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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For The Fiscal Year Ended October 31, 2008
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or
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
SECURITIES EXCHANGE
ACT OF 1934
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For the transition period from
to
Commission File Number 0-8877
CREDO PETROLEUM CORPORATION
(Exact name of registrant as specified in its
charter)
Colorado
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84-0772991
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(State or other
jurisdiction
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(I.R.S. Employer
Identification Number)
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of incorporation or organization)
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1801 Broadway, Suite 900,
Denver, Colorado 80202-3837
(Address of principal executive offices and
zip code)
Registrants telephone number, including area
code:
(303) 297-2200
Securities registered pursuant to Section 12(b) of
the Act:
None
Securities registered pursuant to Section 12(g) of
the Act:
Common Stock, $.10 Par Value
(Title of class and shares outstanding)
Indicate by check mark if the registrant is a well-known seasoned
issuer, as defined in Rule 405 of the Securities Act:
o
Yes
x
No
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act:
o
Yes
x
No
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.
x
Yes
o
No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or
any amendment to this Form 10-K.
x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer.
(See definition of accelerated filer and large accelerated filer in Rule 12b-2
of the Act.)
Large accelerated filer
o
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Accelerated filer
x
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Non-accelerated filer
o
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Smaller reporting
company
o
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(Do not check if a
smaller
reporting company)
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Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Act.
o
Yes
x
No
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of April 30, 2008, the end of the registrants most recently completed second quarter was $78,774,000.
As of January 7, 2009, the registrant had 10,437,000 shares of common stock outstanding.
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DOCUMENTS INCORPORATED BY REFERENCE
Pursuant to instruction G (3) to Form 10-K, Items 10, 11, 12,
13 and 14 are omitted because the company will file a definitive proxy
statement (the Proxy Statement) pursuant to Regulation 14A under the
Securities Exchange Act of 1934 not later than 120 days after the end of
the fiscal year. The information
required by such items will be included in the Proxy Statement to be so filed
for the companys annual meeting of shareholders to be held on or about March 19, 2009
and is hereby incorporated by reference.
NON-GAAP FINANCIAL MEASURES
In this Annual Report on Form 10-K, the company uses the term EBITDA
(Earning Before Unrealized Gains/Losses of Derivative Contracts, Interest,
Taxes, Depreciation and Amortization) which is considered a non-GAAP financial
measure as defined in SEC Regulation S-K Item 10 and should not be considered
in isolation or as a substitute for measures of performance prepared in
accordance with GAAP. See Item 7 Managements
Discussion and Analysis of Financial Condition and Results of Operations for a
definition of this measure as used in this Annual Report on Form 10-K.
Estimated Future Net Revenues Discounted at 10% is not a GAAP measure of
operating performance. This pre-tax,
non-GAAP measure is used by the company in connection with estimating funds
expected to be available in the future for drilling and other operating
activities. See Item 2 PROPERTIES,
Significant Properties, Estimated Proved Oil and Gas Reserves, and Future Net
Revenues for a reconciliation of Estimated Future Net Revenues Discounted at
10% to the Standardized Measure of Discounted Future Net Cash Flows as shown in
Note 9 to the companys Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K
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 Annual Report on Form 10-K, 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 include, among other things, statements
relating to:
·
the companys future financial position,
including working capital and anticipated cash flow;
·
amounts and nature of future capital
expenditures;
·
projections of operating costs and other
expenses;
·
wells to be drilled or reworked including new
drilling expectations;
·
expectations regarding oil and natural gas
prices and demand;
·
existing fields, wells and prospects;
·
diversification of exploration, capital
exposure, risk and reserve potential of drilling activities;
·
estimates of proved oil and natural gas
reserves;
·
expectations and projections regarding joint
ventures;
·
reserve potential;
·
development and drilling potential;
·
expansion and other development trends in the
oil and natural gas industry;
·
the companys business strategy;
·
production and production potential of oil and
natural gas;
·
matters related to the Calliope Gas Recovery
System, including projections for future use of Calliope and the success of
Calliope;
·
effects of federal, state and local
regulation;
·
adequacy of insurance coverage;
·
employee relations;
·
effectiveness of the companys hedging
transactions;
·
investment strategy and risk; and
·
expansion and growth of the companys business
and operations.
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Although the company believes
that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to be
correct. Disclosure of important factors
that could cause actual results to differ materially from the companys expectations,
or cautionary statements, are included under Risk Factors and elsewhere in
this Annual Report on Form 10-K, including, without limitation, in
conjunction with the forward-looking statements. The following factors, among others that
could cause actual results to differ materially from the companys
expectations, include:
·
unexpected changes in business or economic
conditions;
·
significant changes in natural gas and oil
prices;
·
timing and amount of production;
·
unanticipated down-hole mechanical problems in
wells or problems related to producing reservoirs or infrastructure;
·
changes in overhead costs;
·
material events resulting in changes in
estimates; and
·
competitive factors.
All forward-looking statements speak only as of the date made. All subsequent written and oral
forward-looking statements attributable to the company, or persons acting on
the companys behalf, are expressly qualified in their entirety by the
cautionary statements. Except as
required by law, the company undertakes no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which it is made or to reflect the occurrence of anticipated or unanticipated
events or circumstances.
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PART I
General
CREDO Petroleum Corporation (CREDO) was incorporated in Colorado in
1978. CREDO and its wholly owned
subsidiaries, SECO Energy Corporation and United Oil Corporation (SECO, United
and collectively the company), are Denver, Colorado based independent oil and
gas companies which engage primarily in oil and gas exploration, development
and production activities in the Mid-Continent region of the United
States. The company has operating
activities in ten states and has thirteen full-time employees. CREDO is an active operator in Kansas,
Wyoming, Colorado, Louisiana and Texas.
United is an active operator doing business primarily in Oklahoma, and
SECO primarily owns royalty interests in the Rocky Mountain region. References to years as used in this report
indicate fiscal years ended October 31.
Business Activities
During 2008, the company continued implementation of new exploration
projects in central Kansas, South Texas, and North Dakota, which projects are
designed to sustain the companys growth by expanding and diversifying its
business, both technically and geographically.
These projects will also diversify the capital exposure, risk and
reserve potential of the companys drilling activities.
The companys goal is to create steady growth by adding production and
long-lived reserves at reasonable costs and risks. The strategy to achieve this goal involves
drilling and increasing the number of Calliope installations. Third party industry participants are
involved in most of the companys operating activities.
Historically, the companys primary drilling focus has been in the
Anadarko Basin of Oklahoma where the company owns interests in approximately
70,000 gross acres. The company will
continue generating prospects and drilling on this acreage concentrating on
medium depth properties generally ranging from 7,000 to 11,000 feet. Refer to Managements Discussion and
Analysis of Financial Condition and Results of Operations-Oil and Gas
Activities-Drilling Activities-Northern Anadarko Basin for additional
information.
In
recent years, the company has significantly expanded both the volume and
breadth of its exploration program with new projects in South Texas and
north-central Kansas. Compared to
drilling in Oklahoma, the South Texas project involves higher costs and greater
risks but significantly higher per well reserve potential. The South Texas project is 3-D seismic driven
with well depths ranging from 10,000 to 17,000 feet. In South Texas, the initial test well on the Gemini
Prospect resulted in a dry hole. The
17,000-foot well confirmed the seismic interpretation and found porous sand. However, the sand was water wet and the well
was plugged and abandoned. CREDO
received approximately $1,300,000 of cash for the multiple prospect package and
retained an 11.25% carried interest in the test well.
The prospect package
consists of two additional Deep Wilcox prospects located to the north of Gemini
Prospect. These two prospects are
structurally different and unique compared to the Gemini Prospect. Those prospects are being further evaluated,
and if drilled, CREDO will have the same 11.25% carried interest in the next
well as it did in the Gemini Prospect test well.
The north-central Kansas project is geared to oil exploration and has
excellent potential to add significant reserves at moderate costs and
risks. This project is also 3-D seismic
driven with well depths of approximately 4,000 feet. Exploration teams for both projects
specialize in their respective geographic areas and have been highly successful
finding new reserves using 3-D seismic. The companys Kansas acreage is located
in prolific oil producing areas where 3-D seismic has proven effective in
identifying undrilled structures.
Drilling targets the Lansing-Kansas City and Arbuckle formations at
about 4,000 feet, making the cost of drilling very inexpensive in relation to
potential reserve value. At October 31,
2008, 29 wells have been drilled on company acreage, of which 49% have
been successful.
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During the fourth quarter of fiscal 2008, the company
acquired approximately 4,100 net acres on the Fort Berthold Reservation in
North Dakota. The acreage is in the
Bakken Shale Resource Play. The company
believes that these projects have the potential to generate significant future
production and reserve growth. Refer to Managements
Discussion and Analysis of Financial Condition and Results of OperationsOil
and Gas ActivitiesDrilling Activities-Drilling Program Expansion and
Diversification, South Texas, and North-Central Kansas for additional
information.
On
November 6, 2008 the company purchased all of the patents underlying the
Calliope gas recovery technology, all of the related third party interests in
future installations of the technology and patents covering a new fluid lift
technology for shallow wells known as Tractor Seal for $4,500,000.
The company owns the patents covering the Calliope Gas Recovery System (Calliope)
and has been instrumental in developing, testing, refining, and patenting the
Calliope Gas Recovery System. Calliope
efficiently lifts fluids from wellbores using pressure differentials, thus
allowing gas previously trapped by fluid build-up in the wellbore to flow to
the surface. Calliope is distinguished
from all other fluid lift technologies because it does not rely on bottom-hole
pressure and has only one down-hole moving part. Calliope is primarily applicable to mature
natural gas wells in low pressure, natural gas expansion reservoirs at depths
below 8,000 feet. External sources
of capital have not been required for the development, refinement or
installation of Calliope. The company
has proven Calliopes economic viability and flexibility over a wide range of
applications.
The company currently has Calliope installed on wells
located in Oklahoma, Texas and Louisiana which include both sandstones and
limestones in Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria,
Red Fork and Springer reservoirs. Joint
venture discussions were accelerated in fiscal year 2008 with two new
agreements reached and others under negotiation at October 31, 2008.
Refer to Managements Discussion and Analysis of Financial Condition and
Results of Operations-Oil and Gas Activities-Calliope Gas Recovery Technology
for additional information.
The company acts as operator of approximately 130 wells pursuant to
standard industry operating agreements.
The company owns working interests in 314 producing wells and overriding
royalty interests in 1,167 wells.
Markets and Customers
Marketing of the companys oil and gas production is influenced by many
factors which are beyond the companys control, and the exact effect of which
cannot be accurately predicted. These factors include changes in supply and
demand, market prices, regulation, and actions of major foreign producers. Oil price fluctuations can be extremely
volatile as was demonstrated when, during 2008, the posted price for West Texas
intermediate in July reached more than $140.00 per barrel, then fell below
$35.00 in December.
Natural gas price decontrol, the advent of an active spot market for
natural gas, changes in supply and demand for natural gas, and weather patterns
cause natural gas prices to be subject to significant fluctuations. The company presently sells virtually all of
its natural gas under one to five year contracts with major pipeline
companies. The sales price is typically
based on monthly index prices for the applicable pipeline. Title to the natural gas normally passes to
the pipeline at meters located near the wells.
The index prices are reduced by certain pipeline charges.
Most
of the companys natural gas production is located in northwestern
Oklahoma. There has been significant
consolidation among natural gas pipelines in this area, thereby reducing the
number of available purchasers. In many
instances, there may be only one viable pipeline option, which enables the
pipeline to charge higher rates. The
first leg of the Rocky Mountain Express pipeline was completed in early 2008
that transports gas from the Rocky Mountain region to northeast Missouri. The eastern extension of the pipeline
connects with other pipelines that transport natural gas to the eastern United
States. Until the eastern extension,
extending to Ohio, is completed natural gas is being delivered into the
mid-continent region which is creating excess supply and downward pricing
pressure on mid-continent gas sales.
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Over the past few years there has been increasing concern that a
supply/demand imbalance has developed in domestic natural gas based on
increasing demand and lower deliverability.
This, together with rising oil prices, political unrest and uncertainty
in some major producing regions, supply vulnerability to natural disasters,
such as hurricanes, and active speculation in the natural gas futures market
caused natural gas prices to become increasingly volatile. The economic downturn that commenced in the
2nd half of 2008 appears to have resulted in demand reductions at a time when
supply has been increasing. The supply/demand
imbalance pendulum has recently swung in the opposite direction, as evidenced
by volatile price reductions experienced in the 2nd half of 2008. The Panhandle Eastern Pipeline natural gas
index, the basis for most of the companys gas sales, has fallen from $11.07
per Mcf in July 2008 to $2.81 for November, 2008. The company expects natural gas prices to
return to more historical levels but cannot reasonably predict the extent or
timing of natural gas price fluctuations.
As discussed elsewhere in this Annual Report on Form 10-K, the
company periodically hedges the price of a portion of its estimated natural gas
production in the form of forward short positions and collars on the NYMEX
futures market.
Oil production is sold to crude oil purchasing companies at competitive
spot field prices. Crude oil and condensate production are readily marketable,
and the company is generally not dependent on a single purchaser. Crude oil prices are subject to world-wide
supply and demand, and are primarily dependent upon available supplies which
can vary significantly depending on production and pricing policies of OPEC and
other major producing countries and on significant events in major producing
regions. Until recently, political
unrest and market uncertainty in the Middle East, Africa, South America and
former Soviet Union, OPECs renewed cooperation in managing the price of its
produced oil, and increased demand from countries with developing economies,
such as China and India, have resulted in higher world-wide oil prices during
the past several years. Recently the
economic crisis that commenced in the 2nd half of 2008 has resulted in rapid
global reductions in demand for oil. The
effects of oversupply are evidenced by volatile price reductions experienced in
the 2nd half of 2008. World wide prices
for oil have declined approximately 70% since reaching peak levels in July 2008.
Information concerning the companys major customers is included in Note
(10) to the Consolidated Financial Statements.
Competition and Regulation
The oil and gas industry is
highly competitive. As a small
independent, the company must compete against companies with substantially
larger financial, human and other resources in all aspects of its business.
Oil and gas drilling and production operations are regulated by various
federal, state and local agencies. These
agencies issue binding rules and regulations which carry penalties, often
substantial, for failure to comply. The
company anticipates its aggregate burden of federal, state and local regulation
will continue to increase particularly in the area of rapidly changing
environmental laws and regulations. The
company also believes that its present operations substantially comply with
applicable regulations. To date, such
regulations have not had a material effect on the companys operations, or the
costs thereof. There are no known
environmental or other regulatory matters related to the companys operations
which are reasonably expected to result in material liability to the
company. The company believes that
capital expenditures related to environmental control facilities or other
regulatory matters will not be material in 2009. The company cannot predict what subsequent
legislation or regulations may be enacted or what effect they might have on the
companys business.
In evaluating the company, careful consideration should be given to the
following risk factors, in addition to the other information included or
incorporated by reference in this Annual Report on Form 10-K. Each of these risk factors could adversely
affect the companys business, operating results and financial condition, as
well as adversely affect the value of an investment in the companys common
stock.
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Volatility of oil and
natural gas prices could adversely affect the companys profitability and
financial condition.
The companys performance in terms of revenues, operating results,
profitability, future rate of growth and the carrying value of its oil and
natural gas properties is significantly impacted by prevailing market prices
for oil and natural gas. Any substantial
or extended decline in the price of oil or natural gas could have a material
adverse effect on the company. It could
reduce the companys operating cash flow as well as the value and, to a lesser
degree, the quantity of its oil and natural gas reserves. See the table of oil and gas sales volumes
and prices on page 13 for further information.
Historically, the markets for
oil and natural gas have been volatile, and they are likely to continue to be
volatile. Relatively minor changes in
supply or demand can have a significant effect on oil and natural gas
prices. Some of the factors affecting
oil and natural gas prices which are beyond the companys control include:
·
worldwide and domestic supplies of oil and
natural gas;
·
worldwide and domestic demand for oil and
natural gas;
·
the ability of the members of OPEC to agree to
and maintain oil price and production controls;
·
political instability or armed conflict in oil
or natural gas producing regions;
·
worldwide and domestic economic conditions;
·
the availability of transportation facilities;
·
weather patterns; and
·
actions of governmental authorities.
Competition for opportunities to replace and increase production and
reserves is intense and could adversely affect the company.
Properties produce at a declining rate over time. In order to maintain current production rates
the company must add new oil and natural gas reserves to replace those being
depleted by production. Competition
within the oil and natural gas industry is intense and many of the companys
competitors have financial and other resources substantially greater than those
available to the company. This could
place the company at a disadvantage with respect to accessing opportunities to
maintain, or increase, its oil and natural gas reserve base.
In the event that the company does not have adequate cash flow to fund
operations, it may be required to use debt or equity financing.
The company makes, and will continue to make, significant expenditures
to find, acquire, develop and produce oil and natural gas reserves. In the event of sustained low oil and gas
prices, or if operating difficulties are encountered that result in cash flow
from operations being less than expected, the company may have to reduce
capital expenditures unless additional funds are raised through debt or equity
financing. Debt or equity financing or
cash generated by operations may not be available to the company in sufficient
amounts or on acceptable terms to meet these requirements.
