Table of Contents
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 April 30,
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
(Registrants 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-T (§232.405 of this chapter) 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
|
(Do not check if a smaller reporting company)
|
|
|
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 issuers
classes of common stock, net of treasury
stock, as of the latest practicable date.
Date
|
|
Class
|
|
Outstanding
|
|
June 9,
2010
|
|
Common stock, $.10 par value
|
|
10,157,000
|
|
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Quarterly
Report on Form 10-Q For the Period Ended April 30, 2010
TABLE OF
CONTENTS
The terms CREDO, Company, we, our, and us refer to CREDO
Petroleum Corporation and its subsidiaries unless the context suggests
otherwise.
2
Table
of Contents
PART I - FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Balance Sheets
ASSETS
|
|
April 30,
|
|
October 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
Current Assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
10,079,000
|
|
$
|
12,348,000
|
|
Short-term investments
|
|
2,050,000
|
|
635,000
|
|
Receivables:
|
|
|
|
|
|
Accrued oil and gas sales
|
|
1,544,000
|
|
1,566,000
|
|
Trade
|
|
186,000
|
|
487,000
|
|
Derivative assets
|
|
206,000
|
|
104,000
|
|
Other current assets
|
|
651,000
|
|
859,000
|
|
Total current assets
|
|
14,716,000
|
|
15,999,000
|
|
|
|
|
|
|
|
Long-term Assets:
|
|
|
|
|
|
Oil and gas properties, at cost, using full cost
method:
|
|
|
|
|
|
Unevaluated oil and gas properties
|
|
8,875,000
|
|
7,363,000
|
|
Evaluated oil and gas properties
|
|
78,318,000
|
|
76,127,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(54,697,000
|
)
|
(53,211,000
|
)
|
Net oil and gas properties, at cost, using full cost
method
|
|
32,496,000
|
|
30,279,000
|
|
|
|
|
|
|
|
Intangible
Assets, net of accumulated amortization of $653,000 in 2010 and $436,000 in
2009
|
|
3,796,000
|
|
4,013,000
|
|
|
|
|
|
|
|
Compressor and tubular inventory to be used in
development
|
|
1,956,000
|
|
1,865,000
|
|
|
|
|
|
|
|
Other, net
|
|
402,000
|
|
396,000
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
53,366,000
|
|
$
|
52,552,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
3
Table of Contents
LIABILITIES AND STOCKHOLDERS
EQUITY
|
|
April 30,
|
|
October 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
751,000
|
|
$
|
407,000
|
|
Revenue distribution
payable
|
|
912,000
|
|
653,000
|
|
Accrued compensation
|
|
467,000
|
|
948,000
|
|
Other accrued liabilities
|
|
263,000
|
|
394,000
|
|
Derivative liability
|
|
78,000
|
|
|
|
Income taxes payable
|
|
67,000
|
|
55,000
|
|
Total current liabilities
|
|
2,538,000
|
|
2,457,000
|
|
|
|
|
|
|
|
Long Term Liabilities:
|
|
|
|
|
|
Deferred income taxes, net
|
|
2,902,000
|
|
2,537,000
|
|
Asset retirement obligation
|
|
1,411,000
|
|
1,502,000
|
|
Total liabilities
|
|
6,851,000
|
|
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
|
|
31,506,000
|
|
31,472,000
|
|
Treasury stock at cost, 485,000 shares in 2010 and
419,000 in 2009
|
|
(3,620,000
|
)
|
(2,803,000
|
)
|
Retained earnings
|
|
17,563,000
|
|
16,321,000
|
|
Total stockholders equity
|
|
46,515,000
|
|
46,056,000
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
53,366,000
|
|
$
|
52,552,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
4
Table
of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Operations
(Unaudited)
|
|
Six Months Ended
|
|
Three Months Ended
|
|
|
|
April 30,
|
|
April 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
3,530,000
|
|
$
|
2,118,000
|
|
$
|
1,806,000
|
|
$
|
1,496,000
|
|
Natural gas sale
s
|
|
2,557,000
|
|
2,343,000
|
|
1,139,000
|
|
857,000
|
|
|
|
6,087,000
|
|
4,461,000
|
|
2,945,000
|
|
2,353,000
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
1,658,000
|
|
1,623,000
|
|
802,000
|
|
737,000
|
|
Depreciation, depletion
and amortization
|
|
1,723,000
|
|
