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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
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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, 2007
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or
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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/A.
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
Accelerated filer
x
Non-accelerated filer
o
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, 2007, the end of the registrants most recently completed second quarter was $110,276,000.
As of January 8, 2008, the registrant had 9,295,000 shares of common stock outstanding.
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EXPLANATORY NOTE
On September 2, 2008, 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.
The company has restated its consolidated
financial statements for fiscal years ended October 31, 2005, 2006,
2007 and the first and second quarters of fiscal year ending October 31, 2008. There is no effect in any period on overall
cash flows, EBITDA, total assets, total liabilities or total stockholders
equity. The restatement did not have any
impact on any of the Companys financial covenants under its line of
credit. Details of the effect of the
restatement are indicated in Note 1 to the Consolidated Financial Statements.
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DOCUMENTS INCORPORATED BY REFERENCE
Pursuant
to instruction G (3) to Form 10-K/A, 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 close 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 20, 2008 and is
hereby incorporated by reference.
NON-GAAP FINANCIAL MEASURES
In
this Annual Report on Form 10-K/A, the company uses the term EBITDA
(Earning Before 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/A.
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/A 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/A, 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/A, 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
ITEM 1. BUSINESS
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 twelve 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.
The company effected a 20% stock dividend in fiscal 2003, and a
three-for-two stock split in each of fiscal 2005 and 2004. All share and per share amounts discussed and
disclosed in this Annual Report on Form 10-K/A reflect the effect of the
dividend and stock splits.
Business Activities
During 2007, the company continued implementation of new drilling
projects in central Kansas and South Texas, which projects are designed to
sustain the companys growth rate 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. This includes approximately equal commitments
to conventional drilling and to the companys patented Calliope Gas Recovery
System (Calliope) operations.
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
conventional 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. 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 company believes
that both 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.
The
company has participated in developing, testing, refining, and patenting
Calliope. 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. The company has a
10 year
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unrestricted
exclusive license for the Calliope technology that expires in 2010, but that
can be extended, at the companys option, to cover the term of the latest
patent. External sources of capital have
not been required for the development, refinement or installation of
Calliope. At October 31, 2007,
Calliope has been installed on 25 wells ranging in depth from
6,500 feet to 18,400 feet. 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 2007 with two new
agreements reached and others under negotiation at October 31, 2007. 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 115 wells pursuant to
standard industry operating agreements.
The company owns working interests in 282 producing wells and overriding
royalty interests in 1,163 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 2003, the posted price for West Texas
intermediate fell below $25.00 per barrel and then rose to over $90.00 per
barrel during 2007.
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. A new
pipeline is scheduled to be completed in early 2008 that will transport gas
from the Rocky Mountain region to northeast Missouri. The pipeline will connect with other
pipelines that transport natural gas to the eastern United States. Depending on supply and demand factors, gas
delivered from the Rocky Mountain region may compete with the companys
Oklahoma gas resulting in the possibility of downward pressure on gas prices
received by the company in Oklahoma.
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 certain major
producing regions, supply vulnerability to natural disasters, such as hurricanes,
and active speculation in the natural gas futures market has caused natural gas
prices to become increasingly volatile.
The company expects natural gas prices to remain strong but cannot
reasonably predict the extent or timing of natural gas price fluctuations.
As discussed elsewhere in this Annual Report on Form 10-K/A, 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 both the NYMEX
futures market and regional markets.
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
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and
pricing policies of OPEC and other major producing countries and on significant
events in major producing regions.
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.
Information concerning the companys major customers is included in Note
(9) 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 2008. The company cannot predict what subsequent
legislation or regulations may be enacted or what effect they might have on the
companys business.
ITEM 1A. RISK FACTORS
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/A. 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.
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.
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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. If oil and natural gas prices decrease, 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 make the company more vulnerable to competitive
pressures and economic downturns.
Reserve quantities and values are subject to many variables and estimates and actual results may vary.
This
Annual Report on Form 10-K/A 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, 2007, approximately 24% 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
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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/A.
The
companys reserve quantities and values are concentrated in a relative few
properties and fields.
The
companys reserves, and reserve values, are concentrated in 61 properties which
represent 26% of the companys total properties but a disproportionate 77% of
the discounted value (at 10%) of the companys reserves. Individual wells on which Calliope is
installed comprise 20% of these significant properties and 22% of the
discounted reserve value of such properties.
New wells comprise 16% of these significant properties and 15% 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.
The
company is currently experiencing delays in securing drilling rigs and delivery
of production equipment, primarily compressors and coil tubing. These delays are extending the time it takes
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.
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The companys hedging
arrangements 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 hedging 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 hedge. 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 hedging 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
company recognizes all derivatives as fair value hedges on its balance sheet at
the end of each period. Changes in the
fair value of hedges are recorded in the Consolidated Statement of Operations.
A
new pipeline is scheduled to be completed in early 2008 that will transport gas
from the Rocky Mountain region to northeast Missouri. The pipeline will connect with other
pipelines that transport natural gas to the eastern United States. Depending on supply and demand factors, gas
delivered from the Rocky Mountain region may compete with the companys
Oklahoma gas resulting in the possibility of downward pressure on gas prices
received by the company in Oklahoma.
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. Management believes that the level of
insurance against these risks is reasonable and is consistent with general
industry practices. 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.
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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.
These projects diversify the companys exploration geographically,
scientifically, and in terms of capital, risk and reserve potential. Compared to the companys Oklahoma drilling,
the South Texas project involves higher costs and greater risks but offers
significantly higher per well production and reserve potential.
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.
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 President
and 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.
ITEM 2.
PROPERTIES
General
The
companys 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.
Since 2002, the company has participated in drilling approximately 89
wells on such prospects with interests ranging up to 83%. Of those wells, 64 were completed as producers
and 25 were dry holes. Several of the
wells are exceptional for the area, and 22 of the wells are included in the
companys Significant Properties (see
12
Table of Contents
definition
below). The company has recently
expanded its drilling activities into South Texas and Kansas.
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.
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. To date, Calliope has been
installed 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 3.4 billion cubic feet of gas and
they now have estimated ultimate (8/8ths) Calliope reserves totaling 13.6
billion cubic feet of gas. Twelve of the
Calliope wells are included in the companys Significant Properties.
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 61 properties (Significant
Properties). Some of the Significant
Properties are individual wells and others are multi-well properties. At year-end, Significant Properties represent
26% of the companys total properties but a disproportionate 77% of the
discounted value (at 10%) of the companys reserves. Individual Calliope wells comprise 20% of the
Significant Properties and represent 22% of the discounted reserve value of
such properties. New wells comprise 16% of
the Significant Properties and represent 15% 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.
McCartney Engineering, Inc., an independent petroleum engineering
firm, estimated proved reserves for the companys properties which represented
64% in 2007, 63% in 2006 and 63% in 2005 of the total estimated future
value of estimated reserves. Remaining
reserves were estimated by the company in all years. At October 31, 2007, natural gas
represented 83% and crude oil represented 17% 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 (9) to the Consolidated Financial
Statements where additional reserve information is provided. The average price used to calculate estimated
future net revenues was $5.89, $6.32, and $10.26 per Mcf of gas and $86.61, $53.69,
and $55.59 per barrel of oil as of October 31, 2007, 2006, and 2005,
respectively. Amounts do not include
estimates of future Federal and state income taxes.
13
Table of
Contents
|
|
|
|
|
|
|
|
Estimated Future
|
|
|
|
Gas
|
|
Oil
|
|
Estimated Future
|
|
Net Revenues
|
|
Year
|
|
(Mcf) *
|
|
(bbls) *
|
|
Net Revenues
|
|
Discounted at 10%
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
16,973,000
|
|
591,000
|
|
$
|
101,501,000
|
|
$
|
62,071,000
|
|
2006
|
|
16,005,000
|
|
422,000
|
|
$
|
84,861,000
|
|
$
|
52,328,000
|
|
2005
|
|
15,516,000
|
|
386,000
|
|
$
|
136,878,000
|
|
$
|
81,209,000
|
|
*
The percentage of total reserves classified as
proved developed was approximately 76% in 2007, 87% in 2006, and 89% in
2005.
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.
|
|
Year Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Estimated future
net revenues discounted at 10%
|
|
$
|
62,071,000
|
*
|
$
|
52,328,000
|
*
|
$
|
81,209,000
|
*
|
|
|
|
|
|
|
|
|
Future income
tax expense
|
|
(24,967,000
|
)
|
(20,747,000
|
)
|
(36,054,000
|
)
|
|
|
|
|
|
|
|
|
Effect of the
10% discount factor on future income tax expense
|
|
9,697,000
|
|
8,170,000
|
|
14,332,000
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
$
|
59,487,000
|
|
*
The average price used to calculate estimated
future net revenues was $5.89, $6.32, and $10.26 per Mcf of gas and $86.61,
$53.69, and $55.59 per barrel of oil as of October 31, 2007, 2006, and
2005, 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 are net of any realized
hedging gains or losses.
|
|
2007
|
|
2006
|
|
2005
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,926,000
|
|
$
|
6.78
|
(1)
|
2,176,000
|
|
$
|
6.11
|
(2)
|
1,830,000
|
|
$
|
6.16
|
(3)
|
Oil (bbls)
|
|
51,000
|
|
$
|
60.95
|
|
41,000
|
|
$
|
61.14
|
|
37,000
|
|
$
|
50.90
|
|
(1)
Includes $0.99 Mcf realized hedging gain.
(2)
Includes $0.12 Mcf realized hedging loss.
(3)
Includes $0.39 Mcf realized hedging 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 $1.51, $1.40, and $1.35 per Mcfe in 2007, 2006, and 2005,
respectively.
14
Table of
Contents
Productive Wells and Developed Acreage
Developed acreage at October 31, 2007 totaled 27,000 net and 80,000
gross acres. At October 31, 2007,
the company owned working interests in 82.13 net (282 gross) wells consisting
of 65.52 net (236 gross) natural gas wells and 16.61 net (46 gross) oil
wells. In addition, the company owned
royalty and production payment interests in approximately 1,163 wells,
primarily coal bed methane, located in Wyoming.
In 2007, the company sold 0.28 net (one gross) well and abandoned
0.37 net (one gross) well. In the same
period, the company drilled and acquired interests in 5.54 net (17 gross)
productive wells in which it did not previously own an interest.
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.
Expiration
|
|
Royalty
|
|
Working
|
|
Year Ending
|
|
Interest Acreage
|
|
Interest Acreage
|
|
October 31,
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
32,900
|
|
9,300
|
|
2009
|
|
|
|
|
|
8,200
|
|
4,200
|
|
2010
|
|
3,300
|
|
100
|
|
22,300
|
|
10,400
|
|
2011
|
|
|
|
|
|
100
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
3,700
|
|
500
|
|
300
|
|
200
|
|
Held-By-Production
|
|
152,100
|
|
8,000
|
|
20,500
|
|
5,100
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
159,100
|
|
8,600
|
|
84,300
|
|
29,200
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
24
|
|
5
|
|
11
|
|
7
|
|
|
|
1
|
|
|
|
2006
|
|
27
|
|
1
|
|
9
|
|
13
|
|
1
|
|
3
|
|
|
|
2005
|
|
26
|
|
|
|
10
|
|
2
|
|
|
|
14
|
|
|
|
15
Table of
Contents
Net Wells
|
|
Year Ended
|
|
Total Net
|
|
Exploratory
|
|
Development
|
|
October 31,
|
|
Wells
|
|
Oil
|
|
Gas
|
|
Dry
|
|
Oil
|
|
Gas
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
8.591
|
|
1.166
|
|
4.143
|
|
2.700
|
|
|
|
0.582
|
|
|
|
2006
|
|
10.421
|
|
0.300
|
|
3.184
|
|
5.029
|
|
0.306
|
|
1.602
|
|
|
|
2005
|
|
4.683
|
|
|
|
3.075
|
|
0.208
|
|
|
|
1.400
|
|
|
|
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.