Future cash flows and the availability of financing will be subject to a
number of variables, such as:
·
the companys success in locating and
producing new reserves;
·
the level of production from existing wells;
and
·
prices of oil and natural gas;
Issuing equity securities to satisfy the companys financing
requirements could cause substantial dilution to existing stockholders. Debt financing could also make the company
more vulnerable to competitive pressures and economic downturns.
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Reserve quantities and values are subject to many variables and estimates and actual results may vary.
This Annual Report on Form 10-K contains
estimates of the companys proved oil and natural gas reserves and the
estimated future net revenues from those reserves. Any significant negative variance in these
estimates could have a material adverse effect on the companys future
performance.
Reserve estimates are based on various
assumptions, including assumptions required by the SEC relating to oil and
natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The
process of estimating reserves is complex.
This process requires significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data.
Reserve estimates are dependent on many
variables, and therefore, as more information becomes available, it is reasonable
to expect that there will be changes to the estimates. Actual future production, oil and natural gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves will most likely vary
from those estimated. Any significant
variance could materially affect the estimated quantities and present value of
reserves disclosed by the company. In
addition, estimates of proved reserves will be adjusted in the future to
reflect production history, results of exploration and development, prevailing
oil and natural gas prices and other factors, many of which are beyond the
companys control.
As of October 31, 2008, approximately 33%
of the companys estimated proved reserves are classified as proved
undeveloped. Estimation of proved
undeveloped reserves and proved developed non-producing reserves is generally
based on volumetric calculations rather than the performance data used to
estimate reserves for producing properties.
Recovery of proved undeveloped reserves generally requires significant
capital expenditures and successful drilling operations. Revenues from proved developed non-producing
and proved undeveloped reserves will not be realized until some time in the
future. The reserve estimate includes an
estimate of the capital expenditures required to develop these reserves as well
as the timing of such expenditures.
Although the company has prepared estimates of its proved undeveloped
reserves and the associated development costs in accordance with industry
standards, they are based on estimates, and actual results may vary.
You should not interpret the present value of
estimated reserves, or PV-10, as the current market value of reserves
attributable to the companys properties.
The 10% discount factor, which we are required to use to calculate PV-10
for reporting purposes, is not necessarily the most appropriate discount factor
given actual interest rates and risks to which the companys business or the
oil and natural gas industry in general are subject. The company has based the PV-10 on prices and
costs as of the date of the reserve estimate, in accordance with applicable
regulations. Actual future prices and
costs may be materially higher or lower.
In addition to the price volatility factors discussed above, factors
that will affect actual future net cash flows, include:
·
the amount and timing of actual production;
·
curtailments or increases in consumption by
oil and natural gas purchasers; and
·
changes in governmental regulations or
taxation.
As a result, the companys actual future net
cash flows could be materially different from the estimates included in this
Annual Report on Form 10-K.
Full cost pool ceiling subject to
reserve values.
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. 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.
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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 considers price increases subsequent to
the 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.
The companys reserve quantities
and values are concentrated in a relative few properties and fields.
The companys reserves, and reserve values,
are concentrated in 68 properties which represent 24% of the companys
total properties but a disproportionate 80% of the discounted value
(at 10%) of the companys reserves.
Individual wells on which Calliope is installed comprise 16% of
these significant properties and 14% of the discounted reserve value of such
properties. Reserves added during 2008
comprise 25% of these significant properties and 26% of the discounted reserve
value of such properties.
Estimates of reserve quantities and values for
these properties must be viewed as being subject to significant change as more
data about the properties becomes available.
Such properties include wells with limited production histories and
properties with proved undeveloped or proved non-producing reserves. In addition, Calliope is generally installed
on mature wells. As such, they contain
older down-hole equipment that is more subject to failure than new
equipment. The failure of such
equipment, particularly casing, can result in complete loss of a well.
Competition for materials and
services is intense and could adversely affect the company.
Major oil companies, independent producers,
and institutional and individual investors are actively seeking oil and gas
properties throughout the world, along with the equipment, labor and materials
required to develop and operate properties.
Shortages of equipment, labor or materials may result in increased costs
or the inability to obtain such resources as needed. Many of the companys competitors have
financial and technological resources which exceed those available to the
company.
During 2008, the company experienced delays in
securing drilling rigs and delivery of production equipment, primarily
compressors and coil tubing. These
delays extended the time it took the company to conduct its field
operations. As a result, the company could
be at risk for price increases related to these types of services and
equipment.
Natural gas derivatives involve
credit risk and may limit future revenues from price increases.
To manage the companys exposure to price
risks associated with the sale of natural gas, the company periodically enters
into derivative transactions for a portion of its estimated natural gas
production. These transactions may limit
the companys potential gains if natural gas prices were
to rise substantially over the price
established by the derivatives. In
addition, such transactions may expose the company to the risk of financial
loss in certain circumstances, including instances in which:
·
the companys production is less than the
amount hedged;
·
the contractual counterparties fail to perform
under the contracts; or
·
a sudden, unexpected event, materially impacts
natural gas prices.
The terms of the companys derivative
agreements may also require that it furnish cash collateral, letters of credit
or other forms of performance assurance in the event that mark-to-market
calculations result in settlement obligations by the company to the
counterparties, which would encumber the companys liquidity and capital
resources.
The companys derivatives are generally based
on NYMEX prices but the companys hedged production is primarily sold on a
regional pipeline index price. The
regional price is normally 15% to
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17% below NYMEX prices. However, regional weather conditions and
other economic factors, such as the current delay in completion of the eastern
extension of the Rocky Mountain Express gas pipeline, resulting in excess natural
gas supplies to the mid-continent region, can periodically result in
substantially higher basis differentials.
At October 31, 2008, the Oklahoma basis differential was 56% of the
NYMEX price.
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.
The marketability of the companys
natural gas production is dependent upon infrastructure, such as gathering
systems, pipelines and processing facilities, that the company does not own or
control.
The marketability of the companys natural gas
production depends in part upon the availability, proximity and capacity of
natural gas gathering systems, pipelines and processing facilities necessary to
move the companys natural gas production to market. The company does not own this infrastructure
and is dependent on other companies to provide it.
Oil and natural gas operations
are inherently risky.
The oil and natural gas business involves a
variety of risks, including the risks of operating hazards such as fires,
explosions, cratering, blow-outs, and encountering formations with abnormal
pressures. The occurrence of any of
these risks could result in losses. The
company maintains insurance against some, but not all, of these risks. The occurrence of a significant event that is
not fully insured could have a material adverse effect on the companys
financial position and results of operations.
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.
The company has recently expanded the volume and
breadth of its exploration program with new drilling projects in South
Texas. Compared to the companys
Oklahoma drilling, the South Texas project involves higher costs and greater
risks.
The companys operations are
subject to a variety of regulatory constraints.
The production and sale of oil and natural gas
are subject to a variety of federal, state and local government
regulations. These include:
·
the prevention of waste;
·
the discharge of materials into the
environment;
·
the conservation of oil and natural gas;
·
pollution;
·
permits for drilling operations;
·
drilling bonds;
·
reports concerning operations;
·
the spacing of wells; and
·
the unitization and pooling of properties.
Because current regulations covering the
companys operations are subject to change at any time, and despite its belief
that it is in substantial compliance with applicable environmental and other
government laws and regulations, the company could incur significant costs for
future compliance.
11
Table
of Contents
Increases in taxes on energy
sources may adversely affect the companys operations.
Federal, state and local governments which
have jurisdiction in areas where the company operates impose taxes on the oil
and natural gas products sold.
Historically, there has been on-going consideration by federal, state
and local officials concerning a variety of energy tax proposals. Such matters are beyond the companys ability
to accurately predict or control.
The company is highly dependent
on the services of one of its officers.
The company is highly dependent on the
services of James T. Huffman, its Chief Executive Officer. The loss of Mr. Huffman could have a
material adverse effect on the company.
ITEM
1B.
|
|
UNRESOLVED STAFF COMMENTS
|
The company does not have any unresolved
comments from the Commission.
General
The companys Oklahoma drilling activities are
primarily located along the Northern Anadarko Basin of Oklahoma including the
Oklahoma Panhandle where the company owns interests in approximately 70,000
gross developed and undeveloped acres.
Specifically, drilling expenditures have been focused on prospects
located in Harper, Ellis and Beaver Counties, Oklahoma. Wells target the Morrow and Chester
formations between 7,000 and 11,000 feet.
The companys Kansas drilling activities
provide diversification to the companys drilling program geographically and
scientifically through the use of 3-D seismic to identify shallow oil
prospects. The acreage is located in prolific oil producing areas where 3-D
seismic has proven effective in identifying satellite structures near mature
producing fields. Generally higher oil
prices have justified using 3-D seismic technology to locate undrilled
structures that are very difficult to find with old technology. Drilling targets the Lansing-Kansas City and
Arbuckle formations at about 4,000 feet and, compared to the companys
Northern Anadarko Basin and South Texas projects, is relatively low cost, low
risk, and exclusively targets oil reserves in an effort to bring better product
balance to the companys reserve base.
The company has assembled about 139,000 gross (65,000 net) acres and is
continuing to seek opportunities to increase its exposure to the play. The company owns working interests in the
existing prospects ranging from 12.5% to 85%.
The company owns the exclusive right to the
Calliope Gas Recovery System. The
company has proven that Calliope will add 0.5 to 2.0 Bcf of proved gas
reserves to many dead and uneconomic wells.
The company believes there are presently many (more than 1,000) wells
that meet its general criteria for Calliope candidate wells and thousands more
that will meet its general Calliope criteria in the future.
On November 6, 2008 the company purchased
all of the patents underlying the Calliope gas recovery technology, all of the
related third party interests in future installations of the technology and
patents covering a new fluid lift technology for shall wells known as Tractor
Seal for $4,500,000.
Calliope operations were historically focused
in Oklahoma where the company has a significant field operations
infrastructure. Most Calliope wells are
located in the Northern Anadarko Basin of Oklahoma. The companys current compilation of Calliopes
track record shows Calliope installations on 25 wells located in Oklahoma,
Texas and Louisiana. The Calliope wells
include both sandstone and carbonate reservoirs including the Chester, Cotton
Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Redfork and Springer formations.
The Calliope wells range in depth from 6,400 to 18,400 feet. At the time Calliope was installed, 14 of the
wells were dead, nine were uneconomic and two were marginal. There are 14 non-experimental Calliope wells. As a group, those wells were producing a
total of 88 thousand cubic feet of gas per day at the time Calliope was
installed. Since Calliope was installed,
those wells have produced 0.0 billion cubic feet of gas and they now have
estimated ultimate (8/8ths) Calliope reserves totaling 00.0 billion cubic feet
of gas. Eleven of the Calliope wells are
included in the companys Significant Properties.
12
Table
of Contents
For additional information regarding current
year activities, including oil and gas production, refer to Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Significant
Properties, Estimated Proved Oil and Gas Reserves, and
Future Net Revenues
The companys reserves, and reserve values,
are concentrated in 68 properties (Significant Properties). Some of the Significant Properties are
individual wells and others are multi-well properties. At year-end, Significant Properties represent
24% of the companys total properties but a disproportionate 80% of the
discounted value (at 10%) of the companys reserves. Individual Calliope wells comprise 16% of the
Significant Properties and represent 14% of the discounted reserve value of
such properties. Reserves added in 2008
comprise 25% of the Significant Properties and represent 26% of the
discounted value of such properties.
Estimates of reserve quantities and values for
certain Significant Properties must be viewed as being subject to significant
change as more data about the properties becomes available. Such properties
include wells with limited production histories (including post Calliope
installation wells) and properties with proved undeveloped or proved
non-producing reserves. In addition, Calliope wells are generally mature
wells. As such, they contain older
down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly
casing, can result in complete loss of a well.
At October 31, 2008, LaRoche Petroleum
Consultants, Ltd., an independent petroleum engineering firm, estimated proved
reserves for all of the companys properties.
In 2007 and 2006 McCartney Engineering, Inc., an independent
petroleum engineering firm, estimated proved reserves for the companys
properties which represented 64% in 2007 and 63% in 2006 of the total estimated
future value of estimated reserves. In
2007 and 2006, remaining reserves were estimated by the company. At October 31, 2008, natural gas
represented 78% and crude oil represented 22% of total reserves denominated in
equivalent Mcfs using a six Mcf of gas to one barrel of oil conversion
ratio.
The following table sets forth, as of October 31
of the indicated year, information regarding the companys proved reserves
which is based on the assumptions set forth in Note (10) to the
Consolidated Financial Statements where additional reserve information is
provided. The average price used to
calculate estimated future net revenues was $3.50, $5.89, and $6.32 per Mcf of
gas and $62.25, $86.61, and $53.69 per barrel of oil as of October 31,
2008, 2007, and 2006, respectively.
Amounts do not include estimates of future Federal and state income
taxes.
|
|
|
|
|
|
|
|
Estimated Future
|
|
|
|
Gas
|
|
Oil
|
|
Estimated Future
|
|
Net Revenues
|
|
Year
|
|
(Mcf) *
|
|
(bbls) *
|
|
Net Revenues
|
|
Discounted at 10%
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
15,525,000
|
|
710,000
|
|
$
|
53,655,000
|
|
$
|
32,330,000
|
|
2007
|
|
16,973,000
|
|
591,000
|
|
$
|
101,501,000
|
|
$
|
62,071,000
|
|
2006
|
|
16,005,000
|
|
422,000
|
|
$
|
84,861,000
|
|
$
|
52,328,000
|
|
*
The percentage of total reserves classified as
proved developed was approximately 67% in 2008, 76% in 2007, and 87% in 2006.
Estimated Future Net Revenues Discounted at
10% is not a GAAP measure of operating performance. Because the company drills
new wells on an ongoing basis, and plans to continue to do so in the future, it
expects to continue to generate deferred income taxes which are not reasonably
expected to be paid in the near term.
This pre-tax, non-GAAP measure is used by the company in connection with
estimating funds expected to be available in the future for drilling and other
operating activities. The company
believes that this performance measure may also be useful to investors for the
same purpose. The difference between
this measure and the Standardized Measure of Discounted Future Net Cash Flows
From Reserves is that this measure excludes future income tax expense and the
effect of the 10% discount factor on future income tax expense. The following table provides a reconciliation
of Estimated Future Net Revenues Discounted at 10% to the Standardized Measure
of Discounted Future Net Cash Flows as shown in Note 9 to the companys
Consolidated Financial Statements.
13
Table
of Contents
|
|
Year Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Estimated future
net revenues discounted at 10%
|
|
$
|
32,330,000
|
*
|
$
|
62,071,000
|
*
|
$
|
52,328,000
|
*
|
|
|
|
|
|
|
|
|
Future income
tax expense
|
|
(9,119,000
|
)
|
(24,967,000
|
)
|
(20,747,000
|
)
|
|
|
|
|
|
|
|
|
Effect of the 10%
discount factor on future income tax expense
|
|
4,408,000
|
|
9,697,000
|
|
8,170,000
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
27,619,000
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
* The average price used to calculate
estimated future net revenues was $3.50, $5.89 and $6.32 per Mcf of gas and
$62.25, $86.61, and $53.69 per barrel of oil as of October 31, 2008, 2007,
and 2006, respectively.
Production,
Average Sales Prices and Average Production Costs
The companys net production quantities and
average price realizations per unit for the indicated years are set forth
below. Price realizations include
realized derivative gains or losses.
|
|
2008
|
|
2007
|
|
2006
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,545,000
|
|
$
|
7.40
|
(1)
|
1,926,000
|
|
$
|
6.78
|
(2)
|
2,176,000
|
|
$
|
6.11
|
(3)
|
Oil (bbls)
|
|
56,000
|
|
$
|
99.28
|
|
51,000
|
|
$
|
60.95
|
|
41,000
|
|
$
|
61.14
|
|
(1) Includes $0.25 Mcf realized natural
gas hedging derivative loss.
(2) Includes $0.99 Mcf realized natural
gas hedging derivative gain.
(3) Includes $0.12 Mcf realized natural
gas hedging derivative loss.
Average production costs, including production
taxes, per equivalent Mcf of production (using a six Mcf of gas to one barrel
of oil conversion ratio) were $2.05, $1.51 and $1.40 per Mcfe in 2008,
2007, and 2006, respectively.
Productive
Wells and Developed Acreage
Developed acreage at October 31, 2008
totaled 27,000 net and 82,000 gross acres.
At October 31, 2008, the company owned working interests in
88.26 net (334 gross) wells consisting of 69.16 net (266 gross) natural gas
wells and 19.1 net (68 gross) oil wells.
In addition, the company owned royalty and production payment interests
in approximately 1,169 wells, primarily coal bed methane, located in
Wyoming. In 2008, the company sold
0.29 net (2 gross) wells. No wells
were abandoned. In the same period, the
company acquired interests in 6.14 net (23 gross) productive wells.