2,540,000
|
|
858,000
|
|
1,203,000
|
|
Write-down of oil and natural gas properties (Note
3) and impairment of long lived assets (Note 8)
|
|
|
|
24,652,000
|
|
|
|
8,030,000
|
|
General and administrative
|
|
1,119,000
|
|
1,389,000
|
|
577,000
|
|
521,000
|
|
|
|
4,500,000
|
|
30,204,000
|
|
2,237,000
|
|
10,491,000
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
1,587,000
|
|
(25,743,000
|
)
|
708,000
|
|
(8,138,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Other income and (expense)
|
|
|
|
|
|
|
|
|
|
Realized and unrealized gains from derivative
contracts
|
|
27,000
|
|
1,927,000
|
|
41,000
|
|
461,000
|
|
|
|
|
|
|
|
|
|
|
|
Investment and other income (loss)
|
|
43,000
|
|
(120,000
|
)
|
44,000
|
|
22,000
|
|
|
|
70,000
|
|
1,807,000
|
|
85,000
|
|
483,000
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes
|
|
1,657,000
|
|
(23,936,000
|
)
|
793,000
|
|
(7,655,000
|
)
|
Income taxes
|
|
(415,000
|
)
|
9,335,000
|
|
(190,000
|
)
|
2,945,000
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,242,000
|
|
$
|
(14,601,000
|
)
|
$
|
603
,000
|
|
$
|
(4,710,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share of
Common StockBasic
|
|
$
|
.12
|
|
$
|
(1.41
|
)
|
$
|
.06
|
|
$
|
(.46
|
)
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share of
Common StockDiluted
|
|
$
|
.12
|
|
$
|
(1.41
|
)
|
$
|
.06
|
|
$
|
(.46
|
)
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares of Common Stock
and dilutive securities:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
10,140,000
|
|
10,358,000
|
|
10,187,000
|
|
10,330,000
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
10,179,000
|
|
10,358,000
|
|
10,205,000
|
|
10,330,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
5
Table of Contents
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Six Months Ended
|
|
|
|
April 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,242,000
|
|
$
|
(14,601,000
|
)
|
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
|
|
|
|
24,652,000
|
|
Depreciation, depletion and amortization
|
|
1,723,000
|
|
2,540,000
|
|
ARO liability accretion
|
|
39,000
|
|
38,000
|
|
Unrealized (gain) loss on derivative instruments
|
|
(24,000
|
)
|
348,000
|
|
Deferred income taxes
|
|
365,000
|
|
(9,335,000
|
)
|
(Gain) loss on short term investments
|
|
(11,000
|
)
|
208,000
|
|
Compensation expense related to stock options
granted
|
|
34,000
|
|
16,000
|
|
Other
|
|
|
|
27,000
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
Purchase of short term investments
|
|
(1,500,000
|
)
|
|
|
Proceeds from short-term investments
|
|
96,000
|
|
975,000
|
|
Accrued oil and gas sales
|
|
22,000
|
|
(167,000
|
)
|
Trade receivables
|
|
301,000
|
|
465,000
|
|
Other current assets
|
|
208,000
|
|
(177,000
|
)
|
Accounts payable and accrued liabilities
|
|
(363,000
|
)
|
(981,000
|
)
|
Income taxes payable
|
|
12,000
|
|
(1,000
|
)
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
2,144,000
|
|
4,007,000
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
Additions to oil and gas properties
|
|
(3,565,000
|
)
|
(10,368,000
|
)
|
Proceeds from sale of oil and gas properties
|
|
86,000
|
|
|
|
Changes in other long-term assets
|
|
(117,000
|
)
|
(41,000
|
)
|
Purchase intangible assets
|
|
|
|
(4,400,000
|
)
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
(3,596,000
|
)
|
(14,809,000
|
)
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
Purchase of treasury stock
|
|
(1,114,000
|
)
|
(1,152,000
|
)
|
Proceeds from exercise of stock options
|
|
297,000
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing
activities
|
|
(817,000
|
)
|
(1,152,000
|
)
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
(2,269,000
|
)
|
(11,954,000
|
)
|
|
|
|
|
|
|
Cash and cash equivalents:
|
|
|
|
|
|
Beginning of period
|
|
12,348,000
|
|
22,332,000
|
|
|
|
|
|
|
|
End of period
|
|
$
|
10,079,000
|
|
$
|
10,378,000
|
|
The accompanying
notes are an integral part of these consolidated financial statements.