As
of October 31, 2007, the company had 12 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, (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/A.
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/A, the company is not a party to any pending legal
proceedings. No such proceedings have
been threatened and none are contemplated by the company.
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 2007.
16
Table of
Contents
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.
|
|
2007
|
|
2006
|
|
Quarter Ended
|
|
High
|
|
Low
|
|
High
|
|
Low
|
|
January 31
|
|
$
|
13.27
|
|
$
|
11.55
|
|
$
|
30.46
|
|
$
|
17.16
|
|
April 30
|
|
$
|
16.00
|
|
$
|
11.58
|
|
$
|
29.97
|
|
$
|
20.46
|
|
July 31
|
|
$
|
14.60
|
|
$
|
11.78
|
|
$
|
25.40
|
|
$
|
16.85
|
|
October 31
|
|
$
|
11.92
|
|
$
|
9.52
|
|
$
|
22.02
|
|
$
|
12.86
|
|
At
January 4, 2008, the company had 2,621 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 50,000 shares of
its common stock on the open market at a weighted average price of $10.13. The purchase was made pursuant to a stock
repurchase plan announced on October 4, 2007. The plan authorized repurchases up to
$1,000,000, but could be expanded, suspended or discontinued at any time. No
additional shares have been repurchased subsequent to October 31, 2007.
17
Table of
Contents
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,
2007 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.
Comparison
of 6 Year Cumulative Total Return
October
2007
(Assumes
Initial Investment of $100)
|
|
October 31
|
|
|
|
2001
|
|
2002
|
|
2003
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
CREDO Petroleum
Corporation
|
|
$
|
100
|
|
$
|
156
|
|
$
|
388
|
|
$
|
483
|
|
$
|
919
|
|
$
|
685
|
|
$
|
512
|
|
Standard &
Poors 500 Stock Index
|
|
100
|
|
84
|
|
99
|
|
107
|
|
114
|
|
130
|
|
146
|
|
AMEX Natural Gas
Index
|
|
100
|
|
67
|
|
102
|
|
141
|
|
201
|
|
225
|
|
297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
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, 2007 were derived from the audited
financial statements and the accompanying notes to those financial statements.
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
Statement
of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
14,265,000
|
|
$
|
16,103,000
|
|
$
|
13,862,000
|
|
$
|
10,084,000
|
|
$
|
7,586,000
|
|
Investment and other income
|
|
819,000
|
|
654,000
|
|
146,000
|
|
343,000
|
|
461,000
|
|
Oil and gas production expense
|
|
3,375,000
|
|
3,407,000
|
|
2,759,000
|
|
2,075,000
|
|
1,608,000
|
|
Depreciation, depletion and amortization
|
|
3,666,000
|
|
3,642,000
|
|
2,402,000
|
|
1,747,000
|
|
1,333,000
|
|
General and administrative
|
|
1,397,000
|
|
1,291,000
|
|
1,117,000
|
|
1,171,000
|
|
1,315,000
|
|
Interest expense
|
|
26,000
|
|
42,000
|
|
37,000
|
|
39,000
|
|
46,000
|
|
Income from operations
|
|
6,620,000
|
|
8,375,000
|
|
7,693,000
|
|
5,395,000
|
|
3,745,000
|
|
Realized hedge gains(losses)
|
|
1,909,000
|
|
(266,000
|
)
|
(719,000
|
)
|
(717,000
|
)
|
(92,000
|
)
|
Unrealized hedge gains(losses)
|
|
(454,000
|
)
|
1,327,000
|
|
182,000
|
|
(857,000
|
)
|
199,000
|
|
Income before income taxes
|
|
8,075,000
|
|
9,436,000
|
|
7,156,000
|
|
3,821,000
|
|
3,852,000
|
|
Net income
|
|
5,760,000
|
|
6,836,000
|
|
5,153
,000
|
|
2,751,000
|
|
2,845,000
|
|
Net income per share(1):
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.62
|
|
$
|
0.74
|
|
$
|
0.57
|
|
$
|
0.30
|
|
$
|
0.32
|
|
Diluted
|
|
$
|
0.61
|
|
$
|
0.72
|
|
$
|
0.55
|
|
$
|
0.30
|
|
$
|
0.31
|
|
Weighted-average shares
|
|
|
|
|
|
|
|
|
|
|
|
outstanding(1):
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
9,280,000
|
|
9,207,000
|
|
9,080,000
|
|
9,036,000
|
|
8,869,000
|
|
Diluted
|
|
9,395,000
|
|
9,482,000
|
|
9,367,000
|
|
9,282,000
|
|
9,042,000
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
Working capital
|
|
12,511,000
|
|
10,073,000
|
|
7
,697,000
|
|
5,611,000
|
|
6,577,000
|
|
Total assets
|
|
55,349,000
|
|
47,759,000
|
|
37,844,000
|
|
30,976,000
|
|
23,572,000
|
|
Long-term obligations:
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes-net
|
|
9,204,000
|
|
8,039,000
|
|
5,978,000
|
|
4,605,000
|
|
3,192,000
|
|
Asset retirement obligation
|
|
1,016,000
|
|
954,000
|
|
929,000
|
|
748,000
|
|
238,000
|
|
Exclusive license agreement obligation
|
|
85,000
|
|
163,000
|
|
233,000
|
|
297,000
|
|
355,000
|
|
Stockholders equity
|
|
41,140,000
|
|
34,767,000
|
|
26,947,000
|
|
20,920,000
|
|
17,635,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,926,000
|
|
2,176,000
|
|
1,830,000
|
|
1,710,000
|
|
1,449,000
|
|
Oil (Bbls)
|
|
51,000
|
|
41,000
|
|
37,000
|
|
41,000
|
|
35,000
|
|
Mcfe
|
|
2,234,000
|
|
2,422,000
|
|
2,050,000
|
|
1,960,000
|
|
1,660,000
|
|
Average sales price before realized
hedging:
|
|
|
|
|
|
|
|
|
|
|
|
Per Mcf
|
|
$
|
5.79
|
|
$
|
6.24
|
|
$
|
6.55
|
|
$
|
5.02
|
|
$
|
4.57
|
|
Per Bbls
|
|
$
|
60.95
|
|
$
|
61.14
|
|
$
|
50.90
|
|
$
|
36.57
|
|
$
|
27.68
|
|
Average sales price after realized
hedging:
|
|
|
|
|
|
|
|
|
|
|
|
Per Mcf
|
|
$
|
6.78
|
|
$
|
6.11
|
|
$
|
6.16
|
|
$
|
4.60
|
|
$
|
4.50
|
|
Per Bbls
|
|
$
|
60.95
|
|
$
|
61.14
|
|
$
|
50.90
|
|
$
|
36.57
|
|
$
|
27.68
|
|
Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
16,973,000
|
|
16,005,000
|
|
15,516,000
|
|
15,273,000
|
|
13,786,000
|
|
Oil (Bbls)
|
|
591,000
|
|
422,000
|
|
386,000
|
|
407,000
|
|
385,000
|
|
Mcfe
|
|
20,517,000
|
|
18,537,000
|
|
17,835,000
|
|
17,717,000
|
|
16,097,000
|
|
Estimated future net revenues
|
|
$
|
101,501,000
|
|
$
|
84,861,000
|
|
$
|
136,878,000
|
|
$
|
77,612,000
|
|
$
|
45,165,000
|
|
Estimated future net revenues
discounted at 10%
|
|
$
|
62,071,000
|
|
$
|
52,328,000
|
|
$
|
81,209,000
|
|
$
|
44,551,000
|
|
$
|
28,024,000
|
|
(1) The effect of the three for two stock splits in 2005 and 2004,
and 20% stock dividend in 2003, are reflected in all historical share and
per share data.
19
Table of
Contents
ITEM
7.
|
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
Liquidity and Capital Resources
At October 31, 2007,
working capital increased 24% to $12,511,000, compared to $10,073,000 at October 31, 2006. For the year ended October 31, 2007, net
cash provided by operating activities was $11,674,000 compared to $12,973,000
for the same period in 2006. The
difference is primarily due to a decrease in non-cash items (DD&A, deferred
income taxes and other items) of $226,000, an increase in short term
investments of $759,000 in 2007 compared to $129,000 in 2006 and net changes in
other operating assets. For the year
ended October 31, 2007 and 2006, net cash used in investing activities was
$8,750,000 and $11,096,000, respectively.
Investing activities primarily included oil and gas exploration and
development expenditures, including Calliope, totaling $9,144,000 and $11,746,000,
respectively. Financing activities
primarily included the purchase of treasury stock of $506,000 and proceeds from
exercise of stock options of $368,000 and $835,000 in 2007 and 2006,
respectively.
The companys adjusted earnings before unrealized gains/losses on
derivative contracts, interest, taxes, depreciation, depletion and
amortization, (EBITDA) increased 4% to $12,221,000 for the year ended October 31, 2007
from $11,793,000 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,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
$
|
5,153,000
|
|
Add Back:
|
|
|
|
|
|
|
|
Unrealized
(Gain) Loss on Derivative Contracts
|
|
454,000
|
|
(1,327,000
|
)
|
(182,000
|
)
|
Interest Expense
|
|
26,000
|
|
42,000
|
|
37,000
|
|
Income Tax
Expense
|
|
2,315,000
|
|
2,600,000
|
|
2,003,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
3,666,000
|
|
3,642,000
|
|
2,402,000
|
|
EBITDA
|
|
$
|
12,221,000
|
|
$
|
11,793,000
|
|
$
|
9,413,000
|
|
The average return on the companys investments for the year ended October 31,
2007 and 2006 was 11.0% and 8.4%, respectively.
At October 31, 2007, approximately 46% of the investments were
directly invested in mutual funds and were managed by professional money
managers. Remaining investments are in
managed partnerships that use various strategies to minimize their correlation
to stock market movements. Most of the
investments are highly 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, 2007,
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.
20
Table of
Contents
As of October 31, 2007, 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
|
|
$
|
163,000
|
|
$
|
77,000
|
|
$
|
86,000
|
|
$
|
|
|
$
|
|
|
Operating lease obligations
|
|
110,000
|
|
32,000
|
|
63,000
|
|
15,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
273,000
|
|
$
|
109,000
|
|
$
|
149,000
|
|
$
|
15,000
|
|
$
|
|
|
Off-Balance Sheet Financing
The
company has no off-balance sheet financing arrangements at October 31,
2007.