Undeveloped
Acreage
The following table sets forth the number of
undeveloped acres leased by the company (primarily located in the Mid-Continent
and Rocky Mountain Regions) which will expire during the next five years (and
thereafter) unless production is established in the interim. Undeveloped acres held-by-production
represent the undeveloped portions of producing leases which will not expire
until commercial production ceases.
14
Table of
Contents
Expiration
|
|
Royalty
|
|
Working
|
|
Year Ending
|
|
Interest Acreage
|
|
Interest Acreage
|
|
October 31,
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
22,700
|
|
8,000
|
|
2010
|
|
3,300
|
|
100
|
|
48,300
|
|
14,500
|
|
2011
|
|
|
|
|
|
55,500
|
|
22,100
|
|
2012
|
|
|
|
|
|
1,000
|
|
100
|
|
2013
|
|
|
|
|
|
3,600
|
|
3,400
|
|
Thereafter
|
|
3,700
|
|
500
|
|
12,800
|
|
2,300
|
|
Held-By-Production
|
|
152,100
|
|
8,000
|
|
7,400
|
|
3,700
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
159,100
|
|
8,600
|
|
151,300
|
|
53,100
|
|
In general, royalty interests are
non-operated interests which are not burdened by costs of exploration or lease
operations, while working interests have operating rights and participate in
such costs.
Drilling
The following tables set forth the number of
gross and net oil and gas wells in which the company has participated and the
results thereof for the periods indicated.
Gross Wells
|
|
Year Ended
|
|
Total Gross
|
|
Exploratory
|
|
Development
|
|
October 31,
|
|
Wells
|
|
Oil
|
|
Gas
|
|
Dry
|
|
Oil
|
|
Gas
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
(1)
|
|
32
|
|
12
|
|
9
|
|
11
|
|
|
|
|
|
|
|
2007
|
|
|
24
|
|
5
|
|
11
|
|
7
|
|
|
|
1
|
|
|
|
2006
|
|
|
27
|
|
1
|
|
9
|
|
13
|
|
1
|
|
3
|
|
|
|
(1)
Of the gross wells drilled in 2008, four of
the gas wells and three of the dry holes were operated by the
company. The remaining wells represent
company participations in wells operated by others.
Net Wells
|
|
Year Ended
|
|
Total Net
|
|
Exploratory
|
|
Development
|
|
October 31,
|
|
Wells
|
|
Oil
|
|
Gas
|
|
Dry
|
|
Oil
|
|
Gas
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
(1)
|
|
6.581
|
|
1.874
|
|
1.886
|
|
2.821
|
|
|
|
|
|
|
|
2007
|
|
|
8.591
|
|
1.166
|
|
4.143
|
|
2.700
|
|
|
|
0.582
|
|
|
|
2006
|
|
|
10.421
|
|
0.300
|
|
3.184
|
|
5.029
|
|
0.306
|
|
1.602
|
|
|
|
(1)
Of the net wells drilled in 2008, 1.380 net
gas wells and 0.925 net dry holes were operated by the company. The remaining wells represent company
participations in wells operated by others.
Insurance
The company believes that its existing
insurance coverage is adequate to protect it from the risks associated with the
ongoing operation of its business. This
coverage includes commercial property, liability and auto, workers
compensation, inland marine and excess liability.
Facilities
and Employees
The companys corporate headquarters are
located at 1801 Broadway, Suite 900, Denver, Colorado, in approximately
4,000 square feet occupied under a lease.
The company believes that this space is adequate for its current
needs. The companys current lease
expires in April 2011.
15
Table
of Contents
As of October 31, 2008, the company had
13 employees. None of the companys
employees is subject to a collective bargaining agreement, and the company
considers relations with its employees to be good.
Company
Website
Information related to the following items,
among other information, can be found on the companys website at
www.credopetroleum.com: (a) company
filings with the Securities and Exchange Commission including our annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and amendments to those reports filed or furnished pursuant to Section 13(a) of
15(d) of the Exchange Act as soon as reasonably practicable after filing, (b) company
press releases, (c) officers, directors and ten percent shareholders
filings on Forms 3, 4 and 5, and (d) the companys Code of Ethics and
Audit Committee Charter. The companys
website is not a part of, or incorporated by reference in, this Annual Report
on Form 10-K.
ITEM
3.
|
|
LEGAL PROCEEDINGS
|
From time to time, the company may be involved
in litigation relating to claims arising out of the companys operations in the
normal course of business. As of the
date of this Annual Report on Form 10-K, 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.
ITEM 4.
|
|
SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS
|
No matters were submitted to a vote of
security holders during the fourth quarter of 2008
PART II
ITEM 5.
|
|
MARKET FOR THE REGISTRANTS
COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY
SECURITIES
|
The companys common stock is traded on the
NASDAQ Global Market
SM
under
the symbol CRED. Market quotations
shown below were reported by the Financial Industry Regulatory Authority
(FINRA) and represent prices between dealers excluding retail mark-up or
commissions and may not necessarily represent actual transactions.
|
|
2008
|
|
2007
|
|
Quarter Ended
|
|
High
|
|
Low
|
|
High
|
|
Low
|
|
January 31
|
|
$
|
10.37
|
|
$
|
7.95
|
|
$
|
13.27
|
|
$
|
11.55
|
|
April 30
|
|
$
|
11.36
|
|
$
|
8.57
|
|
$
|
16.00
|
|
$
|
11.58
|
|
July 31
|
|
$
|
18.04
|
|
$
|
9.93
|
|
$
|
14.60
|
|
$
|
11.78
|
|
October 31
|
|
$
|
11.06
|
|
$
|
6.03
|
|
$
|
11.92
|
|
$
|
9.52
|
|
At January 7, 2009, the company had 2,451
shareholders of record. The company has
never paid a cash dividend and does not expect to pay any cash dividends in the
foreseeable future. Earnings are
reinvested in business activities.
Issuer Purchases of Equity Securities.
During the fourth quarter of the fiscal year, the company repurchased
98,940 shares of its common stock on the open market at a weighted average
price of $7.30. The purchases were made
pursuant to a stock repurchase plan announced on September 24, 2008. The plan authorized repurchases up to
$2,000,000, but could be expanded, suspended or discontinued at any time. Subsequent to October 31, 2008, and through
January 5, 2009, the company has repurchased an additional 64,112 shares,
bringing the total shares repurchased to 163,052 at an average price per share
of $8.60.
16
Table
of Contents
Issuer Purchases of Equity
Securities
|
|
|
|
|
|
Total number
|
|
|
|
|
|
|
|
|
|
of shares
|
|
Maximum dollar
|
|
|
|
|
|
|
|
purchased
|
|
value 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
|
|
|
|
|
|
|
|
|
|
|
|
September 1 - 30
2008
|
|
18,571
|
|
$
|
7.38
|
|
18,571
|
|
$
|
1,844,000
|
|
October 1 - 31
2008
|
|
80,369
|
|
$
|
7.04
|
|
80,369
|
|
$
|
1,278,000
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
98,940
|
|
|
|
98,940
|
|
$
|
1,278,000
|
|
Subsequent to October 31, 2008, and through January 5, 2008, the
company has repurchased an additional 64,112 shares, bringing the total shares
repurchased to 163,052 at an average price per share of $8.60.
Performance Graph
The following performance graph compares the cumulative total
stockholder return on the companys common stock for the six-year period ended October 31,
2008 with the cumulative total return of the AMEX Natural Gas Index, and the
Standard & Poors 500 Stock Index.
The identities of the companies included in the index will be provided
upon request.
|
|
October 31
|
|
|
|
2002
|
|
2003
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
2008
|
|
CREDO Petroleum
Corporation
|
|
$
|
100
|
|
$
|
259
|
|
$
|
310
|
|
$
|
610
|
|
$
|
440
|
|
$
|
329
|
|
$
|
296
|
|
Standard &
Poors 500 Stock Index
|
|
100
|
|
119
|
|
128
|
|
136
|
|
156
|
|
175
|
|
109
|
|
AMEX Natural Gas
Index
|
|
100
|
|
152
|
|
210
|
|
299
|
|
335
|
|
443
|
|
340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
Table
of Contents
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth certain
financial information with respect to the company and is qualified in its
entirety by reference to the historical financial statements and notes thereto
of the company included in Item 8, Financial Statements and Supplementary
Data. The statement of operations and
balance sheet data included in this table for each of the five years in the
period ended October 31, 2008 were derived from the audited financial
statements and the accompanying notes to those financial statements.
|
|
Years Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
2005
|
|
2004
|
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
Statement
of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
17,345,000
|
|
$
|
14,265,000
|
|
$
|
16,103,000
|
|
$
|
13,862,000
|
|
$
|
10,084,000
|
|
Oil and gas production expense
|
|
3,861,000
|
|
3,375,000
|
|
3,407,000
|
|
2,759,000
|
|
2,075,000
|
|
Depreciation, depletion and amortization
|
|
3,583,000
|
|
3,666,000
|
|
3,642,000
|
|
2,402,000
|
|
1,747,000
|
|
General and administrative
|
|
1,637,000
|
|
1,397,000
|
|
1,291,000
|
|
1,117,000
|
|
1,171,000
|
|
Income from operations
|
|
8,264,000
|
|
5,827,000
|
|
7,763,000
|
|
7,584,000
|
|
5,091,000
|
|
Realized hedge gains(losses)
|
|
(1,113,000
|
)
|
1,909,000
|
|
(266,000
|
)
|
(719,000
|
)
|
(717,000
|
)
|
Unrealized hedge gains(losses)
|
|
1,301,000
|
|
(454,000
|
)
|
1,327,000
|
|
182,000
|
|
(857,000
|
)
|
Investment and other income(loss)
|
|
(291,000
|
)
|
819,000
|
|
654,000
|
|
146,000
|
|
343,000
|
|
Interest expense
|
|
8,000
|
|
26,000
|
|
42,000
|
|
37,000
|
|
39,000
|
|
Income before income taxes
|
|
8,153,000
|
|
8,075,000
|
|
9,436,000
|
|
7,156,000
|
|
3,821,000
|
|
Net income
|
|
5,993,000
|
|
5,760,000
|
|
6,836,000
|
|
5,153
,000
|
|
2,751,000
|
|
Net income per share(1):
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.62
|
|
$
|
0.62
|
|
$
|
0.74
|
|
$
|
0.57
|
|
$
|
0.30
|
|
Diluted
|
|
$
|
0.61
|
|
$
|
0.61
|
|
$
|
0.72
|
|
$
|
0.55
|
|
$
|
0.30
|
|
Weighted-average shares outstanding(1):
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
9,697,000
|
|
9,280,000
|
|
9,207,000
|
|
9,080,000
|
|
9,036,000
|
|
Diluted
|
|
9,758,000
|
|
9,395,000
|
|
9,482,000
|
|
9,367,000
|
|
9,282,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
Working capital
|
|
24,160,000
|
|
12,511,000
|
|
10,073,000
|
|
7
,697,000
|
|
5,611,000
|
|
Total assets
|
|
80,650,000
|
|
55,349,000
|
|
47,759,000
|
|
37,844,000
|
|
30,976,000
|
|
Long-term obligations:
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes-net
|
|
11,117,000
|
|
9,204,000
|
|
8,039,000
|
|
5,978,000
|
|
4,605,000
|
|
Asset retirement obligation
|
|
1,338,000
|
|
1,016,000
|
|
954,000
|
|
929,000
|
|
748,000
|
|
Exclusive license agreement obligation
|
|
|
|
85,000
|
|
163,000
|
|
233,000
|
|
297,000
|
|
Stockholders equity
|
|
62,211,000
|
|
41,140,000
|
|
34,767,000
|
|
26,947,000
|
|
20,920,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,545,000
|
|
1,926,000
|
|
2,176,000
|
|
1,830,000
|
|
1,710,000
|
|
Oil (Bbls)
|
|
56,000
|
|
51,000
|
|
41,000
|
|
37,000
|
|
41,000
|
|
Mcfe
|
|
1,880,000
|
|
2,234,000
|
|
2,422,000
|
|
2,050,000
|
|
1,960,000
|
|
Avg. sales price before
realized derivative gains & losses:
|
|
|
|
|
|
|
|
|
|
|
|
Per Mcf
|
|
$
|
7.65
|
|
$
|
5.79
|
|
$
|
6.24
|
|
$
|
6.55
|
|
$
|
5.02
|
|
Per Bbls
|
|
$
|
99.28
|
|
$
|
60.95
|
|
$
|
61.14
|
|
$
|
50.90
|
|
$
|
36.57
|
|
Avg. sales price after realized
derivative gains & losses:
|
|
|
|
|
|
|
|
|
|
|
|
Per Mcf
|
|
$
|
7.40
|
|
$
|
6.78
|
|
$
|
6.11
|
|
$
|
6.16
|
|
$
|
4.60
|
|
Per Bbls
|
|
$
|
99.28
|
|
$
|
60.95
|
|
$
|
61.14
|
|
$
|
50.90
|
|
$
|
36.57
|
|
Reserves(2):
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
15,525,000
|
|
16,973,000
|
|
16,005,000
|
|
15,516,000
|
|
15,273,000
|
|
Oil (Bbls)
|
|
710,000
|
|
591,000
|
|
422,000
|
|
386,000
|
|
407,000
|
|
Mcfe
|
|
19,788,000
|
|
20,517,000
|
|
18,537,000
|
|
17,835,000
|
|
17,717,000
|
|
Estimated future net revenues
|
|
$
|
53,655,000
|
|
$
|
101,501,000
|
|
$
|
84,861,000
|
|
$
|
136,878,000
|
|
$
|
77,612,000
|
|
Estimated future net revenues discounted at 10%
|
|
$
|
32,330,000
|
|
$
|
62,071,000
|
|
$
|
52,328,000
|
|
$
|
81,209,000
|
|
$
|
44,551,000
|
|
(1) The effect of the three for two stock splits in 2005 and 2004
are reflected in all historical share and per share data.
(2) See Footnote 10 to the Consolidated Financial Statements.
18
Table
of Contents
ITEM
7.
|
MANAGEMENTS DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
Operations
Summary
During 2008, the
companys operations were focused on its two core projects drilling
in the Mid-Continent area of the U.S. and application of its Calliope Gas
Recovery System. During the past several
years, the company has significantly expanded the volume and breadth of its
drilling activities by diversifying geographically, scientifically, and in
terms of capital, risk and reserve potential.
The company has also implemented a program to increase the volume of its
Calliope applications by joint venturing with other companies.
These activities are discussed in greater
detail below.
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 oil and natural gas 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 2009, 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 availability 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.
During the year, the company experienced
delays in securing delivery of production equipment, primarily compressors and
coil tubing. These delays extended the
time to conduct field operations in general, and in particular related to
installations of Calliope systems.
Results of Operations
In 2008, oil and gas revenues increased 22% to
$17,345,000 compared to $14,265,000 in 2007.
The increase was due to a 63% increase in oil prices and a 32% increase
in gas prices (excluding realized derivative gains and losses) partially offset
by a 16% decrease in gas equivalent production.
As the oil and gas price/volume table on page 22 shows, total gas
price realizations, which reflect realized derivative transactions, increased
9% to $7.40 per Mcf and oil price realizations increased to $99.28 per
barrel. The net effect of these price
realization changes was to increase oil and gas sales by $3,252,000 (vs.
$5,547,000 increase without derivative gains and losses). Realized derivative losses were $1,113,000 in
2008 compared to gains of $1,909,000 in 2007. During the same period, the companys gas
equivalent production fell 16% resulting in a decrease in oil and gas
sales of $2,467,000. Unrealized
derivative gains were $1,301,000 in FY 2008 compared to unrealized losses of
$454,000 in 2007. Investment and other
income decreased primarily due to market place declines impact on the companys
investments.
In 2008, total costs and
expenses rose 7.6% to $9,081,000 compared to $8,438,000 in 2007. Oil and gas production expenses increased 14%
due primarily to the addition of new wells and escalating field service
costs. General and administrative
expenses increased 17% primarily due to increases in salaries and
benefits, accounting and professional fees.
The effective tax rate was 26.5% and 28.7% for the 2008 and
2007 periods, respectively. The
variation from statutory rate is primarily due to percentage depletion.
In 2007, oil and gas revenues decreased 11% to
$14,265,000 compared to $16,103,000 in 2006.
The decrease was due to a 7% decline in gas prices (excluding realized
derivative gains and losses) and an 8% decrease in gas equivalent
production. As the oil and gas
price/volume table on page 22
19
Table
of Contents
shows, total gas price realizations, which
reflect realized hedging transactions, increased 11% to $6.78 per Mcf and
oil price realizations fell to $60.95 per barrel. The net effect of these price realization
changes was to increase oil and gas sales by $1,187,000 (vs. $988,000 decrease
without derivatives). Realized
derivative gains were $1,909,000 in 2007 compared to losses of $266,000 in
2006. During the same period, the
companys gas equivalent production fell 8% resulting in a decrease in oil
and gas sales of $849,000. Unrealized
derivative losses were $454,000 in FY 2007 compared to unrealized gains of
$1,327,000 in 2006. Investment and other
income increased primarily due to improved performance from the companys
investments.