6
Table of Contents
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
Notes To
Consolidated Financial Statements (Unaudited)
April 30, 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 companys results for the periods
presented. For a more complete
understanding of the companys financial condition and accounting policies,
these consolidated financial statements should be read in conjunction with the
companys 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
Credos
accounts receivable are primarily from purchasers of the companys 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 companys overall credit risk because the companys
customers and working interest owners may be similarly affected by changes in
economic and financial market conditions, commodity prices, and other
conditions. Credos oil and gas
production is sold to various purchasers in accordance with the companys
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 six months
ended April 30, 2010 and 2009 were $1,485,000 and $2,273,000
respectively, and were $740,000 and $1,081,000 for the three months ended April 30,
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.
7
Table
of Contents
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
April 30, 2010 the estimated present value of future net revenues from
proved reserves, net of related income tax considerations, exceeded the
capitalized costs of the companys oil and natural gas properties. Therefore, a ceiling test write-down was not
required. For the three and six months
ended April 30, 2009, the company recorded non-cash ceiling test
write-downs of $8,030,000 and $23,726,000 respectively.
Changes in oil and natural gas prices have historically had the most
significant impact on the companys 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 companys 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 companys 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 six months ended April 30, 2010 and 2009, the company recognized
stock based compensation expense of $34,000 and $16,000, respectively. For the three months ended April 30,
2010 and 2009, the company recognized stock based compensation expense of
$27,000 and $8,000, respectively. The
estimated unrecognized compensation cost from unvested stock options as of April 30, 2010
was approximately $171,000 which is expected to be recognized over an average
of 2.7 years.
No options were granted during fiscal year 2009. The fair value of the 50,000 options granted
during the six months ended April 30, 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 estimated in accordance with the
provisions of FASB ASC 718 will also be included in compensation expense.
8
Table
of Contents
Plan activity for the six
months ended April 30, 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 April 30, 2010
|
|
179,063
|
|
$
|
8.40
|
|
$
|
356,000
|
|
|
|
|
|
|
|
|
|
Exercisable at April 30, 2010
|
|
124,063
|
|
$
|
7.86
|
|
$
|
336,000
|
|
|
|
|
|
|
|
|
|
Weighted average contractual life at April 30, 2010
|
|
|
|
5.73
|
years
|
|
|
|
|
Outstanding
|
|
Exercisable
|
|
|
|
Number
|
|
Weighted Average
|
|
Weighted
|
|
Number
|
|
|
|
Range of
|
|
Outstanding
|
|
Remaining
|
|
Average
|
|
Exercisable at
|
|
Weighted
|
|
Exercise
|
|
at April 30,
|
|
Contractual
|
|
Exercise
|
|
April 30,
|
|
Average
|
|
Prices
|
|
2010
|
|
Life in Years
|
|
Price
|
|
2009
|
|
Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93
|
|
89,063
|
|
3.12
|
|
$
|
5.93
|
|
89,063
|
|
$
|
5.93
|
|
$ 9.30
|
|
50,000
|
|
9.67
|
|
$
|
9.30
|
|
|
|
$
|
9.30
|
|
$12.78
|
|
40,000
|
|
6.60
|
|
$
|
12.78
|
|
35,000
|
|
$
|
12.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93 -$12.78
|
|
179,063
|
|
5.73
|
|
$
|
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 oil and natural gas 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 companys 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 six months ended April 30, 2010 and 2009, the company had
realized gains on natural gas derivatives of $3,000 and $2,275,000,
respectively, and unrealized gains (losses) of $36,000 and ($348,000)
respectively. For the quarters ended April 30,
2010 and 2009 the company had realized gains on natural gas derivatives of
$12,000 and $1,350,000 respectively, and unrealized gains (losses) of $41,000
and ($889,000), respectively.
At April 30, 2010 the company held open derivative contracts
representing natural gas short sales positions for 400,000 MMBtus at NYMEX
basis prices ranging from $5.31 to $7.27 and covering the production months of May 2010
through December 2010. The company
also held open derivative contracts with the same counterparty representing
natural gas long positions for 360,000 MMBtus at NYMEX basis prices ranging
from $4.26 to $5.83 and covering the production months of May 2010 through
December 2010. These positions are
presented net due to the contractual netting provisions with the
counterparty. The open derivative contracts
net to 40,000 MMBtus with a net unrealized gain of $206,000 at April 30,
2010.
9
Table
of Contents
Average natural gas prices received in the companys primary market
have historically been 15% - 17% below NYMEX prices due to basis differentials
compared to the current differentials of about 4%.