Product Prices and Production
Refer
to Item 1., Markets and Customers, for discussion of oil and gas prices and
marketing.
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.
|
|
2007
|
|
2006
|
|
2005
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
1,926,000
|
|
$
|
6.78
|
(1)
|
2,176,000
|
|
$
|
6.11
|
(2)
|
1,830,000
|
|
$
|
6.16
|
(3)
|
% change
|
|
-11
|
%
|
+11
|
%
|
+19
|
%
|
-1
|
%
|
+7
|
%
|
+34
|
%
|
Oil (bbls)
|
|
51,000
|
|
$
|
60.95
|
|
41,000
|
|
$
|
61.14
|
|
37,000
|
|
$
|
50.90
|
|
% change
|
|
+24
|
%
|
00
|
%
|
+11
|
%
|
+20
|
%
|
-10
|
%
|
+39
|
%
|
(1) Includes
$0.99 Mcf hedging gain.
(2) Includes
$0.l2 Mcf hedging loss.
(3) Includes
$0.39 Mcf hedging loss.
Significant Properties (see definition on page 12) contributed 62%
of 2007 production on a gas-equivalent basis.
Increases in oil volumes resulted primarily from successful drilling in
Kansas.
Although
product prices are key to the companys ability to operate profitably and to
budget capital expenditures, they are beyond the companys control and are
difficult to predict. Since 1991, the
company has periodically hedged the price of a portion of its estimated natural
gas production when the potential for significant downward price movement is
anticipated. Hedging transactions
typically take the form of forward short positions and collars on the NYMEX
futures market, and are closed by purchasing offsetting positions.
On
September 2, 2008, 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.
21
Table of Contents
The company recognizes all
derivatives as fair value hedges on its balance sheet at fair value at the end
of each period. Changes in the fair
value of hedges are now recorded in the Consolidated Statement of Operations.
The company had realized hedging gains of $1,909,000 in fiscal 2007 and
losses of $266,000 in fiscal 2006 and $719,000 in fiscal 2005. In fiscal 2007 the company had unrealized
hedging losses of $454,000 and gains of $1,327,000 in fiscal 2006 and $182,000
in fiscal 2005.
Open hedge contracts at October 31, 2007 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 10% to 12% below NYMEX prices primarily
due to basis differentials.
As of December 31, 2007, hedges covering the contract months of November 2007
through January of 2008 had been closed at expiration resulting in a gain
of $847,000. Such hedges covered
430 MMBtus at NYMEX basis prices ranging from $8.70 to $9.92. Open hedge positions as of December 31,
2007, are set forth below.
|
|
Period
|
|
|
|
Average Price
|
|
Commodity
|
|
Covered
|
|
Volume
|
|
NYMEX Basis
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
February 2008
|
|
150 MMbtu
|
|
$
|
9.52
|
|
Natural Gas
|
|
March 2008
|
|
140 MMbtu
|
|
$
|
9.28
|
|
Natural Gas
|
|
April 2008
|
|
150 MMbtu
|
|
$
|
7.83
|
|
Natural Gas
|
|
May 2008
|
|
150 MMbtu
|
|
$
|
7.83
|
|
Natural Gas
|
|
June 2008
|
|
150 MMbtu
|
|
$
|
7.92
|
|
Natural Gas
|
|
July 2008
|
|
150 MMbtu
|
|
$
|
8.01
|
|
Natural Gas
|
|
August 2008
|
|
150 MMbtu
|
|
$
|
8.07
|
|
Natural Gas
|
|
September 2008
|
|
150 MMbtu
|
|
$
|
8.05
|
|
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 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.
Oil and Gas Activities
Capital Spending.
Capital spending, net of sales, in 2007 totaled $8,808,000, consisting
primarily of additions to oil and gas properties, excluding the change in the
companys asset retirement related asset.
Operations
Summary
During 2007, 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.
Production casing has been set on three wells that were drilling over
fiscal year end, and the wells are in the process of being tested and
completed. Subsequent to year end, 13
wells commenced drilling, of which three are currently drilling, two are
producing, five are being tested or completed for production, and three are dry
holes. Four of the wells were drilled in
northwest Oklahoma, all of which have been, or are in the process of being,
completed for production. One well is
currently drilling in Oklahoma. Five of
the wells were drilled in central Kansas of which one is producing, one is awaiting
completion for production, and three were dry holes. One well is currently drilling in central
Kansas. One well was drilled in South
Texas and is awaiting pipeline
22
Table of
Contents
connection, and one well is drilling in North Texas. In addition to follow-up drilling that will
be generated by the new wells, 14 additional wells are currently scheduled on
prospects in Oklahoma, central Kansas and South Texas. The scheduled wells include a high potential
well in South Texas to test the Wilcox formation at 17,500 feet. A high potential well in North Texas is
currently drilling toward 11,200 feet.
Also subsequent to fiscal year end, the company has continued to discuss
possible joint ventures with other companies for its Calliope Gas Recovery
System. One joint venture agreement has
been executed and another is in the drafting stage. Several are in the discussion stage.
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 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 2008, 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.
The company is currently experiencing delays in securing delivery of
production equipment, primarily compressors and coil tubing. These delays are extending the time it takes
the company to conduct its field operations in general, and in particular
related to installations of its Calliope system. As a result, the company could be at risk for
price increases related to these types of services and equipment.
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.
In Hemphill County, Texas, the 11,200-foot wildcat well drilled in
fiscal 2007 to test the 3,780 gross acre Humphreys Prospect encountered
excellent quality Morrow sands, and tested at the rate of 3.0 MMcf per
day. However, production declined
rapidly but stabilized at 150 Mcf per day.
The stabilized production rate suggests that the first well is
indirectly connected to a larger Morrow reservoir. The company subsequently purchased and
reprocessed 3-D seismic over the prospect, and believes that it has identified
the primary Morrow channel. A second
well has commenced to test the seismic interpretation. The company owns a 25% working interest. This is an expensive but high potential well
that, if successful, could have a material positive effect on the companys
production in 2008.
23
Table of Contents
In Canadian County, Oklahoma, the 640 gross acre
Loosen Prospect continues to yield excellent drilling results from the Redfork
and Skinner formations. The 11,500-foot
Marcia #1-14 is currently drilling and is the fifth well drilled on the
prospect. The Marcia well is a north
extension to the recently completed Chappell well which encountered pay zones
in five separate formations. The well is
currently completed in three of the five zones and is producing 1.9 MMcf and 30
barrels of oil per day. The remaining
zones will be opened for production at a later date. The Chappell well was a north extension to
the Hazel well, drilled in December 2006, which is still producing 2.0
MMcf (million cubic feet of gas) and about 20 barrels of oil per day.
The company owns working interests in the new wells as follows: Hazel 6.25%; Chappell 16.3%, Marcia 14.5%.
In Harper County, Oklahoma, the 3,840 gross acre Buffalo Creek Prospect
continues to be a very active drilling area for the company based on a recently
completed 3-D seismic program. Nine wells have now been completed on the
prospect with production from the Chester, Morrow and Oswego formations. The most recent well encountered 14 feet of
excellent Morrow sand porosity that electric logs indicate is productive. The well is currently being completed. The
company owns working interests in the prospect ranging from 31% to 37%. Three to five new drilling locations are
currently planned for 2008, and more are expected based on the results of
future wells.
In Ellis County, Oklahoma, the first well has been drilled on the
companys 2,560 gross acre North Boxer Prospect. The 8,500-foot well is currently classified
as a tight hole, meaning information is not being released for proprietary
business reasons. A second wildcat well
has been drilled about one mile to the south and is currently being completed.
The company owns working interests in the prospect ranging from 30% to 40%.
In Kingfisher County, Oklahoma, the first two wells have been drilled
on the 1,280 gross acre Okarche Prospect to test the Hunton, Meramec,
Chester and Redfork formations. Both
wells are currently awaiting completion.
The company owns working interests ranging from 9.5% to 11%.
In Carter County, Oklahoma, the Southeast
Hewitt Waterflood Unit has produced over 600,000 incremental barrels of
oil, significantly outperforming initial expectations. As a result of development drilling,
production from the unit has recently increased about
40% to 270 barrels of oil per day. Further development is under
consideration. The company owns a
17% working interest.
In Love County, Oklahoma, a new waterflood project is currently in the
initial stages of operations. The
company owns a 10% to 12% working interest in various phases of the project.
South
Texas
The company has recently expanded the volume and breadth of its
exploration program with new drilling projects in South Texas. These projects diversify the companys
exploration geographically, scientifically, and in terms of capital, risk and
reserve potential. Compared to the
companys Oklahoma drilling, the South Texas project involves higher costs and
greater risks but offers significantly higher per well production and reserve
potential.
The most significant of the two
South Texas projects is 3-D seismic driven and focuses on the Vicksburg, Frio
and Queen City sands in Hidalgo County and the Wilcox sands in Jim Hogg County
at depths ranging from 7,200 feet to 17,500 feet. To date, the company has invested
approximately $1,872,000 (net) in the project, exclusive of drilling. Prior to sale or farmout of the prospects,
the company owns a 75% interest before recovery of its investment, exclusive of
drilling, and 37.5% thereafter. The
company has the option to participate in drilling any of the prospects for its
full interest or to reduce its costs and risks by selling or farming-out its
interest to third parties in return for cash consideration and a carried
interest on the initial wildcat well(s).
The primary objective of this project has been
identification of, leasing and sale of three deep Wilcox prospects located in
Jim Hogg County. The prospects cover 3,600 gross acres, range in depth from
16,500 to 17,500 feet, and are located in an area where several nearby
fields have produced hundreds of billions of cubic feet of gas from the Wilcox
formation. The companys 3-D seismic
interpretation indicates that the prospects
are large enough in size to have very substantial production and reserve
potential in relation to the companys existing production and reserves. However, the prospects are high risk, rank
wildcat prospects and per well drilling costs far exceed those normally
incurred by the company. Therefore, the
company has elected to sell a
24
Table
of Contents
portion of its
interest for cash consideration and a carried interest on two initial wildcat
wells. Third parties have committed to
purchase the three prospects and to drill a wildcat well on one prospect. The second wildcat well is optional based on
the outcome of the first well. Paperwork
is in the process of being completed.
The operator has indicated the intent to commence drilling early in
2008. In addition to recovering a
significant portion its cash investment in the project and being carried for
an interest in the initial test well(s), the company has preserved its option
to participate in other wells drilled on the prospects with interests ranging
from 18% before recovery of its investment to 9% after recovery.
If drilling is successful, the
company expects that its retained interest in the prospects will have a very
significant impact on its production and reserve growth.
Elsewhere in South Texas, the first
well has been drilled on the 2,500 gross acre Briggs Ranch Prospect located in
Victoria County. The prospect is fault
separated from the Heyser Field which has produced 738,000 barrels of oil and
17 Bcf from the Frio sands. The
8,600-foot Briggs Ranch #1 encountered 11 feet of Frio sands that electric logs
indicate are productive. The well has
been completed and is awaiting pipeline connection. The company owns a 9% working interest.
North-Central Kansas
The company further expanded the volume and
breadth of its exploration program with a new drilling project in central
Kansas. The Kansas project provides
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
four separate drilling projects which encompass about 41,000 gross 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 75%.