In 2007, total costs and
expenses rose 1% to $8,438,000 compared to $8,340,000 for 2006. Oil and gas production expenses fell 1% due
primarily to reduced taxes associated with lower production. General and administrative expenses increased
8% primarily due to increases in professional fees related to compliance
with Sarbanes-Oxley regulations.
Interest expense relates to the Calliope exclusive license agreement
note payment. The effective tax rate was
28.7% and 27.6% for the 2007 and 2006 periods, respectively.
Liquidity and Capital Resources
At October 31, 2008, working capital
increased 93% to $24,160,000, compared to $12,511,000 at October 31, 2007,
primarily due to the sale of 1,150,000 shares of newly issued common
stock. For the year ended October 31,
2008, net cash provided by operating activities was $12,293,000 compared to
$11,674,000 for the same period in 2007.
The difference is primarily due to differences in non-cash unrealized
gains/losses from derivatives of $1,755,000 between 2007 and 2008, a change in
net proceeds from short-term investments from 2007 to 2008 of $3,480,000 and a
decrease in accounts payable and accrued liabilities from 2007 to 2008 of $285,000
and an increase in trade receivables from 2007 to 2008 of $759,000. Investing activities primarily included oil
and gas exploration and development expenditures, including Calliope, totaling
$12,528,000 and $9,144,000, in 2008 and 2007.
Financing activities primarily included the sale of common stock of
$15,095,000 net of transaction costs in 2008, the purchase of treasury stock of
$722,000 and $506,000 and proceeds from exercise of stock options of $637,000
and $368,000 in 2008 and 2007, respectively.
The companys earnings before unrealized
gains/losses on derivative contracts, interest, taxes, depreciation, depletion
and amortization, (EBITDA) was $11,744,000 for the year ended October 31, 2008
and $11,767,000 for the prior year.
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
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. A
reconciliation between EBITDA and net income is provided in the table below:
|
|
For The Year Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
5,993,000
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
Add
Back(Deduct):
|
|
|
|
|
|
|
|
Interest Expense
|
|
8,000
|
|
26,000
|
|
42,000
|
|
Income Tax
Expense
|
|
2,160,000
|
|
2,315,000
|
|
2,600,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
3,583,000
|
|
3,666,000
|
|
3,642,000
|
|
EBITDA
|
|
$
|
11,744,000
|
|
$
|
11,767,000
|
|
$
|
13,120,000
|
|
The average return, loss, on the companys
investments for the year ended October 31, 2008 and 2007 was a loss of
2.0% and a gain of 11.0%, respectively.
At October 31, 2008, approximately 92% of the investments consist
primarily of professionally managed limited partnerships which include
investments that are not publicly traded and may have less readily determinable
market values. The company is in the
process of liquidating these investments.
Remaining investments are directly invested in mutual funds and were
managed by professional money managers.
Most of the investments
20
Table
of Contents
are liquid and the company believes they
represent a responsible approach to cash management. In the companys opinion, the greatest
investment risk is the potential for negative market impact from unexpected,
major adverse news.
Existing working capital and anticipated cash flow are expected to be
sufficient to fund operations and capital requirements for at least the next 12
months. At October 31, 2008,
the company had no lines of credit or other bank financing arrangements except
for the hedging line of credit discussed in Note 1 to the Consolidated
Financial Statements. 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.
As of October 31, 2008, the company had the following known
contractual obligations:
|
|
Payments Due by Period
|
|
|
|
|
|
Less Than
|
|
1-3
|
|
3-5
|
|
More Than
|
|
|
|
Total
|
|
1 Year
|
|
Years
|
|
Years
|
|
5 Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exclusive
license obligation(1)
|
|
$
|
85,000
|
|
$
|
85,000
|
|
$
|
|
|
$
|
|
|
$
|
|
|
Operating lease obligations
|
|
78,000
|
|
32,000
|
|
46,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
163,000
|
|
$
|
117,000
|
|
$
|
46,000
|
|
$
|
|
|
$
|
|
|
(1)
|
Subsequent to
October 31, 2008, the company purchased the patents underlying the
license agreement and eliminated this commitment.
|
Impact of Current Credit Markets
As the company exited the fourth quarter of
fiscal 2008, oil and natural gas prices had declined sharply from their recent
record levels. In addition, recent
problems in the credit markets, steep stock market declines, financial
institution failures and government bail-outs provide evidence of a weakening
United States and global economy. As a
result of the market turmoil and price decreases, oil and gas companies with
high debt levels and lack of liquidity have been and will continue to be
negatively impacted. However, the
company does not expect to be significantly impacted by these recent
events. The company has no debt and is
in a financially-strong position due to its past strategies. The company anticipates its cash on hand and
operating cash flow will adequately fund planned capital expenditures and other
capital uses over the near-term.
Off-Balance Sheet Arrangements
The company has no off-balance sheet arrangements at October 31,
2008.
Product Prices and Production
Refer to Item 1., Markets and Customers, for discussion of oil and gas
prices and marketing.
21
Table
of Contents
Oil
and natural gas sales volume and price realization comparisons for the indicated
years ended October 31 are set forth below. Price realizations include realized hedging
gains and losses.
|
|
2008
|
|
2007
|
|
2006
|
|
Price
Realization
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
Net wellhead
price received (per Mcf)
|
|
$
|
7.65
|
|
$
|
5.79
|
|
$
|
6.23
|
|
Effects of
derivative gains (losses) (per Mcf)(1)
|
|
(0.25
|
)
|
0.99
|
|
(0.12
|
)
|
Net price
realization (per Mcf)
|
|
$
|
7.40
|
|
$
|
6.78
|
|
$
|
6.11
|
|
% Change
|
|
9
|
%
|
11
|
%
|
(1
|
)%
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
Net wellhead
price received (per Bbl)
|
|
$
|
99.28
|
|
$
|
60.95
|
|
$
|
61.14
|
|
Effects of
derivative gains (losses) (per Bbl)
|
|
|
|
|
|
|
|
Net price
realization (per Bbl)
|
|
$
|
99.28
|
|
$
|
60.95
|
|
$
|
61.14
|
|
% Change
|
|
63
|
%
|
0
|
%
|
20
|
%
|
|
|
|
|
|
|
|
|
Total
Sales Volumes
|
|
|
|
|
|
|
|
Natural Gas
(Mcf)
|
|
1,545,000
|
|
1,926,000
|
|
2,176,000
|
|
% Change
|
|
(20
|
)%
|
(11
|
)%
|
19
|
%
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
56,000
|
|
51,000
|
|
41,000
|
|
% Change
|
|
9
|
%
|
24
|
%
|
11
|
%
|
|
|
|
|
|
|
|
|
Total equivalent
production (Mcfe)
|
|
1,880,000
|
|
2,234,000
|
|
2,422,000
|
|
% Change
|
|
(16
|
)%
|
(8
|
)%
|
18
|
%
|
(1)
Effects of realized gains (losses) on natural gas
hedging derivative contracts.
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.
Derivative transactions typically take the form of forward short positions
and collars on the NYMEX futures market, and are closed by purchasing
offsetting positions.
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.
Open derivative contracts at October 31,
2008 are indexed to the NYMEX and are represented by short positions. Actual price realizations in the companys
principal areas of operations (primarily Oklahoma) are expected to be 15% to
17% below NYMEX prices primarily due to basis differentials. However, regional weather conditions and
other economic factors, such as the current delay in completion of the eastern
extension of the Rocky Mountain Express gas pipeline, resulting in excess
natural gas supplies to the mid-continent region, can periodically result in
substantially higher basis differentials.
At October 31, 2008, the Oklahoma basis differential was 56% of the
NYMEX price.
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 $5,900,000 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 November 15, 2010.
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Oil and Gas Activities
Capital
Spending.
Capital spending in 2008 totaled $14,948,000,
consisting primarily of additions to oil and gas properties. Subsequent to fiscal year end, the company
purchased all of the Calliope Gas Recovery System patents and all of the
remaining third party right, title and interest in the Calliope
technology. In addition, the company
purchased all of the patents for its new Tractor Seal fluid lift technology
together with all third party right, title and interest in the technology The Tractor Seal technology is currently in
the development state and, except for the patents, the company has not yet
provided public disclosure regarding the technology. The total purchase price was $4,500,000.
Drilling Activities
Northern Anadarko Basin
The company owns a significant inventory of
acreage (approximately 70,000 gross acres) located along the northern
portion of the Anadarko Basin where it conducts an active drilling
program. Wells generally target the Morrow,
Oswego and Chester formations between 7,000 and 11,000 feet. The company expects to drill a substantial
number of additional wells on this acreage.
During the year, the company drilled thirteen
wells on its Oklahoma properties. Of
those, eleven are producers and two were dry holes. Subsequent to fiscal year end, the company
drilled three wells in Oklahoma, all of which appear to be commercial
producers. During the final 24-hour
test, a new deeper pool discover well on the companys 1,280 gross acre
PoolProffitt prospect produced oil and gas at high rates from the Hunton
formation with virgin pressure. Electric
logs and drilling and completion data indicate that the Chester and
Mississippian formations are also productive in the well. However, completion of the up-hole zones will
be delayed in order to more fully evaluate the Hunton zone potential. The company owns a 47% working interest and
is the operator. About one mile to the
north on the PoolProffitt prospect, another well is currently being completed
in the Mississippian and Chester formations.
The company owns a 73% working interest and is the operator. A third well is currently being completed for
production in Carter County in which the company owns a 44% working
interest. The new well will develop two
deeper Deese formation oil sands and the Woodford formation, both of which
electric logs indicate are productive.
In Southern Oklahoma, the company is
participating in three waterflood projects as part of its overall strategy to
improve the oil ratio in its reserve base.
In Carter County, CREDO owns 17% of the Southeast Hewitt waterflood unit
which has already produced 703,000 barrels of oil. The company also owns about 22% in
Phase 1, and 12.3% in Phase 2, of a Twin Forks Deese sand waterflood unit
that has recently been formed. In Love
County, CREDO owns 13% in Phase 1, and 9.5% in Phase 2, of the Eastman
Hills waterflood unit that is installed and operational.
In Hemphill County, Texas, the company has
purchased interests in over 6,000 gross acres and has taken over as
operator of 11 wells. The new acreage
complements the companys existing prospect acreage and brings its total
acreage in the area to approximately 9,000 gross acres.
South Texas
In South Texas, the initial test well on the Gemini Prospect resulted
in a dry hole. The 17,000-foot well confirmed the seismic interpretation and
found porous sand. However, the sand was
water wet and the well was plugged and abandoned. CREDO received approximately
$1,300,000 of cash for the multiple prospect package and retained an
11.25% carried interest in the test well.
The prospect package consists of two additional Deep Wilcox prospects
located north of the Gemini Prospect.
These two prospects are structurally different and unique compared to
the Gemini Prospect. Those prospects are
being further evaluated, and if drilled, CREDO will have an 11.25% carried
interest in the first well.
Elsewhere in South Texas, the company has purchased a 15.5% working interest in
the Escobas Field. A new 15,500-foot Wilcox well has been drilled in which the
company has a small carried interest.
That well is currently producing 2.7 MMcfd (million cubic of gas per
day) on a 12/64ths choke.
Central Kansas Uplift
The company further
expanded the volume and breadth of its exploration program with a new drilling
project in central Kansas and Nebraska.
The project provides
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diversification to the
companys drilling program geographically and scientifically through the use of
3-D seismic to identify shallow oil prospects.
The acreage is located in prolific oil producing areas where 3-D seismic
has proven effective in identifying satellite structures near mature producing
fields. Higher oil prices have justified
using 3-D seismic technology to locate undrilled structures that are very
difficult to find with old technology.
Drilling targets the Lansing-Kansas City and Arbuckle formations at
about 4,000 feet and, compared to the companys Northern Anadarko Basin
and South Texas projects, is relatively low cost, low risk, and exclusively
targets oil reserves in an effort to bring better product balance to the
companys reserve base. The company has
assembled about 141,000 gross (66,000 net) acres and is continuing to seek
opportunities to increase its exposure to the play. The company owns working interests in the
existing prospects ranging from 12.5% to 85%. The companys recent drilling results have
improved significantly as it continues to find the keys to successful seismic
and geologic interpretation. At October 31,
2008, the company has participated in drilling a total of 29 wells on the
acreage, of which 48% have been successfully completed as oil producers. Well depths range from 3,500 to 4,000 feet
and drilling costs are moderate.
The company has recently
drilled a wildcat well on a 2,150 gross acre seismically defined prospect.
Production pipe has been set through the Lansing-Kansas City formation. The well is classified as a tight hole,
meaning that detailed information is not being released for proprietary
business reasons. CREDO owns an 85%
working interest in the prospect and is the operator. Development drilling is scheduled.
North Dakota
During 2008 the
company expanded its exploration program into North Dakota and acquired
approximately 4,200 gross acres (4,100 net) in the Fort Berthold Indian
Reservation area of the Bakken shale play.
Calliope Gas Recovery
Technology
Calliopes Track Record
The companys current compilation of Calliopes
track record shows Calliope installations on 25 wells located in Oklahoma,
Texas and Louisiana. The Calliope wells
produce from both sandstone and carbonate reservoirs including the Chester,
Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria, Redfork and Springer
formations. The Calliope wells range in
depth from 6,400 to 18,400 feet. These
wells represent rigorous applications for Calliope because at the time
Calliope was installed, 14 of the wells were dead (an average of two to
three years), nine were uneconomic and two were marginal. In addition, prior to the time Calliope was
installed, many of the reservoirs were damaged by the parting shots of
previous operators. Twenty-three of the wells were acquired from
other operators after the operators had given-up on these wells. The previous operators were mostly medium
to large independent oil and gas companies.
Initial Calliope production rates range up to
650 Mcfd and average per well Calliope reserves for non-experimental wells
are estimated to be 1.0 Bcf. One of the
companys early Calliope installations, the J.C. Carroll well, has now produced
over 1.1 billion cubic feet of gas using Calliope.
The 25 Calliope applications are grouped into
two categories experimental wells and non-experimental wells, also referred
to as go-forward applications. Eleven
of the 25 wells are experimental applications and 14 are go-forward
applications. Experimental wells
generally represent the first experimental application of a Calliope
configuration in a wellbore. For
example, the first installation of Calliope inside a particular tubing size is
classified as an experimental application.
Calliope has achieved compelling results on
these less than ideal wells. For
example, the entire group of 14 non-experimental wells were producing a total
of only 88 Mcfd when Calliope was installed.
Without Calliope, the wells represented a substantial plugging
liability. However, with Calliope, those
same 14 wells have now produced an approximate incremental 4.2 Bcfe to
date, and they are still producing substantial quantities of gas. With Calliope and depending on natural gas
prices at the time gas is produced, the 14 wells are projected to have
estimated ultimate incremental Calliope reserves ranging from 11 to 14 Bcfe
depending primarily on the effect that natural gas prices have on well
economics.
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Calliope has proven to be a low risk and low
cost liquid lift technology. The average
cost of a Calliope system is $400,000 for a 12,000-foot application. Based on average per well Calliope reserves
of 1.0 Bcfe for go-forward applications, cost of Calliope in terms of units of
natural gas reserves added is low compared to industry averages. Based on current natural gas prices, Calliope
can economically be installed on wells which will yield significantly less than
1.0 Bcf of Calliope reserves. This
will enable the company to significantly expand the range of Calliope
applications to include many low permeability reservoirs, possibly including
those in shale and other resource plays.
Realizing Calliopes value continues to be one
of the companys top priorities. The
company has been focused on three fronts to increase the number of Calliope
installations: expanding the geographic
region for purchasing Calliope candidate wells from third parties, joint
ventures with larger companies, and drilling wells into low-pressure gas
reservoirs for the purpose of using Calliope to recover stranded natural gas
reserves.
Purchasing Calliope Candidate
Wells
The company
has Calliope operations in Oklahoma, Texas and Louisiana, and considers Texas
and Louisiana to be very fertile areas for Calliope. Accordingly, the company opened a Houston
office to focus exclusively on purchasing wells for Calliope and on Calliope
joint ventures.
During most of 2008, higher natural gas prices made it increasingly
difficult for the company to purchase wells for its Calliope system. In addition, higher gas prices provided the
incentive for other companies to perform high risk procedures (parting shots)
in an attempt to revive wells prior to abandoning or selling the wells. These parting shots often result in severe
reservoir damage that renders wells unsuitable for Calliope. Accordingly, viable Calliope candidate wells
available to be purchased by the company were very restricted.
Joint Ventures With Third Parties
In an effort to increase the number of
Calliope installations, the company has been discussing joint ventures
with larger companies. Presentations
have been made to a select group of companies, including majors and large
independents. All of the companies have
expressed an interest in Calliope. Two
joint venture agreements were completed during 2007, and joint venture
discussions are in progress with a number of companies, including evaluation of
candidate wells.
Calliope Drilling Project
The company believes that there is a huge
amount of gas stranded in abandoned and low pressure reservoirs that, depending
on natural gas prices, can be economically recovered using Calliope. It believes drilling new wells for Calliope
into such reservoirs will provide a repeatable opportunity to lease large areas
for systematic re-development. In
addition, new wells allow optimum casing and tubular sizes to be installed
which will substantially improve reserves and production compared to installing
Calliope on existing wells where undersized tubulars often restrict Calliopes
optimum performance.