At April 30, 2010 the company also held natural gas basis
differential hedges on 280,000 MMBtus with NYMEX vs. Panhandle Eastern Pipeline
basis differentials of $0.47 and covering the production months of May 2010
through December 2010. These open
basis differential contracts represent unrealized losses of $66,000 at April 30,
2010.
Subsequent to April 30, the May and June natural gas
related derivative contracts closed, resulting in realized derivative gains
of $32,000.
At
April 30, 2010 the company also held costless collar derivative contracts
for 6,000 barrels of oil for the production months of May 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 April 30, 2010. Unrealized losses on oil derivative contracts
were $12,000 for the three and six month periods ended April 30,
2010. There were no oil hedges in
2009. Subsequent to April 30, the May contract
closed, resulting in a realized gain of $1,000.
There were no oil hedges in 2009.
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 companys 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 April 30, 2010
|
|
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Natural Gas Forward Positions
|
|
Derivative
Asset
|
|
$
|
206,000
|
|
Natural Gas Basis Positions
|
|
Derivative
Liability
|
|
(66,000
|
)
|
Crude Oil Collars
|
|
Derivative
Liability
|
|
(12,000
|
)
|
|
|
|
|
|
|
|
Amount
of Gain or (Loss) Recognized in Income on Derivatives:
Derivatives
not designated as hedging instruments:
|
|
Location of Gain/(Loss)
|
|
Six Months
|
|
|
|
Recognized in
|
|
Ended
|
|
|
|
Income on Derivatives
|
|
April 30, 2010
|
|
Natural Gas Forward Positions
|
|
Other
Income and (Expense)
|
|
$
|
107,000
|
|
Natural Gas Basis Positions
|
|
Other
Income and (Expense)
|
|
(68,000
|
)
|
Crude Oil Collars
|
|
Other
Income and (Expense)
|
|
(12,000
|
)
|
|
|
|
|
|
|
|
10
Table of Contents
6.
EARNINGS
PER SHARE
The companys calculation of
earnings per share of common stock is as follows:
|
|
Six Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
(Loss)
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
(Loss)
|
|
Shares
|
|
Per Share
|
|
Basic earnings (loss) per share
|
|
$
|
1,242,000
|
|
10,140,000
|
|
$
|
.12
|
|
$
|
(14,601,000
|
)
|
10,358,000
|
|
$
|
(1.41
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive shares of common stock from stock options
|
|
|
|
39,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share
|
|
$
|
1,242,000
|
|
10,179,000
|
|
$
|
.12
|
|
$
|
(14.601,000
|
)
|
10,358,000
|
|
$
|
(1.41
|
)
|
|
|
Three Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
Net
|
|
|
|
Income
|
|
Net
|
|
|
|
(Loss)
|
|
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Loss
|
|
Shares
|
|
Per Share
|
|
Basic earnings (loss) per share
|
|
$
|
603,000
|
|
10,187,000
|
|
$
|
.06
|
|
$
|
(4,710,000
|
)
|
10,330,000
|
|
$
|
(.46
|
)
|
Effect of dilutive shares of common stock from stock options
|
|
|
|
18,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share
|
|
$
|
603,000
|
|
10,205,000
|
|
$
|
.06
|
|
$
|
(4,710,000
|
)
|
10,330,000
|
|
$
|
(.46
|
)
|
The companys outstanding options were not included in the calculation
of diluted loss per share for the three and six month periods ended April 30,
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 April 30, 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.
11
Table
of Contents
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 7.1 to
16.4 years.
|
|
April 30, 2010
|
|
|
|
Gross Carrying
|
|
Accumulated
|
|
|
|
Amount
|
|
Amortization
|
|
|
|
|
|
|
|
Amortized intangible assets:
|
|
|
|
|
|
Calliope intangible assets
|
|
$
|
4,449,000
|
|
$
|
653,000
|
|
|
|
|
|
|
|
Aggregate amortization expense:
|
|
|
|
|
|
For the six months ended April 30, 2010
|
|
|
|
$
|
217,000
|
|
|
|
|
|
|
|
|
|
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 six months ended April 30,
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 companys
short-term
investments consist primarily 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 counterpartys non-performance
risk with respect to the companys financial assets and the companys non-performance
risk with respect to the companys financial liabilities. The following table provides the assets and
liabilities carried at fair value measured on a recurring basis as of April 30,
2010:
|
|
As of April 30, 2010
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
|
(in thousands)
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
Short-term investments
|
|
$
|
1,815
|
|
$
|
|
|
$
|
235
|
|
$
|
2,050
|
|
Derivative
asset
|
|
$
|
|
|
$
|
206
|
|
$
|
|
|
$
|
206
|
|
Derivative
liability
|
|
$
|
|
|
$
|
(73
|
)
|
$
|
|
|
$
|
(73
|
)
|
12
Table
of Contents
Level 3 instruments are comprised of the companys investments in
professionally managed limited partnerships.