The companys recent drilling results have
improved dramatically as it continues to find the keys to successful seismic
and geologic interpretation. Four of the
last seven wells have been completed as producers, and three of those appear to
be outstanding wells.
In Graham County, a wildcat well has been completed on the 3,280 gross
acre White Anticline prospect. The well
encountered excellent porosity in the Lansing-Kansas City limestone and is
producing 100 barrels of oil per day.
A second well on the prospect resulted in a dry hole. In the same area, the first well on the 4,900
gross acre Mount Vernon prospect encountered Lansing-Kansas City limestone that
appears from tests and electric logs to be productive. The well is currently being completed and has
swab tested at rates in excess of 150 barrels of oil per day. The company owns a 12.5% working interest in
both prospects.
In Sheridan County, a wildcat well has been successfully completed on
the companys 20,000 gross acre Lucerne Prospect. The new well is located in the same general
area as the previously reported Ficken #1-23 which has been an excellent well,
having produced about 35,000 barrels of oil in 12 months. The new well encountered productive
Lansing-Kansas City limestone and is producing about 40 barrels of oil per
day. Also in Sheridan County, a new well
has been drilled on the St. Peter North prospect and is awaiting completion
after an excellent recovery on drillstem test.
The company owns a 30% working interest in both wells.
Calliope
Gas Recovery Technology
The company owns the exclusive right to a
patented technology known as the Calliope Gas Recovery System. There are currently three U.S. patents and
two Canadian patents related to the technology.
One additional patent that mirrors the U.S. patents has been applied for
in Canada. Calliope systems are
installed on wells located in Oklahoma, Texas and Louisiana.
Calliope can achieve substantially lower
flowing bottom-hole pressure than other production methods because it does not
rely on reservoir pressure to lift liquids.
In many reservoirs, lower bottom-hole pressure can translate into
recovery of substantial additional natural gas reserves.
25
Table of
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Calliope has proven to be reliable and flexible over a wide range of
applications on wells the company owns and operates. It has also proven to be consistently
successful. Accordingly, the company is
implementing strategies designed to expand the population of wells on which it
can install Calliope.
Calliopes Track Record
At fiscal year end, Calliope had been
installed 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 a 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
as is shown in the table below. 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 incremental 3.4 Bcfe to date, and they
are still producing about 2.0 MMcfed.
With Calliope, the 14 wells were projected to have estimated ultimate
incremental Calliope reserves totaling 13.6 Bcfe.
|
|
|
|
Average
|
|
Total
|
|
Total
|
|
|
|
|
|
Calliope
|
|
Calliope
|
|
Projected
|
|
|
|
|
|
Reserves
|
|
Production
|
|
Calliope
|
|
|
|
No. of
|
|
Per Well
|
|
to Date
|
|
Reserves
|
|
Group
|
|
Wells
|
|
(Bcfe)
|
|
(Bcfe)
|
|
(Bcfe)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Experimental
Wells
|
|
14
|
|
1.0
|
|
3.4
|
|
13.6
|
|
|
|
|
|
|
|
|
|
|
|
Experimental
Wells
|
|
11
|
|
0.2
|
|
0.6
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
All Wells
|
|
25
|
|
0.6
|
|
4.0
|
|
15.0
|
|
Calliope has proven to be a low risk and low cost liquid lift
technology. Calliope has never failed to
lift the liquids out of a wellbore. 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
26
Table of
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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
Calliope operations were expanded into Texas
and Louisiana in fiscal 2006. The
company considers Texas and Louisiana to be very fertile areas for Calliope and
has retained personnel and opened a Houston office to focus exclusively on
purchasing wells for Calliope and on Calliope joint ventures.
In general, higher natural
gas prices have made it increasingly difficult for the company to purchase
wells for its Calliope system. In
addition, higher gas prices have 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 have been 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, one agreement is presently
in the drafting stage, and joint venture discussions are in progress with a
number of the companies, including evaluation of candidate wells.
The joint venture negotiation
process has taken longer than expected because there are many decision points
within large companies that cause delays.
Nevertheless, the company continues to dedicate substantial resources to
joint venture projects, as it believes that the company will eventually be
successful in the joint venture area.
Calliope Drilling Project
The company believes that there is a huge
amount of gas stranded in abandoned and low pressure reservoirs that can be
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.
In June 2007, 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 $65,000 (salvage value). Calliope
was installed and immediately brought the well to life, producing at the rate
of 250 Mcf per day. The well
provided a successful test of the Calliope drilling concept and demonstrated
that Calliope will successfully solve liquid loading problems that are
difficult, if not impossible, to address with other liquid lift technologies.
During 2006, the company entered into a 50/50 joint venture with a
private company to drill wells for the purpose of using Calliope to recover
stranded gas reserves. The joint venture
committed the company to an exclusive project area with the joint venture
partner that covered much of South and East Texas. The terms of the agreement provided for an
activity threshold of at least three wells in the first year, and that either
party could terminate the agreement at the end of the first year if the
threshold was not met. As of the first
anniversary of the agreement, no wells had been drilled and the company elected
to terminate the agreement because it believed that the companys interest
would be better served to open the extensive project area covered by the
agreement to other Calliope drilling opportunities. There were no cancellation penalties.
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.
27
Table
of Contents
Results of Operations
In 2007, total revenues decreased 10% to
$15,084,000 compared to $16,757,000 last year.
The decrease was due to an 8% decrease in gas equivalent production and
a 7% decline in gas prices (excluding realized hedging transactions). As the oil and gas price/volume table on page 20
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 hedges).
Realized hedging 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 hedging 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
$8,464,000 compared to $8,382,000 for last year. 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.
In 2006, total revenues increased 20% to
$16,757,000 compared to $14,008,000 in 2005, due primarily to an 18% increase
in gas equivalent production. As the oil
and gas price/volume table on page 20 shows, total gas price realizations,
which reflect realized hedging transactions, fell 1% to $6.11 per Mcf and oil
price realizations increased 20% to $61.14 per barrel. The net effect of these price realization
changes was to increase oil and gas sales by $300,000. Realized hedging losses were $266,000 in 2006
compared to $719,000 in 2005. During the
same period, the companys gas equivalent production increased
18% resulting in an increase to oil and gas sales of $2,394,000. Unrealized hedging gains were $1,327,000 in
fiscal 2006 compared to $182,000 in fiscal 2005. Investment and other income increased primarily
due to improved performance from the companys investments.
In 2006, total costs and expenses rose 33% to
$8,382,000 compared to $6,315,000 for in 2005. Oil and gas production expenses
rose 23% due primarily to increased production taxes on higher revenues and new
wells added during the year.
Depreciation, depletion and amortization (DD&A) increased 52% due
to increased production volumes and an increase in costs being amortized. General and administrative expenses rose
16% primarily due to increases in professional fees related to compliance
with Sarbanes-Oxley regulations and accelerated filing requirements for SEC
financial reports. Interest expense
relates to the exclusive license agreement note payment. The effective tax rate was 27.6% and
28.0% for the 2006 and 2005 periods, respectively.
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 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.
Hedging.
The company recognizes all derivatives as fair value hedges on its
balance sheet at fair value at the end of each period. Changes in the fair value of hedges are now
recorded in the Consolidated Statement of Operations
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
28
Table
of Contents
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. 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 company has made only one ceiling
write-down in its 29-year history. That
write-down was made in 1986 after oil prices fell 51% and natural gas prices
fell 45% between fiscal year-end 1985 and 1986.
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 61 properties (Significant Properties). Some of the Significant Properties are
individual wells and others are multi-well properties. At October 31, 2007, the Significant
Properties represent 26% of the companys total properties but a
disproportionate 77% of the discounted value (at 10%) of the companys
reserves. Individual wells on which the
companys patented liquid lift system is installed comprise 20% of the
Significant Properties and represent 22% of the discounted reserve value of
such properties. New wells comprise 16%
of the Significant Properties and represent 15% 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.
29
Table
of Contents
Price changes will affect the economic lives
of oil and gas properties and, therefore, price changes may cause reserve
revisions. Price changes have not caused
significant proved reserve revisions by the company except in 1986 when a 51%
decline in oil prices and a 45% decline in natural gas prices resulted in
an 8.7% reduction in estimated proved reserves.
Based upon this historical experience, the company does not believe its
reserve estimates are particularly sensitive to prices changes within
historical ranges.
One measure of the life of the companys
proved reserves can be calculated by dividing proved reserves at fiscal year
end 2007 by production for fiscal year 2007.
This measure yields an average reserve life of 9 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, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the
company to make judgments based on historical experience and future
expectations. Revisions to the estimates
may be required based on such things as changes to cost estimates or the timing
of future cash outlays. Any such changes
that result in upward or downward revisions in the estimated obligation will
result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis.
Recent Accounting Pronouncements
In July 2006, the FASB issued
Interpretation No. 48,
Accounting for
Uncertainty in Income Taxesan interpretation of FASB Statement No. 109 (FIN
48).
This interpretation
clarifies the application of SFAS 109 by defining the criterion than an
individual tax position must meet for any part of the benefit of that position
to be recognized in an enterprises financial statements and also provides
guidance on measurement, de-recognition, classification, interest and penalties,
accounting in interim periods and disclosure.
FIN 48 is effective for our fiscal year commencing November 1,
2007. The adoption of FIN 48 is not
expected to have an impact on the companys results of Operations or Financial
Condition.
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.
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. As of December 1,
2007 the FASB has proposed a one-year deferral for the implementation of the
Statement for nonfinancial assets and nonfinancial liabilities that are
recognized or disclosed at fair value in the financial statements on a
30
Table of
Contents
nonrecurring basis. Management is
currently evaluating the requirements of FAS 159 and has not yet determined the
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. Management is currently evaluating the
requirements of FAS 159 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.