Current low natural gas prices may delay such
drilling projects until prices recover.
For example, the company entered into a joint
venture to purchase an 11,000-foot well located in East Texas. The previous operator drilled the well and
encountered low reservoir pressure.
After unsuccessful attempts to make the well produce, the operator sold
the well to the company joint venture for salvage value. Calliope was installed and immediately made
the well a highly commercial producer.
The well provided a successful test of the Calliope drilling concept and
demonstrated that Calliope will successfully solve liquid loading problems that
are difficult to address with other liquid lift technologies.
Reserves.
Refer
to Item 2, Properties, Significant Properties, Estimated Proved Oil and Gas
Reserves and Future Net Revenues, for information regarding oil and gas
reserves.
Critical Accounting Policies and Estimates
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
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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 critical 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 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.
Periodically market conditions can result in a
significant increase in the differential between the NYMEX price for natural
gas and the regional price index that is utilized to value the companys reserves.
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 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.
The companys reserves, and reserve values,
are concentrated in 68 properties (Significant Properties). Some of the Significant Properties are
individual wells and others are multi-well
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properties.
At October 31, 2008, the Significant Properties represent 24% of
the companys total properties but a disproportionate 80% of the discounted
value (at 10%) of the companys reserves.
Individual wells on which the companys patented Calliope liquid lift
system is installed comprise 16% of the Significant Properties and represent
14% of the discounted reserve value of such properties. Reserves added in 2008 comprise 25% of the
Significant Properties and represent 26% of the discounted value of such
properties.
Estimates of reserve quantities and values for
certain Significant Properties must be viewed as being subject to significant
change as more data about the properties becomes available. Such properties
include wells with limited production histories and properties with proved
undeveloped or proved non-producing reserves.
In addition, the companys patented Calliope liquid lift system is
generally installed on mature wells. As
such, they contain older down-hole equipment that is more subject to failure
than new equipment. The failure of such
equipment, particularly casing, can result in complete loss of a well. Historically, performance of the companys
wells has not caused significant revisions in its proved reserves.
Price changes will affect the economic lives
of oil and gas properties and, therefore, price changes may cause reserve
revisions. Price changes have resulted
in estimated reserve revisions in fiscal year 2008. Compared with fiscal year end 2007, natural
gas prices have decreased 30% and oil prices have decreased 22%. These price decreases resulted in a 14.5%
reduction in estimated proved reserves.
One measure of the life of the companys
proved reserves can be calculated by dividing proved reserves at fiscal year
end 2008 by production for fiscal year 2008.
This measure yields an average reserve life of 10.5 years. Since this measure is an average, by
definition, some of the companys properties will have a life shorter than the
average and some will have a life longer than the average. The expected economic lives of the companys
properties may vary widely depending on, among other things, the size and
quality, natural gas and oil prices, possible curtailments in consumption by
purchasers, and changes in governmental regulations or taxation. As a result, the companys actual future net
cash flows from proved reserves could be materially different from its
estimates.
Asset Retirement Obligations.
Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations requires that the company estimate the future
cost of asset retirement obligations, discount that cost to its present value,
and record 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, 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.
Recent Accounting Pronouncements
In March 2008, the FASB issued Statement No. 161
(FAS 161), Disclosures about Derivative Instruments and Hedging Activities, an
amendment of FASB Statement No. 133, which requires additional
disclosures about the objectives of using derivative instruments, the method by
which the derivative instruments and related hedged items are accounted for
under FASB Statement No. 133 and its related interpretations, and the
effect of derivative instruments and related hedged items on financial
position, financial performance and cash flows.
FAS 161 also requires disclosure of the fair values of derivative
instruments and their gains and losses in a tabular format. FAS 161 is effective for fiscal years
beginning after November 15, 2008 and interim periods within those fiscal
years (fiscal 2010 for the company). The
Company is in the process of determining the effects the adoption of FAS 161
will have on its financial statement disclosures.
In December, 2007 the FASB issued FSAS No. 159,
The Fair Value Option for Financial Assets and
Financial Liabilities Including an amendment of FASB Statement No. 115.
This Statement provides all
entities with an option to report selected financial assets and liabilities at
fair value. The Statement is effective
as of the beginning of an entitys first fiscal year beginning after
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November 15, 2007, with early adoption available in certain
circumstances. The company does not
expect to elect the options provided by FAS 159.
In December, 2007 the FASB issued FSAS No. 157
, Fair Value
Measurements
. This Statement
does not require any new fair value measurements, but rather, it provides
enhanced guidance to other pronouncements that require or permit assets or liabilities
to be measured at fair value. However,
the application of this Statement may change how fair value is determined. The Statement is effective for financial
statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years.
The company will adopt FAS 157 for the first quarter of fiscal 2009 and
does not expect a material impact on its financial statements.
In November 2007, the FASB issued SFAS No. 141
(revised 2007),
Business Combination
(FAS 141(R)) and SFAS No. 160,
Noncontrolling
Interests in Consolidated Financial Statements, an amendment of ARB No. 51
(FAS 160). FAS 141(R) will
change how business acquisitions are accounted for and will impact financial
statements both on the acquisition date and in subsequent periods. FAS 160 will change the accounting and
reporting for minority interests, which will be recharacterized as
noncontrolling interests and classified as a component of equity. FAS 141(R) and FAS 160 are
effective for both public and private companies for fiscal years beginning on
or after December 15, 2008 (fiscal 2010 for the Company). FAS 141(R) will be applied
prospectively. FAS 160 requires
retroactive adoption of the presentation and disclosure requirements for
existing minority interests. All other
requirements of FAS 160 will be applied prospectively. Early adoption is prohibited for both
standards. Management is currently
evaluating the requirements of FAS 141(R) and FAS 160 and has
not yet determined the impact on its financial statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The company manages exposure to commodity
price fluctuations by periodically hedging a portion of estimated natural gas
production through the use of derivatives, typically collars and forward short
positions in the NYMEX futures market.
At October 31, 2008 open derivative contracts covered
830 MMBtus at NYMEX prices ranging from $8.00 to $10.60 and covered the
production months of November, 2008 through October, 2009. See Managements Discussion and Analysis of
Financial Condition and Results of OperationsProduct Prices and Production
for more information on the companys hedging activities.
ITEM 8.
FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA
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CONSOLIDATED
BALANCE SHEETS
October 31, 2008 and
2007
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
2008
|
|
2007
|
|
ASSETS
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
22,332,000
|
|
$
|
7,285,000
|
|
Short-term
investments
|
|
3,044,000
|
|
6,383,000
|
|
Receivables:
|
|
|
|
|
|
Trade
|
|
995,000
|
|
602,000
|
|
Accrued oil and
gas sales
|
|
1,733,000
|
|
1,647,000
|
|
Derivative
assets
|
|
1,745,000
|
|
443,000
|
|
Other current assets
|
|
205,000
|
|
55,000
|
|
Total current
assets
|
|
30,054,000
|
|
16,415,000
|
|
|
|
|
|
|
|
Long-term
assets:
|
|
|
|
|
|
Oil and gas
properties, at cost, using full cost method:
|
|
|
|
|
|
Unevaluated oil
and gas properties
|
|
12,280,000
|
|
7,791,000
|
|
Evaluated oil
and gas properties
|
|
59,730,000
|
|
51,691,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(25,554,000
|
)
|
(22,108,000
|
)
|
Net oil and gas
properties
|
|
46,456,000
|
|
37,374,000
|
|
Intangible
assets, net of accumulated amortization of $595,000 in 2008 and $501,000 in
2007
|
|
1,079,000
|
|
198,000
|
|
Compressor and
tubular inventory to be used in development of oil and gas properties
|
|
2,592,000
|
|
1,090,000
|
|
Other, net
|
|
379,000
|
|
272,000
|
|
Total assets
|
|
$
|
80,560,000
|
|
$
|
55,349,000
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
3,857,000
|
|
$
|
1,639,000
|
|
Revenue
distribution payable
|
|
982,000
|
|
979,000
|
|
Other accrued
liabilities
|
|
931,000
|
|
852,000
|
|
Income taxes
payable
|
|
124,000
|
|
434,000
|
|
Total current
liabilities
|
|
5,894,000
|
|
3,904,000
|
|
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
|
|
Deferred income
taxes, net
|
|
11,117,000
|
|
9,204,000
|
|
Exclusive
license obligation, less current obligations of $85,000 in 2008 and $77,000
in 2007
|
|
|
|
85,000
|
|
Asset retirement
obligation
|
|
1,338,000
|
|
1,016,000
|
|
Total
liabilities
|
|
18,349,000
|
|
14,209,000
|
|
|
|
|
|
|
|
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 shares issued in
2008 and 9,510,000 shares issued in 2007
|
|
1,066,000
|
|
951,000
|
|
Capital in
excess of par value
|
|
31,352,000
|
|
15,913,000
|
|
Treasury stock,
at cost, 223,000 shares in 2008, and 215,000 shares in 2007
|
|
(982,000
|
)
|
(506,000
|
)
|
Retained
earnings
|
|
30,775,000
|
|
24,782,000
|
|
Total
stockholders equity
|
|
62,211,000
|
|
41,140,000
|
|
|
|
|
|
|
|
Total
liabilities and stockholders equity
|
|
$
|
80,560,000
|
|
$
|
55,349,000
|
|
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENTS OF OPERATIONS
For
the Three Years Ended October 31, 2008
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
Oil and
gas sales
|
|
$
|
17,345,000
|
|
$
|
14,265,000
|
|
$
|
16,103,000
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
Oil and gas
production
|
|
3,861,000
|
|
3,375,000
|
|
3,407,000
|
|
Depreciation,
depletion and amortization
|
|
3,583,000
|
|
3,666,000
|
|
3,642,000
|
|
General and
administrative
|
|
1,637,000
|
|
1,397,000
|
|
1,291,000
|
|
|
|
9,081,000
|
|
8,438,000
|
|
8,340,000
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
8,264,000
|
|
5,827,000
|
|
7,763,000
|
|
|
|
|
|
|
|
|
|
Other
income and (expense)
|
|
|
|
|
|
|
|
Gains (losses)
from derivatives Realized
|
|
(1,113,000
|
)
|
1,909,000
|
|
(266,000
|
)
|
Unrealized
|
|
1,301,000
|
|
(454,000
|
)
|
1,327,000
|
|
|
|
188,000
|
|
1,455,000
|
|
1,061,000
|
|
|
|
|
|
|
|
|
|
Investment and
other income (loss)
|
|
(291,000
|
)
|
819,000
|
|
654,000
|
|
Interest
(expense)
|
|
(8,000
|
)
|
(26,000
|
)
|
(42,000
|
)
|
|
|
(111,000
|
)
|
2,248,000
|
|
1,673,000
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
8,153,000
|
|
8,075,000
|
|
9,436,000
|
|
Income taxes
|
|
(2,160,000
|
)
|
(2,315,000
|
)
|
(2,600,000
|
)
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
5,993,000
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
$
|
.62
|
|
$
|
.62
|
|
$
|
.74
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
$
|
.61
|
|
$
|
.61
|
|
$
|
.72
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares of common stock and dilutive securities:
|
|
|
|
|
|
|
|
Basic
|
|
9,697,000
|
|
9,280,000
|
|
9,207,000
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
9,758,000
|
|
9,395,000
|
|
9,482,000
|
|
See accompanying notes to consolidated financial statements.
30
Table
of Contents
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS EQUITY
For the Three Years Ended October 31, 2008
CREDO PETROLEUM
CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
Excess Of
|
|
Treasury
|
|
Retained
|
|
Stockholders
|
|
|
|
Shares
|
|
Amount
|
|
Par Value
|
|
Stock
|
|
Earnings
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
October 31, 2005
|
|
9,510,000
|
|
$
|
951,000
|
|
$
|
13,935,000
|
|
$
|
(125,000
|
)
|
$
|
12,186,000
|
|
$
|
26,947,000
|
|
Net income
|
|
|
|
|
|
|
|
|
|
6,836,000
|
|
6,836,000
|
|
Exercise of
common stock options
|
|
|
|
|
|
710,000
|
|
125,000
|
|
|
|
835,000
|
|
Compensation
expense related to stock options
|
|
|
|
|
|
209,000
|
|
|
|
|
|
209,000
|
|
Tax Benefit for FAS
123R option expense
|
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
October 31, 2006
|
|
9,510,000
|
|
951,000
|
|
14,794,000
|
|
|
|
19,022,000
|
|
34,767,000
|
|
Net income
|
|
|
|
|
|
|
|
|
|
5,760,000
|
|
5,760,000
|
|
Purchase of
treasury stock
|
|
|
|
|
|
|
|
(506,000
|
)
|
|
|
(506,000
|
)
|
Exercise of
common stock options
|
|
|
|
|
|
368,000
|
|
|
|
|
|
368,000
|
|
Compensation
expense related to stock options
|
|
|
|
|
|
153,000
|
|
|
|
|
|
153,000
|
|
Tax benefit from
exercise of stock options
|
|
|
|
|
|
598,000
|
|
|
|
|
|
598,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
October 31, 2007
|
|
9,510,000
|
|
951,000
|
|
15,913,000
|
|
(506,000
|
)
|
24,782,000
|
|
41,140,000
|
|
Net income
|
|
|
|
|
|
|
|
|
|
5,993,000
|
|
5,993,000
|
|
Sale of common
stock
|
|
1,150,000
|
|
115,000
|
|
16,560,000
|
|
|
|
|
|
16,675,000
|
|
Payment of
transactions costs
|
|
|
|
|
|
(1,580,000
|
)
|
|
|
|
|
(1,580,000
|
)
|
Purchase of
treasury stock
|
|
|
|
|
|
|
|
(722,000
|
)
|
|
|
(722,000
|
)
|
Exercise of
common stock options
|
|
|
|
|
|
294,000
|
|
246,000
|
|
|
|
540,000
|
|
Compensation
expense related to stock options
|
|
|
|
|
|
68,000
|
|
|
|
|
|
68,000
|
|
Tax benefit from
exercise of stock options
|
|
|
|
|
|
97,000
|
|
|
|
|
|
97,000
|
|
Balance,
October 31, 2008
|
|
10,660,000
|
|
$
|
1,066,000
|
|
$
|
31,352,000
|
|
$
|
(982,000
|
)
|
$
|
30,775,000
|
|
$
|
62,211,000
|
|
See accompanying notes to consolidated financial statements.
31
Table
of Contents
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Three Years Ended October 31, 2008
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
2008
|
|
2007
|
|
2006
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
Net income
|
|
$
|
5,993,000
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
Adjustments to
reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
3,583,000
|
|
3,666,000
|
|
3,642,000
|
|
ARO liability
accretion
|
|
51,000
|
|
36,000
|
|
40,000
|
|
Unrealized
(gains) losses from derivatives
|
|
(1,301,000
|
)
|
454,000
|
|
(1,327,000
|
)
|
Deferred income
taxes
|
|
1,913,000
|
|
1,763,000
|
|
2,001,000
|
|
(Gain) loss on
short-term investments
|
|
618,000
|
|
(603,000
|
)
|
(480,000
|
)
|
Compensation
expense related to stock options granted
|
|
68,000
|
|
153,000
|
|
209,000
|
|
Other
|
|
63,000
|
|
26,000
|
|
(22,000
|
)
|
Changes in
operating assets and liabilities:
|
|
|
|
|
|
|
|
Proceeds from
short-term investments
|
|
2,721,000
|
|
1,544,000
|
|
551,000
|
|
Purchase of short-term
investments
|
|
|
|
(1,700,000
|
)
|
(200,000
|
)
|
Trade
receivables
|
|
(393,000
|
)
|
316,000
|
|
226,000
|
|
Accrued oil and
gas sales
|
|
(86,000
|
)
|
175,000
|
|
813,000
|
|
Other current
assets
|
|
(150,000
|
)
|
16,000
|
|
174,000
|
|
Accounts payable
and accrued liabilities
|
|
(477,000
|
)
|
(192,000
|
)
|
667,000
|
|
Income taxes
payable
|
|
(310,000
|
)
|
260,000
|
|
(157,000
|
)
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
12,293,000
|
|
11,674,000
|
|
12,973,000
|
|
|
|
|
|
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
Additions to oil
and gas properties
|
|
(9,544,000
|
)
|
(9,144,000
|
)
|
(11,746,000
|
)
|
Proceeds from
sale of oil and gas properties
|
|
|
|
310,000
|
|
670,000
|
|
Changes in other
long-term assets
|
|
(1,652,000
|
)
|
84,000
|
|
(20,000
|
)
|
Additions to
intangible assets
|
|
(975,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
(12,171,000
|
)
|
(8,750,000
|
)
|
(11,096,000
|
)
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
Sale of common
stock
|
|
15,095,000
|
|
|
|
|
|
Proceeds from
exercise of stock options
|
|
637,000
|
|
368,000
|
|
835,000
|
|
Purchase of
treasury stock
|
|
(722,000
|
)
|
(506,000
|
)
|
|
|
Principal
payment on exclusive license obligation
|
|
(85,000
|
)
|
(78,000
|
)
|
(70,000
|
)
|
|
|
|
|
|
|
|
|
Net
cash provided (used) by financing activities
|
|
14,925,000
|
|
(216,000
|
)
|
765,000
|
|
|
|
|
|
|
|
|
|
Increase
in cash and cash equivalents
|
|
15,047,000
|
|
2,708,000
|
|
2,642,000
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents:
|
|
|
|
|
|
|
|
Beginning of
period
|
|
7,285,000
|
|
4,577,000
|
|
1,935,000
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
22,332,000
|
|
$
|
7,285,000
|
|
$
|
4,577,000
|
|
|
|
|
|
|
|
|
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
Cash paid during
the period for income taxes
|
|
$
|
447,000
|
|
$
|
371,000
|
|
$
|
620,000
|
|
Cash paid during
the period for interest
|
|
$
|
8,000
|
|
$
|
26,000
|
|
$
|
30,000
|
|
Additions to
oil & gas properties included in current liabilities
|
|
$
|
3,127,000
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
32
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
October 31,
2008
CREDO PETROLEUM CORPORATION AND SUBSIDIARIES
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of
Operations and Basis of Presentation
The
consolidated financial statements include the accounts of CREDO Petroleum
Corporation and its wholly owned subsidiaries (the company). The company engages in oil and gas
acquisition, exploration, development and production activities in the United
States. All significant intercompany
transactions have been eliminated. All
references to years in these Notes refer to the companys fiscal October 31
year.
