,800 |
|
$ |
503,000 |
|
|
April 1 – 30, 2010 |
|
16,378 |
|
$ |
9.84 |
|
16,378 |
|
$ |
342,000 |
|
|
May 1 – 30, 2010 |
|
18,600 |
|
$ |
9.24 |
|
18,600 |
|
$ |
170,000 |
|
|
June 1 – 30, 2010 |
|
21,167 |
|
$ |
8.02 |
|
21,167 |
|
$ |
— |
|
|
July 1 – 31, 2010 |
|
24,000 |
|
$ |
7.59 |
|
24,000 |
|
$ |
818,000 |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Total |
|
474,636 |
|
$ |
8.81 |
|
474,636 |
|
$ |
818,000 |
|
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
None.
Exhibits are as follow:
31.1 Certification by Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2 Certification by Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002
32.1 Certification by Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)
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.
|
|
CREDO Petroleum Corporation |
|
|
|
(Registrant) |
|
|
|
|
|
|
|
|
|
|
|
By: |
/s/ Marlis E. Smith, Jr. |
|
|
|
Marlis E. Smith, Jr. |
|
|
|
Chief Executive Officer |
|
|
|
(Principal Executive Officer) |
|
|
|
|
|
|
By: |
/s/ Alford B. Neely |
|
|
|
Alford B. Neely |
|
|
|
Chief Financial Officer |
|
|
|
(Principal Financial and Accounting Officer) |
|
|
|
|
|
|
|
|
|
Date: September 7, 2010 |
|
|