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
31
Table
of Contents
CONSOLIDATED
BALANCE SHEETS
October 31, 2007 and 2006
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
2007
|
|
2006
|
|
|
|
(Restated)
|
|
(Restated)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
7,285,000
|
|
$
|
4,577,000
|
|
Short-term
investments
|
|
6,383,000
|
|
5,624,000
|
|
Receivables:
|
|
|
|
|
|
Trade
|
|
602,000
|
|
777,000
|
|
Accrued oil and
gas sales
|
|
1,647,000
|
|
1,963,000
|
|
Derivative
assets
|
|
443,000
|
|
897,000
|
|
Other current
assets
|
|
55,000
|
|
71,000
|
|
|
|
|
|
|
|
Total current
assets
|
|
16,415,000
|
|
13,909,000
|
|
|
|
|
|
|
|
Long-term
assets:
|
|
|
|
|
|
Oil and gas
properties, at cost, using full cost method:
|
|
|
|
|
|
Unevaluated oil
and gas properties
|
|
7,791,000
|
|
7,060,000
|
|
Evaluated oil
and gas properties
|
|
51,691,000
|
|
43,588,000
|
|
Less:
accumulated depreciation, depletion and amortization of oil and gas
properties
|
|
(22,108,000
|
)
|
(18,556,000
|
)
|
Net oil and gas
properties
|
|
37,374,000
|
|
32,092,000
|
|
Exclusive
license agreement, net of accumulated amortization of $501,000 in 2007 and
$431,000 in 2006
|
|
198,000
|
|
268,000
|
|
Compressor and
tubular inventory to be used in development
|
|
1,090,000
|
|
1,293,000
|
|
Other, net
|
|
272,000
|
|
197,000
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
55,349,000
|
|
$
|
47,759,000
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,639,000
|
|
$
|
1,581,000
|
|
Revenue
distribution payable
|
|
979,000
|
|
1,273,000
|
|
Other accrued
liabilities
|
|
852,000
|
|
808,000
|
|
Income taxes
payable
|
|
434,000
|
|
174,000
|
|
|
|
|
|
|
|
Total current
liabilities
|
|
3,904,000
|
|
3,836,000
|
|
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
|
|
Deferred income
taxes, net
|
|
9,204,000
|
|
8,039,000
|
|
Exclusive
license obligation, less current obligations of $77,000 in 2007 and $70,000
in 2006
|
|
85,000
|
|
163,000
|
|
Asset retirement
obligation
|
|
1,016,000
|
|
954,000
|
|
|
|
|
|
|
|
Total
liabilities
|
|
14,209,000
|
|
12,992,000
|
|
|
|
|
|
|
|
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, 9,510,000 shares issued in 2007
and 2006
|
|
951,000
|
|
951,000
|
|
Capital in
excess of par value
|
|
15,913,000
|
|
14,794,000
|
|
Treasury stock,
at cost, 215,000 shares in 2007, and 249,000 shares in 2006
|
|
(506,000
|
)
|
|
|
Retained
earnings
|
|
24,782,000
|
|
19,022,000
|
|
|
|
|
|
|
|
Total
stockholders equity
|
|
41,140,000
|
|
34,767,000
|
|
|
|
|
|
|
|
Total
liabilities and stockholders equity
|
|
$
|
55,349,000
|
|
$
|
47,759,000
|
|
See
accompanying notes to consolidated financial statements.
32
Table
of Contents
CONSOLIDATED
STATEMENTS OF OPERATIONS
For the Three Years Ended October 31,
2007
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
Revenues:
|
|
|
|
|
|
|
|
Oil and gas
sales
|
|
$
|
14,265,000
|
|
$
|
16,103,000
|
|
$
|
13,862,000
|
|
Investment and
other income
|
|
819,000
|
|
654,000
|
|
146,000
|
|
|
|
|
|
|
|
|
|
|
|
15,084,000
|
|
16,757,000
|
|
14,008,000
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
Oil and gas
production
|
|
3,375,000
|
|
3,407,000
|
|
2,759,000
|
|
Depreciation,
depletion and amortization
|
|
3,666,000
|
|
3,642,000
|
|
2,402,000
|
|
General and
administrative
|
|
1,397,000
|
|
1,291,000
|
|
1,117,000
|
|
Interest
|
|
26,000
|
|
42,000
|
|
37,000
|
|
|
|
|
|
|
|
|
|
|
|
8,464,000
|
|
8,382,000
|
|
6,315,000
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
6,620,000
|
|
8,375,000
|
|
7,693,000
|
|
|
|
|
|
|
|
|
|
Derivative
gains and losses
|
|
|
|
|
|
|
|
Realized gains
(losses) from derivatives
|
|
1,909,000
|
|
(266,000
|
)
|
(719,000
|
)
|
Unrealized gains
(losses) from derivatives
|
|
(454,000
|
)
|
1,327,000
|
|
182,000
|
|
|
|
1,455,000
|
|
1,061,000
|
|
(537,000
|
)
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
8,075,000
|
|
9,436,000
|
|
7,156,000
|
|
Income taxes
|
|
(2,315,000
|
)
|
(2,600,000
|
)
|
(2,003,000
|
)
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
$
|
5,153,000
|
|
|
|
|
|
|
|
|
|
Basic
income per share
|
|
$
|
.62
|
|
$
|
.74
|
|
$
|
.57
|
|
|
|
|
|
|
|
|
|
Diluted
income per share
|
|
$
|
.61
|
|
$
|
.72
|
|
$
|
.55
|
|
Weighted average
number of shares of common stock and dilutive securities:
|
|
|
|
|
|
|
|
Basic
|
|
9,280,000
|
|
9,207,000
|
|
9,080,000
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
9,395,000
|
|
9,482,000
|
|
9,367,000
|
|
See
accompanying notes to consolidated financial statements.
33
Table
of Contents
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
For the Three Years Ended October 31,
2007
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
Excess Of
|
|
Treasury
|
|
Retained
|
|
Stockholders
|
|
|
|
Shares
|
|
Amount
|
|
Par Value
|
|
Stock
|
|
Earnings
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
October 31, 2004
|
|
9,510,000
|
|
$
|
951,000
|
|
$
|
13,388,000
|
|
$
|
(452,000
|
)
|
$
|
7,033,000
|
|
$
|
20,920,000
|
|
Net income
|
|
|
|
|
|
|
|
|
|
5,153,000
|
|
5,153,000
|
|
Purchase of treasury
stock
|
|
|
|
|
|
|
|
(8,000
|
)
|
|
|
(8,000
|
)
|
Exercise of common
stock options
|
|
|
|
|
|
|
|
335,000
|
|
|
|
335,000
|
|
Tax benefit from
the exercise of common stock options
|
|
|
|
|
|
340,000
|
|
|
|
|
|
340,000
|
|
Compensation
expense related to employee stock options
|
|
|
|
|
|
288,000
|
|
|
|
|
|
288,000
|
|
Tax Benefit for FAS
123R Option Expense
|
|
|
|
|
|
(81,000
|
)
|
|
|
|
|
(81,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
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 employee stock options
|
|
|
|
|
|
209,000
|
|
|
|
|
|
209,000
|
|
Tax Benefit for FAS
123R Option Expense
|
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
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
Treasury Stock
|
|
|
|
|
|
|
|
(506,000
|
)
|
|
|
(506,000
|
)
|
Exercise of common
stock options
|
|
|
|
|
|
368,000
|
|
|
|
|
|
368,000
|
|
Compensation
expense related to employee stock options
|
|
|
|
|
|
153,000
|
|
|
|
|
|
153,000
|
|
Tax Benefit from
Exercise of Stock Options
|
|
|
|
|
|
598,000
|
|
|
|
|
|
598,000
|
|
Balances,
October 31, 2007
|
|
9,510,000
|
|
$
|
951,000
|
|
$
|
15,913,000
|
|
(506,000
|
)
|
$
|
24,782,000
|
|
$
|
41,140,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to consolidated financial statements.
34
Table
of Contents
CONSOLIDATED
STATEMENTS OF CASH FLOWS
For the Three Years Ended October 31,
2007
CREDO PETROLEUM CORPORATION AND
SUBSIDIARIES
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
Net income
|
|
$
|
5,760,000
|
|
$
|
6,836,000
|
|
$
|
5,153,000
|
|
Adjustments to
reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
3,666,000
|
|
3,642,000
|
|
2,402,000
|
|
Unrealized
(gains) losses from derivatives
|
|
454,000
|
|
(1,327,000
|
)
|
(182,000
|
)
|
Deferred income
taxes
|
|
1,763,000
|
|
2,001,000
|
|
1,292,000
|
|
Compensation
expense related to stock options granted
|
|
153,000
|
|
209,000
|
|
288,000
|
|
Other
|
|
62,000
|
|
18,000
|
|
|
|
Changes in
operating assets and liabilities:
|
|
|
|
|
|
|
|
Proceeds from
short-term investments
|
|
1,544,000
|
|
551,000
|
|
2,500,000
|
|
Purchase of
short-term investments
|
|
(2,303,000
|
)
|
(680,000
|
)
|
(1,624,000
|
)
|
Trade
receivables
|
|
316,000
|
|
226,000
|
|
16,000
|
|
Accrued oil and
gas sales
|
|
175,000
|
|
813,000
|
|
(725,000
|
)
|
Other current
assets
|
|
16,000
|
|
174,000
|
|
299,000
|
|
Accounts payable
and accrued liabilities
|
|
(192,000
|
)
|
667,000
|
|
(917,000
|
)
|
Income taxes
payable
|
|
260,000
|
|
(157,000
|
)
|
319,000
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
11,674,000
|
|
12,973,000
|
|
8,821,000
|
|
|
|
|
|
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
Additions to oil
and gas properties
|
|
(9,144,000
|
)
|
(11,746,000
|
)
|
(6,938,000
|
)
|
Proceeds from
sale of oil and gas properties
|
|
310,000
|
|
670,000
|
|
180,000
|
|
Changes in other
long-term assets
|
|
84,000
|
|
(20,000
|
)
|
(909,000
|
)
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
(8,750,000
|
)
|
(11,096,000
|
)
|
(7,667,000
|
)
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
Proceeds from
exercise of stock options
|
|
368,000
|
|
835,000
|
|
335,000
|
|
Purchase of
treasury stock
|
|
(506,000
|
)
|
|
|
(8,000
|
)
|
Principal
payment on exclusive license obligation
|
|
(78,000
|
)
|
(70,000
|
)
|
(64,000
|
)
|
|
|
|
|
|
|
|
|
Net
cash used by financing activities
|
|
(216,000
|
)
|
765,000
|
|
263,000
|
|
|
|
|
|
|
|
|
|
Increase
in cash and cash equivalents
|
|
2,708,000
|
|
2,642,000
|
|
1,417,000
|
|
|
|
|
|
|
|
|
|
Cash and
cash equivalents:
|
|
|
|
|
|
|
|
Beginning of
period
|
|
4,577,000
|
|
1,935,000
|
|
518,000
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
7,285,000
|
|
$
|
4,577,000
|
|
$
|
1,935,000
|
|
|
|
|
|
|
|
|
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
Cash paid during
the period for income taxes
|
|
$
|
371,000
|
|
$
|
620,000
|
|
$
|
100,000
|
|
Cash paid during
the period for interest
|
|
$
|
26,000
|
|
$
|
30,000
|
|
$
|
36,000
|
|
See
accompanying notes to consolidated financial statements.
35
Table of Contents
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
October 31, 2007
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
(1) FINANCIAL STATEMENT RESTATEMENT
On September 2, 2008, 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.
In this Form 10-K/A, the company is
restating its consolidated financial statements for fiscal years ended October 31, 2005,
2006 and 2007. Unrealized gains and losses from derivative contracts have been
reclassified from Other Comprehensive Income to a separate line item on the
Statement of Operations, and realized gains and losses on derivative contracts
have been reclassified from Oil and Gas Sales to a separate line item on the
Statement of Operations. There is no effect in any period on overall cash
flows, total assets, total liabilities or total stockholders equity. The cumulative effect on all periods of the
restatement and the correction to the third quarter of 2008 was to reduce net
income by $182,000 and diluted income per share by $.03. 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. The primary financial statement items
impacted by this restatement for the years ended October 31, 2005, 2006, and
2007 are indicated below: (The effects
on the quarters within three years are presented in Note 10.)