Cash, Cash Equivalents, and Short-Term Investments
Cash equivalents consist of liquid investments with original maturities
of three months or less. At October 31, 2008,
approximately 92% of 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. The company is in the process of liquidating
these investments. The partnerships are
invested primarily in financial instruments.
Unrealized gains on limited partnerships are not significant. Remaining short term investments are directly
invested in mutual funds and were managed by professional money managers. Short-term investments are classified as trading
and are stated at fair value with realized and unrealized gains and losses
immediately recognized.
Concentration of Credit
Risk
Substantially all of the
companys receivables are within the oil and natural gas industry, primarily
from purchasers of oil and gas and from joint interest owners. These receivables are due from many companies
with collectability being dependent upon the financial wherewithal of each
individual company as well as the general economic conditions of the
industry. The receivables are not
collateralized. In any event that
monthly JIB receivables become delinquent, the company has the ability to net
the receivables against revenue distributions to the delinquent account. To date the company has had minimal bad
debts.
Fair Value of Financial Instruments
The companys financial instruments including cash and cash equivalents,
accounts receivable and accounts payable are carried at cost, which
approximates fair value due to the short-term maturity of these instruments.
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 separate
expenses. Revenue is recorded in the
month production is delivered to the purchaser at which time title changes
hands, the sales method. Payment is
generally received between 30 and 90 days after the date of production. 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, or when better
information is available.
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
33
Table of
Contents
pre-determined and published monthly index price. The terms of these contracts have not had an
effect on how the company recognizes its revenue.
Accounting
Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those
estimates. Significant estimates with
regard to these financial statements include the estimate of proved oil and
natural gas reserve quantities and the related present value of estimated
future net cash flows therefrom.
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.
Depletion costs per Mcfe (thousand cubic feet equivalent) were $1.83,
$1.59 and $1.46 in 2008, 2007 and 2006 respectively. A change in proved reserves without a
corresponding change in capitalized costs will cause the depletion rate to
increase or decrease.
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.
For the years ended October 31, 2008, 2007, and 2006, the company
capitalized $403,000, $316,000, and $330,000 of general and administrative
costs, respectively.
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 considers price increases subsequent to
the 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 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.
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
34
Table of
Contents
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 Note 9 for further discussion of reserve estimates and the related
uncertainties.
Intangible
Assets
Intangible
assets are carried at cost less accumulated amortization. Amortization is calculated on a ratable basis
over the expected useful life of the asset.
Intangible assets are periodically reviewed for indications of
impairment and if impairment has occurred, the asset is written down to its
expected realizable value.
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, 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.
A reconciliation of the companys asset retirement obligation liability
is as follows:
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Beginning asset
retirement obligation
|
|
$
|
1,016,000
|
|
$
|
954,000
|
|
Accretion
expense
|
|
51,000
|
|
36,000
|
|
Obligations
incurred
|
|
259,000
|
|
46,000
|
|
Obligations
settled
|
|
|
|
|
|
Change in
estimate
|
|
12,000
|
|
(20,000
|
)
|
Ending asset
retirement obligation
|
|
$
|
1,338,000
|
|
$
|
1,016,000
|
|
Environmental Matters
Environmental costs are expensed or capitalized depending on their
future economic benefit. Costs that relate to an existing condition caused by
past operations with no future economic benefit are expensed. Liabilities for future expenditures of a
non-capital nature are recorded when future environmental expenditures and/or
remediation is deemed probable and the costs can be reasonably estimated. Costs of future expenditures for
environmental remediation obligations are not discounted to their present
value.
Long-Lived Assets
The company applies SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, to long-lived
assets not included in oil and gas properties.
Under SFAS No. 144, all long-lived assets are tested for
recoverability whenever events or changes in circumstances indicate that their
carrying value may not be recoverable.
The carrying amount of a long-lived asset is not recoverable if it
exceeds the sum of the undiscounted cash flows expected to result from its use
and eventual disposition. An impairment
loss is recognized when the carrying value of a long-lived asset is not
recoverable and exceeds its fair value.
35
Table of
Contents
Income Taxes
The company accounts for income taxes in accordance with SFAS No. 109,
Accounting for Income Taxes, which requires the use of the asset and
liability method of computing deferred income taxes. The objective of the asset and liability
method is to establish deferred tax assets and liabilities for the temporary
differences between the book basis and the tax basis of the companys assets
and liabilities at enacted tax rates expected to be in effect when such amounts
are realized or settled.
Natural Gas
Derivatives
The
company periodically uses derivatives as economic hedges of the price of a
portion of its estimated natural gas production when the potential for
significant downward price movement is anticipated. These transactions typically take the form of
forward short positions and collars based upon the NYMEX futures market, 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.
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.
The
company had realized hedging losses of $1,113,000 in 2008, gains of $1,909,000
in 2007 and losses of $266,000 in 2006.
The company had unrealized gains on derivative contracts in 2008 of
$1,301,000, $1,327,000 in 2006, and losses of $454,000 in 2007. At October 31, 2008 open derivative
contracts covered 830 MMBtus at NYMEX basis prices ranging from $8.00 to
$10.60, and cover the production months of November 2008 through October 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 $5,900,000 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 November 15, 2010.
Stock-Based Compensation
The
companys 2007 Stock Option Plan (the Plan), was approved by the shareholders
at the Annual Meeting of Shareholders on March 22, 2007 and authorizes the
granting of incentive and nonqualified options to purchase shares of the
companys common stock. The maximum
number of shares that may be made subject to grants is 1,000,000. The Plan is administered by the Board of
Directors which determines the terms pursuant to which any option is granted. The Plan provides that upon a change in
control of the company, options then outstanding will immediately vest and the
company will take such actions as are necessary to make all shares subject to
options immediately salable and transferable.
Plan activity is set forth below.
The companys 1997 Stock Option Plan, which was similar in all respects
to the 2007 Plan, expired on July 29, 2007. No additional options can be granted under
the 1997 Plan. However, all outstanding
options granted under the 1997 Plan will continue to be governed by the terms
of the 1997 Plan.
The fair value of the stock option grants are amortized over the
respective vesting period using the straight-line method and assuming no
forfeitures. Based on the historical
experience of the company, forfeitures are not significant. Compensation expense related to stock options
included in General and Administrative Expense for the years ended October 31, 2008,
2007 and 2006 is $68,000, $153,000 and $209,000, respectively. The
36
Table of
Contents
estimated unrecognized compensation cost from unvested options as of October 31,
2008 was approximately $224,000, which is expected to be recognized over an
average period of 3.0 years.
The following table summarizes stock option activity in the companys
stock-based compensation plans for the years ended October 31, 2008, 2007
and 2006.
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
Aggregate
|
|
Number of
|
|
|
|
Number of
|
|
Exercise
|
|
Intrinsic
|
|
shares
|
|
|
|
shares
|
|
Price
|
|
Value (1)
|
|
exercisable
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
November 1, 2005
|
|
485,064
|
|
5.78
|
|
3,512,000
|
|
348,114
|
|
Exercised
|
|
(143,813
|
)
|
5.81
|
|
2,227,000
|
|
|
|
Cancelled
|
|
(26,249
|
)
|
8.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
October 31, 2006
|
|
315,002
|
|
5.52
|
|
2,363,000
|
|
266,939
|
|
Granted at fair
value
|
|
40,000
|
|
12.78
|
|
|
|
|
|
Exercised
|
|
(84,187
|
)
|
4.39
|
|
704,000
|
|
|
|
Cancelled
|
|
(564
|
)
|
5.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
October 31, 2007
|
|
270,251
|
|
6.94
|
|
875,000
|
|
236,918
|
|
Granted at
premium to fair value
|
|
53,706
|
|
14.31
|
|
|
|
|
|
Exercised
|
|
(91,188
|
)
|
5.93
|
|
415,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
October 31, 2008
|
|
232,769
|
|
9.04
|
|
394,000
|
|
157,397
|
|
(1) The intrinsic value of a stock option is the amount by which
the current market value of the underlying stock exceeds the exercise price of
the option.
Stock options, except those granted at a premium in 2008, are granted at
the fair market value of one share of Common Stock on the date of grant. Options granted to non-employee directors
vest 1/3 immediately and 1/3 on each subsequent anniversary. Options granted to non-director officers and
other employees vest over three to four years.
All outstanding options had a term of ten years at the date of grant.
The fair value of each option granted in 2008, 2007 and 2006 was
estimated using the Black-Scholes option pricing model.
The following assumptions were used to compute the weighted average fair
value of options granted during the periods presented.
|
|
2008
|
|
2007
|
|
2006
|
|
Expected life of
options
|
|
5 years
|
|
2.5 years
|
|
N/A - No grants in 2006
|
|
Risk free
interest rates
|
|
2.93
|
%
|
4.58
|
%
|
|
|
Estimated
volatility
|
|
49.41
|
%
|
50.84
|
%
|
|
|
Dividend yield
|
|
0.00
|
%
|
0.00
|
%
|
|
|
Weighted average
fair market value of options granted during the year
|
|
$
|
3.15
|
|
$
|
4.47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Table
of Contents
The following table summarizes information about options outstanding at October 31,
2008.
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Remaining
|
|
Average
|
|
Aggregate
|
|
|
|
Average
|
|
Aggregate
|
|
Range of
|
|
Number of
|
|
Contractual
|
|
Exercise
|
|
Intrinsic
|
|
Number
|
|
Exercise
|
|
Intrinsic
|
|
Exercise Prices
|
|
Options
|
|
Life (Years)
|
|
Price
|
|
Value
|
|
Exercisable
|
|
Price
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5.93
|
|
139,063
|
|
4.6
|
|
$
|
5.93
|
|
$
|
394,000
|
|
139,063
|
|
5.93
|
|
394,000
|
|
12.78
|
|
40,000
|
|
8.1
|
|
12.78
|
|
|
|
18,334
|
|
12.78
|
|
|
|
14.31
|
|
53,706
|
|
9.9
|
|
14.31
|
|
|
|
|
|
14.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$5.93 - $14.31
|
|
232,769
|
|
6.4
|
|
$
|
9.04
|
|
$
|
394,000
|
|
157,397
|
|
6.73
|
|
$
|
394,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Amounts
Basic income per share is computed using the weighted average number of
shares outstanding. Diluted income per share reflects the potential dilution
that would occur if stock options were exercised using the average market price
for the companys stock for the period.
Total potential dilutive shares based on options outstanding at October 31, 2008
were 60,976.
The companys calculation of earnings per share of common stock is as
follows:
|
|
Year
Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
Income
|
|
|
|
|
|
Income
|
|
|
|
|
|
Income
|
|
|
|
Net
|
|
|
|
Per
|
|
Net
|
|
|
|
Per
|
|
Net
|
|
|
|
Per
|
|
|
|
Income
|
|
Shares
|
|
Share
|
|
Income
|
|
Shares
|
|
Share
|
|
Income
|
|
Shares
|
|
Share
|
|
Basic earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
per share
|
|
$
|
5,993,000
|
|
9,697,000
|
|
$
|
.62
|
|
$
|
5,760,000
|
|
9,280,000
|
|
$
|
.62
|
|
$
|
6,836,000
|
|
9,207,000
|
|
$
|
.74
|
|
Effect of
dilutive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shares of common
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock options
|
|
|
|
61,000
|
|
(.01
|
)
|
|
|
115,000
|
|
(.01
|
)
|
|
|
275,000
|
|
(.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
per share
|
|
$
|
5,993,000
|
|
9,758,000
|
|
$
|
.61
|
|
$
|
5,760,000
|
|
9,395,000
|
|
$
|
.61
|
|
$
|
6,836,000
|
|
9,482,000
|
|
$
|
.72
|
|
Reclassifications
Certain 2007 and 2006 amounts
have been reclassified to conform to current year presentation. Such reclassifications had no effect on net
income or shareholders equity.
Recent Accounting Pronouncements
On
December 29, 2008 the Securities and Exchange Commission announced final
approval of new requirements for reporting oil and gas reserves to be effective
in January 2010.
The new
disclosure requirements provide for consideration of new technologies in
evaluating reserves, allow companies to disclose their probable and possible
reserves to investors, report oil and gas reserves using an average price based
on the prior 12-month period rather than year-end prices, and revise the disclosure
requirements for oil and gas operations.
The accounting for the limitation on capitalized costs for full cost
companies will also be revised. The new rule is
expected to be effective for years ending on or after December 31, 2009,
although the transition may be extended.
The company has not yet
evaluated the effects on its financial statements and disclosures.
In
March 2008, the FASB issued Statement No. 161 (FAS 161), Disclosures
about Derivative Instruments and Hedging Activities, an amendment of FASB
Statement No. 133, which requires additional disclosures about the
objectives of using derivative instruments, the method by which the derivative
instruments and related hedged items are accounted for under FASB
38
Table of Contents
Statement
No. 133 and its related interpretations, and the effect of derivative
instruments and related hedged items on financial position, financial
performance and cash flows. FAS 161
also requires disclosure of the fair values of derivative instruments and their
gains and losses in a tabular format.
FAS 161 is effective for fiscal years beginning after November 15,
2008 and interim periods within those fiscal years (fiscal 2010 for the
company). The Company is in the process
of determining the effects the adoption of FAS 161 will have on its
financial statement disclosures.
In
December, 2007 the FASB issued FSAS No.157
, Fair Value Measurements
. This Statement does not require any new fair
value measurements, but rather, it provides enhanced guidance to other
pronouncements that require or permit assets or liabilities to be measured at
fair value. However, the application of
this Statement may change how fair value is determined. The Statement is
effective for financial statements issued for fiscal years beginning after November 15,
2007, and interim periods within those fiscal years. The company will adopt FAS 157 for the first
quarter of fiscal 2008 and does not expect a material impact on its financial
statements.
In
December, 2007 the FASB issued FSAS No.159,
The
Fair Value Option for Financial Assets and Financial Liabilities Including an
amendment of FASB Statement No. 115.
This Statement provides all entities with an option to report
selected financial assets and liabilities at fair value. The Statement is effective as of the
beginning of an entitys first fiscal year beginning after November 15,
2007, with early adoption available in certain circumstances. The company does not expect to elect the
options provided by FAS 159.
In November 2007, the FASB issued SFAS No. 141 (revised 2007),
Business Combination
(FAS 141(R)) and SFAS No. 160,
Noncontrolling
Interests in Consolidated Financial Statements, an amendment of ARB No. 51
(FAS 160). FAS 141(R) will
change how business acquisitions are accounted for and will impact financial
statements both on the acquisition date and in subsequent periods. FAS 160 will change the accounting and
reporting for minority interests, which will be recharacterized as
noncontrolling interests and classified as a component of equity. FAS 141(R) and FAS 160 are
effective for both public and private companies for fiscal years beginning on
or after December 15, 2008 (fiscal 2010 for the Company). FAS 141(R) will be applied
prospectively. FAS 160 requires
retroactive adoption of the presentation and disclosure requirements for
existing minority interests. All other
requirements of FAS 160 will be applied prospectively. Early adoption is prohibited for both
standards. Management is currently
evaluating the requirements of FAS 141(R) and FAS 160 and has
not yet determined the impact on its financial statements.
(2) COMMON STOCK AND
PREFERRED STOCK
The
company has authorized 20,000,000 shares of $0.10 par value common stock and as
of October 31, 2008, common shares issued are 10,660,000, common shares
held in treasury are 223,000 and common shares outstanding are 10,437,000. In addition, the company has authorized
5,000,000 shares of preferred stock which may be issued in series and with
preferences as determined by the companys Board of Directors. Approximately 100,000 shares of the companys
authorized but unissued preferred stock have been reserved for issuance
pursuant to the provisions of the companys Shareholders Rights Plan.