The fair value represents the net asset value of the companys 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 six months ended April 30, 2010:
|
|
Three Months
|
|
Six Months
|
|
|
|
Ended
|
|
Ended
|
|
|
|
April 30, 2010
|
|
April 30, 2010
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
Balance
as of January 31, 2010 and October 31, 2009, respectively(1)
|
|
$
|
275
|
|
$
|
342
|
|
Total
gains (losses):
|
|
|
|
|
|
Included
in earnings(2)
|
|
(1
|
)
|
(12
|
)
|
Redemptions
|
|
(39
|
)
|
(95
|
)
|
Balance
as of April 30, 2010(1)
|
|
$
|
235
|
|
$
|
235
|
|
(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 companys 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. 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 April 30, 2010, the company acquired
47,978 shares of its common stock at an aggregate cost of $448,000. For the six months ended April 30, 2010,
the company acquired 115,435 shares of its common stock at an aggregate cost of
$1,114,000. A total of
410,869 shares have been repurchased under the program at an average price
per share of $8.90. Subsequent to April 30,
2010 through May 20, 2010, 18,600 shares have been acquired at an average
cost per share of $9.25.
11.
COMMITMENTS AND CONTINGENCIES
The company has been 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 company believes that a
contractual agreement requires that disputes be resolved by arbitration. Although the company believes the allegations
are without merit and that the company will ultimately prevail, the ultimate
outcome of this lawsuit, or arbitration, cannot be determined at this time.
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 April 30,
2010.
13
Table
of Contents
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 companys 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, but may require expanded disclosure about fair value
measurements.
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 companys 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 Commissions (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
14
Table
of Contents
reasonably expects, believes
or anticipates will or may occur in the future.
Forward-looking statements may relate to, among other things:
·
the companys 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 companys
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 companys business and operations.
LIQUIDITY
AND CAPITAL RESOURCES
At April 30, 2010,
working capital was $12,178,000 compared to $13,542,000 at October 31,
2009. For the six months ended April 30,
2010, net cash provided by operating activities was $2,144,000 compared to
$4,007,000 for the same period in 2009.
The principle difference resulted from transfers between cash and short
term investments. Income before taxes
increased $25,593,000 primarily due to impairment losses of $24,652,000 in
2009, an increase in revenue of $1,626,000 and decreased other costs and
expenses of $1,052,000 in 2010.
For the six months ended April 30, 2010 and 2009, net cash used in
investing activities was $3,596,000 and $14,809,000, respectively. Last years investment expenditures included
$4,400,000 purchase of Calliope patents, $1,600,000 North Dakota Bakken acreage
acquisition expenditures, $2,859,000 seismic and drilling expenditures in
Central Kansas and $2,235,000 Oklahoma drilling project expenditures. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$3,555,000 and $10,368,000 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 April 30, 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 companys adjusted earnings before interest, taxes, depreciation,
depletion and amortization, including impairment losses, (EBITDA) was
$3,380,000 for the six months ended April 30, 2010 compared to $3,256,000
for the six months ended April 30, 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
15
Table
of Contents
consider this measure in isolation or as a substitute for operating income,
or any other measure for determining the companys 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:
|
|
Six Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
RECONCILIATION OF EBITDA:
|
|
|
|
|
|
Net Income (loss)
|
|
$
|
1,242,000
|
|
$
|
(14,601,000
|
)
|
Add Back (Deduct):
|
|
|
|
|
|
Interest Expense
|
|
|
|
|
|
Income Tax Expense (Benefit)
|
|
415,000
|
|
(9,335,000
|
)
|
Depreciation, Depletion and Amortization Expense Including Write-Down
and Impairment
|
|
1,723,000
|
|
27,192,000
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
3,380,000
|
|
$
|
3,256,000
|
|
OFF-BALANCE SHEET
FINANCING
The company has no off-balance sheet arrangements at April 30,
2010.