Consolidated Statements of Income
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
Previously
Reported
|
|
As
Restated
|
|
Previously
Reported
|
|
As
Restated
|
|
Previously
Reported
|
|
As
Restated
|
|
|
|
(amounts in thousands, except per share amounts)
|
|
Oil & Gas Sales
|
|
$
|
16,174
|
|
$
|
14,265
|
|
$
|
15,837
|
|
$
|
16,103
|
|
$
|
13,143
|
|
$
|
13,862
|
|
Total Revenues
|
|
16,993
|
|
15,084
|
|
16,491
|
|
16,757
|
|
13,289
|
|
14,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Operations
|
|
8,529
|
|
6,620
|
|
8,109
|
|
8,375
|
|
6,974
|
|
7,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gains (Losses) from derivative
contracts
|
|
|
|
1,909
|
|
|
|
(266
|
)
|
|
|
(719
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Gains (Losses) from derivative
contracts
|
|
|
|
(454
|
)
|
|
|
1,327
|
|
|
|
182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Taxes
|
|
8,529
|
|
8,075
|
|
8,109
|
|
9,436
|
|
6,974
|
|
7,156
|
|
Income Taxes
|
|
(2,438
|
)
|
(2,315
|
)
|
(2,229
|
)
|
(2,600
|
)
|
(1,952
|
)
|
(2,003
|
)
|
Net Income
|
|
6,091
|
|
5,760
|
|
5,880
|
|
6,836
|
|
5,022
|
|
5,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.66
|
|
$
|
0.62
|
|
$
|
0.64
|
|
$
|
0.74
|
|
$
|
0.55
|
|
$
|
0.57
|
|
Diluted
|
|
$
|
0.65
|
|
$
|
0.61
|
|
$
|
0.62
|
|
$
|
0.72
|
|
$
|
0.54
|
|
$
|
0.55
|
|
Consolidated Balance Sheets
|
|
Years Ended October 31,
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
Previously
Reported
|
|
As
Restated
|
|
Previously
Reported
|
|
As
Restated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comperhensive income (loss)
|
|
319
|
|
|
|
650
|
|
|
|
|
|
|
|
Retained earnings
|
|
24,463
|
|
24,782
|
|
18,372
|
|
19,022
|
|
|
|
|
|
36
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
October 31, 2007
CREDO
PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
Previously
Reported
|
|
As
Restated
|
|
Previously
Reported
|
|
As
Restated
|
|
Previously
Reported
|
|
As
Restated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
6,091
|
|
5,760
|
|
5,880
|
|
6,836
|
|
5,022
|
|
5,153
|
|
Unrealized loss on derivative contracts
|
|
|
|
454
|
|
|
|
(1,327
|
)
|
|
|
(182
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
139
|
|
16
|
|
234
|
|
174
|
|
|
|
|
|
Accounts Payable & Accrued
Liabilities
|
|
|
|
|
|
236
|
|
667
|
|
(968
|
)
|
(917
|
)
|
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Basis of Presentation
The consolidated financial statements include the accounts of CREDO
Petroleum Corporation and its wholly owned subsidiaries (the company). The company engages in oil and gas
acquisition, exploration, development and production activities in the United
States. Certain operations are conducted
through limited partnerships and limited liability companies which, as general
partner or member company, the company manages and controls. The companys interests in these entities are
combined on the proportionate share basis in accordance with accepted industry
practice. All significant intercompany
transactions have been eliminated. All
references to years in these Notes refer to the companys fiscal October 31
year. The company effected a three-for
two stock split in each of fiscal 2005 and 2004. All share and per share amounts discussed and
disclosed in this Annual Report on Form 10-K/A reflect the effect of these
stock splits.
Cash, Cash Equivalents, and Short-Term Investments
Cash equivalents consist of highly liquid investments with original
maturities of three months or less. At October 31, 2007,
approximately 46% of short-term investments are mutual funds. Other short-term investments consist
primarily of professionally managed limited partnerships which provide readily
determinable market values and short-term liquidity. The partnerships are invested primarily in
financial instruments. Unrealized gains
on limited partnerships are not significant.
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. 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. Derivatives are carried at
fair value on the balance sheet. See
Natural Gas Price Hedging on page 41 for further discussions.
37
Table of Contents
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
when the month production is delivered to the purchaser at which time title
changes hands. 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.
A majority of the companys sales are made
under contractual arrangements with terms that are considered to be usual and
customary in the oil and gas industry.
The contracts are for periods of up to five years with prices determined
based upon a percentage of a pre-determined and published monthly index
price. The terms of these contracts have
not had an effect on how the company recognizes its revenue.
Hedging
The company recognizes all derivatives as fair
value hedges on its balance sheet at fair value at the end of each period. Changes in the fair value of hedges are now
recorded in the Consolidated Statement of Operations.
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. 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. 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.
38
Table of Contents
The company has made only one ceiling
write-down in its 29-year history. That
write down was made in 1986 after oil prices fell 51% and natural gas prices
fell 45% between fiscal year end 1985 and 1986.
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 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 61 properties (Significant Properties). Some of the Significant Properties are
individual wells and others are multi-well properties. At October 31, 2007, the Significant
Properties represent 26% of the companys total properties but a
disproportionate 77% of the discounted value (at 10%) of the companys
reserves. Individual wells on which the
companys patented liquid lift system is installed comprise 20% of the Significant
Properties and represent 22% of the discounted reserve value of such
properties. New wells comprise 16% of
the Significant Properties and represent 15% 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 not caused
significant proved reserve revisions by the company except in 1986 when a 51%
decline in oil prices and a 45% decline in natural gas prices resulted in
an 8.7% reduction in estimated proved reserves.
Based upon this historical experience, the company does not believe its
reserve estimates are particularly sensitive to prices changes within
historical ranges.
One measure of the life of the companys
proved reserves can be calculated by dividing proved reserves at fiscal year
end 2007 by production for fiscal year 2007.
This measure yields an average reserve life of nine 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
39
Table of Contents
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.
The company estimates the future cost of asset
retirement obligations, discounts that cost to its present value, and records a
corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on
many significant estimates, including future abandonment costs, inflation,
market risk premiums, useful life, and cost of capital. The nature of these estimates requires the
company to make judgments based on historical experience and future
expectations. Revisions to the estimates
may be required based on such things as changes to cost estimates or the timing
of future cash outlays. Any such changes
that result in upward or downward revisions in the estimated obligation will
result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis. A
reconciliation of the companys asset retirement obligation liability is as
follows:
|
|
October 31,
|
|
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
Beginning asset retirement obligation
|
|
$
|
954,000
|
|
$
|
929,000
|
|
Accretion expense
|
|
36,000
|
|
40,000
|
|
Obligations incurred
|
|
46,000
|
|
58,000
|
|
Obligations settled
|
|
|
|
(58,000
|
)
|
Change in estimate
|
|
(20,000
|
)
|
(15,000
|
)
|
Ending asset retirement obligation
|
|
$
|
1,016,000
|
|
$
|
954,000
|
|
Depreciation, Depletion and
Amortization.
Effective August 1, 2006, the company changed its estimate with
respect to estimated salvage value of lease and well equipment. This change in estimate resulted in a
decrease in depreciation, depletion and amortization due to an increase in
salvage value.
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.
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
40
Table of Contents
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 Price Hedging
On September 2, 2008, 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.
The company periodically hedges the price of a portion of its estimated
natural gas production when the potential for significant downward price
movement is anticipated. Hedging
transactions typically take the form of forward short positions and collars on
the NYMEX futures market, and are closed by purchasing offsetting
positions. Such hedges do not exceed
estimated production volumes, are expected to have reasonable correlation
between price movements in the futures market and the cash markets where the
companys production is located, and are authorized by the companys Board of
Directors. Hedges are expected to be
closed as related production occurs but may be closed earlier if the
anticipated downward price movement occurs or if the company believes that the
potential for such movement has abated.
The company recognizes all derivatives as fair
value hedges on its balance sheet at fair value at the end of each period. Changes in the fair value of hedges are now
recorded in the Consolidated Statement of Operations.
The company had realized hedging gains of $1,909,000 in fiscal 2007 and
losses of $266,000 in fiscal 2006, and $719,000 in fiscal 2005. The company had unrealized losses on
derivative contracts in fiscal 2007 of $454,000, and gains of $1,327,000 in
fiscal 2006 and $182,000 in fiscal 2005. At October 31, 2007 open
derivative contracts covered 1,620 MMBtus at NYMEX basis prices ranging from
$7.65 to $9.92.
Open hedge contracts are indexed to the
NYMEX. Periodically, the company enters
into contracts indexed to Panhandle Eastern Pipeline Company for Texas,
Oklahoma mainline. For comparative
purposes, hedges indexed to Panhandle Eastern Pipeline Company are expressed on
a NYMEX basis. For hedges indexed to
Panhandle Eastern Pipeline Company, the individual month price (basis)
differentials between the NYMEX and Panhandle Eastern Pipeline Company range
from minus $1.45 in the winter months to minus $0.90 in the spring months.
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 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
41
Table of Contents
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 and has been adjusted for the 3-for-2 stock splits in fiscal 2005 and
2004 and the 20% stock dividend in 2003.
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 weighted average grant date fair value of
the 20,000 options granted to the companys directors during the year ended October 31,
2007 was $4.01. The weighted average
grant date fair value for the 20,000 options granted to employees during the
year ended October 31, 2007 was $4.93. In each case, the fair value was measured
using the Black-Scholes valuation model with the following assumptions: expected stock price volatility of 50.84%;
risk free interest rate of 4.58%; no dividends; and an expected future life of
3 years for employees and 2 years for directors.
The fair value of the stock option grants are
amortized over the respective vesting period using the straight-line method and
assuming no forfeitures.
Compensation expense related to stock options
included in General and Administrative Expense for the years ended October 31,
2007, 2006 and 2005 is $153,000, $209,000 and $288,000, respectively. The tax benefit associated with these
expenditures was $44,000, $60,000 and $81,000 in fiscal year 2007, 2006 and
2005, respectively. The estimated
unrecognized compensation cost from unvested options as of October 31,
2007 was approximately $123,000, which is expected to be recognized over an
average period of 2.6 years.
42
Table of Contents
Plan activity for the years ended October 31, 2007, 2006 and 2005
is set forth below and has been adjusted for the 3-for-2 stock splits in fiscal
2005 and 2004.
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Number of
|
|
Exercise
|
|
Number of
|
|
Exercise
|
|
Number of
|
|
Exercise
|
|
|
|
Options
|
|
Price
|
|
Options
|
|
Price
|
|
Options
|
|
Price
|
|
Outstanding at beginning of year
|
|
315,002
|
|
$
|
5.52
|
|
485,064
|
|
$
|
5.78
|
|
565,875
|
|
$
|
7.11
|
|
Granted
|
|
40,000
|
|
12.78
|
|
|
|
|
|
33,750
|
|
8.93
|
|
Exercised
|
|
(84,187
|
)
|
4.39
|
|
(143,813
|
)
|
5.81
|
|
(61,686
|
)
|
5.43
|
|
Cancelled or forfeited
|
|
(564
|
)
|
5.93
|
|
(26,249
|
)
|
8.82
|
|
(52,875
|
)
|
6.01
|
|
Outstanding at end of year
|
|
270,251
|
|
$
|
6.94
|
|
315,002
|
|
$
|
5.52
|
|
485,064
|
|
$
|
5.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average contractual life at end of
year
|
|
|
|
6.13
|
|
|
|
6.40
|
|
|
|
7.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of grants
|
|
|
|
$
|
4.47
|
|
|
|
|
|
|
|
$
|
6.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year
|
|
236,918
|
|
$
|
6.12
|
|
266,939
|
|
$
|
5.53
|
|
348,114
|
|
$
|
5.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value of Exercisable Options
|
|
$
|
855,000
|
|
|
|
$
|
1,999,000
|
|
|
|
$
|
4,118,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of options exercised during fiscal years
2007, 2006 and 2005 was approximately $704,000, $2,227,000 and $250,000,
respectively.