During the quarter ended July 31, 2008 the company entered into,
and closed, a Company Stock Purchase Agreement with RCH Energy Opportunity Fund
II, LP (RCH). Under the terms of the
agreement the company sold to RCH 1,150,000 shares of newly-issued common
stock, par value $0.10 at a price of $14.50 per share, in cash. Transaction fees paid from the proceeds of
sale were $1,580,000.
Also under the terms of the agreement, RCH nominated, and the companys
Board of Directors elected, two new directors to serve on the companys Board
of Directors for so long as RCH beneficially owns at least 15% of the companys
outstanding stock and one director for so long as RCH beneficially owns at
least 10% of the companys outstanding stock.
39
Table of
Contents
The Purchase Agreement contains a standstill provision that prohibits
RCH from acquiring any additional shares of the companys stock for a period of
two years without the consent of the company.
In connection with the Company Stock Purchase Agreement with RCH the
company amended its Rights Agreement, dated as of April 11, 1989, as
amended, in order to exempt the Common Stock Purchase Agreement from
application of the Rights Agreement.
During
2007, the Company entered into a joint venture agreement with RCH Energy
Opportunity Fund II, LP, its affiliates and its General Partner, RR Advisors,
LLC to use the Calliope Gas Recovery Technology on wells that they might
propose to the joint venture. As of October 31, 2008, there
have been no transactions under this agreement
On September 22, 2008, the companys Board of Directors authorized
a stock repurchase Program. Under the
program, the company may acquire up to $2,000,000 of its common stock. 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. At October 31, 2008,
the company has acquired 98,940 shares at an aggregate cost of $722,000.
Subsequent to October 31, 2008, and through January 5,
2008, the company has repurchased an additional 64,112 shares, bringing the
total shares repurchased to 163,052 at an average price per share of $8.60.
(3) COMMITMENTS AND CONTINGENCIES
The company leases office facilities under an operating lease agreement
entered into May 1, 2006 which expires April 30, 2011. The lease agreement requires payments of
$32,000 in each year through 2010, and $15,000 in 2011. Total rental expense was $78,000 in 2008,
$75,000 in 2007, and $80,000 in 2006.
The company has no capital leases and no other operating lease commitments.
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. This is the only litigation currently involving
the company.
(4) BENEFIT PLANS
Profit Sharing 401(k) Plan
The company has established a
401(k) plan for the benefit of its employees. Eligible employees may make voluntary
contributions not exceeding statutory limitations to the plan. These contributions
may be matched by the company, at its discretion. Historically, the company has made matching
contributions ranging from 40% to 50% of the employees annual
contributions. Matching contributions
recorded in fiscal 2008, 2007 and 2006 were $44,000, $44,000, and $37,000,
respectively.
Other Company Benefits
The company provides a health and welfare benefit plan to all regular
full-time employees. The plan includes health insurance.
(5) INCOME TAXES
The deferred income tax
liability is extremely complicated for any energy company to estimate due in
part to the long-lived nature of depleting oil and gas reserves and multiple
variables. Certain parts of the tax
calculations involve judgment and estimates.
On
November 1, 2007 the company adopted the provisions of FASB Interpretation
No. 48,
40
Table of Contents
Accounting
for Uncertainty in Income Taxes (FIN 48).
In implementing FIN 48, we did not identify any significant uncertain
tax positions. Our policy is to
recognize potential accrued interest and penalties related to unrecognized tax
benefits in income tax expense, which is consistent with the recognition of these
items in prior reporting periods. No
interest and penalties related to uncertain tax positions were accrued at October 31,
2008.
We
have not had any material changes to our unrecognized tax benefits since
adoption, nor do we anticipate significant changes to the total amount of
unrecognized tax benefits within the next twelve months.
As
of October 31, 2008 the companys 2007 Federal tax return is under audit
by the IRS. We remain subject to
examination of our Federal and state tax returns, except Colorado, for the tax
years 2005 and 2006, and for the tax years 2004 through 2007 for our Colorado
tax returns.
At October 31, 2008 the company had $1,232,000 of statutory
depletion carry forward for tax return purposes.
The income tax expense recorded in the Consolidated Statements of
Operations consists of the following:
|
|
Years Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Current
|
|
$
|
247,000
|
|
$
|
1,150,000
|
|
$
|
473,000
|
|
Deferred
|
|
1,913,000
|
|
1,165,000
|
|
2,127,000
|
|
|
|
|
|
|
|
|
|
Total income tax
expense
|
|
$
|
2,160,000
|
|
$
|
2,315,000
|
|
$
|
2,600,000
|
|
The effective income tax rate differs from the U.S. Federal statutory
income tax rate due to the following:
|
|
Years Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Federal taxes at
statutory rate
|
|
2,853,000
|
|
2,826,000
|
|
3,303,000
|
|
Graduated rates
|
|
(56,000
|
)
|
(64,000
|
)
|
(62,000
|
)
|
State income
taxes and other
|
|
210,000
|
|
214,000
|
|
134,000
|
|
Percentage
depletion
|
|
(847,000
|
)
|
(661,000
|
)
|
(775,000
|
)
|
|
|
|
|
|
|
|
|
|
|
2,160,000
|
|
2,315,000
|
|
2,600,000
|
|
41
Table of Contents
The
principal sources of temporary differences resulting in deferred tax assets and
liabilities at October 31, 2008 and 2007 are as follows:
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
Percentage depletion carryforward
|
|
419,000
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
419,000
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
|
Oil and gas assets
|
|
(9,706,000
|
)
|
(8,043,000
|
)
|
Derivative instruments
|
|
(590,000
|
)
|
(148,000
|
)
|
State taxes
|
|
(871,000
|
)
|
(710,000
|
)
|
Other
|
|
(369,000
|
)
|
(303,000
|
)
|
Total deferred tax liabilities
|
|
11,536,000
|
|
(9,204,000
|
)
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
11,117,000
|
|
$
|
(9,204,000
|
)
|
|
|
|
|
|
|
|
|
(6)
INTANGIBLE ASSETS
On September 1, 2000, the company acquired an unrestricted,
exclusive license for patented Calliope Gas Recovery System technology. In July 2008, the company acquired the
third party rights resulting from future Calliope installations for
$975,000. This intangible asset is being
amortized over ten years on a straight line basis.
|
|
October 31, 2008
|
|
|
|
Gross Carrying
|
|
Accumulated
|
|
|
|
Amount
|
|
Amortization
|
|
Amortized intangible assets:
|
|
|
|
|
|
Calliope intangible assets
|
|
$
|
1,674,000
|
|
$
|
595,000
|
|
|
|
|
|
|
|
Aggregate amortization expense:
|
|
|
|
|
|
For the year ended October 31, 2008
|
|
|
|
$
|
94,000
|
|
|
|
|
|
|
|
Estimated future amortization expense:
|
|
|
|
|
|
For the year ended October 31, 2009
|
|
|
|
167,500
|
|
For the year ended October 31, 2010
|
|
|
|
155,000
|
|
For the year ended October 31, 2011
|
|
|
|
97,500
|
|
Thereafter at $97,500 per year
|
|
|
|
659,000
|
|
Total
|
|
|
|
$
|
1,079,000
|
|
|
|
|
|
|
|
|
|
These amortizable intangible assets are related to
the companys patented liquid lift system for low pressure gas wells.
The company reviews the value of its intangible
assets in accordance with SFAS No. 142, Goodwill and Other
Intangible Assets, which requires that it evaluate these 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.
42
Table of Contents
At October 31, 2008, these amortizable
intangible assets had a net book value of $1,079,000. The value of these assets
is believed to be realizable based on the companys estimation of future cash
flows from application of the companys patented liquid lift system. The companys impairment test compares the
estimated undiscounted future net cash flows related to this asset with the
related net capitalized costs of the asset at the end of each period. If the
net capitalized cost exceeds the undiscounted future net cash flows, the cost
of the asset is written down to estimated fair value. As of October 31, 2008, the company has
not recorded an impairment write-down for these assets. The estimated undiscounted value of future
net cash flows is derived from estimates of proved reserve values.
On
November 6, 2008 the company purchased all of the patents underlying the
Calliope Gas Recovery Technology, all of the related third party interests in
future installations of the technology and patents covering a new fluid lift
technology for shallow wells known as Tractor Seal for $4,500,000. The patents have remaining lives ranging from
8.6 to 17.6 years.
(7)
COMPRESSOR AND TUBULAR
INVENTORY
Compressor
and tubular inventory are finished goods, recorded at cost, which are expected
to be used in the future development of the companys oil and gas
properties. The company has classified
this inventory as a long-term asset because the compressors and tubulars are
not held for re-sale and the cost, net of amounts billed to joint interest
owners in the normal course of business, will eventually be included in
evaluated properties.
(8)
RESTATEMENT OF PRIOR YEARS
In
connection with preparing its quarterly report for third quarter 2008,
management of CREDO Petroleum Corporation (the company) and the Audit
Committee of its Board of Directors determined that the contemporaneous formal
documentation it had historically prepared to support its initial hedge
designations in connection with the companys natural gas hedging program does
not meet the technical requirements to qualify for cash flow hedge accounting
treatment in accordance with SFAS 133.
The primary reason for this determination was that the formal hedge
documentation lacks specificity of the hedged items and therefore, the cash
flow designations failed to meet hedge documentation requirements for cash flow
hedge accounting treatment.
Consequently, the unrealized gain or loss should have been recorded in
the consolidated statements of operations as a component of income before income
taxes. Under the cash flow accounting treatment
used by the company, the fair values of the hedge contracts was recognized in
the consolidated balance sheets with the resulting unrealized gain or loss, net
of income taxes, recorded initially in accumulated other comprehensive income
and later reclassified through earnings when the hedged production affected
earnings.
On
Form 10-K/A, filed September 15, 2008, the company restated its
consolidated financial statements for fiscal years ended October 31, 2005,
2006 and 2007. Unrealized gains and
losses from derivative contracts were reclassified from Other Comprehensive
Income to a separate line item on the Statement of Operations, and realized
gains and losses on derivative contracts were reclassified from Oil and Gas
Sales to a separate line item on the Statement of Operations. There was no effect in any period on overall
cash flows, total assets, total liabilities or total stockholders equity. For the three years ended October 31, 2007,
the cumulative effect of the restatement was to increase net income by $756,000
and to increase diluted income per share by $.07. The restatement did not have any impact on
any of the Companys financial covenants under its line of credit.
(9)
SUBSEQUENT EVENT
On
November 6, 2008 the company purchased all of the patents underlying the
Calliope gas recovery technology, all of the related third party interests in
future installations of the technology and patents covering a new fluid lift
technology for shallow wells known as Tractor Seal for $4,500,000.
43
Table of Contents
(10)
SUPPLEMENTARY OIL AND GAS INFORMATION
Capitalized Costs
|
|
October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Unevaluated properties not being amortized
|
|
$
|
12,280,000
|
|
$
|
7,791,000
|
|
$
|
7,060,000
|
|
Properties being amortized
|
|
59,730,000
|
|
51,691,000
|
|
43,588,000
|
|
Accumulated depreciation, depletion and
amortization
|
|
25,554,000
|
|
(22,108,000
|
)
|
(18,556,000
|
)
|
|
|
|
|
|
|
|
|
Total capitalized costs
|
|
$
|
46,456,000
|
|
$
|
37,374,000
|
|
$
|
32,092,000
|
|
Unevaluated Oil and Gas Properties
Costs directly associated
with the acquisition and evaluation of unproved properties are excluded from the
amortization computation until they are evaluated. The following table shows, by year incurred,
the unevaluated oil and gas property costs (net of transfers to the full cost
pool and sales proceeds) excluded from the amortization computation as of October 31, 2008:
|
|
|
|
Total
|
|
|
|
Net Costs Incurred
|
|
|
|
Unevaluated
|
|
|
|
During Periods Ended:
|
|
|
|
Properties
|
|
|
|
|
|
|
|
|
|
|
|
October 31,
2008
|
|
|
|
$
|
6,185,000
|
|
|
|
October 31,
2007
|
|
|
|
2,118,000
|
|
|
|
October 31,
2006 and prior
|
|
|
|
3,977,000
|
|
|
|
|
|
|
|
$
|
12,280,000
|
|
|
|
Prospect
leasing and acquisition normally requires one to two years and the subsequent
evaluation normally requires an additional one to two years.
Acquisition, Exploration and Development Costs Incurred (Net of Sales)
|
|
Years Ended October 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Property acquisition costs net of
divestiture proceeds:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
442,000
|
|
$
|
82,000
|
|
$
|
102,000
|
|
Unproved
|
|
6,539,000
|
|
2,106,000
|
|
1,815,000
|
|
Exploration costs
|
|
4,057,000
|
|
3,368,000
|
|
6,388,000
|
|
Development costs
|
|
1,219,000
|
|
3,252,000
|
|
2,786,000
|
|
|
|
|
|
|
|
|
|
Total before asset retirement obligation
|
|
$
|
12,257,000
|
|
$
|
8,808,000
|
|
$
|
11,091,000
|
|
|
|
|
|
|
|
|
|
Total including asset retirement obligation
|
|
$
|
12,528,000
|
|
$
|
8,834,000
|
|
$
|
11,076,000
|
|
Major Customers and Operating Region
The company operates exclusively within the United States. Except for cash investments, all of the
companys assets are employed in, and all its revenues are derived from, the
oil and gas industry. The company had
sales in excess of 10% of total revenues to oil and gas purchasers as
follows: DCP Midstream LLP 49% in 2008,
40% in 2007 and 39% in 2006.
44
Table of Contents
Oil and Gas Reserve Data (Unaudited)
At October 31, 2008,
LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm,
estimated proved reserves for all of the companys properties.
In
2006 and 2007 McCartney Engineering, Inc., an independent petroleum
engineering firm, estimated proved reserves for the companys properties which
represented 64% in 2007 and 63% in 2006 of the total estimated future
value of estimated reserves.
Reserve definitions and pricing requirements prescribed by the
Securities and Exchange Commission were used.
The determination of oil and gas reserve quantities involves numerous
estimates which are highly complex and interpretive. The estimates are subject to continuing
re-evaluation and reserve quantities may change as additional information
becomes available. Estimated values of
proved reserves were computed by applying prices in effect at October 31
of the indicated year. The average price
used was $62.25, $86.61 and $53.69 per barrel for oil and $3.50, $5.89 and
$6.32 per Mcf for gas in 2008, 2007 and 2006, respectively. Estimated future costs were calculated
assuming continuation of costs and economic conditions at the reporting date.
The
companys reserves, and reserve values, are concentrated in 68 properties
(Significant Properties). Some of the
Significant Properties are individual wells and others are multi-well
properties. At October 31, 2008,
the Significant Properties represent 24% of the companys total properties but
a disproportionate 80% of the discounted value (at 10%) of the companys
reserves. Individual wells on which the
companys patented liquid lift system is installed comprise 16% of the
Significant Properties and represent 14% of the discounted reserve value of
such properties. Reserve addition in
2008 comprises 25% of the Significant Properties and represent 26% of the
discounted value of such properties.
Estimates
of reserve quantities and values for certain Significant Properties must be
viewed as being subject to significant change as more data about the properties
becomes available. Such properties include wells with limited production
histories and properties with proved undeveloped or proved non-producing
reserves. In addition, the companys
patented liquid lift system is generally installed on mature wells. As such, they contain older down-hole
equipment that is more subject to failure than new equipment. The failure of such equipment, particularly
casing, can result in complete loss of a well.
Historically, performance of the companys wells has not caused
significant revisions in its proved reserves.
Price
changes will affect the economic lives of oil and gas properties and,
therefore, price changes may cause reserve revisions. Price changes have resulted in estimated
reserve revisions in fiscal year 2008.
Compared with fiscal year 2007, natural gas prices have decreased 30%
and oil prices have decreased 22%. These
price decreases resulted in a 14.5% reduction in estimated proved
reserves.
One
measure of the life of the companys proved reserves can be calculated by
dividing proved reserves at fiscal year end 2008 by production for fiscal year
2008. This measure yields an average
reserve life of 10.5 years. Since this
measure is an average, by definition, some of the companys properties will
have a life shorter than the average and some will have a life longer than the
average. The expected economic lives of
the companys properties may vary widely depending on, among other things,
their size and quality, natural gas and oil prices, possible curtailments in
consumption by purchasers, and changes in governmental regulations or
taxation. As a result, the companys
actual future net cash flows from proved reserves could be materially different
from its estimates.