PRODUCT PRICES AND
PRODUCTION
Although
product prices are key to the companys ability to operate profitably and to
budget capital expenditures, they are beyond the companys 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 companys production. The companys 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 tables below exclude
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.
|
|
Six Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
% Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
48,500
|
|
$
|
72.74
|
|
54,800
|
|
$
|
38.63
|
|
- 12
|
%
|
+ 89
|
%
|
Gas (Mcf)
|
|
523,000
|
|
$
|
4.89
|
|
647,000
|
|
$
|
3.62
|
|
- 19
|
%
|
+ 35
|
%
|
BOE
(Barrels of
Oil
Equivalent)
|
|
135,700
|
|
$
|
44.86
|
|
162,600
|
|
$
|
27.43
|
|
- 17
|
%
|
+ 64
|
%
|
16
Table of Contents
|
|
Three
Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
%
Change
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbls)
|
|
25,000
|
|
$
|
72.31
|
|
38,100
|
|
$
|
39.25
|
|
- 35
|
%
|
+ 84
|
%
|
Gas (Mcf)
|
|
248,000
|
|
$
|
4.60
|
|
285,000
|
|
$
|
3.01
|
|
- 13
|
%
|
+ 53
|
%
|
BOE (Barrels of Oil Equivalent)
|
|
66,200
|
|
$
|
44.49
|
|
85,600
|
|
$
|
27.49
|
|
- 23
|
%
|
+ 62
|
%
|
The effect of realized derivative gains and losses on total price
realizations are reflected in the following table:
|
|
Six Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Net
|
|
Derivative
|
|
Effective
|
|
Net
|
|
Derivative
|
|
Effective
|
|
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Product
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
72.74
|
|
$
|
|
|
$
|
72.74
|
|
$
|
38.63
|
|
$
|
|
|
$
|
38.63
|
|
Gas
|
|
$
|
4.89
|
|
$
|
0.01
|
|
$
|
4.90
|
|
$
|
3.62
|
|
$
|
3.51
|
|
$
|
7.13
|
|
|
|
Three Months Ended April 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Realized
|
|
|
|
|
|
Net
|
|
Derivative
|
|
Effective
|
|
Net
|
|
Derivative
|
|
Effective
|
|
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Wellhead
|
|
Gain
|
|
Price
|
|
Product
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
Price
|
|
(Loss)
|
|
Realization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
72.31
|
|
$
|
|
|
$
|
72.31
|
|
$
|
39.25
|
|
$
|
|
|
$
|
39.25
|
|
Gas
|
|
$
|
4.60
|
|
$
|
0.05
|
|
$
|
4.65
|
|
$
|
3.01
|
|
$
|
4.74
|
|
$
|
7.75
|
|
OPERATIONS
During the first six months of fiscal 2010, the companys operations
continued to focus on its two core projects oil and natural gas drilling and
application of its patented Calliope Gas Recovery System.
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 companys 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 companys 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.
17
Table
of Contents
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 Dakotas Williston Basin. 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 companys Oklahoma drilling projects while still
yielding excellent economics.
All of the companys oil and natural gas properties are located
on-shore in the continental United States.
The companys 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 companys 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 April 30, 2010, the
companys first Bakken horizontal well, the Petro Hunt 148-94-17D-08-1H (17-D),
has been on production for 79 days and is currently flowing without artificial
lift. During initial testing, the well
flowed 1,267 barrels of oil and 1.24 million cubic feet of gas, or
1,474 barrels of oil equivalent (Boe), over a 24-hour period. Through the first 90 days the well flowed
40,000 Boe. Credo owns a 10%
working interest.
Credos
second horizontal Bakken well, also on the Fort Berthold Reservation, commenced
drilling in May. The 147-94-3A-10-1H (3-A)
well is being drilled on a 1,280 acre spacing unit located about four miles southeast
of the 17-D. The 3-A well will also be
operated by Petro-Hunt, and 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 companys 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, drilling has commenced on Credos third
horizontal Bakken well, the Brigham Exploration Weisz 11-14#1-H (Weisz). The well is located on a 1,280 acre spacing
unit about one mile east of Brighams Olson 10-15-H well which has produced
almost 115,000 Boe in 15 months. Credo
owns a 6% working interest and, based on Brighams 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.
Horizontal
drilling targets the Bakken and Three Forks formations. The companys 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 in which it owns an
85% working interest. That field
has produced over 100,000 barrels of oil in about 15 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 56 wells on its Central Kansas Uplift acreage, of which 45% 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.
18
Table
of Contents
Recent
wildcat discoveries include the Campbell #18-1 and the Keith #13-1, both
located in Graham County. The Campbell
was completed pumping 75 Bopd and establishes first production on a large
seismic feature for the area. A second
well on this feature is scheduled for June.