The company has issued shares from its treasury stock whenever stock
options have been exercised in fiscal years 2007, 2006 and 2005.
The following table summarizes information about stock options
outstanding at October 31, 2007:
|
|
Outstanding
|
|
Exercisable
|
|
|
|
Number
|
|
Weighted Average
|
|
Weighted
|
|
Number
|
|
|
|
Range of
|
|
Outstanding
|
|
Remaining
|
|
Average
|
|
Exercisable at
|
|
Weighted
|
|
Exercise
|
|
at October 31,
|
|
Contractual
|
|
Exercise
|
|
October 31,
|
|
Average
|
|
Prices
|
|
2007
|
|
Life in Year
|
|
Price
|
|
2007
|
|
Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93
|
|
230,251
|
|
5.62
|
|
$
|
5.93
|
|
230,251
|
|
$
|
5.93
|
|
$12.78
|
|
40,000
|
|
9.10
|
|
$
|
12.78
|
|
6,667
|
|
$
|
12.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 5.93-$12.78
|
|
270,251
|
|
6.13
|
|
$
|
6.94
|
|
236,918
|
|
$
|
6.12
|
|
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, 2007
were 114,597.
43
Table
of Contents
The
companys calculation of earnings per share of common stock is as follows:
|
|
Year Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
|
|
|
|
|
|
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
|
|
$
|
5,760,000
|
|
9,280,000
|
|
$
|
.62
|
|
$
|
6,836,000
|
|
9,207,000
|
|
$
|
.74
|
|
$
|
5,153,000
|
|
9,080,000
|
|
$
|
.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of
dilutive shares of common stock from stock options
|
|
|
|
115,000
|
|
(.01
|
)
|
|
|
275,000
|
|
(.02
|
)
|
|
|
287,000
|
|
(.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings
per share
|
|
$
|
5,760,000
|
|
9,395,000
|
|
$
|
.61
|
|
$
|
6,836,000
|
|
9,482,000
|
|
$
|
.72
|
|
$
|
5,153,000
|
|
9,367,000
|
|
$
|
.55
|
|
Recent Accounting Pronouncements
In July 2006, the FASB issued
Interpretation No. 48,
Accounting for
Uncertainty in Income Taxesan interpretation of FASB Statement No. 109
(FIN 48).
This
interpretation clarifies the application of SFAS 109 by defining the criterion
that an individual tax position must meet for any part of the benefit of that
position to be recognized in an enterprises financial statements and also
provides guidance on measurement, de-recognition, classification, interest and
penalties, accounting in interim periods and disclosure. FIN 48 is effective for our fiscal year
commencing November 1, 2007. The
adoption of FIN 48 is not expected to have an impact on our results of
operations or financial condition.
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.
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. As of December 1, 2007 the FASB has
proposed a one-year deferral for the implementation of the Statement for
nonfinancial assets and nonfinancial liabilities that are recognized or
disclosed at fair value in the financial statements on a nonrecurring basis. Management is currently evaluating the
requirements of FAS 159 and has not yet determined the 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
44
Table of Contents
certain circumstances. Management
is currently evaluating the requirements of FAS 159 and has not yet determined
the impact on its financial statements.
(3) 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, 2007, common shares issued are 9,510,000, common
shares held in treasury are 215,000 and common shares outstanding are
9,295,000. 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.
On September 13, 2005, the company
declared a 3-for-2 stock split to shareholders of record on September 26,
2005. Accordingly, 3,170,000 additional
shares were issued on October 11, 2005. Common stock has been increased by the par
value of the shares issued with a corresponding decrease in capital in excess
of par value for all periods presented.
Reclassifications
Certain 2006 and 2005 amounts have been
reclassified to conform to current year presentation. Such reclassifications had no effect on net
income or shareholders equity.
(4) COMMITMENTS
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 $75,000 in 2007,
$80,000 in 2006, and $79,000 in 2005.
The company has no capital leases and no other operating lease
commitments.
(5) 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
2007, 2006 and 2005 were $44,000, $37,000, and $39,000, respectively.
Other
Company Benefits
The company provides a health and welfare
benefit plan to all regular full-time employees. The plan includes health
insurance.
(6) 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 variables such as product prices. Accordingly, the liability is subject to
continual recalculation, revision of the numerous estimates required, and may
change significantly in the event of such things as major acquisitions,
divestitures, product price changes, changes in reserve estimates, changes in
reserve lives, and changes in tax rates or tax laws.
At October 31, 2007 the company had
$828,000 of statutory depletion carry forward for tax return purposes.
45
Table
of Contents
The income tax expense recorded in the Consolidated Statements of
Operations consists of the following:
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
Current
|
|
$
|
1,150,000
|
|
$
|
473,000
|
|
$
|
715,000
|
|
Deferred
|
|
1,165,000
|
|
2,127,000
|
|
1,288,000
|
|
|
|
|
|
|
|
|
|
Total income tax
expense
|
|
$
|
2,315,000
|
|
$
|
2,600,000
|
|
$
|
2,003,000
|
|
The effective income tax rate differs from the U.S. Federal statutory
income tax rate due to the following:
|
|
Years Ended October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
Federal taxes at
statutory rate
|
|
2,826,000
|
|
3,303,000
|
|
2,505,000
|
|
Graduated rates
|
|
(64,000
|
)
|
(62,000
|
)
|
(72,000
|
)
|
State income
taxes and other
|
|
214,000
|
|
134,000
|
|
150,000
|
|
Percentage
depletion
|
|
(661,000
|
)
|
(775,000
|
)
|
(580,000
|
)
|
|
|
|
|
|
|
|
|
|
|
2,315,000
|
|
2,600,000
|
|
2,003,000
|
|
The principal sources of temporary differences resulting in deferred tax
assets and tax liabilities at October 31, 2007 and 2006 are as follows:
|
|
October 31,
|
|
|
|
2007
|
|
2006
|
|
Deferred tax
assets:
|
|
|
|
|
|
Gain on property
sales
|
|
$
|
800,000
|
|
$
|
789,000
|
|
|
|
|
|
|
|
Total deferred
tax assets
|
|
800,000
|
|
789,000
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
Intangible
drilling, leasehold and other exploration costs capitalized for financial
reporting purposes but deducted for tax purposes
|
|
(8,843,000
|
)
|
(7,661,000
|
)
|
State taxes and
other
|
|
(1,161,000
|
)
|
(1,167,000
|
)
|
|
|
|
|
|
|
Total deferred
tax liabilities
|
|
(10,004,000
|
)
|
(8,828,000
|
)
|
|
|
|
|
|
|
Net deferred tax
liability
|
|
$
|
(9,204,000
|
)
|
$
|
(8,039,000
|
)
|
(7) EXCLUSIVE LICENSE AGREEMENT OBLIGATION
On
September 1, 2000, the company acquired an unrestricted, exclusive license
for patented technology. The initial
license term was 10 years and includes an option for the company to extend the
term to the remaining life of the patents.
The licensor will receive a net 8.3% carried interest in any
installation of the technology. The
license purchase price was $1,115,000, of which $953,000 has been paid. The balance, which is due in two remaining
annual increments of $93,750, is recorded at 10% present value. The related assets are being amortized over
10 years on a straight-line basis. If
the option to extend the license after the initial 10-year term is exercised,
the cost will be $93,750 per year to the expiration of the last patent.
46
Table of
Contents
|
|
October 31, 2007
|
|
|
|
Gross Carrying
|
|
Accumulated
|
|
|
|
Amount
|
|
Amortization
|
|
Amortized
intangible assets:
|
|
|
|
|
|
Exclusive
license agreement
|
|
$
|
699,000
|
|
$
|
501,000
|
|
|
|
|
|
|
|
Aggregate
amortization expense:
|
|
|
|
|
|
For the year
ended October 31, 2007
|
|
|
|
$
|
70,000
|
|
|
|
|
|
|
|
Estimated future
amortization expense:
|
|
|
|
|
|
For the year
ended October 31, 2008
|
|
|
|
70,000
|
|
For the year
ended October 31, 2009
|
|
|
|
70,000
|
|
For the year
ended October 31, 2010
|
|
|
|
58,000
|
|
Total
|
|
|
|
$
|
198,000
|
|
|
|
|
|
|
|
|
|
This amortizable intangible asset is an exclusive
license agreement related solely 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.
At October 31, 2007, this amortizable intangible
asset had a net book value of $198,000.
The value of this asset 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, 2007, the
company has not recorded an impairment write-down for this asset. The estimated undiscounted value of future
net cash flows is derived from estimates of proved reserve values.
(8) 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 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.
(9) SUPPLEMENTARY OIL AND GAS INFORMATION
Capitalized Costs
|
|
October 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Unevaluated
properties not being amortized
|
|
$
|
7,791,000
|
|
$
|
7,060,000
|
|
$
|
3,452,000
|
|
Properties being
amortized
|
|
51,691,000
|
|
43,588,000
|
|
36,121,000
|
|
Accumulated
depreciation, depletion and amortization
|
|
(22,108,000
|
)
|
(18,556,000
|
)
|
(15,022,000
|
)
|
|
|
|
|
|
|
|
|
Total
capitalized costs
|
|
$
|
37,374,000
|
|
$
|
32,092,000
|
|
$
|
24,551,000
|
|
47
Table
of Contents
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,
2007:
|
|
Total
|
|
Net Costs Incurred
|
|
Unevaluated
|
|
During Periods Ended:
|
|
Properties
|
|
|
|
|
|
October 31, 2007
|
|
$
|
3,274,000
|
|
October 31, 2006
|
|
2,629,000
|
|
October 31, 2005
|
|
1,888,000
|
|
|
|
$
|
7,791,000
|
|
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,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Property
acquisition costs net of divestiture proceeds:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
82,000
|
|
$
|
102,000
|
|
$
|
81,000
|
|
Unproved
|
|
2,106,000
|
|
1,815,000
|
|
2,092,000
|
|
Exploration
costs
|
|
3,368,000
|
|
6,388,000
|
|
834,000
|
|
Development
costs
|
|
3,252,000
|
|
2,786,000
|
|
4,170,000
|
|
|
|
|
|
|
|
|
|
Total before
asset retirement obligation
|
|
$
|
8,808,000
|
|
$
|
11,091,000
|
|
$
|
7,177,000
|
|
|
|
|
|
|
|
|
|
Total including
asset retirement obligation
|
|
$
|
8,834,000
|
|
$
|
11,076,000
|
|
$
|
7,327,000
|
|
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: Duke Energy 40% in 2007, 39% in
2006 and 40% in 2005.