45
Table of Contents
Total estimated proved reserves and the changes therein are set forth
below for the indicated year.
|
|
2008
|
|
2007
|
|
2006
|
|
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, November 1
|
|
16,973,000
|
|
591,000
|
|
16,005,000
|
|
422,000
|
|
15,516,000
|
|
386,000
|
|
Revisions of previous estimates
|
|
(4,206,000
|
)
|
(82,000
|
)
|
(548,000
|
)
|
52,000
|
|
(637,000
|
)
|
24,000
|
|
Extensions and discoveries
|
|
3,935,000
|
|
248,000
|
|
3,442,000
|
|
168,000
|
|
3,302,000
|
|
53,000
|
|
Purchases of reserves in place
|
|
368,000
|
|
9,000
|
|
|
|
|
|
|
|
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
(1,545,000
|
)
|
(56,000
|
)
|
(1,926,000
|
)
|
(51,000
|
)
|
(2,176,000
|
)
|
(41,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, October 31
|
|
15,525,000
|
|
710,000
|
|
16,973,000
|
|
591,000
|
|
16,005,000
|
|
422,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
12,890,000
|
|
458,000
|
|
13,683,000
|
|
397,000
|
|
13,603,000
|
|
381,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
10,621,000
|
|
449,000
|
|
12,890,000
|
|
458,000
|
|
13,683,000
|
|
397,000
|
|
The standardized measure of discounted future net
cash flows from reserves is set forth below as of October 31 of the
indicated year.
|
|
2008
|
|
2007
|
|
2006
|
|
Future cash inflows
|
|
$
|
98,560,000
|
|
$
|
151,169,000
|
|
$
|
123,889,000
|
|
Future production and development costs
|
|
(44,905,000
|
)
|
(49,667,000
|
)
|
(39,028,000
|
)
|
Future income tax expense
|
|
(9,119,000
|
)
|
(24,967,000
|
)
|
(20,747,000
|
)
|
Future net cash flows
|
|
44,536,000
|
|
76,535,000
|
|
64,114,000
|
|
10% discount factor
|
|
(16,917,000
|
)
|
(29,734,000
|
)
|
(24,363,000
|
)
|
Standardized measure of discounted future
net cash flows
|
|
$
|
27,619,000
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
The principal sources of
change in the standardized measure of discounted future net cash flows from
reserves are set forth below for the indicated year.
|
|
2008
|
|
2007
|
|
2006
|
|
Balance, November 1
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
$
|
59,487,000
|
|
Sales of oil and gas produced, net of
production costs
|
|
(13,484,000
|
)
|
(12,800,000
|
)
|
(12,430,000
|
)
|
Net changes in prices and production costs
|
|
(17,290,000
|
)
|
3,233,000
|
|
(33,058,000
|
)
|
Extensions and discoveries, net of future
development and production costs
|
|
11,134,000
|
|
16,658,000
|
|
12,998,000
|
|
Changes in future development costs
|
|
(2,485,000
|
)
|
(12,000
|
)
|
(536,000
|
)
|
Previously estimated development costs
incurred during the period
|
|
1,506,000
|
|
932,000
|
|
1,299,000
|
|
Revisions of previous quantity estimates,
timing, and other
|
|
(10,116,000
|
)
|
(2,355,000
|
)
|
(3,396,000
|
)
|
Purchases of reserves in place
|
|
866,000
|
|
|
|
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
Accretion of discount
|
|
5,811,000
|
|
3,975,000
|
|
5,949,000
|
|
Net change in income taxes
|
|
4,876,000
|
|
(2,581,000
|
)
|
9,438,000
|
|
|
|
|
|
|
|
|
|
Balance, October 31
|
|
$
|
27,619,000
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
46
Table of Contents
(11)
QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
The following is a tabulation
of the companys unaudited quarterly operating results for fiscal 2006, 2007
and 2008.
|
|
|
|
Income (Loss)
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
Before
|
|
|
|
Basic Net
|
|
Net
|
|
|
|
Oil & Gas
|
|
Income
|
|
Net
|
|
Income (Loss)
|
|
Income (Loss)
|
|
|
|
Sales
|
|
Taxes
|
|
Income (Loss)
|
|
Per Share
|
|
Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
4,386,000
|
|
$
|
2,779,000
|
|
$
|
2,001,000
|
|
$
|
0.22
|
|
$
|
0.21
|
|
Second Quarter
|
|
3,723,000
|
|
1,963,000
|
|
1,392,000
|
|
0.15
|
|
0.15
|
|
Third Quarter
|
|
3,966,000
|
|
1,799,000
|
|
1,286,000
|
|
0.14
|
|
0.14
|
|
Fourth Quarter
|
|
4,028,000
|
|
2,895,000
|
|
2,157,000
|
|
0.23
|
|
0.22
|
|
|
|
$
|
16,103,000
|
|
$
|
9,436,000
|
|
$
|
6,836,000
|
|
$
|
0.74
|
|
$
|
0.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
3,412,000
|
|
$
|
1,529,000
|
|
$
|
1,093,000
|
|
$
|
0.12
|
|
$
|
0.12
|
|
Second Quarter
|
|
4,095,000
|
|
2,108,000
|
|
1,498,000
|
|
0.16
|
|
0.16
|
|
Third Quarter
|
|
3,613,000
|
|
3,411,000
|
|
2,447,000
|
|
0.26
|
|
0.26
|
|
Fourth Quarter
|
|
3,145,000
|
|
1,027,000
|
|
722,000
|
|
0.08
|
|
0.07
|
|
|
|
$
|
14,265,000
|
|
$
|
8,075,000
|
|
$
|
5,760,000
|
|
$
|
0.62
|
|
$
|
0.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
3,733,000
|
|
$
|
2,221,000
|
|
$
|
1,573,000
|
|
$
|
0.17
|
|
$
|
0.17
|
|
Second Quarter
|
|
4,942,000
|
|
(1,233,000
|
)
|
(880,000
|
)
|
(0.09
|
)
|
(0.09
|
)
|
Third Quarter
|
|
5,646,000
|
|
4,607,000
|
|
3,343,000
|
|
0.35
|
|
0.34
|
|
Fourth Quarter
|
|
3,024,000
|
|
2,558,000
|
|
1,957,000
|
|
0.19
|
|
0.19
|
|
|
|
$
|
17,345,000
|
|
$
|
8,153,000
|
|
$
|
5,993,000
|
|
$
|
0.62
|
|
$
|
0.61
|
|
47
Table
of Contents
Report
Of Independent Registered Public Accounting Firm
The
Board of Directors and Shareholders of CREDO Petroleum Corporation
We
have audited the accompanying consolidated balance sheet of CREDO Petroleum
Corporation and subsidiaries as of October 31, 2008 and the related consolidated
statements of operations, shareholders equity, and cash flows for the year
then ended. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on
these financial statements based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In
our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of CREDO Petroleum
Corporation and subsidiaries at October 31, 2008 and the consolidated
results of their operations and their cash flows for the year then ended in
conformity with U.S. generally accepted accounting principles.
We
also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), CREDO Petroleum Corporations
internal control over financial reporting as of October 31, 2008, based on
criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated January 12, 2009 expressed an unqualified opinion thereon.
Ernst &
Young LLP
Denver,
Colorado
January 12,
2009
Report of Independent Registered Public Accounting
Firm
The
Board of Directors and Shareholders of CREDO Petroleum Corporation
We
have audited CREDO Petroleum Corporations internal control over financial
reporting as of October 31, 2008, based on criteria established in
Internal ControlIntegrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). CREDO Petroleum Corporations management is
responsible for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Managements Report on
Internal Control Over Financial Reporting.
Our responsibility is to express an opinion on the companys internal
control over financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included obtaining an understanding
of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing
such other procedures as we
48
Table
of Contents
considered
necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A
companys internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.
A companys internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In
our opinion, CREDO Petroleum Corporation maintained, in all material respects,
effective internal control over financial reporting as of October 31,
2008, based on the COSO criteria
.
We also have
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet of CREDO
Petroleum Corporation and subsidiaries as of October 31, 2008, and the
related consolidated statements of operations, shareholders equity, and cash
flows for the year then ended and our report dated January 12, 2009
expressed an unqualified opinion
thereon.
Ernst & Young
LLP
Denver,
Colorado
January 12,
2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders
Credo Petroleum Corporation
We have audited the
consolidated balance sheet of Credo Petroleum Corporation and subsidiaries as
of October 31, 2007, and the related consolidated statements of
operations, stockholders equity and cash flows for each of the two years in
the period ended October 31, 2007.
These financial statements are the responsibility of the Companys
management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also
includes assessing the accounting principles used and significant estimates
made by management, as well as
49
Table
of Contents
evaluating
the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In
our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Credo Petroleum
Corporation and subsidiaries as of October 31, 2007, and the results of
their operations and their cash flows for each of the two years in the period
ended October 31, 2007, in conformity with U.S. generally accepted accounting
principles.
HEIN
&
ASSOCIATES LLP
Denver,
Colorado
January 14,
2008, except for the matters described in Note 8 as to which the date is September 15,
2008
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Managements
Report on Internal Control Over Financial Reporting
Under the supervision and
with the participation of our management, including our Chief Executive Officer
and our Chief Financial Officer, we evaluated the effectiveness of our
50
Table
of Contents
disclosure controls and
procedures, as such term is defined under Rule 13a-15(e) promulgated
under the Securities Exchange Act of 1934, as amended. Our management is responsible for
establishing and maintaining adequate internal control over financial
reporting, as defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting
is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles.
Under the supervision and
with the participation of our management, including our Chief Executive Officer
and Chief Financial Officer, we conducted an evaluation of the effectiveness of
our internal control over financial reporting by using the criteria established
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)
in
Internal
ControlIntegrated Framework
.
Based on our evaluation under the framework in
Internal ControlIntegrated Framework
,
our management concluded that the Companys disclosure controls and procedures
are effective, in all material respects, with respect to the recording,
processing, summarizing and reporting, within the time periods specified in the
Commissions rules and forms, of information required to be disclosed by
the Company in the reports that it files or submits under the Exchange Act.
There were no significant
changes in the Companys internal control over financial reporting that
occurred during the fourth quarter that has materially affected, or is
reasonably likely to materially effect, the Companys internal control over
financial reporting.
Because
of its inherent limitations, internal controls over financial reporting may not
prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
The effectiveness of CREDO
Petroleum Corporations internal control over financial reporting as of October 31,
2008, has been audited by Ernst & Young, LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT
ITEM 11.
EXECUTIVE COMPENSATION
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
ITEM 13.
CERTAIN RELATIONSHIPS, RELATED
TRANSACTIONS AND DIRECTOR INDEPENDENCE
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND
SERVICES
Pursuant
to instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are
incorporated herein by reference from the companys definitive proxy statement
for its annual meeting of stockholders to be filed with the United States
Securities and Exchange Commission within 120 days after the end of the fiscal
year ended October 31, 2008.
51
Table of Contents
PART IV
ITEM 15. EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
(a)(1)
|
|
Financial Statements:
|
|
|
Consolidated Balance Sheets - October 31, 2007 and 2006
|
|
|
Consolidated Statements of Operations - Three Years ended
October 31, 2007
|
|
|
Consolidated Statements of Shareholders Equity - Three Years ended
October 31, 2007
|
|
|
Consolidated Statements of Cash Flows - Three Years ended
October 31, 2007
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Report of Independent Registered Public
Accounting Firm
|
|
|
|
(2)
|
|
Financial Statement
Schedules:
|
Schedules
are omitted because of the absence of the conditions under which they are
required or because the information is included in the financial statements or
notes to the financial statements.
(b)
|
|
Exhibits. The following
exhibits are filed with or incorporated by reference into this report on
Form 10-K.
|
3(a)(i)
& 4(a)
|
|
Articles of Incorporation of CREDO Petroleum Corporation (incorporated
by reference to Form 10-K dated October 31, 1982).
|
3(a)(ii)
|
|
Articles of Amendment of Articles of Incorporation, dated
March 9, 1982 (incorporated by reference to Form 10-K dated
October 31, 1982).
|
3(a)(iii)
|
|
Articles of Amendment of Articles of Incorporation, dated
October 28, 1982 (incorporated by reference to Form 10-K dated
October 31, 1982).
|
3(a)(iv)
|
|
Articles of Amendment of Articles of Incorporation dated
April 18, 1984 (incorporated by reference to Form 10-K dated
October 31, 1984).
|
3(a)(v)
|
|
Articles of Amendment of Articles of Incorporation dated
April 18, 1984 (incorporated by reference to Form 10-K dated
October 31, 1984).
|
3(a)(vi)
|
|
Articles of Amendment of Articles of Incorporation dated
April 2, 1985 (incorporated by reference to Form 10-K dated
October 31, 1985).
|
3(a)(vii)
|
|
Articles of Amendment of Articles of Incorporation dated
March 25, 1986 (incorporated by reference to Form 10-K dated
October 31, 1986).
|
3(a)(viii)
|
|
Articles of Amendment of Articles of Incorporation dated
March 24, 1988 (incorporated by reference to Form 10-K dated
October 31, 1989).
|
3(a)(ix)
|
|
Articles of Amendment to Articles of Incorporation dated
May 11, 1990.
|
3(b)(i)
|
|
By-Laws of CREDO Petroleum Corporation, as amended October 30,
1986 (incorporated by reference to Form 10-K dated October 31,
1986).
|
3(b)(ii)
|
|
Amendment to Article X of CREDO Petroleum Corporations By-Laws
dated March 24, 1988 (incorporated by reference to the companys
definitive proxy dated February 5, 1988).
|
4(i)
|
|
Shareholders Rights Plan, dated April 11, 1989.
|
4(ii)
|
|
Amendment to Shareholders Rights Plan, dated February 24, 1999
(incorporated into Part II of the companys Form 10-QSB dated
January 31, 1999).
|
10(a)
|
|
CREDO Petroleum Corporation Non-qualified Stock Option Plan, dated
January 13, 1981 (incorporated by reference to Amendment No. 1 to
Form S-1 dated February 2, 1981).
|
10(b)
|
|
CREDO Petroleum Corporation Incentive Stock Option Plan, dated
October 2, 1981 (incorporated by reference to the companys
definitive proxy statement, dated January 22, 1982).
|
10(c)
|
|
Model of Director and Officer Indemnification Agreement provided for
by Article X of CREDO Petroleum Corporations By-Laws (incorporated by
reference to Form 10-K dated October 31, 1987).
|
10(d)
|
|
CPC Exclusive License Agreement, dated September 1, 2000
(incorporated by reference to Form 10-KSB dated October 31, 2000).
|
10(e)
|
|
CREDO Petroleum Corporation 1997 Stock Option Plan, as amended and
restated effective October 25, 2001 (incorporated by reference to
Form 10-KSB dated October 31, 2001).
|
52
Table
of Contents
10(f)
|
|
CREDO Petroleum Corporation 2007 Stock Option Plan (incorporated by
reference to the companys definitive proxy statement filed with the SEC on
February 20, 2007).
|
14.1
|
|
Code of Business Conduct and Ethics (incorporated by reference to
Form 10-KSB dated October 31, 2004).
|
21
|
|
CREDO Petroleum Corporation (a Colorado corporation) and its
subsidiaries SECO Energy Corporation (a Nevada corporation) and United Oil
Corporation (an Oklahoma corporation) are located at 1801 Broadway,
Suite 900, Denver, CO 80202-3837.
|
23.1 *
|
|
Consent of Independent Registered Public Accounting Firm dated
January 12, 2009
|
23.2 *
|
|
Consent of Independent Registered Public accounting Firm dated
January 12, 2009
|
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).
|
3.03
|
|
Report of Strategic Investment (incorporated by reference to
Form 8-K dated June 3, 2008).
|
1.01
|
|
Entry into a Material Definitive Agreement ((incorporated by reference
to Form 8-K dated June 3, 2008).
|
5.02
|
|
Directors or Principal Officers-Changes (incorporated by reference to
Form 8-K dated November 17, 2008).
|
* Filed with this Form 10-K.
53
Table
of Contents
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized in the City of Denver,
State of Colorado on January 14, 2009.
|
CREDO PETROLEUM CORPORATION
|
|
(Registrant)
|
|
|
|
|
|
By:
|
/s/ James T. Huffman
|
|
|
James T. Huffman,
|
|
|
Chairman of the Board of
Directors, and
|
|
|
Chief Executive Officer
|
In
accordance with the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
|
Date
|
|
Signature
|
|
Title
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ James T. Huffman
|
|
Chairman of the Board of
Directors,
|
|
|
|
|
James T. Huffman
|
|
Treasurer and Chief
Executive Officer
|
|
|
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ Alford B. Neely
|
|
Chief Financial Officer
|
|
|
|
|
Alford B. Neely
|
|
(Principal Financial and Accounting
Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ Clarence H. Brown
|
|
Director
|
|
|
|
|
Clarence H. Brown
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ Oakley Hall
|
|
Director
|
|
|
|
|
Oakley Hall
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ W. Mark Meyer
|
|
Director
|
|
|
|
|
W. Mark Meyer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ John A. Rigas
|
|
Director
|
|
|
|
|
John A. Rigas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ H. Leigh Severance
|
|
Director
|
|
|
|
|
H. Leigh Severance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14,
2009
|
|
/s/
William F. Skewes
|
|
Director
|
|
|
|
|
William
F. Skewes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 14, 2009
|
|
/s/ Richard B. Stevens
|
|
Director
|
|
|
|
|
Richard B. Stevens
|
|
|
|
54
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