The Keith is currently awaiting completion after yielding good oil
recovery on drill stem tests. This well
also establishes production on a prominent seismic feature that has good
development potential. Credo owns 27%
and 46% working interests in the wells, respectively.
Calliope
Gas Recovery Technology
Calliope Gas Recovery System
The company is are
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.
Credo
recently entered into a Calliope license agreement with a mid-sized oil and gas
producer to install Calliope on a pilot project. In addition, the company is in late stage
discussions with a large independent for a Calliope pilot project over a cross
section of applications that will test its efficacy for a large population of
wells.
Calliopes 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
Six Months Ended April 30,
2010 Compared to Six Months Ended April 30, 2009
For
the six months ended April 30, 2010, oil and gas revenues increased 36% to
$6,087,000 compared to $4,461,000 during the same period last year. As the oil and gas price/volume table on page 16
shows, oil sales prices increased 89% to $72.74 per barrel and natural gas
sales prices increased 35% to $4.89 per Mcf.
The net effect of these price changes was to increase oil and gas sales
by $2,694,000. On an energy equivalency
basis (six Mcf equals one barrel of oil), total first half production was down
17% primarily due to the impact of flush oil production last year from the
companys Huslig Field discovery. For
the period, oil production was down 12% and natural gas production was down
19%. This resulted in an oil and gas
sales decrease of $1,068,000 for the six months ended April 30, 2010. Investment and other income increased
$163,000, primarily due to market performance.
For the six months ended April 30, 2010,
total costs and expenses, excluding the impairment loss of $24,652,000 in 2009,
decreased 19% to $4,500,000 compared to $5,552,000 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 25% and 39% for
the 2010 and 2009 periods, respectively.
Three Months Ended April 30, 2010 Compared to
Three Months Ended April 30, 2009
For
the three months ended April 30, 2010, total revenues increased 25% to
$2,945,000 compared to $2,353,000 during the same period last year. As the oil and gas price/volume table on page 16
shows, oil prices increased 84% to $72.31 per barrel and natural gas sales
prices increased 53% to $4.60 per Mcf. The net effect of these price changes
was to increase oil and gas sales by $1,713,000. For the second quarter, total production was
down 23%, calculated on the energy equivalency basis due to flush
19
Table
of Contents
production
from the Huslig Field discovery last year and suspension of drilling for
natural gas. For the period, oil
production was down 35% and natural gas production was down 13%. 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 $1,121,000 for the quarter ended April 30,
2010. Investment and other income
increased $22,000 due to a generally improved investment environment.
For the three months ended April 30,
2010, total costs and expenses fell 9% to $2,237,000 compared to $2,461,000,
excluding the 2009 impairment loss of $8,030,000, for the comparable period in
2009. Oil and gas production expenses
increased 8% 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 increased primarily due to legal and professional
fees. The effective tax rate was 24% and
39% for the 2010 and 2009 periods, respectively.
SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally
accepted accounting principles requires the company 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.
The company believes the following accounting policies and estimates are
significant in the preparation of its consolidated financial statements: the
carrying value of its oil and natural gas properties, the accounting for oil
and natural gas reserves, and the estimate of its asset retirement obligations.
Derivatives
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 its balance sheet and changes in fair
value are recorded in the Consolidated Statements of Operations as they occur.
Oil and Gas Properties
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.
Depreciation, depletion and amortization is a significant component of
oil and natural gas properties. A change
in proved reserves without a corresponding change in capitalized costs will
cause the depletion rate to increase or decrease.
Both the volume of proved reserves and any estimated future
expenditures used for the depletion calculation are based on estimates such as
those described under Oil and Gas Reserves below.
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. 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 considered price increases subsequent to
the quarterly balance sheet date which may reduce or eliminate a write-down. Any such write-down will reduce earnings in
the period of occurrence and result in lower depreciation and depletion in
future periods. A write-down may not be
reversed in future periods, even though higher oil and natural gas prices may
subsequently increase the ceiling.
Changes in oil and natural gas prices have historically had the most
significant impact on the companys 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
20
Table
of Contents
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 companys 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 companys
assessment of future prices or costs, but rather are based on prices and costs
in effect as of the end the test period.