Oil and Gas Reserve Data (Unaudited)
Independent petroleum engineers estimated proved reserves for the
companys properties which represented approximately 64% in 2007, 63% in 2006
and 63% in 2005 of total estimated future net revenues. The remaining reserves were estimated by the
company. Reserve definitions and pricing
requirements prescribed by the Securities and Exchange Commission were
used. The determination of oil and gas
reserve quantities involves numerous estimates which are highly complex and
interpretive. The estimates are subject
to continuing re-evaluation and reserve quantities may change as additional
information becomes available. Estimated
values of proved reserves were computed by applying prices in effect at October 31
of the indicated year. The average price
used was $86.61, $53.69 and $55.59 per barrel for oil and $5.89, $6.32 and
$10.26 per Mcf for gas in 2007, 2006 and 2005, respectively. Estimated future costs were calculated
assuming continuation of costs and economic conditions at the reporting date.
48
Table of Contents
Total estimated proved reserves and the changes therein are set forth
below for the indicated year.
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Gas (Mcf)
|
|
Oil (bbls)
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
November 1
|
|
16,005,000
|
|
422,000
|
|
15,516,000
|
|
386,000
|
|
15,273,000
|
|
407,000
|
|
Revisions of previous
estimates
|
|
(548,000
|
)
|
52,000
|
|
(637,000
|
)
|
24,000
|
|
(889,000
|
)
|
(6,000
|
)
|
Extensions and discoveries
|
|
3,442,000
|
|
168,000
|
|
3,302,000
|
|
53,000
|
|
2,962,000
|
|
22,000
|
|
Purchases of reserves
in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of
reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
(1,926,000
|
)
|
(51,000
|
)
|
(2,176,000
|
)
|
(41,000
|
)
|
(1,830,000
|
)
|
(37,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, October 31
|
|
16,973,000
|
|
591,000
|
|
16,005,000
|
|
422,000
|
|
15,516,000
|
|
386,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of
year
|
|
13,683,000
|
|
397,000
|
|
13,603,000
|
|
381,000
|
|
13,993,000
|
|
374,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
12,890,000
|
|
458,000
|
|
13,683,000
|
|
397,000
|
|
13,603,000
|
|
381,000
|
|
The standardized measure of
discounted future net cash flows from reserves is set forth below as of October 31
of the indicated year.
|
|
2007
|
|
2006
|
|
2005
|
|
Future cash
inflows
|
|
$
|
151,169,000
|
|
$
|
123,889,000
|
|
$
|
180,726,000
|
|
Future
production and development costs
|
|
(49,667,000
|
)
|
(39,028,000
|
)
|
(43,848,000
|
)
|
Future income
tax expense
|
|
(24,967,000
|
)
|
(20,747,000
|
)
|
(36,054,000
|
)
|
Future net cash
flows
|
|
76,535,000
|
|
64,114,000
|
|
100,824,000
|
|
10% discount
factor
|
|
(29,734,000
|
)
|
(24,363,000
|
)
|
(41,337,000
|
)
|
Standardized
measure of discounted future net cash flows
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
$
|
59,487,000
|
|
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.
|
|
2007
|
|
2006
|
|
2005
|
|
Balance,
November 1
|
|
$
|
39,751,000
|
|
$
|
59,487,000
|
|
$
|
32,859,000
|
|
Sales of oil and
gas produced, net of production costs
|
|
(12,800,000
|
)
|
(12,430,000
|
)
|
(10,384,000
|
)
|
Net changes in
prices and production costs
|
|
3,233,000
|
|
(33,058,000
|
)
|
29,821,000
|
|
Extensions and
discoveries, net of future development and production costs
|
|
16,658,000
|
|
12,998,000
|
|
15,804,000
|
|
Changes in
future development costs
|
|
(12,000
|
)
|
(536,000
|
)
|
(1,692,000
|
)
|
Previously
estimated development costs incurred during the period
|
|
932,000
|
|
1,299,000
|
|
2,248,000
|
|
Revisions of
previous quantity estimates, timing, and other
|
|
(2,355,000
|
)
|
(3,396,000
|
)
|
(2,962,000
|
)
|
Purchases of
reserves in place
|
|
|
|
|
|
|
|
Sales of
reserves in place
|
|
|
|
|
|
|
|
Accretion of
discount
|
|
3,975,000
|
|
5,949,000
|
|
3,286,000
|
|
Net change in
income taxes
|
|
(2,581,000
|
)
|
9,438,000
|
|
(9,493,000
|
)
|
|
|
|
|
|
|
|
|
Balance,
October 31
|
|
$
|
46,801,000
|
|
$
|
39,751,000
|
|
$
|
59,487,000
|
|
49
Table of
Contents
(10) QUARTERLY FINANCIAL
INFORMATION (UNAUDITED)
The following is a tabulation
of the companys unaudited quarterly operating results for fiscal 2005, 2006
and 2007: (The amounts have been restated for the change in accounting for
derivatives described in note 1)
|
|
|
|
Income
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
Before
|
|
|
|
Basic Net
|
|
Net
|
|
|
|
Total
|
|
Income
|
|
Net
|
|
Income
|
|
Income
|
|
|
|
Revenue
|
|
Taxes
|
|
Income
|
|
Per Share
|
|
Per Share
|
|
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
2,673,000
|
|
$
|
1,859,000
|
|
$
|
1,338,000
|
|
$
|
0.15
|
|
$
|
0.14
|
|
Second Quarter
|
|
3,093,000
|
|
1,593,000
|
|
1,147,000
|
|
0.12
|
|
0.12
|
|
Third Quarter
|
|
3,507,000
|
|
1,967,000
|
|
1,417,000
|
|
0.16
|
|
0.15
|
|
Fourth Quarter
|
|
4,735,000
|
|
1,737,000
|
|
1,251,000
|
|
0.14
|
|
0.14
|
|
|
|
$
|
14,008,000
|
|
$
|
7,156,000
|
|
$
|
5,153,000
|
|
$
|
0.57
|
|
$
|
0.55
|
|
Fiscal 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
4,631,000
|
|
$
|
2,779,000
|
|
$
|
2,001,000
|
|
$
|
0.22
|
|
$
|
0.21
|
|
Second Quarter
|
|
3,921,000
|
|
1,963,000
|
|
1,392,000
|
|
0.15
|
|
0.15
|
|
Third Quarter
|
|
3,969,000
|
|
1,799,000
|
|
1,286,000
|
|
0.14
|
|
0.14
|
|
Fourth Quarter
|
|
4,236,000
|
|
2,895,000
|
|
2,157,000
|
|
0.23
|
|
0.22
|
|
|
|
$
|
16,757,000
|
|
$
|
9,436,000
|
|
$
|
6,836,000
|
|
$
|
0.74
|
|
$
|
0.72
|
|
Fiscal 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
3,659,000
|
|
$
|
1,529,000
|
|
$
|
1,093,000
|
|
$
|
0.12
|
|
$
|
0.12
|
|
Second Quarter
|
|
4,301,000
|
|
2,108,000
|
|
1,498,000
|
|
0.16
|
|
0.16
|
|
Third Quarter
|
|
3,846,000
|
|
3,411,000
|
|
2,447,000
|
|
0.26
|
|
0.26
|
|
Fourth Quarter
|
|
3,278,000
|
|
1,027,000
|
|
722,000
|
|
0.08
|
|
0.07
|
|
|
|
$
|
15,084,000
|
|
$
|
8,075,000
|
|
$
|
5,760,000
|
|
$
|
0.62
|
|
$
|
0.61
|
|
50
Table of Contents
Report
Of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders
Credo Petroleum
Corporation
We have audited the
consolidated balance sheets of Credo Petroleum Corporation and subsidiaries as
of October 31, 2007 and 2006, and the related consolidated statements of
operations, stockholders equity and cash flows for each of the three 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 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 2006, and the results of their
operations and their cash flows for each of the three years in the period ended
October 31, 2007, in conformity with U.S. generally accepted accounting
principles.
As discussed in Note 1 of
the October 31, 2007 Form 10-K/A, the Company restated its results of
operations for the years ended October 31, 2007, 2006 and 2005.
We also have audited, in
accordance with the standards of the Public Company Accounting Oversight Board
(United States), Credo Petroleum Corporations and subsidiaries internal
control over financial reporting as of October 31, 2007, based on criteria established in
Internal ControlIntegrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Our report dated January 14, 2008 expressed an opinion that Credo
Petroleum Corporation had not maintained effective internal control over
financial reporting as of October 31, 2007, based on criteria established
in
Internal ControlIntegrated Framework
issued
by COSO.
HEIN
& ASSOCIATES LLP
|
|
|
Denver, Colorado
|
January 14, 2008,
except for the matters described in Note 1 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 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
51
Table
of Contents
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 identified a
material weakness in the companys internal controls over financial
reporting. A material weakness is a
significant deficiency, or combination of significant deficiencies, that
results in more than a remote likelihood that a material misstatement of the
annual or interim financial statements will not be prevented or detected by the
companys internal control over financial reporting.
Management
concluded that the companys disclosure controls and procedures were not
operating effectively as of October 31, 2007, due to the material
weakness described below.
The company does not have the technical resources to review highly
complex and non-recurring transactions.
Management
intends to address this material weakness by providing additional training for
its senior accounting staff in certain highly technical and complex accounting
areas involving new rules and pronouncements and new interpretations of rules and
pronouncements, and may retain experts to advise it regarding these areas.
Limitations of the effectiveness of internal control
.
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.
52
Table of Contents
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
53
Table of Contents
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/A, 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 close 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 20,
2008 and is hereby incorporated by reference.
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/A.
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).
|
54
Table of
Contents
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).
|
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 September 15, 2008
|
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).
|
*
Filed with this Form 10-K/A.
55
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 September 15, 2008.
|
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
|
|
|
|
|
|
September 15, 2008
|
|
/s/ James T. Huffman
|
|
Chairman of the Board
|
|
|
James T. Huffman
|
|
of Directors, Treasurer and
|
|
|
|
|
Chief Executive Officer
|
|
|
|
|
(Principal Executive
|
|
|
|
|
Officer)
|
|
|
|
|
|
September 15, 2008
|
|
/s/ Alford B. Neely
|
|
Chief Financial Officer
|
|
|
Alford B. Neely
|
|
(Principal Financial and
|
|
|
|
|
Accounting Officer)
|
|
|
|
|
|
September 15, 2008
|
|
/s/ Clarence H. Brown
|
|
Director
|
|
|
Clarence H. Brown
|
|
|
|
|
|
|
|
September 15, 2008
|
|
/s/ Oakley Hall
|
|
Director
|
|
|
Oakley Hall
|
|
|
|
|
|
|
|
September 15, 2008
|
|
/s/ W. Mark Meyer
|
|
Director
|
|
|
W. Mark Meyer
|
|
|
|
|
|
|
|
September 15, 2008
|
|
/s/ John A. Rigas
|
|
Director
|
|
|
John A. Rigas
|
|
|
|
|
|
|
|
September 15, 2008
|
|
/s/ William F. Skewes
|
|
Director
|
|
|
William F. Skewes
|
|
|
|
|
|
|
|
September 15, 2008
|
|
/s/ Richard B. Stevens
|
|
Director
|
|
|
Richard B. Stevens
|
|
|
56
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