Oil and Gas Reserves
The
determination of depreciation and depletion expense as well as ceiling test
write-downs related to the recorded value of the companys oil and natural gas
properties are highly dependent on the estimates of the proved oil and natural
gas reserves. Oil and natural gas
reserves include proved reserves that represent estimated quantities of crude
oil and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. There are numerous uncertainties inherent in
estimating oil and natural gas reserves and their values, including many
factors beyond the companys control.
Accordingly, reserve estimates are often different from the quantities
of oil and natural gas ultimately recovered and the corresponding lifting costs
associated with the recovery of these reserves.
See Footnote 12 for description of new SEC rules which Credo will
adopt, effective October 31, 2010.
Asset Retirement Obligations
The company estimates the future cost of asset retirement obligations,
discounts that cost to its present value, and records a corresponding asset and
liability in its Consolidated Balance Sheets.
The values ultimately derived are based on many significant estimates,
including future abandonment costs, inflation, market risk premiums, useful
life, and cost of capital. The nature of
these estimates requires the company to make judgments based on historical
experience and future expectations.
Revisions to the estimates may be required based on such things as
changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or
downward revisions in the estimated obligation will result in an adjustment to
the related capitalized asset and corresponding liability on a prospective
basis.
Revenue Recognition
The company derives its revenue primarily from the sale of
produced natural gas and crude oil. The
company reports revenue gross for the amounts received before taking into account
production taxes and transportation costs which are reported as oil and gas
production expenses. Revenue is recorded
in the month production is delivered to the purchaser at which time title
changes hands. The company makes
estimates of the amount of production delivered to purchasers and the prices it
will receive. The company uses its
knowledge of its properties, their historical performance, the anticipated
effect of weather conditions during the month of production, NYMEX and local
spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual
amounts received are recorded when payment is received.
A majority of the companys sales are made under contractual
arrangements with terms that are considered to be usual and customary in the
oil and gas industry. The contracts are
for periods of up to five years with prices determined based upon a percentage
of a pre-determined and published monthly index price. The terms of these contracts have not had an
effect on how the company recognizes its revenue.
21
Table
of Contents
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 April 30, 2010 the
company held open natural gas derivative contracts representing short sales
positions for 400,000 MMBtus at NYMEX basis prices ranging from $5.31 to $7.27
and covering the production months of May 2010 through December 2010. The company also held open natural gas
derivative contracts with the same counterparty representing long positions for
360,000 MMBtus at NYMEX basis prices ranging from $4.26 to $5.83 and covering
the production months of May 2010 through December 2010. These positions are presented net due to the
contractual netting provisions with the counterparty. The open derivative contracts net to 40,000
MMBtus with a net unrealized gain of $206,000 at April 30, 2010. Average prices in the companys primary
market are currently 0% 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
April 30, 2010 the company also held basis differential hedges on 280,000
MMBtus with NYMEX vs. Panhandle Eastern Pipeline basis differentials of $0.47
and covering the production months of May 2010 through December 2010. These open basis differential contracts represent
an unrealized loss of $66,000 at April 30, 2010.
See Note 5 to the
Consolidated Financial Statements for more information regarding derivative
transactions.
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 April 30,
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 SECs 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 April 30, 2010 that has materially affected or is
reasonably likely to materially affect, our internal control over financial
reporting.
PART II
- OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
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
22
Table
of Contents
reference into this Part II,
Item I.
ITEM 1A.
RISK FACTORS
There have been no
material changes from the risk factors previously disclosed in the companys
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 six months of fiscal year 2010, the company
repurchased 115,435 shares of its common stock on the open market at a weighted
average price of $9.65. 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. The extended plan authorized repurchases up
to $4,000,000, but could be expanded, suspended or discontinued at any
time. At April 30, 2010, the
company has repurchased 410,869 shares of common stock at an average price per
share of $8.90. Subsequent to April 30,
through May 20, 2010, the company has repurchased an additional 18,600
shares, bringing the total shares repurchased to 429,469 at an average price
per share of $8.92.
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
|
|
|
|
$
|
|
|
|
|
$
|
|
|
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
|
|
$
|
342,014
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
410,869
|
|
$
|
8.90
|
|
410,869
|
|
$
|
342,014
|
|
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 5.
OTHER INFORMATION
None.
23
Table
of Contents
ITEM 6.
EXHIBITS
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)
SIGNATURES
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:
June 9,
2010
|
|
|
24
iShares Trust (NASDAQ:CRED)
Historical Stock Chart
From Jun 2024 to Jul 2024
iShares Trust (NASDAQ:CRED)
Historical Stock Chart
From Jul 2023 to Jul 2024